TECHNICAL FIELD

[0001] This invention relates to an energy storage and power production system. BACKGROUND ART

[0002] The following discussion of the background art is intended to facilitate an understanding of the present invention only. The discussion is not an acknowledgement or admission that any of the material referred to is or was part of the common general knowledge as at the priority date of the application.

[0003] Over the past decade, renewable power generation technologies such as solar (using solar photovoltaic cells) and wind (using wind turbines) have been proven to provide a cost-competitive, low carbon alternative to traditional fossil-fuel based technologies such as coal and natural gas generation. However, these renewable technologies are dependent upon uncontrollable weather conditions and can only generate power intermittently when conditions are favourable. Without a form of energy storage, solar and wind generation are dependent upon legacy fossil fuel systems to provide back-up power.

[0004] In order to further displace fossil fuels for power generation, renewable energy technologies must be combined with a cost effective and reliable form of energy storage.

[0005] Whilst lithium ion batteries are already a commercially competitive technology for short-duration energy storage, the high mineral intensity of these batteries prevents them from being a competitive long-duration energy storage solution.

[0006] Hydrogen production from intermittent renewable power, known as ‘Green Hydrogen’ or ‘Green H2’, offers a potential solution for long-duration, large-scale energy storage and transportation without the high mineral requirements of lithium batteries.

[0007] Green hydrogen power systems depend on a source of renewable electricity which provides the electrical input to an electrolyser which separates water into its constituent elements to produce hydrogen and oxygen (in the molecular forms H2 and O2). The hydrogen is then compressed, stored, transported and eventually utilised by existing technologies such as a fuel cell, combustion turbine or engine to generate electrical power when it is required.

[0008] When hydrogen is used as a fuel for thermal power generation technologies such as gas turbines or engines, combustion management must be addressed due to the relatively faster flame propagation speed of hydrogen compared to natural gas combustion.

[0009] A known high thermal efficiency cycle is the supercritical CO2 (SCO2) Brayton Cycle which is a thermodynamic process in which high-purity carbon dioxide working fluid undergoes a series of temperature, pressure and volume changes to convert thermal power into electricity. A SCO2 Brayton Cycle is characterised by the carbon dioxide working fluid existing in the supercritical phase during certain stages of the cycle (or the entirety of the cycle).

[0010] When a substance is heated and compressed to a temperature and pressure beyond the substance’s critical temperature and pressure (denoted T _c and P _c ), it enters the supercritical phase. In the supercritical phase, separate gas and liquid phases do not exist and the substance exists as a homogenous phase with a density like that of a liquid but with the flow and expansion properties of a gas.

[0011] sCC>2 Brayton Cycles have demonstrated superior thermal efficiencies to the Rankine Cycles that have been traditionally used for power generation utilising either steam (typically preferred for many applications) or an organic working fluid, with thermal efficiency defined as useful power produced by the cycle divided by the total thermal input power to the cycle (on a lower heating value (LHV) basis).

[0012] Historically, SCO2 Brayton Cycles have utilised an external heat source such as combustion of coal or natural gas, heat from nuclear reactions, concentrated solar power (CSP) or waste heat from an industrial process. However, more recent research has focussed upon the development of direct fuelled SCO2 power cycles which integrate internal combustion of a fossil fuel such as natural gas into the SCO2 Brayton Cycle. This is a similar concept to traditional combustion turbines, however, using recirculated SCO2 as a working fluid rather than air.

[0013] An example of a direct fuelled SCO2 power cycle is the Allam-Fetvedt Cycle, the viability of which was recently demonstrated by a pilot plant. [0014] As with traditional combustion turbines, the working fluid of the Allam-Fetvedt Cycle is the high-pressure, high-temperature products of combustion which expand across a turbine to produce rotary motion and drive an electrical generator. However, whilst traditional combustion turbines utilise an air-fuel mixture, the Allam-Fetvedt Cycle combusts hydrocarbon fuel in the presence of pure oxygen and supercritical CO2.

[0015] Further describing the Allam-Fetvedt Cycle, with reference to Figure 1 , supercritical CO2 125 is circulated to a combustion chamber 120 along with natural gas fuel 110 pressurised in compressor 115 to form a pressurised natural gas stream 121 to be combusted with high-purity oxygen 123 in the power production system 100. Supercritical CO2 125 is continuously recirculated through the cycle, whilst natural gas 110 is supplied from an external source and high-purity oxygen 123 is generated by a cryogenic Air Separation Unit (ASU) 150. The co-located ASU 150 represents a significant parasitic load and is an integral part of the overall system 100, providing both oxygen for combustion and an important external heat source required to thermally balance the cycle.

[0016] Combustion occurs in combustion chamber 120 at extremely high pressure and temperature (300 bar and 1150°C) and the resulting products of combustion flow to the power generation turbine 130 where they expand to a lower pressure (approximately 30 bar), driving the generator 131 and producing electrical power. A portion of the gross quantity of electrical power is used to power equipment within the cycle such as the SCO2 compressor 166, pumps 115, 156, 171 and ASU 150. The remaining portion of electrical power (net electrical power) is available for export to the grid or direct use at site.

[0017] Published data for the Allam-Fetvedt Cycle indicates that a system, such as system 100, projected to produce 303 MWe of net electrical power requires 511 MWt of thermal power input (implied thermal efficiency of 59.3%). The combustion chamber 120 mass balance for this system is presented in Table 1 below, assuming that the thermal input is provided by pure methane (CH4) fuel. Table 1 Allam-Fetvedt Combustion Mass Balance for System 100

RMM is relative molecular mass.

[0018] The exhaust gas 134 leaving the turbine 130 flows to a recuperator 140, which is a multi-channel heat exchanger, with hot turbine exhaust gas 134 on the hot side and cooler supercritical CO2 138 on the cold side of recuperator 140. In this sense, the recuperator 140 is an economiser which transfers residual heat from the turbine exhaust gas 134 into the supercritical CO2 138 before it enters the combustion chamber 120, providing pre-heat to the supercritical CO2 138 prior to combustion and improving the thermal efficiency of the cycle.

[0019] The temperature difference between the turbine exhaust gas 134 entering the recuperator 140 and the recycled supercritical CO2 125 leaving the recuperator 140 is called the ‘approach temperature’. The cycle’s efficiency is optimised by reducing the approach temperature as far as is practical (i.e. the recycled supercritical CO2 125 temperature approaches the temperature of the turbine exhaust gas 134). Approach temperature can be reduced by adding a significant quantity of relatively low temperature heat from an external heat source. [0020] The external heat source is the ASU 150 which generates surplus heat which is thermally integrated into the recuperator 140 to improve the overall cycle efficiency.

[0021] The recuperator 140 also pre-heats the oxygen produced by the ASU 150 prior to combustion. Liquid oxygen 154 from the ASU 150 is blended with a determined portion 139 of the recirculated CO2 138 extracted upstream of the CO2 recycle pump 171 to moderate the flame temperature in combustion chamber 120. The blended oxygen and CO2 stream 154 is pumped to >300 bar by the oxygen pump 156. This high-pressure blended O2/CO2 stream 158 (25 mol% O2) enters the cold side of the recuperator 140 for pre-heating prior to inlet to the combustion chamber 120.

[0022] Table 2 summarises the hot and cold streams in the recuperator 140.

Table 2 Recuperator Hot and Cold Streams

[0023] In the recuperator, hot turbine exhaust gas 134 will cool from approximately 730°C to 45°C at a pressure of approximately 30 bar. At a temperature of approximately 230°C, the water portion of the exhaust gas will begin to condense. The presence of liquid water and carbon dioxides presents a corrosion risk in the recuperator and downstream equipment.

[0024] Downstream of the recuperator 140, the exhaust gas 142 flows to the exhaust cooler 144, where its temperature is further reduced so that the water molecules formed by the combustion process drop-out into the liquid phase so that they can be separated from the CO2. The cooling source can be either water provided by an evaporative cooling tower or direct air cooling. The cooled CO2 and water mixture 148 then flows to the Water Separator Vessel (WSV) 160 where the gas (CO2) and liquid (water) phases disengage and separate, with reject water 164 leaving via the bottom of the WSV 160 and CO2 162 via the top. [0025] Turning to the supercritical CO2 recompression unit 165, the CO2 162 then flows to the CO2 compressor 166 which boosts the pressure beyond the critical pressure of CO2. Downstream of the CO2 compressor 166, an export portion 168 of the CO2 equal to the quantity formed by the combustion process is separated from the stream 162. This export portion 168 of CO2 is then either sequestered underground (in a process that typically presents technical challenges), used for industrial purposes or discharged into the atmosphere. The remaining CO2 169 is then cooled into its liquid form by the compressor aftercooler 170 before its pressure is increased to approximately 300 bar by the CO2 recycle pump 171.

[0026] The high-pressure, liquid CO2 138 discharged by the CO2 recycle pump 171 then flows to the recuperator 140 where its temperature is increased, returning the CO2 into a supercritical state (SCO2). The resulting SCO2 125 flows to the combustion chamber 120, completing the cycle.

[0027] The Allam-Fetvedt cycle is extremely efficient, with reported thermal efficiency approaching, and potentially exceeding, 60% (defined as the net quantity of power generated divided by the LHV thermal power of the fuel). In comparison, a traditional open cycle turbine may achieve thermal efficiencies of 40%, a reciprocating engine may achieve up to 50%. A modern combined cycle power station may achieve up to 60% but at the cost of significant operational complexity.

[0028] Furthermore, the CO2 by-product produced by combustion is removed downstream of the CO2 compressor 166 in a high-pressure, captive and exportable state. This contrasts with traditional combustion turbines where CO2 is contained in low pressure exhaust gas which must be treated to recover the CO2 which is then compressed at additional cost and loss of efficiency.

[0029] The supercritical CO2 working fluid is also purposefully extremely dense compared to the fuel-air mix of traditional turbines and the steam working fluid of traditional Rankine cycles. This results in extremely compact and cost-effective equipment for the Allam-Fetvedt Cycle and supercritical C0 ₂ cycles in general.

[0030] Further, by utilising high purity oxygen as part of the combustion mixture, the Allam-Fetvedt cycle eliminates the presence of nitrogen (rejected in the ASU 150) in the combustion chamber 120. Nitrogen and oxygen form nitrogen oxides (NOx) at high pressure and temperature (such as the typical conditions of a combustion chamber 120). Traditional combustion turbines limit the combustion temperature to keep NOx emissions within legislative requirements; however, this reduces the efficiency of the process since high combustion temperatures generally achieve higher efficiencies. By eliminating the presence of nitrogen, NOx emissions are reduced to zero and combustion temperatures greater than those of traditional gas turbines can be achieved.

[0031] It would be desirable to provide an energy storage and power production system that has greater thermal efficiency than the prior art cycles described above and eliminates C0 ₂ emissions.

SUMMARY OF INVENTION

[0032] The invention provides, in one aspect, a combined energy storage and power production system comprising: a hydrogen and oxygen production unit, preferably green hydrogen production by electrolysis producing oxygen as a by-product; and a hydrogen compression, cooling and storage unit for compressing, cooling and storing hydrogen from the hydrogen and oxygen production unit; an oxygen compression, cooling and storage unit for compressing, cooling and storing oxygen from the hydrogen and oxygen production unit; and a power production unit wherein supercritical carbon dioxide is expanded across a turbine for power production and recompressed in a Brayton Cycle using internal hydrogen-oxygen combustion as a thermal power source, said hydrogen being supplied from said hydrogen compression, cooling and storage unit and said oxygen being supplied from said oxygen compression, cooling and storage unit; and optionally, a water recovery, treatment and storage system wherein said power production unit includes a combustion chamber wherein hydrogen-oxygen combustion occurs in the presence of supercritical carbon dioxide. [0033] Certain technologies for hydrogen and oxygen production may operate more efficiently when a heat source is available. Desirably, the hydrogen and oxygen compression units are thermally integrated into the water recovery, treatment and storage unit to provide pre-heating of electrolysis feedwater, if required. The optimum temperature for electrolysis is dependent upon the type of electrolysis technology selected, with certain technologies operating most efficiently at elevated temperatures. Using compression heat to pre-heat electrolysis feedwater potentially eliminates the requirement for an external heat source for feedwater preheating and will improve the overall energy efficiency of the system. The hydrogen and oxygen compression, cooling and storage units may also respectively include hydrogen and oxygen storage.

[0034] By integrating hydrogen and oxygen production within one unit, though it will be understood that more than one hydrogen and oxygen production unit could be provided, hydrogen and oxygen are produced simultaneously in the stoichiometric proportions required for combustion and there is no requirement for the power production system to include an air separation unit (ASU) and this parasitic load, as well as associated capital expenditure, operating expenditure and complexity for an ASU is avoided. Further, since hydrogen is combusted with oxygen, carbon dioxide is not generated during combustion. There is no requirement for separating and compressing excess carbon dioxide and utilising or sequestering this carbon dioxide. The system is therefore advantageous in achieving decarbonised power production.

[0035] Preferably, the hydrogen and oxygen production unit involves hydrogen production by electrolysis producing oxygen as a by-product, the ratio of hydrogen to oxygen corresponding with the stoichiometric ratio for combustion. Electrical power for electrolysis is desirably generated from renewable energy such as wind or solar energy, consistently with a green hydrogen system.

[0036] The power production system conveniently includes a heat exchanger to heat a supercritical CO2 stream (or, in short, a SCO2 stream), which is typically recirculated through the power production system, by heat exchange with a hot exhaust gas stream from the power production unit. The heat exchanger is conveniently a recuperator, preferably in the form of a multiple flow channel heat exchanger with two expected hot streams, exhaust gas and hot compressed CO2, and three cold streams: 1) cool CO2 for power production, 2) cool CO2 for turbine blade cooling, and 3) oxygen/CC>2 mixture. [0037] The system would typically include a system for separating carbon dioxide and water downstream of the recuperator. The system may include an exhaust gas cooler for condensing water and a water separator vessel to separate water from carbon dioxide. Desirably, the water separator vessel is configured so that the quantity of water separated is equivalent to the quantity created through the combustion of hydrogen. The desired degree of water separation may be achieved through vessel sizing and the configuration of vessel internal devices such as inlet and outlet devices and demisters. The exhaust gas cooler and water separator vessel may be replaced with an alternative; for example, with a cyclone separator which would achieve water separation through partially recoverable pressure drop and momentum effects rather than by a permanent reduction in temperature. This would potentially increase the thermal efficiency of the power production system.

[0038] Desirably, water separated from the exhaust gas is treated and returned to the hydrogen and oxygen production unit. By recycling water, the system can significantly reduce its water consumption making it suitable for installation in water constrained areas, addressing one of the principal limitations of traditional combined cycle power stations and planned systems to utilise hydrogen fuel in combustion turbines or reciprocating engines where water contained in the exhaust gas will be unrecoverable and vented to atmosphere.

[0039] The combustion chamber may be of diffusion or premixed type. A diffusion combustion chamber involves separate injection of fuel and oxidant (here H2 and O2) whereas a premixed combustion chamber would involve upstream mixing of Fteand O2. Without wishing to be bound by theory, a disadvantage of premixed combustion is that the stable combustion range is narrower than that of an equivalent diffusion combustion chamber, resulting in an increased likelihood of flashback. Flashback describes a situation where a flame front propagates upstream of the combustion chamber. In a flashback situation, combustion may occur upstream of the combustion chamber in equipment systems that are not designed for combustion temperatures. Flashback occurs when the flame propagation speed is greater than the speed of the fuel/oxidant mixture entering the combustion chamber. Flydrogen fuel combusts more readily than natural gas, therefore, the flame propagation speed is faster and the risk of flashback is greater. [0040] Yet a premixed combustion chamber type may be preferred so as to prevent flame temperature from exceeding the temperature limits of construction materials of the system. This concern is particularly relevant to hydrogen-oxygen combustion which may produce combustion temperatures greater than those associated with natural gas combustion. In this case, the combustion chamber must maintain hydrogen/oxygen/supercritical CO2 velocities that are greater than the flame propagation speed. Premixing may be achieved by inducing a swirling flow path in the hydrogen/oxygen/supercritical CO2 mixture. Swirling may be induced, for example, by flowing an oxygen/supercritical CO2 mixture over a series of stationary blades with hydrogen fuel being injected through small holes in the surface of the blades. Swirling ensures adequate mixing of hydrogen/oxygen/supercritical CO2. A central region of the swirling hydrogen/oxygen/supercritical CO2 flow exhibits lower velocities than the peripheral region. Therefore, flashback is most likely to occur in this central region. Optionally, additional supercritical CO2 may be injected through a nozzle situated in the centre of the stationary blades. The increased hydrogen/oxygen/supercritical CO2 velocity in the central region, through this or an alternative arrangement, balances the high flame propagation velocity associated with hydrogen, preventing flashback and achieving stable combustion in the combustion chamber.

[0041] Preferably, one or both of the hydrogen and oxygen compression, cooling and storage units involve multi-stage compression, desirably with intercoolers between the compression stages. A discharge cooler for further cooling of compressed hydrogen and/or oxygen may also be provided. Desirably, coolant for cooling within both the hydrogen and oxygen compression units is supplied from the same coolant supply system. Hot coolant leaving the compression units provides a potential heat source for pre-heating the electrolysis feedwater in cases where the selected hydrogen and oxygen production technology operates most efficiently at elevated temperature. In this circumstance, the achievable electrolysis feedwater temperature is limited by the coolant temperature, which is expected, for example, to be approximately 120°C.

[0042] An alternative embodiment of the power production system features a multi-stage recuperator, desirably a two-stage recuperator with inter-stage water separation between a first stage recuperator operating at a first temperature; and a second stage recuperator operating at a second temperature, where the second temperature is lower than the first temperature. This embodiment, which may be applied to power production units involving other combustion processes including combustion of fuels, such as hydrocarbons, in the presence of supercritical carbon dioxide, has the advantage of preventing or mitigating carbonic acid corrosion which occurs when liquid water and CO2 are present and is particularly severe at high temperatures and pressures as expected in a supercritical CO2 Brayton cycle.

[0043] The first stage recuperator (which may conveniently be designated as the high- temperature recuperator), is desirably a multiple channel heat exchanger where supercritical CO2 and oxygen are heated through heat exchange with the exhaust gas stream from the power production unit. As the exhaust gas cools in the high-temperature recuperator at pressure, for example, approximately 30 bar, the water contained within the exhaust gas will begin to condense at, for example, approximately 230°C whilst the CO2 remains in the gas phase.

[0044] Exhaust gas leaving the high-temperature recuperator flows to the high-temperature water separator where the liquid water is separated at relatively high pressure and high temperature (for example approximately 30 bar and 230°C). The high-temperature water separator can be either a cooler plus pressure vessel arrangement or a cyclonic separator, desirably a supersonic cyclone separator.

[0045] Dehydrated exhaust gas flows from the high-temperature water separator to the second stage recuperator (which may conveniently be designated as the low- temperature recuperator). The low-temperature recuperator is desirably a multiple channel heat exchanger with two expected hot streams, dehydrated exhaust gas and hot compressed CO2, and three cold streams: 1) cool CO2 for power production, 2) cool CO2 for turbine blade cooling and 3) oxygen/CC>2 mixture.

[0046] Exhaust gas leaving the low-temperature recuperator may still contain traces of water and the system may include a low-temperature water separation system for further separation of water from carbon dioxide downstream of the low-temperature recuperator, though substantially all the water formed by combustion will be separated by the high-temperature water separator which makes a single stage recuperator an option and a need for more than two recuperation stages likely unnecessary as described below. The low-temperature water separation system may consist of an exhaust gas cooler and a low-temperature water separator vessel. Desirably, the low- temperature water separation system is designed so that the total quantity of water separated by the power production system is equivalent to the quantity created through the combustion of hydrogen. If the high-temperature separator can remove a quantity of water equivalent to the quantity formed by combustion, it may be possible to eliminate the low-temperature water separation system. The low-temperature water separation system may be a cyclonic separator.

[0047] The water separated from the power production system is conveniently treated and stored in a water storage vessel, preferably insulated, from where it is recycled to the hydrogen and oxygen production unit as required for electrolysis. The efficiency of certain technologies for hydrogen and oxygen production by electrolysis may be improved when the process occurs at high temperature. The favoured two-stage recuperator design with inter-stage, high-temperature water separation, allows separation of the majority of the water, at approximately 230°C, and can potentially achieve higher electrolysis feedwater temperatures than those achieved by using hydrogen and oxygen compressor coolant for electrolysis feedwater pre-heating, where feedwater temperatures are limited by the maximum coolant temperature of, for example, approximately 120°C.

[0048] The combined energy storage and power production system of the present invention, based on a supercritical carbon dioxide (sCC ) cycle, is expected to achieve efficiencies that are comparable with, and potentially superior to, fuel cells whilst also providing the inertia and consequent grid stabilising capabilities that are characteristic of combustion turbines.

[0049] In another embodiment, the present invention provides an electrical grid supplied with electricity from embodiments of an energy storage and power production system as described above. Whilst the energy storage and power production system could be implemented for a single site, advantageously for an industrial or mining facility, it may supply electricity to an electrical grid which may also be supplied with electricity sources such as the renewable energy sources described above. The energy storage and power production system or electrical grid may supply a range of electricity users, not necessarily co-located, with a focus on industrial users though domestic use of such electricity is not precluded.

[0050] The combined energy storage and power production system of the present invention overcomes a principal disadvantage encountered by Allam-Fetvedt cycles, that is, in the challenge of utilising or sequestering the high-pressure CO2 by-product produced by hydrocarbon combustion. Corrosion risks are also addressed. While potential uses include Enhanced Oil Recovery (EOR) or as a feedstock for the chemical, food or beverage industries, the quantities of CO2 that would be produced if the Allam-Fetvedt Cycle were widely adopted would be greatly in excess of the quantities of CO2 that could be productively utilised by industry. While geological sequestering is an option for disposing of surplus CO2, this typically involves significant additional expense due to the subsurface drilling that is required. Furthermore, geological conditions are often not suitable for this purpose. Additionally, the requirement for pure oxygen as part of the combustion mixture introduces a significant parasitic load - for the ASU - into the Allam-Fetvedt Cycle, as well as additional capital expenditure (CAPEX) and complexity.

[0051] The combined energy storage and power production system of embodiments of the present invention include design features intended to maximise the system’s ability to utilise low-cost surplus renewable energy, store this energy chemically as hydrogen and oxygen and then generate high value electrical power during periods of renewable energy deficit. The system advantageously includes control features which maximise the utilisation of the system’s hydrogen and oxygen storage volume, allowing the system to continue generating power when the pressure in the storage vessels declines below the value normally required to supply hydrogen and oxygen fuel to the system.

BRIEF DESCRIPTION OF THE DRAWINGS

[0052] Further features of the combined energy storage and power production system of the present invention are more fully described in the following description of several non-limiting and preferred embodiments thereof. This description is included solely for the purposes of exemplifying the present invention. It should not be understood as a restriction on the broad summary, disclosure or description of the invention as set out above. The description will be made with reference to the accompanying drawings in which:

[0053] Figure 1 is a: process flow diagram for an Allam-Fetvedt power production system of the prior art. [0054] Figure 2 is a: process flow diagram for an energy storage and power production system including a single-stage recuperator according to a first embodiment of the present invention.

[0055] Figure 2a is a: process flow diagram for a portion of an energy storage and power production system as shown in Figure 2 but showing inclusion of a two-stage recuperator according to a second embodiment of the present invention.

[0056] Figure 3 is a: schematic diagram of a premixed combustion chamber which may be used in the system of Figure 2 and Figure 2a.

[0057] Figure 4 is a: schematic diagram of a premixed combustion chamber preferred for use in the system of Figure 2 and Figure 2a.

[0058] Figures 5a, b and c represent different modes of operation of the Flydrogen and Oxygen compression, cooling and storage units.

DESCRIPTION OF PREFERRED EMBODIMENTS

[0059] Referring to Figure 2, there is shown a combined energy storage and power production system 200 in which intermittent renewable power (solar, wind etc.) preferably provides the electrical input required for electrolysis subsystem 100 for separating water into hydrogen (H2) and oxygen (O2). Electrolysis subsystem 100, which is further referred to as the hydrogen and oxygen production subsystem or unit 100, may be conducted using any electrolytic arrangement and electrolytic cell or electrolyser 101 known in the art of water electrolysis. Alkaline electrolysis may be preferred in this embodiment. Hydrogen and oxygen production unit 100 may also be conducted using any thermal process or catalytic direct sunlight to hydrogen and oxygen production process that produces hydrogen and oxygen from water. Both products of water electrolysis are collected in the respective low-pressure hydrogen and oxygen receiver vessels 201 and 301. This contrasts with usual electrolysis practice where the oxygen would be utilised off-site or vented if there is no convenient way of utilising it.

[0060] The energy storage and power production system 200 has two modes of operation: 1. H2-O2 Production Mode - electrolysis, compression and storage occur when surplus electricity is available from renewable power generation assets; and

2. Power Generation Mode - Electricity is generated by direct fuelled SCO2 power cycle using stored hydrogen-oxygen as fuel.

[0061] The long-duration energy storage and power production system 200 utilises cheap surplus electricity and produces high-value electricity during extended periods of renewable energy deficit relative to electricity demand.

[0062] The overall system consists of the following subsystems or units:

• Hydrogen and Oxygen Production 100

• Hydrogen Compression and High-Pressure Storage 200A

• Oxygen Compression and Medium-Pressure Storage 300

• Direct Fuelled SCO2 Power Generation Cycle or Power Production Unit 400

Hydrogen Intermittent electricity produced by renewable technologies is used to generate Green Hydrogen and Oxygen by electrolysis (either Proton Exchange Membrane, Alkaline or Solid Oxide). Hydrogen and oxygen are compressed and stored, providing a form of chemical energy storage. Critically, hydrogen and oxygen are produced by electrolysis in the same proportions required for combustion, as shown by the processes:

2 H ₂ 0 2 if 2 + 0 ₂ Electrolysis 11I ₂ + 0 ₂ ® 2 H ₂ 0 Combustion

[0063] Hydrogen and oxygen are produced and consumed in the same proportions; therefore, the overall water balance of the system is neutral since water formed by combustion is recovered from the SCO2 power production unit 400, treated and returned to the hydrogen and oxygen production unit 100. Furthermore, since the quantity of oxygen required for hydrogen combustion is cogenerated by the electrolysis process, an external Air Separation Unit (ASU) is not required to produce Oxygen. [0064] When electricity is required, stored hydrogen and oxygen are used as fuel and oxidant in the combustion chamber of the supercritical CO2 (SCO2) Brayton cycle power production unit 400 to generate power. In the combustion chamber 401 , hydrogen- oxygen combustion occurs in the presence of high-pressure (300 bar) SCO2 403, providing energy input into the cycle.

[0065] The hydrogen and oxygen production unit 100 operates during H2-O2 Production Mode when cheap surplus electricity is available from renewable power generation assets. Typically, the subsystem 100 does not operate simultaneously with the Direct Fuelled SCO2 Power Production Unit 400 during Power Generation Mode, however, simultaneous operation of all subsystems or units is possible. The operation of the Hydrogen Compression and Storage subsystem 200 and the Oxygen Compression and Storage subsystem 300 differ, in embodiments of the invention, between H2-O2 Production Mode and Power Generation Mode.

[0066] Figure 5a demonstrates the equipment line-up of the Hydrogen Compression and Storage subsystem 200A during H2-O2 Production Mode. Low pressure Hydrogen produced by the electrolyser 101 of the hydrogen and oxygen production subsystem 100 is stored in the LP Hydrogen Receiver 201 at 30 bar(g). The function of the LP Hydrogen Receiver 201 is to provide a suction vessel for the compression process during H2-O2 Production Mode.

[0067] The hydrogen compressor 203 can be either a reciprocating, diaphragm or centrifugal compressor. Non-mechanical compression systems such as electrochemical, metal hydride or ionic liquid compressors can also be used. The following process description is focussed upon a reciprocating mechanical compressor such as a reciprocating piston or diaphragm compressor.

[0068] The hydrogen compressor 203 desirably consists of multiple stages with intercoolers installed between stages (multiple stages, intercoolers and discharge coolers are not shown in attached figures for brevity). In accordance with Standard API 618, the contents of which are hereby incorporated herein by reference, the hydrogen discharge temperature from each stage will be limited to approximately 135°C.

[0069] Table 3 presents a preliminary design for a 4-stage compressor that receives Hydrogen at an initial pressure of 30 bar(g) and delivers Hydrogen to the HP Hydrogen Storage Vessel 205 at approximately 460 bar(g).

Table 3 Hydrogen Compression Preliminary Stage Design

[0070] The details provided in Table 3 are indicative and the actual compressor 203 design may feature a greater number of stages and a higher final pressure. Hydrogen storage pressures for HP Hydrogen Storage Vessel 205 greater than 700 bar(g) are achievable with additional compression stages.

[0071] The hydrogen compressor 203 stages are powered by electric motors (not shown) which are supplied with surplus electricity from renewable power generation assets during H2-O2 Production Mode.

[0072] Hydrogen is stored in the HP Hydrogen Storage Vessel 205 at 460 bar(g) to be used as fuel for power generation when required. The very high storage pressure results in a low specific volume, allowing large quantities to be stored in a relatively small vessel. Hydrogen can be stored in the HP Hydrogen Storage Vessel 205 for long periods of time with negligible loss of contained energy, making the system suitable for long-duration, seasonal energy storage.

[0073] During the initial phase of Power Generation Mode, Hydrogen stored in the HP Hydrogen Storage Vessel 205 at 460 bar(g) is discharged to the combustion chamber 401 of the Direct Fuelled SCO2 Power Production unit 400 providing fuel for the process. During Power Generation Mode, the initial line-up of the Hydrogen Compression and Storage subsystem 200A is demonstrated by Figure 5b.

[0074] The combustion chamber 401 operates at 300 bar(g), therefore, initially there is 160 bar of differential pressure between the HP Hydrogen Storage Vessel 205 and combustion chamber 401. As hydrogen is consumed by the Power Generation Cycle, the pressure in the HP Hydrogen Storage Vessel 205 will decline. Eventually, there will no longer be adequate differential pressure between the HP Hydrogen Storage Vessel 205 and the combustion chamber 401 to ensure the required flow rate of hydrogen.

[0075] Direct fuelled SCO2 power cycles operate most efficiently at 200 to 400 bar(g) on the high-pressure side. The high-pressure side of the power cycle is pressurised by the CO2 Pump 421. Embodiments of the present invention desirably include a cascade control function whereby the discharge pressure set point of the CO2 Pump 421 is dependent upon the pressure of the HP Hydrogen Storage Vessel 205.

[0076] As the pressure of the HP Hydrogen Storage Vessel 205 approaches the level at which there will no longer be adequate pressure differential to deliver hydrogen fuel to the Direct Fuelled SCO2 Power Production unit 400, the cascade control function will act to reduce the discharge pressure of the CO2 Pump 421. This will reduce the operating pressure of the high-pressure side of the power cycle and ensure that there is adequate differential pressure between the HP Hydrogen Storage Vessel 205 and the combustion chamber 401.

[0077] The cascade control function will reduce the discharge pressure set point of the CO2 Pump 421 down to a minimum value of, for example, 200 bar(g). When the discharge pressure set point reaches this minimum value, the Hydrogen Compression and Storage subsystem 200A will adopt the line-up depicted in Figure 5c.

[0078] The subsystem control valves (210a-210d and with valve open/closed states as indicated) will line-up the HP Hydrogen Storage Vessel 205 as a suction vessel for the Hydrogen Compressor 203, which will start-up and deliver hydrogen to the HP Hydrogen Receiver 207. The HP Hydrogen Receiver 207 is maintained at a pressure greater than 200 bar(g) and acts as a discharge vessel between the Hydrogen Compressor 203 and the combustion chamber 401. The volume of the HP Hydrogen Receiver 207 is relatively small compared to the HP Hydrogen Storage Vessel 205 since its function is to provide a discharge volume for the hydrogen compressor 203 rather than a large volume for energy storage.

[0079] Hydrogen 206 is discharged from the Hydrogen Storage Vessel (HSV) 205 into the combustion chamber 401 where it is combusted with oxygen 402, sourced from electrolyser 101 , in the presence of supercritical CO2 (SCO2) 403, providing thermal input to the power production system 400. [0080] The quantity of hydrogen required to fuel a power production system, such as system 200 described here, is calculated by dividing the required thermal input by the Lower Heating Value of hydrogen (119.96 MJ/kg). Using the previously described Allam-Fetvedt cycle as an example, the thermal input of 511 MWt can be provided by combustion of 4.26 kg/s of hydrogen. On the basis of the United States Department of Energy (US DOE) objective to achieve water electrolysis system efficiency of 44 kWh per kg H2 (US DOE, Technical Targets for Hydrogen Production 2020’ the contents of which are hereby incorporated herein by reference), this implies an average continuous power input of 675 MWe to produce 4.26 kg/s of hydrogen though it must be noted that this power input will not normally be provided continuously but rather intermittently by renewable power generation assets.

[0081] A mass balance for the electrolyser 101 of the hydrogen and oxygen production unit 100 is exemplified in Table 4 below:

Table 4 Electrolysis Mass Balance

RMM is relative molecular mass

[0082] Hydrogen and oxygen 105 and 106 are respectively produced by the Hydrogen and Oxygen production unit 100, compressed and stored in HSV 205 and Oxygen Storage Vessel (OSV) 305 in the same stoichiometric proportions as required for combustion. Therefore, the Hydrogen and Oxygen production unit 100 supplies the full oxygen requirement for combustion in combustion chamber 401 and there is no requirement for supplemental oxygen generation from an ASU. The ability to operate without a cryogenic ASU, which involves an energy intensive process, avoids capital and operating costs, including the energy costs imposed by parasitic load, and increases the thermal efficiency of energy storage and power production system 200

[0083] Low pressure oxygen 106 produced by electrolysis in hydrogen and oxygen production unit 100 is recovered into the Low Pressure (LP) Oxygen Feed or Receiver vessel 301 from where it is compressed to a final medium pressure, for example of approximately 460 bar, by the oxygen compression unit 303. The operation of the Oxygen compression and storage unit 300 is equivalent to that of the Hydrogen compression and storage unit 200A described above during both H2-O2 Production mode and Power Generation Mode.

[0084] Oxygen 427 from the OSV 305 is blended with a portion 423 of the recirculated CO2 422 taken from downstream of the CO2 recycle pump 421. The high-pressure oxygen/C02 stream 428 is then pre-heated in the recuperator 408 before flowing as stream 402 to the combustion chamber 401.

[0085] Both hydrogen 208 and oxygen/sC02 mixture 402 are fed to the combustion chamber 401 , along with the recirculated stream of CO2403.

[0086] The design of the combustion chamber 401 differs from that of the Allam-Fetvedt cycle based on natural gas, and for example as described below, since it must accommodate the faster flame speed associated with combustion of hydrogen 208 compared to combustion of natural gas 121 in hydrogen and oxygen production unit 100. Furthermore, premixed combustion may be required due to the potentially higher temperatures associated with hydrogen-oxygen combustion compared to natural gas.

[0087] Combustion conditions in the combustion chamber 401 are otherwise similar to those for an Allam-Fetvedt Cycle (approximately 300 bar and 1150°C); however - and in contrast - the only product of combustion is water since there is no carbon present in the fuel: hydrogen. No additional CO2 is produced by combustion; therefore, there is no CO2 by-product - eliminating the associated CO2 utilisation and disposal issues that are a major disadvantage of the natural gas or hydrocarbon based Allam-Fetvedt Cycle. The only CO2 in the system is the stream 403 of supercritical CO2 working fluid that is continuously circulated through the power production system 200. A combustion mass balance is provided in Table 5 below:

Table 5 Hydrogen Fuelled Combustion Mass Balance

RMM is molecular mass.

[0088] Another difference from an Allam-Fetvedt Cycle is that power production system 400 will produce approximately 65% more water, resulting in a proportionally higher partial pressure of water in the combustion product mixture. The composition of the products of combustion mixture is predominantly CO2 with a small portion of water formed during the combustion process (approximately 9% on a molar basis). The products of combustion 404 flow, at approximately 1150°C and 300 bar, to the power generation turbine 405 where they expand to a lower pressure (approximately 30 bar), driving the generator 406 and producing electricity.

Exhaust gas is discharged from the turbine 407 at approximately 30 bar and 750°C and flows to the single stage recuperator 408. The single stage recuperator 408 is a multiple flow channel heat exchanger. Table 6 summarises the recuperator 408 hot and cold streams: Table 6 Recuperator Hot and Cold Streams

[0089] The cooled exhaust gas 409 from the single stage recuperator 408 is further cooled in an exhaust cooler 410 which may be a conventional shell and tube heat exchanger with exhaust gas 409 on the hot side and cooling medium or coolant on the cold side or an air-cooled heat exchanger if ambient conditions are suitable to achieve the desired temperature of cooled exhaust gas.

[0090] Cooled exhaust gas 411 enters the water separator vessel (WSV) 412, of a water, treatment and storage system, where the water by-product 426 is separated. The process conditions, physical dimensions and internal design (diameter, height and design of inlet and outlet devices and vessel internal devices) of the WSV 412 are selected so that the WSV 412 is adequately designed to separate a quantity of water 426 equivalent to that which is produced by combustion when the power production system 400 is running at maximum power. The separated water 426 is treated and stored in the water storage vessel 103, from where it is recycled to the hydrogen and oxygen production unit 100. Recycling the water formed by combustion significantly reduces the freshwater requirements of the system which is a significant benefit in water constrained environments. Water treatment stage 104 may include deaeration, filtering and de-oiling prior to returning water to the electrolysis system 100.

[0091] The exhaust cooler 410 and WSV 412 may be replaced with a cyclone separator, desirably a supersonic cyclone separator, which will remove water 426 by exploiting partially recoverable pressure drop and momentum effects rather than a permanent reduction in the temperature of the exhaust gas 409. This may improve the overall efficiency of system 400 by reducing the quantity of thermal energy removed from the system 400 to achieve water separation.

[0092] CO2 413 from the WSV 412 flows to the CO2 compressor 414 which boosts the pressure beyond the critical pressure of CO2. It is to be noted that there is no CO2 offtake downstream of the CO2 compressor 414 since no additional CO2 is formed during combustion. The system 400 eliminates the problems of CO2 utilisation and disposal encountered with a natural gas based direct fuelled supercritical CO2 power cycle such as the Allam-Fetvedt cycle. The CO2 temperature will increase during compression with hot, compressed CO2 415 leaving the compressor at approximately 150°C and 100 bar. Hot, compressed CO2 415 then flows to the single stage recuperator 408 where it provides useful low-temperature heat input to pre-heat the cool recirculated CO2 stream 422, Turbine Cooling SCO2 stream 424 and the blended oxygen/CC>2 stream 428.

[0093] The CO2 stream 416 leaving the single stage recuperator 408 is then further cooled by the CO2 cooler 417, preferably to a temperature less than 31 °C, below which the CO2 will be a dense-phase liquid at 100 bar. The CO2 cooler 417 can be either a shell and tube heat exchanger with CO2 on the hot side and coolant on the cold side or an air-cooled heat exchanger if ambient conditions are suitable to achieve the desired temperature of cooled CO2.

[0094] Cooled liquid CO2 418, 420 then flows to the CO2 recycle pump 421 which increases its pressure to approximately 300 bar. The high pressure, liquid CO2 422 discharged by the CO2 recycle pump 421 then flows to the recuperator 408 where its temperature is increased to approximately 700°C through heat exchange with the turbine exhaust gas 407 and hot compressed CO2 415, returning the CO2 into a supercritical state. The supercritical CO2 403 then flows to the combustion chamber 401 , completing the cycle.

[0095] A portion 424 of the high-pressure CO2 stream 422 is separated upstream of the recuperator 408 and flows separately to the recuperator 408. This portion 424 of the high pressure CO2 stream 422 is used for turbine blade cooling and is heated by the Recuperator 408 to a lower temperature than the main SCO2 stream, approximately 400°C. [0096] Another portion 423 of the high-pressure CO2 stream 422 is separated and blended with the high pressure Oxygen 427 from the HP Oxygen Storage Vessel 305 to produce the mixed Oxidant Stream 428 which is preheated by the Recuperator.

[0097] Referring to Figure 2a, there is shown an alternative embodiment which, though otherwise adopting the features of the power production system 400 shown in Figure 2, features a two-stage recuperator 408, 408a with inter-stage water separation in contrast to a single stage recuperator. The two recuperator stages of Figure 2a are designated as high-temperature recuperator stage 408 and low-temperature recuperator stage 408a.

[0098] The high-temperature recuperator stage 408 is a multiple flow channel heat exchanger. Table 7 summarises the high-temperature recuperator stage 408 hot and cold streams:

Table 7 High-Temperature Recuperator Hot and Cold Streams

[0099] As the exhaust gas cools in the high-temperature recuperator stage 408, the water portion will condense. At the high-temperature recuperator stage 408 operating pressure of 30 bar, condensation of water occurs at approximately 230°C. Under these conditions, the presence of liquid water and CO2 would lead to the formation of carbonic acid which would corrode the steel channels of a single stage recuperator. This corrosion can be mitigated by separating the liquid water from the exhaust gas. Exhaust gas 407a leaves the high-temperature recuperator 408 at approximately 230°C and 30 bar and flows to the high-temperature water separator 412a where liquid water 430 is separated from CO2.

[00100] Supplemental pre-cooling may be required upstream of the high- temperature water separator 412a to ensure sufficient condensation of water from the exhaust gas 407a. The high-temperature water separator 412a can be either a water separation vessel (WSV) or a cyclonic separator, desirably a supersonic cyclone separator. The advantage of a vessel separator is that separation can be achieved with minimal pressure drop, however, the degree of water/CC>2 separation will be less than that achieved by a cyclonic separator (which requires some unrecoverable pressure drop to operate effectively).

[00101] Liquid water 430 leaves the separator 412a at approximately 230°C and 30 bar and flows to the insulated water storage vessel 103, via treatment stage 104, from where it is recycled to the electrolyser 100. By separating the water at relatively high temperature and retaining the heat by storing the water in a thermally insulated vessel, the system eliminates the requirement for feedwater pre-heating for electrolyser technologies that operate most efficiently at elevated temperature and pressure (up to approximately 230°C and 30 bar).

[00102] The high-temperature water separator 412a is designed to separate the majority of the water formed by combustion, particularly if a cyclonic type separator is used. The dehydrated CO2407b leaves the separator and flows to the low-temperature recuperator 408a. The low-temperature recuperator 408a is a multi-channel heat exchanger with hot and cold streams summarised by Table 8:

Table 8 Low-Temperature Recuperator Hot and Cold Streams [00103] In the low-temperature recuperator stage 408a, heat transfer occurs from the hot streams into the cold streams. This provides pre-heat for the cold streams before they enter the high-temperature recuperator 408 and pre-cooling of the hot streams ahead of compression / pumping.

[00104] The remaining combustion, power turbine, compression and pumping equipment items within the power production system 400 are the same as those described previously for Figure 2. Likewise, the hydrogen and oxygen production unit 100 and compression systems 200 and 300 are not shown in Figure 2a but are the same as those described for Figure 2.

[00105] The ability to operate without a cryogenic ASU 150 (see, in contrast, Figure 1), which involves an energy intensive process, reduces the auxiliary energy consumption improving the cycle’s thermal efficiency. This advantage is quantified by Table 9 which provides a comparison between a prior art Allam-Fetvedt Cycle and the presently described hydrogen-fuelled cycle. Data for the hydrogen-fuelled cycle is generated by assuming that the same quantity of input heat is required, though provided by hydrogen rather than natural gas. The quantity of gross power and the parasitic load of the CO2 compressor 414 are assumed to be the same in both cases since the composition of the working fluid is very similar.

[00106] Oxygen compression 300 is included as an additional parasitic load for the hydrogen-fuelled cycle of system 200 with an estimated load of 22 MW. This load is not relevant to the existing Allam-Fetvedt cycle where the cryogenic ASU produces liquid oxygen. This liquid can be pumped to 300 bar, consuming a fraction of the power required for compression.

[00107] Table 9 excludes the parasitic load of hydrogen compression 200. This parasitic load is excluded since the intention of Table 9 is to estimate the thermal efficiency of the hydrogen fuelled - supercritical CO2 system 200 for comparison against other technologies for utilising hydrogen, namely combustion turbines and fuel cells. These technologies also require high-pressure hydrogen compression and storage; therefore, the parasitic load has been excluded for the purpose of comparison. Table 9 Gross and Net Power Generation Comparison

[00108] As a means of utilising high-pressure green hydrogen, the above described hydrogen fuelled-supercritical CO2 system 200 can achieve a thermal efficiency of 65.9% as shown in Table 9. The US DOE Fuel Cells Technologies Program estimates that experimental advanced fuel cell technologies may achieve efficiencies up to 60%. In this context, the hydrogen fuelled-supercritical CO2 system 200 represents a more efficient method for utilising green hydrogen than existing technologies.

Table 10 presents the round-trip efficiency of hydrogen fuelled power generation using the described hydrogen fuelled-supercritical CO2 (H2SCO2) system 200, fuel cells and combustion turbines. Roundtrip efficiency assesses the entire power generation system from initial power input to final net power output (incorporating all parasitic loads): Table 10 Hydrogen Power Generation - Roundtrip Efficiency Comparison

Notes: 1. Total Power consists of 674.7 MWe for electrolysis and 61.8 MWe for hydrogen compression to 300 bar.

2. Roundtrip efficiency = Total Power In/Net Electrical Power Out

[00109] Table 10 demonstrates that the H2-SCO2 system 200 described here achieves approximately 10% superior round trip efficiency to the next best alternative for hydrogen power generation (fuel cell technology). The major obstacle to widespread hydrogen utilisation is the cost of producing the fuel. By offering superior roundtrip efficiency, the H2-SCO2 cycle can substantially improve the economics of green hydrogen and advance the use of hydrogen as a means of storing renewable power.

[00110] In the above described green H2-SCO2 power generation system 200, the generator 406 is driven by a rotating turbine 405. When connected to an electrical grid, the rotational motion of the turbine 405 provides a source of inertia which can help to slow the rate of grid frequency decline in the event of power loss elsewhere on the grid. By slowing the rate of frequency decline, the inertia contribution of the rotating turbine provides a grid stabilising effect. This effect will increase the time period between the event causing loss of generating power and grid shutdown due to low frequency, increasing the time period available for reserve capacity to come online to compensate for the loss of power.

[00111] By contributing inertia, the above described H2-SCO2 power generation system 200 will reduce the probability of electrical grid shutdown events due to low- frequency. These events have become more prevalent in recent years, particularly where power grids feature high penetration of renewable power such as South Australia and California. This represents an additional advantage over hydrogen fuel cells which do not feature rotating mass and, therefore, do not contribute inertia.

[00112] Referring to Figures 3 and 4, a premixed combustion chamber 220 or 1220 in which oxygen/supercritical CO2 290 and hydrogen 294 are separately injected into the combustion chamber 220, 1220 is preferred to prevent flame temperature from exceeding the temperature of construction materials of the system. In this case, the combustion chamber 220, 1220 must maintain hydrogen/oxygen/supercritical CO2 290, 294 velocities that are greater than the flame propagation speed. Premixing is achieved by inducing a swirling flow path 299 in the hydrogen/oxygen/supercritical CO2 mixture by flowing an oxygen/supercritical CO2 mixture over a series of stationary blades 602 with hydrogen fuel 603 being injected through small holes 604 in the surface of the blades 602. Swirling ensures adequate mixing of hydrogen/oxygen/supercritical CO2. A central region 610 of the swirling hydrogen/oxygen/supercritical CO2 flow exhibits lower velocities than the peripheral region 620. Therefore, flashback is most likely to occur in this central region 610 as shown in Figures 3 and 4. Optionally, additional supercritical CO2 607 may be injected through a nozzle 606 situated in the centre of the stationary blades 602 as shown in Figure 4. The increased hydrogen/oxygen/supercritical CO2 velocity in the central region 610 of the combustion chamber 1220 of Figure 4 balances the high flame propagation velocity associated with hydrogen, preventing flashback and achieving stable combustion in the combustion chamber 1220.

[00113] Modifications to the combined energy storage and power production system of the present invention may be apparent to skilled readers of this disclosure. Such modifications and variations are deemed within the scope of the present invention.

[00114] Throughout this specification, unless the context requires otherwise, the word "comprise" or variations such as "comprises" or "comprising", will be understood to imply the inclusion of a stated integer or group of integers but not the exclusion of any other integer or group of integers.