US20190390538A1

US20190390538A1 - Downhole Solid State Pumps

Info

Publication number: US20190390538A1
Application number: US16/446,108
Authority: US
Inventors: Robert A. Frantz, III; Conal H. O'Neill; Lucas Marrero; Michael C. Romer; Timothy J. Hall
Original assignee: Individual
Current assignee: ExxonMobil Upstream Research Co
Priority date: 2018-06-22
Filing date: 2019-06-19
Publication date: 2019-12-26
Also published as: CA3047561A1; CA3047561C

Abstract

A pump includes a solid state pump including a solid state actuator actuatable to pressurize a hydraulic fluid, and a secondary pump in fluid communication with the solid state pump via a fluid circuit. The secondary pump is actuatable with the hydraulic fluid received from the solid state pump, and actuating the secondary pump draws in an external fluid into the secondary pump, pressurizes the external fluid within the secondary pump, and discharges a pressurized external fluid.

Description

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the benefits of U.S. Provisional Application 62/688,731, filed Jun. 22, 2018, the entirety of which is incorporated herein.

BACKGROUND

In the oil and gas industry, wellbores are drilled for the purpose of producing hydrocarbons from subterranean formations. Some wellbores produce liquid hydrocarbons, while others primarily produce gaseous hydrocarbons. Over time, gas production wells can fill with wellbore liquids, such as water, condensate, and/or liquid hydrocarbons. These wellbore liquids create an impediment to gas flow and, in more severe cases, can entirely stop gas production.
One way to deal with accumulating wellbore liquids in gas wells is to install an artificial lift system to remove the wellbore liquids. Artificial lift systems take advantage of a forced pressure differential between the casing that lines the wellbore and production tubing extended into the casing to extract the liquids. The pressure differential is created by sealing the well and subsequently actuating a surface valve to systematically remove liquids from the well.
Plunger lift and pumping systems are examples of common artificial lift systems used to remove wellbore liquids from gas wells. While effective under certain circumstances, these systems may not be capable of efficiently removing wellbore liquids from long and/or deep gas wells, from wells that are deviated, or from wells in which the gaseous hydrocarbons do not generate at least a threshold pressure. Moreover, pumping systems suffer from reliability issues and/or considerable installation/deployment costs since a workover rig is typically required for intervention.
Plunger lift systems are dependent on reservoir pressure and can only remove a limited amount of liquid per day. Pumping systems are typically employed when water volumes are high or reservoir pressure is too low for a plunger application. Common pump types used include sucker rod pumps, electric submersible pumps (ESPs), progressive cavity pumps (PCPs), and hydraulic pumps. Conventional sucker rod pumps and PCPs are positive displacement pumps that can produce high head at various volumetric throughputs, and do not require a multitude of stages/sections to achieve a desired head. Rod pumps are typically powered by reciprocating rods, and the theoretical production volume is limited by the maximum number of rod strokes per minute that can be achieved without failing the surface pumping unit or the downhole equipment. PCPs are typically powered with rotating rods, and the theoretical production volume is limited by the maximum rpm at which the rods can be rotated without failing the surface driver(s) or downhole equipment.
The mechanical connection from the pumps to surface can also limit the application depth of a rod pump or PCP system. Additionally, rods can wear and create holes in the production tubing in which they are installed, particularly in deviated or horizontal wells. Electric submersible PCPs have been developed, but are still depth limited by the maximum head that can be generated from the rotor-in-stator design.
Significant gas and oil reserves are at stake if liquids cannot be economically produced from gas wells, and the foregoing issues with plunger lift and pumping systems can make economical hydrocarbon production impracticable. What is needed is a pumping system that can be implemented in deep wells, that is less expensive to deploy/replace, and is more resistant to deviated/tortuous trajectories.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures are included to illustrate certain aspects of the present disclosure, and should not be viewed as exclusive embodiments. The subject matter disclosed is capable of considerable modifications, alterations, combinations, and equivalents in form and function, without departing from the scope of this disclosure.

FIG. 1 is a schematic diagram of an example well system that may incorporate one or more principles of the present disclosure.

FIG. 2 is an enlarged partial cross-sectional view of a portion of the well system of FIG. 1, including the positive-displacement solid state pump, according to one or more embodiments of the present disclosure.

FIG. 3 is an enlarged schematic view of another example embodiment of the positive-displacement solid state pump as included in the well system of FIG. 1.

FIG. 4 is a schematic diagram of an example positive-displacement solid state pump, according to embodiments of the present disclosure.

FIGS. 5A and 5B depict example operation of the solid state pump of FIG. 4.

FIG. 6 is an enlarged schematic view of another example pump that may be used in the well system of FIG. 1.

FIG. 7 is an enlarged schematic view of another example pump that may be used in the well system of FIG. 1.

DETAILED DESCRIPTION

The present disclosure is generally related to systems and methods for artificial lift in a wellbore and, more specifically, to systems and methods that utilize a downhole solid state pump to remove wellbore liquids from the wellbore.
The embodiments disclosed herein describe a pump that may be used in a well system to extract wellbore liquids from a wellbore. The pump may be conveyable into production tubing extended within the wellbore, and the pump may include a solid state pump and a secondary pump in fluid communication with the solid state pump via a fluid circuit. The solid state pump may include a solid state actuator actuatable to pressurize a hydraulic fluid, and the secondary pump may be actuatable with the hydraulic fluid received from the solid state pump. A control system may be communicably coupled to the pump to control its operation. Actuating the secondary pump may draw in a wellbore liquid into the secondary pump, pressurize the wellbore liquid within the secondary pump, and discharge a pressurized wellbore liquid into the production tubing for production to a surface location.
FIG. 1 is a schematic diagram of an example well system 100 that may incorporate one or more principles of the present disclosure. As illustrated, the well system 100 includes a wellhead 102 arranged at a surface location 104 and a wellbore 106 that extends from the wellhead 102 and through one or more subterranean formations 108. In some embodiments, the wellhead 102 may be replaced with a surface rig (e.g., a derrick or the like), a service truck, or other types of surface intervention systems. The wellbore 106 may be lined with one or more strings of casing 110, and a production tubing 112 may be arranged or otherwise extended within the casing 110. In some applications, the casing 110 and the production tubing 112 may both extend from and otherwise be “hung off” the wellhead 102.
As used herein, the term “production tubing” can refer to any pipe or pipe string known to those skilled in the art, such as casing, liner, drill string, injection tubing, coiled tubing, a pup joint, a buried pipeline, underwater piping, or aboveground piping.
In some applications, as illustrated, the wellbore 106 may deviate from vertical at some point and terminate at a toe 114 in a slanted or horizontal portion of the wellbore 106. Those skilled in the art will readily appreciate that the principles of the present disclosure are applicable to wells having a variety of wellbore directional configurations including vertical wellbores, deviated wellbores, horizontal wellbores, slanted wellbores, multilateral wells, combinations thereof, and the like.
As illustrated, the well system 100 may include a pump 116 conveyable into the production tubing 112 and operable as an artificial lift system to remove wellbore liquids from the wellbore 106. In some embodiments, the pump 116 may comprise a positive-displacement solid state pump. Accordingly, the pump 116 may be referred to herein as “the solid state pump 116.” In some embodiments, the well system 100 may include a lubricator 118 (shown in dashed lines) arranged at the surface location 104 in conjunction with the wellhead 102. The lubricator 118 may be used to receive and inject the solid state pump 116 into the wellbore 106 and, more particularly, within the production tubing 112. The lubricator 118 may also be used to remove the solid state pump 116 from the wellbore 106 as needed.
As compared to traditional artificial lift systems, the solid state pump 116 may be small enough to be introduced into the wellbore 106 via the lubricator 118. This may prove advantageous in allowing the solid state pump 116 to be located within the wellbore 106 without depressurizing or killing the well system 100, and/or while containing wellbore fluids within the wellbore 106. Moreover, this may increase efficiency of operations by decreasing the time required to introduce or remove the solid state pump 116 into/from the wellbore 106. The solid state pump 116 may also be short enough to be conveyed past deviations in most wellbores. Such deviated regions might obstruct or retain longer or larger-diameter traditional pumping systems, but the presently disclosed solid state pump 116 may be operable in well systems that are otherwise inaccessible to more traditional artificial lift systems.
The solid state pump 116 may be conveyed downhole on a conveyance 120, which may comprise, but is not limited to, a wire, a cable, wireline, coiled tubing, drill pipe, slickline, or any combination thereof. In at least one embodiment, the conveyance 120 may include a seven cable logging cable that provides electrical communication with the surface location 104 to provide telecommunication and electrical power downhole to operate the solid state pump 116. In such embodiments, the solid state pump 116 may be powered by a surface power source 122 that may comprise, but is not limited to, a generator (e.g., an AC generator, a DC generator, etc.), a genset, a turbine, solar-power, wind-power, one or more batteries, one or more fuel cells, or any combination thereof. In other embodiments, however, the solid state pump 116 may be powered downhole (locally) by an onboard power source 124 included in the solid state pump 116. In such embodiments, the onboard power source 124 may comprise, but is not limited to, a battery pack, one or more fuel cells, a downhole power generator, or any combination thereof. When batteries are used in the surface or onboard power sources 122, 124, such batteries may be rechargeable.
In some embodiments, the solid state pump 116 may be conveyed downhole with the production tubing 112. In such embodiments, the solid state pump 116 may be installed within and otherwise coupled to the production tubing 112 at the surface location 104 and extended into the wellbore 106 concurrently with the production tubing 112. Moreover, in such embodiments the solid state pump 116 may be referred to as a “tubing pump.”
In some embodiments, the well system 100 may further include a sealing assembly 126 configured to secure or seat the solid state pump 116 within the production tubing 112 at a predetermined location (e.g., at or near the end of the production tubing 112). In some embodiments, the sealing assembly 126 may comprise a profile or radial shoulder defined on the inner radial surface of the production tubing 112 and configured to receive a corresponding profile or outer radial shoulder provided by the solid state pump 116. In other embodiments, the sealing assembly 126 may comprise an expandable packer element that provides a sealed interface between the production tubing 112 and the solid state pump 116. In at least one embodiment, the radial sealing assembly 126 may help isolate and otherwise separate the intake and discharge points of the solid state pump 116.
In example operation, the solid state pump 116 may be deployed downhole and at least partially immersed in wellbore liquids 127 present within the wellbore 106. The wellbore liquid 127 may include, but is not limited to, water, condensate, liquid hydrocarbons, or any combination thereof. Unless they are removed from the wellbore 106, the wellbore liquid 127 can obstruct gas production to the surface location 104. Accordingly, the solid state pump 116 may be configured to draw in and pressurize the wellbore liquid 127, and subsequently discharge a pressurized wellbore liquid 128 into the production tubing 112 for production to the surface location 104. Wellbore gas 130 may simultaneously be produced to the surface location 104 via an annulus 132 defined between the production tubing 112 and the inner wall of the casing 106.
In some embodiments, the well system 100 may include a control system 134 configured to control operation of all or a portion of the well system 100, such as the solid state pump 116. In some embodiments, the control system 134 may be located at or adjacent the wellhead 102. In such embodiments, the control system 134 may include a display or terminal viewable by an operator to evaluate the status of the well system 100. In other embodiments, however, the control system 134 may be remotely located and accessible by an operator via wired or wireless communication. In yet other embodiments, the control system 134 may be located downhole, such as forming part of the solid state pump 106. In such embodiments, the control system 134 may comprise an autonomous or automatic controller programmed to control operation of the solid state pump 116 without requiring data or command signals sent from the surface location 104.
The well system 100 may further include one or more sensors configured to detect a variety of downhole parameters and communicate with the control system 134. It is contemplated herein that one or more sensors may be present within the wellbore 106 at any suitable location. In at least one embodiment, for example, a first sensor 136 a may be operatively coupled to or form an integral part of the solid state pump 116. The first sensor 136 a may be configured to detect process parameters relating to operation of the solid state pump 116 and communicate with the control system 134. When the control system 134 is located at the surface location, the first sensor 136 a may communicate with the control system 134 via the conveyance 120, but may otherwise communicate wirelessly with the control system 134. The control system 134 may include computer hardware and a processor (e.g., microprocessor) configured to execute one or more sequences of instructions, programming stances, or code stored on a non-transitory, computer-readable medium. Based on signals received from the first sensor 136 a, the control system 134 may be configured to alter or control operation of the solid state pump 116.
Moreover, in at least one embodiment, a second sensor 136 b may be positioned at or near the surface location 104, such as at or near the wellhead 102. The second sensor 136 b may also be configured to monitor downhole parameters, but at or near the wellhead 102, and communicate data and signals to the control system 134. While the second sensor 136 b is depicted as being arranged outside the wellbore 106, it is contemplated herein that the second sensor 136 b (or an additional third sensor) may be arranged within the wellbore 106 at or near the wellhead 102, without departing from the scope of the disclosure.
The first and second sensors 136 a,b may comprise any suitable instrument configured to detect one or more downhole parameters. Example downhole parameters include, but are not limited to, downhole temperature, downhole pressure, pressure and temperature at an inlet to the solid state pump 116, inlet flow rate into the solid state pump 116, pressure and temperature at an outlet of the solid state pump 116, the temperature of the solid state pump 116, internal pressure(s) of the solid state pump 116, discharge flow rate from the solid state pump 116, system vibration, other pump system electrical/mechanical characteristics, downhole flow rate, pressure and temperature at or near the wellhead 102, flowrate of gases or liquids out of the wellbore 106, or any combination thereof
Data obtained from the sensors 136 a,b allows the control system 134 to report and/or display operating conditions of the well system 100 and, more particularly, the solid state pump 116. Based on data obtained by the sensors 136 a,b, the control system 134 may be programmed to maintain a target liquid level within the wellbore 106 above the solid state pump 116. This may include increasing a discharge flow rate of pressurized wellbore liquid 128 generated by the solid state pump 116 to decrease the liquid level within the wellbore 106 and/or decreasing the discharge flow rate to increase the liquid level. In other embodiments, the control system 134 may be programmed to regulate the discharge flow rate to control the discharge pressure from the solid state pump 116 and thereby prevent deadheading against a closed valve at the wellhead 102. This may include increasing the discharge flow rate to increase the discharge pressure and/or decreasing the discharge flow rate to decrease the discharge pressure. In other embodiments, the control system 134 may be programmed to shut off the solid state pump 116 when a certain system parameter (such as temperature) exceeds or drops below a programmed window (threshold).
Unlike traditional rod pump systems, the solid state pump 116 may operate without utilizing a reciprocating mechanical linkage extending to the surface location 104. This may allow the solid state pump 116 to be utilized in long, deep, and/or deviated wellbores where traditional rod pump systems may be ineffective, inefficient, or otherwise unable to generate the pressurized wellbore liquid 128. Moreover, the solid state pump 116 may generate pressurized wellbore liquid 128 without requiring a threshold minimum pressure of wellbore gas 130. This may allow the solid state pump 116 to be utilized in hydrocarbon wells that do not develop sufficient gas pressure to permit utilization of traditional plunger lift systems.
Furthermore, the solid state pump 116 may operate as a positive displacement pump and thus may be sized, designed, and/or configured to generate pressurized wellbore liquid 128 at a pressure that is sufficient to convey the pressurized wellbore liquid 128 to the surface location 104 without utilizing a large number of pumping stages. Reducing the number of pumping stages correspondingly decreases the length of solid state pump 116. In some embodiments, for example, the solid state pump 116 may include fewer than five stages or a single stage.
FIG. 2 is an enlarged partial cross-sectional view of a portion of the well system 100 of FIG. 1. FIG. 2 also depicts an enlarged schematic view of one example embodiment of the solid state pump 116. As illustrated, the solid state pump 116 is positioned within the production tubing 112, and the production tubing 112 is extended within the casing 110. In the illustrated embodiment, the sealing assembly 126 comprises an expandable packer used to receive and secure the solid state pump 116 within the production tubing 112. The casing 110 includes a plurality of perforations 202 that provide fluid communication between the wellbore 106 and the surrounding subterranean formation 108.
The solid state pump 116 may include a housing 204 and a solid state actuator 206 may be positioned at least partially within the housing 204. The housing 204 may at least partially define a pressure chamber 208, and the solid state actuator 206 may be actuatable to extend at least partially into the pressure chamber 208, as shown by the dashed lines. The housing 204 may provide or otherwise define one or more inlet ports 210 a (one shown) that places the pressure chamber 208 in fluid communication with the wellbore liquid 127 that may be present within the wellbore 106. The housing 204 may also provide or otherwise define one or more outlet ports 210 b (two shown) that place the pressure chamber 208 in fluid communication with the interior of the production tubing 112.
The solid state actuator 206 may include, but is not limited to a piezoelectric actuator, an electrostrictive actuator, a magnetorestrictive actuator, or any combination thereof. In some embodiments, the solid state actuator 206 may be made of a ceramic perovskite material, where the ceramic perovskite material may comprise lead zirconate titanate or lead magnesium niobate. In other embodiments, the solid state actuator 206 may alternatively be made of terbium dysprosium iron.
During an intake stroke of the solid state pump 116, the solid state actuator 206 may selectively transition from an extended state (shown in dashed lines) to a contracted state. In contrast, during an exhaust stroke, the solid state actuator 206 may transition from the contracted state to the extended state. During the intake stroke, the wellbore liquid 127 may be drawn into the pressure chamber 208 from the wellbore 106 via the inlet port 210 a. In contrast, during the exhaust stroke, the pressurized wellbore liquid 128 may be discharged from the pressure chamber 208 via the outlet ports 210 b.
In some embodiments, actuating the solid state actuator 206 between the extended and contracted states may result from receipt of an electric current, such as an AC (or DC) electric current. In such embodiments, the discharge flow rate of the pressurized wellbore liquid 128 generated by the solid state pump 116 may be controlled, regulated, and/or varied by controlling, regulating, and/or varying the frequency of an AC (or DC) electric current provided to the solid state actuator 206. In some embodiments, the control system 134 (FIG. 1) may be programmed to control the frequency of the AC (or DC) electric current provided to the solid state actuator 206, thus controlling the discharge flow rate. This may include increasing the frequency of the AC (or DC) electric current to increase the discharge flow rate and/or decreasing the frequency of the AC (or DC) electric current to decrease the discharge flow rate.
In some embodiments, the solid state actuator 206 may be configured to operate at or near its resonant frequency. Illustrative, non-exclusive examples of the frequency of the AC (or DC) electric current include frequencies of at least 0.01 Hertz (Hz), at least 0.05 Hz, at least 0.1 Hz, at least 0.5 Hz, at least 1 Hz, at least 5 Hz, at least 10 Hz, at least 20 Hz, at least 30 Hz, at least 40 Hz, at least 60 Hz, at least 80 Hz, and/or at least 100 Hz. Additional illustrative, non-exclusive examples of the frequency of the AC (or DC) electric current include frequencies of less than 4000 Hz, less than 3500 Hz, less than 3000 Hz, less than 2500 Hz, less than 2000 Hz, less than 1500 Hz, less than 1000 Hz, less than 750 Hz, less than 500 Hz, less than 250 Hz, less than 200 Hz, less than 150 Hz, and/or less than 100 Hz. Further illustrative, non-exclusive examples of the frequency of the AC (or DC) electric current include frequencies in any range of the preceding minimum and maximum frequencies.
The solid state pump 116 may include one or more check valves to help regulate fluid flow through the pressure chamber 208 and thereby facilitate the creation and pumping of the pressurized wellbore liquid 128 from the wellbore 106 via the production tubing 112. More particularly, one or more first check valves 214 a (one shown) may be arranged between the inlet port 210 a and the pressure chamber 208, and one or more second check valves 214 b (two shown) may be arranged between the pressure chamber 208 and the outlet ports 210 b. The first and second check valves 214 a,b may comprise any suitable structure that allows fluid flow in one direction, but prevents the fluid from flowing in the opposite direction. Accordingly, the first check valve 214 a may permit the wellbore liquid 127 to enter the pressure chamber 208, but resist, restrict, and/or block the pressurized wellbore liquid 128 from reversing back into the wellbore 106. Moreover, the second check valves 214 b may permit the pressurized wellbore liquid 128 to exit the pressure chamber 208 via the outlet ports 210 b, but resist, restrict, and/or block the pressurized wellbore liquid 128 from reversing back into the pressure chamber 208.
In some embodiments, the first and second check valves 214 a,b may be passive devices that are mechanically actuated based on fluid flow. In such embodiments, the first and second check valves 214 a,b may comprise passive one-way disc valves. In other embodiments, however, the first and second check valves 214 a,b may be active devices that are electrically actuated and/or electrically controlled. In such embodiments, the first and second check valves 214 a,b may comprise any type of electrically controlled check valve such as, but not limited to, an active microvalve array, an active micro electromechanical system (MEMS) valve array or a combination thereof. The control system 134 (FIG. 1) may be in communication with the first and second check valves 214 a,b to control operation thereof. As the first and second check valves 214 a,b operate, the wellbore gas 130 may flow within the annulus 132 defined between the casing 110 and the production tubing 112.
In the illustrated embodiment, the first sensor 136 a is arranged at or near the inlet port 210 a to detect a plurality of downhole parameters at that location. A third sensor 136 c may be arranged at or near the outlet ports 210 b to likewise detect downhole parameters at that location. Data obtained by the first and third sensors 136 a,c may be communicated to the control system 134 (FIG. 1) to help regulate operation of the solid state pump 116.
FIG. 3 is an enlarged schematic view of another example embodiment of the solid state pump 116 that may be used in the well system 100. Like numerals used in both FIG. 2 and FIG. 3 refer to like components not described again. As illustrated, the solid state pump 116 is extended into the production tubing 112 on the conveyance 120, and the production tubing 112 is extended within the casing 110. In the illustrated embodiment, the sealing assembly 126 comprises a profile seat 302 positioned within the production tubing 112 and configured to engage a corresponding radial extension 304 coupled to or forming part of the solid state pump 116. In some embodiments, the profile seat 302 may comprise a locking groove structured and arranged to matingly engage the radial extension 304.
The solid state actuator 206 may be positioned within the housing 204 and actuatable to draw the wellbore liquid 127 into the pressure chamber 208, and discharge pressurized wellbore liquid 128. The inlet port 210 a is provided on the housing 204 to place the pressure chamber 208 in fluid communication with the wellbore liquid 127, and the outlet ports 210 b (one shown) are provided on the housing 204 to place the pressure chamber 208 in fluid communication with the interior of the production tubing 112. The first check valve 214 a is arranged between the inlet port 210 a and the pressure chamber 208, and the second check valves 214 b (one shown) are arranged between the pressure chamber 208 and the outlet ports 210 b.
In some embodiments, the solid state pump 116 may include a barrier 306 configured to isolate the solid state actuator 206 from the pressure chamber 208 and thereby isolate the wellbore liquid 127 from the solid state actuator 206. This may prove advantageous in preventing wellbore liquids containing particulates from directly contacting the solid state actuator 206. In some embodiments, the barrier 306 may comprise a piston movable into and out of the pressure chamber 208 based on actuation of the solid state actuator 206. In such embodiments, the solid state pump 116 may be characterized as a piston pump or the like. In other embodiments, however, the barrier 306 may comprise a flexible isolation structure that is movable into and out of the pressure chamber 208 based on actuation of the solid state actuator 206. In such embodiments, the flexible isolation structure may comprise, for example, a diaphragm, an isolation coating, or a combination thereof, and the solid state pump 116 may be characterized as a diaphragm pump. In yet other embodiments, the barrier 306 may comprise a sealing structure, such as an O-ring or the like.
In some embodiments, the system 100 may further include a well screen or filter 308 in fluid communication with the inlet port 210 a of the solid state pump 116. As illustrated, the filter 308 may include a screen 310 through which the wellbore liquid 127 may pass, but sand and debris (e.g., fluid particulates) of a predetermined size may be prevented from passing therethrough. Accordingly, the screen 310 may operate as a sand screen. Moreover, however, the screen 310 may also be configured to restrict flow of the wellbore gas 130 therethrough and into the solid state pump 116.
In at least one embodiment, the filter 308 may further include a standing valve 312 designed to allow the wellbore liquid 127 to pass uphole, but prevent the wellbore liquid 127 from reversing back into the wellbore 106 below the filter 308. Accordingly, the standing valve 312 may operate as a one-way check valve. In at least one embodiment, the standing valve 312 may comprise a velocity fuse structured and arranged to back-flush the filter 308 and maintain a column of fluid within the production tubing 112 in response to an increase in pressure drop across the filter 308.
FIG. 4 is a schematic diagram of an example positive-displacement solid state pump 402, according to embodiments of the present disclosure. The positive-displacement solid state pump 402 (hereafter “the solid state pump 402”) may be the same as or similar to the solid state pump 116 of FIGS. 1-3 and, therefore, may be best understood therewith. In some embodiments, the solid state pump 402 may replace the solid state pump 116 (or any other solid state pump described herein) in any of the embodiments discussed herein.
As illustrated, the solid state pump 402 may include a housing 404 and a solid state actuator 406 may be positioned at least partially within the housing 404. The solid state actuator 406 may be similar to the solid state actuator 206 of FIGS. 2-3 and, in the illustrated embodiment, may comprise a piezoelectric actuator stack. A power source 408 may be communicably coupled to the solid state actuator 406 to provide power thereto, such as AC (or DC) current. In some embodiments, the power source 408 may comprise a surface power source, such as the surface power source 122 of FIG. 1. In other embodiments, however, the power source 408 may comprise a downhole power source, such as the onboard power source 124 of FIG. 1, without departing from the scope of the disclosure. In either scenario, the power source 408 may be in communication with the control system 134 (FIG. 1), which may control operation of the solid state pump 402. A frequency modulator 410 and an amplitude modulator 412 may be connected in series, and can be adjusted to vary the frequency and amplitude of the signal conveyed to the solid state actuator 406.
The housing 404 may at least partially define a pressure chamber 414 and a barrier 416 may be arranged to isolate the solid state actuator 406 from the pressure chamber 414. In the illustrated embodiment, the barrier 416 comprises a flexible diaphragm, but could alternatively comprise any of the other example barriers mentioned herein. The housing 404 may also provide or otherwise define an inlet port 418 a and an outlet port 418 b. A first check valve 420 a interposes the inlet port 418 a and the pressure chamber 414 and controls fluid flow into the pressure chamber 414. Similarly, a second check valve 420 b interposes the outlet port 418 b and the pressure chamber 414 and controls fluid flow out of the pressure chamber 414.
Similar to the first and second check valves 214 a,b of FIGS. 2-3, the first and second check valves 420 a,b may be passive or active devices. More specifically, the first and second check valves 420 a,b may be mechanically actuated based on fluid flow or may be electrically actuated and/or electrically controlled. In embodiments where the first and second check valves 420 a,b are mechanically actuated (passive), the first and second check valves 420 a,b may comprise passive one-way disc valves. In embodiments where the first and second check valves 420 a,b are electrically controlled (active), the first and second check valves 420 a,b may be communicably coupled to the power source 408 and the control system 134 to power and operate (e.g., open or close) the first and second check valves 420 a,b. Moreover, in such embodiments, the first and second check valves 420 a,b may comprise any type of electrically controlled check valve such as, but not limited to, an active microvalve array, an active micro electromechanical system (MEMS) valve array or a combination thereof
Referring now to FIGS. 5A and 5B, with continued reference to FIG. 4, example operation of the solid state pump 402 is depicted, according to one or more embodiments. As voltage (or current) is applied to the solid state actuator 406 via the power source 408 (FIG. 4), the solid state actuator 406 will expand and contract in response to the supplied signal, which causes the barrier 416 to flex (bend) up and down in a piston-like fashion.
In FIG. 5A, when the barrier 416 flexes downward, the pressure chamber 414 experiences a pressure drop, which causes the first check valve 420 a to open and permit the flow of fluid into the pressure chamber 414. The pressure drop correspondingly urges the second check valve 420 b to close and thereby prevent a back flow of fluid from the outlet port 418 b into the pressure chamber 414. In embodiments where the first and second check valves 420 a,b are electrically controlled, however, the control system 134 may operate (open and close) the first and second check valves 420 a,b based on a predetermined operational program or otherwise based on detected pressures within the pressure chamber 414.
In FIG. 5B, when the barrier 416 flexes upward, the pressure chamber 414 experiences an increase in pressure, which causes the second check valve 420 b to open and permit fluid flow out of the pressure chamber 414. The pressure increase correspondingly urges the first check valve 420 a to close and thereby prevent a back flow of fluid from the pressure chamber 414 into the inlet port 418 a. In embodiments where the first and second check valves 420 a,b are electrically controlled, the control system 134 may operate (open and close) the first and second check valves 420 a,b based on a predetermined operational program or otherwise based on detected pressures within the pressure chamber 414. This process may be repeated to enable to solid state pump 402 to continuously pump fluid from the inlet port 418 a to the outlet port 418 b.
FIG. 6 is an enlarged schematic view of another example pump 602 that may be used in the well system 100 of FIG. 1, according to one or more embodiments of the present disclosure. The pump 602 may be similar in some respects to the pump 116 of FIGS. 1-3 and thus may be best understood with reference thereto. In some embodiments, the pump 602 may replace the pump 116. Accordingly, the pump 602 may be conveyed into the wellbore 106 via the conveyance 120, and the pump 602 may be communicably coupled to the control system 134, which may control the pump 602. The control system 134 may be arranged either at the surface location 104 (FIG. 1) or otherwise included in the pump 602.
As illustrated, the pump 602 may include a housing 604 that contains or otherwise houses a first pump 606 and a second pump 608. In at least one embodiment, however, at least one of the pumps 606, 608 may be positioned outside of the housing 604, such as forming part of another downhole tool or component operatively coupled to the housing 604 or the conveyance 120. The first pump 606 may comprise a positive-displacement solid state pump, similar to or the same as the solid state pump 116 of FIGS. 1-3 or the solid state pump 402 of FIGS. 4 and 5A-5B. Accordingly, the first pump 606 may be referred to herein as the solid state pump 606, and may include a solid state actuator 611 actuatable to extend at least partially into a pressure chamber 612 defined in the housing 604, as shown by the dashed lines. The solid state actuator 611 may be the same as or similar to the solid state actuators 206 and 406 discussed herein, and thus may include, but is not limited to a piezoelectric actuator, an electrostrictive actuator, a magnetorestrictive actuator, or any combination thereof
The solid state pump 606 may be in fluid communication with the second or “secondary” pump 608 via a fluid circuit 610. In some embodiments, as illustrated, the fluid circuit 610 may be arranged or otherwise contained within the housing 604. In other embodiments, however, a portion of the fluid circuit 610 may be positioned external to the housing 604. As described herein, the solid state pump 606 and the secondary pump 608 may cooperatively operate to draw the wellbore liquid 127 into the pump 602, pressurize the wellbore liquid 127, and discharge the pressurized wellbore liquid 128 from the pump 602 into the production tubing 112 for production to the surface location 104 (FIG. 1). In at least one embodiment, the solid state pump 606 may operate as the “power end” to the pump 602, while the secondary pump 608 may operate as the “fluid end” to the pump 602.
In the illustrated embodiment, the secondary pump 608 comprises one or more expansion pumps, shown as a first expansion pump 614 a and a second expansion pump 614 b. While two expansion pumps 614 a,b are depicted, it is contemplated herein that a single expansion pump (or more than two) may be employed, without departing from the scope of the disclosure.
In the illustrated embodiment, the expansion pumps 614 a,b are configured to operate in parallel within the fluid circuit 610. Each expansion pump 614 a,b includes an expandable member 616 positioned within a corresponding expansion tank 618. In some embodiments, the expandable member 616 may comprise an elastomer bladder, but in other embodiments, the expandable member 616 may comprise a metal bellows. In yet other embodiments, the expandable member 616 may comprise a combination of an elastomer bladder and a metal bellows.
In some embodiments, the housing 604 may provide or otherwise define one or more inlet ports, shown as a first inlet port 620 a and a second inlet port 620 b. The first expansion pump 614 a may be in fluid communication with the wellbore liquid 127 via the first inlet port 620 a, and the second expansion pump 614 b may be in fluid communication with the wellbore liquid 127 via the second inlet port 620 b. In the illustrated embodiment, the expansion tanks 618 of the first and second expansion pumps 614 a,b are fluidly coupled to the first and second inlet ports 620 a,b, respectively. In other embodiments, however, the expandable member 616 of the first and second expansion pumps 614 a,b may alternatively be fluidly coupled to the first and second inlet ports 620 a,b, respectively, without departing from the scope of the disclosure.
In some embodiments, the housing 604 may further provide or otherwise define one or more outlet ports, shown as a first outlet port 622 a, and a second outlet port 622 b. The first expansion pump 614 a may be in fluid communication with the interior of the production tubing 112 via the first outlet port 622 a, and the second expansion pump 614 b may be in fluid communication with the interior of the production tubing 112 via the second outlet port 622 b. In the illustrated embodiment, the expansion tanks 618 of the first and second expansion pumps 614 a,b are fluidly coupled to the first and second outlet ports 622 a,b, respectively. In other embodiments, however, the expandable members 616 of the first and second expansion pumps 614 a,b may alternatively be fluidly coupled to the first and second outlet ports 622 a,b, respectively, without departing from the scope of the disclosure.
While the inlet ports 620 a,b and the outlet ports 622 a,b are each depicted as being provided or otherwise defined by the housing 604, it is contemplated herein that some or all of the inlet ports 620 a,b and the outlet ports 622 a,b may be provided or otherwise defined by another downhole tool or component operatively coupled to the housing 604 or the conveyance 120.
Actuation of the expansion pumps 614 a,b may cause the wellbore liquid 127 to be drawn into the pump 602 and subsequently discharged as pressurized wellbore liquid 128 into the production tubing 112. The expansion pumps 614 a,b may be actuated by repeatedly expanding and contracting the expandable member 616 of each expansion pump 614 a,b. In the illustrated embodiment, actuation of the expansion pumps 614 a,b causes the wellbore liquid 127 to be drawn into the respective expansion tank 618 and subsequently discharged as pressurized wellbore liquid 128. In other embodiments, however, actuating the expansion pumps 614 a,b may draw the wellbore liquid 127 into the respective expandable member 616, which may subsequently discharge the pressurized wellbore liquid 128.
In the illustrated embodiment, the expandable members 616 may be actuated (expanded and contracted) by circulating a hydraulic fluid through the fluid circuit 610 and, more particularly, through each expandable member 616. In other embodiments, however, the expandable members 616 may be actuated (expanded and contracted) by circulating a hydraulic fluid through the respective expansion chambers 618. In such embodiments, the circulating hydraulic fluid within the expansion chambers 618 acts on and causes the expandable members 616 to expand and contract. The hydraulic fluid may be made of, but is not limited to, a mineral oil, a dielectric oil, water, a fluid with specific additives to promote system reliability, or any combination thereof.
The solid state pump 606 may be operable to circulate the hydraulic fluid through the fluid circuit 610, and thereby actuate the expansion pumps 614 a,b. More particularly, the solid state pump 606 may include an inlet 624 a that receives the hydraulic fluid into the pressure chamber 612, and an outlet 624 b that discharges pressurized hydraulic fluid from the pressure chamber 612. Actuating the solid state actuator 611 may draw the hydraulic fluid into the pressure chamber 612 and subsequently discharge the pressurized hydraulic fluid toward the expansion pumps 614 a,b. In some embodiments, the fluid circuit 610 may be a closed loop system, which may prove advantageous in mitigating damage to the solid state pump 606 that might ensue from circulating a fluid with foreign particulate matter (e.g., the wellbore liquid 127) therethrough.
In some embodiments, the pump 602 may further include a switching valve 626 arranged in the fluid circuit 610 and interposing the solid state pump 606 and the secondary pump 608. The switching valve 626 may be configured to coordinate hydraulic fluid flow within the fluid circuit 610 and, more particularly, between the first and second expansion pumps 614 a,b as needed. In some embodiments, the switching valve 626 may be communicably coupled to the control system 134, which may be programmed to operate the switching valve 626.
In example operation, the switching valve 626 may be in a first state where hydraulic fluid flow is provided to actuate the first expansion pump 614 a and thereby discharge pressurized wellbore liquid 128 via the first outlet 622 a. In the illustrated embodiment, the hydraulic fluid may be conveyed into the expandable member 616 of the first expansion pump 614 a, which progressively compresses the wellbore liquid 127 present within the expansion tank 618 and eventually urges the pressurized wellbore liquid 128 out of the expansion tank 618. In other embodiments, however, the hydraulic fluid may alternatively be conveyed into the expansion tank 618 of the first expansion pump 614 a, which progressively acts on the wellbore liquid 127 that may be present within the expandable member 616 and eventually urges the pressurized wellbore liquid 128 out of the expandable member 616.
With the switching valve 626 in the first state, hydraulic fluid may be also be received from the second expansion pump 614 b. More specifically, in the illustrated embodiment, as the expandable member 616 of the second expansion pump 614 b contracts toward its natural state, hydraulic fluid within the expandable member 616 may be conveyed to the switching valve 626, which conveys the hydraulic fluid to the pressure chamber 612 to be pressurized. As the expandable member 616 contracts, additional wellbore liquid 127 may be drawn into the expansion chamber 618 of the second expansion pump 614 b.
The switching valve 626 may then be actuated or “switched” to a second state where hydraulic fluid flow is provided to actuate the second expansion pump 614 b and thereby discharge pressurized wellbore liquid 128 via the second outlet 622 b. In the illustrated embodiment, the hydraulic fluid may be conveyed into the expandable member 616 of the second expansion pump 614 b, which progressively compresses the wellbore liquid 127 present within the expansion tank 618 and eventually urges the pressurized wellbore liquid 128 out of the expansion tank 618. In other embodiments, however, the hydraulic fluid may alternatively be conveyed into the expansion tank 618 of the second expansion pump 614 b, which progressively acts on the wellbore liquid 127 that may be present within the expandable member 616 and eventually urges the pressurized wellbore liquid 128 out of the expandable member 616.
With the switching valve 626 in the second state, hydraulic fluid may be also be received from the first expansion pump 614 a. More specifically, in the illustrated embodiment, as the expandable member 616 of the first expansion pump 614 a contracts toward its natural state, hydraulic fluid within the expandable member 616 may be conveyed to the switching valve 626, which conveys the hydraulic fluid to the pressure chamber 612 to be pressurized. As the expandable member 616 contracts, additional wellbore liquid 127 may be drawn into the expansion chamber 618 of the first expansion pump 614 a.
The switching valve 626 may be repeatedly operated as described above to continuously discharge the pressurized wellbore liquid 128 into the production tubing 112 for production to the surface location 104 (FIG. 1).
One or more check valves may be included in the pump 602 to help regulate fluid flow through each expansion pump 614 a,b and thereby help facilitate the creation and pumping of the pressurized wellbore liquid 128. More particularly, one or more first check valves 628 a may be arranged between the first and second inlet ports 620 a,b and the expansion pumps 614 a,b, respectively, and one or more second check valves 628 b may be arranged between each expansion pump 614 a,b and the first and second outlet ports 622 a,b, respectively. The first and second check valves 628 a,b may be passive or active devices similar to the first and second check valves 214 a,b of FIGS. 2 and 3, and, therefore, may comprise any suitable structure that allows fluid flow in one direction, but prevents the fluid from flowing in the opposite direction. The first check valves 628 a may permit the wellbore liquid 127 to enter each expansion pump 614 a,b, but resist, restrict, and/or block the wellbore liquid 127 from reversing back into the wellbore 106. Moreover, the second check valves 628 b may permit the pressurized wellbore liquid 128 to exit each expansion pump 614 a,b, but resist, restrict, and/or block the pressurized wellbore liquid 128 from reversing back into the respective expansion pump 614 a,b.
Moreover, one or more additional check valves 630 may be included in the fluid circuit 610 to help regulate hydraulic fluid flow between the solid state pump 606 and the secondary pump 608 and through the switching valve 626. As illustrated, one or more check valves 630 may interpose the pressure chamber 612 and the switching valve 626. One or more check valves 630 may also interpose the switching valve 626 and each expansion pump 614 a,b. The check valves 630 may be passive or active devices that help regulate hydraulic fluid flow through the hydraulic circuit 610. In some embodiments, some or all of the check valves 630 may comprise electrically controlled check valves in communication with the control system 134. In such embodiments, the control system 134 may operate the check valves 630 to ensure proper fluid flow to generate the pressurized wellbore liquid 128.
In some embodiments, the pump 602 may further include one or more sensors used to monitor operation of the secondary pump 608. In the illustrated embodiment, for example, a first sensor 632 a may be included in or otherwise associated with the first expansion pump 614 a, and a second sensor 632 b may be included in or otherwise associated with the second expansion pump 614 b. In some embodiments, the first and second sensors 632 a,b may be in communication with the control system 134 and used to determine when an expandable member 616 has reached an expansion/contraction limit and thereby help trigger a change in the flow path of the pumped hydraulic fluid so that the other expandable member 616 might be filled/emptied. The sensors 632 a,b may comprise mechanical and/or electrical sensors such as, but not limited to, a position sensor, a volumetric sensor, a pressure sensor, a tensile sensor, or any combination thereof. In at least one embodiment, outputs from the sensors 632 a,b may be conveyed to the control system 134 to trigger actuation of the switching valve 626 and thereby alter the hydraulic fluid flow path. Alternatively, the switching valve 626 may be actuated based on a pre-programmed timer that determines switch activation and frequency.
FIG. 7 is an enlarged schematic view of another example pump 702 that may be used in the well system 100 of FIG. 1, according to one or more embodiments of the present disclosure. The pump 702 may be similar in some respects to the pump 602 of FIG. 6 and therefore may be best understood with reference thereto, where like numerals will represent like components not described again in detail. Similar to the pump 602 of FIG. 6, the pump 702 may replace the pump 116 of FIGS. 1-3. Accordingly, the pump 702 may be conveyed into the wellbore 106 via the conveyance 120, and the pump 702 may be communicably coupled to the control system 134, which may control operation of the pump 702. The control system 134 may be arranged either at the surface location 104 (FIG. 1) or otherwise included in the pump 702.
As illustrated, the pump 702 includes the solid state pump 606 positioned within the housing 604. The pump 702 further includes a secondary pump 704 that may also be positioned within the housing 604 or alternatively form part of another downhole tool or component operatively coupled to the housing 604 or the conveyance 120. The solid state pump 606 may be in fluid communication with the secondary pump 704 via a fluid circuit 706. In some embodiments, as illustrated, the fluid circuit 706 may be arranged or otherwise contained within the housing 604. In other embodiments, however, a portion of the fluid circuit 706 may be positioned external to the housing 604.
The solid state pump 606 and the secondary pump 704 may cooperatively operate to draw the wellbore liquid 127 into the pump 702, pressurize the wellbore liquid 127, and discharge the pressurized wellbore liquid 128 from the pump 702 into the production tubing 112 for production to the surface location 104 (FIG. 1). In at least one embodiment, the solid state pump 606 may operate as the “power end” to the pump 702, while the secondary pump 704 may operate as the “fluid end” to the pump 702.
In the illustrated embodiment, the secondary pump 704 comprises a hydraulic motor 708 operatively coupled to a fluid pump 710 with a drive shaft 712. The hydraulic motor 708 may be configured to convert hydraulic pressure and flow into torque and angular displacement (rotation) of the drive shaft 712, which causes actuation of the fluid pump 710. The fluid pump 710 may comprise any type of pump configured to pressurize and discharge a pressurized fluid. The fluid pump 710 may include, but is not limited to, a centrifugal pump, a rotary screw pump, a rotary lobe pump, a gerotor pump, a progressive cavity pump, or any combination thereof.
In some embodiments, the housing 604 may provide or otherwise define one or more inlet ports 714 (one shown). The fluid pump 710 may be in fluid communication with the wellbore liquid 127 via the inlet port 714. The housing 604 may further provide or otherwise define one or more outlet ports 716 (two shown). The fluid pump 710 may be in fluid communication with the interior of the production tubing 112 via the outlet ports 716. While the inlet and outlet ports 714, 716 are depicted as being provided or otherwise defined by the housing 604, it is contemplated herein that some or all of the inlet and outlet ports 714, 716 may be provided or otherwise defined by another downhole tool or component operatively coupled to the housing 604 or the conveyance 120.
Actuation of the fluid pump 710 may cause the wellbore liquid 127 to be drawn into the pump 702 and subsequently discharged as pressurized wellbore liquid 128 into the production tubing 112. The fluid pump 710 may be actuated by rotating the drive shaft 712, and actuating the fluid pump 710 causes the wellbore liquid 127 to be drawn into the fluid pump 710 and subsequently discharged as pressurized wellbore liquid 128. The drive shaft 712 may be rotated by circulating a hydraulic fluid through the fluid circuit 706 and, more particularly, through the hydraulic motor 708. As with the embodiment of FIG. 6, the hydraulic fluid may be made of, but is not limited to, a mineral oil, a dielectric oil, water, or any combination thereof.
The solid state pump 606 may be operable to circulate the hydraulic fluid through the fluid circuit 706, and thereby actuate the hydraulic motor 708. More particularly, actuating the solid state actuator 611 may draw the hydraulic fluid into the pressure chamber 612 via the inlet 624 a and subsequently discharge the pressurized hydraulic fluid toward the hydraulic motor 708 via the outlet 624 b. Accordingly, the pump 702 may be configured to convert the reciprocating motion of the solid state actuator 611 into a rotating motion of the drive shaft 712 at the hydraulic pump 708, which drives (actuates) the fluid pump 710.
One or more check valves may be included in the pump 702 to help regulate fluid flow through the fluid pump 710 and thereby help facilitate the creation and pumping of the pressurized wellbore liquid 128. More particularly, one or more first check valves 718 a (one shown) may be arranged between the inlet port 714 and the fluid pump 710, and one or more second check valves 718 b (two shown) may be arranged between the fluid pump 710 and the outlet ports 716. The first and second check valves 718 a,b may be passive or active devices similar to the first and second check valves 214 a,b of FIGS. 2 and 3, and, therefore, may comprise any suitable structure that allows fluid flow in one direction, but prevents the fluid from flowing in the opposite direction. The first check valve 718 a may permit the wellbore liquid 127 to the fluid pump 710, but resist, restrict, and/or block the wellbore liquid 127 from reversing back into the wellbore 106. Moreover, the second check valves 718 b may permit the pressurized wellbore liquid 128 to exit the fluid pump 710, but resist, restrict, and/or block the pressurized wellbore liquid 128 from reversing back into the fluid pump 710.
Moreover, one or more additional check valves 720 may be included in the fluid circuit 706 to help regulate hydraulic fluid flow between the solid state pump 606 and the secondary pump 704. As illustrated, one or more check valves 720 may interpose the pressure chamber 612 and the hydraulic pump 708. The check valves 720 may be passive or active devices that help regulate hydraulic fluid flow through the hydraulic circuit 706. In some embodiments, some or all of the check valves 720 may be electrically controlled and in communication with the control system 134. In such embodiments, the control system 134 may operate the check valves 720 to ensure proper fluid flow to generate the pressurized wellbore liquid 128.
Consistent with any of the embodiments described herein, it is contemplated to include multiple pumps (e.g., solid state pump) installed in the well system 100, without departing from the scope of the disclosure. As will be appreciated, this would increase the maximum volume flow possible. Each independent pump would need to have an independent inlet, but their outlets may be combined to reduce the total number of flow conduits necessary.
Embodiments disclosed herein include:
A. A pump that includes a solid state pump including a solid state actuator actuatable to pressurize a hydraulic fluid, and a secondary pump in fluid communication with the solid state pump via a fluid circuit, wherein the secondary pump is actuatable with the hydraulic fluid received from the solid state pump, and wherein actuating the secondary pump draws in an external fluid into the secondary pump, pressurizes the external fluid within the secondary pump, and discharges a pressurized external fluid.
B. A well system that includes a pump arrangeable within production tubing extended within a wellbore, the pump including a solid state pump including a solid state actuator actuatable to pressurize a hydraulic fluid, and a secondary pump in fluid communication with the solid state pump via a fluid circuit, wherein the secondary pump is actuatable with the hydraulic fluid received from the solid state pump. The well system further including a control system communicably coupled to the pump to control operation of the pump, wherein actuating the secondary pump draws a wellbore liquid into the secondary pump, pressurizes the wellbore liquid within the secondary pump, and discharges a pressurized wellbore liquid into the production tubing for production to a surface location.
C. A method that includes positioning a pump within production tubing extended within a wellbore, the pump including a solid state pump having a solid state actuator, and a secondary pump in fluid communication with the solid state pump via a fluid circuit, actuating the solid state actuator and thereby conveying a hydraulic fluid to the secondary pump via the fluid circuit, actuating the secondary pump with the hydraulic fluid received from the solid state pump and thereby drawing a wellbore liquid into the secondary pump and pressurizing the wellbore liquid within the secondary pump, discharging a pressurized wellbore liquid from the secondary pump and into the production tubing for production to a surface location, and controlling operation of the pump with a control system communicably coupled to the pump.
Each of embodiments A, B, and C may have one or more of the following additional elements in any combination: Element 1: wherein the solid state actuator is selected from the group consisting of a piezoelectric actuator, an electrostrictive actuator, a magnetorestrictive actuator, and any combination thereof. Element 2: further comprising one or more check valves that control flow of the hydraulic fluid and the external fluid. Element 3: wherein the secondary pump comprises one or more expansion pumps, and each expansion pump includes an expansion tank and an expandable member positioned within the expansion tank. Element 4: wherein the expandable member comprises at least one of an elastomer bladder and a metal bellows. Element 5: wherein the one or more expansion pumps comprise a first expansion pump and a second expansion pump, and wherein the pump further comprises a switching valve arranged in the fluid circuit to coordinate hydraulic fluid flow between the solid state pump and the first and second expansion pumps. Element 6: wherein the secondary pump comprises a hydraulic motor in fluid communication with the solid state pump to receive the hydraulic fluid and thereby rotate a drive shaft, and a fluid pump operatively coupled to the hydraulic motor via the drive shaft, wherein the external fluid is drawn into the fluid pump and pressurized upon rotating the drive shaft. Element 7: wherein the fluid pump is selected from the group consisting of a centrifugal pump, a rotary screw pump, a rotary lobe pump, a gerotor pump, a progressive cavity pump, and any combination thereof.
Element 8: further comprising one or more sensors in communication with the control system and operable to detect one or more downhole parameters, wherein operation of the pump is based on one or more signals received from the one or more sensors. Element 9: wherein the solid state actuator is selected from the group consisting of a piezoelectric actuator, an electrostrictive actuator, a magnetorestrictive actuator, and any combination thereof. Element 10: wherein the secondary pump comprises one or more expansion pumps, and each expansion pump includes an expansion tank and an expandable member positioned within the expansion tank. Element 11: wherein the expandable member comprises at least one of an elastomer bladder and a metal bellows. Element 12: wherein the one or more expansion pumps comprise a first expansion pump and a second expansion pump, the well system further comprising a switching valve arranged in the fluid circuit to coordinate hydraulic fluid flow between the solid state pump and the first and second expansion pumps. Element 13: wherein the secondary pump comprises a hydraulic motor in fluid communication with the solid state pump to receive the hydraulic fluid and thereby rotate a drive shaft, and a fluid pump operatively coupled to the hydraulic motor via the drive shaft, wherein the wellbore liquid is drawn into the fluid pump and pressurized upon rotation of the drive shaft. Element 14: wherein the fluid pump comprises a pump selected from the group consisting of a centrifugal pump, a rotary screw pump, a rotary lobe pump, a gerotor pump, a progressive cavity pump, and any combination thereof.
Element 15: further comprising detecting one or more downhole parameters with one or more sensors in communication with the control system, and controlling operation of the pump based at least partially on one or more signals received from the one or more sensors. Element 16: wherein the secondary pump comprises a first expansion pump and a second expansion pump, and wherein a switching valve is arranged in the fluid circuit, the method further comprising operating the switching valve to coordinate hydraulic fluid flow between the solid state pump and the first and second expansion pumps. Element 17: wherein the secondary pump comprises a hydraulic motor in fluid communication with the solid state pump, and a fluid pump operatively coupled to the hydraulic motor at a drive shaft extended from the hydraulic motor, the method further comprising receiving the hydraulic fluid from the solid state pump at the hydraulic motor and thereby rotating the drive shaft, and drawing the wellbore liquid into the fluid pump upon rotation of the drive shaft, and thereby pressurizing the wellbore liquid.
By way of non-limiting example, exemplary combinations applicable to A, B, and C include: Element 3 with Element 4; Element 3 with Element 5; Element 6 with Element 7; Element 10 with Element 11; Element 10 with Element 12; and Element 13 with Element 14.
Therefore, the disclosed systems and methods are well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the teachings of the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined, or modified and all such variations are considered within the scope of the present disclosure. The systems and methods illustratively disclosed herein may suitably be practiced in the absence of any element that is not specifically disclosed herein and/or any optional element disclosed herein. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the elements that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.
As used herein, the phrase “at least one of” preceding a series of items, with the terms “and” or “or” to separate any of the items, modifies the list as a whole, rather than each member of the list (i.e., each item). The phrase “at least one of” allows a meaning that includes at least one of any one of the items, and/or at least one of any combination of the items, and/or at least one of each of the items. By way of example, the phrases “at least one of A, B, and C” or “at least one of A, B, or C” each refer to only A, only B, or only C; any combination of A, to B, and C; and/or at least one of each of A, B, and C.
The use of directional terms such as above, below, upper, lower, upward, downward, left, right, uphole, downhole and the like are used in relation to the illustrative embodiments as they are depicted in the figures, the upward direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding figure, the uphole direction being toward the surface of the well and the downhole direction being toward the toe of the well.

Claims

What is claimed is:

1. A pump, comprising

a solid state pump including a solid state actuator actuatable to pressurize a hydraulic fluid; and

a secondary pump in fluid communication with the solid state pump via a fluid circuit, wherein the secondary pump is actuatable with the hydraulic fluid received from the solid state pump, and

wherein actuating the secondary pump draws in an external fluid into the secondary pump, pressurizes the external fluid within the secondary pump, and discharges a pressurized external fluid.

2. The pump of claim 1, wherein the solid state actuator is selected from the group consisting of a piezoelectric actuator, an electrostrictive actuator, a magnetorestrictive actuator, and any combination thereof.

3. The pump of claim 1, further comprising one or more check valves that control flow of the hydraulic fluid and the external fluid.

4. The pump of claim 1, wherein the secondary pump comprises one or more expansion pumps, and each expansion pump includes an expansion tank and an expandable member positioned within the expansion tank.

5. The pump of claim 4, wherein the expandable member comprises at least one of an elastomer bladder and a metal bellows.

6. The pump of claim 4, wherein the one or more expansion pumps comprise a first expansion pump and a second expansion pump, and wherein the pump further comprises a switching valve arranged in the fluid circuit to coordinate hydraulic fluid flow between the solid state pump and the first and second expansion pumps.

7. The pump of claim 1, wherein the secondary pump comprises:

a hydraulic motor in fluid communication with the solid state pump to receive the hydraulic fluid and thereby rotate a drive shaft; and

a fluid pump operatively coupled to the hydraulic motor via the drive shaft, wherein the external fluid is drawn into the fluid pump and pressurized upon rotating the drive shaft.

8. The pump of claim 7, wherein the fluid pump is selected from the group consisting of a centrifugal pump, a rotary screw pump, a rotary lobe pump, a gerotor pump, a progressive cavity pump, and any combination thereof.

9. A well system, comprising:

a pump arrangeable within production tubing extended within a wellbore, the pump including:

a secondary pump in fluid communication with the solid state pump via a fluid circuit, wherein the secondary pump is actuatable with the hydraulic fluid received from the solid state pump; and

a control system communicably coupled to the pump to control operation of the pump,

wherein actuating the secondary pump draws a wellbore liquid into the secondary pump, pressurizes the wellbore liquid within the secondary pump, and discharges a pressurized wellbore liquid into the production tubing for production to a surface location.

10. The well system of claim 9, further comprising one or more sensors in communication with the control system and operable to detect one or more downhole parameters, wherein operation of the pump is based on one or more signals received from the one or more sensors.

11. The well system of claim 9, wherein the solid state actuator is selected from the group consisting of a piezoelectric actuator, an electrostrictive actuator, a magnetorestrictive actuator, and any combination thereof.

12. The well system of claim 9, wherein the secondary pump comprises one or more expansion pumps, and each expansion pump includes an expansion tank and an expandable member positioned within the expansion tank.

13. The well system of claim 12, wherein the expandable member comprises at least one of an elastomer bladder and a metal bellows.

14. The well system of claim 12, wherein the one or more expansion pumps comprise a first expansion pump and a second expansion pump, the well system further comprising a switching valve arranged in the fluid circuit to coordinate hydraulic fluid flow between the solid state pump and the first and second expansion pumps.

15. The well system of claim 9, wherein the secondary pump comprises:

a fluid pump operatively coupled to the hydraulic motor via the drive shaft, wherein the wellbore liquid is drawn into the fluid pump and pressurized upon rotation of the drive shaft.

16. The well system of claim 15, wherein the fluid pump comprises a pump selected from the group consisting of a centrifugal pump, a rotary screw pump, a rotary lobe pump, a gerotor pump, a progressive cavity pump, and any combination thereof.

17. A method, comprising:

positioning a pump within production tubing extended within a wellbore, the pump including a solid state pump having a solid state actuator, and a secondary pump in fluid communication with the solid state pump via a fluid circuit;

actuating the solid state actuator and thereby conveying a hydraulic fluid to the secondary pump via the fluid circuit;

actuating the secondary pump with the hydraulic fluid received from the solid state pump and thereby drawing a wellbore liquid into the secondary pump and pressurizing the wellbore liquid within the secondary pump;

discharging a pressurized wellbore liquid from the secondary pump and into the production tubing for production to a surface location; and

controlling operation of the pump with a control system communicably coupled to the pump.

18. The method of claim 17, further comprising

detecting one or more downhole parameters with one or more sensors in communication with the control system; and

controlling operation of the pump based at least partially on one or more signals received from the one or more sensors.

19. The method of claim 17, wherein the secondary pump comprises a first expansion pump and a second expansion pump, and wherein a switching valve is arranged in the fluid circuit, the method further comprising operating the switching valve to coordinate hydraulic fluid flow between the solid state pump and the first and second expansion pumps.

20. The method of claim 17, wherein the secondary pump comprises a hydraulic motor in fluid communication with the solid state pump, and a fluid pump operatively coupled to the hydraulic motor at a drive shaft extended from the hydraulic motor, the method further comprising:

receiving the hydraulic fluid from the solid state pump at the hydraulic motor and thereby rotating the drive shaft; and

drawing the wellbore liquid into the fluid pump upon rotation of the drive shaft, and thereby pressurizing the wellbore liquid.