Systems and processes for subsurface pumped hydropower storage

Abstract

A subsurface pumped hydropower storage system is provided and includes an upper reservoir, and a lower reservoir within a subsurface formation. The system includes a completed well extending into the subsurface geological strata to reach the lower reservoir, the completed well has a wellhead at the surface, a casing, a tubing string extending within the casing, the tubing being adapted to establish fluid communication between the upper reservoir and the lower reservoir. An electric submersible pump (ESP) assembly operable in a turbine configuration and a pumping configuration is coupled to the tubing string, where, when in the turbine configuration, electricity is generated and transmitted to the surface via a power cable connected to the ESP assembly, and, when in the pumping configuration, electricity is consumed by the ESP assembly to pump the working fluid from the lower reservoir into the upper reservoir.

Description

SYSTEMS AND METHODS FOR SUBSURFACE PUMPED HYDROPOWER STORAGETECHNICAL FIELD

[0001] The technical field generally relates to systems and processes for generating and storing electric power, and more specifically relates to subsurface pumped hydropower storage systems and methods.BACKGROUND

[0002] Hydropower, or hydroelectric power, is one of the oldest and largest sources of renewable energy, which uses the natural flow of moving water to generate electricity. Hydropower technologies generate power by using the elevation difference, occurring naturally or manmade (e.g., created by a dam or diversion structure), of water flowing in on one side and out, far below, on the other.

[0003] As more and more organizations, companies and cities strive to go towards renewable energy, there is an increased need for energy storage. Renewable energy, such as wind power and solar energy are intermittent sources of generation, since the wind does not always blow, and the sun does not always shine. Long duration, hydropower storage solutions are therefore being developed to provide energy supply when renewable energy systems are not contributing. Renewable energy market penetration is also increasing much faster than energy storage implementation, which is either capping renewable development, or contributing to grid instability. Either way, there is a looming shortage of energy storage.

[0004] For instance, pumped hydro storage (PHS) is a type of hydroelectric energy storage. It is a configuration of two water reservoirs at different elevations that can generate power as water moves from the upper reservoir into the lower reservoir, passing through a turbine. The system also requires power as it pumps water back into the upper reservoir. PHS acts similarly to a giant battery because it can store power and then releases it when needed.

[0005] Currently, over 90% of the world’s energy storage capacity comes from pumped hydro storage, and while PHS systems can be very efficient (up to 80%), there exists some downsides. A typical PHS project can cost more than 1 billion dollars to build. In addition, the required permits, stakeholder approvals, the construction of dams to create reservoirs and the drilling of tunnels can take more than 10 years. Moreover, the creation of multiple manmade reservoirs at different elevations, can have a negative impact on valley ecosystems, which can create a backlash from the local communities. This is one of the primary reasons why new PHS systems are rarely developed.

[0006] In order to circumvent some of the known drawbacks from conventional PHS systems, underground systems have been developed, typically referred to as underground PHS or LIPHS systems. LIPHS replaces the lower reservoir with an underground cavity mined from hard rock. This configuration eliminates dependence upon fortuitous topography, provides higher hydraulic heads, and reduces environmental concerns. Although LIPHS is not a new idea and various concepts have been researched and developed, nothing has been implemented on a large scale. Therefore, LIPHS has not found commercial traction.

[0007] It would thus be particularly useful to be able to provide a renewable energy storage system which would be able to overcome or at the very least minimize some of the known drawbacks and / or deficiencies associated with conventional methods and / or devices, for example. More specifically, there is an unmet need for improved processes and systems for subsurface pumped hydropower storage.SUMMARY

[0008] According to an aspect, a subsurface pumped hydropower storage system is provided. The subsurface pumped hydropower storage system includes an upper reservoir proximate to surface and adapted to store working fluid corresponding to a fluid from a lower reservoir located within a subsurface strata; a completed well extending into the subsurface strata to reach the lower reservoir, the completed well comprising: a wellhead at the surface; a casing lining an inner surface of the well; a tubing string extending within the casing, the tubing string being adapted to establish fluid communication between the upper reservoir and the lower reservoir; a downhole tool comprising an electric submersible pump (ESP) assembly having a plurality of ESPscoupled to the tubing string and adapted to be submerged or in fluid communication with the lower reservoir, the ESP assembly being operable in a turbine configuration and a pumping configuration, wherein, when in the turbine configuration, at least one of the plurality of ESPs is adapted to generate electricity in response to the working fluid being released from the upper reservoir and flowing downhole into the lower reservoir and passing through the downhole tool, the electricity being transmitted to the surface via a power cable connected to the corresponding ESP, and when in the pumping configuration, at least one of the plurality of ESPs is adapted to use electricity received from the surface via the power cable to provide lift and pump the working fluid from the lower reservoir to the surface and into the upper reservoir.

[0009] In one implementation, the casing has a casing diameter between about 5-1 / 2” and 13”, and wherein the tubing string has a tubing diameter between about 2-7 / 8” and 10”.

[0010] In one implementation, each ESP comprises an electric motor and pump impellers, wherein, when in the pumping configuration, the electric motor is powered by the power cable and operable to engage the impellers in rotation to provide lift to the working fluid within the lower reservoir; and when in the turbine configuration, the impellers are rotated via fluid flow and the electric motor is adapted to operate as a generator to generate electricity.

[0011] In one implementation, the ESP assembly comprises a pair of ESPs.

[0012] In one implementation, the ESP assembly comprises a lower ESP and an upper ESP, the lower ESP being proximate to or submerged in the lower reservoir.

[0013] In one implementation, the lower ESP is positioned below or within the lower reservoir, and the upper ESP is positioned above, within or below the lower reservoir.

[0014] In one implementation, when in the pumping configuration, the ESP assembly is adapted to provide a pump rate between about 5,000 and 75,000 bbls / d; and when in the turbine configuration, the ESP assembly is adapted to provide a turbine rate between about 10,000 and 112,500 bbls / d.

[0015] In one implementation, the lower reservoir corresponds to any one of a suspended oil reservoir, an abandoned oil reservoir, a substantially depleted oil reservoir, a substantially depleted natural gas pool, a salt cavern, a brine aquifer and a brine reservoir.

[0016] In one implementation, the upper reservoir comprises a storage tank at the surface or a pond.

[0017] In one implementation, the completed well, the upper reservoir and the lower reservoir together define a closed-loop system.

[0018] In one implementation, a pressure head is defined between the upper reservoir and the lower reservoir, and, when operating the ESP assembly in the turbine configuration, a corresponding working fluid pressure is generated, and wherein the working fluid pressure is greater than an internal pressure of the lower reservoir.

[0019] In one implementation, the ESP assembly is operable in the pumping configuration to store the working fluid in the upper reservoir during periods of low electricity demand or during periods when renewable energy is curtailed, and is operable in the turbine configuration to generate electricity during periods of high electricity demand.

[0020] In one implementation, the subsurface pumped hydropower storage system further includes a power unit located at surface and being in electrical connection with each ESP of the ESP assembly via the power cable to provide electricity to the ESP assembly when in the pumping configuration, and to receive electricity from the ESP assembly when in the turbine configuration.

[0021] In one implementation, the power unit comprises a generator in electrical connection with the ESP assembly to supply power to each ESP operating in the pumping configuration.

[0022] In one implementation, the power unit comprises a grid connection in electrical connection with each ESP to supply power thereto when in the pumping configuration and / or to receive electricity therefrom when in the turbine configuration.

[0023] In one implementation, a nearby load is in electrical connection with the ESP assembly to receive electricity therefrom when in the turbine configuration.

[0024] In one implementation, each ESP of the ESP assembly is operatively coupled to respective regenerative variable speed drives (RVSD).

[0025] In one implementation, the plurality of ESPs of the ESP assembly are installed in parallel to define a parallel circuit establishing fluid communication between the upper and lower reservoirs.

[0026] In one implementation, each ESP of the plurality of ESPs are configured to cooperate in a common configuration between the pumping and turbine configurations.

[0027] In one implementation, the downhole tool comprises a diverter tool coupled between the ESP assembly and the tubing string, the diverter tool being configured to combine the working fluid being pumped to the upper reservoir by respective ESPs of the ESP assembly operating in the pumping configuration; and split the working fluid being injected or fed to the lower reservoir via the tubing string to have separate fluid paths leading working fluid to each ESP.

[0028] In one implementation, the ESP assembly includes a dedicated pump ESP and a dedicated turbine ESP.

[0029] In one implementation, the downhole tool comprises a diverter valve coupled between the ESP assembly and the tubing string, the diverter valve being operable between a pump position and a turbine position, and wherein, when in the pump position, the diverter valve prevents fluid flow to the dedicated turbine ESP to enable working fluid to be pumped by the dedicated pump ESP from the lower reservoir to the upper reservoir; and when in the turbine position, the diverter valve prevents fluid flow to the dedicated pump ESP such that the working fluid being released from the upper reservoir passes through the dedicated turbine ESP to generate electricity.

[0030] In one implementation, the diverter valve comprises a flapper mechanism selectively operable between pump position and the turbine position.

[0031] In one implementation, the flapper mechanism is configured to autonomously shift into the pump position upon operating the ESP assembly in the pumping configuration, and into the turbine position upon operating the ESP assembly in the turbine configuration.

[0032] In one implementation, the flapper mechanism includes a biasing element configured to bias the flapper mechanism in the turbine position such that, when the subsurface pumped hydropower storage system is idle, the flapper mechanism is in the turbine position.

[0033] In one implementation, the plurality of ESPs of the ESP assembly are installed in series to define a series circuit establishing fluid communication between the upper and lower reservoirs.

[0034] In one implementation, the downhole tool comprises a first diverter tool adapted to split a passage of the tubing string into two fluid passages; and a second diverter tool adapted to combine the two fluid passages into a lower fluid passage, wherein at least one of the plurality of ESPs is coupled to the lower fluid passage and at least another one of the plurality of ESPs is coupled to one of the two fluid passages.

[0035] In one implementation, the downhole tool comprises a plug installed in one of the two fluid passages to prevent fluid flow therealong and forcing fluid flow to pass through the other one of the two fluid passages and through the series circuit.

[0036] In one implementation, the plug and fluid passage it is in, is adapted to provide structural support to the ESP assembly.

[0037] In one implementation, the first and second diverter tools are symmetrical.

[0038] In one implementation, the first and second diverter tools correspond to first and second Y-tools.

[0039] In one implementation, the second diverter tool is inverted relative to the first diverter tool.

[0040] In one implementation, the tubing string and the casing define an annulus therebetween, and wherein the tubing string comprises ports adapted to establish fluidcommunication between the tubing string and the annulus to enable working fluid to flow between the upper and lower reservoirs through the tubing string, through the annulus, or through both.

[0041] In one implementation, the downhole tool comprises a tubular sleeve slidably coupled to the tubing string, the tubular sleeve being operable between a closed configuration, where the tubular sleeve occludes the ports to prevent fluid communication between the tubing and the annulus and an open configuration.

[0042] In one implementation, the tubular sleeve is slidably coupled to an inner surface of the tubing string.

[0043] In one implementation, the tubular sleeve is mechanically or hydraulically actuatable between the closed and open configurations.

[0044] In one implementation, the downhole tool comprises a seat configured to receive an occluding device, and wherein, upon having the occluding device engage the seat, fluid pressure within the tubing string and annulus is increased as working fluid is injected or fed into the tubing string to enable pressure testing the annulus.

[0045] In one implementation, the downhole tool comprises packers installed in the annulus and configured to isolate an uphole well section from a downhole well section.

[0046] In one implementation, the ports are defined in the tubing string within the uphole well section.

[0047] In one implementation, the tubular sleeve is located in the uphole well section in both the open and closed configurations.

[0048] In one implementation, the ESP assembly is located in the downhole well section.

[0049] In one implementation, the diverter tools are located in the downhole well section.

[0050] In one implementation, the downhole tool further comprises an ESP housing secured between adjacent ESPs of the ESP assembly, the ESP housing being configured to establish a structural connection between the adjacent ESPs and establish fluid communication therebetween.

[0051] In one implementation, the ESP housing comprises a tubular member having a lower end secured to a first ESP of the adjacent ESPs, and an upper end secured to a second ESP of the adjacent ESPs, the tubular member defining an enclosed conduit for directing working fluid between the adjacent ESPs.

[0052] In one implementation, the ESP housing is configured to maintain the adjacent ESPs axially aligned within the casing.

[0053] In one implementation, the ESP housing is configured to maintain the adjacent ESPs centralized within the casing.

[0054] In one implementation, the ESP housing is shaped and sized to define a working-fluid flowpath having a cross-sectional area equal to or greater than a cross-sectional area of the tubing string.

[0055] In one implementation, the ESP housing is shaped and sized to define a working-fluid flowpath having a cross-sectional area smaller than a cross-sectional area of the tubing string.

[0056] In one implementation, the ESP housing comprises one or more cable pass-throughs configured to route at least one power cable and / or instrumentation cable to at least one of the adjacent ESPs.

[0057] According to another aspect, a process for generating electric power using the subsurface pumped hydropower storage system as defined above is provided, the process comprising:a. operating the downhole tool in the pumping configuration;b. pumping fluid from the lower reservoir to the upper reservoir to store energy; c. operating the downhole tool in the turbine configuration; andd. pumping or gravity feeding fluid from the upper reservoir to the lower reservoir to generate electricity.

[0058] In one implementation, steps a. to d. are cyclically repeated.

[0059] In one implementation, the initial step of the process is step a or c.

[0060] In one implementation, the process further includes assessing the formation parameters, including determining which one of the upper reservoir and the lower reservoir contains the working fluid.

[0061] According to another aspect, a subsurface pumped hydropower storage system is provided and includes a completed well extending into a subsurface strata to reach a lower reservoir that is under-pressured, the completed well being configured to house fluid communication of working fluid and comprising: a wellhead at surface and being in fluid communication with an upper reservoir located at or proximate to the surface; a casing lining an inner surface of the well; a tubing string extending within the casing and defining an annulus therebetween, at least one of the tubing string and the annulus being adapted to establish fluid communication between the upper reservoir and the lower reservoir; a downhole tool comprising an electric submersible pump (ESP) assembly coupled to the tubing string and adapted to be submerged or in fluid communication with the lower reservoir, the ESP assembly being operable in a turbine configuration and a pumping configuration, wherein, when in the turbine configuration, the ESP assembly is adapted to generate electricity in response to the working fluid being released from the upper reservoir and flowing downhole via at least one of the tubing string and the annulus into the lower reservoir and passing through the downhole tool, the electricity being transmitted to the surface via a power cable connected to the ESP assembly, and when in the pumping configuration, the ESP assembly is adapted to use electricity received from the surface via the power cable to provide lift and pump the working fluid from the lower reservoir to the surface via at least one of the tubing string and the annulus and into the upper reservoir.

[0062] According to another aspect, a downhole tool for connection with a tubing string extending within a casing lining an inner surface of a well extending into a subsurface strata to reach an under-pressured lower reservoir and having a wellhead at surface in fluid communication with an upper reservoir as part of a subsurface pumped hydropower storage system is provided. The downhole tool includes an electric submersible pump (ESP) assembly coupled to the tubing string and adapted to be submerged or in fluid communication with the lower reservoir, the ESP assembly being operable in a turbineconfiguration and a pumping configuration, wherein: when in the turbine configuration, the ESP assembly is adapted to generate electricity in response to working fluid being released from the upper reservoir and flowing downhole via at least one of the tubing string and an annulus defined between the tubing string and the casing, and into the lower reservoir, the working fluid passing through the downhole tool, and the electricity generated is transmitted to the surface via a power cable connected to the ESP assembly, and when in the pumping configuration, the ESP assembly is adapted to use electricity received from the surface via the power cable to provide lift and pump the working fluid from the lower reservoir to the surface via at least one of the tubing string and the annulus and into the upper reservoir.

[0063] According to another aspect, a subsurface pumped hydropower storage system is provided. The system includes a completed well extending into a subsurface strata to reach a lower reservoir that is under-pressured, the completed well being configured to house fluid communication of working fluid and comprising: a wellhead at surface and being in fluid communication with an upper reservoir located at or proximate to the surface, the wellhead comprising: an occluding device catcher; an occluding device releasably housed within the occluding device catcher; and a ball valve operable between an open configuration to enable the occluding device to flow into and out of the occluding device catcher, and a closed configuration. The system also includes a casing lining an inner surface of the completed well and coupled to the wellhead; a tubing string extending within the casing and defining an annulus therebetween, at least one of the tubing string and the annulus being coupled to the wellhead and adapted to establish fluid communication between the upper reservoir and the lower reservoir; a downhole tool comprising an electric submersible pump (ESP) assembly coupled to the tubing string and adapted to be submerged or in fluid communication with the lower reservoir, the ESP assembly being operable in a turbine configuration to generate electricity in response to the working fluid being released from the upper reservoir, and in a pumping configuration to provide lift and pump the working fluid from the lower reservoir to the surface and / or into the upper reservoir; and an occluding device profile provided along the tubing string between the wellhead and the ESP assembly, the occluding device profile being adapted to receive the occluding device thereon to prevent fluid flow therethrough and enable pressure testing the tubing string and / or the annulus.

[0064] In one implementation, the subsurface pumped hydropower storage system further includes a packer installed in the annulus and configured to isolate an uphole well section from a downhole well section, and wherein the occluding device profile is positioned proximate the packer.

[0065] In one implementation, the occluding device profile extends within the tubing string opposite the packer such that fluid flow into the downhole well section is prevented upon engagement of the occluding device on the occluding device profile.

[0066] In one implementation, the tubing string comprises ports defined therethrough and adapted to establish fluid communication between the tubing string and the annulus to enable working fluid to flow between the upper and lower reservoirs through the tubing string, through the annulus, or through both.

[0067] In one implementation, the downhole tool comprises a tubular sleeve slidably coupled to the tubing string, the tubular sleeve being operable between a closed configuration, where the tubular sleeve occludes the ports to prevent fluid communication between the tubing and the annulus and an open configuration.

[0068] In one implementation, the tubular sleeve is slidably coupled to an inner surface of the tubing string.

[0069] In one implementation, the tubular sleeve is mechanically or hydraulically actuatable between the closed and open configurations.

[0070] In one implementation, the ports are defined in the tubing string within the uphole well section.

[0071] In one implementation, the tubular sleeve is located in the uphole well section in both the open and closed configurations.

[0072] In one implementation, the ESP assembly is located in the downhole well section.

[0073] According to another aspect, a process for pressure testing the tubing string and / or the annulus of the completed well used in the subsurface pumped hydropower storage system defined above is provided. The process includes operating the ball valve in the open configuration to enable the occluding to flow out of the occluding devicecatcher; engaging the occluding device with the occluding device profile; filling at least one of the tubing string and the annulus with fluid from the surface; and pressure testing the at least one of the tubing string and the annulus.

[0074] In one implementation, following the pressure testing, the process comprises bleeding off internal pressure by enabling fluid flow from the at least one of the tubing string and the annulus to the upper reservoir and / or the lower reservoir.

[0075] In one implementation, following the pressure testing, the ESP assembly is operable in the pumping configuration to pump the occluding device off of the occluding device profile, along the tubing string and into the occluding device catcher.

[0076] In one implementation, following the occluding device returning into the occluding device catcher, the ball valve is operated from the open configuration to the closed configuration to prevent release of the occluding device.BRIEF DESCRIPTION OF THE DRAWINGS

[0077] Figure 1 is a schematic view of a subsurface pumped hydropower storage system having a single well, according to an implementation.

[0078] Figure 2 is a schematic view of the subsurface pumped hydropower storage system of Figure 1, showing a downhole tool operable to cycle working fluid between reservoirs at different elevations, according to an implementation.

[0079] Figure 3 illustrates steps of a cyclical process for generating electricity using the subsurface pumped hydropower storage system shown in Figure 1, according to an implementation.

[0080] Figure 4 is a schematic view of an implementation of the downhole tool shown in Figure 2, showing an ESP assembly in a pumping configuration, according to an implementation.

[0081] Figure 5 is a schematic view of the downhole tool shown in Figure 4, showing the ESP assembly in a turbine configuration, according to an implementation.

[0082] Figure 6 is a schematic view of an implementation of the downhole tool shown in Figure 2, showing an ESP assembly having two ESPs forming a parallel circuit, according to an implementation.

[0083] Figure 7 is a schematic view of an implementation of the downhole tool shown in Figure 2, showing an ESP assembly having two ESPs forming a series circuit, according to an implementation.

[0084] Figures 8 and 9 are schematic view of the downhole tool shown in Figures 4 and 5, respectively, showing a fluid flowing along the annulus and along the tubing string, according to an implementation.

[0085] Figures 10 and 11 are schematic view of the downhole tool shown in Figures 6 and 7, respectively, showing a fluid flowing along the annulus and along the tubing string, according to an implementation.

[0086] Figures 12 and 13 are schematic view of alternate implementations of the downhole tool, showing an ESP assembly having two ESPs forming a series circuit and provided with an ESP housing connected to and establishing fluid communication between the two ESPs.

[0087] Figure 14 is a schematic view of an implementation of the downhole tool, showing an occluding device catcher provided in a wellhead, according to an implementation.DETAILED DESCRIPTION

[0088] As will be explained below in relation to various implementations, the present disclosure describes apparatuses, systems and methods for generating electrical power using downhole tools implemented in wellbores, such as wellbores and associated components used as part of traditional well completions and / or downhole operations in the oil & gas industry.

[0089] In some implementations, the present disclosure relates to systems and methods associated with a subsurface pumped hydropower storage (SPHS) system including downhole tools for the generation and storage of electricity. The SPHS system can be implemented in an existing completed well which has been previously operated to producematerial, such as hydrocarbons, from a subsurface reservoir (or formation) or in a newly drilled well dedicated for the hydropower storage operation. In some implementations, the formation can be an under-pressured subsurface reservoir. For instance, the formation pressure is generally low due to its contents having been removed (e.g., produced to surface) and / or due to other geological factors. For example, the formation can include depleted natural gas pools, suspended and / or abandoned oil reservoirs, salt caverns, low pressure brine reservoirs, etc.

[0090] In some implementations, the SPHS system is operable to cycle working fluid between a lower reservoir and an upper reservoir. The lower reservoir can correspond to the depleted subsurface formation, and the upper reservoir can be provided proximate to the surface, such as partially or completely underground, or at the surface (e.g., on and / or aboveground). The lower and upper reservoirs are connected to one another via the completed well such that the working fluid can flow therebetween. As will be described further below, the under-pressured lower reservoir can increase the power-generating potential of the SPHS system by enabling a greater fluid head pressure differential at across the ESP, facilitating injection of the working fluid into the lower reservoir. In some implementations, the completed well is retrofitted as part of the SPHS system such that drilling and completing a new well is not required. However, in other implementations, the well can be newly drilled and completed to include desired specifications, such as a desired sizes (e.g. , diameters, depth, etc.) for deployment and implementation of a desired downhole tool design facilitating the hydropower storage operation.

[0091] The downhole tool of the SPHS system includes an electric submersible pump (ESP) assembly installed within the well for enabling fluid flow between the lower and upper reservoirs. For instance, the ESP assembly includes multiple ESPs (e.g., at least two) configured to cooperate in the well as part of the SPHS system. The ESPs can be operated as pumps in order to pump the working fluid uphole from the lower reservoir to the upper reservoir (e.g., to surface). The ESPs are thus operated in pumping mode to displace the working fluid from the lower reservoir to the upper reservoir. The ESPs can also be operable as turbines to enable the generation of electric power when the working fluid flows through the well from the upper reservoir down into the lower reservoir (i.e. , as the working fluid flows downhole). Thus, the ESPs can be configured to cycle between at least two operational modes, e.g., a pumping mode and a turbine mode, as part of theSPHS system. It is noted that the working fluid is pumped uphole via operation of the ESPs in the pumping mode, and then is introduced back into the well to flow through the ESPs operated in the turbine mode to generate electricity, thereby creating a power storage-and-generating cycle.

[0092] In some multiple-ESP implementations of the SPHS system, a first ESP can be operated in a dedicated pumping mode, and a second ESP can be operated in a dedicated turbine mode. During operation, a diverter valve can be provided to isolate the working fluid from one of the first and second ESPs, depending on the ongoing operations of the SPHS system. For instance, the diverter valve can be configured to “block” the first ESP while electricity is being generated via working fluid flowing through the second ESP. In other words, the diverter valve can be adapted to isolate the working fluid from the first ESP during operation of the SPHS system for the generation of electricity. Similarly, the diverter valve can be shifted and configured to block the second ESP while working fluid is being pumped by the first ESP from the lower reservoir to the upper reservoir. In other words, the diverter valve can be adapted to isolate the working fluid from the second ESP during operation of the SPHS system for pumping working fluid towards the surface into the upper reservoir.

[0093] In other implementations, multiple-ESPs can alternate (e.g., cycle) between pumping and turbine modes. In such implementations, the ESPs can be installed in series and / or in parallel to cooperate in either pump or turbine modes. It should be understood that single or multi-ESP SPHS systems can be implemented in one or more wells, where each well is equipped with a given ESP assembly depending on the well design. Preferably, the SPHS system includes multiple wells, each being equipped with a corresponding ESP assembly, and where a set of wells is in fluid communication with an upper reservoir and a lower reservoir. However, it should be understood that various configurations of wells, ESP assembly, ESPs and reservoirs are possible.

[0094] The ESP(s) of the SPHS system can be operated in the pumping mode during periods of low demand when power is readily available and lower cost, and can be operated in the turbine mode during periods of high demand when power is more scarce and higher cost. This SPHS operation can be performed in alignment with pumped-storage hydroelectricity principles as well as other factors. The ESP(s) can also beoperated in the pumping mode during periods of curtailment for renewables caused by power grid operating requirements.

[0095] It is also noted that cycling the operation of the ESPs between the pumping mode and the turbine mode can benefit from establishing predetermined parameters of the SPHS system, including parameters related to the ESPs, the well, the subsurface reservoir(s) and / or the equipment at surface. The predetermined parameters can, for example, assist in maintaining the ESP within mechanical tolerances for each of the operational modes. The designing of the SPHS system (e.g., the predetermined parameters) can be performed to facilitate economic viability for given circumstances.

[0096] With reference to Figure 1, an implementation of a subsurface pumped hydropower storage (SPHS) system 10 is shown. The SPHS system 10 includes a well 12 extending from the surface 14 into subsurface strata 15. It should be noted that the subsurface strata 15 corresponds to one or more layers of the subsurface reservoir, each layer can, in turn, correspond to respective subsurface formations and / or a single subsurface formation (e.g., when combined). The SPHS system 10 also includes a lower reservoir 16, provided within the subsurface strata 15, and an upper reservoir 18, provided near or at the surface 14. The SPHS system 10 is configured to cycle a working fluid between the lower and upper reservoirs 16, 18 to generate electricity and store electricity as potential energy. In this implementation, the SPHS system 10 includes a downhole tool 20 installed within the well 12 and operable to provide lift to the working fluid contained in the lower reservoir 16 in order to generate fluid flow from the lower reservoir to the upper reservoir 18. Moreover, and as will be described further below, the downhole tool 20 is also operable to generate electricity as the working fluid flows from the upper reservoir 18, e.g., by gravity or via pumping, through the downhole tool 20 and into the lower reservoir.

[0097] In the present implementation, the downhole tool 20 includes an electrical submersible pump (ESP) assembly 21. The ESP assembly 21 includes a plurality of ESPs 22, such as at least two ESPs 22 installed within the well 12. Each ESP 22 can correspond to a subsurface oilfield ESP designed for operation within a wellbore provided in an underground formation, for instance, to produce oil therefrom. However, it is appreciated that other configurations are possible. For example, the ESPs 22 can be designed as partof a system connected to a geothermal reservoir or a salt cavern for lifting fluid stored in the salt cavern, among other possibilities.

[0098] With reference to Figure 2, it should be understood that, as used herein, the ESPs of the ESP assembly correspond to a type of well pump operable to pump fluids from the lower reservoir to the upper reservoir. At least one of the ESPs can be designed to operate submerged in the fluid being pumped (i.e. , the working fluid) and includes, and is driven by, a submersible electric motor 25. Typical ESPs include a multi-stage centrifugal pump 24 connected to the submersible electric motor 25, which is coupled and powered by cables 26 connected to surface components, such as a transformer 27, a junction box 28 and a regenerative variable speed drive (RVSD) 34. More particularly, each ESP 22 has a motor lead extension 36 which provides the required connection for the power cable 26, thereby allowing a link to be established between the ESPs and its power source (or “power unit”).

[0099] The ESPs 22 also have respective fluid intakes 30 at a first end thereof, and respective fluid discharges 32 at a second end thereof. It is thus noted that, during pumping operations of the SPHS system, operation of the motor 25 engages a shaft in rotation, which in turn engages impellers of the centrifugal pumps 24 to draw fluid through the ESP intake 30, and lifting the fluid through the ESP discharge 32, and up the tubing using centrifugal force from one or more pump stages / impellers, towards the upper reservoir. In some implementations, the power unit of the ESP can be on-site generators, such as wind-powered, solar-powered, fuel cell(s), natural gas / hydrogen fired turbines, steam-powered (combined cycle plants, co-generation, oxy-fuel, coal), organic rankine cycle, hydro, etc, (e.g., at surface and / or proximate a wellhead 5), or the ESP can be connected directly to the local power grid. It should be noted that, in some implementations, the power required to pump the working fluid to the upper reservoir is derived from renewable and / or carbon-free energy sources.

[0100] In the implementation shown in Figure 1, the ESP assembly 21 is installed in the well 12 in a manner such that the ESPs 22 are located within or in fluid communication with the lower reservoir 16. The ESPs 22 can be operable in at least two operational modes. For example, the ESPs 22 can operate in a pumping mode, where both ESPs operate to pump the working fluid from the lower reservoir to the upper reservoir. TheESPs can be further operated in a turbine mode, where the working fluid flows into the lower reservoir, flowing through both ESPs (in turbine mode) to generate electricity. It should therefore be noted that the SPHS system 10 includes a dual-mode ESP assembly 21 implemented and operated in the well 12 for bidirectional flow. As will be described further below, the ESP assembly 21 is designed to cycle between pumping and generating operations to establish the power storage-and-generation cycle. It should thus be noted that the power storage-and-generation cycle can be defined using the ESPs 22 of the ESP assembly 21 installed in a single well (i.e. , the well 12).

[0101] It should be noted that an ESP is designed for pumping such that the efficiency of the ESP in turbine mode may not be optimized. If efficiency of the SPHS system is the primary goal, the SPHS system can be set up using one wellbore specifically designed and operated for pumping fluid from the lower reservoir to the upper reservoir, and a separate, second wellbore, designed and operated for power generation. In such implementations, the impellers installed within the second wellbore can be redesigned specially for power generation. However, if economic viability is the primary goal, using one well for both pumping and power generation significantly reduces upfront capital costs. An economic analysis can be conducted for each proposed SPHS project in order to determine the optimal path for development. In some implementations, economic viability and system efficiency can be improved by installing the ESP assembly 21 in the single well, with one ESP designed for pumping, and another ESP designed for power generation. As will be described further below, the ESP assembly 21 can include a diverting and / or isolating mechanism, such as a diverter valve configured to isolate the ESP which is not solicited for operation, for instance, by diverting the flow of working fluid. In other words, during pumping operations, the diverter valve can isolate the ESP designed for power generation, and vice versa.

[0102] In the SPHS system, the working fluid is stored within the upper reservoir 18 and released therefrom into the well to generate power. The working fluid can be pumped down the well (e.g., injected under pressure) and into the lower reservoir 16 to operate the ESP in turbine mode to generate electricity. In other implementations, the working fluid can be released from the upper reservoir to flow down the well (e.g., by gravity). In yet other implementations, the working fluid can flow into the lower reservoir via a combination of gravity and pumping. In some implementations, the working fluid can include fluidsoriginating externally to the SPHS system, which is then injected and cycled in the well. The working fluid can therefore include the desired type of fluid having known contents, desired flow characteristics and / or fluid dynamics, such as density, viscosity, compressibility, etc. Alternatively, in other implementations, the working fluid originates from the lower reservoir 16. For example, the working fluid can correspond to a liquid suitable to be pumped uphole via at least one ESP 22 of the ESP assembly 21 in pumping mode, and be reintroduced downhole to operate the turbine (i.e. , at least one ESP 22 in turbine mode). In some implementations, the working fluid can include oil, water, oil-in-water emulsions, brine having any suitable amount of dissolved solids or particulates consisting of, but not limited to, silica, borate, carbonate, and / or any combinations thereof. It should also be noted that, although gaseous / vapor fluids can operate the turbine, these types of fluids reduce efficiency and should therefore be avoided in the SPHS system.

[0103] The SPHS system also includes a regenerative variable speed drive (RVSD) 34 configured to enable the ESPs 22 to both consume and generate power. More specifically, the RVSD 34 enables electricity from the power unit (e.g., the power grid) to be used by the ESPs, e.g., during operation in the pumping mode, and also enables electricity generated, e.g., during operation in the turbine mode, to be sold onto the transmission system (i.e., the grid) or to a nearby industrial load. In some implementations, the power unit can include renewable or carbon free energy sources, such as wind power, solar power, etc.

[0104] In some implementations, the well 12 corresponds to a completed well which has since been suspended, abandoned or shut in following initial operation. For instance, the well 12 could have been drilled and completed as part of an oilfield production system, where the well 12 was used to produce oil from the underground formation. The lower reservoir 16 of the SPHS system 10 therefore corresponds to the depleted formation (e.g., depleted of oil and / or gas), which now contains low pressure liquid, such as brine. The completed well can therefore be retrofitted with the ESP assembly 21 to define the SPHS system 10. It should be noted that, in oilfield operations, a plurality of wells can be drilled and completed to access a common underground formation. These wells can be similar (e.g., identical) to each other, or can have different sizes, orientations and / or configurations. Therefore, the SPHS system 10 can be implemented in any one of the wells accessing a given formation or in a plurality of wells thereof (e.g., one SPHS systemper well). The well orwells can be chosen based on desired or predetermined parameters, such as the size of the wellbore and tubulars, depth of the well within the lower reservoir, etc.

[0105] It is appreciated that the depth of the lower reservoir affects the hydraulic head of the SPHS system 10, which is generally defined as the distance between the upper and lower reservoirs, which contributes to generating a working fluid pressure within the well, among others. The hydraulic head of the SPHS system 10, and corresponding working fluid pressure, can assist in establishing design parameters of the ESPs 22, such as the working fluid injection rate, size and number of centrifugal pump stages and / or impellers 24, motor / generator size when operating in the pumping mode and / or turbine mode. The centrifugal pump 24 of each ESP 22 can be chosen based on the hydraulic head, which can represent the minimum capability of the pump. In other words, in order to be technically viable, the ESPs are designed to have the pumped fluid reach the upper reservoir during operation in the pumping mode. In this implementation, the characteristics of the ESPs are adjusted and / or established based on the parameters of the well. However, in other implementations, pre-established ESP characteristics can assist in determining parameters of the well. For example, the hydraulic head of the chosen well must be suitable for operation of a given ESP 22 in the pumping mode. In addition, it is noted that the hydraulic head (or pressure head) of the well provides energy to the ESPs when operating in the turbine mode, which is extracted and converted by the generator into electricity. The hydraulic head of the well should therefore be considered when selecting the well so as to be suitable for use with ESP assembly 21 configurations, and specific ESP 22 characteristics, both in the pumping and turbine modes.

[0106] In some implementations, the upper reservoir 18 can include a storage tank provided at surface and configured to store working fluid therein. Alternatively, the upper reservoir 18 can include man-made ponds or naturally-occurring storage areas in which quantities of working fluid can be stored or held. It is noted that the upper reservoir can be at surface, such as among or proximate to the surface facilities of the SPHS system. In other implementations, the upper reservoir 18 can correspond to a subsurface reservoir, similar to the lower reservoir, but which is sufficiently higher than the lower reservoir to enable operation of the SPHS system. For example, and as described above, the upperreservoir 18 can be sufficiently higher than the lower reservoir to define the hydraulic head suitable to enable power generation when operating the ESP in the turbine mode.

[0107] In some implementations, the lower reservoir 16 includes brine which can correspond to residual fluids from depleted oil or natural gas fields. The brine can therefore correspond to the working fluid in which one or more ESPs 22 can be submerged. The ESP assembly 21 can then be operated in the pumping mode to pump the brine out of the lower reservoir and into the upper reservoir. The ESP assembly 21 can then be operated in the turbine mode as the working fluid is released and / or injected from the upper reservoir, into the well and the lower reservoir. The ESP assembly 21 is cycled between the two operational modes as desired, such as based on electricity market conditions. It is therefore noted that the general process for generating electricity using the SPHS system 10 can define the power storage-and-generating cycle 100. For instance, and with reference to Figure 3, the ESP assembly 21 can be initially operated in the pumping mode to extract working fluid from the lower reservoir and pump it into the upper reservoir. Then, the working fluid can be released from the upper reservoir to flow down the well to spin the impellers in turbine mode to generate electricity. The cycle 100 can be repeated at any time, and for any duration, subject to upper and lower reservoir working fluid volume capacity, among others.

[0108] It is appreciated that the demand for power can vary, which can provide indication on a suggested operational mode of the ESP assembly. For instance, during periods of low demand of power, one or more ESPs can be operated in the pumping mode and the working fluid can be pumped from the lower reservoir and stored in the upper reservoir. Once demand for power increases, one or more ESPs can be operated in the turbine mode and the working fluid can be released from the upper reservoir and pumped and / or gravity fed into the well to generate power. It should therefore be understood that the working fluid can be stored in the upper reservoir for an undetermined amount of time, and released, when needed and / or desired, to generate electricity.

[0109] In some implementations, the lower reservoir 16 can be substantially depleted (e.g., dry), such as following the production of natural gas pools, for instance. In this implementation, suitable amounts of brine (or any other working fluid) can be injected into the lower reservoir 16. The working fluid can be drained from an adjacent subsurfacereservoir, such as a subsurface reservoir which was not located at a suitable depth for the SPHS system. Preferably, the drained subsurface reservoir contains non-potable water, such as water with high salinity or dissolved solids, for example. The working fluid is therefore drained from the adjacent subsurface reservoir, transferred to the SPHS system (e.g., to the upper or lower reservoir) and can then be cycled between the lower and upper reservoirs during the power-generating process of the SPHS system.

[0110] In some implementations, any one of the upper and lower reservoirs can define a containment area adapted to maintain the stored working fluid generally localized. For example, at surface, a storage tank is configured to contain and store the working fluid locally. Natural or man-made ponds can also be provided with membranes to assist in maintaining and storing the working fluid. The power-generating process of the SPHS system can correspond to a “closed loop” process, where the same working fluid is repeatedly pumped and cycled between the upper and lower reservoirs.

[0111] In some implementations, continuous generation can be achieved through the potential energy generated from an active oilfield. For instance, an oil operator pumps saline water and oil to surface, separating out the oil and reinjecting the water. Dedicated ESPs in turbine mode can be installed in the injection wells to generate continuous power. This configuration corresponds to a closed loop system, but leverages the operations of an active oilfield to generate electricity.

[0112] Operation of the one or more ESPs 22 in pumping mode can correspond to standard operating procedures of the ESP. Power is provided to the motor 25 (via the cables 26) which engages the impellers of the pumps 24 in rotation to generate lift, thereby pumping fluids from the lower reservoir towards surface and into the upper reservoir. Inversely, operation of the one or more ESPs 22 in turbine mode uses fluid being injected into the well to generate power. Therefore, it is noted that, when in turbine mode, the conventional fluid intake 30 of the corresponding ESP becomes the fluid discharge, and the conventional fluid discharge becomes the fluid intake. Moreover, as the impellers of the pump 24 rotate as fluid flows down the well, the electric motor 25 operates as a generator 25’ adapted to generate power, which is transmitted to surface via the power cable 26. It should be noted that the power cable used to provide electricity to the ESPs (e.g., to operate the ESP as a pump) can be the same power cable which transfersgenerated electricity back to surface (e.g., when operating the ESP as a turbine). However, it is appreciated that other configurations are possible, such as providing independent cables for providing power to the ESP and transferring generated electricity to surface, for example.

[0113] It is understood that operating the ESPs 22 in pumping mode requires and consumes electricity, whereas operating the ESP 22 in turbine mode generates electricity. Therefore, operation of the SPHS system 10 can require an operational balance to achieve technical and economic viability. This operational balance can be achieved by establishing predetermined parameters, or at least ranges thereof, among others. In other words, preferred implementations of the SPHS system 10 include operation of the system (and related components) within the bounds of the established predetermined parameters to be viable. It should be understood that, as used herein, the expression “economic viability” can refer to the “cost to revenue ratio” of the SPHS system. The cost can include the electricity required to power and operate the ESPs (e.g., in the pumping mode). Alternatively, or additionally, the costs can include the costs associated with setting up the SPHS system, such as the costs for retrofitting an existing well with the ESP assembly and related tubing, or the costs for drilling and completing new custom-sized wells having specific dimensions (e.g., diameter, depth, etc.), for example. In this implementation, the revenue corresponds to the amount of generated electricity (e.g., in the turbine mode) which can be stored, used and / or sold. It should be noted that, while the initial installation cost of the SPHS system can be high, operation of the SPHS system, over a period of time (which can be calculated), is economically viable.

[0114] It should also be understood that, as used herein, the expression “technical viability” can refer to the ability of the SPHS system to function properly and / or as desired, for example, during a prolonged period of time and / or in specific circumstances. For example, repeatedly cycling the ESP assembly 21 between pumping and powergenerating operations can lead to mechanical failure of the ESPs 22 under certain operational conditions. Particularly, and although adapted to operate as a turbine, the ESPs 22 are designed to operate as pumps. Therefore, to maintain technical viability of the ESPs, predetermined parameters and / or enhancements can be established and / or incorporated in order to protect the components of the ESP in both operational modes.

[0115] For instance, when operating in the turbine mode, the generator 25’ (e.g., the motor 25) can act as a brake for the turbine by limiting the speed of the turbine to avoid malfunctions, such as the creation of a “run-away” condition. In some implementations, the RVSD is connected to the generator to preset the speed of the generator, thereby acting as a brake while in turbine mode. It should therefore be noted that, regardless of the hydraulic power of the working fluid, the generator will not be allowed to spin in a runaway condition. Moreover, it should be understood that the size (e.g., diameter) of the well allows for higher rates, which provides for more power. Larger wells are also suitable to house larger pumps and generators. The RVSD is configured to monitor diagnostics of the generator in real-time and can be adapted to shut down the generator if it is operating under conditions which could lead to a failure. Also, computational fluid dynamic (CFD) modelling can be used to appropriately size pumps and motors to the range of fluid rates and hydraulic head available, among other possibilities.

[0116] In view of the above, it is noted that some of the predetermined parameters of the SPHS system 10 for achieving operational balance can include parameters relating to the well 12 (e.g., tubular size, depth, etc.), the ESP assembly 21 (e.g., number of ESPs, disposition of ESPs, etc.), the ESPs 22 (e.g., specifications, size, number of stages, etc.) and / or the operational parameters of the SPHS system such as flowrates, head pressure, etc.

[0117] Completed oil & gas wells typically include a casing 40 (also referred to as a production casing or outer pipe) and a tubing string 42 (or inner pipe). The casing typically assists in maintaining the structural integrity of the well by lining the inner surface of the drilled wellbore and can be adapted to reach into or below the lower reservoir. The tubing string 42 extends within the casing 40 and is adapted to enable fluid flow, for example, between the lower and upper reservoirs. It should therefore be noted that, in this implementation, the ESPs 22 are coupled to the tubing string 42 to enable and cooperate with said fluid flow. The casing 40 and the tubing string 42 can run parallel and / or concentrically relative to each other to define an annulus 44, or annular region, therebetween. Generally, the motor lead extension 36 extends from the ESPs into the annulus 44 to facilitate connection with the power cable 26. The motor lead extension 36 and power cable therefore run along the outside of the ESPs and tubing string 42, within the annulus 44. In some implementations, the tubing string 42 has a diameter which isbetween 2” and 6” smaller than a diameter of the casing, thereby defining a correspondingly-sized annulus 44 therebetween adapted to house the motor lead extension 36 and the power cable 26. However, it should be noted that any other suitable size of tubulars can be used to define a suitably-sized annulus 44 for housing the motor lead extension 36 and the cable 26.

[0118] With reference to Figures 4 to 9, different implementations of the ESP assembly 21 are illustrated. The ESP assembly 21 is installed in a single-well and can include a plurality of ESPs 22 operable to enable the power storage-and-generating cycle 100 (illustrated in Figure 3). Referring more specifically to Figures 4 and 5, the ESP assembly 21 can include a pair of ESPs 22 coupled to the tubing string 42 to cooperate with the flow of working fluid along the tubing string. In this implementation, the ESPs 22 are respectively dedicated to operating as a pump and as a turbine. In other words, a first ESP 22a is dedicated to pumping operations (i.e., the pump), and a second ESP 22b is dedicated to power-generating operations (i.e., the turbine). Each one of the first and second ESPs include a fluid intake 30 at a first end thereof, and a fluid discharge 32 at a second end thereof. It should be understood that the fluid discharge 32 of the pump (e.g., the first ESP 22a) is in fluid communication with the passage of the tubing string 42 to enable pumping fluid from the lower reservoir towards the surface and the upper reservoir. Inversely, the fluid intake 30 of the turbine (e.g., the second ESP 22b) is in fluid communication with the passage of the tubing string 42 to enable working fluid flowing down the tubing string (from the upper reservoir to the lower reservoir) to flow through the turbine to generate power.

[0119] In this implementation, the downhole tool 20 further includes a diverter valve 50 configured to isolate one of the ESPs 22 from the tubing string 42 passage, thereby blocking fluid communication therebetween. For instance, during pumping operations, the diverter valve 50 is configured to isolate the second ESP 22b by blocking the fluid intake 30 of the second ESP 22b, while enabling fluid communication between the first ESP 22a (e.g., its fluid discharge 32) and the tubing string 42. Working fluid can thus be pumped from the lower reservoir to the upper reservoir via the first ESP 22a while the second ESP 22b remains isolated. Similarly, during power-generating operations, the diverter valve 50 is configured to isolate the first ESP 22a by blocking the fluid discharge 32 of the first ESP 22a, while enabling fluid communication between the second ESP 22b (e.g., its fluid intake30) and the tubing string 42. Working fluid can thus be released from the upper reservoir and fed to the lower reservoir, passing through the second ESP 22b, while the first ESP 22a remains isolated.

[0120] As shown in Figures 4 and 5, the first ESP 22a is lower than the second ESP 22b. In other words, the first ESP can correspond to a lower ESP, and the second ESP can correspond to an upper ESP. This configuration can improve efficiency of both the pump (e.g., the lower ESP) and the turbine (e.g., the upper ESP). However, it should be noted that other configurations are possible, such as having the first and second ESPs be positioned at generally the same location / depth, or having the second ESP be lower and closer to the lower reservoir.

[0121] In this implementation, the diverter valve 50 includes a flapper mechanism 52 having a flapper housing 54 installed along the tubing string 42 and a flapper 56 pivotally coupled to the flapper housing 54, which is then attached to the tubing string 42. The flapper 56 includes an isolating surface 58 shaped and sized to isolate one of the pair of ESPs 22 by blocking fluid flow towards that ESP (based on the operational configuration of the SPHS). In this implementation, the flapper 56 is operable between a closed position, or pump position, where fluid flow to the second ESP is blocked (seen in Figure 4), and an open position, or turbine position, where fluid flow to the first ESP is blocked (seen in Figure 5). The flapper housing 54 can include shoulders 55 adapted to have the flapper 56 engage therewith in order to have the isolating surface 58 block fluid flow towards a corresponding one of the ESPs. As seen in Figures 4 and 5, the flapper 56 also includes a weighted arm 60 configured to bias the flapper in the open position. Particularly, the weighted arm 60 is connected to and extends from the isolated surface 58 such that, when in the closed position, the weighted arm 60 can bias the flapper 56 in the open position via downward flow of the working fluid, via gravity or both. It should be noted that, under static conditions (e.g., when the SPHS system is idle and / or when there is no fluid flowing through the ESP), the weighted arm 60 can be adapted to bias the flapper in the open position via gravity only.

[0122] It should therefore be understood that the flapper 56 is, by default, in the open position. Moreover, during pumping operations, the first ESP 22a is operated to pump fluid from the lower reservoir and into the diverter valve 50. As such, the flow of working fluidis adapted to push against the flapper 56 (e.g., against the isolating surface 58 and / or the weighted arm 60) to pivot the flapper in the closed position. The second ESP 22b is thus isolated while working fluid is pumped to the upper reservoir for storage. Upon stopping the pumping operations, the fluid along the tubing string 42 stabilizes and the weighted arm 60 urges rotation of the flapper 56 via gravity, in the open position. The first ESP 22a is thus isolated and working fluid can be released from the upper reservoir for powergenerating operations. Working fluid flows downhole and into the diverter tool 50, pushing against and putting additional force on the flapper to ensure it is fully engaged with the corresponding shoulder 55 of the flapper housing 54. Isolation of the pump is similarly ensured, and the working fluid is fully diverted towards the turbine for power generation. The flapper remains in the open position until the pump is initiated once more, thereby pivoting the flapper in the closed position. It is thus noted that the flapper can autonomously and / or automatically move between the open and closed positions based on the operations SPHS system.

[0123] Now referring to Figures 6 and 7, the ESP assembly 21 can include a pair of ESPs 22 coupled to the tubing string 42 to cooperate with the flow of working fluid along the tubing string. In this implementation, the ESPs 22 are non-dedicated to an operational configuration. In other words, the ESPs can each cycle between pumping and powergenerating operations. In some implementations, the ESPs 22 can form a series circuit, where working fluid flows along a single path between the upper and lower reservoirs. Alternatively, the ESPs can form a parallel circuit, where working fluid flows along separate paths along at least a portion of the SPHS system between the upper and lower reservoirs.

[0124] Referring more specifically to Figure 6, the ESP assembly 21 illustratively includes a pair of ESPs 22 mounted in parallel, and therefore forming the parallel circuit. When operating in parallel, both ESPs 22 work independently from one another. For example, during pumping operations, both ESPs 22 are operable to pump working fluid to the upper reservoir. In this implementation, the discharge of each ESP 22 is combined within the tubing string 42 to generate higher flowrates of working fluid. It should be noted that the working fluid can be pumped at higher flowrates, for instance, when compared to previously described implementations using a single dedicated pumping ESP (seen in Figure 4). Similarly, operating both ESPs of the ESP assembly as turbines enables higher working fluid injection rates. More specifically, the working fluid fed to the lower reservoiris split between the two ESPs 22, resulting in increased power generation. This configuration can be used when a single ESP would be unable to handle the torque generated by the hydraulic head and / or fluid injection rates, for example. It should also be noted that, since both ESPs can operate independently from the other, each ESP can be operatively coupled to respective RVSDs at surface.

[0125] The present implementation includes a diverter tool 51 to enable connecting the ESP conduits to one another and to the tubing string 42. As seen in Figure 6, the diverter tool 51 is located uphole of the pair of ESPs 22. As such, the discharge of each ESP 22 is combined as it flows through the diverter tool 51 and within the tubing string 42. Inversely, as fluid is injected and / or fed into the lower reservoir, the diverter tool 51 is adapted to split the working fluid flow in two separate flows for operating respective turbines. In some implementations, the diverter tool 51 corresponds to a Y-tool adapted to correspondingly combine two fluid paths into one (e.g., when pumping) and split one fluid path into two (e.g., when generating power). However, it is appreciated that other configurations and implementations of the diverter tool are possible and can be used.

[0126] In this implementation, the discharge of each ESP 22 is combined within the tubing string 42 to generate higher flowrates of working fluid. It should be noted that the working fluid can be pumped at higher flowrates, for instance, when compared to previously described implementations using a single dedicated pumping ESP (seen in Figure 4). Similarly, operating both ESPs of the ESP assembly as turbines enables higher working fluid injection rates. More specifically, the working fluid fed to the lower reservoir is split between the two ESPs 22, resulting in increased power generation. This configuration can be used when a single ESP would be unable to handle the torque generated by the hydraulic head and / or fluid injection rates. It should also be noted that, since both ESPs can operate independently from the other, each ESP can be operatively coupled to respective RVSDs at surface.

[0127] Now referring to Figure 7, the pair of ESPs 22 of the ESP assembly 21 are mounted in series, thereby forming the series circuit. When operating in series, both ESPs 22 cooperate with one another. For example, during pumping operations, the lower ESP (e.g., the first ESP 22a) pumps working fluid from the lower reservoir to the fluid intake of the upper ESP (e.g., the second ESP 22b). The upper ESP then pumps the working fluidto the upper reservoir. The lower ESP can be adapted to pump generally low-pressure working fluid (e.g., fluid in the lower reservoir) to a medium pressure between the fluid discharge of the lower ESP and the fluid intake of the upper ESP. Operation of the ESP then brings the medium-pressure working fluid to a high-pressure working fluid to enable lifting the fluid to the upper reservoir. This configuration can be used for high hydraulic head applications. For example, multiple ESPs installed in series can be used when the desired flowrates and / or hydraulic head exceed the limitations of a single-ESP SPHS system. When operating the ESPs as turbine, the series circuit enables working fluid to pass through the upper ESP to generate power. The working fluid flows through the upper ESP and into the lower ESP, where additional power is generated. Lastly, the working fluid flows through the lower ESP and into the lower reservoir.

[0128] In this implementation, the downhole tool 20 includes a pair of diverter tools 51 coupled to the tubing string 42 and the pair of ESPs 22. The pair of diverter tools 51 includes a first diverter tool 51a adapted to split the flow of working fluid into two separate flows. However, and as seen in Figure 7, the first diverter tool 51a is provided with a plug 62 configured to prevent fluid communication along one of the two paths defined by the first diverter tool 51a. As such, it is noted that the working fluid only flows down one path and into the upper ESP. The pair of diverter tools 51 also includes a second diverter tool 51b positioned between the upper and lower ESPs, and which is inverted relative to the first diverter tool 51a. In this implementation, the second diverter tool 51b is adapted to direct the working fluid from the upper ESP to the lower ESP to generate power via both ESPs 22. The plug 62 is adapted to block the path connecting the first and second diverter tools 51a, 51b such that all working fluid flows through each ESP in succession. The plug can also provide structural support to the ESP assembly 21. Similar to previous implementations, each ESP of the series circuit can be operatively coupled to respective RVSDs at surface.

[0129] Referring broadly to Figures 4 to 7, the well can include one or more packers 38 configured to isolate sections of the well from one another. This configuration can enable the production casing (e.g., the casing 40) to be isolated from the working fluid being pumped to the upper reservoir and / or fed to the lower reservoir. In each implementation, the packers 38 are installed within the annulus 44, defined as the space between the casing 40 and the tubing string 42, above the ESPs 22, such as above the diverter tool51, thus defining well sections on either side thereof. The casing well section below the packer, or the downhole section 46, can be subjected (e.g., exposed) to the working fluid. The casing well section above the packer 38, or the uphole section 48, can therefore be isolated from being subjected to the working fluid. In other words, the annulus 44 is isolated from the working fluid above the packer 38. In some implementations, the casing 40 is isolated from the working fluid due to the potential for corrosion. For example, working fluid, such as reservoir brine / saline brine, can be corrosive and damage and / or weaken the casing over time. The potential for corrosion is one of the reasons why working fluid is typically contained within the tubing string 42. Generally, the only internal part of the casing 40 which can come in contact with the working fluid is located below the packers 38, in the downhole section 46. It is noted that the packer can be provided with a cable pass-through to allow the power cable 26 to pass through the packer 38 for connection with the motor of the ESPs 22. The cable pass-through can correspond to a hole defined through the packer 38 using a packer penetrator tool for enabling extension of the power cable therethrough.

[0130] In some implementations, the size (e.g., diameter) of the ESPs 22 can be adapted to the size of the tubing string and / or casing. It should be noted that a SPHS system 10 having a larger tubing string and casing can be coupled to larger ESPs 22 which can be operated to generate more power when compared to SPHS systems 10 operating with smaller tubing, casing, and ESPs. More particularly, while introducing fluid downhole at a given flowrate, smaller tubing strings allow for smaller volumes of fluids to flow, which, when operating the ESP in turbine mode, results in less power being generated. Moreover, smaller tubing strings can create more friction forces than larger tubing strings (at the same flowrate), thereby reducing the overall fluid flowrate, further reducing the amount of power generated.

[0131] It should therefore be understood that larger wells can be better suited for the generation of larger amounts of electricity. However, it is known that larger wells are more expensive to drill and complete, and that corresponding larger casings, tubing strings and equipment (e.g., ESPs) suitable to engage those larger wells are similarly expensive. It should also be noted that limiting the flow path of the working fluid to the tubing string 42 (e.g., using packers 38) can correspondingly limit the flowrates during pumping and / or power-generating operations.

[0132] In another implementation, and with reference to Figures 8 to 11, the SPHS system 10 can be operated to include both the passage of the tubing string 42 and the annulus 44 when working fluid is pumped and injected between the upper and lower reservoirs. In this implementation, the tubing string 42 can include one or more ports 72 (e.g., openings) enabling fluid communication between the passage of the tubing string and the annulus 44. The downhole tool 20 can also include a sliding sleeve 74 operable to selectively open and close the ports 72, thereby controlling the state of fluid communication between the passage of the tubing string and the annulus 44. Particularly, the sliding sleeve 74 can be slidably coupled to the tubing string 42 and operable between a closed configuration, where the sliding sleeve 74 obstructs / occludes the ports 72 and prevents fluid communication therethrough, and an open configuration, where fluid communication through the ports 72 is enabled. It is thus noted that working fluid can flow along the tubing string 42 only via operation of the sliding sleeve in the closed configuration, and that working fluid can flow along both the tubing string and the annulus 44 via operation of the sliding sleeve in the open configuration. The casing 40 can be made from corrosion resistant material and / or be provided with a corrosion resistant coating. The casing 40 can also be subjected to scheduled pressure tests and corrosion inhibitor treatments to further assist in preventing corrosion damage.

[0133] In some implementations, the sliding sleeve 74 can be generally cylindrical and coupled to the tubing string 42. The sliding sleeve 74 can have an occluding section configured to occlude the ports 72 when aligned therewith, and an open section configured to allow fluid flow through the ports 72 when aligned therewith. For example, the occluding section can correspond to a solid section of the body of the sliding sleeve 74, and the open section can correspond to sleeve ports defined through a thickness of the sliding sleeve to enable fluid flow through the ports 72 when aligned therewith. Alternatively, to operate the sliding sleeve from the closed configuration to the open configuration, the sliding sleeve can be shifted to a position leaving the ports 72 unobstructed and open to enable fluid communication therethrough. It is appreciated that other configurations are possible for modulating fluid flow between the tubing string and the annulus, and that the implementations described above are exemplary and should not be considered limiting.

[0134] As seen in Figures 8 to 11, the SPHS system 10can include an occluding device catcher 76 adapted to hold, release, retrieve, catch, or otherwise cooperate with anoccluding device, such as a ball 78 or a dart. It is appreciated that the occluding device can be removably connected to the occluding device catcher 76 and introduced down the wellbore together with the downhole tool 20. In some implementations, the ball 78 can be disconnected from the occluding device catcher 76 for engagement with an inner profile of the packer 38 (e.g., a seat 79) in order to occlude the working fluid passage through the packer 38. It is noted that, by occluding the fluid passage through the packer 38, and while the sliding sleeve 74 is in the open position to allow fluid communication through the ports 72 and between the tubing 42 and the casing uphole section 48, the casing uphole section 48 can be pressure tested without service rig intervention. Upon completion of the pressure test, the ESP(s) 22 can be operated in pump-mode to pump the ball 78 from the seat 79 within the packer 38 back to the occluding device catcher 76. It is appreciated that the occluding device can also be used in a configuration that enables increasing the fluid pressure inside the tubing string for actuating the sliding sleeve 74. Moreover, the occluding device profile (e.g., the seat 79) can alternatively be located at any other suitable location along the downhole tool 20 (e.g., along the tubing 42) and / or within the SPHS system 10 to enable blocking fluid flow and / or increasing fluid pressure in desired locations.

[0135] It should thus be understood that, in some implementations, the sliding sleeve 74 is fluid-pressure actuatable between the closed and open positions. Alternatively, or additionally, the sliding sleeve 74 can be adapted for mechanical actuation, where a running tool is lowered into the wellbore for engaging and shifting the sliding sleeve (e.g., directly or indirectly). Technologies for shifting sleeves in downhole tools are well known, for example, in the oil and gas industry, and it is appreciated that any suitable means, method and / or system can be implemented and used to shift the sliding sleeve between the closed and open positions.

[0136] In addition, while it is understood that larger wells can be better suited for the generation of larger amounts of electricity, larger wells are also more expensive to drill and complete. Moreover, the larger casings, tubing strings and equipment (e.g., ESPs), suitable to engage those larger wells, are similarly more expensive than their smaller counterparts. As such, in some implementations, enabling fluid flow along the annulus 44 can allow for smaller casings, tubing strings and equipment to be installed, thereby reducing brine flow friction effects and reducing the upfront capital required to install theSPHS system 10, which further improves the economics of the system. In some implementations, the tubing string 42 can be sized such that a majority of the working fluid flows along the annulus 44 of the well.

[0137] While the casing 40 (which can be manufactured and / or treated to resist to the corrosive effect of the working fluid) can be between 3” to 8” wider than the tubing string. For example, the tubing string can have a diameter of about 3” or less. As such, the annulus 44 can define most of the flow area through which working fluid can flow. It is appreciated that incorporating smaller tubing strings can reduce costs, while also enabling the installation of a correspondingly smaller ESP assembly (e.g., smaller ESPs 22), which can also reduce costs. It is noted that, while the annular flow of working fluid is illustrated and described in combination with an ESP assembly having a plurality of ESPs 22 (e.g., at least two), other configurations are possible. For instance, an SPHS system provided with an ESP assembly having a single ESP 22 can be operated using the above-described methods enabling fluid flow along the annulus 44. For instance, a single-ESP assembly can include the sliding sleeve 74 and corresponding occluding device catcher 76 to enable fluid flow along the annulus.

[0138] In other implementations, and with reference to Figures 12 and 13, the pair of ESPs 22 can be mounted in series and the SPHS system 10 can include an ESP housing 80 configured to establish a structural connection between the lower ESP and the upper ESP, while simultaneously providing a continuous working-fluid conduit. In this implementation, the lower ESP 22a and upper ESP 22b remain axially aligned within the wellbore such that the ESP assembly can remain centralized (e.g., relative to the wellbore). It should be noted that, by having the lower and upper ESPs remain axially aligned, the fluid flowpath is no longer split, diverted or forced down a smaller conduit (e.g., as seen in Figures 7 and 11). The ESP housing 80 includes a tubular member 82 securable at a lower end thereof to the lower ESP 22a and at an upper end thereof to the upper ESP 22b. The ESP housing 80 thereby forms an enclosed conduit 85 defining the working-fluid flowpath between the two ESPs.

[0139] The ESP housing 80 defines and maintains a large cross-sectional area for the passage of the working fluid, which can assist in reducing the frictional losses, for instance, when compared to implementations where the working fluid is diverted intosmaller-diameter conduits. In addition, it is noted that, by maintaining a single, centralized flowpath between the two pumps, the assembly avoids having to install a second tubing string for structural support. It should thus be understood that the ESP housing 80 simplifies the mechanical layout of the ESP system. A simplified design can assist in reducing potential for vibration, cavitation and / or erosion, thereby increasing subsurface equipment longevity. The simplified design can also help reduce installation costs, directly improving economics of the SPHS system

[0140] The ESP housing 80 can also include one or more cable pass-throughs 86, for example, to route power and instrumentation cables to the ESPs 22. In some implementations, a single cable pass-through 86 (e.g., a single hole) can be defined proximate the upper end of the ESP housing 80 for cables 26 dedicated for the upper ESP 22b, as shown in Figure 12. However, in some implementations, the ESP housing 80 can be provided with additional (e.g., one or more) cable pass-throughs provided at one or both ends thereof for allowing cables 26 therethrough for connecting with the lower ESP 22a, as shown in Figure 13. The cable pass-throughs can enable integrating the cable 26 routing within the ESP housing 80, which can protect the cables 26 from external abrasion and can also reduce the overall outer diameter of the ESP assembly. In this implementation, the ESP housing 80 can have an external diameter which is greater than the ESPs and / or the tubing string 42. However, the external diameter of the ESP housing 80 can be less than the overall diameter of the off-set configuration of ESPs, such as those illustrated in Figures 4 to 11, for example.

[0141] In some implementations, the ESP housing 80 can be used together with the packer 38, the ports 72 and / or the sliding sleeve 74, as previously described, to enable fluid flow into and along the annulus 44. However, it is appreciated that the packer 38 is not required in all implementations and can be omitted, for instance, for applications in which annulus isolation from the working fluid is not required or desired. It is noted that the annulus being isolated from the working fluid can prevent, or at least reduce, fluid-induced corrosion of the casing 40, among others.

[0142] This implementation can also include the occluding device catcher 76 adapted to catch an occluding device, such as the ball 78, to permit pressure testing the casing 40, such as uphole of the packer 38, for example. When the occluding device 78 is releasedfrom the occluding-device catcher, it travels down the tubing string and seats in an occluding-device profile (e.g., the seat 79). If the mechanical sliding sleeve is open, the annulus 44 can be pressure-tested, and if the sliding sleeve is closed, the tubing string 42 can be pressure-tested. After pressure testing, the occluding device may be pumped back to the occluding-device catcher by operating the ESPs in pump mode. The sliding sleeve also provides flexibility to allow tubing-only flow or combined tubing-and-annulus flow, which can reduce friction losses and can reduce the required tubing size and associated installation costs. The ability to pressure-test the annulus without rig intervention can enable using the annulus for working-fluid flow for certain applications / operations.

[0143] With reference to Figure 14, in addition to Figures 8 to 13, the occluding device catcher 76 can be integrated or connected to the wellhead 5 (e.g., proximate the surface). The wellhead 5 can be provided with various conduits defining flowpaths to enable fluid communication of working fluid between the surface (e.g., in storage, in the upper reservoir, from vehicles, etc.) and the downhole tool 20 and associated parts (e.g., the casing 40, the tubing 42, the ESPs 22, the lower reservoir, etc.). In this embodiment, the wellhead 5 includes a tubing string conduit 90 configured to establish fluid communication between the tubing 42 and the surface components. The wellhead 5 also includes an annulus conduit 92 configured to establish fluid communication between the annulus 44 and the surface components. As seen in Figure 14, the tubing string conduit 90 and the annulus conduit 92 can be linked to enable a surface flow (S) to flow into and out from the SPHS system 10. For example, the surface flow (S) can be defined between the storage tank and / or the upper reservoir and the corresponding conduits of the wellhead.

[0144] The tubing string conduit 90 and the annulus conduit 92 can be provided with respective valves 95 operable between open and closed configurations, respectively enabling and blocking fluid flow through the conduits. In this embodiment, the wellhead 5 includes a central conduit 94 configured to establish fluid communication between the tubing 42 and the occluding device catcher 76. The occluding device 78 (e.g., the ball or dart) can therefore be adapted to travel along the central conduit 94 and into the tubing 42 to ultimately land on the seat within the packer 38. It should be noted that the ball is released from the occluding device catcher 76 and seated on the seat when pressuretesting the downhole conduits (e.g., the casing 40 and / or the tubing 42). In order to perform a pressure-test, a pressure flow (P) is pumped into the central conduit 94 from the surface.For instance, a truck tie-in can be coupled to one or more conduits to enable fluid flow into the system.

[0145] In some embodiments, a ball valve 95b located within the occluding device catcher 76 is opened to release the occluding device 78 therefrom. A central valve 95a can also be provided and opened to enable the occluding device to travel from the occluding device catcher 76, along the central conduit 94 and into the tubing 42. Once the occluding device 78 engages with the seat, fluid can be pumped from the surface (e.g., along the pressure flow (P)) to fill and pressurize the tubing 42 and / or the annulus 44. Pressure tests can then be conducted (e.g., using a pressure truck). After completing the pressure test, the pressure is bled off from within the tubing and / or the annulus, and the pressure test truck tie-in line can be closed. It should be noted that, in order to conduct the pressure test, fluid flow to the ESP assembly is occluded. As such, the ESPs can be configured in either the pumping mode or the turbine mode as no fluid flows through the ESPs.

[0146] In this embodiment, the occluding device 78 can be unseated and retrieved to resume standard operations of the SPHS system. The ESPs can be operated in pumping mode to allow working fluid to carry the occluding device 78 back to the occluding device catcher 76. The central valve 95a and the ball valve 95b remain open to allow passage of the occluding device. The working fluid is allowed to flow through the occluding device catcher until the occluding device is returned. The ball valve 95b can be slotted and / or include valve passages configured to enable fluid flow therethrough when operated in the closed configuration. As such, it is appreciated that fluid flow through the ball valve is allowed during retrieval of the occluding device, which facilitates retrieval. A pressure-test valve 95d can be provided and closed to urge the working fluid towards the storage tank(s) and / or the upper reservoir. It is noted that an overflow valve 95e can be provided and opened to enable the working fluid to flow into the storage tank(s) and / or the upper reservoir. However, the overflow valve 95e is closed to urge working fluid into the tubing string conduit 90 and the annulus conduit 92.

[0147] In this embodiment, the occluding device catcher 76 is configured to enable entry of the occluding device 78 therein (e.g., from the central conduit 94), but prevent passage therethrough. In other words, the occluding device catcher 76 “catches” the occludingdevice. Once the occluding device is caught, the ball valve 95b can be closed to prevent the occluding device from exiting the occluding device catcher back down the central conduit 94, for instance. In addition, upon closing the ball valve to capture the occluding device, the central valve 95a below can be closed to prevent working fluid from flowing through the wellhead vertically until the next pressure test. Standard pumping and turbine operations of the SPHS system 10 can then be resumed.

[0148] Referring back to Figures 12 and 13, the ESP assembly can be operated in pump mode and in turbine mode, similar to previously described implementation. In this implementation, when operating the ESP assembly in pump mode, working fluid from the lower reservoir is made to enter the intake of the lower ESP 22a. The lower ESP 22a then pressurizes the working fluid and discharges it into the ESP housing 80. The working fluid then travels upward through the ESP housing 80 and into the intake of the upper ESP 22b. The upper ESP 22b further increases the fluid pressure to a level sufficient to lift the working fluid to the upper reservoir. Particularly, from the discharge of the upper ESP 22b, the working fluid flows into the tubing string 42 and the annulus 44 (if allowed) to then flow to the upper reservoir. It is therefore appreciated that the lower ESP 22a can be configured to boost (e.g., increase) an interstage pressure, corresponding to a pressure within the ESP housing 80.

[0149] In turbine mode, working fluid flows from the upper reservoir, through the tubing string 42 and enters the intake of the upper ESP 22b. The incoming working fluid causes rotation of the pump stages of the upper ESP, which function as a turbine, to generate power. The working fluid then exits via the discharge of the upper ESP 22b to flow into the ESP housing 80, and into the intake of the lower ESP 22a. The lower ESP 22a, operating in turbine mode, generates additional power as the working fluid passes through it. The working fluid exits via the discharge of the lower ESP 22a and flows into the wellbore, and ultimately into the lower reservoir.

[0150] It should also be noted that wells suited for high flowrates (e.g., wide casing, tubing string, etc.) and greater hydraulic head (e.g., deep lower reservoir) can create runaway conditions of the ESPs. This is especially true if the ESPs are not protected by the surface RVSD, which can lead to reduced efficiency, damages and / or complete failure of the SPHS system. It is therefore noted that, while larger tubulars can be suited to generatemore power, those same tubulars can pose a significant operational risk to the ESP assembly, for instance, if the ESPs are not designed to the operational parameters of the SPHS system. Operational balance of the SPHS system requires suitably-sized tubulars with regards to power-generating goals, the equipment used, and the overall economics of the SPHS system.

[0151] Therefore, it is noted that some of the parameters of the SPHS system can be established based on one or more other known parameters. For instance, if a desired power-generation output is known (e.g., over 1MWh), then specific ranges of tubular sizes / diameters, pumps and motor / generator specifications, hydraulic head, fluid flowrates, among others, can be established for the SPHS system 10. As an example, known equipment (e.g., ESPs) adapted to generate over 1MWh of power can require tubing strings having an outer diameter of 7” or more. As such, in this case, the surrounding casing would have an inner diameter of about 11” or more to accommodate the larger tubing string and define a suitably-sized annulus to house the motor lead extension and the power cable. It is appreciated that these dimensions can be adjusted if the SPHS system is adapted to enable fluid flow along the annulus. For instance, the tubing string can have a smaller outer diameter (e.g., smaller than 7”) and / or the casing can have a smaller inner diameter (e.g., smaller than 11”) while still allowing the SPHS system to generate over 1 MWh of power.

[0152] In other implementations, such as when retrofitting existing wells as part of the SPHS system, the well parameters can be known, which allows for a selection of an ESP assembly having desired characteristics and / or for the operation of the SPHS system within specific operational parameters. For example, conventional oilfield wells typically have production casings of 5.5” to 7”, with tubing strings of 3.5” or less. ESPs suited for conventional oilfield wells can be implemented in the SPHS system and operated under specific operational parameters to establish and maintain the operational balance of the system. The power-generating output can therefore be known, or at least partially predicted, if the chosen ESP specifications are known prior to installation due to knowledge of the wellbore and well parameters.

[0153] It should also be noted that the parameters of the SPHS system 10 can depend on the parameters of the lower reservoir in which the well of the SPHS system 10 islocated. For example, as stated above, larger tubulars can accept greater volumes of fluids at a desired flowrate. However, if the lower reservoir has low permeability and / or high pressure, the working fluid will not be able to flow into or be extracted from the lower reservoir at a sufficiently high rate to maintain the viability of the SPHS system. In such cases, the tubular size is adjusted (e.g., reduced) to compensate for the low reservoir permeability. It is noted that the size of the tubular can be proportional to the permeability of the reservoir, where higher permeability allows for larger tubulars. It is understood that reducing the tubular size can correspondingly reduce the amount of power generated, as previously discussed. However, in scenarios with low reservoir permeability, the operational balance of the SPHS system can be increased by reducing the size of the tubulars due to the restrictive parameters of the reservoir.

[0154] The reservoir pressure can also affect the operational balance of the SPHS system 10. For example, higher formation pressures can reduce the pressure head acting on the turbine, leading to reduced power generation. Therefore, it can be desirable to select suitably under-pressured lower reservoirs to increase the pressure differential across the turbine for increased power generation. As previously stated, the selected well can correspond to an existing completed well which has been operated to produce material from a subsurface reservoir, which has since been depleted. The depleted reservoir therefore defines the under-pressured lower reservoir, allowing for a greater pressure head of the SPHS system and higher power generation potential of the SPHS system. In some implementations, the lower reservoir can include depleted natural gas pools, suspended and / or abandoned oil reservoirs, salt caverns and / or brine aquifers, among other possibilities.

[0155] It is noted that brine aquifers (or brine reservoirs) correspond to reservoirs which do not contain any hydrocarbons (e.g., gas or oil), which can make these types of reservoirs suitable and desirable for the SPHS system. For instance, the brine reservoir can be adapted for the SPHS system by removing at least some of the brine fluid therefrom in order to reduce the pressure of the lower reservoir, if required. Brine fluid is typically not as compressible as gas, for example, such that removing a small amount of brine fluid from the reservoir can reduce the pressure to a level suitable for operation of the SPHS system. The brine fluid removed in this manner can be displaced and / or disposed into another adjacent reservoir, such as a reservoir which does not have attributes suitable forthe SPHS system. It is thus noted that adjusting the pressure of a first reservoir (e.g., by removing some brine fluid) for establishing a first SPHS system can simultaneously enable adjusting the pressure and / or attributes of a second reservoir to work towards establishing a second SPHS system.

[0156] In view of the above, it is appreciated that a plurality of parameters of the SPHS system are linked to one another. Therefore, known parameters can assist in establishing ranges or thresholds for other parameters. For example, for a given ESP assembly, the lower reservoir can be located at a maximum depth to maintain technical viability of the various ESPs, for example, to avoid load rejection and / or run-away conditions of one or more of the ESPs in turbine mode. In some implementations, desired power-generation output can be predetermined, thereby setting a threshold (e.g., a minimum) for the characteristics of the ESP assembly, for example, a minimum number of ESP stages and / or impellers for each ESP to convert the available hydraulic head for optimized power generation. Friction forces thresholds can also be established to assist in generating the desired amounts of power, which in turn can define a threshold for the minimum size of the well tubulars and / or assist in defining fluid flow paths (e.g., tubing string only, annulus only, tubing string and annulus, etc.).

[0157] A variability of lower reservoir parameters is indicative that SPHS system equipment and tubular design can be custom-built (e.g., “unique”) for each installation. For example, a lower reservoir with low pressure, high permeability, is a “high head and high working fluid injection rate” application. In some implementations, in order to optimize power generation, larger diameter wellbores and tubulars can be selected, for instance, to reduce losses due to friction. A higher ESP stage / impeller count (i.e. , additional stages of centrifugal pumps) can also be selected to make use of the available hydraulic head. In addition, pump / turbine and motor / generator size can be increased to take advantage of the low pressure, high permeability lower reservoir, and / or a different number of ESPs can be installed. Alternatively, a lower reservoir with lower permeability but which still has high hydraulic head can still require ESPs with high ESP stage / impeller counts, but the tubulars can be smaller, as lower working fluid injection rates will minimize friction losses. In this application, the power generation potential is reduced, allowing for smaller ESP equipment. It is thus noted that mechanical and geological parameters can also impact the design of SPHS systems. Ultimately, economic viability resulting from changing SPHSparameters must be carefully analyzed. For example, high working fluid rate and high hydraulic head applications generate more power, however, these installations also require larger and more expensive equipment. In most scenarios, a cost / benefit analysis can be decisive in determining if the upside is worth the extra costs.

[0158] As previously discussed, in some implementations, the SPHS system is retrofitted into an existing well. The well parameters can therefore be known and can assist in making an equipment selection. For instance, the general steps can include:> collecting information relative to the selected well (e.g., depth of lower reservoir, casing size, reservoir temperatures and pressures, permeability, etc.);> verify the planned flow rate and pressure of the pumped and / or injected working fluid based on the collected information;> size the ESPs accordingly (e.g., each ESP diameter, number of stages and motor / generator size) based on the planned flow rates and available hydraulic head; and> establish the ESP assembly configuration (e.g., number of ESPs, series circuit, parallel circuit, etc.).

[0159] With reference to Table 1 below, example implementations of SPHS system parameters are depicted. The table provides exemplary parameters of the well, such as minimum casing size and a corresponding maximum tubing string size, exemplary parameters of the ESP, such as pump / turbine size, and exemplary operational parameters of the SPHS system, such as pump rates, turbine rates and power generation capabilities. It is appreciated that larger tubulars (e.g., ESP series D and E) can accommodate larger pumps and turbines which in turn enable greater amounts of power generation, as previously discussed. However, these parameters have to be balanced with the subsurface formation parameters to improve the efficiency of the SPHS system.Oil & Gas ESP Pump / Turbine Average Pump Average Turbine Minimum Casing Max Tubing Size for Min Power Generated Series Size OD (In) Rate(bbls / d) Rate (bbls / d) Size OD (in) Casing Size OD (in) kW A 53 / 8 10,000 15,000 7 3 1 / 2 130 B 55 / 8 20,000 30,000 85 / 8 4 1 / 2 220 C 7 1 / 4 30,000 45,000 95 / 8 5 1 / 2 360 D 9 1 / 2 45,000 67,500 11 3 / 4 7 1,200 E 11 1 / 4 75,000 112,500 135 / 8 95 / 8 1,800Table 1 - example implementations of SPHS system parameters

[0160] For example, an existing well having a casing of about 10” is selected to be retrofitted / repurposed as part of a new SPHS system. The casing diameter therefore establishes a threshold for the “maximum tubing size” parameter. In this implementation, and using Table 1 as a reference, it is noted that ESP series A, B and C are suitable for installation within the selected well due to the casing size. In order to maximize power generation, ESP series C can be preliminarily selected. Then, upon analysis of the subsurface formation parameters, such as the depth of the lower reservoir, the lower reservoir temperature, the lower reservoir pressure, the lower reservoir permeability, etc., it is concluded that the lower reservoir is not suited for accommodating flowrates (e.g., when injecting or extracting) greater than about 25,000bbls / d. Therefore, the ESP series C is rejected as a suitable choice, and the ESP series B is instead selected. This configuration of components provides improved efficiency by balancing the parameters of the well, the ESP and the subsurface formation. It is appreciated that ESP assemblies having multiple ESPs installed either in series or in parallel can have any suitable combination of ESP series A to E to optimize, or at least improve, power generation using a given well having known parameters.

[0161] However, it is appreciated that, in the case of a new well, which is drilled and completed with desired dimensions to reach a lower reservoir at a desired depth, the reservoir parameters can be substantially optimized to accommodate downhole equipment designed to generate a desired power-generation output. For example, and with continued reference to Table 1, a new well can be drilled and completed with a 13-5 / 8” casing, provided with 9-5 / 8” tubing adapted to be coupled to a pair of ESP series E respectively operable, in the pumping mode, to pump 75,000 bbls / d, and suited to receive,in the turbine mode, flow rates of 112,500 bbls / d, resulting in a power generation output of about 1,800 kW.

[0162] It will be appreciated from the foregoing disclosure that there is provided a subsurface pumped hydropower storage system having an electric submersible pump assembly including multiple electric submersible pumps which can be operated as both a pump and a turbine. Therefore, a single well can be used to incorporate an underpressured and / or depleted subsurface reservoir in the subsurface pumped hydropower storage system. Conventional well completions and downhole tools can be leveraged from the oil & gas industries in the context of subsurface pumped hydropower storage. The present disclosure recognizes that under-pressured subsurface reservoirs (such as depleted natural gas pools, suspended or abandoned oil reservoirs, salt caverns, brine aquifers / brine reservoirs, etc.) can be used as the lower reservoir in the subsurface pumped hydropower storage system. Particularly, the lower reservoir can be connected to an upper reservoir (at or near the surface), by a completed well, such that a working fluid can be cycled between the upper and lower reservoirs. However, the technical and economic viability of the subsurface pumped hydropower storage system requires an operational balance between parameters of the well, the pump, the turbine, tubular sizes, the working fluid, the subsurface reservoir and the operational parameters of the overall system (e.g., flowrates, pressures, temperatures, etc.).

[0163] The described ESPs of the ESP assembly are configured to cycle between a pumping mode, where fluid is pumped to the upper reservoir, which consumes electricity, and a turbine mode, where fluid is injected into the lower reservoir, which produces electricity. Alternatively, at least one of the multiple ESPs is operated as a dedicated pump, while at least another one of the ESPs is operated as a dedicated turbine. These configurations enable single-well implementations that avoid the large capital outlays associated with drilling / completing / retrofitting a second well. However, it should be noted that additional wells can be implemented in the SPHS system. Multi-well implementations can include at least two ESP assemblies, which allows for the ESPs of one ESP assembly (in a first well) to be dedicated for pumping, and for the ESPs of another ESP assembly (in a second well) to be dedicated for power generation (turbine mode).

[0164] The present disclosure also recognizes the need to maintain an operational balance to achieve technical and economic viability of the SPHS system. Using ESPs as a pump and / or a turbine requires staying within its mechanical tolerances in both operational modes. In turbine mode, this can correspond to throttling the flow rate to prevent load rejections and run-away conditions. However, this results in a commensurate decrease in power generation, which threatens project economics. The disclosed SPHS system maintains viable economics by selecting suitably under-pressured reservoirs and employing adapted tubing diameters, pump / turbine stages, automation controls, fluid column heights, etc. In other words, the SPHS system utilizes custom flowrates and head, specific to the lower reservoir’s unique attributes (e.g., pressure, temperature, permeability, fluid specific gravity, etc,), to incorporate under-pressured subsurface reservoirs into SPHS systems. The SPHS system can also be adjusted to define desired flowpaths between the upper and lower reservoirs. During operations, working fluid can be made to flow along the tubing string of the SPHS system, along the annulus (between the tubing string and the casing), or along both.

[0165] The described example implementations are to be considered in all respects as being only illustrative and not restrictive. For example, although the SPHS system is described as cycling the working fluid between the upper and lower reservoirs, it should be noted that residual oil and / or gas can be extracted from the subsurface reservoir. In such instances, the surface facilities can include and / or be equipped with the proper tools to enable separation of the oil and gas from the working fluid. In an attempt to avoid pumping residual oil / gas from the subsurface reservoir, the selected subsurface reservoir can be sufficiently thick such that oil and gas migration to a structurally high position within the lower reservoir has occurred (e.g., over geologic time or millions of years). The ESP assembly, which can be submerged in the lower reservoir, would therefore see very little to no residual / movable oil or gas at those depths. In some cases, the lower reservoir thickness is thin, thereby introducing additional risk of oil or gas inflow into the working fluid. In such cases, the intake of the lower ESP can be provided deeper in the well, such as below the bottom of the lower reservoir. As such, working fluid can be drawn from the bottom of the lower reservoir during operation of the lower ESP in pumping mode. It is noted that the movable substances at the bottom of the lower reservoir generally include, but are not limited to, saline working fluid, Positioning the lower ESP intake lower also allows the annulus to act like a separator, where lighter oil and gas can migrate to the topof the lower reservoir via the vertical relief within the annulus, while heavier saline working fluid enters the ESP intake lower in the annulus.

[0166] In the present disclosure, an implementation is an example or embodiment of the SPHS system. The various appearances of “one implementation,” “an implementation” or “some implementations” do not necessarily all refer to the same implementations. Although various features may be described in the context of a single implementation, the features may also be provided separately or in any suitable combination. Conversely, although the SPHS system and associated components may be described herein in the context of separate implementations for clarity, it may also be embodied in a single implementation. Reference in the specification to “some implementations”, “an implementation”, “one implementation”, or “other implementations”, means that a particular feature, structure, or characteristic described in connection with the implementations is included in at least some implementations, but not necessarily in all implementations.

[0167] As used herein, the terms “coupled”, “coupling”, “attached”, ’’connected” or variants thereof as used herein can have several different meanings depending in the context in which these terms are used. For example, the terms coupled, coupling, connected or attached can have a mechanical connotation. For example, as used herein, the terms coupled, coupling or attached can indicate that two elements or devices are directly connected to one another or connected to one another through one or more intermediate elements or devices via a mechanical element depending on the particular context.

[0168] Similarly, positional descriptions such as “top”, “bottom”, “above”, “under”, “below”, “left”, “right”, “front”, “rear”, “parallel”, “perpendicular”, “transverse”, “inner”, “outer”, “internal”, “external”, and the like should, unless otherwise indicated, be taken in the context of the figures and should not be considered limiting.

[0169] In the above description, the same numerical references refer to similar elements. Furthermore, for the sake of simplicity and clarity, namely so as to not unduly burden the figures with several references numbers, not all figures contain references to all the components and features, and references to some components and features may be found in only one figure, and components and features of the present disclosure whichare illustrated in other figures can be easily inferred therefrom. The implementations, geometrical configurations, materials mentioned and / or dimensions shown in the figures are optional, and are given for exemplification purposes only.

[0170] In addition, although the optional configurations as illustrated in the accompanying drawings comprises various components and although the optional configurations of the SPHS system as shown may consist of certain geometrical configurations as explained and illustrated herein, not all of these components and geometries are essential and thus should not be taken in their restrictive sense, i.e. should not be taken as to limit the scope of the present disclosure. It is to be understood that other suitable components and cooperations thereinbetween, as well as other suitable geometrical configurations may be used for the implementation and use of the SPHS system, and corresponding parts, as briefly explained and as can be easily inferred herefrom, without departing from the scope of the disclosure.

Claims

CLAIMS1. A subsurface pumped hydropower storage system, comprising:an upper reservoir proximate to surface and adapted to store working fluid corresponding to a fluid from a lower reservoir located within a subsurface strata;a completed well extending into the subsurface strata to reach the lower reservoir, the completed well comprising:a wellhead at the surface;a casing lining an inner surface of the well;a tubing string extending within the casing, the tubing string being adapted to establish fluid communication between the upper reservoir and the lower reservoir;a downhole tool comprising an electric submersible pump (ESP) assembly having a plurality of ESPs coupled to the tubing string and adapted to be submerged or in fluid communication with the lower reservoir, the ESP assembly being operable in a turbine configuration and a pumping configuration, wherein:when in the turbine configuration, at least one of the plurality of ESPs is adapted to generate electricity in response to the working fluid being released from the upper reservoir and flowing downhole into the lower reservoir and passing through the downhole tool, the electricity being transmitted to the surface via a power cable connected to the corresponding ESP, andwhen in the pumping configuration, at least one of the plurality of ESPs is adapted to use electricity received from the surface via the power cable to provide lift and pump the working fluid from the lower reservoir to the surface and into the upper reservoir.

2. The subsurface pumped hydropower storage system of claim 1, wherein the casing has a casing diameter between about 5-1 / 2” and 13”, and wherein the tubing string has a tubing diameter between about 2-7 / 8” and 10”.

3. The subsurface pumped hydropower storage system of claim 1 or 2, wherein each ESP comprises an electric motor and pump impellers, wherein:when in the pumping configuration, the electric motor is powered by the power cable and operable to engage the impellers in rotation to provide lift to the working fluid within the lower reservoir; andwhen in the turbine configuration, the impellers are rotated via fluid flow and the electric motor is adapted to operate as a generator to generate electricity.

4. The subsurface pumped hydropower storage system of any one of claims 1 to 3, wherein the ESP assembly comprises a pair of ESPs.

5. The subsurface pumped hydropower storage system of any one of claims 1 to 4, wherein the ESP assembly comprises a lower ESP and an upper ESP, the lower ESP being proximate to or submerged in the lower reservoir.

6. The subsurface pumped hydropower storage system of claim 5, wherein the lower ESP is positioned below or within the lower reservoir, and the upper ESP is positioned above, within or below the lower reservoir.

7. The subsurface pumped hydropower storage system of any one of claims 1 to 6, wherein:when in the pumping configuration, the ESP assembly is adapted to provide a pump rate between about 5,000 and 75,000 bbls / d; andwhen in the turbine configuration, the ESP assembly is adapted to provide a turbine rate between about 10,000 and 112,500 bbls / d.

8. The subsurface pumped hydropower storage system of any one of claims 1 to 7, wherein the lower reservoir corresponds to any one of a suspended oil reservoir, an abandoned oil reservoir, a substantially depleted oil reservoir, a substantially depleted natural gas pool, a salt cavern, a brine aquifer and a brine reservoir.

9. The subsurface pumped hydropower storage system of any one of claims 1 to 8, wherein the upper reservoir comprises a storage tank at the surface or a pond.

10. The subsurface pumped hydropower storage system of any one of claims 1 to 9, wherein the completed well, the upper reservoir and the lower reservoir together define a closed-loop system.

11. The subsurface pumped hydropower storage system of any one of claims 1 to 10, wherein a pressure head is defined between the upper reservoir and the lower reservoir, and, when operating the ESP assembly in the turbine configuration, a corresponding working fluid pressure is generated, and wherein the working fluid pressure is greater than an internal pressure of the lower reservoir.

12. The subsurface pumped hydropower storage system of any one of claims 1 to 11, wherein the ESP assembly is operable in the pumping configuration to store the working fluid in the upper reservoir during periods of low electricity demand or during periods when renewable energy is curtailed, and wherein the ESP assembly is operable in the turbine configuration to generate electricity during periods of high electricity demand.

13. The subsurface pumped hydropower storage system of any one of claims 1 to 10, further comprising a power unit located at surface and being in electrical connection with each ESP of the ESP assembly via the power cable to provide electricity to the ESP assembly when in the pumping configuration, and to receive electricity from the ESP assembly when in the turbine configuration.

14. The subsurface pumped hydropower storage system of claim 13, wherein the power unit comprises a generator in electrical connection with the ESP assembly to supply power to each ESP operating in the pumping configuration.

15. The subsurface pumped hydropower storage system of claim 13 or 14, wherein the power unit comprises a grid connection in electrical connection with each ESP to supply power thereto when in the pumping configuration and / or to receive electricity therefrom when in the turbine configuration.

16. The subsurface pumped hydropower storage system of any one of claims 1 to 15, wherein a nearby load is in electrical connection with the ESP assembly to receive electricity therefrom when in the turbine configuration.

17. The subsurface pumped hydropower storage system of any one of claims 1 to 16, wherein each ESP of the ESP assembly is operatively coupled to respective regenerative variable speed drives (RVSD).

18. The subsurface pumped hydropower storage system of any one of claims 1 to 17, wherein the plurality of ESPs of the ESP assembly are installed in parallel to define a parallel circuit establishing fluid communication between the upper and lower reservoirs.

19. The subsurface pumped hydropower storage system of claim 18, wherein each ESP of the plurality of ESPs are configured to cooperate in a common configuration between the pumping and turbine configurations.

20. The subsurface pumped hydropower storage system of claim 18 or 19, wherein the downhole tool comprises a diverter tool coupled between the ESP assembly and the tubing string, the diverter tool being configured to:combine the working fluid being pumped to the upper reservoir by respective ESPs of the ESP assembly operating in the pumping configuration; and split the working fluid being injected or fed to the lower reservoir via the tubing string to have separate fluid paths leading working fluid to each ESP.

21. The subsurface pumped hydropower storage system of claim 18, wherein the ESP assembly includes a dedicated pump ESP and a dedicated turbine ESP.

22. The subsurface pumped hydropower storage system of claim 21, wherein the downhole tool comprises a diverter valve coupled between the ESP assembly and the tubing string, the diverter valve being operable between a pump position and a turbine position, and wherein:when in the pump position, the diverter valve prevents fluid flow to the dedicated turbine ESP to enable working fluid to be pumped by the dedicated pump ESP from the lower reservoir to the upper reservoir; andwhen in the turbine position, the diverter valve prevents fluid flow to the dedicated pump ESP such that the working fluid being released from the upper reservoir passes through the dedicated turbine ESP to generate electricity.

23. The subsurface pumped hydropower storage system of claim 21 or 22, wherein the diverter valve comprises a flapper mechanism selectively operable between pump position and the turbine position.

24. The subsurface pumped hydropower storage system of claim 23, wherein the flapper mechanism is configured to autonomously shift into the pump position upon operating the ESP assembly in the pumping configuration, and into the turbine position upon operating the ESP assembly in the turbine configuration.

25. The subsurface pumped hydropower storage system of claim 23 or 24, wherein the flapper mechanism includes a biasing element configured to bias the flapper mechanism in the turbine position such that, when the subsurface pumped hydropower storage system is idle, the flapper mechanism is in the turbine position.

26. The subsurface pumped hydropower storage system of any one of claims 1 to 17, wherein the plurality of ESPs of the ESP assembly are installed in series to define a series circuit establishing fluid communication between the upper and lower reservoirs.

27. The subsurface pumped hydropower storage system of claim 26, wherein the downhole tool comprises:a first diverter tool adapted to split a passage of the tubing string into two fluid passages; anda second diverter tool adapted to combine the two fluid passages into a lower fluid passage,wherein at least one of the plurality of ESPs is coupled to the lower fluid passage and at least another one of the plurality of ESPs is coupled to one of the two fluid passages.

28. The subsurface pumped hydropower storage system of claim 27, wherein the downhole tool comprises a plug installed in one of the two fluid passages to define aplugged fluid passage to prevent fluid flow therealong and forcing fluid flow to pass through the other one of the two fluid passages and through the series circuit.

29. The subsurface pumped hydropower storage system of claim 28, wherein the plug and the plugged fluid passage are adapted to provide structural support to the ESP assembly.

30. The subsurface pumped hydropower storage system of any one of claims 27 to 29, wherein the first and second diverter tools are symmetrical.

31. The subsurface pumped hydropower storage system of any one of claims 27 to 30, wherein the first and second diverter tools correspond to first and second Y-tools.

32. The subsurface pumped hydropower storage system of any one of claims 27 to 31, wherein the second diverter tool is inverted relative to the first diverter tool.

33. The subsurface pumped hydropower storage system of any one of claims 1 to 32, wherein the tubing string and the casing define an annulus therebetween, and wherein the tubing string comprises ports adapted to establish fluid communication between the tubing string and the annulus to enable working fluid to flow between the upper and lower reservoirs through the tubing string, through the annulus, or through both.

34. The subsurface pumped hydropower storage system of claim 33, wherein the downhole tool comprises a tubular sleeve slidably coupled to the tubing string, the tubular sleeve being operable between a closed configuration, where the tubular sleeve occludes the ports to prevent fluid communication between the tubing and the annulus and an open configuration.

35. The subsurface pumped hydropower storage system of claim 34, wherein the tubular sleeve is slidably coupled to an inner surface of the tubing string.

36. The subsurface pumped hydropower storage system of claim 33 or 34, wherein the tubular sleeve is mechanically or hydraulically actuatable between the closed and open configurations.

37. The subsurface pumped hydropower storage system of any one of claims 34 to 36, wherein the downhole tool comprises a seat configured to receive an occluding device, and wherein, upon having the occluding device engage the seat, fluid pressure withinthe tubing string and annulus is increased as working fluid is injected or fed into the tubing string to enable pressure testing the annulus.

38. The subsurface pumped hydropower storage system of any one of claims 34 to 37, wherein the downhole tool comprises a packer installed in the annulus and configured to isolate an uphole well section from a downhole well section.

39. The subsurface pumped hydropower storage system of claim 38, wherein the ports are defined in the tubing string within the uphole well section.

40. The subsurface pumped hydropower storage system of claim 38 or 39, wherein the tubular sleeve is located in the uphole well section in both the open and closed configurations.

41. The subsurface pumped hydropower storage system of any one of claims 38 to 40, wherein the ESP assembly is located in the downhole well section.

42. The subsurface pumped hydropower storage system of any one of claims 38 to 40, wherein the diverter tools are located in the downhole well section.

43. The subsurface pumped hydropower storage system of any one of claims 1 to 17 and 26, wherein the downhole tool further comprises an ESP housing secured between adjacent ESPs of the ESP assembly, the ESP housing being configured to establish a structural connection between the adjacent ESPs and establish fluid communication therebetween.

44. The subsurface pumped hydropower storage system of claim 43, wherein the ESP housing comprises a tubular member having a lower end secured to a first ESP of the adjacent ESPs, and an upper end secured to a second ESP of the adjacent ESPs, the tubular member defining an enclosed conduit for directing working fluid between the adjacent ESPs.

45. The subsurface pumped hydropower storage system of claim 43 or 44, wherein the ESP housing is configured to maintain the adjacent ESPs axially aligned within the casing.

46. The subsurface pumped hydropower storage system of claim 45, wherein the ESP housing is configured to maintain the adjacent ESPs centralized within the casing.

47. The subsurface pumped hydropower storage system of any one of claims 43 to 46, wherein the ESP housing is shaped and sized to define a working-fluid flowpath having a cross-sectional area equal to or greater than a cross-sectional area of the tubing string.

48. The subsurface pumped hydropower storage system of any one of claims 43 to 46, wherein the ESP housing is shaped and sized to define a working-fluid flowpath having a cross-sectional area smaller than a cross-sectional area of the tubing string.

49. The subsurface pumped hydropower storage system of any one of claims 43 to 48, wherein the ESP housing comprises one or more cable pass-throughs configured to route at least one power cable and / or instrumentation cable to at least one of the adjacent ESPs.

50. A process for generating electric power using the subsurface pumped hydropower storage system of any one of claims 1 to 49, the process comprising:a. operating the downhole tool in the pumping configuration;b. pumping fluid from the lower reservoir to the upper reservoir to store energy; c. operating the downhole tool in the turbine configuration; andd. pumping or gravity feeding fluid from the upper reservoir to the lower reservoir to generate electricity.

51. The process of claim 50, wherein steps a. to d. are cyclically repeated.

52. The process of claim 50 or 51, wherein the initial step of the process is step a or c.

53. The process of any one of claim 50 to 52, further comprising assessing the formation parameters, including determining which one of the upper reservoir and the lower reservoir contains the working fluid.

54. A subsurface pumped hydropower storage system, comprising :a completed well extending into a subsurface strata to reach a lower reservoir that is under-pressured, the completed well being configured to house fluid communication of working fluid and comprising:a wellhead at surface and being in fluid communication with an upper reservoir located at or proximate to the surface;a casing lining an inner surface of the completed well;a tubing string extending within the casing and defining an annulus therebetween, at least one of the tubing string and the annulus being adapted to establish fluid communication between the upper reservoir and the lower reservoir;a downhole tool comprising an electric submersible pump (ESP) assembly coupled to the tubing string and adapted to be submerged or in fluid communication with the lower reservoir, the ESP assembly being operable in a turbine configuration and a pumping configuration, wherein:when in the turbine configuration, the ESP assembly is adapted to generate electricity in response to the working fluid being released from the upper reservoir and flowing downhole via at least one of the tubing string and the annulus into the lower reservoir and passing through the downhole tool, the electricity being transmitted to the surface via a power cable connected to the ESP assembly, andwhen in the pumping configuration, the ESP assembly is adapted to use electricity received from the surface via the power cable to provide lift and pump the working fluid from the lower reservoir to the surface via at least one of the tubing string and the annulus and into the upper reservoir.

55. A downhole tool for connection with a tubing string extending within a casing lining an inner surface of a well extending into a subsurface strata to reach an under-pressured lower reservoir and having a wellhead at surface in fluid communication with an upper reservoir as part of a subsurface pumped hydropower storage system, the downhole tool comprising:an electric submersible pump (ESP) assembly coupled to the tubing string and adapted to be submerged or in fluid communication with thelower reservoir, the ESP assembly being operable in a turbine configuration and a pumping configuration, wherein:when in the turbine configuration, the ESP assembly is adapted to generate electricity in response to working fluid being released from the upper reservoir and flowing downhole via at least one of the tubing string and an annulus defined between the tubing string and the casing, and into the lower reservoir, the working fluid passing through the downhole tool, and the electricity generated is transmitted to the surface via a power cable connected to the ESP assembly, andwhen in the pumping configuration, the ESP assembly is adapted to use electricity received from the surface via the power cable to provide lift and pump the working fluid from the lower reservoir to the surface via at least one of the tubing string and the annulus and into the upper reservoir.

56. A subsurface pumped hydropower storage system, comprising :a completed well extending into a subsurface strata to reach a lower reservoir that is under-pressured, the completed well being configured to house fluid communication of working fluid and comprising:a wellhead at surface and being in fluid communication with an upper reservoir located at or proximate to the surface, the wellhead comprising:an occluding device catcher;an occluding device releasably housed within the occluding device catcher; anda ball valve operable between an open configuration to enable the occluding device to flow into and out of the occluding device catcher, and a closed configuration;a casing lining an inner surface of the completed well and coupled to the wellhead;a tubing string extending within the casing and defining an annulus therebetween, at least one of the tubing string and the annulus being coupled to the wellhead and adapted to establish fluid communication between the upper reservoir and the lower reservoir;a downhole tool comprising:an electric submersible pump (ESP) assembly coupled to the tubing string and adapted to be submerged or in fluid communication with the lower reservoir, the ESP assembly being operable in a turbine configuration to generate electricity in response to the working fluid being released from the upper reservoir, and in a pumping configuration to provide lift and pump the working fluid from the lower reservoir to the surface and / or into the upper reservoir;an occluding device profile provided along the tubing string between the wellhead and the ESP assembly, the occluding device profile being adapted to receive the occluding device thereon to prevent fluid flow therethrough and enable pressure testing the tubing string and / or the annulus.

57. The subsurface pumped hydropower storage system of claim 56, further comprising a packer installed in the annulus and configured to isolate an uphole well section from a downhole well section, and wherein the occluding device profile is positioned proximate the packer.

58. The subsurface pumped hydropower storage system of claim 57, wherein the occluding device profile extends within the tubing string opposite the packer such that fluid flow into the downhole well section is prevented upon engagement of the occluding device on the occluding device profile.

59. The subsurface pumped hydropower storage system of any one of claims 56 to 58, wherein the tubing string comprises ports defined therethrough and adapted to establish fluid communication between the tubing string and the annulus to enable working fluid to flow between the upper and lower reservoirs through the tubing string, through the annulus, or through both.

60. The subsurface pumped hydropower storage system of claim 59, wherein the downhole tool comprises a tubular sleeve slidably coupled to the tubing string, the tubular sleeve being operable between a closed configuration, where the tubular sleeve occludes the ports to prevent fluid communication between the tubing and the annulus and an open configuration.

61. The subsurface pumped hydropower storage system of claim 60, wherein the tubular sleeve is slidably coupled to an inner surface of the tubing string.

62. The subsurface pumped hydropower storage system of claim 60 or 61, wherein the tubular sleeve is mechanically or hydraulically actuatable between the closed and open configurations.

63. The subsurface pumped hydropower storage system of any one of claims 60 to 62, wherein the ports are defined in the tubing string within the uphole well section.

64. The subsurface pumped hydropower storage system of any one of claims 60 to 63, wherein the tubular sleeve is located in the uphole well section in both the open and closed configurations.

65. The subsurface pumped hydropower storage system of any one of claims 60 to 64, wherein the ESP assembly is located in the downhole well section.

66. The subsurface pumped hydropower storage system of any one of claims 60 to 65, wherein the ball valve includes valve passages configured to enable fluid flow therethrough when operating the ball valve in the open configuration, the closed configuration, or both.

67. The subsurface pumped hydropower storage system of any one of claims 56 to 66, further comprising any one of the features of any one of claims 1 to 49.

68. A process for pressure testing the tubing string and / or the annulus of the completed well used in the subsurface pumped hydropower storage system of any one of claims 56 to 67, the process comprising:operating the ball valve in the open configuration to enable the occluding to flow out of the occluding device catcher;engaging the occluding device with the occluding device profile;filling at least one of the tubing string and the annulus with fluid from the surface; andpressure testing the at least one of the tubing string and the annulus.

69. The process of claim 68, wherein, following the pressure testing, the process comprises bleeding off internal pressure by enabling fluid flow from the at least one of the tubing string and the annulus to the upper reservoir and / or the lower reservoir.

70. The process of claim 68 or 69, wherein, following the pressure testing, the ESP assembly is operable in the pumping configuration to pump the occluding device off of the occluding device profile, along the tubing string and into the occluding device catcher.

71. The process of claim 70, wherein, following the occluding device returning into the occluding device catcher, the ball valve is operated from the open configuration to the closed configuration to prevent release of the occluding device.

72. The process of any one of claims 68 to 71, wherein pressure testing the tubing string and / or the annulus is completed without service rig intervention.

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