Systems and methods 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) 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, and, when in the pumping configuration, electricity is consumed 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.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 somedownsides. 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] The present disclosure recognizes that under-pressured subsurface reservoirs - such as depleted natural gas pools, suspended or abandoned oil reservoirs, salt caverns - can be utilized as the lower reservoir, in a subsurface pumped hydropower storage system (SPHS). In particular, they can be connected to an upper reservoir (at or near surface), by a completed well, such that a working fluid can be cycled to / from the upper and lower reservoirs. The SPHS system utilizes an electric submersible pump (ESP) that is configured to cycle between pumping mode (pumping fluid to the upper reservoir, consuming electricity) and turbine mode (injecting fluid into the lower reservoir, producing electricity). This enables single-well implementations that avoid the large capital outlays associated with drilling, completing, and / or retrofitting a second well. Using a single ESP as both a pump and a turbine requires staying within its mechanical tolerances in both modes. The present disclosure maintains viable economics by selecting suitably under-pressured reservoirs and employing optimized tubing diameters, pump / turbine stages, automation controls, fluid column heights, etc. It is noted that a high-pressure lower reservoir reduces the fluid head acting on the turbine, leading to reduced power generation potential. In other words, the present disclosure utilizes custom flowrates and head parameters, specific to the lower reservoir’s unique attributes (e.g., depth, pressure, temperature, permeability, fluid specific gravity, etc.) to successfully incorporate underpressured subsurface reservoirs into SPHS systems.

[0009] According to an aspect, a subsurface pumped hydropower storage (SPHS) system is provided. The SPHS system includes an upper reservoir proximate to surface and adapted to store working fluid, corresponding to a liquid inside a lower reservoir, within a subsurface geological strata, and a completed well extending into the subsurface strata to reach the lower reservoir. The completed well includes 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. The SPHS system also includes a downhole tool comprising an electric submersible pump (ESP) coupled to the tubing string and adapted to be submerged or in fluid communication with the lower reservoir, the ESP being operable in a turbine configuration and a pumping configuration, wherein when in the turbine configuration, the ESP 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 ESP in turbine configuration, the electricity being transmitted to the surface via a power cable connected to the ESP, and when in the pumping configuration, the ESP 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.

[0010] According to a possible implementation, the casing has a diameter between about 5-1 / 2” and 13”, and the tubing string has a diameter between about 2-7 / 8” and 10”.

[0011] According to a possible implementation, the 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.

[0012] According to a possible implementation, the downhole tool comprises a singleESP.

[0013] According to a possible implementation, when in the pumping configuration, the ESP is adapted to provide a pump rate between about 5,000 and 75,000 bbls / d; and when in the turbine configuration, the ESP is adapted to provide a turbine rate between about 10,000 and 112,500 bbls / d.

[0014] According to a possible 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 or a salt cavern.

[0015] According to a possible implementation, the upper reservoir comprises a storage tank at the surface or a pond.

[0016] According to a possible implementation, the completed well, the upper reservoir and the lower reservoir together define a closed-loop system.

[0017] According to a possible implementation, a pressure head is defined between the upper reservoir and the lower reservoir, and, when operating the ESP 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 subsurface formation.

[0018] According to a possible implementation, the ESP is operable in 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.

[0019] According to a possible implementation, the SPHS system further comprises a power unit located at surface and being in electrical connection with the ESP via the power cable to provide electricity to the ESP for the pumping mode and the grid or nearby load to receive electricity from the ESP in the turbine mode.

[0020] According to a possible implementation, the power unit comprises a generator in electrical connection with the ESP to supply power thereto when in the pumping mode.

[0021] According to a possible implementation, the power unit comprises a grid connection in electrical connection with the ESP, and to receive electricity therefrom when in the turbine mode.

[0022] According to another aspect, a process for generating electric power using the subsurface hydroelectric storage system defined above is provided. The process includes 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; and d) releasing fluid from the upper reservoir for introduction into the lower reservoir to generate electricity.

[0023] According to a possible implementation, steps a to d are cyclically repeated.

[0024] According to a possible implementation, the initial step of the process is step a or c.

[0025] According to a possible implementation, the process further includes an initial step of assessing the subsurface formation parameters, including determining which one of the upper reservoir and the lower reservoir contains the initial working fluid volume. The working fluid could be sourced from the lower reservoir, or working fluid could be sourced from an alternative location and transported to the upper reservoir.

[0026] According to another aspect, a subsurface hydroelectric storage system is provided. The SPHS system includes a completed well extending into a subsurface formation to reach a lower reservoir that is under-pressured, the completed well, being configured to house fluid communication of working fluid brine between the upper and lower reservoirs. The completed well includes 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, 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) positioned proximate to a bottom end of the tubing string located in the lower reservoir, the ESP being proximate to or submerged below a reservoir liquid level and being operable in a turbine configuration and a pumping configuration. In the turbine configuration, the ESP is operable to generate electricity in response to the working fluid brine flowing therethrough from the upper reservoir into the lower reservoir, and in the pumping configuration, the ESP is operable to pump the working fluid brine from the lowerreservoir to the surface and into the upper reservoir. The SPHS system includes a power unit located at surface and being in electrical connection with the ESP, the power unit being configured to provide electricity to the ESP for the pumping mode during periods of low electricity demand or during periods when renewable energy is curtailed and receive electricity from the ESP in the turbine mode during periods of high electricity demand.

[0027] According to a possible implementation, the casing has a diameter between about 5-1 / 2” to 13”.

[0028] According to a possible implementation, the tubing string has a diameter between about 2-7 / 8” to 10”.

[0029] According to a possible implementation, the power unit comprises a generator in electrical connection with the ESP to supply power thereto when in the pumping mode.

[0030] According to a possible implementation, the power unit comprises a grid connection in electrical connection with the ESP to supply power thereto when in the pumping mode.

[0031] According to a possible implementation, the power unit comprises a grid connection in electrical connection with the ESP to receive electricity therefrom when in the turbine mode.

[0032] According to a possible implementation, a nearby load is in electrical connection with the ESP to receive electricity therefrom when in the turbine mode.

[0033] According to a possible implementation, the power unit is in electrical connection with the ESP via a power cable extending down the completed well in an annulus defined between the casing and the tubing string.

[0034] According to a possible implementation, the 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 brine within the lower reservoir; and when in the turbine configuration, the impellers are rotated via fluid flow and the electric motor is operated as a generator to generate electricity.

[0035] According to a possible implementation, the SPHS system further includes a motor lead extension operatively coupled to and extending from the electric motor into the annulus to facilitate connection with the power cable.

[0036] According to a possible implementation, the downhole tool comprises a single ESP.

[0037] According to a possible implementation, when in the pumping configuration, the ESP is adapted to provide a pump rate between about 5,000 and 75,000 bbls / d; and when in the turbine configuration, the ESP is adapted to provide a turbine rate between about 10,000 and 112,500 bbls / d.

[0038] According to a possible 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 or a salt cavern.

[0039] According to a possible implementation, the upper reservoir comprises a storage tank at the surface or a pond.

[0040] According to a possible implementation, the completed well, the upper reservoir and the lower reservoir and associated surface equipment, together define a closed-loop system .

[0041] According to a possible implementation, hydraulic head is defined between the upper reservoir and the lower reservoir, and, when operating the ESP in the turbine configuration, a working fluid pressure is generated, and wherein the working fluid pressure measured at the ESP, is greater than the internal pressure of the subsurface formation.

[0042] According to another aspect, a method for generating electric power using a subsurface pumped hydropower storage system is provided. The method includes implementing a dual-mode electric submersible pump (ESP) into a completed well extending into a subsurface formation to reach a lower reservoir; operating the dual-mode ESP in a pumping mode to use electricity received from surface via a power cable to provide lift and pump working fluid from the lower reservoir to the surface and into an upper reservoir for temporary storage; releasing the working fluid from the upper reservoir and into the completed well; operating the dual-mode ESP in a turbine mode to generate electricity in response to the working fluid being released from the upper reservoir andflowing downhole and passing through the dual-mode ESP; and transmitting the electricity to the surface via the power cable.

[0043] According to a possible 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 or a salt cavern.

[0044] According to a possible implementation, the working fluid is temporarily stored in the upper reservoir during periods of low electricity demand.

[0045] According to a possible implementation, the dual-mode ESP is operated in the pumping mode during periods of low electricity demand.

[0046] According to a possible implementation, working fluid is released from the upper reservoir during periods of high electricity demand.

[0047] According to a possible implementation, the dual-mode ESP is operated in the turbine mode during periods of high electricity demand.

[0048] According to a possible implementation, the working fluid is gravity-fed into the completed well upon release from the upper reservoir.

[0049] According to a possible implementation, the working fluid is pumped into the completed well upon release from the upper reservoir.BRIEF DESCRIPTION OF THE DRAWINGS

[0050] Figure 1 is a schematic view of a subsurface pumped hydropower storage system having a single well, according to an implementation.

[0051] Figure 2 is a schematic view of the subsurface pumped hydropower storage system of Figure 1 , showing downhole tools operable to cycle working fluid between reservoirs at different elevations, according to an implementation.

[0052] Figure 3 illustrate steps of a process for generating electricity using the subsurface pumped hydropower storage system.DETAILED DESCRIPTION

[0053] 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.

[0054] 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 produce material, such as hydrocarbons, from a subsurface reservoir (or formation) or in a newly drilled well dedicated for the hydropower storage operation. More specifically, the formation can be an under-pressured subsurface reservoir. In other words, 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, etc.

[0055] 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 or at the surface. 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 at 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.

[0056] The downhole tool of the SPHS system includes an electric submersible pump (ESP) installed within the well for enabling fluid flow between the lower and upper reservoirs. For instance, the ESP is operable as a pump in order to pump the working fluid uphole from the lower reservoir to the upper reservoir (e.g., to surface). The ESP is thus operated in pumping mode to displace the working fluid from the lower reservoir to theupper reservoir. The ESP is further operable as a turbine 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 ESP can be configured to cycle between at least two operational modes, a pumping mode and a turbine mode, as part of the SPHS system. It is noted that the working fluid is pumped uphole via operation of the ESP in the pumping mode, and then is introduced back into the well to flow through the ESP operated in the turbine mode to generate electricity, thereby creating a power storage-and-generating cycle. It should be understood that the SPHS system can be implemented in one or more wells, where each well is equipped with one or more ESP’s depending on the well design. Preferably, the SPHS system includes multiple wells, each being equipped with a corresponding ESP, 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’s and formations are possible.

[0057] The ESP 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 ESP operation can be performed in alignment with pumped-storage hydroelectricity principles as well as other factors. The ESP can also be operated in the pumping mode during periods of curtailment for renewables caused by power grid operating requirements.

[0058] It is also noted that cycling the operation of the ESP between the pumping mode and the turbine mode can benefit from establishing predetermined parameters of the SPHS system, including parameters related to the ESP, the well, the formation 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.

[0059] 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 a subsurface formation 15. 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 and store electricity as potential energy. In this implementation, the SPHS system 10 includes adownhole tool 20 installed within the well 12 and being 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 and into the lower reservoir.

[0060] In the present implementation, the downhole tool 20 includes an electrical submersible pump (ESP) 22. The 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 ESP 22 can be designed as part of a system connected to a geothermal reservoir or a salt cavern for lifting fluid stored in the salt cavern, among other possibilities.

[0061] With reference to Figure 2, it should be understood that, as used herein, the ESP corresponds to a type of well pump operable to pump fluids from the reservoir surrounding the well towards surface. The ESP is designed to operate submerged in the fluid being pumped and includes, and is driven by, a submersible electric motor 25. Typical ESPs include a multiple 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, the 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 ESP and its power source (or “power unit”). The ESP 22 also has a fluid intake 30 at a first end thereof, and a fluid discharge 32 at a second end thereof.

[0062] 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 the wellhead), or the ESP can be connected directly to the local power grid. 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 surface.

[0063] In the implementation shown in Figure 1 , the ESP 22 is installed in the well 12, within or in fluid communication with the lower reservoir 16. The ESP 22 is operable in at least two operational modes. For example, the ESP 22 can operate in a pumping mode, where the ESP operates to pump the working fluid from the lower reservoir to the upper reservoir. In addition, the ESP is operable in a turbine mode, where the working fluid flows into the lower reservoir, flowing through the ESP in turbine mode to generate electricity. It should therefore be noted that the SPHS system 10 includes a dual-mode ESP 22 implemented and operated in the well 12 for bidirectional flow. In this implementation, the ESP 22 is designed to cycle between the pumping and turbine modes to establish the power storage-and-generating cycle. It should thus be noted that the power storage-and- generating cycle can be defined using a single ESP 22 installed in a single well (i.e. , the well 12), although it is appreciated that other configurations are possible.

[0064] 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 should 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.

[0065] The working fluid is stored within the upper reservoir 18 and released therefrom and into the well to generate power. The working fluid can be pumped (e.g., injected under pressure) down the well and into the lower reservoir 16 to operate the ESP (in turbine mode) and generate electricity or released from the upper reservoir to flow down the well (e.g., by gravity and / or via pumping). In some implementations, the working fluid can include fluids originating 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 the ESP in pumping mode, and be reintroduced (e.g., pumped) downhole to operate the turbine (i.e., the ESP in turbine mode). In someimplementations, 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.

[0066] The SPHS system also includes a regenerative variable speed drive (RVSD) 34 configured to enable the ESP 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 ESP, 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.

[0067] 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 22 to define the SPHS system 10. It should be noted that, in oilfield operations, a plurality of wells can be drilled and completed for 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 of a given formation or in a plurality of wells thereof (e.g., one SPHS system per well). The well or wells 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.

[0068] 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 ESP, 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. Thecentrifugal pump 24 of the 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 ESP is designed to have the pumped fluid reach the upper reservoir during operation in the pumping mode. In this implementation, the characteristics of the ESP are adjusted and / or established based on the parameters of the well. However, in other implementations, pre-established ESP 22 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 ESP 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 specific ESP characteristics, both in the pumping and turbine modes.

[0069] 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 upper reservoir 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.

[0070] 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 the ESP can be submerged. The ESP can then be operated in the pumping mode to pump the brine out of the lower reservoir and into the upper reservoir. The ESP can then be operated in the turbine mode as the working fluid is reinjected from the upper reservoir, into the well and the lower reservoir. The ESP 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. For instance, and with reference to Figure 3, the ESP 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 can be repeated at any time, and for any duration, subject to upper and lower reservoir working fluid volume capacity.

[0071] It is appreciated that the demand for power can vary, which can provide indication on a suggested operational mode of the ESP. For instance, during periods of low demand of power, the ESP 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, the ESP can be operated in the turbine mode and the working fluid can be released from the upper reservoir and pumped / 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.

[0072] 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 subsurface reservoir, 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.

[0073] 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.

[0074] In some implementations, continuous generation can be achieved through the potential energy generated from an active oilfield. For instance, an oil operator pumpssaline water and oil to surface, separating out the oil and reinjecting the water. Dedicated ESP’s 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.

[0075] Operation of the ESP 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 ESP 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 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 ESP (e.g., to operate the ESP as a pump) can be the same power cable which transfers generated 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.

[0076] It is understood that operating the ESP 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 includes 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 ESP (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 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 canbe 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.

[0077] 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 22 between the pumping and turbine modes can lead to mechanical failure of the ESP 22 under certain operational conditions. Particularly, and although adapted to operate as a turbine, the ESP 22 is designed to operate as a pump. Therefore, to maintain technical viability of the ESP, predetermined parameters and / or enhancements can be established and / or incorporated in order to protect the components of the ESP in both operational modes.

[0078] 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 embodiments, 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 run-away 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 dynamics (CFD) modelling can be used to appropriately size pumps and motors to the range of fluid rates and hydraulic head available, among other possibilities.

[0079] 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 22 (e.g., specifications, size, number of stages, etc.) and / or the operational parameters of the SPHS system such as flowrates, head pressure, etc.

[0080] Completed oil & gas well typically includes a casing 40 (also referred to as a production casing or outer pipe) and a tubing string 42 (or inner pipe). The casing typicallyassists 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 ESP 22 is coupled to the tubing string 42 to enable and cooperate with said fluid flow. The casing and tubing string 42 can run parallel and / or concentrically relative to each other to define an annulus, or annular region, therebetween. Generally, the motor lead extension 36 extends from the ESP into the annulus to facilitate connection with the power cable 26. The motor lead extension 36 and power cable therefore run along the outside of the ESP and tubing string 42, within the annulus. In some implementations, the tubing string 42 has a diameter which is between 2” and 3” smaller than a diameter of the casing, thereby defining a correspondingly-sized annulus 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 for housing the motor lead extension 36 and the cable 26.

[0081] In some implementations, the size (e.g., diameter) of the ESP 22 can be adapted to the size of the tubing string and casing. It should be noted that a SPHS system 10 having a larger tubing string and casing can be coupled to a larger ESP 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.

[0082] 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. From the above, it is also noted that wells suited for high flowrates and greater hydraulic head can create run-away conditions of the ESP, if 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 generate more power, those same tubulars can pose a significant operational risk to the ESP, forinstance, if the ESP is 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.

[0083] 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.

[0084] In some implementations, the well can be provided with a packer 38 configured to isolate sections of the well from one another. The packer 38 is installed within the annulus, defined as the space between the casing 40 and the tubing string 42, thus defining well sections on either sides thereof. The well section below the packer, or downhole section, can be subjected (e.g., exposed) to the working fluid, which can include saline brine, which can be at least partially corrosive. The well section above the packer 38, or uphole section, can therefore be isolated from being subjected to the saline brine. It is noted that the packer is provided with a cable pass-through to allow the power cable to pass through the packer for connection with the motor of the ESP. The cable pass- through can correspond to a hole defined through the packer using a packer penetrator tool for enabling extension of the power cable therethrough.

[0085] 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 having desired characteristics and / or 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 thechosen ESP specifications are known prior to installation due to knowledge of the wellbore and well parameters.

[0086] 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 is located. 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 example, the low formation permeability. It is noted that the size of the tubular can be proportional to the permeability of the formation, where higher permeability allows for larger tubulars. It is understood that reducing the tubular size correspondingly reduces the amount of power generated, as previously discussed. However, in scenarios with low formation 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 formation.

[0087] The formation 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 formation, which has since been depleted. The depleted formation 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.

[0088] 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, the lower reservoir can be located at a maximum depth to maintain technical viability of the ESP, for example, to avoid load rejection and / or run-away conditions of the ESP 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, for example, a minimum number of ESP stages and / or impellers to convert the availablehydraulic 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.

[0089] 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. Alternatively, a lower reservoir with lower permeability but which still has high hydraulic head can still require a high ESP stage / impeller count, 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 will impact the design of SPHS systems. Ultimately, economic viability resulting from changing SPHS parameters 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.

[0090] 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; and> size the ESP accordingly (e.g., the ESP diameter, number of stages and motor / generator size) based on the planned flow rates and available hydraulic head.

[0091] 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.Table 1 - example implementations of SPHS system parameters

[0092] 1 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.

[0093] 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, andwith 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 an ESP series E 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.

[0094] It will be appreciated from the foregoing disclosure that there is provided a subsurface pumped hydropower storage system utilizing an electric submersible pump 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, or salt caverns) 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.).

[0095] The described ESP is 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. This enables singlewell 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 ESPs, which allows for one ESP to be dedicated for pumping, and another ESP to be dedicated for power generation (turbine mode).

[0096] The present disclosure also recognizes the need to maintain an operational balance to achieve technical and economic viability of the SPHS system. Using a single ESP as both a pump and a turbine requires staying within its mechanical tolerances in both operational modes. In turbine mode, this can correspond to throttling the flow rate toprevent 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.

[0097] 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 submerged in the lower reservoir would therefore see very little to no residual / movable oil or gas at those depths. Where lower reservoir thickness is thin, thereby introducing additional risk of oil or gas inflow into the working fluid, the ESP intake 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, where the movable substances include, but not limited to saline working fluid, during operation of the ESP in pumping mode. Positioning the ESP intake lower also allows the annulus to act like a separator, where lighter oil and gas can migrate to the top of the lower reservoir via the vertical relief within the annulus, while heavier saline working fluid enters the ESP intake lower in the annulus.

[0098] 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 singleimplementation. 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.

[0099] 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.

[0100] 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.

[0101] In the above description, the same numerical references referto 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 which are 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.

[0102] 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 suitablegeometrical 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 hydroelectric 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 formation; a completed well extending into the subsurface formation 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) coupled to the tubing string and adapted to be submerged or in fluid communication with the lower reservoir, the ESP being operable in a turbine configuration and a pumping configuration, wherein: when in the turbine configuration, the ESP 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 ESP, and when in the pumping configuration, the ESP 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 hydroelectric 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 hydroelectric storage system of claim 1 or 2, wherein the 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.

4. The subsurface hydroelectric storage system of claim 3, wherein the downhole tool comprises a single ESP.

5. The subsurface hydroelectric storage system of claim 3, wherein: when in the pumping configuration, the ESP is adapted to provide a pump rate between about 5,000 and 75,000 bbls / d; and when in the turbine configuration, the ESP is adapted to provide a turbine rate between about 10,000 and 112,500 bbls / d.

6. The subsurface hydroelectric storage system of any one of claims 1 to 5, 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 or a salt cavern.

7. The subsurface hydroelectric storage system of any one of claims 1 to 6, wherein the upper reservoir comprises a storage tank at the surface or a pond.

8. The subsurface hydroelectric storage system of any one of claims 1 to 7, wherein the completed well, the upper reservoir and the lower reservoir together define a closed- loop system.

9. The subsurface hydroelectric storage system of any one of claims 1 to 8, wherein a pressure head is defined between the upper reservoir and the lower reservoir, and, when operating the ESP 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 subsurface formation.

10. The subsurface hydroelectric storage system of any one of claims 1 to 9, wherein the ESP 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.

11. The subsurface hydroelectric storage system of any one of claims 1 to 10, further comprising a power unit located at surface and being in electrical connection with the ESP via the power cable to provide electricity to the ESP for the pumping mode and receive electricity from the ESP in the turbine mode.

12. The subsurface hydroelectric storage system of claim 11 , wherein the power unit comprises a generator in electrical connection with the ESP to supply power thereto when in the pumping mode.

13. The subsurface hydroelectric storage system of claim 11 or 12, wherein the power unit comprises a grid connection in electrical connection with the ESP to supply power thereto when in the pumping mode and / or to receive electricity therefrom when in the turbine mode.

14. The subsurface hydroelectric storage system of any one of claims 1 to 13, wherein a nearby load is in electrical connection with the ESP to receive electricity therefrom when in the turbine mode.

15. A process for generating electric power using the subsurface pumped hydropower storage system of any one of claims 1 to 14, 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; and d. pumping or gravity feeding fluid from the upper reservoir to the lower reservoir to generate electricity.

16. The process of claim 15, wherein steps a. to d. are cyclically repeated.

17. The process of claim 15 or 16, wherein the initial step of the process is step a or c.

18. The process of any one of claim 15 to 17, further comprising assessing the formation parameters, including determining which one of the upper reservoir and the lower reservoir contains the working fluid.

19. A subsurface pumped hydropower storage system, comprising : a completed well extending into a subsurface formation 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, 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) positioned proximate to a bottom end of the tubing string located in the lower reservoir, the ESP being proximate to or submerged below a reservoir liquid level and being operable in a turbine configuration and a pumping configuration, wherein: in the turbine configuration, the ESP is operable to generate electricity in response to the working fluid brine flowing therethrough from the upper reservoir into the lower reservoir, and in the pumping configuration, the ESP is operable to pump the working fluid brine from the lower reservoir to the surface and into the upper reservoir. a power unit located at surface and being in electrical connection with the ESP, the power unit being configured to provide electricity to the ESP for the pumping mode during periods of low electricity demand and receive electricity from the ESP in the turbine mode during periods of high electricity demand.

20. The subsurface pumped hydropower storage system of claim 19, wherein the casing has a diameter between about 5-1 / 2” to 13.

21. The subsurface pumped hydropower storage system of claim 19 or 20, wherein the tubing string has a diameter between about 2-7 / 8” to 10”.

22. The subsurface pumped hydropower storage system of any one of claims 19 to 21 , wherein the power unit comprises a generator in electrical connection with the ESP to supply power thereto when in the pumping mode.

23. The subsurface pumped hydropower storage system of any one of claims 19 to 22, wherein the power unit comprises a grid connection in electrical connection with the ESP to supply power thereto when in the pumping mode and / or to receive electricity therefrom when in the turbine mode.

24. The subsurface pumped hydropower storage system of any one of claims 19 to 23, wherein a nearby load is in electrical connection with the ESP to receive electricity therefrom when in the turbine mode.

25. The subsurface pumped hydropower storage system of any one of claims 19 to 24, wherein the power unit is in electrical connection with the ESP via a power cable extending down the completed well in an annulus defined between the casing and the tubing string.

26. The subsurface pumped hydropower storage system of claim 25, wherein the 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 brine 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.

27. The subsurface pumped hydropower storage system of claim 25 or 26, further comprising a motor lead extension operatively coupled to and extending from the electric motor into the annulus to facilitate connection with the power cable.

28. The subsurface pumped hydropower storage system of any one of claims 19 to 27, wherein the downhole tool comprises a single ESP.

29. The subsurface pumped hydropower storage system of any one of claims 19 to 28, wherein:when in the pumping configuration, the ESP is adapted to provide a pump rate between about 5,000 and 75,000 bbls / d; and when in the turbine configuration, the ESP is adapted to provide a turbine rate between about 10,000 and 112,500 bbls / d.

30. The subsurface pumped hydropower storage system of any one of claims 19 to 29, 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 or a salt cavern.

31. The subsurface pumped hydropower storage system of any one of claims 19 to 30, wherein the upper reservoir comprises a storage tank at the surface or a pond.

32. The subsurface pumped hydropower storage system of any one of claims 19 to 31 , wherein the completed well, the upper reservoir and the lower reservoir together define a closed-loop system.

33. The subsurface pumped hydropower storage system of any one of claims 19 to 32, wherein a hydraulic head is defined between the upper reservoir and the lower reservoir, and, when operating the ESP in the turbine configuration, a working fluid pressure is generated based at least one the hydraulic head, and wherein the working fluid pressure is greater than an internal pressure of the subsurface formation.

34. A method for generating electric power using a subsurface pumped hydropower storage system, the method comprising : implementing a downhole tool comprising a dual-mode electric submersible pump (ESP) into a completed well extending into a subsurface formation to reach a lower reservoir; operating the dual-mode ESP in a pumping mode to use electricity received from surface via a power cable to provide lift and pump working fluid from the lower reservoir to the surface and into an upper reservoir for temporary storage; releasing the working fluid from the upper reservoir and into the completed well; operating the dual-mode ESP in a turbine mode to generate electricity in response to the working fluid being released from the upper reservoir and flowing downhole and passing through the dual-mode ESP; andtransmitting the electricity to the surface via the power cable.

35. The method of claim 34, wherein the pressure depleted lower reservoir corresponds to any one of a suspended oil reservoir, an abandoned oil reservoir, a substantially depleted oil reservoir, a suspended natural gas reservoir, an abandoned natural gas reservoir, a substantially depleted natural gas reservoir, a water or brine reservoir, or a salt cavern.

36. The method of claim 34 or 35, wherein the working fluid is temporarily stored in the upper reservoir during periods of low electricity demand.

37. The method of any one of claims 34 to 36, wherein the dual-mode ESP is operated in the pumping mode during periods of low electricity demand.

38. The method of any one of claims 34 to 37, wherein working fluid is released from the upper reservoir during periods of high electricity demand.

39. The method of any one of claims 34 to 38, wherein the dual-mode ESP is operated in the turbine mode during periods of high electricity demand.

40. The method of any one of claims 34 to 39, wherein the working fluid is gravity-fed into the completed well upon release from the upper reservoir.

41. The method of any one of claims 34 to 40, wherein the working fluid is pumped into the completed well upon release from the upper reservoir.