EP4619674A1

EP4619674A1 - Brine-compensated compressed gas energy storage system and method of using same

Info

Publication number: EP4619674A1
Application number: EP23904978.6A
Authority: EP
Inventors: Andrew MCGILLIS; Lucas THEXTON
Original assignee: Hydrostor Inc
Current assignee: Hydrostor Inc
Priority date: 2022-12-23
Filing date: 2023-12-22
Publication date: 2025-09-24
Also published as: AU2023413323A1; WO2024130447A1

Abstract

A method is provided for conveying brine solution in a compressed gas energy storage system. The method includes: measuring a present temperature of a layer of brine solution stored in an accumulator of the compressed gas energy storage system, the accumulator may include an accumulator interior at least partially encapsulated by a salt layer; heating, using a heater subsystem, a brine solution stored in a brine solution source/sink to a temperature equal to or greater than the present temperature of the layer of brine solution in the accumulator; and after determining the brine solution stored in the brine solution source/sink is at the temperature equal to or greater than the present temperature of the layer of brine solution in the accumulator, conveying the brine solution stored in the brine solution source/sink to the accumulator.

Description

BRINE-COMPENSATED COMPRESSED GAS ENERGY STORAGE SYSTEM AND METHOD OF USING SAME

CROSS-REFERENCE TO RELATED APPLICATION:

[0001] This application claims priority from United States Provisional Patent Application No. 63/477,055 filed on December 23, 2022, and titled “BRINE- COMPENSATED COMPRESSED GAS ENERGY STORAGE SYSTEM”, the entire contents of which are herein incorporated by reference.

FIELD

[0002] The present disclosure relates generally to compressed gas energy storage, and more particularly to a compressed gas energy storage system such as, for example, one including a hydrostatically compensated, compressed air energy storage accumulator located underground, and the use thereof.

INTRODUCTION

[0003] Electricity storage is highly sought after, in view of the cost disparities incurred when consuming electrical energy from a power grid during peak usage periods, as compared to low usage periods. The addition of renewable energy sources, being inherently of a discontinuous or intermittent supply nature, increases the demand for affordable electrical energy storage worldwide.

[0004] Thus, there exists a need for effectively storing the electrical energy produced at a power grid or a renewable source during a non-peak period and providing it to the grid upon demand. Additionally, to the extent that the infrastructural preparation costs and the environmental impact from implementing such infrastructure are minimized, the utility and desirability of a given solution is enhanced.

[0005] Furthermore, as grids transform and operators look to storage in addition to renewables to provide power and remove traditional forms of generation that also provide grid stability, such as voltage support, a storage method that offers inertia based synchronous storage is highly desirable.

[0006] US Patent no. 3,996,741 discloses a system and apparatus for the storage of energy generated by natural elements. Energy from natural elements such as from the sun, wind, tide, waves, and the like, is converted into potential energy in the form of air under pressure, which is stored in a large, subterranean cell. Machines of known types such as windmills are driven by natural elements to operate air compressors. Air compressors pump the air under pressure to the storage cell. Air entering the storage cell displaces water from the cell which returns to a water reservoir as an ocean or a lake. Water locks the air in the storage cell. The stored compressed air is available upon demand to perform a work function as driving an air turbine to operate an electric generator.

[0007] International patent publication no. W02013/131202 discloses a compressed air energy storage system comprising a pressure accumulator for gas to be stored under pressure, and a heat accumulator for storing the compression heat that has accumulated during charging of the pressure accumulator, wherein the heat accumulator is arranged ready for use in an overpressure zone. Said arrangement enables a structurally simple heat accumulator to be provided, since said heat accumulator is not loaded by the pressure of the gas passing therethrough.

[0008] US patent publication no. US2013/0061591 discloses, during an adiabatic compressed air energy storage (ACAES) system's operation, energy imbalances may arise between thermal energy storage (TES) in the system and the thermal energy required to raise the temperature of a given volume of compressed air to a desired turbine entry temperature after the air is discharged from compressed air storage of the ACAES system. To redress this energy imbalance, it is proposed to selectively supply additional thermal energy to the given volume of compressed air after it received thermal energy from the TES and before it expands through the turbine. The additional thermal energy is supplied from an external source, i.e., fuel burnt in a combustor. The amount of thermal energy added to the given volume of compressed air after it received thermal energy from the TES is much smaller than the amount of useful work obtained from the given volume of compressed air by the turbine.

[0009] International patent publication no. WO 2018/141057 discloses a compressed gas energy storage system that may include an accumulator for containing a layer of compressed gas atop a layer of liquid. A gas conduit may have an upper end in communication with a gas compressor and expander subsystem and a lower end in communication with accumulator interior for conveying compressed gas into the compressed gas layer of the accumulator when in use. A shaft may have an interior for containing a quantity of a liquid and may be fluidly connectable to a liquid source/sink via a liquid supply conduit. A partition may cover may separate the accumulator interior from the shaft interior. An internal accumulator force may act on the inner surface of the partition and the liquid within the shaft may exert an external counter force on the outer surface of the partition, whereby a partition force acting on the partition is less than the accumulator force.

[0010] International patent publication no. WO2018/16172 discloses a thermal storage subsystem that may include at least a first storage reservoir disposed at least partially underground configured to contain a thermal storage liquid at a storage pressure that is greater than atmospheric pressure. A liquid passage may have an inlet connectable to a thermal storage liquid source and configured to convey the thermal storage liquid to the liquid reservoir. A first heat exchanger may be provided in the liquid inlet passage and may be in fluid communication between the first compression stage and the accumulator, whereby thermal energy can be transferred from a compressed gas stream exiting a gas compressor/expander subsystem to the thermal storage liquid.

[0011] International patent publication no. WO 2020/160670 discloses a method of operating a hydrostatically compensated compressed air energy storage system in a first charging mode including conveying the compressed air at a nearly constant first operating pressure which displaces a corresponding volume of compensation liquid from the layer of compensation liquid out of the accumulator, and a second charging mode including conveying additional compressed air into the accumulator while compensation liquid is not displaced from within the accumulator so that the pressure of the layer of compressed air increases to a second operating pressure that is greater than the first operating pressure.

[0012] International patent publication no. WO 2020/172748 discloses a hydrostatically compensated compressed air energy storage system that may include an accumulator disposed underground and a compressor/expander subsystem in fluid communication. A compensation shaft may extend between an upper and a lower end and define a shaft depth. An upper end wall can cover the upper end of the shaft. A compensation liquid reservoir can be offset above the upper end wall by a reservoir elevation that is at least about 15% of the shaft depth. A compensation liquid flow path may extend between the compensation liquid reservoir and the accumulator and can include the compensation shaft and a liquid supply conduit extending between the compensation liquid reservoir and the upper end of the compensation shaft whereby a total hydrostatic pressure at the lower end of the shaft is greater than a hydrostatic pressure at a depth that is equal to the shaft depth. [0013] International patent publication no. WO2022/213179 discloses a hydrostatically compensated, compressed gas energy storage system can include an accumulator containing a layer of compressed gas at between about 20 bar and about 90 bar above a layer of compensation liquid that has a density of at least 1500 kg/m3. A compressor and expander subsystem may be configured to selectably convey compressed gas into the accumulator and to extract gas from the accumulator. The system may be operable in at least a charging mode in which the compressor and expander subsystem conveys gas into the layer of compressed gas thereby displacing a corresponding volume of compensation liquid from the layer of compensation liquid within the accumulator out of the accumulator via the compensation liquid flow path thereby maintaining the layer of compressed gas at substantially the accumulator pressure during the charging mode.

SUMMARY

[0014] This summary is intended to introduce the reader to the more detailed description that follows and not to limit or define any claimed or as yet unclaimed invention. One or more inventions may reside in any combination or sub-combination of the elements or process steps disclosed in any part of this document including its claims and figures.

[0015] Energy produced by some types of energy sources, such as windmills, solar panels and the like may tend to be produced during certain periods (for example when it is windy, or sunny respectively), and not produced during other periods (if it is not windy, or at night, etc.). However, the demand for energy may not always match the production periods, and it may be useful to store the energy for use at a later time. Similarly, it may be helpful to store energy generated using conventional power generators (coal, gas and/or nuclear power plants for example) to help facilitate storage of energy generated during non-peak periods (e.g. periods when electricity supply could be greater than demand and/or when the cost of electricity is relatively high) and allow that energy to be utilized during peak periods (e.g. when the demand for electricity may be equal to or greater than the supply, and/or when the cost of electricity is relatively high).

[0016] As described herein, compressing and storing a gas (such as air), using a suitable compressed gas energy storage system, is one way of storing energy for later use. For example, during non-peak times, energy (i.e., electricity) can be used to drive compressors and compress a volume of gas to a desired, relatively high pressure for storage. The gas can then be stored at the relatively high pressure inside any suitable container or vessel, such as a suitable accumulator. To extract the stored energy, the pressurized gas can be released from the accumulator and used to drive any suitable expander apparatus or the like, and ultimately to be used to drive a generator or the like to produce electricity. The amount of energy that can be stored in a given compressed gas energy storage system may be related to the pressure at which the gas is compressed/ stored, with higher pressure storage generally facilitating a higher energy storage for a given accumulator/system volume.

[0017] In systems where a compensation liquid is used to help regulate the gas pressure within the accumulator, such as in a hydrostatically compensated compressed gas energy storage system, the operating parameters of the system can be influenced by pressure that can be exerted by the compensation liquid, and more specifically by the hydrostatic pressure of the compensation liquid at the depth/ location of the accumulator. Without the use of pumps or other pressurization mechanisms to pressurize compensation liquid, the hydrostatic pressure of the compensation liquid is generally a function of the depth of the liquid (e.g., orthe height of the liquid column that is above the accumulator or other measurement location). For systems in which the accumulator is partially, or entirely located below ground, the depth of the accumulator below the surface of the ground (and relative to the upper end of any associated compensation liquid shaft) can affect the hydrostatic pressure at the accumulator - and therefore affect operating gas pressure/ accumulator pressure of the system. For example, the hydrostatic pressure at a depth of 200m within a compensation liquid shaft will be less than the hydrostatic pressure at a depth of 600m within the same shaft.

[0018] In other circumstances it may be possible to provide an accumulator at a given depth, but there may be some physical and/or economic limitations on the size of accumulator that can be provided, which can limit the amount of air/gas that can be stored in the accumulator (at a given operating pressure) which can in turn limit the amount of energy that can be stored using the system. Increasing the operating pressure of such systems, even if operating at a given, desirable accumulator depth, by increasing the hydrostatic pressure that is applied via the compensation liquid may help increase the energy density of the accumulator (e.g., more gas can be stored within a given accumulator volume when it is stored at a relatively higher pressure). [0019] In accordance with one broad aspect of the teachings described herein, a hydrostatically compensated, compressed gas energy storage system may include an accumulator disposed underground and having an interior for containing a layer of compressed gas above a layer of compensation liquid. The layer of compressed gas may be at an accumulator pressure that is between about 20 bar and about 90 bar and optionally may be between about 60 and 80 bar and may be between about 30 bar and 55 bar and may be about 40 or about 60 bar in some examples. In other arrangements, the accumulator pressure may be at least 20, 25, 30 ,35, 40, 45, 50, 55, 60, 65, 70, 75, 80 and 85 bar. A compressor and expander subsystem may be in fluid communication with the accumulator interior via a gas flow path and may be configured to selectably convey compressed gas into the accumulator and to extract gas from the accumulator. A compensation liquid reservoir may be spaced apart from the accumulator and a compensation liquid flow path may extend between the compensation liquid reservoir and the layer of compensation liquid. The system may be operable in at least a charging mode in which the compressor and expander subsystem conveys gas into the layer of compressed gas thereby displacing a corresponding volume of compensation liquid from the layer of compensation liquid within the accumulator out of the accumulator via the compensation liquid flow path thereby maintaining the layer of compressed gas at substantially the accumulator pressure during the charging mode.

[0020] The system may be operable in a discharging mode in which the compressor and expander subsystem extracts gas from the layer of compressed gas as a corresponding volume of compensation liquid flows from compensation liquid flow path into the layer of compensation liquid within the accumulator thereby maintaining the layer of compressed gas at substantially the accumulator pressure during the discharging mode.

[0021] The accumulators used in systems of this nature utilize suitable caves, caverns or other such formations or may be constructed using materials such as concrete, metal and the like. One example of a structure that can be utilized to provide an accumulator is an underground salt cavern. Salt caverns of this nature can be formed using any suitable techniques including, for example, solution mining. The salt caverns may be left over from a previous mining operation or, in some instances, may be purposely constructed using solution mining for use in compressed gas storages systems (including those described herein). [0022] Using salt caverns to provide the accumulators in a hydrostatically compensated compressed air energy storage system may have some advantages as compared to using other types of naturally occurring ground or rock formations, such as being relatively liquid and gas impermeable (to help reduce leakage of the stored gas or compensation liquid). However, salts tend to be water soluble and can tend to be dissolved/ eroded when in contact with water or other such solvents, and the effect of the water may tend to be increased if the water is flowing. For example, when water is used as a compensation liquid for a hydrostatically compensated compressed air energy storage system that uses a salt cavern accumulator the use of the flowing compensation liquid may dissolve salt from the cavern walls (and floor and ceiling, etc. which can all be understood to be examples of cavern walls as described herein) and may weaken or destroy the cavern over time. This type of erosion/ dissolving may also have the effect of changing the shape and/or volume of the accumulator, which could impact the operation of the CAES system overtime. As such, reducing and/or avoiding erosion of the salt cavern by reducing the dissolving of salt into the compensation liquid may be desirable in some instances.

[0023] For example, to help reduce this unwanted cavern damage, the systems can be configured to use a compensation liquid in which salt has a relatively lower solubility as compared to typical freshwater. Such liquids could include oils and other non-polar liquids but utilizing fluids of this nature can lead to other challenges with respect to availability of the liquid, handling and storage of the liquid, the relative heat storage capacity of the liquid and the environmental affects of the use or leakage of such liquid. Therefore, it is desirable to utilize water as the compensation liquid in the systems described herein, but to modify the parameters of the water to help reduce the solubility of the cavern salt in the water. One way to reduce the solubility of the cavern salt in the compensation water is to pre-dissolve a salt (preferably the same type of salt that forms the accumulator cavern) in the compensation liquid so that the compensation liquid is a brine that is at least partially saturated with salt when it enters the accumulator. The solubility of the cavern salt into an already partially saturated brine solution may be lower, and promote less dissolving of the cavern walls, as compared to the solubility of the cavern salt into a fresh, generally salt-free compensation liquid. [0024] The solubility of a salt into the compensation liquid may also be affected by other properties of the liquid, such as the temperature and pressure. In some optional configurations, the compensation liquid can be heated to a temperature that is at or above the internal operating temperature of accumulator (at depth) and the compensation liquid may be brine that is at least partially, preferably substantially, and optionally fully saturated with salt at the operating temperature - prior to the entering the accumulator. Providing a compensation liquid that is essentially fully saturated with salt, at the relevant operating conditions of the accumulator, prior to introducing the compensation liquid into the accumulator may help reduce the amount of dissolving of salt from the cavern walls into the compensation liquid as the compensation liquid cycles into and out of the accumulator while the system discharges and charges.

[0025] In accordance with one broad aspect of the teachings described herein that may be used alone or in combination with any other aspects described herein a compressed gas energy storage system can include an accumulator having a primary opening, an upper wall, a lower wall, an accumulator sidewall and an accumulator interior at least partially bounded the upper wall, the lower wall and the accumulator sidewall, the accumulator for containing a layer of compressed gas atop a layer of brine solution when in use. At least one of the upper walls, the lower wall and accumulator sidewall include a salt layer that at least partially encapsulates the accumulator interior. A gas compressor and expander subsystem may be spaced apart from the accumulator and a gas conduit having an upper end in communication with the gas compressor and expander subsystem and a lower end in communication with the accumulator interior for conveying compressed gas into the compressed gas layer of the accumulator when in use. A shaft may include a lower end adjacent the primary opening, an upper end spaced apart from the lower end, and a shaft sidewall extending upwardly from the lower end to the upper end and at least partially bounding a shaft interior for containing a quantity of a brine solution. The shaft may be fluidly connectable to a brine solution reservoir via a liquid supply conduit. A heater subsystem may be configured to heat the brine solution in the brine solution reservoir, and/or before it enters the accumulator and/ as it is exiting the accumulator and/or before it enters the brine solution reservoir) to a temperature equal to or greater than a present temperature of the layer of brine solution in the accumulator.

[0026] A partition may cover the primary opening and may separate the accumulator interior from the shaft interior. The partition may have an outer surface in communication with the shaft interior and an opposing inner surface in communication with the accumulator interior. When in use, at least one of the layer of compressed gas and the layer of liquid bears against and exerts an internal accumulator force on the inner surface of the partition and the quantity of liquid within the shaft bears against and exerts an external counter force on the outer surface of the partition, whereby a net force acting on the partition while the compressed gas energy storage system is in use is a difference between the accumulator force and the counter force and is less than the accumulator force.

[0027] The heater subsystem may include a thermal storage subsystem provided in fluid communication between the gas compressor and expander subsystem and the accumulator, whereby thermal energy is extracted from the compressed gas exiting the gas compressor and expander subsystem at an exit temperature and stored in the thermal storage subsystem; and wherein the thermal energy that has been stored in the thermal storage subsystem is transferred to the brine solution in the in the brine solution source/sink via a gas/brine heat exchanger.

[0028] The gas compressor and expander subsystem may include a plurality of compression stages, each one of the plurality of compression stages may include a heat exchanger, and at least one of the heat exchangers from amongst the plurality of compression stages is fluidly connected to the gas/brine heat exchanger.

[0029] Each of the heat exchangers in the plurality of compression stages may be fluidly connected in series, and wherein, in a compression operation, ambient air is received into a first heat exchanger in a first compression stage and is conveyed through the plurality of compression stages in series including into a last heat exchanger in a last compression stage; and heated air exiting the last heat exchanger conveys the thermal energy to the gas/brine heat exchanger.

[0030] The plurality of compression stages may include a first compression stage, a second compression stage, and a third compression stage such that when in a compression process, in a first compression stage, incoming air A from ambient is conveyed into a first compressor driven by a motor of the first compression stage, and the air A exiting the first compressor is then conveyed through a first heat exchanger of the thermal storage subsystem to transfer heat into a thermal storage liquid that is drawn from a first thermal storage reservoir; in a second compression stage, air exiting the first heat exchanger, which is conditioned to be air A’, is then conveyed into a second compressor driven by the motor of the second compression stage, and the air A’ exiting the second compressor is then conveyed through a second heat exchanger of the thermal storage subsystem to transfer heat into the thermal storage liquid; in a third compression stage, air exiting the second heat exchanger, which is conditioned to be air A”, is then conveyed into a third compressor driven by the motor of the third compression stage, and the air A” exiting the second compressor is then conveyed through a third heat exchanger of the thermal storage subsystem to transfer heat into the thermal storage liquid; and air exiting the third heat exchanger, which is conditioned to be air A’”, is then conveyed to the gas/brine heat exchanger to transfer heat from the air A’” to the brine solution in the brine solution source/sink.

[0031 ] A temperature of the air A’” may be higher than the present temperature of the layer of brine solution in the accumulator.

[0032] A temperature of the air A’” may be greater than 50 deg. C and the present operating temperature of the layer of brine solution in the accumulator may be 50 deg. C or less.

[0033] A temperature of the air A’” may be between about 50 deg. C and 90 deg. C, and the present operating temperature of the layer of brine solution in the accumulator may be between about 15 deg. C and 50 deg. C.

[0034] The gas/brine heat exchanger may include an externally powered heater to heat the brine solution in the brine solution source/sink

[0035] The system may include a heater positioned at the brine solution source/sink. The heater may be configured to heat the brine solution in the brine solution source/sink

[0036] Waste heat may be generated by the gas compressor and expander subsystem through different operating modes, the operating modes may include standby mode, charging mode, and discharging mode; and wherein the waste heat may be transferred to the heater subsystem to heat the brine solution in the brine solution source/sink.

[0037] The system may include a trim cooler of air, and wherein waste heat may be generated from the trim cooler of air in a charging mode of the gas compressor and expander subsystem, and the waste heat is transferred to the heater subsystem to heat the brine solution in the brine solution source/sink.

[0038] Additional waste heat may also be generated from thermal fluid cooling in the charging mode and in a discharging mode of the gas compressor and expander subsystem; and the additional waste heat may be transferred to the heater subsystem to heat the brine solution in the brine solution source/sink.

[0039] The compensation brine that is exiting the accumulator via the shaft may be heated using the heater subsystem to a brine exit temperature that is higher than the present temperature of the layer of brine solution in the accumulator, and the brine solution exiting the accumulator, and after being heated, may be stored in the brine solution source/sink.

[0040] The present operating temperature of the layer of brine solution in the accumulator may be about 50 deg. C or less, and the brine exit temperature may be about 70 deg. C.

[0041] The heater subsystem may include a thermal storage subsystem provided in fluid communication between the gas compressor and expander subsystem and the accumulator, whereby thermal energy is extracted from the compressed gas exiting the gas compressor and expander subsystem at an exit temperature and stored in the thermal storage subsystem. The thermal energy that has been stored in the thermal storage subsystem may be transferred to the brine solution exiting the accumulator via a gas/brine heat exchanger.

[0042] The gas compressor and expander subsystem may include a plurality of compression stages, each one of the pluralities of compression stages may include a heat exchanger, and at least one of the heat exchangers from amongst the plurality of compression stages is fluidly connected to the gas/brine heat exchanger.

[0043] Each of the heat exchangers in the plurality of compression stages may be fluidly connected in series, and wherein, in a compression operation, ambient air is received into a first heat exchanger in a first compression stage and is conveyed through the plurality of compression stages in series including into a last heat exchanger in a last compression stage; and heated air exiting the last heat exchanger conveys the thermal energy to the gas/brine heat exchanger.

[0044] The gas/brine heat exchanger may include an externally powered heater to heat the brine solution exiting the accumulator, and optionally before it enters the reservoir or while it is in the reservoir.

[0045] The brine solution source/sink may include a thermal insulating material that at least partially encapsulates the brine solution stored in the brine solution source/sink. [0046] In accordance with another broad aspect of the teachings described herein which may be used alone or in combination with any other aspect a method for conveying brine solution in a compressed gas energy storage system, can include the steps of:

Maintain a layer of compensation brine stored below a layer of compressed gas within an accumulator of the compressed gas energy storage system at an operating temperature, the accumulator being at least partially bounded by accumulator walls that may include a salt layer that is exposed to the layer of compensation brine; heating, using a heater subsystem, a compensation brine stored in compensation reservoir to a storage temperature that is within 25% of the operating temperature and so that the compensation brine is an aqueous solution containing dissolved salt at a preconditioned salt concentration that is within about 25% of a salt saturation limit of the aqueous solution at the operating temperature; and after determining the brine solution stored in the brine solution source/sink is at the temperature equal to or greater than the present temperature of the layer of brine solution in the accumulator, conveying the brine solution stored in the brine solution source/sink to the accumulator.

[0047] The accumulator may include a primary opening, an upper wall, a lower wall, an accumulator sidewall and an accumulator interior at least partially bounded the upper wall, the lower wall and the accumulator sidewall, the accumulator for containing a layer of compressed gas atop the layer of bring solution when in use.

[0048] The upper wall, the lower wall and accumulator sidewall may each include the salt layer that at least partially encapsulates the accumulator interior.

[0049] The compressed gas energy storage system may include a gas compressor and expander subsystem spaced apart from the accumulator and a gas conduit having an upper end in communication with the gas compressor and expander subsystem and a lower end in communication with the accumulator interior are used for conveying compressed gas into the compressed gas layer of the accumulator when in use.

[0050] The compressed gas energy storage system may include a shaft. The shaft may have a lower end adjacent the primary opening, an upper end spaced apart from the lower end, and a shaft sidewall extending upwardly from the lower end to the upper end and at least partially bounding a shaft interior is used for containing a quantity of a brine solution. The shaft may be fluidly connectable to the brine solution source/sink via a liquid supply conduit.

[0051] The compressed gas energy storage system may include a partition that covers the primary opening and separates the accumulator interior from the shaft interior, the partition having an outer surface in communication with the shaft interior and an opposing inner surface in communication with the accumulator interior.

[0052] When in use, at least one of the layer of compressed gas and the layer of liquid may bear against and exert an internal accumulator force on the inner surface of the partition and the quantity of liquid within the shaft bears against and exerts an external counter force on the outer surface of the partition, whereby a net force acting on the partition while the compressed gas energy storage system is in use is a difference between the accumulator force and the counter force and is less than the accumulator force.

[0053] The compressed gas energy storage system may include an auxiliary gas release subsystem. The auxiliary gas release subsystem may include an auxiliary gas release conduit having an inlet in communication with the accumulator interior and an outlet, the auxiliary gas release conduit being spaced apart from gas conduit and configured to facilitate release of gas from the layer of gas within the accumulator.

[0054] The heater subsystem may include a thermal storage subsystem provided in fluid communication between the gas compressor and expander subsystem and the accumulator. The method may include extracting thermal energy from the compressed gas exiting the gas compressor and expander subsystem at an exit temperature; storing the thermal energy in the thermal storage subsystem and transferring the thermal energy that has been stored in the thermal storage subsystem to the brine solution in the in the brine solution source/sink via a gas/brine heat exchanger.

[0055] The gas compressor and expander subsystem may include a plurality of compression stages, each one of the plurality of compression stages may include a heat exchanger, and at least one of the heat exchangers from amongst the plurality of compression stages is fluidly connected to the gas/brine heat exchanger.

[0056] Each of the heat exchangers in the plurality of compression stages may be fluidly connected in series. In a compression operation, the method may include receiving ambient air into a first heat exchanger in a first compression stage and conveying the ambient air through the plurality of compression stages in series including into a last heat exchanger in a last compression stage; and using heated air exiting the last heat exchanger to convey the thermal energy to the gas/brine heat exchanger.

[0057] The plurality of compression stages may include a first compression stage, a second compression stage, and a third compression stage, in which, in a first compression stage, incoming air A from ambient may be conveyed into a first compressor driven by a motor of the first compression stage, and the air A exiting the first compressor may then be conveyed through a first heat exchanger of the thermal storage subsystem to transfer heat into a thermal storage liquid that is drawn from a first thermal storage reservoir; in a second compression stage, air exiting the first heat exchanger, which is conditioned to be air A’, is then conveyed into a second compressor driven by the motor of the second compression stage, and the air A’ exiting the second compressor is then conveyed through a second heat exchanger of the thermal storage subsystem to transfer heat into the thermal storage liquid; in a third compression stage, air exiting the second heat exchanger, which is conditioned to be air A”, may then be conveyed into a third compressor driven by the motor of the third compression stage, and the air A” exiting the second compressor is then conveyed through a third heat exchanger of the thermal storage subsystem to transfer heat into the thermal storage liquid; and air exiting the third heat exchanger, which is conditioned to be air A’”, may be then conveyed to the gas/brine heat exchanger to transfer heat from the air A’” to the brine solution in the brine solution source/sink.

[0058] A temperature of the air A’” may be higher than the present temperature of the layer of brine solution in the accumulator.

[0059] A temperature of the air A’” may be greater than 50 deg. C and the present temperature of the layer of brine solution in the accumulator may be 50 deg. C or less. [0060] A temperature of the air A’” may be between about 50 deg. C and 90 deg. C, and the present operating temperature of the layer of brine solution in the accumulator may be between about 15 deg. C and 50 deg. C.

[0061] The gas/brine heat exchanger may include an externally powered heater to heat the brine solution in the brine solution source/sink

[0062] The heater subsystem may include a heater positioned at the brine solution source/sink, wherein the heater is configured to heat the brine solution in the brine solution source/sink

[0063] The method may include generating waste heat by the gas compressor and expander subsystem through different operating modes. The operating modes may include: standby mode, charging mode, and discharging mode; and transferring the waste heat is transferred to the heater subsystem to heat the brine solution in the brine solution source/sink.

[0064] The compressed gas energy storage system may include a trim cooler of air, and the method may include: generating waste heat from the trim cooler of air in a charging mode of the gas compressor and expander subsystem and transferring the waste heat to the heater subsystem to heat the brine solution in the brine solution source/sink.

[0065] The method may include generating additional waste heat from thermal fluid cooling in the charging mode and in a discharging mode of the gas compressor and expander subsystem; and transferring the additional waste heat to the heater subsystem to heat the brine solution in the brine solution source/sink.

[0066] The method may include heating the compensation brine that is exiting the accumulator via the shaft using the heater subsystem to a brine exit temperature that is higher than the present temperature of the layer of brine solution in the accumulator; and, storing the brine solution exiting the accumulator, after being heated, in the brine solution source/sink.

[0067] The present operating temperature of the layer of brine solution in the accumulator may be about 50 deg. C or less, and the brine exit temperature is about 70 deg. C.

[0068] The heater subsystem may include a thermal storage subsystem provided in fluid communication between the gas compressor and expander subsystem and the accumulator. The method may include extracting the thermal energy from the compressed gas exiting the gas compressor and expander subsystem at an exit temperature; storing the thermal energy in the thermal storage subsystem; and transferring the thermal energy that has been stored in the thermal storage subsystem to the brine solution exiting the accumulator via a gas/brine heat exchanger.

[0069] The gas compressor and expander subsystem may include a plurality of compression stages, each one of the plurality of compression stages may include a heat exchanger, and at least one of the heat exchangers from amongst the plurality of compression stages is fluidly connected to the gas/brine heat exchanger.

[0070] Each of the heat exchangers in the plurality of compression stages may be fluidly connected in series, and wherein, in a compression operation, ambient air is received into a first heat exchanger in a first compression stage and is conveyed through the plurality of compression stages in series including into a last heat exchanger in a last compression stage; and heated air exiting the last heat exchanger conveys the thermal energy to the gas/brine heat exchanger.

[0071] The gas/brine heat exchanger may include an externally powered heater, and the method may include using the externally powered heater to heat the brine solution exiting the accumulator.

[0072] The brine solution source/sink may include a thermal insulating material that at least partially encapsulates the brine solution stored in the brine solution source/sink. [0073] In accordance with another broad aspect of the teachings described herein, that may be used alone or in combination with any other aspects, a compressed gas energy system may include a brine compensated salt cavern, wherein the brine in a surface reservoir, which is fluidly connectable to the brine compensated salt cavern, is maintained at a temperature equal or greater to the cavern temperature when in the surface reservoir.

[0074] Heat added to the brine in the surface reservoir may be at least partially transferred from a compressed gas energy system process that may include compressing air for storage in the brine compensated salt cavern and expanding air for release from the brine compensated salt cavern.

[0075] In accordance with another broad aspect of the teachings herein, that can be used in alone or in combination with any other aspects described herein a hydrostatically compensated compressed gas energy storage system can include an accumulator disposed underground and having an interior for containing a layer of compressed gas above a layer of compensation brine at an operating temperature. The layer of compressed gas may be at an accumulator pressure that is at least about 20 bar. The interior may be at least partially bounded by accumulator walls that comprise a salt layer that is exposed to the layer of compensation brine. A compressor and expander subsystem may be in fluid communication with the accumulator interior via a gas flow path and may be configured to selectably convey compressed gas into the accumulator and to extract gas from the accumulator. A compensation liquid reservoir may be spaced apart from the accumulator and may containing a quantity of the compensation brine that is an aqueous solution containing dissolved salt at a preconditioned salt concentration that is within about 25% of a salt saturation limit of the aqueous solution at the operating temperature. A compensation brine flow path may extend between the compensation liquid reservoir and the layer of compensation brine within the accumulator. The system may be operable in at least a discharging mode in which the compressor and expander subsystem extracts gas from the layer of compressed gas as a corresponding volume of the compensation brine flows into the layer of compensation brine via the compensation brine flow path and into contact with the salt layer within the accumulator, whereby an amount of salt from the salt layer that is dissolved into the incoming compensation brine at the preconditioned salt concentration is less than an amount of salt that would be dissolved into an incoming flow of compensation brine having a salt concentration that is lower than the preconditioned salt concentration and thereby reducing an amount of accumulator wall dissolution and cavern growth while maintaining the layer of compressed gas at substantially the accumulator pressure during the discharging mode.

[0076] The system may also be operable in a charging mode in which the compressor and expander subsystem conveys gas into the layer of compressed gas thereby displacing a corresponding volume of the compensation brine from the layer of compensation brine within the accumulator out of the accumulator via the compensation brine flow path thereby maintaining the layer of compressed gas at substantially the accumulator pressure during the charging mode.

[0077] A salt concentration of the volume of the compensation brine removed from the compensation brine layer may be equal to or less than the preconditioned salt concentration.

[0078] The salt concentration of the volume of the compensation brine removed from the compensation brine layer may be equal to or greater than the salt saturation limit of the aqueous solution at the operating temperature.

[0079] A salt concentration of the layer of compensation brine within the accumulator may be equal to or greater than the salt saturation limit of the aqueous solution at the operating temperature.

[0080] The compensation brine contained within the compensation liquid reservoir may be at a storage temperature that is within 25% of the operating temperature. [0081] The storage temperature may be within 10% of the operating temperature.

[0082] The storage temperature may be substantially equal to or greater than the operating temperature.

[0083] A brine heater assembly may be operable to heat the compensation brine contained to within the compensation liquid reservoir to the storage temperature.

[0084] A brine heater assembly may be operable to heat the compensation brine to a brine exit temperature that is greater than the storage temperature before the compensation brine enters the compensation liquid reservoir, and preferably wherein the brine exit temperature is at least 55 deg. C, and preferably is at least 60 deg. C or is at least 70 deg. C.

[0085] A brine heater assembly may be disposed in the compensation brine flow path upstream from the compensation liquid reservoir and is operable to heat the compensation brine contained within the compensation liquid reservoir to a storage temperature that is substantially equal to or greater than the operating temperature.

[0086] The brine heater assembly may include a gas/brine heat exchanger whereby thermal energy from a heat source is used to heat the compensation brine to be about the operating temperature or higher.

[0087] The heat source may include waste heat produced by the compressor and expander subsystem.

[0088] A thermal storage subsystem may be provided in fluid communication with the gas flow path between the compressor and expander subsystem and the accumulator, whereby the thermal energy is extracted from the compressed gas exiting the gas compressor and expander subsystem at an exit temperature, and the thermal energy that that is extracted is at least a portion of the heat source and is transferred to the compensation brine.

[0089] The gas compressor and expander subsystem may include a plurality of compression stages, each one of the plurality of compression stages comprising a heat exchanger, and at least one of the heat exchangers from amongst the plurality of compression stages is fluidly connected to the gas/brine heat exchanger.

[0090] Each of the heat exchangers in the plurality of compression stages may be fluidly connected in series, and wherein, in a compression operation, ambient air is received into a first heat exchanger in a first compression stage and is conveyed through the plurality of compression stages in series including into a last heat exchanger in a last compression stage; and heated air exiting the last heat exchanger conveys the thermal energy to the gas/brine heat exchanger.

[0091] The plurality of compression stages may include a first compression stage, a second compression stage, and a third compression stage, and wherein: in a first compression stage, incoming air A from ambient is conveyed into a first compressor driven by a motor of the first compression stage, and the air A exiting the first compressor is then conveyed through a first heat exchanger of the thermal storage subsystem to transfer heat into a thermal storage liquid that is drawn from a first thermal storage reservoir; in a second compression stage, air exiting the first heat exchanger, which is conditioned to be air A’, is then conveyed into a second compressor driven by the motor of the second compression stage, and the air A’ exiting the second compressor is then conveyed through a second heat exchanger of the thermal storage subsystem to transfer heat into the thermal storage liquid; in a third compression stage, air exiting the second heat exchanger, which is conditioned to be air A”, is then conveyed into a third compressor driven by the motor of the third compression stage, and the air A” exiting the second compressor is then conveyed through a third heat exchanger of the thermal storage subsystem to transfer heat into the thermal storage liquid; and air exiting the third heat exchanger, which is conditioned to be air A’”, is then conveyed to the gas/brine heat exchanger to transfer heat from the air A’” to the brine solution in the brine solution source/sink.

[0092] A temperature of the air A’” may be higher than the operating temperature.

[0093] A temperature of the air A’” may be greater than 50 deg. C and the operating temperature may be 50 deg. C or less.

[0094] A temperature of the air A’” may be between about 50 deg. C and 90 deg. C, and the operating temperature may be between about 15 deg. C and 50 deg. C.

[0095] The heat source may include an externally powered heater system.

[0096] The externally powered heater system may include a fuel-fired heater.

[0097] The externally powered heater system may include a solar heater system.

[0098] The preconditioned salt concentration may be within about 10% of the salt saturation limit of the aqueous solution at the operating temperature.

[0099] The preconditioned salt concentration may be within about 2% of the salt saturation limit of the aqueous solution at the operating temperature.

[00100] The preconditioned salt concentration may be substantially equal to or greater than the salt saturation limit of the aqueous solution at the operating temperature.

[00101] The compensation liquid reservoir may include a thermal insulating material that at least partially encapsulates the compensation brine stored in the compensation liquid reservoir. [00102] A salt dispensing system may be configured to dispense salt into the compensation liquid reservoir.

[00103] An agitating system may be in the compensation liquid reservoir to facilitate dissolving salt in the compensation liquid reservoir.

[00104] The agitating system may include at least one of: a mechanical mixing structure, a sparger, and a bubbler.

[00105] In accordance with another broad aspect of the teachings herein, that can be used in alone or in combination with any other aspects described herein a method for conveying brine solution in a compressed gas energy storage system may include: providing a layer of compensation brine stored below a layer of compressed gas within an accumulator of the compressed gas energy storage system at an operating temperature, the accumulator being at least partially bounded by accumulator walls that comprise a salt layer that is exposed to the layer of compensation brine; maintaining a compensation brine stored in a compensation liquid reservoir at a storage temperature that is within 25% of the operating temperature and so that the compensation brine is an aqueous solution containing dissolved salt at a preconditioned salt concentration that is within about 25% of a salt saturation limit of the aqueous solution at the operating temperature; and conveying the compensation brine having the precondition salt concentration to the accumulator.

[00106] Conveying of the compensation brine at the precondition salt concentration to the accumulator may occur when the compressed gas energy storage system is in a discharging mode in which a compressor and expander subsystem extracts gas from the layer of compressed gas as a corresponding volume of the compensation brine from the compensation liquid reservoir flows into the layer of compensation brine, via a compensation brine flow path, and into contact with the salt layer within the accumulator, whereby an amount of salt from the salt layer that is dissolved into the incoming compensation brine at the preconditioned salt concentration is less than an amount of salt that would be dissolved into an incoming flow of compensation brine having a salt concentration that is lower than the preconditioned salt concentration and thereby reducing an amount of accumulator wall dissolution and cavern growth while maintaining the layer of compressed gas at substantially the accumulator pressure during the discharging mode.

[00107] The accumulator may be disposed underground and the layer of compressed gas is at an accumulator pressure that is at least about 20 bar.

[00108] The compressed gas energy storage system may be operated in a charging mode in which the compressor and expander subsystem conveys gas into the layer of compressed gas thereby displacing a corresponding volume of the compensation brine from the layer of compensation brine within the accumulator out of the accumulator via the compensation brine flow path thereby maintaining the layer of compressed gas at substantially the accumulator pressure during the charging mode.

[00109] A salt concentration of the volume of the compensation brine removed from the compensation brine layer may be equal to or less than the preconditioned salt concentration.

[00110] The salt concentration of the volume of the compensation brine removed from the compensation brine layer may be equal to or greater than the salt saturation limit of the aqueous solution at the operating temperature.

[00111] A salt concentration of the layer of compensation brine within the accumulator is equal to or greater than the salt saturation limit of the aqueous solution at the operating temperature.

[00112] The method can include heating, using a brine heater assembly, the compensation brine contained within the compensation liquid reservoir to a storage temperature that is within 25% of the operating temperature

[00113] The method can include heating, using a brine heater assembly, the compensation brine contained within the compensation liquid reservoir to a storage temperature that is within 10% of the operating temperature.

[00114] The method can include heating, using a brine heater assembly, the compensation brine contained within the compensation liquid reservoir to a storage temperature that is substantially equal to or greater than the operating temperature.

[00115] The brine heater assembly may include a gas/brine heat exchanger whereby thermal energy from a heat source is used to heat the compensation brine to be about the operating temperature or higher.

[00116] The heat source may include waste heat produced by a compressor and expander subsystem of the compressed gas energy storage system. [00117] A thermal storage subsystem may be provided in fluid communication with the gas flow path between the compressor and expander subsystem and the accumulator, whereby the thermal energy is extracted from the compressed gas exiting the gas compressor and expander subsystem at an exit temperature, and the thermal energy that that is extracted is at least a portion of the heat source and is transferred to the compensation brine.

[00118] The gas compressor and expander subsystem may include a plurality of compression stages, each one of the plurality of compression stages comprising a heat exchanger, and at least one of the heat exchangers from amongst the plurality of compression stages is fluidly connected to the gas/brine heat exchanger.

[00119] Each of the heat exchangers in the plurality of compression stages may be fluidly connected in series, and wherein, in a compression operation, ambient air may be received into a first heat exchanger in a first compression stage and is conveyed through the plurality of compression stages in series including into a last heat exchanger in a last compression stage. Heated air exiting the last heat exchanger may convey the thermal energy to the gas/brine heat exchanger.

[00120] The plurality of compression stages may include a first compression stage, a second compression stage, and a third compression stage, and wherein: in a first compression stage, incoming air A from ambient is conveyed into a first compressor driven by a motor of the first compression stage, and the air A exiting the first compressor is then conveyed through a first heat exchanger of the thermal storage subsystem to transfer heat into a thermal storage liquid that is drawn from a first thermal storage reservoir; in a second compression stage, air exiting the first heat exchanger, which is conditioned to be air A’, is then conveyed into a second compressor driven by the motor of the second compression stage, and the air A’ exiting the second compressor is then conveyed through a second heat exchanger of the thermal storage subsystem to transfer heat into the thermal storage liquid; in a third compression stage, air exiting the second heat exchanger, which is conditioned to be air A”, is then conveyed into a third compressor driven by the motor of the third compression stage, and the air A” exiting the second compressor is then conveyed through a third heat exchanger of the thermal storage subsystem to transfer heat into the thermal storage liquid; and air exiting the third heat exchanger, which is conditioned to be air A’”, is then conveyed to the gas/brine heat exchanger to transfer heat from the air A’” to the brine solution in the brine solution source/sink.

[00121] A temperature of the air A’” may be higher than the operating temperature.

[00122] A temperature of the air A’” may be greater than 50 deg. C and the operating temperature is 50 deg. C or less.

[00123] A temperature of the air A’” may be between about 50 deg. C and 90 deg. C, and the operating temperature is between about 15 deg. C and 50 deg. C.

[00124] The heat source may include an externally powered heater system.

[00125] The externally powered heater system may include a fuel-fired heater.

[00126] The externally powered heater system may include a solar heater system.

[00127] The preconditioned salt concentration may be within about 10% of the salt saturation limit of the aqueous solution at the operating temperature.

[00128] The preconditioned salt concentration may be within about 2% of the salt saturation limit of the aqueous solution at the operating temperature.

[00129] The preconditioned salt concentration may be substantially equal to or greater than the salt saturation limit of the aqueous solution at the operating temperature.

[00130] The compensation liquid reservoir may include a thermal insulating material that at least partially encapsulates the compensation brine stored in the compensation liquid reservoir.

[00131] The method may include heating the compensation brine to the storage temperature using a brine heater assembly that is configured to heat the compensation brine while it is contained within the compensation liquid reservoir.

[00132] The method may include pre-heating an incoming stream of the compensation brine using a brine heater assembly to a brine exit temperature that is greater than the storage temperature and then conveying the compensation brine into the compensation liquid reservoir.

[00133] The brine exit temperature may be at least 55 deg. C, and preferably is at least 60 deg. C or is at least 70 deg. C.

[00134] In accordance with another broad aspect of the teachings herein, that can be used in alone or in combination with any other aspects described herein a compressed gas energy system may include a brine compensated salt cavern, wherein the brine in a surface compensation liquid reservoir, which is fluidly connectable to the brine compensated salt cavern, is maintained at a temperature equal or greater to the cavern temperature when in the surface reservoir.

[00135] Heat added to the brine in the surface reservoir may be at least partially transferred from a compressed gas energy system process that comprises compressing air for storage in the brine compensated salt cavern and expanding air for release from the brine compensated salt cavern.

BRIEF DESCRIPTION OF THE DRAWINGS

[00136] The drawings included herewith are for illustrating various examples of articles, methods, and apparatuses of the teaching of the present specification and are not intended to limit the scope of what is taught in any way.

[00137] Figure 1a is a schematic representation of one example of a hydrostatically compensated compressed gas energy storage system;

[00138] Figure 1 b is another schematic representation of the hydrostatically compensated compressed gas energy storage system of Figure 1 showing a thermal storage subsystem;

[00139] Figure 2 is a schematic representation of a portion of the system of Figure 1 ;

[00140] Figure 3 is a schematic representation of another example of a hydrostatically compensated compressed gas energy storage system;

[00141] Figure 4 is a schematic representation of another example of a hydrostatically compensated compressed gas energy storage system;

[00142] Figure 5 is a schematic representation of a hydrostatically compensated compressed gas energy storage system in a charging mode; and

[00143] Figure 6 is a schematic representation of the hydrostatically compensated compressed gas energy storage system of Figure 5 in a discharging mode.

DETAILED DESCRIPTION

[00144] Various apparatuses or processes will be described below to provide an example of an embodiment of each claimed invention. No embodiment described below limits any claimed invention and any claimed invention may cover processes or apparatuses that differ from those described below. The claimed inventions are not limited to apparatuses or processes having all of the features of any one apparatus or process described below or to features common to multiple or all of the apparatuses described below. It is possible that an apparatus or process described below is not an embodiment of any claimed invention. Any invention disclosed in an apparatus or process described below that is not claimed in this document may be the subject matter of another protective instrument, for example, a continuing patent application, and the applicants, inventors or owners do not intend to abandon, disclaim or dedicate to the public any such invention by its disclosure in this document.

[00145] Referring to Figures 1 a and 1 b one example of a hydrostatically compensated compressed gas energy storage system 10A, that can be used to compress, store and release a gas, includes an accumulator 12 that is located underground (although in another embodiment the accumulator may be located above ground). In this example, the accumulator 12 serves as a chamber for holding both compressed gas and a compensation liquid (such as water or a brine as described herein) and can include any suitable type of pressure vessel or tank, or as in this example can be an underground cave or chamber that is within ground 200. Optionally, the accumulator 12 may be lined, for example using concrete, metal, plastic and combinations thereof or the like, to help make it substantially gas and/or liquid impermeable so as to help to prevent unwanted egress of gas or liquid from within its interior. However, in the present example the accumulator is preferably impermeable to gas and or liquid without requiring such a lining. Instead, in the embodiments described herein the accumulator 12 is at least partially formed by an underground salt cavity or cavern, such as may be found naturally occurring in some locations or as may be left over from a salt mining operation. Preferably, the cavern may be purposely developed for gas storage, such as through solution mining or other suitable excavation technique. In these examples the walls of the salt cavern are generally exposed and can come into direct, physical contact with the compensation liquid that is used in the system.

[00146] Underground salt caverns may have some desirable attributes that can make them relatively well suited to store liquids or gases as compared to other rock or mineral formations. For example, salt caverns tend to be generally liquid and/or vapour impermeable due to their crystalline structure and may reduce or eliminate the need to provide a separate cavern lining. This may help simplify construction of the systems described herein and/or reduce the construction costs.

[00147] Underground salt caverns have been used to store liquids and/or gases in other applications, such as in oil and gas storage and the like and may also be suitable for storing water or other aqueous solutions. When storing water or other liquids in which salt is soluble at least some of the salt from the cavern walls may dissolve into the liquid as the liquid flows into, and is held within, the cavern. The dissolving of the salt from the cavern walls may continue until the liquid within the cavern reaches its salt saturation point - for the given temperature and pressure of the liquid as it is stored within the cavern. As salt is dissolved from the cavern walls the interior volume of the cavern may increase. In some situations, the removal of salt from the cavern walls via dissolving into the liquid may reduce the local thickness of the cavern wall and can, under some circumstances, lead to cracks or breaches in the salt cavern wall - exposing the surrounding rock or soil. This may be disadvantageous as the material surrounding the salt cavern may not have the same impermeability as the salt, so breaches in the salt cavern walls may allow the contents of the cavern to escape/leak into the surrounding ground. Increased growth of the cavern through uncontrolled dissolving of the cavern walls may also lead to an unstable cavern geometry which could lead to roof falls or other cavern instability issues.

[00148] The degree of wall erosion via salt dissolving can be related to the volume of water or liquid that is introduced into the cavern and its relative salt content. Adding “fresh” or generally salt free liquid into the cavern may tend to cause relatively high amounts of dissolving. Similarly, erosion/ dissolving may not occur evenly across all of the salt cavern surfaces, and instead may tend to be localized in entry/exit points where the liquid is flowing relatively quickly, and on the lower/bottom surfaces of a cavern which will tend to be submerged even when the cavern is only partially full of liquid.

[00149] The accumulator 12 may have any suitable configuration, and in this example, includes an upper wall 13 and an opposing lower wall 15 that are separated from each other by an accumulator height 17. While the accumulators 12 described herein are illustrated schematically as generally rectangular chambers, the accumulator(s) provided in a given embodiment of the teachings described herein may be of any suitable shape and volume and may be irregularly shaped - as may be the case when using a salt cavern as the accumulator. [00150] The upper and lower walls 13 and 15 may be of any suitable configuration, including curved, arcuate, angled, and the like, and in the illustrated example are shown as generally planar surfaces, that are generally parallel to a horizontal reference plane 19. The accumulator 12 also has an accumulator width (not shown - measured into the page as illustrated in Figure 1). The upper and lower walls 13 and 15, along with one or more sidewalls 21 at least partially define an interior of the accumulator 12, that has an accumulator volume. In embodiments where the accumulator includes a salt cavern or similar structure at least some portions of the upper and lower walls 13 and 15, along with one or more sidewalls 21 (collectively the walls) of the accumulator 12 can include a salt layer that helps bound the interior of the accumulator 12. In some examples the walls can be formed substantially entirely from salt (for at least a material thickness) and in other examples the walls may include rock or other non-salt materials that carry a layer of salt that is exposed to the accumulator interior. In some configurations, the walls may be only, or at least partially covered with a salt layer and other portions of the wall may not have exposed salt surfaces. For example, the sidewalls 21 in a given accumulator may have exposed salt layers while portions of the upper wall 13 may be exposed rock, concrete, metal, plastic or the like. Such configurations would be examples of an accumulator interior that is at least partially bounded by accumulator walls that include a salt layer that is exposed to the layer of compensation liquid (such as a compensation brine) that is contained within the accumulator 12.

[00151] The accumulator 12 in a given embodiment of the system 10A can be sized based on a variety of factors (e.g., the quantity of gas to be stored, the available space in a given location, etc.) and may, in some examples may be between about 1 ,000m³ and about 2,000,000m³ or more. For example, in this embodiment the accumulator 12 contains a layer of stored compressed gas 14 atop a layer of compensation liquid 16, and its volume (and thus capacity) can be selected based on the quantity of gas 14 to be stored, the duration of storage required for system 10A, the desired accumulator pressure, features of the surrounding ground/rocks, compensation liquid composition and other suitable factors which may be related to the capacity or other features of a suitable power source and/or power load with which the system 10A is to be associated. The power source/load may be, in some examples, a power grid G (Figure 2), a power source (including renewable and optionally non-renewable sources) and the like. Furthermore, the power source and power load may be completely independent of each other (e.g., the power source may be a renewable source, and the power load may be the grid).

[00152] Preferably, the accumulator 12 may be positioned below ground, but alternatively in some other examples may be at least partially or entirely above ground using a suitable containment vessel. Positioning the accumulator 12 within the ground 200, as shown, may allow the weight of the ground/soil to help backstop/ buttress the walls 13, 15 and 21 of the accumulator 12, and help resist any outwardly acting forces that are exerted on the walls 13, 15 and 21 of the interior 23 of the accumulator. Its depth in the ground, shown as an accumulator depth 50 in Figure 1 , is established according to the pressures at which the compression/expansion equipment to be used is most efficiently operated as this depth 50 and influence the hydrostatic pressure exerted by the compensation liquid, as well as the geology in the surrounding area and the like. The depth 50 may be between about 200m and about 700m and may be between 400m and 600m and may be at least 500m in some examples.

[00153] The gas that is to be compressed and stored in the accumulator 12 may be any suitable gas, including, but not limited to, air, nitrogen, carbon dioxide, noble gases and combinations thereof and the like. Using air may be preferable in some embodiments as a desired quantity of air may be drawn into the system from the surrounding, ambient environment and gas/air that is released from within the accumulator 12 can similarly be vented to the ambient environment, optionally without requiring further treatment. In this embodiment, the compressed gas 14 is compressed atmospheric air.

[00154] The compensation liquid may be any suitable liquid, with water or aqueous solutions being preferred in some embodiments. In the presently described embodiments where the accumulator 12 includes an underground salt cavern, using water or aqueous solutions that are not saturated with salt may tend to cause portions of the cavern walls to dissolve into the compensation liquid while the system 10A is in use, particularly when the compensation liquid is flowing into and out of the accumulator 12 on a frequent basis. In examples where the system 10A is cycled (as described herein) relatively infrequently, e.g., so that the flow of compensation liquid into and out of the accumulator does not occur very often, using a non-saturated compensation liquid may be acceptable even because there is less of an opportunity to cycle fresh non-saturated brine into the cavern. For example, each cycle may lead to a small amount of dissolution that gradually contributes to cavern expansion via dissolving of salt from the cavern walls, but if the number of cycles is relatively low then this dissolution may be limited. However, in embodiments where the compensation liquid is expected to be at least partially cycled into and out of the accumulator 12 on a relatively high frequency, such as 1-10 times a month, or 1-7 times a week or even once a day or more, the frequent introduction of non-saturated compensation liquid into the cavern may cause undesired rates of dissolving/erosion of the cavern walls. To help mitigate this dissolving/erosion risk, in some examples of the systems 10 described herein it may be preferable to use a brine solution (e.g., an aqueous solution that includes at least some dissolved salt) as the compensation liquid. Introducing a compensation liquid that is an at least partially saturated brine solution, and optionally a fully saturated or over saturated brine, may help reduce the amount of dissolving of salt from the cavern walls that would occur when the compensation liquid is introduced into, withdrawn from and held within the accumulator 12. Compensation liquid that contains at least some dissolved salt can be referred to as a compensation brine.

[00155] Further, the maximum saturation level/concentration of salt in a waterbased solution is at least partially dependent on the temperature of the solution, as such the compensation liquid or brine may have different maximum saturation level in the accumulator than in the surface reservoir. As described herein, the temperature of the layer of gas 14 is expected to be within the accumulator 12 (a storage temperature), and therefore storage temperature of the layer of compensation liquid 16 within the accumulator 12 may be higher than the ambient temperature at the surface. In such arrangements, the maximum salt saturation point/concentration of the compensation brine at the ambient, surface temperature may be less than the saturation concentration of the compensation brine at the operating/storage temperature that it is likely to be exposed to while be stored within the accumulator 12. This could lead to operating conditions where the compensation brine is fully saturated at the surface temperature, but when it reaches the accumulator and is at the system storage temperature then the compensation brine is only partially saturated. As a partially saturated solution at the storage temperature, the compensation brine may contribute to the dissolving/erosion of the salt cavern walls.

[00156] To help reduce such dissolving/erosion, the systems 10 described herein that utilize a compensation brine liquid can optionally be configured to precondition the compensation brine before it enters the accumulator 12 (such as by pre- heating the compensation liquid in the presence of salt) so that the compensation brine is relatively closer to its operating temperature and maximum salt saturation concentration before it enters the accumulator 12. In some examples, the operating temperature within the accumulator 12 while the system 10C is in use may be between about 15 deg. C and 50 deg. C, or more, depending on location and accumulator depth.

[00157] In some examples, the systems 10 can be operated so that the compensation brine is treated with salt or otherwise prepared so that it has a preconditioned salt concentration, while in the reservoir 150, that is within 25%, 20%, 15%, 10%, 5%, 2% and optionally may be at or above its operating temperature salt saturation concentration (e.g., the salt saturation limit of the aqueous solution at the operating temperature the salt saturation concentration for that liquid when at the operating temperature) before the compensation brine enters the accumulator 12. This may help reduce the dissolving of salt from the cavern walls when the compensation brine enters the accumulator, as compared to introducing a flow of compensation liquid that has a lower preconditioned salt concentration and would therefore be likely to dissolve/absorb relatively more salt from the cavern walls before reaching its salt saturation limit.

[00158] Because salt saturation concentration is largely, if not entirely, temperature dependent, some examples of the systems 10 described herein may be configured to extract saturate compensation brine from the accumulator 12 at the operating temperature (such as during a charging cycle), to keep the compensation brine substantially at or above the operating temperature during that time that the system 10A remains charged (thereby inhibiting the dissolved salt from coming out of solution) and then reintroducing the compensation brine into the accumulator (such as during a discharge cycle) in a saturated condition- which can inhibit and/or eliminate further salt dissolving from the cavern walls into the pre-saturated compensation brine. Alternatively, instead of maintaining the compensation brine at or above the operating temperature for the duration of the storage period, the compensation brine may be allowed to cool (thereby driving salt out of solution) but can then be reheated to the operating temperature or higher and may have salt re-introduced into the compensation brine such that the compensation brine is again pre-saturated for the operating temperature prior to be introduced into the accumulator 12. [00159] In some other cases, after compressing the air at the end of a charging processing, the compressed air is further cooled to be close to or about the same temperature as the accumulator 12.

[00160] While the thermal storage subsystem 120 is only schematically illustrated in relation to system 10A it may also be included in systems 10B, 10C and other system designs.

[00161] Optionally, the systems 10A-10C described herein may be configured so that the thermal energy used to heat, and/or re-heat, the compensation brine to the operating temperature may be obtained by transferring heat/ thermal energy from other portions of the system into or out of the compensation brine. This may help utilize thermal energy that might otherwise be exhausted or wasted from the system, which may help reduce the need to provide additional thermal energy just for the purpose of heating the compensation brine. Alternatively, at least some, or all, of the thermal energy required to keep the compensation brine at or above the operating temperature may be provided from an external heat source (such as fuel-fired heater, solar system or the like)

[00162] Optionally, to help provide access to the interior of the accumulator 12, for example for use during construction of the accumulator and/or to permit access for inspection and/or maintenance, the accumulator 12 may include at least one opening that can be sealed in a generally air/gas tight manner when the system 10A is in use. In this example, the accumulator 12 includes a primary opening 27 that is provided in the upper wall 13. The primary opening 27 may be any suitable size and may have a cross-sectional area that is adequate based on the specific requirements of a given embodiment of the system 10A. In one embodiment the cross-sectional area is between about 0.75m2 and about 80 m2 but may be larger or smaller in a given embodiment.

[00163] When the system 10A is in use, the primary opening 27 may be sealed using any suitable type of partition that can function as a suitable sealing member. In the embodiment of Figure 1 , the system 10A includes a partition in the form of a bulkhead 24 that covers the primary opening 27 and that is arranged generally horizontally (as illustrated in Figure 1). In other examples, such as a hydrostatically compensated compressed gas energy storage system 10C that is shown in Figure 4, the bulkhead 24 can be oriented vertically such that it seals an opening in a sidewall of the accumulator 12. Other examples of suitable partitions are described in PCT/CA2018/050112 and PCT/CA2018/050282, which are incorporated herein by reference.

[00164] When the bulkhead 24 is in place, as shown in Figure 1 , it can be secured to, and preferably sealed with the accumulator wall, in this embodiment upper wall 13, using any suitable mechanism to help seal and enclose the interior 23. In this embodiment the shaft 18 is illustrated schematically as a generally linear, vertical column. Alternatively, the shaft 18 may be a generally linear inclined shaft or preferably may be a curved and/or generally spiral/helical type configuration and which may be referred to as a shaft or generally as a decline. Some embodiments may include a generally spiralling configured decline that winds from an upper end to a lower end and can have an analogous function and attributes as the vertical shaft 18 of Figure 1 despite having a different geometrical configuration. Discussions of the shaft/ decline 18 and its purposes in one embodiment can be applied to other embodiments described herein.

[00165] In the embodiment of Figure 1 , the primary opening 27 is provided in the upper surface 13 of the accumulator 12. Alternatively, in other embodiments the primary opening 27 and any associated partition may be provided in different portions of the accumulator 12, including, for example, on a sidewall (such as sidewall 21 as shown in Figures 3 and 4), in a lower surface (such as lower surface 15) or other suitable location. The location of the primary opening 27, and the associated partition, can be selected based on a variety of factors including, for example, the geology and underground conditions, the availability of existing structures (e.g., if the system 10A is being retrofit into some existing spaces, such as mines, quarries, storage facilities and the like), operating pressures, shaft configurations and the like. For example, some aspects of the systems 10A described herein may be retrofit into pre-existing underground chambers, such as salt caverns, which may have been constructed with openings in their sidewalls, floors and the like.

[00166] When the primary opening 27 extends along the sidewall 21 of the accumulator 12 as shown in the embodiment of Figure 3, it may be positioned such that is contacted by only the gas layer 14 (i.e. toward the top of the accumulator 12), contacted by only the layer of compensation liquid 16 (i.e. submerged within the layer of compensation liquid 16 and toward the bottom of the accumulator) and/or by a combination of both the gas layer 14 and the layer of compensation liquid 16 (i.e. partially submerged and partially non-submerged in the liquid). The specific position of the free surface of the layer of compensation liquid 16 (i.e. , the interface between the layer of compensation liquid 16 and the gas layer 14) may change while the system 10A is in use as gas is forced into (causing the liquid layer to drop) and/or withdrawn from the accumulator (allowing the liquid level to rise).

[00167] When the accumulator 12 is in use, at least one of the pressurized gas layer 14 and the layer of compensation liquid 16 may contact and exert pressure on the inner-surface 29 of the bulkhead 24, which will result in a generally outwardly, (upwardly in this embodiment) acting internal accumulator force, represented by arrow 41 in Figure 1 , acting on the bulkhead 24.

[00168] Optionally, in some examples of the systems described herein no partition or bulkhead may be included in the cavern. For example, for the cavern was developed by solution mining or other remote mining techniques there may not be a need to plug access passages that were developed during construction.

[00169] In the present embodiment, the system 10A includes a shaft 18 that is configured so its lower end 43 is in communication with the opening 27 of the accumulator 12, and its upper end 48 that is spaced apart from the lower end 43 by the accumulator depth 50 that also coincides with the shaft height in this example. At least one sidewall 52 extends from the lower end 43 to the upper end 48, and at least partially defines a shaft interior 54 having a volume. In this embodiment, the shaft 18 is generally linear and extends along a generally vertical shaft axis, but may have other configurations, such as a linear, curved, or helical decline, in other embodiments. The upper end 48 of the shaft 18 may be open to the atmosphere A, as shown, or may be capped, enclosed or otherwise sealed. In this embodiment, shaft 18 is generally cylindrical with a diameter 56 of about 3 metres, and in other embodiments the diameter 56 may be between about 2m and about 15m or more, or may be between about 5m and 12m, or between about 2m and about 5m. In such arrangements, the interior 52 of the shaft 18 may be able to accommodate about 1 ,000 - 150,000 m³ or more of a suitable compensation liquid.

[00170] In this arrangement, the bulkhead 24 is positioned at the interface between the shaft 18 and the accumulator 12, and the outer surface 31 (or at least a portion thereof) closes and seals the lower end 43 of the shaft 18. The bulkhead may include a variety of other elements to help facilitate operation of the system 10A, including a gas release valve illustrated schematically using reference character 42. Preferably, the other boundaries of the shaft 18 (e.g., the sidewall 52) are generally liquid impermeable, such that the interior 54 can be filled with, and can generally retain a quantity of a suitable compensation liquid 20. The compensation liquid 20 for a given system 10 can be chosen based on the features of the system, including the accumulator size, the accumulator depth 50 and its desired system operating/accumulator pressure and operating temperature. In some examples, the compensation liquid can be a compensation brine as described herein, while in other examples the compensation liquid can be a different liquid.

[00171] A compensation liquid supply/replenishment conduit 58 can provide fluid communication between the interior 54 of the shaft 18 and a compensation liquid source/sink or reservoir 150 to allow compensation liquid to flow into or out of the interior of the shaft 18 as required when the system 10 is in operational modes. Optionally, a flow control apparatus may be provided in the compensation liquid supply/replenishment conduit 58. The flow control apparatus may include a valve, sluice gate, or other suitable mechanism. The flow control apparatus can be open while the system 10 is in operational modes to help facilitate the desired flow of compensation liquid between the shaft 18 and the compensation liquid reservoir 150. Optionally, the flow control apparatus can be closed to fluidly isolate the shaft 18 and the compensation liquid reservoir 150 if desired. For example, the flow control apparatus may be closed to help facilitate draining the interior 54 of the shaft 18 for inspection, maintenance or the like. One or more suitable pumps or other flow equipment may also be provided in this flow path if desired. In the illustrated examples, a compensation liquid flow path is defined between the compensation liquid reservoir 150 and the layer of compensation liquid 16 within the accumulator, and this path can include the shaft 18, compensation liquid supply conduit 40, supply/replenishment conduit 58 and the compensation liquid reservoir 150, along with other suitable conduits or members. Compensation liquid can flow through this flow path when the system is in the charging and discharging modes.

[00172] The compensation liquid reservoir 150 may be of any suitable nature and configuration fora given system and for a given compensation liquid (e.g., brine, water, slurry or other type of liquid). The compensation liquid reservoir 150 may include, for example, a generally open pond or reservoir (which may be configured to hold the compensation brine, water, slurry or the like), a purposely built reservoir, a storage tank, a water tower, a connection to a municipal water supply or reservoir and/or a natural body of water such as a lake, river or ocean, groundwater, or an aquifer.. In systems that utilize a heated compensation brine, as described herein, the compensation liquid reservoir 150 can include a brine heater assembly that is configured to heat the compensation brine to a desired storage temperature (which can be within about 25%, 20%, 15%, 10%, 5%, 2% of the operating temperature within the accumulator 12, or may be substantially the same as the operating temperature within the accumulator 12). The brine heater assembly can include different types of heaters and apparatuses as are suitable for a given application of the teachings described herein and for a given reservoir configuration. In some embodiments the brine heater assembly can include a direct heating apparatus, such as an electrical or gas/fuel-fired heater to directly warm the compensation brine using an external energy source. In other embodiments, the brine heater assembly can include heat exchanges and other such devices that can allow heat from one portion of the system (such as the compressed gas or thermal storage subsystem) to be transferred to the compensation brine - or vice versa. Some examples of a brine heater assembly may include both direct heating apparatus(es) and heat exchangers.

[00173] If the storage temperature of the compensation brine is higher than the expected ambient temperature of the location where the compensation liquid reservoir 150 is located, it may be desirable for the compensation liquid reservoir 150 to include at least some amount of thermal insulation or otherwise be configured to help reduce heat loss from the stored compensation brine to the surrounding environment. This can include providing an insulating cover, film, lid or the like that can be provided to cover an open compensation liquid reservoir pool or lake as illustrated in some of the examples herein. Alternatively, or in addition to utilizing covers of this nature, the compensation liquid reservoir 150 may also include one or more suitable vessels or tanks that can be insulated using suitable lines, insulating wraps and the like.

[00174] The heaters used to warm the compensation brine can be configured to heat the compensation brine while it is stored within the compensation liquid reservoir 150, to heat the compensation brine before it enters the compensation liquid reservoir 150, and/or optionally to extract at least some of the compensation brine from the compensation liquid reservoir 150, heat it to the desired temperature and then return the compensation brine to the compensation liquid reservoir 150. Other arrangements and methods of heating the compensation brine to its desired temperature may also be used. [00175] If the compensation liquid used is a compensation brine, as described in the examples herein, the system can include a concentration control apparatus that can include salt dispensing device with a supply of salt (either as dry crystals or a premixed, concentrated brine slurry) that can be added into the liquid contained within the compensation liquid reservoir 150 - for example to help adjust the salt concentration of the brine to a desired level. This concentration control apparatus can include any suitable container or vessel, such as a hopper, silo, tank or the like that can hold the salt material. Optionally, the concentration control apparatus may include any suitable mixing, stirring and/or agitating system to help mix the salt into the compensation liquid and/or to help keep salt dissolved within the compensation brine that is stored in the compensation liquid reservoir 150. In the present description the concentration control apparatus illustrated schematically in Figures 3 and 4 using character 180, can have different configurations in different embodiments of the teachings described herein. This may include a mechanical mixing arm or structure that can include any suitable motor or power source and combination of physical engagement or mixing member that can contact and mix the compensation liquid. The agitating system could also include a sparger, bubbler or other type of mixing mechanism. The system 10A may also be arranged so that additional solid material, such as salt may be introduced into the compensation liquid reservoir 150 to be mixed into the brine, for example to alter its salt saturation while the system is in use (such as to account for liquid loss, evaporation, different operating pressure requirements or the like).

[00176] Allowing the compensation liquid to flow through the conduit 58 may help ensure that a sufficient quantity of compensation liquid 20 may be maintained within shaft 18 and that excess compensation liquid 20 can be drained from shaft 18. The conduit 58 may be connected to the shaft 18 at any suitable location, and preferably is connected toward the upper end 48. Preferably, the conduit 58 can be positioned and configured such that compensation liquid will flow from the reservoir 150 to the shaft 18 via gravity, and need not include external, powered pumps or other conveying apparatus. Although the conduit 58 is depicted in the figures as horizontal, it may be non-horizontal.

[00177] In this embodiment, the system 10A includes a gas flow path that provides fluid communication between the compressor and expander subsystem 100 and the accumulator 12. The gas flow path may include any suitable number of conduits, passages, hoses, pipes and the like and any suitable equipment may be provided in (i.e., in air flow communication with) the gas flow path, including, compressors, expanders, heat exchangers, valves, sensors, flow meters and the like. Referring to the example of Figure 1 , in this example the gas flow path includes a gas supply conduit 22 that is provided to convey compressed air between the compressed gas layer 14 and the compressor and expander subsystem 100, which can convert the potential energy of compressed air to and from electricity. Similarly, a liquid supply conduit 40 is configured to convey water between the layer of compensation liquid 16 and the compensation liquid 20 in shaft 18. Each conduit 22 and 40 may be formed from any suitable material, including metal, the surrounding rock, plastic and the like. [00178] In this example, the gas conduit 22 has an upper end 60 that is connected to the compressor and expander subsystem 100, and a lower end 62 that is in communication with the compressed gas layer 14. The gas conduit 22 is, in this example, positioned inside and extends within the shaft 18 whereby at least a portion of the outer surface of the gas supply conduit 22 is in contact with the compensation liquid that is within the shaft 18, and passes through the bulkhead 24 to reach the compressed gas layer 14. Positioning the gas conduit 22 within the shaft 18, and thus exposing at least some of its outer surface to the compensation liquid, may eliminate the need to bore a second shaft and/or access path from the surface to the accumulator 12. The positioning in the current embodiment may also leave the gas conduit 22 generally exposed for inspection and maintenance, for example by using a diver or robot that can travel through the compensation liquid 20 within the shaft 18 and/or by draining some or all of the water from the shaft 18. Alternatively, as shown using dashed lines in Figure 1 (and in the other embodiments described herein), the gas conduit 22 may be external the shaft 18 and/or or may not be in contact with the compensation liquid. Positioning the gas conduit 22 outside the shaft 18 may help facilitate remote placement of the compressor and expander subsystem 100 (i.e., it need not be proximate the shaft 18) and may not require the exterior of the gas conduit 22 (or its housing) to be submerged in the compensation liquid. This may also eliminate the need for the gas conduit 22 to pass through the partition that separates the accumulator 12 from the shaft 18.

[00179] The liquid supply conduit 40 is, in this example, configured with a lower or inner end 64 that is submerged in the layer of compensation liquid 16 while the system 10 is in use and a remote upper, or outer end 66 that is in communication with the interior 54 of the shaft 18. In this configuration, the liquid supply conduit 40 can facilitate the exchange of liquid between the layer of compensation liquid 16 and the compensation liquid 20 in the shaft 18. As illustrated in Figure 1 , the liquid supply conduit 40 can pass through the bulkhead 24 (as described herein), or alternatively, as shown using dashed lines, may be configured to provide communication between the layer of compensation liquid 16 and the compensation liquid 20, but not pass through the bulkhead 24.

[00180] In this arrangement, as more gas is transferred into the gas layer 14 during an accumulation cycle or charging cycle the compensation liquid, such as brine in this preferred example (but optionally a slurry, water or other liquid in other examples) in the layer of compensation liquid 16 can be displaced and forced upwards through the liquid supply conduit 40 into shaft 18. More particularly, the compensation liquid can preferably freely flow from the layer of compensation liquid 16 within the accumulator 12 and into shaft 18 when pressurized by the incoming gas, and ultimately may be exchanged with the reservoir 150 of compensation liquid, via a replenishment conduit 58. Alternatively, any suitable type of flow limiting or regulating device (such as a pump, valve, orifice plate and the like) can be provided in the compensation liquid supply conduit 40. When the system is operated in a discharging mode wherein gas is removed from the gas layer 14 and used to generate energy, compensation liquid can flow from the shaft 18, through the compensation liquid supply conduit 40, into the accumulator to refill the layer of compensation liquid 16 as the gas is withdrawn. As additional compensation brine flows into the accumulator it helps maintain the accumulator pressure at the operating pressure, even as gas is being withdrawn. This can help ensure that the pressure of the gas being extracted remains generally constant even when different amounts of gas are left in the accumulator 12. This can help the compression and expansion subsystem to operate in its intended, and preferably relatively efficient, ranges as the gas to be expanded is at a substantially constant pressure (and temperature if a suitable thermal conditioning systems is used) throughout the discharge mode.

[00181] For example, referring to Figure 1 b, the system 10A is illustrated including an optional thermal storage subsystem 120 that is provided in the gas flow path between the compressor and expander subsystem 100 and the accumulator 12. In this example, the gas conduit 22 that conveys the compressed gas between the compressed gas layer 14 and compressor and expander subsystem 100 includes an upper portion 22A that extends between the compressor and expander subsystem 100 and thermal storage subsystem 120, and a lower portion 22B that extends between thermal storage subsystem 120 and accumulator 12.

[00182] The thermal storage subsystem 120 may include any suitable type of thermal storage apparatus, including, for example latent and/or sensible storage apparatuses. The thermal storage apparatus(es) may be configured as single stage, two stage and/or multiple stage storage apparatus(es). Similarly, the thermal storage subsystem 120 may include one or more heat exchangers (to transfer thermal energy into and/or out of the thermal storage subsystem 120) and one or more storage apparatuses (including, for example storage reservoirs for holding thermal storage fluids and the like). Any of the thermal storage apparatuses may be either be separated from or proximate to their associated heat exchanger and may also incorporate the associated heat exchanger in a single compound apparatus (i.e. , in which the heat exchanger is integrated within the storage reservoir).

[00183] The thermal storage subsystem 120, or portions thereof, may be located in any suitable location, including above-ground, below ground, within the shaft 18, within the accumulator 12, and the like. Optionally, portions of the thermal storage subsystem 120 can be spaced apart from each other and located in different locations. For example, a heat exchanger used in a thermal storage subsystem 120 may be spaced apart from (but fluidly connected to) a corresponding storage apparatus. In such examples, the storage apparatus(es) may be located relatively deep within the ground while the heat exchanger may be relatively shallower and/or may be provided above ground to help facilitate access, etc.. While shown as a single schematic unit in this Figure 1 b, the thermal storage subsystem 120 may include one, two, three or more heat exchangers and other suitable equipment (such as storage reservoirs, pumps, flow control equipment and the like) that may be located close to each other or that may be located in different physical locations but that are fluidly connected using suitable conduits and the like. For example, the system 10A were to include two, three or more compressors and/or expanders then the thermal storage subsystem 120 may include two, three or more heat exchangers, and optionally may be configured so that at least one heat exchanger is provided for each compression and/or expansion stage.

[00184] In this example, the thermal storage subsystem 120 also employs multiple stages including, for example, multiple sensible and/or latent thermal storage stages such as stages having one or more phase change materials and/or pressurized water, or other heat transfer fluid arranged in a cascade. It will be noted that, if operating the system for partial storage/retrieval cycles, the sizes of the stages may be sized according to the time cycles of the phase change materials so that the phase changes, which take time, take place effectively within the required time cycles.

[00185] In general, as gas is compressed by the compressor and expander subsystem 100 during an accumulation cycle and is conveyed for storage towards accumulator 12, the heat of the compressed gas can be drawn out of the compressed gas and into the thermal storage subsystem 120 for sensible and/or latent heat storage. In this way, at least a portion of the heat energy is saved for future use instead of, for example being leached out of the compressed gas into water 20 or in the liquid layer 16, and accordingly substantially lost (i.e., non-recoverable by the system 10A). [00186] Similarly, during an expansion cycle as gas is released from accumulator 12 towards compressor and expander subsystem 100 it can optionally be passed through thermal storage subsystem 120 to re-absorb at least some of the stored heat energy on its way to the expander stage of the compressor and expander subsystem 100. Advantageously, the compressed gas, accordingly heated, can reach the compressor/expander subsystem 100 at a desired temperature (an expansion temperature — that is preferably warmer/higher than the accumulator temperature), and may be within about 10° C. and about 60° C. of the exit temperature in some examples, that may help enable the expander to operate within its relatively efficient operating temperature range(s), rather than having to operate outside of the range with cooler compressed gas.

[00187] In some embodiments, the thermal storage subsystem 120 may employ at least one phase change material, preferably multiple phase change materials, multiple stages and materials that may be selected according to the temperature rating allowing for the capture of the latent heat. Generally, phase change material heat can be useful for storing heat of approximately 150 degrees Celsius and higher. The material is fixed in location and the compressed air to be stored or expanded is flowed through the material. In embodiments using multiple cascading phase change materials, each different phase change material represents a storage stage, such that a first type of phase change material may change phase thereby storing the heat at between 200 and 250 degrees Celsius, a second type of phase change material may change phase thereby storing the heat at between 175 and 200 degree Celsius, and a third type of phase change material may change phase thereby storing the heat at between 150 and 175 degrees Celsius. One example of a phase change material that may be used with some embodiments of the system includes a eutectic mixture of sodium nitrate and potassium nitrate, or the HITEC® heat transfer salt manufactured by Coastal Chemical Co. of Houston, Tex.

[00188] In embodiments of the thermal storage subsystem 120 employing sensible heat storage, pressurized water, or any other suitable thermal storage fluid/liquid and/or coolant, may be employed as the sensible heat storage medium. Optionally, such systems may be configured so that the thermal storage liquid remains liquid while the system is in use and does not undergo a meaningful phase change (i.e. , does not boil to become a gas). For example, such thermal storage liquids (e.g., water) may be pressurized and maintained at an operating pressure that is sufficient to generally keep the water in its liquid phase during the heat absorption process as its temperature rises. Optionally, the pressurized water may be passed through a heat exchanger or series of heat exchangers to capture and return the heat to and from the gas stream that is exiting the accumulator, via conduit 22. Generally, sensible heat storage may be useful for storing heat of temperatures of 100 degrees Celsius and higher. Pressurizing the water in these systems may help facilitate heating the water to temperatures well above 100 degrees Celsius (thereby increasing its total energy storage capability) without boiling.

[00189] Optionally, in some embodiments, a thermal storage subsystem 120 may combine both latent and sensible heat storage stages and may use phase change materials with multiple stages or a single stage. Preferably, particularly for phase change materials, the number of stages through which air is conveyed during compression and expansion may be adjustable by controller 118. This may help the system 10 to adapt its thermal storage and release program to match desired and/or required operating conditions.

[00190] The flow through the replenishment conduit 58 can help ensure that a desired quantity of compensation liquid 20 may be maintained within shaft 18 as compensation liquid is flows into and out of the layer of compensation liquid 16, as excess compensation liquid 20 can be drained from and make-up compensation liquid can be supplied to the shaft 18. This arrangement can allow the pressures in the accumulator 12 and shaft 18 to at least partially, automatically re-balance as gas is forced into and released from the accumulator 12. That is, the pressure within the accumulator 12 may remain relatively constant (e.g., within about 5-10% of the desired accumulator operating pressure) while the system is in the charging mode, storage mode and/or discharging mode. Any given system may be configured to have a desired accumulator pressure, but generally the accumulator pressures may be at least about 10 bar and generally may be between about 10 and about 80 bar or more and may be between about 20 bar and about 70 bar, between about 40 and about 65 bar, and optionally between about 50 and about 60 bar.

[00191] For example, in the embodiment of Figure 1 , the accumulator pressure can be a function of both the accumulator depth 50 and the compensation liquid composition. If an accumulator pressure of about 60 bar is desired, the system 10A can be configured to use water (e.g., a liquid with a density of approximately 1000 kg/m³) as a compensation liquid if the accumulator depth is about 600m. However, if the accumulator depth 50 is less than 600m, such as being approximately 200 -250m, then using water as a compensation liquid could limit the accumulator pressure to only about 20 - 25bar. Different combinations of accumulator depth 50 and compensation liquid composition can be used to provide different accumulator pressures at different accumulator depths 50.

[00192] Preferably, the lower/inner end 64 of the liquid supply conduit 40 is positioned so that it is and remains submerged in the layer of compensation liquid 16 while the system 10 is in operational modes and is not in direct communication with the gas layer 14. In the illustrated example, the lower wall 15 is planar and is generally horizontal (parallel to plane 19, or optionally arranged to have a maximum grade of between about .01 % to about 1 %, and optionally between about 0.5% and about 1 %, from horizontal), and the lower/inner end 64 of the liquid supply conduit 40 is placed close to the lower wall 15. If the lower wall 15 is not flat or not generally horizontal, the lower/inner end 64 of the liquid supply conduit 40 is preferably located in a low point of the accumulator 12 to help reduce the chances of the lower/inner end 64 being exposed to the gas layer 14.

[00193] Similarly, to help facilitate extraction of gas from the gas layer when in a discharging mode, the lower end 62 of the gas conduit 22 is preferably located close to the upper wall 13, or if the upper wall 13 is not flat or generally horizontal at a high point in the interior 23 of the accumulator 12. This may help reduce material trapping of any gas in the accumulator 12. For example, if the upper wall 13 were oriented on a grade, the point at which gas conduit 22 interfaces with the gas layer (i.e., its lower end 62) should be at a high point in the accumulator 12, to help avoid significant trapping of gas.

[00194] Preferably, as will be described, the pressure at which the quantity of compensation liquid 20 bears against bulkhead 24 and can be maintained so that magnitude of the counter force 46 is as equal, or nearly equal, to the magnitude of the internal accumulator force 41 exerted by the compressed gas in compressed gas layer 14 stored in accumulator 12. In the illustrated embodiment, operating system 10 so as to maintain a pressure differential (i.e. the difference between gas pressure inside the accumulator 12 and the hydrostatic pressure at the lower end 43 of the shaft 18) within a threshold amount - an amount preferably between 0 and 4 Bar, such as 2 Bar - the resulting net, partition force acting on the bulkhead 24 (i.e. the difference between the internal accumulator force 41 and the counter force 46) can be maintained below a pre-determined threshold partition force limit.

[00195] In this embodiment, a gas conduit 22 is provided to convey compressed air between the compressed gas layer 14 and the compressor and expander subsystem 100, which can convert compressed air energy to and from electricity. Similarly, a liquid conduit 40 is configured to convey water between the layer of compensation liquid 16 and the compensation liquid 20 in shaft 18. Each conduit 22 and 40 may be formed from any suitable material, including metal, plastic and the like. [00196] Figure 2 is a schematic view of components of one example of a compressor and expander subsystem 100 for the compressed gas energy storage system 10 described herein. In this example, the compressor and expander subsystem 100 includes a compressor 112 of single or multiple stages, driven by a motor 110 that is powered, in one alternative, using electricity from a power grid G or by a renewable power source or the like, and optionally controlled using a suitable controller 118. Compressor 112 is driven by motor 110 during a compression mode of operation, and draws in atmospheric air A, compresses the air, and forces it down into gas conduit 22 for storage in accumulator 12. Compressor and expander subsystem 100 also includes an expander 116 driven by compressed air exiting from gas conduit 22 during an expansion mode of operation and, in turn, driving generator 114 to generate electricity. After driving the expander 116, the expanded air is conveyed for exit to the atmosphere A. While shown as separate apparatuses, the compressor 112 and expander 116 may be part of a common apparatus, as can a hybrid motor/generator apparatus. Optionally, the motor and generator may be provided in a single machine.

[00197] Air entering or leaving compressor and expander subsystem 100 may be conditioned prior to its entry or exit. For example, air exiting or entering compressor/ expander subsystem 100 may be heated and/or cooled to reduce undesirable environmental impacts or to cause the air to be at a temperature suited for an efficient operating range of a particular stage of compressor 112 or expander 116. For example, air (or other gas being used) exiting a given stage of a compressor 112 may be cooled prior to entering a subsequent compressor stage and/or the accumulator 12, and/or the air may be warmed prior to entering a given stage of an expander 116 and may be warmed between expander stages in systems that include two or more expander stages arranged in series.

[00198] Controller 118 operates compressor and expander subsystem 100 so as to switch between compression and expansion modes as required, including operating valves for preventing or enabling release of compressed air from gas conduit 22 on demand.

[00199] Referring to Figures 5 and 6, a more detailed schematic representation of the system 10A showing one example of a configuration for the compressor and expander subsystem 100 and thermal storage subsystem 120.

[00200] In this schematic the compressor and expander subsystem 100 for a compressed gas energy storage system 10, with multiple compression stages and each is associated with a respective heat exchanger of a thermal storage subsystem 120. In particular, when operating in charging mode (as shown in Figure 5), incoming air from the ambient A is conveyed first, optionally via a heat exchanger to modify the temperature of the incoming air, into a first compressor 112a driven by motor 110 for a first stage of compression. In this example, the thermal storage subsystem 120 includes three exchangers 635a-653c that can be provided between the different compression stages (other arrangements are possible in other systems). In this example, following the first stage of compression, air A is then conveyed through a first heat exchanger 635a of a thermal storage subsystem 120 to transfer heat from the air A into the thermal storage liquid that is drawn from a cold thermal storage reservoir 637, using a suitable pump 639, and pumped through the heat exchanger 653a where it is heated and collected for storage in the hot thermal storage reservoir 641. The air exiting heat exchanger 635a is thereby to be conditioned to be air A’ which is then conveyed into compressor 112b driven by motor 110b for a second stage of compression. Following the second stage of compression, air A’ is then conveyed through any additional heat exchangers of the thermal storage subsystem 120 such as second heat exchanger 635b of thermal storage subsystem 120 to transfer heat from the air A” into the thermal storage liquid. A last heat exchanger, in this example, of the thermal storage subsystem 120 is represented in this example as heat exchanger 635c transfer heats from the air A’” into the thermal storage liquid. Following this third stage of compression and thermal storage, the air A’” can be conveyed into accumulator 12 as has been described above with respect to other embodiments.

[00201 ] In some arrangements, the air A’” may exit the heat exchanger 635c at a temperature that is higher than the expecting operating temperature within the accumulator 12. For example, the air A’” may be at an exit temperature that is between about 50 deg. C and about 90 deg. C, or more, and may be at least 50, 55, 60, 65, 70, 75, 80, 85 or 90 deg. C in some embodiments.

[00202] In contrast, the operating temperature within the accumulator (e.g. the temperature of the gas layer and compensation liquid layers within the accumulator) may be between about 15 deg. C and 50 deg. C, and may be at least 15, 20, 25, 30, 35, 40, 45 or 50 deg. C in some embodiments (for example, depending on the depth 50 of the accumulator 12) In such configurations where there is a difference between the accumulator operating temperature and the gas exit temperature, it may be possible to extract some additional thermal energy from the high pressure, compressed air A’” that is exiting the accumulator and transfer at least some of that thermal energy into the compensation brine that is being stored outside the accumulator 12, such as being in the compensation liquid reservoir 150. This can allow excess system heat that might otherwise be wasted or use for other purposes to instead be used to help keep the compensation brine in the reservoir 150 at a storage temperature that is within about 25%, 20%, 15%, 10%, 5%, 2% of the operating temperature within the accumulator 12 and optionally may be used to help keep the compensation brine in the reservoir 150 at a storage temperature that is about equal to or greater than the operating temperature of the accumulator 12. To help provide this heat transfer the embodiment of Figures 5 and 6 utilizes a brine heater assembly 643 that includes , a gas/brine heat exchanger. In this example the brine heater assembly 643 is understood to include a gas/brine heat exchanger that is illustrated schematically as being in the gas flow path between the compressor and expander subsystem and the accumulator 12. In this position thermal energy can be extracted from the compressed gas A’” exiting the gas compressor and expander subsystem at its exit temperature, and the thermal energy that that is extracted is at least a portion of the heat source and is transferred to the compensation brine. That is the gas/brine heat exchanger of the brine heater assembly 643 is in the path of the air A’” to transfer heat from the air A’” into the reservoir 150 while the system 10A is in use.

[00203] In some cases, a temperature sensor TS measures a present value for the operating temperature within the accumulator 12. The controller 118 can be communicably linked in data communication with the temperature sensor TS to obtain the present temperature within the accumulator 12 (which in some cases is a salt cavern), and the controller 118 controls one or more devices in the compressor and expander subsystem 100 to transfer heat to a brine solution stored in a brine solution source/sink. In some case, the brine solution in the brine solution source/sink is heated to a storage temperature that is equal to or greater than the present operating temperature of the layer of brine solution in the accumulator 12.

[00204] Optionally, the compensation brine that is exiting the accumulator 12 via the shaft 18 may already be at, or at least approximately at the operating temperature - such as being at about 50 deg. C in some examples - when it reaches the gas/brine heat exchanger of the brine heater assembly 643. If the system is configured so that the air A’” is at a higher temperature than the operating temperature, such as being at about 90 deg. C in the illustrated example, then the compensation brine heater assembly can be operated so that a flow of compensation brine exiting the gas/brine heat exchanger of the brine heater assembly 643 may be further heated to a brine exit temperature that is higher than the operating temperature (but lower than the exit temperature of the air leaving exchanger 635c). For example, the compensation brine may be heated to a brine exit temperature that is at least 50, 55, 60, 65, 70, 7570 deg. C or more and in some embodiments may be about 70 deg. C. The compensation brine can then enter the reservoir 150 at the elevated, brine exit temperature for storage. While the compensation brine is held in the reservoir 150 after the charging cycle is complete it may slowly decrease in temperature but may still be at or above the operating temperature when the system 10A is operated in its discharging cycle. If the temperature of the compensation brine in the reservoir 150 were to drop below the operating temperature before the system 10A is converted to its discharge mode, then additional heat can be added to the reservoir 150 using any suitable heater. In this example, there is heat transfer between the compressed gas stream A’” and the compensation brine to help heat the compensation brine.

[00205] To help retain heat within the compensation brine, and to help limit heat transfer between the compensation brine and the surrounding environment the reservoir 150 may be insulated with suitable thermal insulating materials.

[00206] The brine heater assembly 643 may also include an externally powered heater, or a separate heater may be provided to help condition the brine to its desired temperatures. This can include a fuel-fired heating system, a solar heating system, an electrical heater, and the like which are also schematically illustrated as part of the brine heater assembly 643.

[00207] Preferably, in the examples described herein, the compensation brine that is held outside the accumulator is an aqueous solution containing dissolved salt (preferably the same salt that forms the salt layer(s) in the accumulator) at a preconditioned salt concentration that is within about 25% of a salt saturation limit of the aqueous solution at the operating temperature. That is, a given compensation liquid is understood to have a saturation limit/concentration of salt for a given operating temperature - which is understood to be the salt saturation limit of the liquid at a given temperature. When the compensation brine has reached its salt saturation limit it may tend to absorb less salt from the cavern walls, than a similar liquid at the same temperature that has not yet reached its salt saturation limit. For the purposes of the discussion herein it is understood that it may be preferable, in some embodiments, for the compensation brine to be configured so that its salt concentration before it enters the accumulator (e.g., its preconditioned salt concentration) approaches or meets the salt saturation limit at the expected operating temperature of the accumulator, which may help reduce the dissolving of salt from the cavern walls. In this arrangement, the compensation brine in the compensation liquid reservoir is preconditioned to have a desired preconditioned salt concentration that preferably within about 25% of a salt saturation limit of the aqueous solution at the operating temperature. The system can then be operated in the discharging mode in which the compressor and expander subsystem extracts gas from the layer of compressed gas 14 as a corresponding volume of the compensation brine flows into the layer of compensation brine 16 via the compensation brine flow path and into contact with the salt layer within the accumulator. By configuring the compensation brine salt concentration as described herein it is believed that an amount of salt from the salt layer within the accumulator 12 that is dissolved into the incoming compensation brine at its preconditioned salt concentration will be less than an amount of salt that would otherwise have be dissolved from the cavern wall into an incoming flow of compensation brine having a salt concentration that is lower than the preconditioned salt concentration.

[00208] Referring to Figure 6, when the system 10A is operated in its discharge mode/cycle, i.e. , during an expansion (release) phase, compressed air A’” is released from accumulator 12 is first conveyed through the heat exchanger 635c to transfer heat from the thermal storage liquid into the air A’” being conveyed thereby to be conditioned as air A”. Air A” is then presented to a first expander 116a which can drive generator 114. Following the first stage of expansion, air A” is then conveyed through the exchanger 635b to transfer stored heat from the thermal storage liquid into the air being conveyed thereby to be conditioned to be air A’, which is then conveyed into expander 116b driving generator 114 for a second stage of expansion. Following the second stage of expansion, air A’ is then conveyed through heat exchanger 635a which transfers stored heat into compressed air being conveyed through expansion stage 635x thereby to be conditioned to be air A, which can be conveyed to the ambient atmosphere as has been described herein. The heat stored in the thermal storage subsystem 120 may have been stored from incoming air being compressed during a storage phase of the compressed gas energy storage system, but alternatively or in some combination may have been stored during operation of another aspect or subsystem of the compressed gas energy storage system, such as during temperature regulation of another subsystem, or during an electrical heating process. It should be noted that, while three stages of expansion with respective thermal storage stages are shown in Figure 6, a compressed gas energy storage system according to this embodiment of the invention may have only two, or more than three stages of expansion with respective thermal storage stages. Furthermore, in alternative embodiments a given stage of expansion is not necessarily always preceded in the processing chain by a stage of release of heat from thermal storage.

[00209] Optionally, as shown in this example, the system 10A can also be configured so that heat can be added to the reservoir 150 during the discharge cycle. Referring to Figure 6, in this example the system 10A is configured to include a liquid/brine heat exchanger 645 that is in communication with the reservoir 150 and the thermal storage liquid that is circulating through the thermal storage subsystem 120. In this arrangement, thermal storage liquid (which may be pressurized water) may be leaving the cold storage reservoir 637 at a temperature that is higher than the operating temperature within the accumulator 12. In that arrangement, the thermal storage liquid can transfer heat into the compensation brine during the discharge cycle. The liquid/brine heat exchanger 645 is, in this example, located between the cold storage reservoir 637 and the heat exchanger 635c, but could be in other locations, such as between exchangers 635c and 635b, or between exchangers 635b and 635a, or other suitable locations. This may also help moderate the temperature of the thermal storage liquid so that it arrives at exchanger 635c at the desired inlet temperature. In this arrangement, the system 10A is configured so that waste heat would be available to help warm the compensation brine through all models of operation: standby (e.g., storage), charge cycle and discharge cycle. The heat can be sourced from waste heat in the both the thermal storage liquid (i.e. , from the thermal storage subsystem) during discharge cycles as well as from the compressed gas stream during charge cycles.

[00210] Optionally, the heat stored in the thermal storage subsystem 120 in the charging mode may be stored entirely for re-incorporating into air being released when the compressed gas energy storage is operated in a discharging mode, but may in some capacity or quantity be employed for some other purposes of the compressed gas energy storage system such as for helping to regulate temperature of another subsystem, or to operate pneumatic tools and instruments, amongst other uses. It should be noted that, while three stages of compression with respective thermal storage stages are shown in Figure 5, a compressed gas energy storage system according to this embodiment of the invention may have only two, or more than three stages of compression with respective thermal storage stages. Furthermore, in alternative embodiments a given stage of compression is not necessarily always followed by a stage of thermal storage. Furthermore, in alternative embodiments, incoming air that has not yet been compressed in the compressed gas energy storage system may first pass through a thermal storage subsystem or stage thereof to reduce or increase its heat content prior to entering a compressor, rather than a heat exchanger that might dissipate the heat from the system.

[00211] In some other cases, a temperature sensor TS is also positioned in the compensation reservoir to measure a temperature of the compensation brine stored therein. [00212] In some cases, heat exchangers are used to exchange heat between a brine stream and waste heat streams from a compressed gas energy storage system, either through heated air (e.g., using a trim cooler), or through a cooling fluid stream, or either through a thermal fluid on the return (e.g., during discharge process) or the exit (e.g., during charge process) from the cool thermal fluid storage tank, or a combination thereof.

[00213] Figure 3 is a schematic representation of another example of a compressed gas energy storage system 10B. The compressed gas energy storage system 10B is analogous to the compressed gas energy storage system 10A, and like features are identified using like reference characters. In this example, the partition separating the interior of the accumulator 12 from the compensation shaft 18 at includes a projection 200A, identified using cross-hatching in Figure 3, that is formed from generally the same material as the surrounding ground 200. In this example, the system 10B need not include a separately fabricated bulkhead 24 as shown in other embodiments. To help provide liquid communication between the interior of the shaft 18 and the layer of compensation liquid 16, a liquid supply conduit 40 can be provided to extend through the projection 200A or, as illustrated, at least some of the liquid supply conduit 40 can be provided by a flow channel that passes beneath the projection 200A and fluidly connects the shaft 18 to the layer of compensation liquid 16, and in ends 64 and 66 of the liquid supply conduit 40 can be the open ends of the passage.

[00214] Optionally, in such embodiments the gas supply conduit 22 may be arranged to pass through the partition/ projection 200A as illustrated in Figure 3. In this arrangement, the conduit 22 can be configured so that its end 62 is positioned toward the upper side of the accumulator 12 to help prevent the layer of compensation liquid 16 reaching the end 62. Alternatively, the gas supply conduit 22 need not pass through the partition, as schematically illustrated using dashed lines for alternative conduit 22.

[00215] A thermal storage subsystem, including any can be used in combination with an accumulator 12 having this arrangement. Some examples of suitable thermal storage subsystem are described in PCT/CA2018/050112 and PCT/CA2018/050282, which are incorporated herein by reference.

[00216] When the accumulator 12 is in use, at least one of the pressurized gas layer 14 and the layer of compensation liquid 16, or both, may contact and exert pressure on the inner surface 29 of the partition 200A, which will result in a generally outwardly, (rightward in this embodiment) acting internal accumulator force, represented by arrow 41 in Figure 3, acting on the partition 200A. The magnitude of the internal accumulator force 41 is dependent on the pressure of the gas 14/liquid 16 and the cross-sectional area of the inner surface 29. For a given inner surface 29 area, the magnitude of the internal accumulator force 41 may vary generally proportionally with the pressure of the gas 14 and/or compensation liquid 16.

[00217] Preferably, an inwardly, (leftward in this embodiment) acting force can be applied to the outer surface 31 of the partition 200A, via the hydrostatic pressure of the compensation liquid, to help offset and/or counterbalance the internal accumulator force 41. Applying a hydrostatic counter force of this nature may help reduce the net partition force acting on the partition 200A while the system 10 is in use.

[00218] In the present embodiment, the system 10 includes a shaft 18 having a lower end 43 that is in communication with the opening 27 in the lower wall 15 of the accumulator 12, and an upper end 48 that is spaced apart from the lower end 43 by the shaft height (which corresponds to the accumulator depth 50 in this example). At least one sidewall 52 extends from the lower end 43 to the upper end 48, and at least partially defines a shaft interior 54 having a volume. In this embodiment, the shaft 18 is generally linear and extends along a generally vertical shaft axis, but may have other configurations, such as a linear or helical decline, in other embodiments. The upper end 48 of the shaft 18 may be open to the atmosphere A, as shown, or may be capped, enclosed or otherwise sealed. In this embodiment, shaft 18 is generally cylindrical with a diameter of about 3 metres, and in other embodiments the diameter may be between about 2m and about 15m or more, or may be between about 5m and 12m, or between about 2m and about 5m. In such arrangements, the interior 52 of the shaft 18 may be able to accommodate about 1 ,000 - 150,000 m3 of water or other suitable compensation liquid.

[00219] Figure 4 is a schematic illustration of another example of a hydrostatically compensated compresses gas energy storage system 10C, which is analogous to system 10A and like features are illustrated using like reference characters.

[00220] What has been described above has been intended to be illustrative of the invention and non-limiting and it will be understood by persons skilled in the art that other variants and modifications may be made without departing from the scope of the invention as defined in the claims appended hereto.

Claims

What is claimed is:

1. A hydrostatically compensated compressed gas energy storage system comprising: an accumulator disposed underground and comprising an interior for containing a layer of compressed gas above a layer of compensation brine at an operating temperature, the layer of compressed gas being at an accumulator pressure that is at least about 20 bar, the interior being at least partially bounded by accumulator walls that comprise a salt layer that is exposed to the layer of compensation brine; a compressor and expander subsystem in fluid communication with the accumulator interior via a gas flow path and configured to selectably convey compressed gas into the accumulator and to extract gas from the accumulator; a compensation liquid reservoir spaced apart from the accumulator and containing a quantity of the compensation brine that is an aqueous solution containing dissolved salt at a preconditioned salt concentration that is within about 25% of a salt saturation limit of the aqueous solution at the operating temperature; and a compensation brine flow path extending between the compensation liquid reservoir and the layer of compensation brine within the accumulator; the system being operable in at least a discharging mode in which the compressor and expander subsystem extracts gas from the layer of compressed gas as a corresponding volume of the compensation brine flows into the layer of compensation brine via the compensation brine flow path and into contact with the salt layer within the accumulator, whereby an amount of salt from the salt layer that is dissolved into the incoming compensation brine at the preconditioned salt concentration is less than an amount of salt that would be dissolved into an incoming flow of compensation brine having a salt concentration that is lower than the preconditioned salt concentration and thereby reducing an amount of accumulator wall dissolution and cavern growth while maintaining the layer of compressed gas at substantially the accumulator pressure during the discharging mode.

2. The system of claim 1 , wherein the system also is operable in a charging mode in which the compressor and expander subsystem conveys gas into the layer of compressed gas thereby displacing a corresponding volume of the compensation brine from the layer of compensation brine within the accumulator out of the accumulator via the compensation brine flow path thereby maintaining the layer of compressed gas at substantially the accumulator pressure during the charging mode.

3. The system of claim 2, wherein a salt concentration of the volume of the compensation brine removed from the compensation brine layer is equal to or less than the preconditioned salt concentration.

4. The system of claim 3, wherein the salt concentration of the volume of the compensation brine removed from the compensation brine layer is equal to or greater than the salt saturation limit of the aqueous solution at the operating temperature.

5. The system of claim 1 , wherein a salt concentration of the layer of compensation brine within the accumulator is equal to or greater than the salt saturation limit of the aqueous solution at the operating temperature.

6. The system of any one of claims 1 to 5, wherein the compensation brine contained within the compensation liquid reservoir is at a storage temperature that is within 25% of the operating temperature.

7. The system of claim 6, wherein the storage temperature is within 10% of the operating temperature.

8. The system of claim 6, wherein the storage temperature is substantially equal to or greater than the operating temperature.

9. The system of claim 6, further comprising a brine heater assembly that is operable to heat the compensation brine contained to within the compensation liquid reservoir to the storage temperature.

10. The system of claim 6, further comprising a brine heater assembly that is operable to heat the compensation brine to a brine exit temperature that is greater than the storage temperature before the compensation brine enters the compensation liquid reservoir, and preferably wherein the brine exit temperature is at least 55 deg. C, and preferably is at least 60 deg. C or is at least 70 deg. C

11. The system of claim 6, further comprising a brine heater assembly that is disposed in the compensation brine flow path upstream from the compensation liquid reservoir and is operable to heat the compensation brine contained within the compensation liquid reservoir to a storage temperature that is substantially equal to or greater than the operating temperature.

12. The system of any one of claims 10-11 , wherein the brine heater assembly comprises a gas/brine heat exchanger whereby thermal energy from a heat source is used to heat the compensation brine to be about the operating temperature or higher.

13. The system of claim 12, wherein the heat source comprises waste heat produced by the compressor and expander subsystem.

14. The system of claim 13, further comprising a thermal storage subsystem provided in fluid communication with the gas flow path between the compressor and expander subsystem and the accumulator, whereby the thermal energy is extracted from the compressed gas exiting the gas compressor and expander subsystem at an exit temperature, and the thermal energy that that is extracted is at least a portion of the heat source and is transferred to the compensation brine.

15. The system of claim 12, wherein the gas compressor and expander subsystem comprises a plurality of compression stages, each one of the plurality of compression stages comprising a heat exchanger, and at least one of the heat exchangers from amongst the plurality of compression stages is fluidly connected to the gas/brine heat exchanger.

16. The system of claim 15, wherein each of the heat exchangers in the plurality of compression stages are fluidly connected in series, and wherein, in a compression operation, ambient air is received into a first heat exchanger in a first compression stage and is conveyed through the plurality of compression stages in series including into a last heat exchanger in a last compression stage; and heated air exiting the last heat exchanger conveys the thermal energy to the gas/brine heat exchanger.

17. The system of claim 15, wherein the plurality of compression stages comprise a first compression stage, a second compression stage, and a third compression stage, and wherein: i) in a first compression stage, incoming air A from ambient is conveyed into a first compressor driven by a motor of the first compression stage, and the air A exiting the first compressor is then conveyed through a first heat exchanger of the thermal storage subsystem to transfer heat into a thermal storage liquid that is drawn from a first thermal storage reservoir; ii) in a second compression stage, air exiting the first heat exchanger, which is conditioned to be air A’, is then conveyed into a second compressor driven by the motor of the second compression stage, and the air A’ exiting the second compressor is then conveyed through a second heat exchanger of the thermal storage subsystem to transfer heat into the thermal storage liquid; iii) in a third compression stage, air exiting the second heat exchanger, which is conditioned to be air A”, is then conveyed into a third compressor driven by the motor of the third compression stage, and the air A” exiting the second compressor is then conveyed through a third heat exchanger of the thermal storage subsystem to transfer heat into the thermal storage liquid; and iv) air exiting the third heat exchanger, which is conditioned to be air A’”, is then conveyed to the gas/brine heat exchanger to transfer heat from the air A’” to the brine solution in the brine solution source/sink.

18. The compressed gas energy storage system of claim 17, wherein a temperature of the air A’” is higher than the operating temperature.

19. The compressed gas energy storage system of claim 18, wherein a temperature of the air A’” is greater than 50 deg. C and the operating temperature is 50 deg. C or less.

20. The compressed gas energy storage system of claim 17, wherein a temperature of the air A’” is between about 50 deg. C and 90 deg. C, and the operating temperature is between about 15 deg. C and 50 deg. C.

21. The system of claim 12 wherein the heat source comprises an externally powered heater system.

22. The system of claim 12, wherein the externally powered heater system comprises a fuel-fired heater.

23. The system of claim 12, wherein the externally powered heater system comprises a solar heater system.

24. The system of any one of claims 1 to 23, wherein the preconditioned salt concentration is within about 10% of the salt saturation limit of the aqueous solution at the operating temperature.

25. The system of any one of claims 1 to 24, wherein the preconditioned salt concentration is within about 2% of the salt saturation limit of the aqueous solution at the operating temperature.

26. The system of any one of claims 1 to 25, wherein the preconditioned salt concentration is substantially equal to or greater than the salt saturation limit of the aqueous solution at the operating temperature.

27. The system of any one of claims 1 to 26, wherein the compensation liquid reservoir comprises a thermal insulating material that at least partially encapsulates the compensation brine stored in the compensation liquid reservoir.

28. The system of any one of claims 1 to 27, further comprising a salt dispensing system configured to dispense salt into the compensation liquid reservoir.

29. The system of any one of claims 1 to 28, further comprising an agitating system in the compensation liquid reservoir to facilitate dissolving salt in the compensation liquid reservoir.

30. The system of claim 29, wherein the agitating system comprises at least one of: a mechanical mixing structure, a sparger, and a bubbler.

31. A method for conveying brine solution in a compressed gas energy storage system, the method comprising: a) providing a layer of compensation brine stored below a layer of compressed gas within an accumulator of the compressed gas energy storage system at an operating temperature, the accumulator being at least partially bounded by accumulator walls that comprise a salt layer that is exposed to the layer of compensation brine; b) maintaining a compensation brine stored in a compensation liquid reservoir at a storage temperature that is within 25% of the operating temperature and so that the compensation brine is an aqueous solution containing dissolved salt at a preconditioned salt concentration that is within about 25% of a salt saturation limit of the aqueous solution at the operating temperature; and c) conveying the compensation brine having the precondition salt concentration to the accumulator.

32. The method of claim 31 , wherein the conveying of the compensation brine at the precondition salt concentration to the accumulator occurs when the compressed gas energy storage system is in a discharging mode in which a compressor and expander subsystem extracts gas from the layer of compressed gas as a corresponding volume of the compensation brine from the compensation liquid reservoir flows into the layer of compensation brine, via a compensation brine flow path, and into contact with the salt layer within the accumulator, whereby an amount of salt from the salt layer that is dissolved into the incoming compensation brine at the preconditioned salt concentration is less than an amount of salt that would be dissolved into an incoming flow of compensation brine having a salt concentration that is lower than the preconditioned salt concentration and thereby reducing an amount of accumulator wall dissolution and cavern growth while maintaining the layer of compressed gas at substantially the accumulator pressure during the discharging mode.

33. The method of claim 31 or 32, wherein the accumulator is disposed underground and the layer of compressed gas is at an accumulator pressure that is at least about 20 bar.

34. The method of any one of claims 31 to 33, wherein the compressed gas energy storage system is operated in a charging mode in which the compressor and expander subsystem conveys gas into the layer of compressed gas thereby displacing a corresponding volume of the compensation brine from the layer of compensation brine within the accumulator out of the accumulator via the compensation brine flow path thereby maintaining the layer of compressed gas at substantially the accumulator pressure during the charging mode.

35. The method of claim 34, wherein a salt concentration of the volume of the compensation brine removed from the compensation brine layer is equal to or less than the preconditioned salt concentration.

36. The method of claim 35, wherein the salt concentration of the volume of the compensation brine removed from the compensation brine layer is equal to or greater than the salt saturation limit of the aqueous solution at the operating temperature.

37. The method of claim 36, wherein a salt concentration of the layer of compensation brine within the accumulator is equal to or greater than the salt saturation limit of the aqueous solution at the operating temperature.

38. The method of claim 37, further comprising heating, using a brine heater assembly, the compensation brine contained within the compensation liquid reservoir to a storage temperature that is within 25% of the operating temperature

39. The method of claim 31 , further comprising heating, using a brine heater assembly, the compensation brine contained within the compensation liquid reservoir to a storage temperature that is within 10% of the operating temperature.

40. The method of claim 31 , further comprising heating, using a brine heater assembly, the compensation brine contained within the compensation liquid reservoir to a storage temperature that is substantially equal to or greater than the operating temperature.

41. The method of any one of claims 38-40, wherein the brine heater assembly comprises a gas/brine heat exchanger whereby thermal energy from a heat source is used to heat the compensation brine to be about the operating temperature or higher.

42. The method of claim 41 , wherein the heat source comprises waste heat produced by a compressor and expander subsystem of the compressed gas energy storage system.

43. The method of claim 2, further comprising a thermal storage subsystem provided in fluid communication with the gas flow path between the compressor and expander subsystem and the accumulator, whereby the thermal energy is extracted from the compressed gas exiting the gas compressor and expander subsystem at an exit temperature, and the thermal energy that that is extracted is at least a portion of the heat source and is transferred to the compensation brine.

44. The method of claim 43, wherein the gas compressor and expander subsystem comprises a plurality of compression stages, each one of the plurality of compression stages comprising a heat exchanger, and at least one of the heat exchangers from amongst the plurality of compression stages is fluidly connected to the gas/brine heat exchanger.

45. The method of claim 44, wherein each of the heat exchangers in the plurality of compression stages are fluidly connected in series, and wherein, in a compression operation, ambient air is received into a first heat exchanger in a first compression stage and is conveyed through the plurality of compression stages in series including into a last heat exchanger in a last compression stage; and heated air exiting the last heat exchanger conveys the thermal energy to the gas/brine heat exchanger.

46. The method of claim 44, wherein the plurality of compression stages comprise a first compression stage, a second compression stage, and a third compression stage, and wherein: i) in a first compression stage, incoming air A from ambient is conveyed into a first compressor driven by a motor of the first compression stage, and the air A exiting the first compressor is then conveyed through a first heat exchanger of the thermal storage subsystem to transfer heat into a thermal storage liquid that is drawn from a first thermal storage reservoir; ii) in a second compression stage, air exiting the first heat exchanger, which is conditioned to be air A’, is then conveyed into a second compressor driven by the motor of the second compression stage, and the air A’ exiting the second compressor is then conveyed through a second heat exchanger of the thermal storage subsystem to transfer heat into the thermal storage liquid; iii) in a third compression stage, air exiting the second heat exchanger, which is conditioned to be air A”, is then conveyed into a third compressor driven by the motor of the third compression stage, and the air A” exiting the second compressor is then conveyed through a third heat exchanger of the thermal storage subsystem to transfer heat into the thermal storage liquid; and iv) air exiting the third heat exchanger, which is conditioned to be air A’”, is then conveyed to the gas/brine heat exchanger to transfer heat from the air A’” to the brine solution in the brine solution source/sink.

47. The method of claim 46, wherein a temperature of the air A’” is higher than the operating temperature.

48. The method of claim 47, wherein a temperature of the air A’” is greater than 50 deg. C and the operating temperature is 50 deg. C or less.

49. The method of claim 48, wherein a temperature of the air A’” is between about 50 deg. C and 90 deg. C, and the operating temperature is between about 15 deg. C and 50 deg. C.

50. The method of claim 41 , wherein the heat source comprises an externally powered heater system.

51. The method of claim 41 , wherein the externally powered heater system comprises is a fuel-fired heater.

52. The method of claim 41 , wherein the externally powered heater system comprises a solar heater system.

53. The method of any one of claims 31 to 52, wherein the preconditioned salt concentration is within about 10% of the salt saturation limit of the aqueous solution at the operating temperature.

54. The method of any one of claims 31 to 52, wherein the preconditioned salt concentration is within about 2% of the salt saturation limit of the aqueous solution at the operating temperature.

55. The method of any one of claims 31 to 52, wherein the preconditioned salt concentration is substantially equal to or greater than the salt saturation limit of the aqueous solution at the operating temperature.

56. The method of claim any one of claims 31 to 52, wherein the compensation liquid reservoir comprises a thermal insulating material that at least partially encapsulates the compensation brine stored in the compensation liquid reservoir.

57. The method of any one of claims 31 to 56, further comprising heating the compensation brine to the storage temperature using a brine heater assembly that is configured to heat the compensation brine while it is contained within the compensation liquid reservoir.

58. The method of any one of claims 31 to 56, further comprising pre-heating an incoming stream of the compensation brine using a brine heater assembly to a brine exit temperature that is greater than the storage temperature and then conveying the compensation brine into the compensation liquid reservoir.

59. The method of claim 58, wherein the brine exit temperature is at least 55 deg. C, and preferably is at least 60 deg. C or is at least 70 deg. C.

60. A compressed gas energy system comprising a brine compensated salt cavern, wherein the brine in a surface compensation liquid reservoir, which is fluidly connectable to the brine compensated salt cavern, is maintained at a temperature equal or greater to the cavern temperature when in the surface reservoir.

61. The compressed gas energy system of claim 60, wherein heat added to the brine in the surface reservoir is at least partially transferred from a compressed gas energy system process that comprises compressing air for storage in the brine compensated salt cavern and expanding air for release from the brine compensated salt cavern.