Patent Publication Number: US-11644150-B2

Title: Thermal storage in pressurized fluid for compressed air energy storage systems

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application is a continuation of U.S. patent application Ser. No. 16/492,401 filed Sep. 9, 2019, which is a 371 national stage of International Patent Application No. PCT/CA2018/050282, filed Mar. 9, 2018, which claims priority to U.S. Provisional Patent Application Ser. No. 62/469,264, filed Mar. 9, 2017 and priority to International Patent Application No. PCT/CA2018/050112, filed Jan. 31, 2018, the entirety of these applications being incorporated by reference herein. 
    
    
     FIELD OF THE DISCLOSURE 
     The present disclosure relates generally to compressed gas energy storage, and more particularly to a compressed gas energy storage system such as, for example, one including a hydrostatically compensated, substantially isobaric compressed air energy storage accumulator located underground, the use thereof, as well as a method of storing compressed gas. The present disclosure also relates generally to a system and method for providing a system for keeping a heated fluid, such as water, in a liquid state and at a pressure that allows fluid to accept greater heat to store and release than would be practical under atmospheric conditions. 
     BACKGROUND 
     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. 
     Thus there exists a need for effectively storing the electrical energy produced at a power grid or a renewable source during a non-peak period and providing it to the grid upon demand. 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. 
     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 
     This summary is intended to introduce the reader to the more detailed description that follows and not to limit or define any claimed or as yet unclaimed invention. One or more inventions may reside in any combination or sub-combination of the elements or process steps disclosed in any part of this document including its claims and figures. 
     In accordance with one broad aspect of the teachings described herein, which may be used alone or in combination with any other aspects, a compressed gas energy storage system may include an accumulator having an interior configured to contain compressed gas when in use. A gas compressor/expander subsystem may be spaced apart from the accumulator and may include at least a first compression stage having a gas inlet and a gas outlet in fluid communication with the accumulator interior for conveying compressed gas to the accumulator when in a charging mode and from the accumulator when in a discharging mode. A thermal storage subsystem may include at least a first storage reservoir disposed at least partially under ground and configured to contain a thermal storage liquid at a storage pressure that is greater than atmospheric pressure, a liquid passage having an inlet connectable to a thermal storage liquid source and configured to convey the thermal storage liquid to the liquid reservoir, and a first heat exchanger provided in the liquid inlet passage and in fluid communication between the first compression stage and the accumulator. Whereby when the compressed gas energy storage system is in the charging mode thermal energy is transferred from a compressed gas stream exiting the gas compressor/expander subsystem to the thermal storage liquid. 
     The thermal storage liquid may be heated to a storage temperature prior to entering the first storage reservoir. The storage temperature is below a boiling temperature of the thermal storage liquid when at the storage pressure and is the above boiling temperature of the thermal storage liquid when at atmospheric pressure. 
     The storage temperature may be between about 150 degrees Celsius and about 350 degrees Celsius. 
     A layer of compressed gas within the accumulator may be at an accumulator pressure, and the storage pressure may be equal to or greater than the accumulator pressure. 
     The storage pressure may be between about 100% and about 200% of the accumulator pressure. 
     The storage pressure may be between about 20 bar and about 60 bar. 
     The first storage reservoir may include a pressurized layer of cover gas above the thermal storage liquid. 
     The thermal storage liquid may be isolated from the layer of liquid within the accumulator to prevent mixing therebetween and further comprising a gas pressurization passage fluidly connecting the layer of compressed gas within the accumulator to the layer of cover gas, whereby pressurizing the accumulator pressurizes the first storage reservoir. 
     A flow regulator may be positioned in the gas pressurization passage and configured to permit gas to flow from accumulator to the first storage reservoir and to prevent gas from first storage reservoir to the accumulator, so that the storage pressure can be higher than the accumulator pressure. 
     A thermal storage compressor system may be configured to pressurize the layer of cover gas to the storage pressure. 
     The layer of cover gas may be formed by the boiling of a portion of the thermal storage liquid within the first storage reservoir whereby the layer of cover gas is pressurized to the storage pressure. 
     A thermal conditioning system may be in fluid communication with the layer of cover gas, the thermal conditioning system operable to reduce the temperature of the layer of cover gas. 
     The first storage reservoir may be at least partially disposed within the accumulator. 
     The thermal storage liquid source may include a source reservoir containing a quantity of the thermal storage liquid at a source temperature that is less than the storage temperature. 
     The thermal storage liquid within the source reservoir may be at a source pressure that is greater than atmospheric pressure. 
     The source pressure may be substantially equal to the storage pressure. 
     The source reservoir may be external the first storage reservoir. 
     The thermal storage liquid in the first storage reservoir may be isolated from the quantity of thermal storage liquid in the source reservoir to prevent mixing therebetween and the source reservoir may include a layer of cover gas above the quantity of thermal storage liquid, and further comprising a reservoir gas passage fluidly connecting the layer of cover gas within the first storage reservoir to the layer of cover gas within the source reservoir, whereby the first storage reservoir and source reservoir are maintained at the same pressure. 
     The source reservoir may include a body of water. 
     The source reservoir may be at least partially disposed within the accumulator. 
     The first storage reservoir may be at least partially underground. 
     The gas compressor/expander system may include a second compression stage downstream from the first compression stage and the first heat exchanger may be fluid communication between the first compression stage and the second compression stage. The thermal storage subsystem may include a second heat exchanger in fluid communication between the second compression stage and the accumulator. Thermal energy may be transferred between the compressed gas stream exiting the second compression stage and the thermal storage liquid. 
     The gas compressor/expander system may include a third compression stage downstream from the second compression stage and the second heat exchanger may be fluid communication between the second compression stage and the third compression stage. The thermal storage subsystem may include a third heat exchanger in fluid communication between the third compression stage and the accumulator. Thermal energy may be transferred between the compressed gas stream exiting the third compression stage and the thermal storage liquid. 
     The first storage liquid reservoir may include a single chamber having a chamber bottom wall, a chamber top wall, a chamber sidewall extending therefrom and may define a chamber interior configure to contain the thermal storage liquid. 
     The chamber may include a natural underground cavity formed at least partially of natural rock. 
     A storage liner may cover at least a portion of an interior surface of the chamber. 
     The compressed gas energy storage system of any one of claims  1  to  11 , wherein the first storage reservoir comprises an outer chamber having a chamber upper wall, a chamber bottom wall, a chamber sidewall extending therefrom and defining a chamber interior, and at least a first liquid tank having a tank bottom wall, a tank sidewall extending therefrom and defining a tank interior, the first liquid tank being disposed within the interior of the chamber and configured to contain the thermal storage liquid. 
     The tank interior may be in fluid communication with the interior of the chamber whereby an internal pressure of the tank is substantially equalized with an internal pressure of the chamber. 
     An upper end of the tank may be at least partially open to provide the fluid communication with the interior of the chamber. 
     The tank may be formed at least partially from at least one of concrete and metal. 
     The tank bottom wall may be spaced above the chamber bottom wall and a bottom thermal insulation layer may be positioned therebetween to inhibit heat transfer from the tank bottom wall to the chamber bottom wall. 
     The bottom thermal insulation layer may include at least one of a gas layer, an insulating material layer, and a flowing cooling fluid layer. 
     The tank sidewall may be spaced apart from the chamber sidewall, and a sidewall thermal insulation layer may be positioned therebetween to inhibit heat transfer from the tank sidewall to the chamber sidewall. 
     The sidewall thermal insulation layer may include at least one of a gas layer, an insulating material layer, and a flowing cooling fluid layer. 
     An extraction pump may be in liquid communication with the thermal storage liquid in the first storage reservoir and may be selectably operable to pump the thermal storage liquid at the storage temperature out of the first storage reservoir. 
     An exit stream of gas is released from the accumulator, thermal energy is transferred from the thermal storage liquid pumped out of the first storage reservoir into the exit stream of gas. 
     The exit stream of gas and the thermal storage liquid pumped out of the first storage reservoir may pass through the first heat exchanger. 
     The pump may include a progressive cavity pump having a rotor and complimentary stator disposed within the first storage reservoir. A motor may be disposed external the first storage reservoir and a shaft may drivingly connect the rotor to the motor. 
     The motor may be disposed above ground. 
     The first storage reservoir may be disposed entirely under ground. 
     A reservoir cooling system may be configured to selectably cool the temperature of the thermal storage liquid contained in the first storage reservoir, thereby reducing the storage pressure within the first storage reservoir. 
     The reservoir cooling system may include a quantity of a cooling liquid stored at a cooling temperature that is below the storage temperature, and may be operable to introduce the quantity of cooling liquid into the first storage reservoir, thereby diluting and reducing the temperature of the thermal storage liquid contained in the first storage reservoir. 
     The reservoir cooling system may include an actuatable drain apparatus that is openable to drain at least some of the thermal storage liquid from the first storage reservoir into a cooling chamber containing a quantity of a cooling liquid stored at a cooling temperature that is below the storage temperature. 
     The cooling chamber may be disposed at a lower elevation than the first storage reservoir, whereby when the drain apparatus is opened the thermal storage liquid flows into the cooling chamber under the influence of gravity. 
     The drain apparatus may include a pressure-actuated drain valve that is operable to open automatically when the storage pressure exceeds a predetermined automatic-cooling pressure threshold. 
     The accumulator may have a primary opening, an upper wall, a lower wall and an accumulator interior containing a layer of the compressed gas above a layer of water when in use and may be at least partially bounded the upper wall and lower wall. 
     A shaft may have a lower end adjacent the primary opening, an upper end spaced apart from the lower end, and a shaft sidewall extending upwardly from the lower end to the upper end and at least partially bounding a shaft interior for containing a quantity of a liquid, the shaft being fluidly connectable to a liquid source/sink via a liquid supply conduit. 
     A partition may cover the primary opening and may separate the accumulator interior from the shaft interior. The partition may have an outer surface in communication with the shaft interior and an opposing inner surface in communication with the accumulator interior. 
     At least one of the layer of compressed gas and the layer of liquid may bear against and exert an internal accumulator force on the inner surface of the partition and the quantity of liquid within the shaft may bear against and exert an external counter force on the outer surface of the partition, whereby a net force acting on the partition while the compressed gas energy storage system is in use is a difference between the accumulator force and the counter force and is less than the accumulator force. 
     When the compressed gas energy storage system is in the discharging mode compressed gas may travel from the accumulator to the gas compressor/expander subsystem and at least a portion of the thermal storage liquid at the storage temperature may be withdrawn from the first storage reservoir and the thermal storage subsystem may be operable so that thermal energy is transferred from at least the portion of the thermal storage liquid withdrawn from the first storage reservoir to the compressed gas exiting the accumulator whereby the temperature of the compressed gas exiting the accumulator is increased before it reaches the gas compressor/expander subsystem. 
     When the compressed gas energy storage system is in a discharging mode the compressed gas traveling from the accumulator to the gas compressor/expander subsystem may pass through the first heat exchanger to receive thermal energy from the thermal storage liquid. 
     Other aspects and embodiments are described in further detail below. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Embodiments of the invention will now be described with reference to the appended drawings in which: 
         FIG.  1    is a schematic, cross-sectional view of components of one example of a hydrostatically compensated compressed gas energy storage system; 
         FIG.  2    is a top plan view of components of a bulkhead for the compressed gas energy storage subsystem of  FIG.  1   ; 
         FIG.  3    is a side elevation view of the bulkhead of  FIG.  2   ; 
         FIG.  4    is a side cross-sectional view of the bulkhead of  FIG.  2   , taken along line  4 - 4 ; 
         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. 
         FIG.  6    is a schematic, cross-sectional view of components of another example of a compressed gas energy storage system; 
         FIG.  7    is a schematic, cross-sectional view of components of another example of a compressed gas energy storage system; 
         FIG.  8    is a schematic view of components of a compressor/expander subsystem for the compressed gas energy storage system, according to an embodiment; 
         FIG.  9    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; 
         FIG.  10    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; 
         FIG.  11    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; 
         FIG.  12    is a schematic view of components of the alternative compressor/expander subsystem of  FIG.  11   , showing airflow during an expansion (release) phase from storage through multiple expanders and respective stages of a thermal storage subsystem; 
         FIG.  13    is a schematic view of components of the alternative compressor/expander subsystem of  FIG.  11   , showing airflow during a compression (storage) from the ambient through multiple compressors and respective stages of a thermal storage subsystem; 
         FIG.  14    is a sectional view of components of a compressed gas energy storage system, according to an alternative embodiment; 
         FIG.  15    is a sectional view of components of an alternative compressed gas energy storage system, according to another alternative embodiment; 
         FIG.  16    is a schematic, cross-sectional view of components of another example of a compressed gas energy storage system; 
         FIG.  17    is a schematic, cross-sectional view of components of yet another example of a compressed gas energy storage system; 
         FIG.  18    is a schematic, cross-sectional view of components of yet another example of a compressed gas energy storage system; 
         FIG.  19    is a schematic, cross-sectional view of components of yet another example of a compressed gas energy storage system; 
         FIG.  20 A  is a schematic, cross-sectional view of components of yet another example of a compressed gas energy storage system; 
         FIG.  20 B  is an enlarged view of a portion of the compressed gas energy storage system of  FIG.  20 A ; 
         FIG.  21    is a schematic, cross-sectional view of components of yet another example of a compressed gas energy storage system; 
         FIG.  22    is a schematic, cross-sectional view of components of yet another example of a compressed gas energy storage system; and 
         FIG.  23    is a schematic, cross-sectional view of components of yet another example of a compressed gas energy storage system. 
     
    
    
     DETAILED DESCRIPTION 
     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. 
     Energy produced by some types of energy sources, such as windmills, solar panels and the like may tend to be produced during certain periods (for example when it is windy, or sunny respectively), and not produced during other periods (if it is not windy, or at night, etc.). However, the demand for energy may not always match the production periods, and it may be useful to store the energy for use at a later time. Similarly, it may be helpful to store energy generated using conventional power generators (coal, gas and/or nuclear power plants for example) to help facilitate storage of energy generated during non-peak periods (e.g. periods when electricity supply could be greater than demand and/or when the cost of electricity is relatively high) and allow that energy to be utilized during peak periods (e.g. when the demand for electricity may be equal to or greater than the supply, and/or when the cost of electricity is relatively high). 
     As described herein, compressing and storing a gas (such as air), using a suitable compressed gas energy storage system, is one way of storing energy for later use. For example, during non-peak times, energy (i.e. electricity) can be used to drive compressors and compress a volume of gas to a desired, relatively high pressure for storage. The gas can then be stored at the relatively high pressure inside any suitable container or vessel, such as a suitable accumulator. To extract the stored energy, the pressurized gas can be released from the accumulator and used to drive any suitable expander apparatus or the like, and ultimately to be used to drive a generator or the like to produce electricity. The amount of energy that can be stored in a given compressed gas energy storage system may be related to the pressure at which the gas is compressed/stored, with higher pressure storage generally facilitating a higher energy storage. However, containing gases at relatively high pressures in conventional systems, such as between about 45-150 atm, can require relatively strong, specialized and often relatively costly storage containers/pressure vessels. 
     Referring to  FIG.  1    one example of a 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 chamber 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. 
     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, angled, and the like, and in the illustrated example are shown as generally planar surfaces, that are generally parallel to a horizontal reference plane  19 . The accumulator  12  also has an accumulator width (not shown—measured into the page as illustrated in  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 m 3  and about 2,000,000 m 3  or 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. 
     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. 
     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 without requiring further treatment. In this embodiment, the compressed gas  14  is compressed atmospheric air, and the liquid is water. 
     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 0.75 m 2  and about 80 m 2 , but may be larger or smaller in a given embodiment. 
     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  FIGS.  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 lower 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 upper 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 upper width  33  that may be between about 1-8 m, 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 1.2 m and about 10 m, 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. 
     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. 
     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. 
     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 between the 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). 
     As illustrated in the schematic representation in  FIG.  16   , the primary opening  27  is provided in the sidewall  15  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  10 F 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. A thermal storage subsystem  120 , including any of the embodiments described herein, can be used in combination with an accumulator  12  having this arrangement. One example of a suitable thermal storage subsystem  120  is illustrated in  FIG.  16   . 
     In the embodiments of  FIGS.  1  and  16   , 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 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 . 
     Referring to  FIG.  17   , another embodiment of a compressed gas storage system  10 G is configured with a partition that includes a projection  200 A, identified using cross-hatching in  FIG.  17   , that is formed from generally the same material as the surrounding ground  200 . In this example, the system  10 G 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  200 A 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  200 A or, as illustrated, at least some of the liquid supply conduit  40  can be provided by a flow channel that passes beneath the projection  200 A 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. 
     Optionally, in such embodiments the gas supply conduit  22  may be arranged to pass through the partition/projection  200 A as illustrated in  FIG.  17   . In this arrangement (and in the embodiment shown in  FIG.  16   ), 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 . A thermal storage subsystem  120 , including any of the embodiments described herein, can be used in combination with an accumulator  12  having this arrangement. One example of a suitable thermal storage subsystem  120  is illustrated in  FIG.  17   . 
     Optionally, the system  10 G 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.  17   , 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 passes beneath the projection  200 A. 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  40  pass through the partition. 
     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 lower surface  29 . For a given lower surface  29  area, the magnitude of the internal accumulator force  41  may vary generally proportionally with the pressure of the gas  14 . 
     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 upper surface  31  to a pressurized environment, such as a pressurized gas or liquid that is in contact with the upper surface  31 , and calibrating the pressure acting on the upper surface  31  (based on the relative cross-sectional area of the upper surface  31  and the pressure acting on the lower 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 . 
     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 2 m and about 15 m or more, or may be between about 5 m and 12 m, or between about 2 m and about 5 m. In such arrangements, the interior  52  of the shaft  18  may be able to accommodate about 1,000-150,000 m 3  of water. 
     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 water source/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. 
     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. 
     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  50  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 . 
     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 . 
     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 the compressed gas in compressed gas layer  14  stored in accumulator  12 . In the illustrated embodiment, operating system  10  so as to maintain a pressure differential (i.e. the difference between gas pressure inside the accumulator  12  and the hydrostatic pressure at the lower end  43  of the shaft  18 ) within a threshold amount—an amount preferably between 0 and 4 Bar, such as 2 Bar—the resulting net force acting on the bulkhead  24  (i.e. the difference between the internal accumulator force  41  and the counter force  46 ) can be maintained below a pre-determined threshold 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 . 
     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. 
     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 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. 
     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 shaft  18 , 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.  17   , 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 . 
     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 pas through the bulkhead  24 . 
     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 . 
     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 0.01% 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 . 
     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. 
       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.  6    for example) 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. 
     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 environmental impacts or to cause the air to be at a temperature suited for an efficient operating range of a particular stage of compressor  112  or expander  116 . 
     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. 
     Optionally, the bulkhead  24  may include one or more apertures or other suitable structures to accommodate the gas conduit  22 , the liquid conduit  40  and other such conduits, such that the conduits pass through the bulkhead  24  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  FIGS.  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  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  to minimize, and preferably prevent, uncontrolled release of compressed gas within accumulator  12  into shaft  18  or water  20  within shaft  18  into accumulator  12  (except via conduit  40 ). 
     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  200 A as shown in the embodiment of  FIG.  17   . 
     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, and then, optionally, release at least a portion of the sequestered 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 an accumulator temperature that is less than the exit temperature, and may be between about 30° C. and about 60° C. in some examples. 
       FIG.  6    is a schematic view of components of a compressed gas energy storage system  10 A, according to an alternative embodiment. Compressed gas energy storage system  10 A is like compressed gas energy storage systems  10 , 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  22 A that extends between the compressor/expander subsystem  100  and thermal storage subsystem  120 , and a lower portion  22 B that extends between thermal storage subsystem  120  and accumulator  12 . 
     The thermal storage subsystem  120  may include any suitable type of thermal storage apparatus, including, for example latent and/or sensible storage apparatuses. The thermal storage apparatus(es) may be configured as single stage, two stage and/or multiple stage storage apparatus(es). Similarly, the thermal storage subsystem  120  may include one or more heat exchangers (to transfer thermal energy into and/or out of the thermal storage subsystem  120 ) and one or more storage apparatuses (including, for example storage reservoirs for holding thermal storage fluids and the like). Any of the thermal storage apparatuses may be either be separated from or proximate to their associated heat exchanger and may also incorporate the associated heat exchanger in a single compound apparatus (i.e. in which the heat exchanger is integrated within the storage reservoir). 
     The thermal storage subsystem  120 , or portions thereof, may be located in any suitable location, including above-ground, below ground, within the shaft  18 , within the accumulator  12 , and the like. Optionally, portions of the thermal storage subsystem  120  can be spaced apart from each other and located in different locations. For example, a heat exchanger used in a thermal storage subsystem  120  may be spaced apart from (but fluidly connected to) a corresponding storage apparatus. In such examples, the storage apparatus(es) may be located relatively deep within the ground while the heat exchanger may be relatively shallower and/or may be provided above ground to help facilitate access, etc. 
     In the illustrated embodiment, substantially the thermal storage subsystem  120  is located underground, which may help reduce the use of above-ground land and may help facilitate the use of the weight of the earth/rock to help contain the pressure in the storage reservoir. That is, the outward-acting pressure within the storage reservoir can be substantially balanced by the inwardly-acting forces exerted by the earth and rock surrounding the first reservoir. In some examples, if a liner or other type of vessel are provided in the storage reservoir such structures may carry some of the pressure load, but are preferably backed-up by and/or supported by the surrounding earth/rock. This can help facilitate pressurization of the storage reservoir to the desired storage pressures, without the need for providing a manufactured pressure vessel that is capable of withstanding the entire pressure differential. In this example, the thermal storage subsystem  120  also employs multiple stages including, for example, multiple sensible and/or latent thermal storage stages such as stages having one or more phase change materials and/or pressurized water, or other heat transfer fluid arranged in a cascade. It will be noted that, if operating the system for partial storage/retrieval cycles, the sizes of the stages may be sized according to the time cycles of the phase change materials so that the phase changes, which take time, take place effectively within the required time cycles. 
     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 ). 
     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 accumulator temperature), and may be within about 10° C. and about 60° C. of the exit temperature in some examples, that may help enable the expander to operate within its relatively efficient operating temperature range(s), rather than having to operate outside of the range with cooler compressed gas. 
     In some embodiments, the thermal storage subsystem  120  may employ at least one phase change material, preferably multiple phase change materials, multiple stages and materials that may be selected according to the temperature rating allowing for the capture of the latent heat. Generally, phase change material heat can be useful for storing heat of approximately 150 degrees Celsius and higher. The material is fixed in location and the compressed air to be stored or expanded is flowed through the material. In embodiments using multiple cascading phase change materials, each different phase change material represents a storage stage, such that a first type of phase change material may change phase thereby storing the heat at between 200 and 250 degrees Celsius, a second type of phase change material may change phase thereby storing the heat at between 175 and 200 degree Celsius, and a third type of phase change material may change phase thereby storing the heat at between 150 and 175 degrees Celsius. One example of a phase change material that may be used with some embodiments of the system includes a eutectic mixture of sodium nitrate and potassium nitrate, or the HITEC® heat transfer salt manufactured by Coastal Chemical Co. of Houston, Tex. 
     In embodiments of the thermal storage subsystem  120  employing sensible heat storage, pressurized water, or any other suitable thermal storage fluid/liquid and/or coolant, may be employed as the sensible heat storage medium. Optionally, such systems may be configured so that the thermal storage liquid remains liquid while the system is in use, and does not undergo a meaningful phase change (i.e. does not boil to become a gas). For example, such thermal storage liquids (e.g. water) may be pressurized and maintained at an operating pressure that is sufficient to generally keep the water in its liquid phase during the heat absorption process as its temperature rises. Optionally, the pressurized water may be passed through a heat exchanger or series of heat exchangers to capture and return the heat to and from the gas stream that is exiting the accumulator, via conduit  22 . Generally, sensible heat storage may be useful for storing heat of temperatures of 100 degrees Celsius and higher. Pressurizing the water in these systems may help facilitate heating the water to temperatures well above 100 degrees Celsius (thereby increasing its total energy storage capability) without boiling. 
     Optionally, in some embodiments, a thermal storage subsystem  120  may combine both latent and sensible heat storage stages, and may use phase change materials with multiple stages or a single stage. Preferably, particularly for phase change materials, the number of stages through which air is conveyed during compression and expansion may be adjustable by controller  118 . This may help the system  10  to adapt its thermal storage and release programme to match desired and/or required operating conditions. 
     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 . In some preferred embodiments, the compressed gas stream will transfer its thermal energy to the thermal storage system  120  (for example by passing through heat exchangers  635  described herein) before the compressed gas travels underground. That is, some portions of the thermal storage subsystem  120  and at least the portion of the gas conduit that extends between the compressor/expander subsystem  100  and the thermal storage subsystem  120  may be provided above ground, 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 , ground or other possible heat sinks along the length of the gas conduit  22 . 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. 
     Referring to  FIG.  18   , one example of the thermal storage subsystem  120  that can be used to transfer thermal energy from the compressed gas stream travelling between the gas compressor/expander subsystem  100  and the accumulator  12  is configured to store thermal energy in a thermal storage liquid  600 . Optionally, the thermal storage liquid  600  can be pressurized in the thermal storage subsystem  120  to a storage pressure that is higher than atmospheric pressure and may optionally be generally equal to or greater than the accumulator pressure. Harmonizing the storage pressure in the thermal storage subsystem  120  and the accumulator  12  may help facilitate configurations in which there is at least some fluid communication between the thermal storage subsystem  120  and the accumulator  12  (including those described herein). In some examples, the storage pressure may be between about 100% and about 200% of the accumulator pressure. 
     Pressurizing the thermal storage liquid  600  in this manner may allow the thermal storage liquid  600  to be heated to relatively higher temperatures (i.e. store relatively more thermal energy and at a more valuable grade) without boiling, as compared to the same liquid at atmospheric pressure. That is, the thermal storage liquid  600  may be pressurized to a storage pressure and heated to a thermal storage temperature such that the thermal storage liquid  600  is maintained as a liquid while the system is in use (which may help reduce energy loss through phase change of the thermal storage liquid). In the embodiments illustrated, the storage temperature may be between about 150 and about 500 degrees Celsius, and preferably may be between about 150 and 350 degrees Celsius. The storage temperature is preferably below a boiling temperature of the thermal storage liquid  600  when at the storage pressure but may be, and in some instances preferably will be the above boiling temperature of the thermal storage liquid  600  if it were at atmospheric pressure. In this example, the thermal storage liquid  600  can be water, but in other embodiments may be engineered heat transfer/storage fluids, coolants, oils and the like. When sufficiently pressurized, water may be heated to a storage temperature of about 250 degrees Celsius without boiling, whereas water at that temperature would boil at atmospheric pressure. 
     Optionally, the thermal storage liquid  600  can be circulated through a suitable heat exchanger to receive heat from the compressed gas stream travelling through the gas supply conduit  22  (downstream from the compressor/expander subsystem  100 ). The heated thermal storage liquid  600  can then be collected and stored in a suitable storage reservoir (or more than one storage reservoirs) that can retain the heated thermal storage liquid  600  and can be pressurized to a storage pressure that is greater than atmospheric pressure (and may be between about 10 and 60 bar, and may be between about 30 and 45 bar, and between about 20 and 26 bar). 
     The storage reservoir may be any suitable type of structure, including an underground chamber/cavity (e.g. formed within the surrounding ground  200 ) or a fabricated tank, container, a combination of a fabricated tank and underground chamber/cavity, or the like. If configured to include an underground chamber, the chamber may optionally be lined to help provide a desired level of liquid and gas impermeability and/or thermal insulation. For example, underground chambers may be at least partially lined with concrete, polymers, rubber, plastics, geotextiles, composite materials, metal and the like. Configuring the storage reservoir to be at least partially, and preferably at least substantially impermeable may help facilitate pressurizing the storage reservoir as described herein. Fabricated tanks may be formed from any suitable material, including concrete, metal, plastic, glass, ceramic, composite materials and the like. Optionally, the fabricated tank may include concrete that is reinforced using, metal, fiber reinforced plastic, ceramic, glass or the like, which may help reduce the thermal expansion difference between the concrete and the reinforcement material. 
     Referring still to  FIG.  18   , in this embodiment the storage reservoir  610  of the thermal storage subsystem  120  includes a chamber  615  that is positioned underground, at a reservoir depth  660 . Preferably, the reservoir depth  660  is less than the depth of the accumulator  12 , which in this example corresponds to the shaft height  50 . Optionally, the thermal storage subsystem  120  can be configured so that the reservoir depth  660  is at least about ⅓ of the accumulator depth/shaft height  50 , or more. For example, if the accumulator  12  is at a depth of about 300 m, the reservoir depth  660  is preferably about 100 m or more. For example, having the reservoir depth  660  being less than the accumulator depth  50  may help facilitate sufficient net positive suction head to be available to the fluid transfer pumps and other equipment utilized to pump the thermal storage liquid  600  through the thermal storage subsystem  120  (for example between source reservoir  606  and storage reservoir  610 ). This may allow the transfer pumps to be positioned conveniently above ground and may help reduce the chances of damaging cavitation from occurring. 
     The reservoir depth  660  being at least ⅓ the depth  50  of the accumulator  12  may also allow for relatively higher rock stability of the subterranean thermal storage cavern, such as chamber  615 . The geostatic gradient, which provides an upper limit on pressure inside underground rock caverns, is typically about 2.5-3 times the hydrostatic gradient. Given this rock stability criterion, the shallowest reservoir depth  660  may be approximately three times less than the accumulator depth in some embodiments, such as when the storage pressure is generally equal than the accumulator pressure. 
     In this example, the chamber  615  is a single chamber having a chamber interior  616  that is at least partially defined by a bottom chamber wall  620 , a top chamber wall  651 , and a chamber sidewall  621 . The chamber  615  is connected to one end of a liquid inlet passage  630  (such as a pipe or other suitable conduit) whereby the thermal storage liquid  600  can be transferred into and/or out of the chamber  615 . In addition to the layer of thermal storage liquid  600 , a layer of cover gas  602  is contained in the chamber  615  and overlies the thermal storage liquid  600 . Like the arrangement used for the accumulator  12 , the layer of cover gas  602  can be pressurized using any suitable mechanism to help pressurize the interior of the chamber  615  and thereby help pressurize the thermal storage liquid  600 . The cover gas may be any suitable gas, including air, nitrogen, thermal storage liquid vapour, an inert gas and the like. Optionally, at least the subterranean portions of the liquid inlet passage  630  (i.e. the portions extending between the heat exchanger  635  and the storage reservoir  610 ) may be insulated (such as by a vacuum sleeve, or insulation material) to help reduce heat transfer between the thermal storage fluid and the surrounding ground. 
     When the thermal storage subsystem  120  is in use, a supply of thermal storage liquid can be provided from any suitable thermal storage liquid source  605 . The thermal storage liquid source can be maintained at a source pressure that may be the same as the storage pressure, or may be different than the storage pressure. For example, the thermal storage liquid source may be at approximately atmospheric pressure, which may reduce the need for providing a relatively strong, pressure vessel for the thermal storage liquid source. Alternatively, the thermal storage liquid source may be pressurized. The thermal storage liquid source may also be maintained at a source temperature that is lower, and optionally substantially lower than the storage temperature. For example, the thermal storage liquid source may be at temperatures of between about 2 and about 100 degrees Celsius, and may be between about 4 and about 50 degrees Celsius. Increasing the temperature difference between the incoming thermal storage liquid from the source and the storage temperature may help increase the amount of heat and/or thermal energy that can be stored in the thermal storage subsystem  120 . 
     The thermal storage liquid source  605  may have any suitable configuration, and may have the same construction as an associated storage reservoir, or may have a different configuration. For example, in the embodiment of  FIG.  18    the thermal storage liquid source  605  includes a source reservoir  606  that is configured in the same underground chamber as the thermal fluid storage chamber  615 . In this arrangement, a closed loop system can be provided, including the storage reservoir  610  and the source reservoir  606 . Alternatively, as shown in the embodiment of  FIG.  19   , the thermal storage liquid source  605  may include a source reservoir  606  that is configured as an above-ground vessel, and optionally need not be pressurized substantially above atmospheric pressure. In other embodiments, the thermal liquid source  605  may include a body of water such as the lake  150 , water  20  from the shaft  18 , liquid from the liquid layer  16  in the accumulator  12  (or from any other portion of the overall system  10 ), water from a municipal water supply or other such sources and combinations thereof. 
     In the embodiment of  FIG.  18   , the source reservoir  606  and storage reservoir  610  are adjacent each other, and are portions of a generally common underground chamber. This may help simplify construction of the thermal storage subsystem  120  as an excavation of a single chamber may provide space for both the source reservoir  606  and storage reservoir  610 . This may also help simplify piping and valving between the source reservoir  606  and the storage reservoir  610 . 
     In some examples, the interiors of the storage reservoir  610  and source reservoir  606  may be substantially fluidly isolated from each other, such that neither gas nor liquid can easily/freely pass between reservoirs  606  and  610 . One example of a subsystem  120  having this arrangement is shown in  FIG.  19   . 
     Alternatively, as illustrated in  FIG.  18   , the interiors of the storage reservoir  610  and source reservoir  606  may be in gas flow communication with each other, such as by providing the gas exchange passage  626  that can connect the layer of cover gas  602  with a layer of cover gas  608  in the source reservoir  606 . The gas exchange passage  626  can be configured to allow free, two-way flow of gas between the storage reservoir  610  and the source reservoir  606 , or may be configured to only allow one-way gas flow (in either direction). Providing a free flow of gas between the storage reservoir  610  and the source reservoir  606  may help automatically match the pressures within the storage reservoir  610  and the source reservoir  606 . Preferably, when arranged in this manner, the interior of the storage reservoir  610  remains at least partially isolated from the interior of the source reservoir  606  during normal operation to inhibit, and preferably prevent mixing of the relatively hot cover gas  602  associated with the thermal storage liquid  600  in the storage reservoir  610  with the relatively cooler cover gas  608  associated with the thermal storage liquid in the source reservoir  606 . In this example, the storage reservoir  610  and source reservoir  606  share a common sidewall, which can function as an isolating barrier  625  to prevent liquid mixing between the reservoirs. This common sidewall may be insulated to prevent unwanted heat transfer from the relatively hot thermal storage liquid  600  in the storage reservoir  610  to the relatively cooler thermal storage liquid in the source reservoir  606   
     When the compressed gas energy storage system  10 H is in a charging mode, compressed gas is being directed into the accumulator  12  and the thermal storage liquid  600  can be drawn from the thermal storage liquid source  605 , passed through one side of a suitable heat exchanger  635  (including one or more heat exchanger stages) to receive thermal energy from the compressed gas stream exiting the compressor/expander subsystem  100 , and then conveyed/pumped through the liquid inlet passage  630  and into the storage reservoir  610  for storage at the storage pressure. 
     When the compressed gas energy storage system is in a storage mode, compressed gas is neither flowing into or out of the accumulator  12  or thorough the heat exchanger  635 , and the thermal storage liquid  600  need not be circulated through the heat exchanger  635 . 
     When the compressed gas energy storage system  10 H is in a discharging mode, compressed gas is being transferred from the accumulator  12  and into the compressor/expander subsystem  100  for expansion and the thermal storage liquid  600  can be drawn from the storage reservoir  610 , passed through one side of a suitable heat exchanger  635  (including one or more heat exchanger stages) to transfer thermal energy from thermal storage liquid into the compressed gas stream to help increase the temperature of the gas stream before it enters the compressor/expander subsystem  100 . Optionally, the thermal storage fluid can then be conveyed/pumped into the source reservoir  606  for storage. 
     When the compressed gas energy storage system  10 I is in charging mode the thermal storage liquid  600  receives thermal energy from the compressed gas is conveyed into the storage reservoir  610 , and while the thermal storage system  10 I is in discharging mode the storage liquid  600  is drawn from the storage reservoir  600  and transfers thermal energy into the compressed gas exiting the accumulator  12  (preferably before it reaches the compressor/expander subsystem  100 ). 
     The thermal storage liquid  600  can be conveyed through the various portions of the thermal storage subsystem  120  using any suitable combination of pumps, valves, flow control mechanisms and the like. Optionally, an extraction pump may be provided in fluid communication with, and optionally at least partially nested within, the storage reservoir  610  to help pump the thermal storage liquid  600  from the storage reservoir  610  up to the surface. Such a pump may be a submersible type pump and/or may be configured so that the pump and its driving motor are both located within the storage reservoir  610 . Alternatively, the pump may be configured as a progressive cavity pump having a stator and rotor assembly  668  (including a rotor rotatably received within a stator) provided in the storage reservoir  610  and positioned to be at least partially submerged in the thermal storage liquid  600 , a motor  670  that is spaced from the stator and rotor assembly  668  (on the surface in this example) and a drive shaft  672  extending therebetween. In this example, the drive shaft  672  is nested within the liquid inlet passage  630  extending to the storage reservoir  610 , but alternatively may be in other locations. 
     Optionally, to help pressurize the storage reservoir  610 , the thermal storage subsystem  120  may include any suitable type of pressurization system, and may include a thermal storage compressor system that can help pressurize the layer of cover gas  602  in the storage reservoir. This may include a thermal storage compressor  664 , as shown in in  FIGS.  18  and  19    for example,) that is in fluid communication with the cover gas layer  602 . The compressor itself may be on the surface, and may be connected to the cover gas layer  602  by a compressor gas conduit  666  that may be spaced from, or at least partially integrated with the liquid inlet passage  630 . Optionally, the compressor  664  may be configured to raise the pressure of the cover gas layer  602  from atmospheric pressure to the storage pressure. The compressor  664 , and any other aspects of the thermal storage subsystem  120  may be controlled at least partially automatically by the controller  118 . While shown as a separate compressor  664 , pressure for the storage reservoir  610  may at least partially be provided by the compressor/expander subsystem  100 . 
     Optionally, as shown in the examples of  FIGS.  19  and  21   , the cover gas layer  602  may be in fluid communication with the compressed gas layer  14  in the accumulator  12 , for example via the gas exchange passage  626 . In such examples, pressuring the accumulator  12  can also cause the simultaneous pressurization of the storage reservoir  610 , and raise the pressure of the cover gas layer  602  to the accumulator pressure. In embodiments where the storage reservoir  610  is to be pressurized to the same pressure as the accumulator, this may be sufficient pressurization of the storage reservoir  610 . 
     Alternatively, if the storage pressure is to be higher than the accumulator pressure, the thermal storage subsystem  120  may include a valve, one-way flow control device or other such flow limiting device that can allow gas to move from the accumulator  12  into the storage reservoir  610  to pressurize the storage reservoir  610  to the accumulator pressure, and can prevent gas from travelling from escaping from the storage reservoir  610  to the accumulator  12 . This may allow the storage reservoir  610  to be at least partially pressurized by the gas layer  14  of the accumulator  12 , and then isolated and further pressurized using a suitable pressurization system (such as the compressor  664 ). 
     In other embodiments, the storage reservoir  610 , and cover gas layer  602  therein, may be pressurized using other means, including, other mechanical compression mechanisms and may optionally be at least partially self pressurizing. That is, the storage reservoir  610  may begin at relatively low pressure and as the thermal storage liquid  600  is heated a relatively small portion of the thermal storage liquid  600  may boil and convert to a vapour phase. The vapour may then form at least part of the cover gas layer  602 , and may increase the pressure within the storage reservoir  610  to a generally equilibrium pressure such that further boiling, at a given temperature, is inhibited. As the temperature of the thermal storage liquid  600  continues to rise, additional amounts of the thermal storage liquid  600  may convert to vapour phase thereby increasing the overall pressure of the storage reservoir  610  and reaching a new equilibrium with the liquid phase. This may be sufficient to pressurize the storage reservoir  610  to the storage pressure, or the subsystem  120  may also include one or more additional pressurization systems, including any of those described herein. 
     In the example of  FIG.  19   , the thermal storage liquid source  605 , e.g. the source reservoir  606  is located above ground and storage reservoir  610  is located underground and is adjacent to the accumulator  12 . In this arrangement, the depth of the storage reservoir  610  is the same as the depth of the accumulator  12 . To keep the thermal storage liquid  600  separate from the liquid layer  16 , there is an isolating barrier  625 . Optionally, the chamber interior  616  may be at least partially covered in a storage liner  617  that is preferably substantially vapour and liquid impermeable at the storage pressure. 
     In this embodiment, the isolating barrier  625  includes a gas exchange passage  626  that allows the pressurized layer of cover gas  602  to communicate with gas layer  14  within the accumulator  12 , which allows the mixing of gas  602  and gas layer  14  which allows the storage reservoir  610  to be at least partially pressurized when the accumulator  12  is pressurized. Optionally, fluid communication through the gas exchange passage  626  can be directionally controlled by a flow regulator  628  (e.g. a check valve) such that, for example, pressurized layer of cover gas  602  cannot enter the accumulator  12  through the gas exchange passage  626 , but gas  14  from the accumulator  12  can enter the chamber  615  of the storage reservoir  610  allowing the gas  14  in the accumulator to initially pressurize the first storage reservoir  610 . This may allow the storage reservoir  610  to be at least partially pressurized by the gas layer  14  of the accumulator  12 , and then isolated and further pressurized using a suitable pressurization system (such as the compressor  664 ). 
     In this embodiment, the liquid inlet passage  630  includes an upper liquid inlet passage  629  and a lower liquid inlet passage  631 . When the compressed energy storage system  10 I is in a charging mode, the upper liquid inlet passage  629  conveys thermal storage liquid  600  from the source reservoir  606  to a first heat exchanger  635  where it is heated to a storage temperature (below a boiling temperature of the thermal storage liquid when at the storage pressure and is the above boiling temperature of the thermal storage liquid when at atmospheric pressure) before the lower liquid inlet passage  631  conveys the thermal storage liquid heated to a storage temperature to the first storage reservoir  610 . For greater certainty only, the thermal storage fluid  600  in the source reservoir  606  is at a source temperature that is less than the storage temperature described above. An analogous configuration may be used in other embodiments. 
     When the compressed gas energy storage system  10 I is in a discharging mode, compressed gas is being transferred from the accumulator  12  and into the compressor/expander subsystem  100  for expansion and the thermal storage liquid  600  can be drawn from the storage reservoir  610 , passed through one side of a suitable heat exchanger  635  (including one or more heat exchanger stages) to transfer thermal energy from thermal storage liquid into the compressed gas stream to help increase the temperature of the gas stream before it enters the compressor/expander subsystem  100 , as illustrated by arrow  632  Optionally, the thermal storage fluid can then be conveyed/pumped into the source reservoir  606  for storage. 
     Optionally, in some embodiments the storage reservoir  610  may include an outer chamber or shell portion that is configured to withstand the desired pressurization described herein, and at least one inner chamber that is configured to receive and retain the heated thermal storage liquid, and optionally may include two or more inner chambers within a common outer chamber. In some examples, the interior of the inner chamber may be in fluid communication with the interior of the outer chamber. This may allow the inner chamber to retain the thermal transfer fluid without having to be a pressure-bearing vessel or otherwise carry a substantial pressure differential across the boundary of the inner chamber. For example, the outer chamber may be a chamber formed in the ground. Such a chamber may be strong enough to withstand the intended operating pressures of the thermal storage system  120 , but may not be the preferred configuration for directly contacting and retaining the thermal storage fluid. To help provide the desired liquid storage, an inner chamber in the form of a tank or other liquid retaining vessel may be positioned inside the outer chamber. The heated thermal storage liquid can then be stored in the tank, under an associated cover gas layer. The upper end of the tank may be at least partially open, such that the cover gas layer in the inner chamber is in communication with, and is therefore at the same pressure as the cover gas layer of the outer chamber. In this arrangement, the inner tank need not carry a substantial pressure load (simply the hydrostatic pressure exerted by the quantity of thermal storage liquid in the tank), and therefore may be of relatively light construction, as compared to a pressure-bearing vessel that would be required to withstand the storage pressure. In some examples, two or more separate tanks may be placed within a common outer chamber, and may be maintained at a common pressure in this manner. 
     Referring to  FIGS.  20 A and  20 B , in this example the storage reservoir  610  includes an outer chamber  615  that has a chamber interior  616  that is at least partially defined by a bottom chamber wall  620 , an upper chamber wall  651 , and a chamber sidewall  621 . An inner chamber includes a tank  684  that is disposed within the chamber interior  616 , and includes a tank bottom wall  686  and a tank sidewall  688  which together help define a tank interior  690 . The thermal storage liquid  600  and layer of cover gas  602  are contained within the tank  684 . The upper end of the tank  684  is open in this example, providing fluid communication between the chamber interior  616  and cover gas layer  602 . The tank  684  may be made from any suitable material, including, for example, metal, concrete, plastic, glass, ceramic, composite materials and combinations thereof. The tank  684  is preferably liquid impermeable, but need not be vapour impermeable. 
     In this arrangement the storage pressure is carried by the relatively strong walls  620 ,  651 , and  621  of the outer chamber  615 , and optionally the tank  684  need not be strong enough to withstand the full storage pressure. 
     Optionally, the tank bottom wall  686  can be spaced above the chamber bottom wall  620  by a offset height  692 . Similarly, the tank side wall  688  may be spaced inwardly from the chamber sidewall  621  by an offset distance  694 . This may help provide thermal insulation of the tank  684  by surrounding it with gas, and may allow the tank  684  to have a desired shape that can be different than the shape/contour of the chamber bottom wall  620  and chamber sidewall  621 . The offset height and distance  692  and  694  may be any suitable distance, and may be between 10 cm and about 10 m or more. 
     Optionally, the thermal storage subsystem  120  may be configured to provide at least some degree of thermal insulation between the heated thermal storage liquid  600  in the first reservoir  610  and the surrounding environment. For example, if the storage reservoir  610  is configured as an underground chamber in which the thermal storage liquid  600  is in contact with the chamber walls (i.e. surrounding rock), heat may be transferred from the thermal storage liquid  600  to the surrounding ground/rock. Providing thermal insulation may help reduce the amount of heat that escapes from the thermal storage liquid  600  while it is being stored. This may help prevent thermal stresses from developing in the rock and thereby help to improve the cavern stability. Similarly, this may also help improve the overall efficiency of the thermal storage subsystem  120  and/or system  10 . Preferably, the thermal storage subsystem  120  may include at least one thermal insulation layer, that may include one or more layers of physical insulating material (such as fiberglass, plastic, refractory material, ceramic and the like) and/or one or more gas layers and/or one or more vacuum layers between the high temperature thermal storage liquid in the storage reservoir and the ambient environment. 
     To help provide such thermal insulation, the chamber walls (e.g. bottom  620  and sidewall  621 ) in the embodiments described may be provided with a layer of insulating material. Alternatively, or in addition to such insulation, embodiments that utilize a separate inner chamber, such as the tank  684  in the embodiment of  FIGS.  20 A and  20 B  may be configured to include gaps  696  due to offset distances  692  and  694  in which air, or any other suitable gas, may collect. Such air gaps may function as bottom and sidewall insulting gas layers, as direct contact, and the associated conductive heat transfer, between the tank walls  686  and  688  and the chamber walls  620  and  621  is substantially eliminated. Such embodiments may also utilize one or more layers of physical insulating material on the various walls of the inner chamber  684 . 
     Optionally, the thermal storage subsystem  120  may include a reservoir cooling system that can be selectably operated to reduce the temperature of the storage reservoir  610 . The reservoir cooling system may be at least partially automatically controlled by the controller  118  (or analogous controller) based on characteristics of the thermal storage subsystem  120 , such as temperatures and/or pressures within the storage reservoir that are above a pre-determined upper threshold. 
     The reservoir cooling system may include any type of closed loop cooling system, including heat exchangers and the like. It may also be operable to introduce relatively cold liquid into the storage reservoir  610  to directly mix with the thermal storage liquid  600  or onto the outer chamber or inner chamber walls to provide surface cooling, and/or may be operable to drain at least some of the hot thermal storage liquid  600  from the storage reservoir  610  into a secondary cooling/mixing chamber. Providing a direct mixing and/or draining of liquid from within the storage reservoir  610  may provide relatively fast cooling, and may be well suited for cooling in emergency overheating/over pressurization conditions. Optionally, the reservoir cooling system for the thermal storage subsystem  120  may include a quantity of cooling liquid that is stored at a cooling temperature (that is lower than the storage temperature and may be similar to or the same as the source temperature) in a cooling chamber. The cooling liquid may be the same as the thermal storage liquid  600 , or may be a different liquid. The cooling chamber may be the same as the storage reservoir, or the out chamber, or may be the same as the source reservoir, or it may be a different chamber. Optionally, the reservoir cooling system for the thermal storage subsystem  120  may include a gas circulation system which conveys the cover gas  602  to a heat exchanger which exhausts a portion of the thermal energy contained with the cover gas to the environment, such as an aerial cooler. 
     Referring to  FIG.  21   , embodiments of a reservoir cooling system are configured such that the source reservoir  606  functions as a cooling chamber  674 , and contains extra thermal storage liquid (not yet heated by the heat exchanger  635 ) that functions as the cooling liquid. A pump  676  is provided along a cooling liquid conduit  678  (which may also include a valve  680  or other equipment) is provided to introduce at least some of the cooling liquid from the cooling chamber  674  into the storage reservoir  610 , thereby diluting and reducing the temperature of the thermal storage liquid  600  in the storage reservoir  610 . Alternatively, an automatically opening, pressure-actuated drain valve that is configured to open at a set condition (possibly pressure) could be provided instead of, or in addition to, the pump  676 . If the pressure within the storage reservoir  610  exceeded a pre-determined automatic-cooling pressure threshold, the drain valve may automatically open and allow the heated thermal storage liquid to rush out of the storage reservoir  610 , and preferably to mix with the cooling liquid. In the example of  FIG.  22   , the source chamber  606  functions as a cooling chamber  674 , and the water layer  16  that functions as the cooling liquid. In this example, a cooling liquid conduit  678  is provided as a conduit that passes through the isolating barrier  625  that can be opened to allow mixing between the heated thermal storage liquid  600  in the storage reservoir  610  and the source chamber  606 , which is at a substantially lower temperature. This flow can be one-way, or two-way. In the embodiment of  FIG.  19    a cooling liquid conduit  678  is provided as a conduit that passes through the isolating barrier  625  that can be opened to allow mixing between the heated thermal storage liquid  600  in the storage reservoir  610  and layer of water  16  in the accumulator, which is at a substantially lower temperature 
     Referring to  FIGS.  20 A and  20 B , in another embodiment the reservoir cooling system for the thermal storage subsystem  120  includes a drain apparatus  682  that is in communication with the storage reservoir  610  and, in this example, is provided as a drain in the side wall  686  of the tank  684 , and can be selectably opened to drain at least some of the thermal storage liquid  600  from the first storage reservoir  610 . The drained thermal storage liquid  600  may be directed to any suitable sink/drain, and in the embodiment of  FIG.  20 A  is directed into a cooling chamber that is provided by the source reservoir  605  and contains a quantity of a cooling liquid stored at a cooling temperature that is below the storage temperature, which in this example is unheated thermal storage fluid at the source temperature. Preferably, the cooling chamber can be located at a lower elevation than the storage reservoir  610 , such that the thermal storage liquid  600  can flow from the storage reservoir  610  into the cooling chamber under the influence of gravity, and optionally without the need for a pump or other conveying mechanism. This may help facilitate operation of the reservoir cooling system, and may enable the thermal storage liquid  600  to be drained even if electrical power is not available. 
       FIG.  22    illustrates an alternative embodiment of a thermal storage subsystem  120  in which both the storage reservoir  610  and the source reservoir  606  are adjacent and to the accumulator  12 . The heat exchanger  635  is spaced from the accumulator  12 , and may preferably be provided above ground. 
       FIG.  23    illustrates an alternative embodiment of a thermal storage subsystem  120  in which both the storage reservoir  610  and the source reservoir  606  are spaced apart from each other and from the accumulator  12 , and are both positioned below ground. In this arrangement, the storage reservoir  610  is adjacent the shaft  18  and is above the accumulator  12 . A gas passage conduit  626  in this example extends from the accumulator  12  to the storage reservoir  610  to provide fluid communication between the gas layer  14  and the cover gas layer  602 . 
       FIG.  7    is a schematic representation of a compressed gas energy storage system  10 B, according to an alternative embodiment. Compressed gas energy storage system  10 B is similar to the other compressed gas energy storage systems described herein, but is configured so that the upper portion  22 A 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. 
     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. This may help facilitate heat transfer and/or storage at two or more stages in the process, which may help improve system efficiency. 
     Referring to  FIG.  8   , optionally, an insulating “jacket”  125  (shown in dotted lines to not occlude portions of the thermal storage subsystem  120 ) can be wrapped around an 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 heat stratification, 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′ 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 . 
     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 .  FIG.  9    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 heat exchanger of a thermal storage subsystem  120 . In particular, when operating in charging mode, incoming air from the ambient A is conveyed first, optionally via a heat exchanger to modify the temperature of the incoming air, into compressor  112   a  driven by motor  110   a  for a first stage of compression. In this example, the thermal storage subsystem  120  may include two or more heat exchangers  635  that can be provided between the different compression stages. Following the first stage of compression, air A is then conveyed through a first heat exchanger  635   a  of a thermal storage subsystem  120  to transfer heat from the air A into the thermal storage liquid  600 , thereby to be conditioned to be air A′ which is then conveyed into compressor  112   b  driven by motor  110   b  for a second stage of compression. Following the second stage of compression, air A′ is then conveyed through any additional heat exchangers of the thermal storage subsystem  120  such as second heat exchanger  635   b  of thermal storage subsystem  120  to transfer heat from the air A″ into the thermal storage liquid  600 . A last heat exchanger of the thermal storage subsystem  120  is represented in this example as heat exchanger  635   x  transfer heats from the air A′″ into the thermal storage liquid  600 . Following this x th  stage of compression and thermal storage, the air A′″ is conveyed down into accumulator  12  as has been described above with respect to other embodiments. Optionally, the heat stored in the thermal storage subsystem  120  in the charging mode may be stored entirely for re-incorporating into air being released when the compressed gas energy storage is operated in a discharging mode, but may in some capacity or quantity be employed for some other purposes of the compressed gas energy storage system such as for helping to regulate temperature of another subsystem, or to operate pneumatic tools and instruments, amongst other uses. It should be noted that, while three stages of compression with respective thermal storage stages are shown in  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, in alternative embodiments a given stage of compression is not necessarily always followed by a stage of thermal storage. Furthermore, in alternative embodiments, incoming air that has not yet been compressed in the compressed gas energy storage system may first pass through a thermal storage subsystem or stage thereof to reduce or increase its heat content prior to entering a compressor, rather than a heat exchanger that might dissipate the heat from the system. 
       FIG.  10    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 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 exchanger  635   a  of a thermal storage subsystem  120  to transfer heat from the thermal storage liquid  600  into the air being conveyed thereby to be conditioned as air A′. Air A′ is presented to a first expander  116   a  driving a generator  114   a  for a first stage of expansion. Following the first stage of expansion, air A′ is then conveyed through a second exchanger  635   b  to transfer stored heat from the thermal storage liquid  600  into the air being conveyed thereby to be conditioned to be air A″, which is then conveyed into expander  116   b  driving generator  114   b  for a second stage of expansion. Following the second stage of expansion, air A″ is then conveyed through any additional stages of the thermal storage subsystem  120 . A last exchanger of the thermal storage subsystem  120  is represented in this example as exchanger  635   x  which transfers stored heat into compressed air being conveyed through expansion stage  635   x  thereby to be conditioned to be air A′″. Following this x th  stage 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 thermal storage subsystem  120  may have been stored from incoming air being compressed during a storage phase of the compressed gas energy storage system, but alternatively or in some combination may have been stored during operation of another aspect or subsystem of the compressed gas energy storage system, such as during temperature regulation of another subsystem, or during an electrical heating process. It should be noted that, while three stages of expansion with respective thermal storage stages are shown in  FIG.  10   , 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. 
       FIG.  11    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 exchanger of the thermal storage subsystem  120 . In this embodiment, a given exchanger 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 heat exchanger  635   a ,  635   b  and  635   x  and airflow is controlled using valves V, as shown in the Figure. This embodiment may be useful 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. 
       FIG.  12    is a schematic view of components of the alternative compressor/expander subsystem of  FIG.  11   , showing airflow during an expansion (release) phase from storage through multiple expander stages and multiple respective heat exchangers 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.  10   . The dashed lines show multiple compression stages the airflow to which is prevented during an expansion phase by the control of valves V. 
       FIG.  13    is a schematic view of components of the alternative compressor/expander subsystem of  FIG.  11   , showing airflow during a compression (storage) phase from the ambient A through multiple compressor stages and multiple respective heat exchangers 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  FIGS.  1  and  12   . The dashed lines show multiple expansion stages the airflow to which is prevented during the compression phase by the control of valves V. 
       FIG.  14    is a sectional view of components of an alternative compressed gas energy storage system  10 C, according to an embodiment. In this embodiment, compressed gas energy storage system  10 C is similar to the other embodiments of the compressed gas energy storage systems described herein. However, in this embodiment the thermal storage subsystem  120  (including any of the suitable variations described herein, including a storage reservoir  610 , source reservoir  606  and related equipment) is located within the accumulator  12  and may be at least partially immersed within the compressed gas in compressed gas layer  14 . The thermal storage subsystem  120  may be positioned within the accumulator  12  during construction via the opening  27  that is thereafter blocked with bulkhead  24  prior to filling shaft  18  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 an anchoring support (not shown). 
     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 to maintain the thermal fluid in its liquid state at the storage temperature. 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 . In some examples, only a portion of the thermal storage subsystem  120 , such as the storage reservoir  610 , may be at least partially nested within the accumulator  12 , and other portions, such as the heat exchangers and the source reservoir  606 , may be spaced apart from the accumulator  12 . 
       FIG.  15    is a sectional view of components of an alternative compressed gas energy storage system  10 D, according to another alternative embodiment. In this embodiment, the compressed energy gas storage system  10 D includes a different type of accumulator  12 D that is not hydrostatically compensated, and may be a salt cavern, an existing geological formation, or manmade. That is, the accumulator  12 D is configured to contain compressed gas but need not include a liquid layer or be associated with a shaft containing water. This is another type of accumulator that may, in some embodiments, be used in place of the accumulators  12  used with respect to other embodiments of the compressed gas energy storage systems described herein. Aspects of the thermal storage subsystems  120  described in this embodiment may be used in combination with the hydrostatically compensated compressed gas energy storage systems described, and aspects of the thermal storage subsystems  120  depicted in other embodiments may be utilized with accumulators similar to accumulator  12 D. In this embodiment, compressed gas energy storage system  10 D 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 highly insulated 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 to maintain the thermal fluid in its liquid state at the storage temperature. The regulating valve  130  opens to allow the pressurized gas in the interior to escape to the pressurized chamber  140  and closes 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 . 
     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. 
     While the embodiment of compressed gas energy storage system  10 D includes an isobaric pressurized 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 . 
     Optionally, any of the thermal storage subsystems  120  described herein may include a thermal conditioning system that can be used to regulate the temperature of the layer of cover gas  602  in the storage reservoir  610  and/or in the source reservoir  606 . For example, the thermal conditioning system may include a fan cooler, heat exchanger, evaporator coils or other such equipment so that it can be used to optionally reduce (or alternatively increase) the temperature of the layer of cover gas  602  when the thermal storage subsystem  120  is in use.