Fuel assisted compressed gas energy storage system

Abstract

A compressed gas energy storage system includes a compression train, an accumulator, and an expansion train. The system also includes a combustor configured to transfer heat generated by combusting a fuel gas to compressed gas received from the accumulator or a compressor in the compression train. The system is selectively operatable in one of: a first mode of operation, in which compressed gas is released from the accumulator to the expansion train for expansion to generate a first level of electrical power; and at least one other mode of operation in which a heated compressed gas stream is directed to an expander for expansion to generate a second level of electrical power. In some systems, a dedicated expander is provided to receive and expand heated compressed gas exiting the combustor to generate electrical power.

Description

FUEL ASSISTED COMPRESSED GAS ENERGY STORAGE SYSTEMCROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application claims priority to United States Provisional Patent Application Serial No. 63 / 511533, filed June 30, 2023 and entitled A HYDROGEN ASSISTED AND HYDROSTATICALLY COMPENSATED COMPRESSED GAS ENERGY STORAGE SYSTEM, the entirety of which is incorporated by reference herein.FIELD OF THE DISCLOSURE

[0002] The present disclosure relates generally to compressed gas energy storage and power generation systems, and more particularly to a compressed gas energy storage system such as, for example, one including a hydrostatically compensated, substantially isobaric compressed air energy storage accumulator located underground, and a fuel assisted power generation system, the use thereof, as well as a method of storing compressed gas.BACKGROUND

[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 returning it to the grid upon demand. Furthermore, 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.SUMMARY

[0006] 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 moreinventions 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.

[0007] In accordance with one broad aspect, there is provided a compressed gas energy storage system comprising: a compression train comprising one or more compressors, the compression train being configured to draw in and compress ambient air to generate compressed gas; an accumulator positioned downstream of the compression train and configured to selectively receive compressed gas from the compression train for storage and to selectively release stored compressed gas for power generation; an expansion train positioned downstream of the accumulator, the expansion train comprising one or more expanders, the expansion train being configured to receive and expand compressed gas from the accumulator to generate electrical power; a combustor configured to receive compressed gas from at least one of the accumulator and at least one of the one or more compressors of the compression train, and transfer heat generated by combusting a fuel to the received compressed gas; and a dedicated expander configured to receive and expand heated compressed gas exiting the combustor to generate electrical power; wherein the system is selectively operatable in one of: a first mode of operation, in which compressed gas is released from the accumulator to the expansion train to generate a first level of electrical power; and at least one of: a second mode of operation, in which ambient air is drawn in and compressed by the at least one of the one or more compressors of the compression train, directed to the combustor as a compressed gas stream, heated by the combustor to generate a heated compressed gas stream, and the heated compressed gas stream is directed to the dedicated expander to generate a second level of electrical power, and a third mode of operation, in which compressed gas is released from the accumulator to the combustor as a compressed gas stream, heated by the combustor to generate a heated compressed gas stream, and the heated compressed gas stream is directed to the dedicated expander to generate a third level of electrical power.

[0008] In some embodiments, the system is selectively operable in the first mode of operation and the second mode of operation.

[0009] In some embodiments, the system is selectively operable in the first mode of operation and the third mode of operation.

[0010] In some embodiments, the system is selectively operable in the first mode of operation, the second mode of operation, and the third mode of operation.

[0011] In some embodiments, in the second mode of operation, ambient air is compressed by at least two of the one or more compressors of the compression train.

[0012] In some embodiments, in the second mode of operation, a gas stream exiting the dedicated expander is directed to at least one of the one or more expanders in the expansion train to generate additional electrical power.

[0013] In some embodiments, in the third mode of operation, a gas stream exiting the dedicated expander is directed to at least one of the one or more expanders in the expansion train to generate additional electrical power.

[0014] In some embodiments, the system further comprises a heat recovery steam generator positioned downstream of the dedicated expander.

[0015] In some embodiments, the system further comprises a heat recuperator positioned downstream of the dedicated expander, the heat recuperator being configured to transfer heat from a gas stream exiting the dedicated expander to the compressed gas stream directed to the combustor from the at least one of the one or more compressors of the compression train.

[0016] In some embodiments, the system further comprises a secondary combustor positioned downstream of the dedicated expander and upstream of the heat recuperator, the secondary combustor being configured to transfer heat generated by combusting fuel to the gas stream exiting the dedicated expander.

[0017] In some embodiments, the heat recovery steam generator is positioned upstream of the heat recuperator.

[0018] In some embodiments, the heat recovery steam generator is positioned downstream of the heat recuperator.

[0019] In accordance with another broad aspect, there is provided a compressed gas energy storage system comprising: a compression train comprising one or more compressors, the compression train being configured to draw in and compress ambient air to generate compressed gas; an accumulator positioned downstream of the compression train and configured to selectively receive compressed gas for storage and to selectively release stored compressed gas for power generation; an expansion train positioned downstream of the accumulator, the expansion train comprising one or more expanders, the expansion train being configured to receive and expand compressed gas from the accumulator to generate electrical power; and a combustor configured to receive compressed gas from at least one of the accumulator and one of the one or more compressors of the compression train, and transfer heat generated by combusting a fuel to the received compressed gas; wherein one of the one or more expanders in the expansion train is configured to receive and expand heated compressed gas exiting the combustor to generate electrical power; wherein the system is selectively operatable in one of: a first mode of operation, in which compressed gas is released from theaccumulator to the expansion train to generate a first level of electrical power; and at least one of: a second mode of operation, in which ambient air is drawn in and compressed by the one of the one or more compressors of the compression train, directed to the combustor as a compressed gas stream, heated by the combustor to generate a heated compressed gas stream, and the heated compressed gas stream is directed to one of the one or more expanders in the expansion train to generate a second level of electrical power, and a third mode of operation, in which compressed gas is released from the accumulator to the combustor as a compressed gas stream, heated by the combustor to generate a heated compressed gas stream, and the heated compressed gas stream is directed to the one of the one or more expanders in the expansion train to generate a third level of electrical power.

[0020] In some embodiments, the system is selectively operable in the first mode of operation and the second mode of operation.

[0021] In some embodiments, the system is selectively operable in the first mode of operation and the third mode of operation.

[0022] In some embodiments, the system is selectively operable in the first mode of operation, the second mode of operation, and the third mode of operation.

[0023] In some embodiments, in the second mode of operation, ambient air is compressed by at least two of the one or more compressors of the compression train.

[0024] In some embodiments, the system further comprises a heat recovery steam generator positioned downstream of the one of the one or more expanders in the expansion train.

[0025] In some embodiments, the system further comprises a heat recuperator positioned downstream of the expansion train, the heat recuperator being configured to transfer heat from a gas stream exiting the one of the one or more expanders in the expansion train to the compressed gas stream directed to the combustor from the at least one of the one or more compressors of the compression train.

[0026] In some embodiments, the heat recuperator is further configured to transfer heat from the gas stream exiting the one of the one or more expanders in the expansion train to a flow of gas between two of the one or more expanders in the expansion train.

[0027] In some embodiments, the system further comprises a secondary combustor positioned downstream of the expansion train and upstream of the heat recuperator, the secondary combustor being configured to transfer heat generated by combusting fuel to the gas stream exiting the one of the one or more expanders in the expansion train.

[0028] In some embodiments, the heat recovery steam generator is positioned upstream of the heat recuperator.

[0029] In some embodiments, the heat recovery steam generator is positioned downstream of the heat recuperator.

[0030] In some embodiments, the third level of electrical power is greater than the first level of electrical power.

[0031] In some embodiments, the fuel comprises a fuel gas, and the combustor operates as a direct fired combustor.

[0032] In some embodiments, the combustor operates as an indirect fired combustor.

[0033] In some embodiments, the fuel comprises a fuel gas, and the fuel gas is premixed with air prior to entering the combustor.

[0034] In accordance with another broad aspect, there is provided a compressed gas energy storage system comprising: a compression train comprising one or more compressors, the compression train being configured to draw in and compress ambient air to generate compressed gas; an accumulator positioned downstream of the compression train and configured to selectively receive compressed gas from the compression train for storage and to selectively release stored compressed gas for power generation; an expansion train positioned downstream of the accumulator, the expansion train comprising one or more expanders, the expansion train being configured to receive and expand compressed gas from the accumulator to generate electrical power; a boiler configured to heat a working fluid by combusting a fuel gas to generate steam; and a working fluid circulation system configured to direct steam exiting the boiler to at least one of the one or more expanders of the expansion train, and to recirculate working fluid exiting the at least one of the one or more expanders to the boiler; wherein the system is selectively operatable in one of: a first mode of operation, in which ambient air is drawn in and compressed by the compression train, stored in the accumulator, and released from the accumulator to the expansion train to generate a first level of electrical power; and a second mode of operation, in which the working fluid is heated by the boiler to generate steam, and the steam is directed through the at least one of the one or more expanders to generate a second level of electrical power.

[0035] In accordance with another broad aspect, there is provided a compressed gas energy storage system comprising: a compression train comprising one or more compressors arranged in series, the compression train being configured to draw in and compress ambient air to generate compressed gas; an accumulator positioned downstream of the compression train and configured to selectively receive compressed gas from the compression train for storage and to selectively release stored compressed gas for power generation; an expansion train positioned downstream of the accumulator, the expansion train comprising one or more expandersarranged in series, the expansion train being configured to receive and expand compressed gas from the accumulator to generate electrical power; a heat exchange subsystem, the heat exchange subsystem comprising: one or more intermediate heat exchangers positioned along a gas flow path of the compression train and along a gas flow path of the expansion train, each intermediate heat exchanger configured to: receive compressed gas from an upstream one of the one or more compressors, transfer heat between the received compressed gas and a thermal fluid, and direct thermally treated compressed gas to a downstream one of the one or more compressors, and receive exhaust gas from an upstream one of the one or more expanders, transfer heat between the received exhaust gas and the thermal fluid, and direct thermally treated exhaust gas to a downstream one of the one or more expanders; a terminal heat exchanger positioned along a gas flow path between the compression train and the accumulator and along a gas flow path between the accumulator and the expansion train, the terminal heat exchanger configured to: receive compressed gas from the downstream one of the one or more compressors, transfer heat between the received compressed gas and the thermal fluid, and direct thermally treated compressed gas to the accumulator, and receive compressed gas from the accumulator, transfer heat between the received compressed gas and the thermal fluid, and direct thermally treated compressed gas to the upstream one of the one or more expanders; a first thermal fluid storage tank configured to hold thermal fluid at a first temperature; a second thermal fluid storage tank configured to hold thermal fluid at a second temperature that is lower than the first temperature; a thermal fluid circulation system configured to circulate thermal fluid between the first storage tank and the second storage tank via the one or more intermediate heat exchangers and the terminal heat exchanger in parallel, and a combustor configured to receive thermal fluid from the first thermal fluid storage tank, transfer heat generated by combusting a fuel gas to the received thermal fluid, and direct the heated thermal fluid to the one or more intermediate heat exchangers and the terminal heat exchanger in parallel, wherein the system is selectively operatable in one of: a first mode of operation, in which compressed air is released from the accumulator to the expansion train for expansion while the combustor is inactive to generate a first level of electrical power; and a second mode of operation, in which compressed air is released from the accumulator to the expansion train for expansion while the combustor is active to generate a second level of electrical power.

[0036] In some embodiments, the fuel comprises a fuel gas.

[0037] In some embodiments, the fuel gas comprises Hydrogen.

[0038] In some embodiments, the fuel gas comprises at least 95% Hydrogen.

[0039] In some embodiments, the compression train comprises three compressors.

[0040] In some embodiments, the expansion train comprises three expanders.

[0041] In some embodiments, the compression train comprises compression train heat exchanges positioned between each of the one or more compressors.

[0042] In some embodiments, the expansion train comprises expansion train heat exchanges positioned between each of the one or more expanders.

[0043] In some embodiments, the accumulator is positioned underground.

[0044] In some embodiments, the accumulator is a hydrostatically compensated compressed air energy storage accumulator.

[0045] In some embodiments, wherein the accumulator is substantially isobaric.

[0046] In accordance with another broad aspect, a compressed gas energy storage system is provided, comprising: an accumulator; a gas compressor / expander subsystem spaced apart from the accumulator and a gas conduit having an upper end in communication with the gas compressor / expander subsystem and a lower end in communication with accumulator interior for conveying compressed gas into the compressed gas layer; a shaft having 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 containing a quantity of a liquid, the shaft being fluidly connectable to a liquid source / sink via a liquid supply conduit; a liquid conduit providing fluid communication between the liquid in the shaft interior and the layer of liquid in the accumulator, whereby liquid can flow between the shaft interior and the layer of liquid in the accumulator in response to changes in the pressure of the layer of compressed gas; one or more heat exchangers provided in fluid communication between the gas compressor / expander subsystem and the accumulator; a selection mechanism; a fuel combustion chamber that is selectably in fluid communication with the selection mechanism; and a dedicated expander, and which the fuel combustion chamber also in fluid communication with the dedicated expander. The selection mechanism is configured to select between (i) diverting the compressed gas from the gas compressor / expander subsystem to the fuel combustion chamber and (ii) diverting the compressed gas from the gas compressor / expander subsystem to the accumulator. The fuel combustion chamber is configured to combust fuel to generate thermal energy and transfer the thermal energy to the compressed gas passing through the fuel combustion chamber to generate thermally enhanced compress gas, and the thermally enhanced compressed gas is conveyed to the dedicated expander. In a preferred embodiment, the fuel is Hydrogen.

[0047] Other aspects and embodiments are described in further detail below.BRIEF DESCRIPTION OF THE DRAWINGS

[0048] Example embodiments of the invention will now be described with reference to the appended drawings in which:

[0049] FIG. 1 is a schematic view of components of one example of a hydrostatically compensated compressed gas energy storage system;

[0050] FIG. 2 is a top plan view of components of a bulkhead for the compressed gas energy storage subsystem of FIG. 1;

[0051] FIG. 3 is a side elevation view of the bulkhead of FIG. 2;

[0052] FIG. 4 is a side cross-sectional view of the bulkhead of FIG. 2, taken along line 4-4;

[0053] FIG. 5 is a schematic representation of components of one example of a compressor / expander subsystem that is usable with any of the compressed gas energy storage systems, according to an embodiment.

[0054] FIG. 6A is a schematic view of components of another example of a compressed gas energy storage system;

[0055] FIG. 7A is an enlarged view of a portion of the components of the compressed gas energy storage system of FIG. 6A;

[0056] FIG. 6B is a schematic view of components of another example of a compressed gas energy storage system;

[0057] FIG. 7B is an enlarged view of a portion of the components of the compressed gas energy storage system of FIG. 6B;

[0058] FIG. 8 is a schematic view of components of another example of a compressed gas energy storage system;

[0059] FIG. 9 is a schematic view of components of another example of a compressed gas energy storage system;

[0060] FIG. 10 is a schematic view of components of a compressor / expander subsystem for the compressed gas energy storage system, according to an embodiment;

[0061] FIG. 11A is a schematic view of components of an alternative compressor / expander subsystem for a compressed gas energy storage system, with multiple compression stages each associated with a respective heat exchanger;

[0062] FIG. 1 IB is a schematic view of components of an alternative compressor / expander subsystem for a compressed gas energy storage system, with multiple compression stages each associated with a respective heat exchanger;

[0063] FIG. 12 is a schematic view of components of an alternative compressor / expander subsystem for a compressed gas energy storage system, with multiple expansion stages each associated with a respective heat exchanger;

[0064] FIG. 13 is a schematic view of components of an alternative compressor / expander subsystem for a compressed gas energy storage system, with pairs of compression and expansion stages each associated with a respective heat exchanger;

[0065] FIG. 14 is a schematic view of components of the alternative compressor / expander subsystem of FIG. 13, showing airflow during an expansion (release) phase from storage through multiple expanders and heat exchangers;

[0066] FIG. 15 is a schematic view of components of the alternative compressor / expander subsystem of FIG. 13, showing airflow during a compression (storage) from the ambient through multiple compressors and heat exchangers;

[0067] FIG. 16 is a schematic view of components of a compressed gas energy storage system, according to an embodiment;

[0068] FIG. 17 is a schematic view of components of a compressor / expander subsystem for the compressed gas energy storage system, according to an embodiment;

[0069] FIG. 18 is a schematic view of components of an alternative compressor / expander subsystem for a compressed gas energy storage system, with multiple compression stages each associated with a respective stage of a thermal storage subsystem;

[0070] FIG. 19 is a schematic view of components of an alternative compressor / expander subsystem for a compressed gas energy storage system, with multiple expansion stages each associated with a respective stage of a thermal storage subsystem;

[0071] FIG. 20 is a schematic view of components of an alternative compressor / expander subsystem for a compressed gas energy storage system, with pairs of compression and expansion stages each associated with a respective stage of a thermal storage subsystem;

[0072] FIG. 21 is a schematic view of components of the alternative compressor / expander subsystem of FIG. 20, showing airflow during an expansion (release) phase from storage through multiple expanders and respective stages of a thermal storage subsystem;

[0073] FIG. 22 is a schematic view of components of the alternative compressor / expander subsystem of FIG. 20, showing airflow during a compression (storage) from the ambient through multiple compressors and respective stages of a thermal storage subsystem;

[0074] FIG. 23 is a schematic view of components of a compressed gas energy storage system, according to an alternative embodiment;

[0075] FIG. 24 is a schematic view of components of an alternative compressed gas energy storage system, according to another alternative embodiment;

[0076] FIG. 25 is a schematic view of components of another example of a compressed gas energy storage system;

[0077] FIG. 26 is a schematic representation of another embodiment of a compressed gas energy storage system;

[0078] FIG. 27 is a schematic view of components of another example of a compressed gas energy storage system;

[0079] FIG. 28 is a schematic view of components of yet another example of a compressed gas energy storage system;

[0080] FIG. 29A is a schematic view of another example of a compressed gas energy storage system including a fuel gas combustion chamber and a dedicated expander, where the combustion chamber is indirect fired;

[0081] FIG. 29B is a schematic view of another example of a compressed gas energy storage system including a fuel gas combustion chamber and a dedicated expander, where the combustion chamber is direct fired;

[0082] FIG. 30 is a schematic view of another example of a compressed gas energy storage system including a fuel gas combustion chamber configured to heat thermal fluid exiting a thermal fluid storage tank;

[0083] FIG. 31 is a schematic view of yet another example of a compressed gas energy storage system including a fuel gas combustion chamber configured to heat thermal fluid exiting a thermal fluid storage tank;

[0084] FIG. 32 is a schematic view of yet another example of a compressed gas energy storage system including a fuel gas combustion chamber and a dedicated expander;

[0085] FIG. 33A is a schematic view of an example of a fuel gas combustion subsystem;

[0086] FIG. 33B is a schematic view of components of another example of a fuel gas combustion subsystem;

[0087] FIG. 34 is a schematic view of another example of a compressed gas energy storage system, operating in a mode in which a compressor of the compression train supplies compressed gas to a fuel gas combustion chamber and heated compressed gas is expanded through a dedicated expander;

[0088] FIG. 35 is a schematic view of the compressed gas energy storage system of FIG. 34, operating in a mode in which an accumulator supplies compressed gas to the fuel gas combustion chamber and heated compressed gas is expanded through the dedicated expander;

[0089] FIG. 36 is a schematic view of another example of a compressed gas energy storage system, operating in a mode in which a compressor of the compression train supplies compressed gas to a fuel gas combustion chamber, heated compressed gas is expanded through a dedicated expander, and exhaust gas from the dedicated expander is expanded through an expander of the expander train after passing through an optional heat recovery steam generator (HRSG);

[0090] FIG. 37 is a schematic view of the compressed gas energy storage system of FIG. 36, operating in a mode in which an accumulator supplies compressed gas to the fuel gas combustion chamber, heated compressed gas is expanded through the dedicated expander, and exhaust gas from the dedicated expander is expanded through the expander of the expander train , after passing through an optional HRSG;

[0091] FIG. 38 is a schematic view of another example of a compressed gas energy storage system, operating in a mode in which a compressor of the compression train supplies compressed gas to a fuel gas combustion chamber, and heated compressed gas is expanded through an expander of the expander train;

[0092] FIG. 39 is a schematic view of the compressed gas energy storage system of FIG. 38, operating in a mode in which an accumulator supplies compressed gas to the fuel gas combustion chamber, and heated compressed gas is expanded through the expander of the expander train;

[0093] FIG. 40 is a schematic view of another example of a compressed gas energy storage system, operating in a mode in which a fuel gas boiler heats and circulates a working fluid through the expanders of an expander train in parallel;

[0094] FIG. 41 is a schematic view of another example of a compressed gas energy storage system, operating in a mode in which a compressor of the compression train supplies compressed gas to a fuel gas combustion chamber via a heat recuperator, heated compressed gas is expanded through an expander of the expander train, and exhaust gas from the expander is directed through the heat recuperator;

[0095] FIG. 42 is a schematic view of another example of a compressed gas energy storage system, operating in a mode in which a compression train supplies compressed gas to a first expander of the expander train via a heat recuperator, exhaust gas from the first expander is directed to a second expander of the expander train via the heat recuperator, exhaust gas from the second expander is directed to a fuel gas combustion chamber, heated compressed gas is expanded through a third expander of the expander train, exhaust gas from the third expanderis directed through a secondary fuel gas combustion chamber, and heated exhaust gas is directed through the heat recuperator; and

[0096] FIG. 43 is a schematic view of the compressed gas energy storage system of Figure 42, showing an optional HRSG to generate additional power from exhaust gas exiting the heat recuperator.DETAILED DESCRIPTION

[0097] 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.

[0098] 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 (for example if it is not windy, or at night, etc.). However, the demand for energy may not always match the production periods for these types of energy sources, 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 (for example, coal, gas, and / or nuclear power plants) to help facilitate storage of energy generated during non-peak demand periods (e.g. periods when electricity supply could be greater than demand and / or when the cost of electricity is relatively low) and allow that energy to be utilized during peak demand 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).

[0099] 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 suitableaccumulator. 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. However, containing gases at relatively high pressures (such as between about 45-150 atm) in conventional systems can require relatively strong, specialized, and often relatively costly storage containers / pressure vessels.

[0100] When gas is compressed for storage (for example during a charging mode) its temperature tends to increase, and if the gas passes through multiple compression stages its temperature can increase with each stage. Further, some compressors may have a preferred inlet temperature range in which they operate with a desired level of efficiency. Gas that has been compressed in one compression stage may, in some systems, be heated to a temperature that is above a desired inlet temperature for a subsequent compressions stage. Reducing the temperature of the gas exiting an upstream compressions stage before it reaches a subsequent compression stage may be advantageous.

[0101] Similarly, when compressed gas is removed from an accumulator and expanded for electricity generation (for example during a discharge mode), the expansion process is endothermic and thermal energy is transferred into the expanding gas.

[0102] Optionally, heat that is removed / extracted from gas exiting one or more compression stages when the system is in a charging mode can be stored in a suitable thermal storage subsystem, and preferably that heat / thermal energy can then be re-introduced into gas that is removed from the accumulator and is passing through one or more suitable expansion stages during a discharge mode. This may help improve the overall efficiency of a compressed gas energy storage system. This may also help reduce and / or eliminate the need for heat sinks / sources or other apparatus to dissipate heat when in the charging mode and / or supply new heat when in the discharge mode.

[0103] Thermal energy / heat that is extracted from the compressed gas can be stored in any suitable thermal storage apparatus, including those described herein. Preferably, at least a portion of the thermal storage subsystem and / or thermal storage apparatus may be provided by adapting and / or repurposing one or more portions of the overall compressed gas energy storage system. For example, systems in which the accumulator and / or other system components are located underground may utilize one or more excavation shafts or similar structures during the construction phase to help transport equipment and personnel to the underground structuresand / or to extract debris and other material from the construction sites. Shafts of this nature will generally extend from an upper end at the surface, or at least accessible from the surface during construction, to a lower end that is adjacent and at least temporarily connected to the underground structure / cavem / chamber, etc. that is being constructed. This can help facilitate the movement of equipment, people, and debris. In some examples, more than one such shaft may be created for a variety of reasons, including to help expedite construction, provide two or more access and egress locations for safety -related reasons, provide underground ventilation and other such purposes. In some embodiments of the compressed gas energy storage systems described herein, these shafts may extend at least 100 m, 200 m, 300 m, 400 m or more into the ground, depending on the design constraints and soil conditions surrounding a given compressed gas energy storage systems. Such shafts may be generally referred to as excavation shafts even if their primary function is ventilation or access and even if no debris is actually extracted via the shaft during construction. Similarly, while the term “shaft” is used for convenience, the actual geometry of the structure may vary depending on the particular building techniques used, and may take the form of a decline, chamber or other such structure, and may be substantially vertical or may be inclined, and / or may be generally linear, or may have a curved or varying geometry.

[0104] The accumulator may be an underground cavern that also holds a liquid to hydrostatically compensate the stored compressed gas. The gas energy can be compensated by adjusting the hydrostatic pressure within the accumulator.

[0105] It has also been recognized by the named inventors of this application that combustion of a fuel, which is preferably a fuel gas (e.g. combustion of Hydrogen, natural gas, biogas, syngas, landfill gas, sewer gas, digester gas or the like) may be used to increase the power capacity or energy capacity, or both, of a hydrostatically compensated compressed gas energy storage system. Alternatively, the fuel could be a liquid fuel (e.g., distillate oil) or a solid fuel (e.g. waste forest product or other biomass).

[0106] By integrating one or more fuel gas combustion chambers into a hydrostatically compensated compressed gas energy storage system, e.g., as described herein, the resultant gas energy storage systems may be characterized as ‘fuel assisted’ gas energy storage systems. Such ‘fuel assisted’ gas energy storage systems may have one or more advantages.

[0107] For example, a ‘fuel assisted’ gas energy storage system may be able to provide energy for an indefinite duration (presuming an adequate supply of fuel gas). In traditional compressed gas energy storage systems, the total power (electricity) available to be output is based on the total volume and / or pressure of stored compressed gas. Once the total volume ofcompressed gas is removed from the accumulator and expanded for electricity generation (e.g., during a discharge mode), the system may no longer be capable of outputting energy (electricity) until the accumulator is recharged with additional compressed gas. In contrast, ‘fuel assisted’ gas energy storage systems may be capable of outputting energy (electricity) after the accumulator is depleted by generating power through the combustion of fuel gas.

[0108] As another example, a ‘fuel assisted’ gas energy storage system may be able to provide energy at a given output level for a longer duration than a traditional compressed gas energy storage system. For example, for a given total volume and / or pressure of stored compressed gas, there is a limit to the total time a traditional system may be capable of outputting a desired power (electricity) output level. In a ‘fuel assisted’ gas energy storage system, by adding heat from combusted fuel gas to stored compressed gas before or while it is being expanded to generate power during a discharge mode, the system may be capable of providing the desired power (electricity) output level for a longer time period (e.g. outputting 100 MW for 16 hours v. outputting 100 MW for 8 hours).

[0109] As yet another example, a ‘fuel assisted’ gas energy storage system may be able to provide energy at an increased output level than a traditional compressed gas energy storage system. For example, for a given pressure and / or total volume of stored compressed gas, there may be a limit to the total power (electricity) output level of a traditional compressed gas energy storage system (e.g., a design limit based on efficiency and / or safety, or other limits). In a ‘fuel assisted’ gas energy storage system, by adding heat from combusted fuel gas to stored compressed gas before or while it is being expanded to generate power during a discharge mode, the system may be capable of providing an increased power (electricity) output level (e.g., outputting 150 MW v. outputting 100 MW).

[0110] In some cases, a fuel assisted gas energy system includes a fuel gas combustion chamber that is integrated with a compressor system (e.g., one compressor or a train of compressors, which may alternatively be referred so as a compressor train) to add thermal energy to an output gas stream of the compressor system, which may be characterized as a thermal energy enhanced compressed gas stream. For example, as compressed air from the compressor system passes through a fuel gas combustion chamber, the combustion of fuel gas in the combustion chamber produces thermal energy that is transferred to a gas stream of the compressor system, generating the thermally energy enhanced gas stream.

[0111] In some examples, the fuel gas combustion chamber does not mix the fuel gas or the combustion products with the compressed gas stream during heating. Such combustionchambers (which may alternatively be referred to as combustors) may be characterised as ‘indirect fired’ combustion chambers.

[0112] In other examples, the fuel gas combustion chamber mixes the fuel gas and the combustion products with the compressed gas stream when generating the thermally enhanced gas stream. Such combustion chambers (or combustors) may be characterised as ‘direct fired’ combustion chambers.

[0113] In some examples, the thermally enhanced gas stream is passed through a turbine system (also herein called an expander system) to generate electrical energy. The system may also include a selector mechanism positioned between the output of the compressor system and the fuel gas combustion chamber. The selector mechanism is operable to switch between two modes: a first mode that directs flow of the output gas stream of the compressor system to the accumulator for storage (or to an intermediary device between the accumulator and the selector mechanism, such as heat exchanger); and a second mode that directs flow of the output gas stream of the compressor system to the fuel gas combustion system. In this way, the selector mechanism allows the system to be selectively switched between at least two operating modes: a first operating mode that includes compressing gas and storing the compressed gas in the accumulator (e.g. when the selector mechanism is selected to be in the first mode; and a second operating mode that includes compressing gas, adding thermal energy to the compressed gas using the fuel gas combustion chamber, and driving an expander (turbine) system to generate electrical energy or other power when the selector mechanism is selected to be in the second mode.

[0114] In some other examples, a fuel assisted gas energy system includes a fuel gas combustion chamber that is placed in fluid communication with one or more heat exchangers that are part of a compressor / expander system of the gas being respectively stored / discharged. The fuel gas combustion chamber may add a ‘heat boost’ to thermal fluid passing through the one or more heat exchangers, which in turn may add a ‘heat boost’ to the gas being discharged from the accumulator and expanded, which in turn may increase the electrical energy or other energy output by the expander system.

[0115] In some embodiments, the one or more heat exchangers are in fluid communication with a first thermal fluid storage tank and a second thermal fluid storage tank. The first thermal fluid storage tank holds a thermal fluid that is at a higher temperature than the thermal fluid held in the second thermal fluid storage tank. The thermal fluid passes through the one or more heat exchanges travelling from the first thermal fluid storage tank to the second thermal fluid storage tank when discharging compressed gas from the storage to atmosphere through theexpander system to generate electricity. The fuel gas combustion chamber is positioned between the first thermal fluid storage tank and the one or more heat exchangers, such that, during discharge of the compressed gas, thermal fluid travels from the first thermal fluid storage tank to the fuel gas combustion chamber, where thermal energy generated by combustion is added to the thermal fluid. The thermal fluid then travels from the fuel gas chamber to the one or more heat exchangers, where thermal energy from the thermal fluid is transferred to gas flowing through the heat exchanger (i.e., the gas stream being discharged), and the thermal fluid then travels to the second thermal fluid storage tank.

[0116] It will be appreciated that the thermal energy added to the gas stream while being discharged will lead to increased electrical energy or power being generated as the heated gas passes through the expander system. As a result, the fuel gas combustion chamber in such systems may be characterized as providing a ‘heat boost’.

[0117] Preferably, a fuel gas combustion chamber providing such a ‘heat boost’ operates as an indirect combustor (i.e., does not mix the fuel gas or its combustion products with the thermal fluid during heating).

[0118] In other examples, a fuel assisted gas energy system includes a fuel gas combustion chamber that is positioned downstream of the accumulator in the decompression fluid path. Compressed gas that is stored in the accumulator is output from the accumulator as a compressed gas stream, and the compressed gas stream passes through the fuel gas combustion chamber. The fuel gas combustion chamber adds thermal energy to the compressed gas stream to generate a thermally enhanced compressed gas stream. The thermally enhanced compressed gas steam is then passed through a turbine system (alternatively referred to herein as an expander system or an expander train), which generates electrical power. The system may also include a selector mechanism positioned between an output of the accumulator and the fuel gas combustion chamber. The selector mechanism is operable to switch between two modes: a first mode that directs flow of the output compressed gas stream of the accumulator to an expander system (e.g., a train of expander turbines) that generates electrical power; and a second mode that directs flow of the output compressed gas stream of the accumulator to the fuel gas combustion system. In this way, the selector mechanism allows the system to controllably switch between at least: a first operating mode that includes a decompression process in which compressed gas from the accumulator drives an expander system to generate electricity without added thermal energy from the fuel gas combustion chamber (i.e. when the selector mechanism is selected to be in the first mode); and a second operating mode that includes the compressed gas powering a dedicated turbine that is powered by fuel gas-combustion-sourced thermallyenhanced compressed gas (i.e. when the selector mechanism is selected to be in the second mode).

[0119] It will be appreciated that, where reference is made herein to generating electrical power, the systems or components could additionally, or alternatively, provide frequency control for grid stabilization. For example, during periods where the system is operating in a ‘fuel assisted’ mode, the increased ability to quickly react to load changes may allow an operator to offer frequency support and inertia to promote a stable grid.

[0120] Referring to FIG. 1 one example of a fuel assisted and hydrostatically compensated compressed gas energy storage system 10, 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 liquid (such as water) and can include any suitable type of pressure vessel or tank, or as in this example can be an underground cave or cavern that is within ground 200. In this embodiment, accumulator 12 is 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 the interior 23. In another embodiment, the accumulator is preferably impermeable to gas and or liquid without requiring a lining.

[0121] 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. The upper and lower walls 13 and 15 may be of any suitable configuration, including curved, arcuate, angle, and the like, and in the illustrated example are shown as generally planar surfaces, which 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 FIG. 1). The upper and lower walls 13 and 15, along with one or more sidewalls 21 at least partially define an interior 23 of the accumulator 12, that has an accumulator volume. The accumulator 12 in a given embodiment of the system 10 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 1,000 m3and about 2,000,000 m3or more. For example, in this embodiment the accumulator 12 contains a layer of stored compressed gas 14 atop a layer of 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 10, and other suitable factors which may be related to the capacity or other features of a suitable power source and / or power load (see power source / load S / L in FIG. 5) with which the system 10 is to be associated.The power source / load S / L may be, in some examples, a power grid, a power source (including renewable and optionally non-renewable sources) and the like.

[0122] Preferably, the accumulator 12 may be positioned below ground or underwater, but alternatively may be at least partially above ground. 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 is established according to the pressures at which the compression / expansion equipment to be used is most efficiently operated.

[0123] 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, 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 within requiring further treatment. In this embodiment, the compressed gas 14 is compressed atmospheric air, and the liquid is water.

[0124] 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 10 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 (taken in the plane 19) that is adequate based on the specific requirements. In one embodiment the cross-sectional area is between about 0.75m2and about 80 m2, but may be larger or smaller in a given embodiment.

[0125] When the system 10 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 FIG. 1, the system 10 includes a partition in the form of a bulkhead 24 that covers the primary opening 27. FIG. 2 is a top plan view of components of this embodiment of a bulkhead 24, and FIG.s 3 and 4 are side elevation and side cross-sectional views, respectively, of bulkhead 24. In this example, the bulkhead 24 has a main body 25 that includes a inner surface 29 that faces the interior 23 of the accumulator 12, and in one alternative, is generally exposed to and in fluid communication with the compressed gas layer 14, and an opposing outer surface 31 at an upper end of the body 25 that faces interior 54. A flange 26 extends generally laterally outwardly toward the lower end of the bulkhead, such that the upper end of the bulkhead 24 has an upperwidth 33 that may be between about l-8m, and may be sized to fit within the opening 27, and the lower end of the bulkhead 24 has a lower width 35 that is greater than the upper width 33 and can be between about 1.2m and about 10m, for example. In this arrangement, a generally upwardly facing shoulder surface 37 is defined and extends around the periphery of the bulkhead 24. When the bulkhead 24 is in place, as shown in FIG. 1, the shoulder surface 37 can abut the upper surface 13 of the accumulator 12 and can help resist upward movement of the bulkhead 24 through the opening 27. The bulkhead 24 may be secured to, and preferably sealed with the upper wall 13 using any suitable mechanism to help seal and enclose the interior 23. In other embodiments, the bulkhead 24 may have a different, suitable configuration.

[0126] The bulkhead 24 may be manufactured in situ, or may be manufactured offsite, and may be made of any suitable material, including, concrete, metal, plastics, composites and the like. In the illustrated embodiment, the bulkhead 24 is assembled in situ at the interface between shaft 18 and accumulator 12 of multiple pieces of reinforced concrete.

[0127] In the embodiment of FIG. 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), 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 soil and underground conditions, the availability of existing structures (e.g. if the system 10 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 10 described herein may be retrofit into pre-existing underground chambers, which may have been constructed with openings in their sidewalls, floors and the like. Utilizing some of these existing formations may help facilitate construction and / or retrofit of the chambers used in the system, and may reduce or eliminate the need to form additional openings in the upper surfaces of the chambers. Reducing the total number of openings in the accumulator may help facilitate sealing and may help reduce the chances of leaks and the like.

[0128] When the primary opening 27 extends along the sidewall 21 of the accumulator 12, 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 liquid layer 16 (i.e. submerged within the liquid layer 16 and toward the bottom of the accumulator) and / or by a combination of both the gas layer 14 and the liquid layer 16 (i.e. partially submerged and partially non-submerged in the liquid). The specific position of the free surface of the liquid layer 16 (i.e., the interface betweenthe liquid layer 16 and the gas layer 14) may change while the system 10 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).

[0129] As illustrated in the schematic representation in FIG. 27, the primary opening 27 is provided in the sidewall 21 of the accumulator 12, and the bulkhead 24 is positioned such that is generally partially submerged in the liquid layer 16 and partially exposed to the gas layer 14 when the system 10H is in use. In this example, the gas supply conduit 22 passes through the bulkhead 24 and is arranged so that its lower end 62 is located toward the top of the accumulator 12 so that it will remain in communication with the gas layer 14, and fluidly isolated from the liquid layer 16, regardless of the level of the liquid within the accumulator 12. Alternatively, the gas supply conduit 22 may be positioned such that it does not pass through the bulkhead 24 when the system is configured in this manner.

[0130] In the embodiments of FIG. 1 and 27, the partition includes a fabricated bulkhead 24 that is positioned to cover, and optionally seal the primary opening 27 in the accumulator perimeter. Alternatively, in other embodiments, the partition may be at least partially formed from natural materials, such as rock and the like. For example, a suitable partition may be formed by leaving and / or shaping portions of naturally occurring rock to help form at least a portion of the pressure boundary between the interior of the accumulator and the shaft. Such formations may be treated, coated or otherwise modified to help ensure they are sufficiently gas impermeable so as to be able to withstand the desired operating pressure differentials between the accumulator interior and the shaft. This may be done, in some embodiments, by selectively excavating the shaft 18 and accumulator 12 such that a portion of the surrounding rock is generally undisturbed during the excavation and construction of the shaft 18 and accumulator 12. Alternatively, rock or other such material may be re-introduced into a suitable location within the accumulator 12 and / or shaft 18 after having been previously excavated. This may help reduce the need to manufacture a separate bulkhead and install it within the system 10. In arrangements of this nature, the primary opening 27 may be formed as an opening in a sidewall 21 of the accumulator 12, or alternatively one side of the accumulator 12 may be substantially open such that the primary opening 27 extends substantially the entire accumulator height 17, and forms substantially one entire side of the accumulator 12.

[0131] Referring to FIG. 28, another embodiment of a compressed gas storage system 101 is configured with a partition that includes a projection 200A, identified using crosshatching in FIG. 28, that is formed from generally the same material as the surrounding ground200. In this example, the system 101 need not include a separately fabricated bulkhead 24 as shown in other embodiments. The system 10 in this embodiment is configured so that the gas supply conduit 22 is spaced apart from the projection 200A and does not extend through the partition. Instead, a separate shaft or bore can be provided to accommodate the conduit 22. To help provide liquid communication between the interior of the shaft 18 and the liquid layer 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 liquid layer 16, and in ends 64 and 66 of the liquid supply conduit 40 can be the open ends of the passage.

[0132] Optionally, in such embodiments the gas supply conduit 22 may be arranged to pass through the partition / projection 200A as illustrated in FIG. 28. In this arrangement (and in the embodiment shown in FIG. 27), 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 liquid layer 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.

[0133] Optionally, the system 101 may be arranged so that the gas supply conduit 22 passes at least partially through the liquid supply conduit 40. This may help reduce the number of openings that need to be provided in the partition / projection 200 A. In the embodiment of FIG. 28, another optional arrangement of gas supply conduit 22 is shown using dashed lines and passes through the flow channel, from the shaft 18 into the interior of the accumulator 12. In this arrangement, the gas supply conduit 22 is nested in, and passes through the liquid supply conduit 40, and also passes beneath the projection 200A. Optionally, a configuration in which at least some of the gas supply conduit 22 is received within a portion of the liquid supply conduit 40 may also be utilized in other embodiments of the system 10 (including those described and illustrated herein), including those in which both the liquid supply conduit 40 and gas supply conduit 22 pass through the partition.

[0134] When the accumulator 12 is in use, at least one of the pressurized gas layer 14 and the liquid layer 16, or both, 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 FIG. 1, acting on the bulkhead 24. The magnitude of the internal accumulator force 41 is dependent on the pressure of the gas 14 and the cross-sectional area (taken in plane 19) 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.

[0135] Preferably, an inwardly, (downwardly in this embodiment) acting force can be applied to the outer-surface 31 of the bulkhead 24 to help offset and / or counterbalance the internal accumulator force 41. Applying a counter force of this nature may help reduce the net force acting on the bulkhead 24 while the system 10 is in use. This may help facilitate the use of a bulkhead 24 with lower pressure tolerances than would be required if the bulkhead 24 had to resist the entire magnitude of the internal accumulator force 41. This may allow the bulkhead 24 be relatively smaller, lighter and less costly. This arrangement may also help reduce the chances of the bulkhead 24 failing while the system 10 is in use. Optionally, a suitable counter force may be created by subjecting the outer surface 31 to a pressurized environment, such as a pressurized gas or liquid that is in contact with the outer surface 31, and calibrating the pressure acting on the outer surface 31 (based on the relative cross-sectional area of the outer surface 31 and the pressure acting on the inner surface 29) so that the resulting counter force, shown by arrow 46 in FIG. 1, has a desirable magnitude. In some configurations, the magnitude of the counter force 46 may be between about 80% and about 99% of the internal accumulator force 41, and may optionally be between about 90% and about 97%, and may be about equal to the magnitude of the internal accumulator force 41.

[0136] 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 upper wall 13 of the accumulator 12, and an upper end 48 that is spaced apart from the lower end 43 by a shaft height 50. 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 51, 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 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 54 of the shaft 18 may be able to accommodate about 1,000 - 150,000 m3of water.

[0137] 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. 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 liquid, such as water 20. A water supply / replenishment conduit 58 can provide fluid communication between the interior 54 of the shaft 18 and a watersource / sink 150 to allow water to flow into or out of the interior of the shaft 18 as required when the system 10 is in use. Optionally, a flow control valve 59 (as shown in FIG. 1) may be provided in the water supply / replenishment conduit 58. The flow control valve 59 can be open while the system 10 is in use to help facilitate the desired flow of water between the shaft 18 and the water source / sink 150. Optionally, the flow control valve 59 can be closed to fluidly isolate the shaft 18 and the water source / sink 150 if desired. For example, the flow control valve 59 may be closed to help facilitate draining the interior 54 of the shaft 18 for inspection, maintenance or the like.

[0138] The water source / sink 150 may be of any suitable nature, and may include, for example a connection to a municipal water supply or reservoir, a purposely built reservoir, a storage tank, a water tower, and / or a natural body of water such as a lake, river or ocean, groundwater, or an aquifer. In the illustrated example, the water source / sink 150 is illustrated as a lake. Allowing water to flow through the conduit 58 may help ensure that a sufficient quantity of water 20 may be maintained with shaft 18 and that excess water 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 water will flow from the source / sink 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.

[0139] In this example, the water 20 in the shaft 18 bears against the outside of bulkhead 24 and is thereby supported atop bulkhead 24. The amount of pressure acting on the outer surface 31 of the bulkhead 24 in this example will vary with the volume of water 20 that is supported, which for a given diameter 56 will vary with the height of the water column. In this arrangement, the magnitude of the counter force 46 can then be generally proportional to the amount of water 20 held in the shaft 18. To increase the magnitude of the counter force 46, more water 20 can be added. To reduce the magnitude of the counter force 46, water 20 can be removed from the interior 54.

[0140] The layer of stored compressed air 14 underlying bulkhead 24 serves, along with the technique by which bulkhead 24 is stably affixed to the surrounding in the ground, in one alternative to surrounding stone in the ground at the interface between accumulator 12 and shaft 18, to support bulkhead 24 and the quantity of liquid contained within shaft 18.

[0141] Preferably, as will be described, the pressure at which the quantity of water 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 thecompressed 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 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 predetermined threshold net force limit. Maintaining the net pressure differential, and the related net force magnitude, below a threshold net pressure differential limit may help reduce the need for the bulkhead 24 to be very large and highly reinforced, and accordingly relatively expensive. In alternative embodiments, using a relatively stronger bulkhead 24 and / or installation technique for affixing the bulkhead 24 to the accumulator 12 may help withstand relatively higher pressure and net pressure differential, but may be more expensive to construct and install, all other things being equal. Furthermore, the height 17 of the accumulator 12 may be important to the pressure differential: if the height 17 is about 10 metres, then the upward pressure on the bulkhead 24 will be 1 Bar higher than the downward pressure on the bulkhead 24 from the water 20 in shaft 18.

[0142] Each of shaft 18 and accumulator 12 may be formed in ground 200 using techniques similar to those used for producing mineshafts and other underground structures.

[0143] To help maintain substantially equal outward and inward forces 41 and 46 respectively on the bulkhead 24, the system 10 may be utilized to help maintain a desired differential in accumulator and shaft pressures that is below a threshold amount. These pressures may be controlled by adding or removing gas from the compressed gas layer 14 accumulator 12 using any suitable compressor / expander subsystem 100, and water can be conveyed between the liquid layer 16 and the water 20 in shaft 18. In some cases, a fuel gas combustion subsystem 401 is located in proximity to the compressor / expander subsystem 100, or is positioned within the same facility housing the compressor / expander subsystem.

[0144] In this embodiment, a gas conduit 22 is provided to convey compressed air between the compressed gas layer 14 and the compressor / 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 liquid layer 16 and the water 20 in shaft 18. Each conduit 22 and 40 may be formed from any suitable material, including metal, plastic and the like.

[0145] In this example, the gas conduit 22 has an upper end 60 that is connected to the compressor / expander subsystem 100, and a lower end 62 that is in communication with the gas layer 14. The gas conduit 22 is, in this example, positioned inside and extends within the shaft18, and passes through the bulkhead 24 to reach the gas layer 14. Positioning the gas conduit 22 within the shaft 18 may eliminate the need to bore a second shaft and / or access point from the surface to the accumulator 12. This position 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 water 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 FIG. 1 and in the embodiment of FIG. 28, the gas conduit 22 may be external the shaft 18. Positioning the gas conduit 22 outside the shaft 18 may help facilitate remote placement of the compressor / 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 water. 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.

[0146] The liquid conduit 40 is, in this example, configured with a lower end 64 that is submerged in the water layer 16 while the system 10 is in use and a remote upper end 66 that is in communication with the interior 54 of the shaft 18. In this configuration, the liquid conduit 40 can facilitate the exchange of liquid between the liquid layer 16 and the water 20 in the shaft 18. As illustrated in FIG. 1, the liquid 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 liquid layer 16 and the water 20, but not pass through the bulkhead 24.

[0147] In this arrangement, as more gas is transferred into the gas layer 14 during an accumulation cycle, and its pressure increases, in this alternative slightly, water in the water layer 16 can be displaced and forced upwards through liquid conduit 40 into shaft 18 against the pressure of the water 20 in the shaft 18. More particularly, water can preferably freely flow from the bottom of accumulator 12 and into shaft 18, and ultimately may be exchanged with the source / sink 150 of water, 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 water conduit 40. When gas is removed from the gas layer 14, water can be forced from the shaft 18, through the water conduit 40, to refill the water layer 16. The flow through the replenishment conduit 58 can help ensure that a desired quantity of water 20 may be maintained within shaft 18 as water is forced into and out of the water layer 16, as excess water 20 can be drained from and make-up water 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 the accumulator 12.

[0148] Preferably, the lower end 64 of the liquid conduit 40 is positioned so that it is and generally remains submerged in the liquid layer 16 while the system 10 is in use, 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 end 64 of the liquid conduit 40 is placed close to the lower wall 15. If the lower wall 15 is not flat or not generally horizontal, the lower end 64 of the liquid conduit 40 is preferably located in a relative low point of the accumulator 12 to help reduce the chances of the lower end 64 being exposed to the gas layer 14.

[0149] Similarly, to help facilitate extraction of gas from the gas layer, the lower end 62 of the gas conduit 22 is preferably located close to the upper wall 13, or at a relative 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.

[0150] FIG. 5 is a schematic view of components of the compressor / expander subsystem 100 for the compressed gas energy storage system 10 described herein, according to an embodiment. In this example, the compressor / 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 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 an accumulation stage of operation, and draws in atmospheric air A, compresses the air, and forces it down into gas conduit 22 for storage in accumulator 12 (via thermal storage subsystem 120 (see Fig. 8) in embodiments including same). Compressor / expander subsystem 100 also includes an expander 116 driven by compressed air exiting from gas conduit 22 during an expansion stage 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.

[0151] It will be understood that air entering or leaving compressor / 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 environmentalimpacts 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.

[0152] Controller 118 operates compressor / expander subsystem 100 so as to switch between accumulation and expansion stages as required, including operating valves for preventing or enabling release of compressed air from gas conduit 22 on demand.

[0153] In an example aspect, the controller 118 also directly controls the fuel gas combustion subsystem 401. In an alternative example aspect, the controller 118 communicates data with another controller that is dedicated to controlling the fuel gas combustion subsystem 401.Auxiliary Gas Release

[0154] Optionally, the compressed gas energy storage system 10 may include one or more auxiliary gas release subsystem that is separate from the gas conduit 22 to help facilitate the release of gas from the compressed gas layer 14. For example, if the pressure within the accumulator 12 approaches and / or surpasses a desired maximum storage pressure, venting at least some of the gas from the compressed gas layer 14 may help reduce the pressure to a desired range. This can also be used to help prevent the compressed gas layer 14 from reaching a level where it comes into fluid communication with the lower end 64 of the conduit 40. Such an auxiliary gas release subsystem preferably includes at least one auxiliary gas release conduit that is separate from the gas supply conduit 22 and may be configured to vent the gas into the ground, into a separate vent shaft, into the water filled shaft 18 or other desired location. For example, the gas release subsystem may enable further flexibility for regulating pressure within system 10 by being operable to release gas in the event that the differential between the pressure bearing against the outside of bulkhead 24 from within shaft 18 and the pressure bearing against the inside of bulkhead 24 from within accumulator 12 rises to such a level as to threaten the integrity of bulkhead 24 or its installation in place. For example, should the liquid 20 in shaft 18 be reduced to a level that lowers the pressure and thereby reduces the magnitude of the counter force 46 acting on the bulkhead 24 below a desired level, the gas release subsystem can enable release of the pressure within accumulator 12.

[0155] In this embodiment, the gas release subsystem includes an auxiliary gas release conduit 45 that is spaced from the gas supply conduit 22 and an optional valve 42 (see Figs. 1- 4) that is in communication with the compressed gas layer 14 and is, in this example, associated with bulkhead 24. The valve 42 may preferably be a one-way or check valve such that it can allow gas to travel from the compressed gas layer 14 into the shaft 18, but impedes or prevents the flow of water 20 from the shaft 18 into the accumulator 12. The valve 42 may be actuatedusing any suitable mechanism, including being configured as a pressure sensitive valve that can be biased towards a closed configuration and will open, preferably automatically, when the pressure in the compressed gas layer 14 exceeds a pre-set threshold limit, and / or may be configured to be opened and closed remotely (such as through remote hydraulic or electrical actuation) to permit gas from gas layer 14 to escape through bulkhead 24 on demand. Optionally, the valve 42 may be controlled by the controller 118 by using a suitable valve actuating system that may include, for example, mechanical actuators, electromechanical actuators, solenoid actuators and the like. For example, whether the valve 42 is opened to release compressed gas out of accumulator 12, and whether and how compressed gas routed through other portions of the system 10 (such as a thermal storage subsystem 120 (see Figs. 8- 9) during an accumulation or expansion cycle as described herein).

[0156] It is preferred that the dimensions of the shaft 18, accumulator 12 and the integrity of bulkhead 24 be related to each other in a way that permits compressed gas layer 14 in accumulator to be maintained within a pressure range that maximizes the efficiency of the equipment used in compressor / expander subsystem 100. Optionally, the system 10 may be configured to store the compressed gas layer at pressures of between about 20 atm and about 40 atm. Over time, for continued efficient operation, such equipment may require that an adjustment in the pressure range be made. This may be done by adjusting the amount of liquid 20 in shaft 18 and the level of compression of gas within accumulator 24, by adjusting conduit sizes, and the like.

[0157] Optionally, the bulkhead 24 may include one or more apertures or other suitable structures to accommodate the gas conduit 22, the liquid conduit 40, the auxiliary gas release conduit 45 and other such conduits, such that the conduits pass through the bulkhead 24 in order to enter the interior 23 of the accumulator 12. Passing the conduits and other such structures through the bulkhead 24 may eliminate the need to make additional shafts / bores to reach the accumulator 12, and may reduce the number of individual openings required in the upper wall 13. Referring to FIG.s 2-4, extending through main body 25 is a first aperture 28 for accommodating passage of gas conduit 22 from above bulkhead 24 in shaft 18 through to gas layer 14 within accumulator 12. Gas conduit 22 is preferably sealed to / within first aperture 28 so as to minimize, and preferably prevent, leaks or other uncontrolled release of compressed gas within accumulator 12 into shaft 18 or water 20 within shaft 18 into accumulator 12. Also extending through bulkhead 24 is a second aperture 32 for accommodating passage of liquid conduit 40 from above bulkhead 24 in shaft 18 through to liquid layer 16 within accumulator 12. Liquid conduit 40 is sealed within second aperture 32 so as to minimize, and preferablyprevent, uncontrolled release of compressed gas within accumulator 12 into shaft 18 or water 20 within shaft 18 into accumulator 12 (except via conduit 40).

[0158] Also extending through bulkhead 24 is, in this example, a third aperture 44 for accommodating passage of gas from the compressed gas layer 14 towards valve 42 and through the auxiliary gas release conduit 45 for release of gas from the compressed gas layer 14 in the event that the pressure differential discussed requires reduction. It will be understood that the valve 42 does not necessarily have to sit atop bulkhead 24 and may in fact be integrated within third aperture 44 or associated with third aperture 44 in some other manner. Valve 42 may also be integrated into the second aperture 32 and the liquid conduit 40, thus eliminating the need for the third aperture 44.

[0159] In this embodiment, an openable and re-sealable access manway 30 is provided for enabling maintenance access by maintenance personnel to the interior of accumulator 12, for inspection and cleaning. This would be done by closing flow control valve 59 (FIG. 1) and emptying shaft 18 of liquid 20, and emptying accumulator 12 of compressed gas thereby to enable manway 30 to be opened and personnel to pass back and forth. As for bulkhead 24, variations are possible. For example, in an alternative embodiment, bulkhead 24 may only have first and second apertures 28, 32 but no manway 30. In an alternative embodiment, bulkhead 24 may include a manway 30, but need not contain first and second apertures 28, 32 and the conduits 22 and 40 do not pass through bulkhead 24. In yet another alternative embodiment, bulkhead 24 contains no manway and no apertures, such that fluid communication with accumulator 12 does not pass through bulkhead 24. Optionally, a manway or the like may also be provided in other types of partitions, including for example the projection 200A as shown in the embodiment of FIG. 28.

[0160] Optionally, a conduit or other type of guide structure can be provided to help channel the gas that is vented from the accumulator 12 via the auxiliary gas release conduit 45, and optionally via the gas release valve 42. For example, in some circumstances it may be desirable to direct the escaping gas along a particular path through the shaft 18, rather than simply releasing the gas freely into the column of water 20. FIG. 6A is a sectional view of components of an alternative embodiment of a compressed gas energy storage system 10A, which is analogous to the compressed gas energy storage system 10 as described above, and like features are identified using like reference characters. However, in this example the gas release subsystem further includes a guide conduit 53 that extends from a lower, inlet end 68 adjacent the output of the auxiliary gas release conduit 45 (in this example, the exit of gas release valve42) upwards to an upper, outlet end 70 that can be provided toward the upper end of the shaft 18, and optionally may protrude above the free surface of the water 20 retained in the shaft 20.

[0161] The guide conduit 53 has a width 72 (which may be also called a diameter if the guide conduit 53 is a cylindrical pipe), and a related cross-sectional area (taken in a plane parallel to the plane 19) may be configured so that it is between about 0.5% and about 5% of the cross- sectional area of the shaft 18. As shown also in FIG. 7A the lower end of 68 of the guide conduit 53 can be positioned close to, and preferably overlying substantially all of the outlet of the auxiliary gas release conduit 45, such that gas exiting the valve 42 tends to enter the lower end 68 of the guide conduit 53 and is then constrained within guide conduit 53 as it continues to travel upwardly through the shaft 18 and until it reaches the outlet end 70.

[0162] As the gas exiting the accumulator 12 via the auxiliary gas release conduit 45 may tend to be at a relatively high pressure (and may tend to be released generally in overpressurization type situations), the gas bubbles within the water 20 may tend to expand as they move upwardly trough the shaft 18. Under some circumstances, the expansion of the gas bubbles may tend to displace water 20 from within the shaft 18 (for example, forcing water through conduit 20 and into the liquid source / sink 150). This may have the effect of reducing the mass of water that is resting on the bulkhead 24 (i.e., may reduce the average density of the interior 54 of the shaft 18), which may reduce the hydrostatic pressure that is acting on the upper surface 31, and in turn reduce the magnitude of the counter force 46. If gas is being vented via the gas release valve 42 because the internal accumulator pressure is too high, and therefore the magnitude of the internal accumulator force 41 is too high, this reduction in the magnitude of the counter force 46 may further increase the force imbalance on the bulkhead 24 and may tend to exacerbate the over loaded condition of the bulkhead 24.

[0163] As illustrated, the guide conduit 53, or similar structure to help restrict expansion of the gas bubbles, may function as a density change prevention structure / boundary; that may receive the compressed gas that is released from accumulator 12 via auxiliary gas release conduit 45 and convey it upwards and out of shaft 18 while constraining its maximum expansion to the internal volume of the guide conduit 53. This can help limit the amount of water displaced by the expanding, rising gas bubbles, and can help reduce the lessening of the counter force 46 during a gas release / venting event. That is, guide conduit 53 also serves to physically contain gas bubbles as they leave gas release valve 42 thereby to prevent the gas bubbles, as they rise upwards through water 20 to leave system 10A (or 10J), from displacing very much water 20 beyond the quantity of water 20 that was contained within in guide conduit 53. This additional feature may help further safeguard the amount of water 20 in shaft 18thereby to safeguard the amount of downward pressure being placed onto bulkhead 24. It would be understood that this may help facilitate faster release of compressed air via the auxiliary gas release conduit 45, should it be needed, than would be advisable using versions of the system 10 that do not include a guide conduit 53. For example, in the absence of guide conduit 53, gas released from gas release valve 42 or auxiliary gas release conduit 45 could rise and spread freely through the shaft 18. As such freely-spreading gas bubbles increase in volume upon rising (decompress), they would displace water 20 from shaft 18 thereby reducing the amount of downward pressure by water 20 onto bulkhead 24. The guide conduit 53 controls this release of gas bubbles, forcing them to expand upward through guide conduit 53 rather than outward into the rest of shaft 18, thereby preserving most of the volume of water 20 in shaft 18. Guide conduit 53 controlling the release of gas bubbles may help prevent catastrophic failure due to density changes causing the bulkhead 24 to release, buckle or otherwise fail due to a relatively sudden net force imbalance.

[0164] Preferably, the interior of the guide conduit 53 is in fluid communication with the interior 54 of the shaft 18, such as by having the lower end 68 at least partially open, so that the interior of the guide conduit 53 can be generally filled with water 20 when the system is in normal use (i.e. when the guide conduit 53 is not filled with vented gas), while still being configured to receive the vented gas. In this way, guide conduit 53 displaces less water 20 from the shaft 18 than it would if the guide conduit 53 was sealed to the bulkhead 24 and only contained air / gas. With its interior filled with water, the guide conduit 53 may, in some examples, only displace an amount of water the is about equal to the volume of the sidewalls of the guide conduit 53.

[0165] While shown as generally straight, vertical conduit for ease of illustration, the guide conduit 53 may have other configurations, and need not be vertical and / or linear. Optionally, in some examples the upper end 70 of the guide conduit 53 need not be positioned above the surface of the water 20 in the shaft 18, but may be submerged therein. In such arrangements, the expansion-limiting effects of the guide conduit 53 may be somewhat reduced (i.e. more water may ultimately be displaced than if the upper end 70 was above the water), but other factors like expected pressures, gas release rates through valve 42 and the like may be adjusted to compensate for such differences to help ensure the total water displaced from the shaft 18 during an over-pressure venting situation is within an acceptable range. Preferably, the upper end 70 may be in the upper half of the shaft 18 (i.e., above its midway point), and more preferably the upper end 70 may be in the upper 25% of the shaft 18 and most preferably may be generally proximate, if not above, the surface of the water 20.

[0166] FIG. 6B is a sectional view of components of an alternative embodiment of a compressed gas energy storage system 10J, which is analogous to the compressed gas energy storage system 10 as described above, and like features are identified using like reference characters. The gas release subsystem in this embodiment is configured such that the auxiliary gas release conduit 45 is substantially coterminous with the liquid supply conduit 40 and also includes a guide conduit 53 that extends from a lower, inlet end 68 to an upper, outlet end 70. In this embodiment, the gas release subsystem need not include a valve 42 as shown in the embodiment of FIG.s 6A and 7A. Instead, excess pressure in the accumulator 12 may be relieved by allowing at least some gas to exit the accumulator 12 via the liquid supply conduit 40.

[0167] When the system 10J is operating under normal operating conditions, the lower end 64 of the liquid supply conduit 40 is submerged in the liquid layer 16, which isolates the liquid supply conduit 40 from the gas layer 14. If the pressure within the accumulator 12 increases beyond a desired operating threshold, water may be forced from the accumulator 12 and into the shaft 18 via the liquid supply conduit 40. As water exits the accumulator 12, the height of the liquid layer 16 may drop to a level at which the lower end 64 of the liquid supply conduit 40 is at least partially exposed. This may allow some of the gas from the compressed gas layer 14 to flow into the liquid supply conduit 40 and escape the accumulator 12, thereby reducing the pressure within the accumulator 12. In this arrangement, the liquid supply conduit 40 also functions as the auxiliary gas release conduit 45. Gas flowing through the liquid supply conduit 40 / auxiliary gas release conduit 45 may then escape into the interior of the shaft 18 and form expanding gas bubbles as described herein. In this embodiment, the gas release subsystem is configured so that the lower end 68 of the guide conduit 53 is positioned to capture at least some of the gas exiting the liquid supply conduit 40 / auxiliary gas release conduit 45, and to contain the gas as described in relation to the embodiment of FIG.s 6A and 7A. This embodiment may eliminate the need to incorporate a separate valve 42, and associated actuators, etc., which may help simplify the system 10J (for example as compared to system 10A) and may help reduce the number of openings that are to be provided in the bulkhead 24.

[0168] As the pressure within the accumulator 12 drops as a result of the escaping gas, liquid may flow into the accumulator through the liquid supply conduit 40 and the level of the liquid in the liquid layer 16 may rise to cover the lower end 64 of the liquid supply conduit 40. This can re-isolate the compressed gas layer 14 from the liquid supply conduit 40, and may stop the release of gas via the liquid supply conduit 40.

[0169] Optionally, a gas release system and suitably configured guide conduit 53 may also be used with the vertically oriented bulkhead 24 of the embodiment of FIG. 27 and / or with other embodiments of partitions, such as the projection shown in the embodiment of FIG. 28.Thermal Storage Subsystem

[0170] Optionally, some embodiments of the compressed gas energy storage system may include a thermal storage subsystem that can be used to absorb heat from the compressed gas that is being directed into the accumulator 12 (i.e. downstream from the compressor 112), sequester at least a portion of the thermal energy for a period of time, and then, optionally, release the heat back into gas that is being extracted / released from the accumulator 12 (i.e. upstream from the expander 116). In such examples, the gas may exit the compressor / expander subsystem 100, after being compressed, at an exit temperature of between about 180°C and about 300°C and may be cooled by the thermal storage subsystem to a storage temperature that is less than the exit temperature, and may be between about 30°C and about 60°C in some examples.

[0171] FIG. 8 is a sectional view of components of a compressed gas energy storage system 10B, according to an alternative embodiment. Compressed gas energy storage system 10B is similar to compressed gas energy storage systems 10 and / or 10A, with the addition of a thermal storage subsystem 120 that is provided in the gas flow path between the compressor / 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 / expander subsystem 100 includes an upper portion 22A that extends between the compressor / expander subsystem 100 and thermal storage subsystem 120, and a lower portion 22B that extends between thermal storage subsystem 120 and accumulator 12.

[0172] 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). 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. In the illustrated embodiment, the thermal storage subsystem 120 is located underground, which may help reduce the use of above-ground land, and 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 otherheat 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.

[0173] In general, as gas is compressed by the compressor / 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 10).

[0174] Similarly, during an expansion cycle as gas is released from accumulator 12 towards compressor / 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 / 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 storage 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.

[0175] 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 someembodiments 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, Texas.

[0176] In embodiments of the thermal storage subsystem 120 employing sensible heat storage, pressurized water, or any other suitable fluid and / or coolant, may be employed as the sensible heat storage medium. Such water is pressurized and maintained at an operating pressure that is sufficient to generally keep the water in its liquid phase during the heat absorption process. 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.

[0177] 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 programme to match desired and / or required operating conditions.

[0178] Optionally, at least some of the gas conduit 22 may be external the shaft 18 so that it is not submerged in the water 20 that is held in the shaft 18. This may help insulate such portions of the gas conduit 22, and may help reduce heat transfer between the gas within the conduit 22 and the water 20. This may be particularly useful for portions of the gas conduit 22 that extend between the compressor / expander subsystem 100 and the thermal storage subsystem 120, as it may be generally desirable in some embodiments to transfer as much excess heat from the gas to the thermal storage subsystem 120, and reduce the likelihood of heat being transferred / lost in the water 20. Similar considerations can apply during the expansion stage, as it may be desirable for the warmed gas to travel from the thermal storage subsystem 120 to the compressor / expander subsystem 100 at a desired temperature, and while reducing the heat lost in transit.

[0179] FIG. 9 is a schematic representation of a compressed gas energy storage system 10C, according to an alternative embodiment. Compressed gas energy storage system 10C is similar to the other compressed gas energy storage systems described herein, but is configured so that the upper portion 22A of the gas conduit 22 that conveys compressed gas between the thermal storage subsystem 120 and the compressor / expander subsystem 100 extends through the ground 200, and not through shaft 18 and water 20. Additional variations are possible.

[0180] Furthermore, while in embodiments illustrated the thermal storage subsystem 120 receives compressed gas from, or provides compressed gas to, the compressor / expander subsystem 100, alternatives are possible in which thermal storage is more tightly integrated with multiple stages of compressor 112 and multiple stages of expander 116 so as to store thermal energy between stages. This may be done to enable the pieces of equipment at downstream stages of compressor 112 and expander 116 to receive and handle compressed gas at a temperature that is within their most efficient operating ranges. For example, thermal storage subsystem 120 components may be positioned in the same or analogous manner as, and optionally in combination with, the heat exchangers 500a, 500b, 500c, etc. shown in the embodiments of FIG.s 11A-15 and as described herein. This may help facilitate heat transfer and / or storage at two or more stages in the process, which may help improve system efficiency.

[0181] Referring to FIG. 16, another example of a thermal storage subsystem 120 is immersed in the liquid 20 within the shaft 18 on supports 121 A and 121B and conveys air from and to the compressor / expander subsystem 100 for storing and releasing heat from and to the conveyed air. In this arrangement, the thermal storage subsystem 120 exchanges heat between thermal storage material within the thermal storage subsystem 120 and the air being conveyed therethrough, thereby to deliver heat-exchanged air A’ to the gas layer 14 in accumulator 12. In this embodiment, the thermal storage subsystem 120 has a single stage (for use with the single-stage compressor / expander subsystem 100) but includes a combination of multiple latent (L) and sensible (S) material sections.

[0182] In this embodiment, each of the latent material sections contains a respective amount of phase change material (PCM) and the sensible material section contains a respective amount of water or other liquid material, solid thermal mass or any other material that is suitable for absorbing heat. The amount and type of material is preferably established / selected for a given embodiment based on durations of storage and release phases of the specific compressed air energy storage system. This may help ensure that the time taken for the PCM to change phase or the liquid to heat up or cool down while storing or releasing heat is generally “matched” to the timing of the phase. This may help facilitate relatively efficient usage of the material itself for the heat storage and release function, as compared to using a PCM material that is too slow, or too quick to respond.

[0183] Referring also to FIG. 17, optionally, an insulating “jacket” 125 (shown in dotted lines to not occlude portions of the thermal storage subsystem 120) can be wrapped around an upper portion of thermal storage subsystem 120 to provide some of thermal insulation between the liquid 20 in shaft 18 and the thermal storage subsystem 120 thereby to promote rapid heatstratification, which may help increase the performance of a PCM heat storage system. As described above, air A from the ambient entering compressor / expander subsystem 100 can be conditioned to become air A’ (see FIG. 11 A and 1 IB) prior to its entry to the compressor 112 by passing the air through thermal storage subsystem 120 thereby to cause the air A’ to be at a temperature suited for an efficient operating range of a particular stage of compressor 112.

[0184] Optionally, the controller 118 may also be configured to change the condition of the thermal storage subsystem 120 so as to change the nature of the heat being exchanged between air coming through the thermal storage subsystem 120 into the compressor 112 and the thermal storage material in the thermal storage subsystem 120, or to change routing of air to the compressor 112 so that it is not passing through thermal storage subsystem 120.

[0185] FIG. 18 is a schematic view of components of an alternative compressor / expander subsystem 100 for a compressed gas energy storage system 10, with multiple compression stages and each is associated with a respective stage of a thermal storage subsystem 120. In particular, during a compression (storage) phase, incoming air from the ambient A is conveyed first, optionally via a heat exchanger to modify the temperature of the incoming air, into compressor 112a driven by motor 110a for a first stage of compression. Following the first stage of compression, air A is then conveyed through a first stage 120a of a thermal storage subsystem 120 to store heat removed from air A, 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 stages of the thermal storage subsystem 120 such as second stage 120b of thermal storage subsystem 120 to store heat in the respective stages to be conditioned to be air A”. A last stage of the thermal storage subsystem 120 is represented in this example as stage 120x which stores heat from the compressed air compressed by compressor 112x driven by motor 11 Ox thereby to be conditioned to be air A’”. Following this xthstage of compression and thermal storage, the air A” ’ is conveyed down into accumulator 12 as has been described above with respect to other embodiments. The heat stored in the stages of the thermal storage subsystem 120 during a storage phase may be stored entirely for re-incorporating into air being released during a release phase as will be described, 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. It should be noted that, while three stages of compression with respective thermal storage stages are shown in FIG. 6, 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, inalternative 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 its heat content prior to entering a compressor, rather than a heat exchanger that might dissipate the heat from the system.

[0186] FIG. 19 is a schematic view of components of an alternative compressor / expander subsystem for a compressed gas energy storage system, with multiple expansion stages each associated with a respective stage of a thermal storage subsystem 120. In particular, during an expansion (release) phase, compressed air A released from accumulator 12 is first conveyed through a first stage 120a of a thermal storage subsystem 120 to incorporate heat from stage 120a into the air being conveyed thereby to be conditioned as air A’. Air A’ is presented to a first expander 116a driving a generator 114a for a first stage of expansion. Following the first stage of expansion, air A’ is then conveyed through a second stage 120b of thermal storage subsystem 120 to incorporate stored heat into the air being conveyed thereby to be conditioned to be air A”, which is then conveyed into expander 116b driving generator 114b for a second stage of expansion. Following the second stage of compression, air A” is then conveyed through any additional stages of the thermal storage subsystem 120. A last stage of the thermal storage subsystem 120 is represented in this example as stage 120x which stores heat and releases the stored heat into compressed air being conveyed through stage 120x thereby to be conditioned to be air A’”. Following this Xthstage of expansion and heat release from thermal storage, the air A” ’ is conveyed to the ambient atmosphere A as has been described above with respect to other embodiments. The heat stored in the stages of 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. It should be noted that, while three stages of expansion with respective thermal storage stages are shown in FIG. 19, 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. Furthermore, in alternative embodiments, air being expanded (decompressed) may pass through heat exchanger as described herein, to gather heat rather than through a thermal storage subsystem or stage thereof to increase its heat content prior to entering an expander.

[0187] FIG. 20 is a schematic view of components of an alternative compressor / expander subsystem for a compressed gas energy storage system, with pairs of compression and expansion stages each associated with a respective stage of the thermal storage subsystem 120. In this embodiment, a given phase of the thermal storage subsystem 120 is used during both the compression and expansion stages, by routing air being conveyed into the accumulator 12 through the thermal storage subsystem 120 to remove heat from the air either prior to a subsequent stage of compression or prior to storage, and routing air being conveyed out of accumulator 12 through the thermal storage subsystem 120 to add heat to the air either after release from accumulator or after a stage of expansion. In a sense, therefore, pairs of compression and expansion stages share a stage 120a, 120b, 120x of the thermal storage subsystem 120 and airflow is controlled using valves V, as shown in the FIG. 20. This embodiment is appropriate where the “same” heat stored from compressed air being conveyed towards the accumulator 12 during a storage phase is to be released into the air being released from the accumulator 12 during a release phase.

[0188] FIG. 21 is a schematic view of components of the alternative compressor / expander subsystem of FIG. 20, showing airflow during an expansion (release) phase from storage through multiple expander stages and multiple respective stages of the thermal storage subsystem 120. In this phase, through control of valves V, airflow is directed through multiple expansion stages in a manner similar to that shown in FIG. 19. The dashed lines show multiple compression stages the airflow to which is prevented during an expansion phase by the control of valves V.

[0189] FIG. 22 is a schematic view of components of the alternative compressor / expander subsystem of FIG. 20, showing airflow during a compression (storage) phase from the ambient A through multiple compressor stages and multiple respective stages of the thermal storage subsystem 120. In this phase, through control of valves V, airflow is directed through multiple compression stages in a manner similar to that shown in FIG. 18. The dashed lines show multiple expansion stages the airflow to which is prevented during the compression phase by the control of valves V.

[0190] FIG. 23 is a sectional view of components of an alternative compressed gas energy storage system 10D, according to an embodiment. In this embodiment, compressed gas energy storage system 10D is similar to the other embodiments of the compressed gas energy storage systems described herein. However, in this embodiment the thermal storage subsystem 120 is located within the accumulator 12 and is immersed within the compressed gas in compressed gas layer 14. The thermal storage subsystem 120 may be positioned within the accumulator 12during construction via the opening 27 that is thereafter blocked with bulkhead 24 prior to filling shaft 18 up with liquid 20. The thermal storage subsystem 120 can thus be designed to allow for the construction, insulation, etc. to be completed prior to placement within the accumulator 12 and / or is constructed in easily assembled components within the accumulator 12. This allows for the units to be highly insulated and quality-controlled in their construction, which enables the thermal storage subsystem 120 to be generally independent of the accumulator 12, with the exception of anchoring support (not shown).

[0191] Optionally, a regulating valve 130 associated with the interior of thermal storage subsystem 120 may be provided and configured to open should the pressure within the thermal storage subsystem 120 become greater than the designed pressure-differential between its interior and the pressure of the compressed gas layer 14 in the surrounding accumulator 12. Pressure within the thermal storage subsystem 120 may be maintained at a particular level for preferred operation of the latent or sensible material. For example, heated water as a sensible material may be maintained at a particular pressure. The regulating valve 130 may open to allow the pressurized gas in the interior to escape to the accumulator 12 and can close once the pressure differential is lowered enough to reach a designated level. In an alternative embodiment, such a regulating valve may provide fluid communication between the interior of the thermal storage subsystem 120 and the ambient A at the surface thereby to allow gas to escape to the ambient rather than into the accumulator 12. While thermal storage subsystem 120 is shown entirely immersed in the compressed gas layer 14, alternative thermal storage subsystems 120 may be configured to be immersed partly or entirely within liquid layer 16.

[0192] FIG. 24 is a sectional view of components of an alternative compressed gas energy storage system 10E, according to another alternative embodiment. In this embodiment, compressed gas energy storage system 10E is similar to above-described compressed gas energy storage systems. However, the thermal storage subsystem 120 is located within an isobaric pressurized chamber 140 within ground 200 that may be maintained at the same pressure as is accumulator 12, or a pressure that is substantially similar to the accumulator pressure or optionally at a pressure that is less than or greater than the accumulator pressure. Optionally, the thermal storage subsystem 120 may be positioned within the pressurized chamber 140 during construction via an opening that is thereafter blocked so the chamber 140 may be pressurized to a working pressure that is, preferably, greater than atmospheric pressure. The thermal storage subsystem 120 can thus be designed to allow for the construction, insulation, etc. to be completed prior to placement within the chamber 140 and / or is constructed in easily assembled components within the chamber 140. This allows for the units to be highlyinsulated and quality-controlled in their construction, which enables the thermal storage subsystem 120 to be generally independent of the chamber 140, with the exception of anchoring support (not shown). A regulating valve 130 associated with the interior of thermal storage subsystem 120 is provided and configured to open should the pressure within the thermal storage subsystem 120 become greater than the designed pressure-differential between the interior and the surrounding pressurized chamber 140. Pressure within the thermal storage subsystem 120 may be required to be maintained at a particular level for optimal operation of the latent or sensible material. For example, heated water as a sensible material may be required to be maintained at a particular pressure. The regulating valve 130 opens to allow the pressurized gas in the interior to escape to the pressurized chamber 140 and will close once the pressure differential is lowered enough to reach a designated level. In an alternative embodiment, such a regulating valve 130 may provide fluid communication between the interior of the thermal storage subsystem 120 and the ambient A at the surface thereby to allow gas to escape to the ambient rather than into the pressurized chamber 140.

[0193] Locating the thermal storage subsystem 120 above the accumulator 12, and thus physically closer to the compression / expansion subsystem 100, may help reduce the length of piping required, which may help reduce the costs of piping, installation and maintenance, as well as reduced fluid-transfer power requirements.

[0194] While the embodiment of compressed gas energy storage system 10E includes an isobaric pressure chamber 140, alternatives are possible in which the chamber 140 is not strictly isobaric. Furthermore, in alternative embodiments the pressurized chamber 140 may be in fluid communication with gas layer 14 and thus can serve as a storage area for compressed gas being compressed by compressor / expander subsystem 100 along with accumulator 12. In this way, the pressure of the gas in which the thermal storage subsystem 120 is immersed can be maintained through the same expansions and compressions of gas being conveyed to and from the accumulator 12.

[0195] Furthermore, while in embodiments described above thermal storage subsystem 120 is buried below-ground, it will be understood that such a thermal storage subsystem 120 may be above-ground in tanks and / or may be below ground in a cavern that is connected to shaft 18 but is partitioned off after construction.Heat Exchangers

[0196] Optionally, the compressed gas storage systems 10 described herein may be provided with one or more heat exchangers (or the like) that can be incorporated into thecompressor / expander subsystem 100, for example to help adjust the temperature of the gas as it passes through the compressor 112 and / or expander 116, and optionally as it travels between two or more compression and / or expansion stages. Such heat exchangers can be of any suitable type and can be placed in any suitable location within the system 10, and optionally can be positioned inside the shaft 18 and at least partially submerged within the water 20 therein such that the water 20 can operate as a heat source / sink for the exchangers.

[0197] As shown in FIG. 10, one example of a heat exchanger 500 is immersed in the liquid 20 within the shaft 18, and is positioned upstream from the compressor / expander subsystem 100- such that ambient air A to travels through the heat exchanger 500 prior to reaching the compressor / expander subsystem 100. The heat exchanger 500 exchanges heat between the liquid 20 in the shaft 18 and the air being conveyed by the heat exchanger 500, and can deliver heat-exchanged (i.e., warmed or cooled) air A’ to the compressor / expander subsystem 100.

[0198] In this embodiment, the heat exchanger 500 comprises a radiator 504 having an air path immersed in the liquid 20 within the shaft 18. An air input conduit 502 extends from outside of the liquid 20 to the radiator 504 to receive and convey atmospheric air A to an air path of the radiator. In this embodiment, a rain cover and dust fdter can be provided to protect the opening of air input conduit 502.

[0199] An air output conduit 506 extends from the radiator 504 to receive and convey the atmospheric air after heat exchange from the air path to the compressor / expander subsystem 100. In this embodiment, the radiator 504 is constructed of generally thermally conductive piping that can be suitable for exposure to the water 20 and for use in the expected temperature, flow and corrosion conditions. In this embodiment, the piping is made of stainless steel, but other materials may be used, such as other metals, plastic, combinations thereof and the like.

[0200] Optionally, the radiator 504 may be suspended within shaft 18 using suspension brackets (not shown) affixed to the inner surface of the wall of shaft 18. In this embodiment, radiator 504 is mounted on brackets with removeable pins, or other such detachable coupling, to allow for the removal of the radiators for servicing without the need to remove the liquid in shaft 18. In an alternative embodiment, radiator 504 may be hung from a weight-bearing bar or bars extending across the shaft 18, and can be un-hung and pulled out of shaft 18 for maintenance or replacement. In an embodiment, radiator 504 is preferably shaped so that, despite being placed in shaft 18, it does not unduly inhibit flow of water between accumulator 12 and replenishment conduit 58. As such, it may be generally vertically positioned in the shaft as shown in the figures thereby to take up little cross-sectional area of the shaft 18. However, in other embodiments the radiator 504 may be oriented horizontally to double as a grating ofsorts to prevent large objects accidentally entering shaft 18 from above from sinking down to the bottom of shaft 18.

[0201] Optionally, in some embodiments the heat exchanger 500 that is provided upstream from the compressor 112 need not be positioned within the shaft 18, and may be located in another suitable location. In such embodiments, the heat exchanger 500 may still be fluidly connected to the interior 54 of the shaft 18, and may be configured to utilize water from within the shaft 18 as one stream in the heat exchanger 500. This can help facilitate the exchange of heat between the air entering the compressor 112 and the water within the shaft 18. The heat exchanger 500 in such embodiments may be any suitable type of heat exchanger that can facilitate transfer of heat between a gas stream and a liquid stream including, for example, a direct contact heat exchanger, a tube and shell heat exchanger, a plate and frame heat exchanger, boiler, evaporative cooler, spiral heat exchanger, hair pin heat exchanger and the like.

[0202] In the illustrated example, the compressor / expander subsystem 100 includes a compressor 112 of single or multiple stages, driven by a motor 110 that is controlled using controller 118. Compressor 112 is driven by motor 110 during an accumulation stage of operation, and draws in atmospheric air A, compresses the air, and forces it down into gas conduit 22 for storage in accumulator 12 (via thermal storage subsystem 120 in embodiments including same). Compressor / expander subsystem 100 also includes an expander 16 driven by compressed air exiting from gas conduit 22 during an expansion stage 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. As described above, air A from the ambient entering compressor / expander subsystem 100 is conditioned to become air A’ prior to its entry to the compressor 112 by passing the air through heat exchanger 500 thereby to cause the air A’ to be at a temperature suited for an efficient operating range of a particular stage of compressor 112.

[0203] Controller 118 may also be configured to change the condition of the heat exchanger(s) 500 so as to change the nature of the heat being exchanged between air coming through the heat exchanger 500 into the compressor 112 and the liquid 20 in the shaft 18, or to change routing of air to the compressor 112 so that it is not passing through heat exchanger 500.

[0204] FIG. 11A is a schematic view of components of an alternative compressor / expander subsystem 100 for a compressed gas energy storage system, with multiple compression stages each associated with a respective heat exchanger. In particular, during a compression (storage)phase, incoming air from the ambient A is conveyed first through a first heat exchanger 504a to exchange heat with water 20 in shaft 18, thereby to be conditioned to be air A’ which is then conveyed into compressor 112a driven by motor 110a for a first stage of compression. Following the first stage of compression, air A’ is then conveyed through a second heat exchanger 504b to exchange heat with water 20 in shaft 18, 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 compression stages including respective heat exchangers. A last heat exchanger is represented in this example as heat exchanger 504x which exchanges heat with water 20 in shaft 18, thereby to be conditioned to be air A’” which is then conveyed into compressor 112x driven by motor HOx for an “Xth” stage of compression. Following this xthstage of compression, the air is conveyed down into accumulator 12 as has been described above with respect to other embodiments.

[0205] Optionally, one or more heat exchangers 500 may be positioned in other locations within the fluid flow path, and need not be disposed within the shaft 18. In some configurations, a heat exchanger 500 that is external the shaft 18 may be fluidly connected to the shaft 18, such as via suitable fluid conduits, such that the heat exchanger 500 can still be configured to exchange heat between the air and the water 20 within the shaft 18. For example, as shown in the alternative embodiment of FIG. 11B.

[0206] It should be noted that, while three stages of compression with respective heat exchangers are shown in FIG.s 11A and 11B, it will be understood that 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 heat exchangers. The heat exchangers used in such embodiments may be of any suitable type, including direct contact, tube and shell and plate frame heat exchangers.

[0207] Referring to FIG. 11B, in this example the heat exchanger 500a is outside the shaft 18 and is not submerged in the water 20. Preferably the heat exchanger 500a can be located proximate the first compressor 112a. This heat exchanger 500a is preferably configured as a direct contact heat exchanger, in which air that is drawn in from the ambient environment A is brought into direct physical contact with liquid, which in this case is water 20 drawn from the shaft 18. A gas inlet 510 is configured to draw in air from the environment, and a gas outlet 512 is connected in fluid connection upstream from the first compressor 112a. A water inlet is fluidly connected to the water 20 via an inlet conduit 516 to draw water from the shaft 18. Preferably, water exiting the heat exchanger 500a can be returned to the shaft 18 via a wateroutlet conduit 518. Alternatively, water can be supplied to the heat exchanger 500a from a source other than the shaft 18, and water exiting the heat exchanger 500a may be directed to an alternative drain or sink, rather than being returned to the shaft 18. The direct contact heat exchanger 500a can be configured as a co-flow (air and water flow in the same direction) or counterflow (air and water flow in opposite directions) heat exchanger, and may include two or more stages if desired.

[0208] FIG. 12 is a schematic view of components of an alternative compressor / expander subsystem for a compressed gas energy storage system, with multiple expansion stages each associated with a respective heat exchanger. In particular, during an expansion (e.g., release) phase, compressed air released from accumulator 12 is conveyed first through a first expander 116a driving generator 114a and then through a first heat exchanger 505a to exchange heat with water 20 in shaft 18, thereby to be conditioned to be air A’”. Following the first stage of expansion, air A’” is then conveyed through a second expander 116b driving generator 114b and then through a second heat exchanger 505b to exchange heat with water 20 in shaft 18, thereby to be condition to be air A”. Following the second stage of expansion, air A” is then conveyed through any additional expansion stages including respective heat exchangers. A last heat exchanger is represented in this example as heat exchanger 505x which enables air A” to exchange heat with water 20 in shaft 18 after an “xth” stage of expansion, namely passing through expander 116x driving generator 114x, thereby to be conditioned to be air A’ which is then conveyed out of the system into the ambient A. It should be noted that, while three stages of compression with respective heat exchangers are shown in FIG. 12, it will be understood that 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 heat exchangers.

[0209] FIG. 13 is a schematic view of components of an alternative compressor / expander subsystem for a compressed gas energy storage system, with pairs of compression and expansion stages each associated with a respective heat exchanger. In this embodiment, a common heat exchanger 504a, 504b, 504c, is used during both the compression and expansion stages for each compression / expansion stage, respectively, for example by routing air being conveyed into accumulator through the heat exchanger and routing air being conveyed out of accumulator through the heat exchanger. In a sense, therefore, pairs of compression and expansion stages share a heat exchanger and airflow is controlled using valves V, as shown in FIG. 13.

[0210] FIG. 14 is a schematic view of components of the alternative compressor / expander subsystem of FIG. 13, showing airflow during an expansion (release) phase from storagethrough multiple expanders and heat exchangers. In this phase, through control of valves V, airflow is directed through multiple expansion stages in a manner similar to that shown in FIG. 12. The dashed lines show multiple compression stages the airflow to which is prevented during an expansion phase by the control of valves V.

[0211] FIG. 15 is a schematic view of components of the alternative compressor / expander subsystem of FIG. 13, showing airflow during a compression (storage) from the ambient through multiple compressors and heat exchangers. In this phase, through control of valves V, airflow is directed through multiple compression stages in a manner similar to that shown in FIG.s 11A and 11B. The dashed lines show multiple expansion stages the airflow to which is prevented during the compression phase by the control of valves V.

[0212] The various configurations for exchanging more or less heat described above may be used in various combinations with each other or with other configurations for achieving a desired heat transfer.

[0213] Furthermore, alternatives are possible in which the air being conveyed from the ambient A to the compressor / expander subsystem 100 may be routed from time to time, perhaps in view of weather changes or the needs of the operation, so as to bypass any heat exchanger that is immersed in the liquid within the shaft and instead be conveyed more directly from the ambient to the compressor / expander subsystem 100.

[0214] In embodiments disclosed herein, the compressed gas energy storage system is operated as an isobaric or near-isobaric whereby a differential between the pressure being exerted by the quantity of liquid within the shaft downwards on the bulkhead and the pressure exerted by the compressed gas within the accumulator upwards on the bulkhead is maintained below a threshold level by conveying compressed gas between the compressor / expander subsystem and the gas layer and by conveying liquid between the shaft and the liquid layer. However, alternatives are possible in which the bulkhead or other dividing structure between the accumulator and the shaft is strong and sufficiently affixed in place such that the pressure differential can be larger.Multiple Gas Access Points

[0215] Optionally, embodiments of the compressed gas energy storage system may be configured to have two or more gas inlet / outlet points. For example, two, three, or more gas supply conduits 22 could be associated with a common accumulator 12, and could be in communication with a common compressed gas layer 14. Preferably, the two or more gas supply conduits can be spaced apart from each other so as to provide access to the compressedgas layer 14, and the energy stored therein, from multiple physical locations on the surface, such as in different areas of an industrial facility, neighbourhood, city, county or the like (depending on the size of the underlying accumulator 12, which may be several kilometers in length in some examples). This may help facilitate connection to one or more power sources and / or power loads that are spaced apart from each other, and may help provide access to the compressed gas layer 14 at a desired location that is proximate where the electrical energy can be provided to, or drawn from, the power grid.

[0216] Optionally, one or more of the gas supply conduits 22 may be spaced apart from the water supply / replenishment conduit 58 and / or the water source / sink 150. For example, in some circumstances the location of the water source / sink 150 may be impossible or impractical to change, such as if the source / sink 150 is a naturally occurring lake as shown. To help provide the water used by the system, the water supply / replenishment conduit 58 may be provided at one end of the accumulator 12 that is physically proximate the lake, or is otherwise well suited to facilitate the liquid transfer between the shaft 18 and lake 150 (such as where flow form the source / sink lake 150 into the shaft 18 is driven by gravity). However, it may be desirable to provide at least one gas inlet / outlet point in another portion of the accumulator 12, that is close to a connection to the grid and is relatively remote from the lake 150. As the water within the accumulator 12, forming layer 16, may tend to flow relatively freely within the interior 23 of the accumulator 12, it may be reasonable in most embodiments to utilize a single shaft 18 and water supply / replenishment conduit 58 to provide substantially all of the water required for the entire accumulator 12. Alternatively, two or more shafts 18, and associated water supply / replenishment conduits 58, may be provided.

[0217] Optionally, the components of the compressor / expander subsystem 100 may be positioned together in the same physical location, as shown in some of the embodiments herein. Alternatively, the components of the compressor / expander subsystem 100 may be separated from each other, and provided in different locations. For example, the compressor 112 may be located in one location (such as in a region with relatively clean air that is suitable to draw in for compression) and may be connected to the gas layer 14 by a first gas conduit 22, while the expander 116 may be located in another location (such as in the interior of a city and close to a grid connection) and may be connected to the gas layer 14 by a separate, second gas conduit 22. In some embodiments, multiple compressors 112 and / or expanders 116 may be provided at multiple different locations, and each may be connected to the gas layer 14 via respective gas conduits 22.

[0218] For example, FIG. 25 is a schematic representation of another embodiment of a compressed gas energy storage system 10F, that is analogous to the other compressed gas energy storage systems described herein, and which includes three, spaced apart gas supply conduits 22 that are in communication with a common accumulator 12. In this example, one of the gas supply conduits 22 (on the right as illustrated) is provided within the shaft 18 and close to the water supply / replenishment conduit 58, whereas the other two gas supply conduits 22 are spaced apart from each other and are do not pass through the shaft 18.

[0219] FIG. 26 is a schematic representation of another embodiment of a compressed gas energy storage system 10G, that is analogous to the other compressed gas energy storage systems described herein, and in which the components of the compressor / expander subsystem 100 are separated and distributed across the surface. In this example, a compressor 112, and associated equipment, is provided proximate to the shaft 18, and compressed gas is forced down the associated gas supply conduit 22 and into the gas layer 14. The other two gas conduits 22 are each connected to a respective expander 116 to extract gas from the gas layer 14. In this example, gas is supplied into the accumulator through one gas conduit 22, and extracted via other conduits 22. In some embodiments, one gas conduit 22 and expander 116 may be provided at each location where it would be desirable to extract energy and / or connect to the grid (such as providing one gas conduit 22 and expander 116 for each building that requires power, etc.), without needing to provide multiple compressors 112 and draw in air from multiple locations. In such examples, the capacity of the compressor 112 (or multiple compressors / stages at a given location) may be greater than the capacity of any one of the multiple expanders 116 provided. Optionally, each compressor 112 and / or expander 116 may be independently operable.Fuel Gas Plant Integration

[0220] Referring to FIG. 29A, an example embodiment of a fuel assisted and hydrostatically compensated compressed gas energy system is provided. A fuel gas combustion chamber 400 and a separate gas turbine train 440 are integrated into the system. In the illustrated example, the system also includes a fuel gas combustion subsystem 401, an example of which is further described in FIG. 33A.Such a configuration allows for the facility to operate in two different modes: (1) a standard (e.g. not fuel assisted) compressed air energy storage (referred to herein as “CAES”) mode, which is operable as an energy storage facility; and (2) a fuel assisted mode, which is operable as a fuel fired power plant that may provide one or more of: i) long duration (e.g. indefinite) back-up capability (e.g. outputting energy (electricity) after the accumulator isdepleted by generating power through the combustion of fuel gas); ii) increased duration capability (e.g. by generating power through the combustion of fuel during a discharge mode so that the overall system output (electricity) can be maintained at a given output level for a longer duration than relying solely on the compressed gas energy storage system; and iii) increased power output capability (e.g. by generating power through the combustion of fuel gas during a discharge mode to that the overall system power output (electricity) is at a greater output level than could be produced solely by the compressed gas energy storage system in the standard CAES mode).

[0221] In the illustrated example, fuel combustion chamber 400 is configured to combust Hydrogen. It will be appreciated that in one or more alternative embodiments, fuel combustion chamber 400 may be configured to combust one or more alternative gas fuels, such as natural gas, biogas, syngas, landfill gas, sewer gas, digester gas, or the like. Alternatively, fuel combustion chamber 400 may be configured to combust a liquid fuel or a solid fuel.

[0222] The system shown in FIG. 29A allows the facility to transition between energy storage operation as a daily or inter-day storage asset, and one or more ’fuel assisted’ modes where the system can effectively operate as a fuel-fired gas plant and utilized as e.g., an ultralong duration power generation asset. The fuel assisted compressed gas energy system, for example, uses the compressor train infrastructure and bypasses the accumulator 12 to drive a dedicated expander (or expander train) 440 during fuel assisted mode operations. When in a fuel assisted mode, the facility may operate without any constraint on duration beyond the availability of fuel gas. In some cases, this would allow the facility to continue outputting power even when the state of compressed gas charge for the facility is too low to otherwise operate.

[0223] In FIG. 29A, the system includes a fuel gas combustion chamber 400 that is positioned downstream of one or more compressors 112a, 112b, and 112x of the compressor system of the compressed gas energy system. The fuel gas combustion chamber 400 is used to heat the received compressed gas stream 432a (i.e., to add thermal energy to the compressed gas stream 432a) to generate a thermally enhanced compressed gas stream 434.

[0224] The illustrated system also includes a selector mechanism 414 that is operable to direct the compressed gas stream 432 from the one or more compressors 112a, 112b, and 112x to the fuel gas combustion chamber 400 or direct the compressed gas stream 432 to the accumulator 12 (e.g., via heat exchanger 120x). In the illustrated example, selector mechanism 414 includes an inlet 415 for receiving the compressed gas stream 432 of the compressor system, a first outlet 417 for outputting compressed gas stream 432 to the accumulator 12, anda second outlet 419 for outputting compressed gas stream 432a to a gas inlet 406 of the fuel gas combustion chamber 400. Selector mechanism 414 may include one or more valves and or / other fluid flow control devices, as known in the art.

[0225] In the illustrated example, selector mechanism 414 is operable to switch between two modes: a first mode that directs flow from the inlet 415 to the first outlet 417, thereby directing a flow of the compressed gas stream 432 to the accumulator for storage (or to an intermediary device between the accumulator and the selector mechanism, such as heat exchanger 120x); and a second mode that directs flow from the inlet 415 to the second outlet 419, thereby directing a flow of the compressed gas stream 432a to the fuel gas combustion system.

[0226] In operation, selector mechanism 414 allows the system to selectively switch between at least two operating modes: a first operating mode that includes compressing gas and storing the compressed gas in the accumulator (e.g. when the selector mechanism is in the first mode), which may be referred to as a CAES mode; and a second operating mode that includes compressing gas, adding thermal energy to the compressed gas using the fuel gas combustion chamber, and using the thermally enhanced compressed gas stream to drive a turbine system to generate electrical energy (or other power) when the selector mechanism is in the second mode.

[0227] For example, in the second operating mode, compressed gas 432 passes through the selector mechanism 414 and then through the fuel gas combustion chamber 400. The combustion of fuel gas in the fuel gas combustion chamber produces thermal energy (heat) that is transferred to the output gas stream of the compressor system, which generates the thermally energy enhanced gas stream 434. In the illustrated example, fuel gas combustion chamber 404 includes a chamber that receives fuel gas 422 through a fuel gas inlet 402, an igniter for combusting the fuel gas in the chamber, and a fuel gas outlet 404 that outputs fuel gas combustion products 424. In some embodiments, fuel gas combustion products 424 may be directed through a flue gas exhaust stack (not shown) prior to being released into the atmosphere. The fuel gas combustion chamber also includes a gas inlet 406 for receiving the compressed gas 432, a gas outlet 408 for outputting the compressed gas, and a fluid flow path (e.g., conduit, tubing, and / or one or more sub-chambers) that directs the flow of compressed gas from the gas inlet 406 to the gas outlet 408. The fluid flow path also promotes heat transfer of heat produced from combustion of the fuel gas to the compressed gas 423 as it travels from the gas inlet 406 to the gas outlet 408.

[0228] In some embodiments, the fuel gas combustion chamber operates as an indirect fired combustion system. That is, the combustion gases (fuel gas and exhaust gases) do not mix withthe compressed gas stream 432 and are separated using e.g., a heat exchanger such that the exhaust gases require an exhaust stack or flue. Such an example is illustrated in FIG. 29 A. In an example embodiment, the thermally enhanced gas stream 434 is passed through a turbine system 440 (also herein called an expander system or expander train) that generates electrical energy. The decompressed gas 436 output by the turbine 440 is vented to atmosphere. In some embodiments, decompressed gas 436 may be directed through a flue gas exhaust stack (not shown) prior to being released into the atmosphere.

[0229] In an alternative embodiment, decompressed gas 436 is directed 438 through at least one of the expanders 116a, 116b, 116x in the expander train.

[0230] In an alternative embodiment, one or more of the turbine stages 116a, 116b, 116x are configured to be in parallel with the turbine 440. In other words, a portion of thermally enhanced gas stream 434 is directed through turbine 440, and another portion of thermally enhanced gas stream 434 is directed through one or more of expanders 116a, 116b, 116x.

[0231] It will be appreciated that fuel gas 422 may be stored in a fuel gas storage tank 420, and the flow of fuel gas to the fuel gas combustor 400 can be regulated using a valve or other suitable flow control device(s).

[0232] In some examples, the fuel gas combustion chamber 400, the fuel gas storage tank 420, and the dedicated turbine 440 may be characterized as being part of the fuel gas subsystem 401.

[0233] It will be appreciated that the heat exchangers 120a, 120b, 120c may take on different forms and configurations. For example, for the gas, the heat exchangers 120a, 120b, 120c may be connected in series so that the gas (e.g., air) flows in series amongst the heat exchangers from atmospheric environment to the accumulator and from the accumulator back to atmospheric environment. For thermal transfer fluid, the heat exchangers 120a, 120b, 120c may be connected in parallel to a first thermal transfer fluid tank (e.g., for storing relatively hotter thermal transfer fluid) and are also connected in parallel to a second thermal transfer fluid tank (e.g., for storing relatively colder thermal transfer fluid). Heat may be transferred from the gas to the thermal transfer fluid, or from the thermal transfer fluid to the gas, via the heat exchangers 120a, 120b, 120c. Details of such athermal transfer fluid subsystem are shown in FIG. 30 and, in some cases, the thermal transfer fluid subsystem is incorporated into the system of FIG. 29 A.

[0234] Turning to FIG. 29B, an alternative example a fuel assisted and hydrostatically compensated compressed gas energy system is provided which is a variation of the system described in FIG. 29 A. In the embodiment illustrated in FIG. 29B, fuel gas combustionchamber 400 is illustrated as a ‘direct fired’ combustor. The fuel gas combustion chamber 400 does not include an outlet dedicated to exhaust fuel gas combustion products. Instead, the fuel gas chamber 400 combusts the fuel gas 422, and the combustion products (which may include un-combusted fuel gas) are mixed or otherwise combined with the compressed gas stream to create thermally enhanced gas stream 434. Further details about fuel combustion chamber 400 are illustrated in FIG. 33B.Thermal Fluid Heat Boost

[0235] Turning to FIG. 30, another example embodiment of a fuel assisted compressed gas energy system is provided. The illustrated system includes a fuel gas combustion chamber 400, which is used to produce thermal energy (heat) to enhance the thermal energy (e.g., temperature) of thermal fluid used for heat storage during charging operations. This would allow the facility to either (a) output greater power while maintaining the same air flow rates or (b) operate for a longer duration with lower air flow rates, when compared to a CAES compression or decompression operation that is not boosted by heat produced by fuel gas combustion. In the example embodiment shown in FIG. 30, the system includes a fuel gas combustion subsystem 401, an example of which is illustrated in FIG. 33A.

[0236] For example, to achieve this boost in power output or energy capacity, heat from fuel gas combustion is transferred to the hot thermal fluid stream before it is used to heat the air in the heat exchangers 120a, 120b, 120x during a discharge operation.

[0237] A fuel assisted gas energy system, according to an example embodiment in FIG. 30, includes a fuel gas combustion chamber 400 that is used to add a heat boost to thermal fluid passing through the one or more heat exchangers, which in turn adds a heat boost to the gas discharged from the accumulator, and which in turn increases the electrical energy or other energy output by the expander system when.

[0238] In the illustrated example, the one or more heat exchangers are in fluid communication with a first thermal fluid storage tank 500 and a second thermal fluid storage tank 510. The first thermal fluid storage tank 500 holds a thermal fluid that is at a higher temperature than thermal fluid held in the second thermal fluid storage tank 510. The thermal fluid passes through the one or more heat exchangers 120a, 120b, 120x when travelling from the first thermal fluid storage tank 500 to the second thermal fluid storage tank 510 when compressed gas from the accumulator is being to atmosphere through the expander system to generate electricity. The fuel gas combustion chamber 400 is positioned between the first thermal fluid storage tank 500 and the one or more heat exchangers 120a, 120b, 120x, suchthat, during discharge of stored compressed gas (also called decompression), the thermal fluid travels from the first thermal fluid storage tank 500 to the fuel gas combustion chamber 400, where thermal energy is added from the fuel gas combustion chamber 400 to the thermal fluid, generating thermally enhanced thermal fluid. The thermally enhanced thermal fluid (alternatively referred to as heat boosted thermal fluid) then travels from the fuel gas combustion chamber 400 to the one or more heat exchangers 120a, 120b, 120x where thermal energy is transferred from the heat boosted thermal fluid to the gas stream being discharged. It will be appreciated that the thermal energy added to the gas stream while being discharged will lead to increased electrical energy or power output as the gas stream passes through the expander system (e.g., the expander train 116a, 116b, 116x).

[0239] In an example embodiment, the fuel gas combustion chamber 400 includes a fuel gas inlet 402 that receives fuel gas from a fuel gas tank 420, and a fuel gas outlet 404 that outputs fuel gas combustion products. The fuel gas combustion chamber also includes a first thermal fluid port 407 (which could be an inlet or an outlet depending on the direction of flow of the thermal fluid) and a second thermal fluid port 409 (which could correspondingly be an outlet or an inlet depending on the direction of flow of the thermal fluid). The fuel gas combustion chamber 400 also includes a fluidic path (e.g., that includes tubing or one or more subchambers, or both) that directs the flow of the thermal fluid from the first thermal fluid port 407 to the second thermal fluid port 409 when the thermal fluid flows out of the first thermal fluid storage tank 500, and vice versa when the thermal fluid flows in the opposite direction into the first thermal fluid storage tank 500.

[0240] In the example illustrated in FIG. 30, the first thermal fluid port 407 is operating as an inlet and receives the thermal fluid that flows out of the first thermal fluid storage tank 500. The fluid path within the fuel gas combustion chamber 400 facilitates heat transfer of heat produced from combustion of the fuel gas to the thermal fluid passing from the first thermal fluid port 407 to the second thermal fluid port 409 (which in FIG. 30 is operating as an outlet). The combustion of fuel gas in the fuel gas combustion chamber produces thermal energy (heat) that is transferred to the exiting thermally enhanced thermal fluid stream 524, which then flows in parallel to each of the heat exchangers 120a, 120b, 120x. The heat from the thermally enhanced thermal fluid stream is transferred to the compressed gas flowing through these heat exchangers. This generates the thermally energy enhanced gas stream flowing through the expanders 116a, 116b, 116x, which in turn increases or boosts the electrical power or other type of power produced by the expanders 116a, 116b, 116x compared to a system that does not have the fuel gas combustion chamber 400. The thermal fluid 526 exiting or flowing out fromthe heat exchangers 120a, 120b, 120x, which has less thermal energy than the thermally enhanced thermal fluid stream 524, is directed into the second thermal fluid storage tank 510.

[0241] In the decompression operation shown in FIG. 30, compressed gas 532 from the accumulator 12 is directed through the heat exchanger 120x and absorbs thermal energy. The compressed gas 534 exiting the heat exchanger 120x is directed into the expander 116a, where it undergoes expansion to generate power. The compressed gas 536 exiting the expander 116a is directed into the heat exchanger 120b where it absorbs thermal energy. The compressed gas 538 exiting the heat exchanger 120b is directed into the expander 116b, where it undergoes expansion to generate power. The compressed gas 540 exiting the expander 116b is directed into the heat exchanger 120a where it absorbs thermal energy. The compressed gas 542 exiting the heat exchanger 120a is directed into the expander 116x, where it undergoes expansion to generate power. The decompressed gas 544 exiting expander 116x is vented to atmosphere.

[0242] In an example embodiment, the system shown in FIG. 30 is selectively operable in: (i) a standard discharge mode, in which no thermal energy from fuel gas combustion is added to the compressed gas exiting the first thermal fluid storage tank 500, and (ii) a fuel boosted discharge mode, in which thermal energy from fuel gas combustion is added to the compressed gas exiting the first thermal fluid storage tank as described above.

[0243] In an example embodiment of the standard discharge mode, the compressed gas in the first thermal storage tank 500 passes through the fuel gas combustion chamber 400 in the absence of fuel gas being combusted therein, which results in no transfer of additional heat. In an example embodiment of the corresponding fuel boosted discharge mode, the compressed gas in the first thermal storage tank 500 passes through the fuel gas combustion chamber 400 in the presence of fuel gas being combusted therein, which results in transfer of additional heat.

[0244] Other configurations of switching between the two modes are applicable to the principles described herein. For example, a three-way valve connected to a diverging fluid path may be used to bypass compressed gas from the first thermal storage tank 500 around the fuel gas combustion chamber 400; or the three-way valve, which is also connected to the fuel gas combustion chamber 400, may direct the compressed gas from the first thermal storage tank 500 to and through the fuel gas combustion chamber 400.

[0245] FIG. 31 shows another example embodiment of a system with thermal fluid heat boosting that includes a fuel gas combustion chamber 400. In this embodiment, the first stage of the compression / expansion subsystem 100 may include a first compressor 112a and a first expander 116a. A different embodiment of a thermal storage subsystem used in the embodiment in FIG. 31 includes a corresponding heat exchanger 1635a that may be used duringboth the compression and expansion stages of the first compressor 112a and first expander 116a. The second stage of compression / expansion may include a second compressor 112b and a second expander 116b. The thermal storage subsystem includes, in this embodiment, a corresponding second heat exchanger 1635b that may be used during both the compression and expansion stages of the second compressor 112b and second expander 116b. The third stage of compression / expansion may include a third compressor 112c and a third expander 116c. The thermal storage subsystem includes, in this embodiment, a corresponding third heat exchanger 1635c which may be used during both the compression and expansion stages of the third compressor 112c and third expander 116c. Embodiments of four or more heat exchangers could also be employed in alternative embodiments.

[0246] The three compression / expansion stages of this embodiment 112a-112c and 116a- 116c, and corresponding heat exchangers 1635a-1635c may be arranged in series such that when the compression / expansion subsystem 100 (and the overall system 10) is operated in its compression / charging mode air may move sequentially through the first compressor 112a and first heat exchanger 1635a, to the second compressor 112b and second heater exchanger 1635b, to the third compressor 112c and third heat exchanger 1635c, then on to the accumulator 12.

[0247] Alternatively, when the compression / expansion subsystem 100 is in its expansion / discharging mode, air may be removed from the accumulator 12 and conveyed sequentially through the third heat exchanger 1635c and third expander 116c, to the second heat exchanger 1635b and second expander 116b, to the first heat exchanger 1635a and first expander 116a.

[0248] As further shown in FIG. 31, the thermal storage subsystem that is used with the compression / expansion subsystem 100 may include a cold fluid source reservoir 1606 that includes a tank 1703 and a hot fluid storage reservoir 1610 that includes a tank 1701. During compression / charging operations, relatively cooler thermal fluid 1704 from the cold fluid storage chamber 1703 may be directed through each of the three heat exchangers 1635a, 1635b, and 1635c, where the relatively cooler thermal fluid will absorb heat / thermal energy from the gas stream passing through each heat exchanger and the resulting, relatively warmer thermal fluid 1702 will be sent from the outlet of each heat exchanger 1635a, 1635b, and 1635c to a common hot thermal fluid storage tank 1701. In a preferred embodiment, each of the three heat exchangers 1635a, 1635b, and 1635c will be configured to operate under analogous conditions i.e., each heat exchanger may be configured to transfer about the same amount of heat to / from the thermal fluid passing through the exchanger. Configuring the heat exchangers 1635a, 1635b, and 1635c to operate under analogous conditions may help facilitate an arrangement inwhich heat exchanger 1635a, 1635b, and 1635c can be provided with incoming, relatively cool thermal fluid from a common thermal fluid source reservoir 1606 (i.e., tank 1703 and associated piping network) and may also help facilitate an arrangement in which the relatively warmer thermal fluid exiting each heat exchanger 1635a, 1635b, and 1635c has been heated to substantially the same exit temperature, and can be collected via a common piping network and stored in a common storage reservoir 1610 (i.e. tank 1701). During discharging, this can also allow the relatively warm thermal fluid to be drawn from the common storage reservoir 1606 and supplied as the inlet fluid to the heat exchanger 1635a, 1635b, and 1635c and used to rewarm the gas exiting the accumulator 12 prior to each stage of expansion the expansion (discharging) operating mode.

[0249] In FIG. 31, the components of the three-stage compressor / expander subsystem with three corresponding heat exchangers 1635a, 1635b and 1635c, also show airflow and thermal fluid flow during an expansion (discharging) mode from storage through multiple expander stages and multiple respective heat exchangers of the thermal storage subsystem.

[0250] In this discharging mode, compressed air may be conveyed from the accumulator 12 to the third heat exchanger 1635c with a specific set of conditions at the discharge mode gas inlet 1714 (which is the gas outlet when in the charging mode).

[0251] As the gas passes through the third heat exchanger 1635c, thermally enhanced thermal fluid exiting from the fuel gas combustion chamber 400 enters the third heat exchanger 1635c via the discharge liquid inlet 1720 and has an inlet temperature and may be passed through the third heat exchanger 1635c and interact, directly or indirectly, with the gas such that the relatively warmer thermal fluid transfers heat to the gas as it travels through the third heat exchanger 1635c and before it enters the third expander 116c.

[0252] In particular, relatively warmer thermal fluid 1702 from the tank 1701 is conveyed into a first port 407 of the fuel gas chamber 400, which in the discharging mode acts as an inlet, and passes through a fluid path connecting to a second port 409 of the fuel gas chamber 400, which in the discharging mode acts as an outlet. While the relatively warmer thermal fluid 1702 passes through the fuel gas chamber 400, fuel gas 422 is passed into the fuel gas chamber 400 and is combusted to generate thermal energy. The thermal energy is transferred to the relatively warmer thermal fluid 1702 that is passing through the fuel gas chamber 400, resulting in thermally enhanced thermal fluid being directed to the third heat exchanger 1635c.The resulting cooler fluid 1704 may then exit the third heat exchanger 1635c and be transferred to a source reservoir 1606.

[0253] Gas exiting the third heat exchanger 1635c when in the discharge mode will have set of conditions at gas outlet 1715 such that the outlet gas pressure at 1715 is about the same as the gas inlet pressure at 1714 and the gas outlet temperature at 1715 is higher than the gas inlet temperature at 1714 and as near to the fluid storage temperature as the heat exchangers will facilitate. In some cases, the temperature is preferably within 5 - 25°C or less. Gas exiting the third heat exchanger 1635c may then be conveyed through the third expander 116c and then into the second heat exchanger 1635b with a specific set of conditions at discharge gas inlet 1716. In certain preferred embodiments gas exiting the first expander 116c may have a resulting pressure at 1716 of around 11 - 18 bar and is around a third of the ratiometric pressure reduction from the accumulator pressure to ambient pressure (i.e. the accumulator gauge pressure to the power of %) and an inlet gas temperature at 1716 of around 30 - 70 C.

[0254] As the gas passes from inlet 1716 through the second heat exchanger 1635b, relatively warmer thermal fluid 1702 from a storage reservoir 1610 can enter via warm liquid inlet 1721 may be passed through the second heat exchanger 1635b and interact, directly or indirectly with the gas such that the warmer fluid 1702 transfers heat to the gas. The resulting cooler fluid 1704 may then be transferred to a cold source reservoir 1606.

[0255] Gas exiting the second heat exchanger 1635b will have specific set of conditions at discharging gas outlet 1717 such that the outlet gas pressure at 1717 is about the same as the gas inlet pressure at 1716 and the gas outlet temperature at 1717 is higher than the gas inlet temperature at 1716 and as near to the fluid storage temperature as the heat exchangers will facilitate, preferably within 5 - 25°C. or less. Gas exiting the second heat exchanger 1635b may then be conveyed through the second expander 116b and then into the first heat exchanger 1635a with a set of inlet conditions at liquid inlet 1718. In certain preferred embodiments gas exiting the second expander 116b may have a resulting pressure at 1718 of around 2 - 5 bar and is around two-thirds of the ratiometric pressure reduction from the accumulator pressure to ambient pressure (i.e. the accumulator gauge pressure to the power of !4) and an inlet gas temperature at 1718 of around 30 - 70°C or lower.

[0256] As the gas flows from the inlet 1718 through the first heat exchanger 1635a, relatively warmer thermal fluid 1702 from the storage reservoir 1610 can enter via liquid inlet 1722 having inlet conditions and may be passed through the first heat exchanger 1635a to interact with, directly or indirectly with the gas such that the relatively warmer thermal fluid 1702 transfers heat to the gas. The resulting cooler fluid 1704 may then be transferred to the source reservoir 1606.

[0257] Gas exiting the first heat exchanger 1635a, via gas outlet 1719 will have outlet conditions such that the outlet gas pressure at 1719 is at or about the same as the gas inlet pressure 1718, and the gas outlet temperature at 1719 is higher than the gas inlet temperature at 1718 and is as near to the fluid storage temperature as the heat exchangers will facilitate, preferably within 5 - 25° C. or less. The gas may then be routed to the first expander 116a.

[0258] While illustrated as above ground tanks / containers, one or both of the source reservoir 1606 and storage reservoir 1610 may be located underground (or at least partially underground) and may have different physical arrangements. For example, one or both of the source reservoir 1606 and storage reservoir 1610 may be configured to include caverns (lined or unlined) and / or may be provided by repurposed parts of the system 10 that can be adapted to hold pressurized water at the desired storage temperature and pressure. Similarly, the fuel gas storage tank 420 may be located above ground or may be located underground (or partially underground). In another example embodiment, the fuel gas storage tank 420 may be configured to include caverns (lined or unlined).

[0259] While in the embodiment shown in FIG. 31 the compressors 112 and expanders 116 are shown as separate devices, in other embodiments the system 10 may include combined apparatuses that can function in both compressor and expander modes if suitable.Air Heat Boost

[0260] Turning to FIG. 32, another example embodiment of a fuel assisted compressed gas energy system is provided. The illustrated system includes a fuel gas combustion chamber 400, which is used to produce a power boost on discharge by supplementing the energy of discharge air stream from the cavern (or another type of accumulator 12) with heat from fuel gas combustion. This would allow the system to output a greater total power when compared to an operation that is not assisted by fuel gas combustion. In an example embodiment, the system shown in FIG. 32 includes a fuel gas combustion subsystem 100, an example of which is further described in FIG. 33A.

[0261] To achieve this boost in output, in an example embodiment, heat from fuel gas combustion is injected into the air stream on discharge after it has been heated by the thermal fluid in the heat exchanger 120x. This ‘heat boosted’ air is then used to drive a dedicated expander train, which includes the turbine or expander 440, for fuel gas boosted operation. An alternative embodiment would utilize at least some of the existing turbine stages either in parallel or series with the dedicated turbine for fuel boosted operations.

[0262] In an example embodiment, the system is selectively operable in either operate in standard discharge mode or operate in fuel boosted discharge mode.

[0263] In FIG. 32, a fuel assisted gas energy system includes a fuel gas combustion chamber 400 that is positioned downstream of the accumulator 12 in a decompression fluid path. Compressed gas that is stored in the accumulator 12 is output from the accumulator as a compressed gas stream 600, and the compressed gas stream passes through a heat exchanger 120x to absorb heat, resulting in an initially heated and compressed gas stream 602. The initially heated and compressed gas stream 602 is conveyed to a gas inlet 406 and through the fuel gas combustion chamber to a gas outlet 408. The fuel gas combustion chamber 400 adds thermal energy to the initially heated and compressed gas stream by combusting fuel gas that is passed into the fuel gas inlet 402. This results in generating a thermally enhanced compressed gas stream 606 that has more thermal energy compared to the initially heated and compressed gas stream 604. This addition of thermal energy is also referred to herein as a heat boost.

[0264] The thermally enhanced compressed gas steam 606 is then passed through a turbine system 440, which generates electrical power or another type of power. In an example embodiment, the fuel gas combustion chamber operates as an ‘indirect fired’ combustor, and does not mix the hydrogen combustion products 424 with the compressed gas stream during heating.

[0265] The system also includes a selector mechanism 474 that is positioned between an output of the heat exchanger 120x and the gas inlet 406 of the fuel gas combustion chamber 400. The selector mechanism 474 includes an inlet 602 and two outlets 477, 479, and is configured to be operated or controlled to direct fluid from the inlet 602 to the outlet 477, or from the inlet 602 to the outlet 479. The selector mechanism 474 is operable to switch between at least two modes. In a first operating mode, the selector mechanism 474 directs flow of the initially heated and compressed gas stream to an expander system (e.g., an expansion train that includes gas stream 622, expander 116a, gas stream 624, heat exchanger 120b, gas stream 626, expander 116b, gas stream 628, heat exchanger 120a, gas stream 630, heat exchanger 116x, and gas stream 632) that generates electrical power or another type of power without fuelcombustion-sourced thermally enhanced compressed gas. This first mode corresponds with the inlet 602 being in fluid communication with the outlet 477, as controlled by the selector mechanism 474. In a second operating mode, the selector mechanism 474 directs flow of the preliminary heated compressed gas stream 602 to the inlet 406 of the fuel gas combustion chamber 400. This second mode corresponds with the inlet 602 being in fluid communication with the outlet 479, as controlled by the selector mechanism 474.

[0266] In other words, the selector mechanism allows the system to controllably switch between at least two operating modes: a first operating mode that includes a decompression process in which compressed gas from the accumulator drives an expander system to generate electricity without the added thermal energy of the fuel gas combustion chamber (i.e. when the selector mechanism is selected to be in the first mode); and a second operating mode that includes the compressed gas powering a dedicated turbine that is powered by fuel-combustion- sourced thermally enhanced compressed gas (i.e. when the selector mechanism is selected to be in the second mode).Fuel Gas Combustion Subsystem

[0267] Turning to FIG. 33A, an example of a fuel gas combustion subsystem 401 is shown. It includes the fuel gas combustion chamber 400. The fuel gas combustion chamber 400 includes a body 702 that defines an interior chamber 704 into which fuel gas 422 is directed. Combustion of fuel gas in the interior chamber 704 - which may be initiated by an ignitor 720 - produces fuel gas combustion product 424. The ignitor 720 may be controlled by a control device 722. In an example embodiment, control device 722 is configured to activate and deactivate the ignitor 720. In a further example embodiment, control device 722 is in data communication with the controller 118.

[0268] Turning to FIG. 33B, another example of a fuel gas combustion subsystem 401 is shown, but it includes a different type of fuel gas combustion chamber 400, which is also sometime called a flueless gas combustion chamber or ‘direct fired’ combustion chamber. Fuel gas 422 is ignited and combusted, which generates fuel gas combustion products. The combustion products are mixed with a gas stream that is input through the inlet or port 406. The mixture of the gas and the combustion product is output from the outlet or port 408. In an example aspect, the mixture exiting from the outlet or port 408 is considered a thermally enhanced gas stream.Further Examples

[0269] Turning to FIGS. 34 and 35, another example of a fuel assisted compressed gas energy system is shown schematically, and referred to generally as 800a. In this example, one of the compressors in the compression train of the gas energy system is used to supply compressed air to the fuel gas combustion subsystem, and a separate expander is provided to generate power (electricity) from the heated compressed gas stream exiting the fuel gas combustion chamber.

[0270] In the example illustrated in FIG. 34, the system is shown operating to provide energy for an indefinite duration (presuming an adequate supply of fuel gas). Compressor 112a (which draws in ambient air) is used to provide a compressed gas stream 432 to fuel gas combustion chamber 400. Fuel gas is separately provided to the combustion chamber 400 where it is combusted, and heat is transferred to the compressed gas stream 432 to produce a heated compressed gas stream 434. The heated compressed gas stream 434 is directed to a separate, dedicated expander 440 (which is not one of the one or more expander of the expansion train), where it is used to drive the expander 440 (e.g., a turbine) to generate power, before being released to the atmosphere.

[0271] Preliminary modeling of the system shown in FIG. 34 was conducted with the following parameters:With these parameters, and assuming compressor 112a draws 44.5 MW and has an adiabatic effect of 90.5%, and expander 440 can generate 144.5 MW (at an isotropic efficiency of 90%), the net overall power generation is expected to be 100 MW (144.5 MW generated - 44.5 MW to drive compressor).

[0272] For comparison, modelling of the system FIG. 34 when operating without the combustor, where compressed air from the accumulator is expanded through the expansion train (i.e., a standard CAES mode) was conducted with the following parameters:93%), expander 116b can generate 37.7 MW (at an isotropic efficiency of 91%), and expander 116a can generate 62.7 MW (at an isotropic efficiency of 90.7%). Accordingly, the net overall power generation is expected to be 132 MW (31.6 + 37.7 + 62.7).

[0273] It will be appreciated that this preliminary modelling is a non-limiting example and was conducted for particular equipment configurations (e.g. compressor size, number of compressors, expander size, number of expanders, dedicated expander size, etc.) and that the parameters of a given system consistent with the embodiments disclosed herein will vary based on e.g. the design requirements for the overall system (e.g. power output, physical plant size, etc.), and / or on the particular equipment configurations for a given system.

[0274] In the example illustrated in FIG. 35, the system is shown operating to provide energy using compressed gas stored in accumulator 12 (in this example a subterranean cavern). Accumulator 12 is used to provide a compressed gas stream 432 to fuel gas combustion chamber 400. Fuel gas is separately provided to the combustion chamber 400 where it is combusted, and heat is transferred to the compressed gas stream 432 to produce a heated compressed gas stream 434. The heated compressed gas stream 434 is directed to expander 440, where it is used to drive the expander (e.g., a turbine) to generate power, before being released to the atmosphere.

[0275] In the illustrated embodiment, compressed gas exiting the accumulator is directed through a heat exchanger (the first heat exchanger 120 of the expansion train) where it is warmed before being directed to the compressed gas stream 432. Additionally, or alternatively, compressed gas exiting the accumulator may be directed through a separate, dedicated heat exchanger (not shown) before being directed to the compressed gas stream 432. Alternatively, compressed gas exiting the accumulator may be directed to fuel gas combustion chamber 400 without passing through a heat exchanger.

[0276] System 800a may have one or more advantages. For example, using one of the compressors in the compression train of the gas energy system to provide compressed gas tothe combustion system may reduce cost and / or increase efficiency. Additionally, or alternatively, using components of the compression train of the gas energy system to provide compressed gas to the combustion system may reduce the number of pieces of equipment on site, which may reduce the overall physical footprint of the system. Additionally, or alternatively, utilizing more of the compressor train may lead to a larger mass flow, which may in turn lead to more power being generated in addition to a potentially reduced cost / MW.

[0277] Turning to FIGS. 36 and 37, another example of a fuel assisted compressed gas energy system is shown schematically, and referred to generally as 800b. In this example, one of the compressors in the compression train of the gas energy system is used to supply compressed air to the fuel gas combustion subsystem, a separate expander is provided to generate power (electricity) from the heated compressed gas stream exiting the fuel gas combustion chamber, and the exhaust gas from the separate expander is directed to one of the expanders in the expansion train of the gas energy system where it is further expanded to generate additional power.

[0278] In the example illustrated in FIG. 36, the system is shown operating to provide energy for an indefinite duration (presuming an adequate supply of fuel gas). Compressor 112a (which draws in ambient air) is used to provide a compressed gas stream 432 to fuel gas combustion chamber 400. Fuel gas is separately provided to the combustion chamber 400 where it is combusted, and heat is transferred to the compressed gas stream 432 to produce a heated compressed gas stream 434. The heated compressed gas stream 434 is directed to expander 440, where it is used to drive the expander (e.g., a turbine) to generate power. The gas exiting expander 440 is directed to expander 116a where it is further expanded before being released to the atmosphere.

[0279] In the example illustrated in FIG. 37, the system is shown operating to provide energy using compressed gas stored in accumulator 12 (in this example a subterranean cavern). Accumulator 12 is used to provide a compressed gas stream 432 to fuel gas combustion chamber 400. Fuel gas is separately provided to the combustion chamber 400 where it is combusted, and heat is transferred to the compressed gas stream 432 to produce a heated compressed gas stream 434. The heated compressed gas stream 434 is directed to expander 440, where it is used to drive the expander (e.g., a turbine) to generate power, before being released to the atmosphere. The gas exiting expander 440 is directed to expander 116a where it is further expanded before being released to the atmosphere.

[0280] In the embodiment illustrated in FIG. 37, compressed gas exiting the accumulator is directed through a heat exchanger (the first heat exchanger 120 of the expansion train) whereit is warmed before being directed to the compressed gas stream 432. Additionally, or alternatively, compressed gas exiting the accumulator may be directed through a separate, dedicated heat exchanger (not shown) before being directed to the compressed gas stream 432. Alternatively, compressed gas exiting the accumulator may be directed to fuel gas combustion chamber 400 without passing through a heat exchanger.

[0281] In the example illustrated in FIGS. 36 and 37, the system is shown with an optional Heat Recovery Steam Generator (HRSG) positioned downstream of expander 440 and upstream of expander 116a. Such a HRSG may optionally be used to recover heat from the gas exiting expander 440 before this gas is further expanded in expander 116a. This heat recovery may improve the overall efficiency and / or power output of the system. Additionally, or alternatively, a HRSG may be positioned downstream of expander 116a, depending on the expected temperature of the gas exiting expander 116a. It will be appreciated that an HRSG may include both a heat recovery vessel, as well as a steam system to drive a steam driven expander turbine.

[0282] System 800b may have one or more advantages. For example, using one of the compressors in the compression train of the gas energy system to provide compressed gas to the combustion system and using one of the expanders in the expansion train of the gas energy system to generate additional power may reduce cost and / or increase efficiency. Additionally, or alternatively, using components of the compression train and expansion train of the gas energy system as part of the combustion system may reduce the number of pieces of equipment on site, which may reduce the overall physical footprint of the system. Additionally, or alternatively, utilizing more of the compressor and / or expander train may lead to a larger mass flow, which may in turn lead to more power being generated in addition to a potentially reduced cost / MW and / or cost / MWh.

[0283] Turning to FIGS. 38 and 39, another example of a fuel assisted compressed gas energy system is shown schematically, and referred to generally as 800c. In this example, one of the compressors in the compression train of the gas energy system is used to supply compressed air to the fuel gas combustion subsystem, and one of the expanders in the expansion train of the gas energy system is used to generate power (electricity) from the heated compressed gas stream exiting the fuel gas combustion chamber.

[0284] In the example illustrated in FIG. 38, the system is shown operating to provide energy for an indefinite duration (presuming an adequate supply of fuel gas). Compressor 112a (which draws in ambient air) is used to provide a compressed gas stream 432 to fuel gas combustion chamber 400. Fuel gas is separately provided to the combustion chamber 400 where it iscombusted, and heat is transferred to the compressed gas stream 432 to produce a heated compressed gas stream 434. The heated compressed gas stream 434 is directed to expander 116a, where it is used to drive the expander (e.g., a turbine) to generate power, before being released to the atmosphere.

[0285] In the example illustrated in FIG. 39, the system is shown operating to provide energy using compressed gas stored in accumulator 12 (in this example a subterranean cavern). Accumulator 12 is used to provide a compressed gas stream 432 to fuel gas combustion chamber 400. Fuel gas is separately provided to the combustion chamber 400 where it is combusted, and heat is transferred to the compressed gas stream 432 to produce a heated compressed gas stream 434. The heated compressed gas stream 434 is directed to expander 116a, where it is used to drive the expander (e.g., a turbine) to generate power, before being released to the atmosphere.

[0286] In the embodiment illustrated in FIG. 39, compressed gas exiting the accumulator is directed through a heat exchanger (the first heat exchanger 120 of the expansion train) where it is warmed before being directed to the compressed gas stream 432. Additionally, or alternatively, compressed gas exiting the accumulator may be directed through a separate, dedicated heat exchanger (not shown) before being directed to the compressed gas stream 432. Alternatively, compressed gas exiting the accumulator may be directed to fuel gas combustion chamber 400 without passing through a heat exchanger.

[0287] System 800c may have one or more advantages. For example, using one of the compressors in the compression train of the gas energy system to provide compressed gas to the combustion system and using one of the expanders in the expansion train of the gas energy system to generate power may reduce cost and / or increase efficiency. Additionally, or alternatively, using components of the compression train and expansion train of the gas energy system as part of the combustion system may reduce the number of pieces of equipment on site, which may reduce the overall physical footprint of the system. Additionally, or alternatively, utilizing more of the compressor and / or expander train may lead to a larger mass flow, which may in turn lead to more power being generated in addition to a potentially reduced cost / MW.

[0288] Turning to FIG. 40, another example of a fuel assisted compressed gas energy system is shown schematically, and referred to generally as 800d. In this example, a fuel gas is used to heat water (or another suitable working fluid) in a boiler 900 to generate steam. The steam exiting boiler 900 is directed into expanders 116a, 116b, and 116x, where it is used to drive theexpanders (turbines) to generate power (electricity). Water (or another working fluid) exiting the expanders 116a, 116b, and 116x is recirculated back to boiler 900 in a closed loop.

[0289] In the embodiment illustrated in FIG. 40, steam is circulated through each of the expanders in the illustrated expander train. It will be appreciated that in one or more alternative embodiments, steam may only be circulated through a subset (e.g., one or more, but not all) of the expanders in an expander train.

[0290] System 800d may have one or more advantages. For example, using components of the expansion train of the gas energy system as part of the boiler system may reduce the number of pieces of equipment on site, which may reduce the overall physical footprint of the system.

[0291] Turning to FIG 41, another example of a fuel assisted compressed gas energy system is shown schematically, and referred to generally as 800e. In this example, one of the compressors in the compression train of the gas energy system is used to supply compressed air to the fuel gas combustion subsystem, one of the expanders in the expansion train of the gas energy system is used to generate power (electricity) from the heated compressed gas stream exiting the fuel gas combustion chamber, and a heat recuperator is used to recover heat from the gas exiting the expander.

[0292] In the example illustrated in FIG. 41 , the system is shown operating to provide energy for an indefinite duration (presuming an adequate supply of fuel gas). Compressor 112a (which draws in ambient air) is used to provide a compressed gas stream 432 to fuel gas combustion chamber 400 after passing through heat recuperator 950, where it is warmed to produce a warmed compressed gas stream 432a. Fuel gas is separately provided to the combustion chamber 400, where it is combusted and heat is transferred to the warmed compressed gas stream 432a to produce a heated compressed gas stream 434. The heated compressed gas stream 434 is directed to expander 116a, where it is used to drive the expander (e.g., a turbine) to generate power. The exhaust gas from expander 116a is directed to heat recuperator 950 to transfer heat to compressed gas stream 432 before being released to the atmosphere. In some embodiments, exhaust gas from expander 116a may be directed through a flue gas exhaust stack (not shown) prior to being released into the atmosphere.

[0293] System 800e may have one or more advantages. For example, using one of the compressors in the compression train of the gas energy system to provide compressed gas to the combustion system and using one of the expanders in the expansion train of the gas energy system to generate power may reduce cost and / or increase efficiency. Additionally, or alternatively, the use of a heat recuperator may improve overall efficiency and / or increase the power output of the system. Additionally, or alternatively, utilizing more of the compressorand / or expander train may lead to a larger mass flow, which may in turn lead to more power being generated in addition to a potentially reduced cost / MW and / or cost / MWh.

[0294] Turning to FIG 42, another example of a fuel assisted compressed gas energy system is shown schematically, and referred to generally as 800f. In this example, three of the compressors in the compression train of the gas energy system are used to supply compressed air to the expansion train of the gas energy system (after passing through a heat recuperator) to generate power (electricity), a gas stream exiting an intermediate expander of the expansion train is provided to a fuel gas combustion chamber, one of the expanders in the expansion train of the gas energy system is used to generate power (electricity) from the heated compressed gas stream exiting the fuel gas combustion chamber, gas exiting the expander is heated using a secondary fuel gas combustor, and a heat recuperator is used to recover heat from the gas exiting the secondary fuel gas combustor.

[0295] In the example illustrated in FIG. 42, the system is shown operating to provide energy for an indefinite duration (presuming an adequate supply of fuel gas). Compressors 112a, 112b, and 112x (and associated heat exchangers 120) are used to provide a compressed gas stream 432 that passes through heat recuperator 950, where it is warmed to produce a warmed compressed gas stream 432a. The warmed compressed gas stream 432a is directed to expander 116x, where it is used to drive the expander (e.g., a turbine) to generate power. The exhaust gas from expander 116x is directed through heat recuperator 950 to recover heat before being directed to expander 116b, where it is used to drive the expander (e.g., a turbine) to generate power. The exhaust gas from expander 116b is directed to fuel gas combustion chamber 400. Fuel gas is separately provided to the combustion chamber 400 where it is combusted, and heat is transferred to the compressed gas stream to produce a heated compressed gas stream 434. The heated compressed gas stream 434 is directed to expander 116a, where it is used to drive the expander (e.g., a turbine) to generate power. The exhaust gas from expander 116a is directed to secondary fuel gas combustion chamber 400’. Fuel gas is separately provided to the combustion chamber 400, where it is combusted and heat is transferred to the expander 116a exhaust gas stream to produce a heated exhaust gas stream 434’ that is directed to heat recuperator 950 to transfer heat to compressed gas stream 432 and to exhaust gas from expander 116b before being released to the atmosphere. In some embodiments, heated exhaust gas stream 434’ may be directed through a flue gas exhaust stack (not shown) prior to being released into the atmosphere.

[0296] In the example illustrated in FIG. 43, the system of FIG. 42 is shown with an optional Heat Recovery Steam Generator (HRSG) positioned downstream of heat recuperator 950. Sucha HRSG may optionally be used to recover heat from the gas exiting heat recuperator 950 before this gas is released to the atmosphere. This heat recovery may improve the overall efficiency and / or power output of the system. Additionally, or alternatively, a HRSG may be positioned downstream of expander 116a, depending on the expected temperature of the gas exiting expander 116a, and / or downstream of secondary fuel gas combustion chamber 400’.

[0297] System 800f may have one or more advantages. For example, using three of the compressors in the compression train of the gas energy system to provide compressed gas to the combustion system and using three of the expanders in the expansion train of the gas energy system to generate power may reduce cost and / or increase efficiency. Additionally, or alternatively, the use of a heat recuperator may improve overall efficiency and / or increase the power output of the system. Additionally, or alternatively, utilizing more of the compressor and / or expander train may lead to a larger mass flow, which may in turn lead to more power being generated in addition to a potentially reduced cost / MW and / or cost / MWh.

[0298] In the example systems 800a, 800b, 800c, and 800f, the first compressor 112a in the compression train is used to provide compressed gas flow to the combustion chamber 400. It will be appreciated that another one, or more than one, of the compressors in a compression train of a gas energy storage system may be used to provide compressed gas flow to the combustion chamber 400 in one or more alternative embodiments.

[0299] Similarly, in the example systems 800b, 800c, and 800e, expander 116a in the expansion train is used to generate power from the heated compressed gas flow exiting the combustion chamber 400 or the compressed gas flow exiting expander 440. It will be appreciated that another one, or more than one, of the expanders in an expansion train of a gas energy storage system may be used to generate power from a compressed gas flow in one or more alternative embodiments.

[0300] In the example systems 800a to 800f, the combustors 400 and 400’ are illustrated as combusting Hydrogen gas. It will be appreciated that one or more other fuel gases (e.g., natural gas, biogas, syngas, landfill gas, sewer gas, digester gas, and the like) may be combusted in addition to, or along with, Hydrogen gas in one or more alternative embodiments.

[0301] In addition, it will be appreciated that fuel gas may be combusted using a direct fired or indirect fired combustion process. Additionally, or alternatively, the fuel gas may be premixed upstream of the combustion chamber.

[0302] For simplicity and clarity of illustration, reference numerals may be repeated among the figures to indicate corresponding or analogous elements. In addition, numerous specific details are set forth to provide a thorough understanding of the subject matter described herein.However, it will be understood by those of ordinary skill in the art that the subject matter described herein may be practiced without these specific details. In other instances, well-known methods, procedures, and components have not been described in detail so as not to obscure the subject matter described herein.

[0303] Various features described herein from different example embodiments can be combined together, although such combinations have not been explicitly described. For example, different embodiments of accumulators or different embodiments of heat exchange systems, or both, can be integrated together with a Hydrogen combustion chamber system according to increase power capacity or energy capacity, or both.

[0304] It will be appreciated that the particular example embodiments shown in the figures and described above are for illustrative purposes only and many other variations can be used according to the example embodiments described herein. Although the above has been described with reference to specific example embodiments, various modifications thereof will be apparent to those skilled in the art as outlined in the appended claims.

Claims

We claim:

1. A compressed gas energy storage system comprising: a compression train comprising one or more compressors, the compression train being configured to draw in and compress ambient air to generate compressed gas; an accumulator positioned downstream of the compression train and configured to selectively receive compressed gas from the compression train for storage and to selectively release stored compressed gas for power generation; an expansion train positioned downstream of the accumulator, the expansion train comprising one or more expanders, the expansion train being configured to receive and expand compressed gas from the accumulator to generate electrical power; a combustor configured to receive compressed gas from at least one of the accumulator and at least one of the one or more compressors of the compression train, and transfer heat generated by combusting a fuel to the received compressed gas; and a dedicated expander configured to receive and expand heated compressed gas exiting the combustor to generate electrical power; wherein the system is selectively operatable in one of: a first mode of operation, in which compressed gas is released from the accumulator to the expansion train to generate a first level of electrical power; and at least one of: a second mode of operation, in which ambient air is drawn in and compressed by the at least one of the one or more compressors of the compression train, directed to the combustor as a compressed gas stream, heated by the combustor to generate a heated compressed gas stream, and the heated compressed gas stream is directed to the dedicated expander to generate a second level of electrical power, and a third mode of operation, in which compressed gas is released from the accumulator to the combustor as a compressed gas stream, heated by the combustor to generate a heated compressed gas stream, and the heated compressed gas stream is directed to the dedicated expander to generate a third level of electrical power.

2. The compressed gas energy storage system of claim 1, wherein the system is selectively operable in the first mode of operation and the second mode of operation.

3. The compressed gas energy storage system of claim 1, wherein the system is selectively operable in the first mode of operation and the third mode of operation.

4. The compressed gas energy storage system of claim 1, wherein the system is selectively operable in the first mode of operation, the second mode of operation, and the third mode of operation.

5. The compressed gas energy storage system of any one of claims 1 to 4, wherein in the second mode of operation, ambient air is compressed by at least two of the one or more compressors of the compression train.

6. The compressed gas energy storage system of any one of claims 1 to 5, wherein in the second mode of operation, a gas stream exiting the dedicated expander is directed to at least one of the one or more expanders in the expansion train to generate additional electrical power.

7. The compressed gas energy storage system of any one of claims 1 to 5, wherein in the third mode of operation, a gas stream exiting the dedicated expander is directed to at least one of the one or more expanders in the expansion train to generate additional electrical power.

8. The compressed gas energy storage system of any one of claims 1 to 7, further comprising a heat recovery steam generator positioned downstream of the dedicated expander.

9. The compressed gas energy storage system of any one of claims 1 to 8, further comprising a heat recuperator positioned downstream of the dedicated expander, the heat recuperator being configured to transfer heat from a gas stream exiting the dedicated expander to the compressed gas stream directed to the combustor from the at least one of the one or more compressors of the compression train.

10. The compressed gas energy storage system of claim 9, further comprising a secondary combustor positioned downstream of the dedicated expander and upstream of the heatrecuperator, the secondary combustor being configured to transfer heat generated by combusting fuel to the gas stream exiting the dedicated expander.

11. The compressed gas energy storage system of claim 9 or claim 10, wherein the heat recovery steam generator is positioned upstream of the heat recuperator.

12. The compressed gas energy storage system of claim 9or claim 10, wherein the heat recovery steam generator is positioned downstream of the heat recuperator.

13. A compressed gas energy storage system comprising: a compression train comprising one or more compressors, the compression train being configured to draw in and compress ambient air to generate compressed gas; an accumulator positioned downstream of the compression train and configured to selectively receive compressed gas for storage and to selectively release stored compressed gas for power generation; an expansion train positioned downstream of the accumulator, the expansion train comprising one or more expanders, the expansion train being configured to receive and expand compressed gas from the accumulator to generate electrical power; and a combustor configured to receive compressed gas from at least one of the accumulator and one of the one or more compressors of the compression train, and transfer heat generated by combusting a fuel to the received compressed gas; wherein one of the one or more expanders in the expansion train is configured to receive and expand heated compressed gas exiting the combustor to generate electrical power; wherein the system is selectively operatable in one of: a first mode of operation, in which compressed gas is released from the accumulator to the expansion train to generate a first level of electrical power; and at least one of: a second mode of operation, in which ambient air is drawn in and compressed by the one of the one or more compressors of the compression train, directed to the combustor as a compressed gas stream, heated by thecombustor to generate a heated compressed gas stream, and the heated compressed gas stream is directed to one of the one or more expanders in the expansion train to generate a second level of electrical power, and a third mode of operation, in which compressed gas is released from the accumulator to the combustor as a compressed gas stream, heated by the combustor to generate a heated compressed gas stream, and the heated compressed gas stream is directed to the one of the one or more expanders in the expansion train to generate a third level of electrical power.

14. The compressed gas energy storage system of claim 13, wherein the system is selectively operable in the first mode of operation and the second mode of operation.

15. The compressed gas energy storage system of claim 13, wherein the system is selectively operable in the first mode of operation and the third mode of operation.

16. The compressed gas energy storage system of claim 13, wherein the system is selectively operable in the first mode of operation, the second mode of operation, and the third mode of operation.

17. The compressed gas energy storage system of any one of claims 13 to 16, wherein in the second mode of operation, ambient air is compressed by at least two of the one or more compressors of the compression train.

18. The compressed gas energy storage system of any one of claims 13 to 17, further comprising a heat recovery steam generator positioned downstream of the one of the one or more expanders in the expansion train.

19. The compressed gas energy storage system of any one of claims 13 to 18, further comprising a heat recuperator positioned downstream of the expansion train, the heat recuperator being configured to transfer heat from a gas stream exiting the one of the one or more expanders in the expansion train to the compressed gas stream directed to the combustor from the at least one of the one or more compressors of the compression train.

20. The compressed gas energy storage system of claim 19, wherein the heat recuperator is further configured to transfer heat from the gas stream exiting the one of the one or more expanders in the expansion train to a flow of gas between two of the one or more expanders in the expansion train.

21. The compressed gas energy storage system of claim 19 or claim 20, further comprising a secondary combustor positioned downstream of the expansion train and upstream of the heat recuperator, the secondary combustor being configured to transfer heat generated by combusting fuel to the gas stream exiting the one of the one or more expanders in the expansion train.

22. The compressed gas energy storage system of any one of claims 19 to 21, wherein the heat recovery steam generator is positioned upstream of the heat recuperator.

23. The compressed gas energy storage system of any one of claims 19 to 21, wherein the heat recovery steam generator is positioned downstream of the heat recuperator.

24. The compressed gas energy storage system of any one of claims 1 to 23, wherein the third level of electrical power is greater than the first level of electrical power.

25. The compressed gas energy storage system of any one of claims 1 to 24, wherein the fuel comprises a fuel gas, and the combustor operates as a direct fired combustor.

26. The compressed gas energy storage system of any one of claims 1 to 24, wherein the combustor operates as an indirect fired combustor.

27. The compressed gas energy storage system of any one of claims 1 to 26, wherein the fuel comprises a fuel gas, and the fuel gas is premixed with air prior to entering the combustor.

28. A compressed gas energy storage system comprising: a compression train comprising one or more compressors, the compression train being configured to draw in and compress ambient air to generate compressed gas;an accumulator positioned downstream of the compression train and configured to selectively receive compressed gas from the compression train for storage and to selectively release stored compressed gas for power generation; an expansion train positioned downstream of the accumulator, the expansion train comprising one or more expanders, the expansion train being configured to receive and expand compressed gas from the accumulator to generate electrical power; a boiler configured to heat a working fluid by combusting a fuel gas to generate steam; and a working fluid circulation system configured to direct steam exiting the boiler to at least one of the one or more expanders of the expansion train, and to recirculate working fluid exiting the at least one of the one or more expanders to the boiler; wherein the system is selectively operatable in one of: a first mode of operation, in which ambient air is drawn in and compressed by the compression train, stored in the accumulator, and released from the accumulator to the expansion train to generate a first level of electrical power; and a second mode of operation, in which the working fluid is heated by the boiler to generate steam, and the steam is directed through the at least one of the one or more expanders to generate a second level of electrical power.

29. A compressed gas energy storage system comprising: a compression train comprising one or more compressors arranged in series, the compression train being configured to draw in and compress ambient air to generate compressed gas; an accumulator positioned downstream of the compression train and configured to selectively receive compressed gas from the compression train for storage and to selectively release stored compressed gas for power generation; an expansion train positioned downstream of the accumulator, the expansion train comprising one or more expanders arranged in series, the expansion train being configured to receive and expand compressed gas from the accumulator to generate electrical power; a heat exchange subsystem, the heat exchange subsystem comprising:one or more intermediate heat exchangers positioned along a gas flow path of the compression train and along a gas flow path of the expansion train, each intermediate heat exchanger configured to: receive compressed gas from an upstream one of the one or more compressors, transfer heat between the received compressed gas and a thermal fluid, and direct thermally treated compressed gas to a downstream one of the one or more compressors, and receive exhaust gas from an upstream one of the one or more expanders, transfer heat between the received exhaust gas and the thermal fluid, and direct thermally treated exhaust gas to a downstream one of the one or more expanders; a terminal heat exchanger positioned along a gas flow path between the compression train and the accumulator and along a gas flow path between the accumulator and the expansion train, the terminal heat exchanger configured to: receive compressed gas from the downstream one of the one or more compressors, transfer heat between the received compressed gas and the thermal fluid, and direct thermally treated compressed gas to the accumulator, and receive compressed gas from the accumulator, transfer heat between the received compressed gas and the thermal fluid, and direct thermally treated compressed gas to the upstream one of the one or more expanders; a first thermal fluid storage tank configured to hold thermal fluid at a first temperature; a second thermal fluid storage tank configured to hold thermal fluid at a second temperature that is lower than the first temperature; a thermal fluid circulation system configured to circulate thermal fluid between the first storage tank and the second storage tank via the one or more intermediate heat exchangers and the terminal heat exchanger in parallel, and a combustor configured to receive thermal fluid from the first thermal fluid storage tank, transfer heat generated by combusting a fuel gas to the received thermal fluid, and direct the heated thermal fluid to the one or more intermediate heat exchangers and the terminal heat exchanger in parallel,wherein the system is selectively operatable in one of: a first mode of operation, in which compressed air is released from the accumulator to the expansion train for expansion while the combustor is inactive to generate a first level of electrical power; and a second mode of operation, in which compressed air is released from the accumulator to the expansion train for expansion while the combustor is active to generate a second level of electrical power.

30. The compressed gas energy storage system of any one of claims 1 to 29, wherein the fuel comprises a fuel gas.

31. The compressed gas energy storage system of claim 30, wherein the fuel gas comprises Hydrogen.

32. The compressed gas energy storage system of claim 31, wherein the fuel gas comprises at least 95% Hydrogen.

33. The compressed gas energy storage system of any one of claims 1 to 32, wherein the compression train comprises three compressors.

34. The compressed gas energy storage system of any one of claims 1 to 33, wherein the expansion train comprises three expanders.

35. The compressed gas energy storage system of any one of claims 1 to 34, wherein the compression train comprises compression train heat exchanges positioned between each of the one or more compressors.

36. The compressed gas energy storage system of any one of claims 1 to 35, wherein the expansion train comprises expansion train heat exchanges positioned between each of the one or more expanders.

37. The compressed gas energy storage system of any one of claims 1 to 36, wherein the accumulator is positioned underground.

38. The compressed gas energy storage system of claim 37, wherein the accumulator is a hydrostatically compensated compressed air energy storage accumulator.

39. The compressed gas energy storage system of claim 38, wherein the accumulator is substantially isobaric.

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