GB2484080A - Power generation using a pressurised carbon dioxide flow - Google Patents

Abstract

A method and system of power generation comprises the steps of supplying carbon dioxide from a carbon-burning power plant 110 to a reservoir 101 and providing a flow of pressurised carbon dioxide from the reservoir 101 to a power generating turbine 107. Heat energy is supplied to the flow of pressurised carbon dioxide by an external source at heater 3. Heat energy may be in the form of reactants which may be added to the flow to initiate a reaction so as to generate heat. The reactants may be gaseous. The system may comprise a first source of substantially pure gaseous oxygen wherein the oxygen may be added, from the first source, to the flow. The system may comprise a second source of fuel wherein the fuel may be added, from the second source, to the flow. The second source may be a source of hydrogen. The second source may be a source of hydrocarbon. There may be a first and second turbine wherein only the second turbine receives a heated flow.

Description

TITLE: POWER GENERATION I2ESCRIPTION

TECHNICAL HELD

The present invention relates to methods of power generation, in particular but not exclusively methods of power generation to meet peak load demand.

BACKGROUND ART

As known, e.g. D. N. Nguyen, "Carbon Dioxide Geological Sequestration: Technical and Economic Reviews", School of Petroleum Engineering, University of New South Wales, carbon capture and sequestration, so-called CCS, involves the capture of dioxide from carbon-burning (e.g. oil or coal burning) power stations and its storage in geological reservoirs.

It is known to address peak load demand by means of compressed air energy storage *(CAES) -see e.g. S. Succar and R. H. Williams, "Compressed Air Energy Storage: Theory, Resources, and Applications For Wind", Power Energy Systems Analysis Group, Princeton Environmental Institute, Princeton University, April 2008.

The use of pressurised carbon dioxide for peak demand energy storage has also been proposed: in an internet posting (http://arch.designcornrnunity.com/topic-3 I 592.html) dated 13 January 2010, Walker Architects have proposed a storage/power regeneration plant in which "captured CO2 is first sequestered as a reservoir of liquid or supercritical C02 in a geologic formation or in a pipe or a tank. The cycle begins when the reservoir is used to store additional energy. A compressor driven by surplus electrical power from any alternative or conventional energy source is used to inject C02, increasing reservoir pressure arid recycling the C02 in the system. The working fluid expands in the reservoir and absorbs additional pressure and heat. Liquid or supercritical C02 is then pulled up an extraction well from the reservoir into any suitable engine type at supercritical pressure.

Pressure, heat and flash vapor phase change reaction all occur as the embodied energy is released creating an explosion which drives the engine to efficiently operate and mechanically regenerate electrical power. The C02 is captured in a suitably large low pressure chamber then re-compressed in the energy input phase and returned to storage in the reservoir as liquid or supercritical C02," The use of C02 as the working fluid in a closed power cycle is known, for example, from Ph Mathieu, R. Nihart, "Sensitivity analysis of the MATLANT cycle", University of Liege, Institut de Mécartique, Liege, Belgium. Also Yantovski E.I., "THE COOPERATE -DEMO POWER CYCLE", Energy Research Institute, Russian Aead. Sci. Also M.D.

Staicovici, "Further research zero CO2 emission power production: the COOLENERG' process", Research and Design Institute for Thermo power Equipments (SCICPET- CERCIETARESA), Bucharest, Romania. Also H. Jericha, M. Fesharaki, "The Graz cycle - 1500°C max temperature potential H2 -02 fired CO2 capture with CH4 -02 firing", Institute of Thermal Turbomachinery and Machine Dynamics, Graz University of Technology, Austria. Also A. Miller, 3. Lewandowski, K. Badyda, S. Kiryk, J. Milewski, "Hydrogen Combustion Turbine Cycles", Institute of Heating Engineering, Warsaw University of Technology.

DISCLOSURE OF INVENT JO N.

According to a first aspect of the present invention there is provided a method of power generation comprising the steps of: supplying carbon dioxide from a carbon-burning power plant to a reservoir, providing a flow of pressurised carbon dioxide from the reservoir, thereafter supplying heat energy to the flow from a source external to said flow, and thereafter feeding the heated flow to a power-generating turbine.

By supplying heat energy to the flow of CO2 between the reservoir and the turbine from an external source (rather than from the flow of carbon dioxide itself via a recuperator), the amount of power that can be generated by th turbine for a given flow rate is increased.

The carbon dioxide flow rate is determined inter alia by the capacity of the reservoir and of the connections between the reservoir and the turbine. Thus for a given reservoir and infrastructure, the present invention allows the available power from the turbine to be increased.

The step of supplying heat energy to the flow from a source external to said flow may comprise the step of adding reactants to the flow and initiating a reaction therebetween so as to generate heat. The step of supplying heat energy may comprise the step of adding gaseous reactants to the flow. The step may comprise adding substantially pure gaseous oxygen and a gaseous fuel to the flow. The gaseous fuel may be hydrogen or a hydrocarbon.

The flow of pressurised carbon dioxide from the turbine may be supplied to a further store, reaction products other than carbon dioxide being removed from said flow prior to the flow entering the store. In particular, water may be removed from the flow of carbon dioxide prior to its entering the store.

The carbon dioxide from the carbon-burning power plant may be supplied under pressure by means of a first compressor, with the same compressor subsequently being used to supply pressurised carbon dioxide from the turbine to the reservoir.

Prior to, or as an alternative to, being fed back to the reservoir, the carbon dioxide exhausting the turbine may be stored in a further store. Pressurised carbon dioxide exhausting from the turbine may be supplied to a further store at a pressure greater than ambient pressure.

There is also provided a system for generating power comprising: a reservoir configured to receive carbon dioxide from a carbon-burning power plant and to supply a flow of pressurised carbon dioxide, a power-generating turbine, and a heater configured to receive a flow of carbon dioxide from the reservoir and energy from a source external to said flow, to heat said flow using said energy and thereafter supply *said heated flow to the turbine.

As before, adding heat energy to the carbon dioxide flow from an external source enables the turbine to deliver more power.

The heater may be configured to add reactants to the flow and initiate a reaction therebetween so as to generate heat.

The heater may be configured to add gaseous reactants.

The system may comprise a first source of substantially pure gaseous oxygen, the heater being configured to add oxygen from the first source to the flow.

The system may comprise a second source of fuel, the heater being configured to add fuel from the second source to the flow. The second source may be a source of hydrogen or a hydrocarbon.

The system may comprise a first and second turbines, said heater being configured to heat the flow entering the second turbine but no said heater being configured to heat the flow entering the first turbine.

The system may comprise a pump interposed between the reservoir and the heater and configured to pump a flow of pressurised carbon from the reservoir to the heater.

According to a second aspect of the present invention there is provided a method of power generation comprising the steps of: feeding a first flow of carbon dioxide from a pressurised reservoir into a power-generating turbine; and simultaneously feeding a second flow of pressurised carbon dioxide from a carbon-burning power plant directly into the power-generating turbine.

Pressurised CO2 from the power plant that is fed directly into the turbine rather than via the pressurised reservoir does not require well capacity to carry it down to the reservoir or well capacity to carry it up again to the power-generating turbine. Thus the present invention reduces the well capacity required for a given peak power generation requirement. Since wells are expensive to drill, the investment required for a given peak power generation is thus reduced. Moreover, since C02 from the power plant flows directly to the turbine rather than via the reservoir and its associated wells, flow losses are reduced, thereby increasing the efficiency of the plant.

According to the sccond aspect there is also provided a method of power generation comprising the steps of: providing a flow of pressurised carbon dioxide from a carbon-burning power plant, a reservoir for storing carbon dioxide under pressure and a power-generating turbine; and selectively feeding the flow directly to the reservoir or directly to the turbine.

At times of low power demand, the CO2 flow from the carbon-burning power plant is fed to the reservoir, where is can be stored under pressure until such lime as power demand is high, when it can -if appropriate -be fed to the turbine to generate extra power. At such times of high power demand, CO2 arriving from the carbon-burning power plant is fed directly to the turbine rather than into the reservoir and back out again. This avoids the need for separate wells to feed CO2 into and out of the reservoir rather, the same well can be used to supply CO2 from the reservoir to drive the turbine at times of peak power demand and to supply CO2 to the reservoir at times of low power demand when the turbine does not need to be driven.

According to the second aspect there is also provided a system for generating power comprising: a valve having an inlet configured to be connected to a supply of pressurised carbon dioxide from a carbon-burning power plant, a first outlet configured to be connected to a reservoir for storing carbon dioxide under pressure, and a second outlet configured to be connected to a power-generating turbine; and a controller configured to receive a signal indicative of whether the power demanded of the turbine is high or low and to control the valve so as to supply pressurised carbon dioxide to the reservoir when the power demand is low and supply pressurised carbon dioxide to the turbine when the power demand is high.

The system may comprise a pump configured to be connected to the supply of pressurised carbon-dioxide upstream of said valve.

BRTEFD ESCIIION OF DRAWINGS

An embodiment of the invention will now be described by way of example with reference to the accompanying drawings, in which: Figure 1 is a diagrammatic view of a first embodiment of a system according to the invention; Figure 2 is a diagrammatic detail view of the plant of the embodiment of figure 1; Figure 3 is a diagrammatic detail view of a second embodiment of a system according to the invention; Figure 4 is a diagrammatic detail view of a third embodiment of a system according to the invention; Figure 5 is a diagrammatic detail view of a fourth embodiment of a system according to the invention; Figure 6 is a diagrammatic view of a fifth embodiment of a system according to the invention; Figure 7 is a diagrammatic view of a sixth embodiment of a system according to the invention;

DETAILED DCRJPTTON OF SPECIFIC EMBODIMENTS

Referring to figure 1, a carbon-burning power plant 110 having a carbon capture ("CCS") facility captures and supplies carbon dioxide to a reservoir 101 vja one or more wells ill.

Such reservoirs or storages may be abandoned oil and gas fields, saline formations, coal bed formations, salt caverns and abandoned mines. Manmade storages are also feasible. In these storages the C02 is injected and stored in supercritical phase at high pressure (1OMPa to I 8MPa), reducing the volume occupied and permitting the storage of high amounts of CO2. The amount of C02 stored increases with the depth d of the reservoir below the surface 100 and associated hydrostatic pressure and geothermal gradient (typically 25°C/krn): from a relative volume of 100 at the surface at ambient pressure and 15°C, the relative volume typically reduces to around 3.8 at a depth of 800m and becomes nearly constant.at around 2.7 at depths greater than 1.5km.

When underground storages are considered, the maximum pressure of injection must be considered: similar to the geothermal gradient, it is possible to define a gradient of pressure that is a function of the depth and it is necessary to evaluate the allowable operative pressure which avoids breakage of the caprock in aquifer or creep in salt and rock formations leading to the escape of CO2. The values of gradient are different on the basis of the characteristic of the storage; for aquifer the values average between 1GM lcPaJm and 18.5 kPalm, while for salt caverns the value is about 22.6 kPa!m. These are the limit values but, when the maximum operative pressure is decided, a certain safety margin has to be considerate; usually, in CAES, the storage is pressurized up to 80% of the maximum pressure. Considering for example a porous rock formation 1.5 km dccp and a gradient of 16.0 kPalm, the maximum pressure is 24.lMPa and the maximum allowable pressure is l6.lMPa (80%); if the formation was 2.5km deep with the same gradient the maximum allowable pressure would be equal to 32. lMPa.

The reservoir 101 containing carbon dioxide under pressure is also connected via a well 102 to plant 99 shown in more detail in figure 2 and having a high pressure heater or combustor 104. As indicated at 3, a flow of pressurised carbon dioxide from the reservoir enters the combustor 104 where reactants are added to the flow and a reaction initiated therebetween so as to generate heat. In the embodiment shown, the gaseous reactants pure oxygen and hydrogen are added to the flow (from sources indicated at 105 and 106) and combustion initiated so as to heat the flow, the combustion products joining the flow. Such combustion with pure oxygen is also known as toxy-fuel combustion" or "OF combustion".

The energy to heat the flow comes from a source external to the flow, namely the oxygen and hydrogen, rather than from the flow itself, e.g. via the recuperator 103 discussed in more detail below. As indicated at 4, the heated flow is then fed from the combustor 104 into a high pressure (HP) power generating turbine 107 connected via a shaft 108 and clutch 109 to an electrical power motor/generator 112.

The aforementioned combustion increases the temperature of the supcrcritical C02 at the inlet to the HP turbine, which in turn improves the performance of the plant. The HP turbine expands the C02 front supercritical phase (at station 4 in figure 2) to the gaseous phase just under the critical point (7.38MPa, station 5 in figure 2). In the example shown, a pressure of 7MPa at station 5 has been assumed in all the models, although other configurations of pressure at the outlet of the HP turbine are also feasible. In the high pressure combustor, a 3% pressure loss has been assumed.

The flow leaving the HP turbine is then fed to a medium (or intermediate) pressure eornbustor 113 where oxygen and hydrogen are again added to the flow in the manner of the high pressure combustor di.scussed above. A 3% pressure loss is again assumed.

The flow is then fed to a medium (or intermediate) pressure turbine 114 where, in the example shown, the flow is expanded from an initial pressure of 6.8MPa (station 6) up to a pressure of 0.8MPa (station 7). Turbine 114 also drives shaft 108.

After this expansion, the flow will then acquire energy again in a low pressure combustor 116 where oxygen and hydrogen are again added to the flow in the manner of the high pressure combustor discussed above. A 3% pressure loss in the combustor is again assumed.

The flow is then fed to low pressure (LP) turbine 117 where, in the example shown, the gas is expanded from a pressure of 0.78MPa (station 8) to ambient pressure (101.5lcPa) at station 9.

On exit from the LP turbine (station 9), the flow is then fed to a recuperator 118 in which heat in the flow is transferred back to the incoming flow from well 102, The recuperator introduces an increment of efficiency both because it reduces the amount of oxygen arid fuel necessary in the HP combustor and because it reduces the cooling system at the outlet of the generation train, allowing the condenser (discussed

S

below) to have smaller dimensions and a lower power requirement). For the recuperator, pressure losses equal to 2% are typical.

On leaving the recuperator, the flow enters temporary storage 119. Products from the combustion reaction other than carbon dioxide, in particular water, are removed from the gas flow prior to its entering the store, in this case by condenser/separator 120.

Note that the exhaust gas at the outlet of the recuperator (station 10) still has energy that can be used for district heating or greenhouses (both heat and CO2 improve the productivity of vegetables in greenhouses).

The temporary storage might have different shapes and nature; it might be an underground cavern such as salt cavern or hard rock cavern or, as shown in figure 1, a manmade storage tank. It will be appreciated that the limitations in the temporarily volume might reduce significantly the generated energy. This is particularly the case if the flow is expanded to low pressure in order to maximize the power produced, in which case the density of the exhaust may be very low and the required temporary storage volume very high.

To reduce the temporary storage volume, the density has to be the highest possible and this is obtained by cooling the flow from the recuperator (station 10) by means of an intercooler or condenser 121. For example, flow leaving the recuperator at an outlet temperature of 436K has a density of I.276kg/rn3, while with an intercooler and an outlet temperature of 293K the value rises to 1.907kg/m3.

Alternatively / in addition, the required temporary storage volume can be reduced by reducing the expansion ratio, resulting in a higher LP turbine outlet pressure that is greater than ambient.

However, this loses more energy than the alternative of expanding the flaw to low pressure followed by compression to reduce the volume requiring temporary storage.

Even if in the concept of peak energy generator the compression and generation arc independent in order to maximise the output power sold to the grid, the authors have evaluated the possibility to introduce a compressor train with small pressure ratio in order to reduce the temporarily volume. When the builder will evaluate the economic aspects of the plant, he will see if it is more convenient a solution with less onpeak power produced (obtained with small expansion ratio) but smaller temporarily volume or, a solution with all the generated power sold to the grid and huge volume or, a small compression train after the C02/H20 separator that reduces the volume. This choice will depend on the geographical (availability of space) and economic (electricity market and building costs) aspects of the specific area chosen for the plant. Obviously if the C02 is compressed to a certain pressure inside the temporarily volume, when it has to be compressed underground, the compression process will require less power.

Expansion of pressurised C02 through turbines as described above allows the generator 112 to supply electrical power to the grid at times of peak demand. Conversely, when demand is low, electrical power can be taken fiom the grid to drive the generator 112 in reverse and feed the carbon dioxide in the temporary storage 119 back in to the reservoir 101. Rather than the single reversible motor/generator shown in figures 1 and 2, a separate generator and motor may be provided for the turbines and compressor train respectively, as shown in figure 3.

Referring to figure 2, clutch 109 is released and clutch 126 is engaged, allowing generator/motor 112 to drive a compressor train 127. Valves 123, 125 are opened arid valves 122, 124 closed so as to allow carbon dioxide to flow from the temporary storage to the compressor train 127 and thence (station 15) to well 102 for reinjection into the reservoir 101.

In the embodiment shown, the compressor train comprises low, medium (intermediate) and high pressure compressors 128,129,130 in order to reach the supereritical phase followed by pumps 134. However, this plant can operate with every type of compressors including reciprocating, multi-casing in-line centrifugal and integral-gear centrifugal compressors. Also applicable are concepts described in J. I Moore, Ph,D.

M. G. Nored, Ryan S. Gernentz, K. Brun, Ph.D., "Novel Concepts for the compression of large volumes of carbon dioxide", DOE, Project No. 18.11919. Some of these novel concepts are represented by isothermal compression, semi-isothermal compression and a concept where the C02 is partially compressed, after it is liquefied using a refrigeration cycle and pumped to the final discharge pressure. These last concepts offer over a 30% reduction in total required power over the traditional approach, increasing the efficiency of the plant and Charging Electricity Ratio (CER), i.e. the ratio of output energy produced to input energy spent to compress.

In the embodiment described, the CO2 gas (at station 13) is withdrawn from the temporarily storage and is compressed just over the critical pressure (7.38MPa). In order to reduce the power necessary to run the compressor train, intercoolers 131, 132 are put between each compressor. The number of compressors is variable: a higher number will reduce the power required but increase the initial outlay. At the compressor train outlet an aftercooler 133 provides the last cooling (at station 14), after this, because the C02 is injected underground in a supercritical phase, a series of pumps 134 are used. The wells 102 used to inject the C02 are the same used during the generation; this because compression and generation happen independently. When the generation takes place there is not injection and vice versa, when the injection takes place there is not compression.. This permits to reduce the capital costs of the plant.

It should be noted that, in each conibustor, the oxygen and the fuel have to be injected at the right pressure. Because the initial pressure of the oxygen and fuel is usually lower than the pressure of the combustion, appropriate systems of compression and pumps are typically necessary to adapt the pressure. Oxygen supplied by a conventional air separation unit (ASU) is typically at a pressure of 500kPa and must therefore, in the particular embodiment described, be pressurised up to O.8MPa for the LP combustor, up to 7MPa for the MP combustor and up to a variable value of l 5MPa-3OMPa for the HP combustor. Average supply pressures for methane in Europe are in the range 4MPa to 6MPa. Average supply pressures for hydrogen may be greater than that in the HP combustor, in which case there is no need for compressors or pumps, the pressure simply being reduced with a valve.

The combustion can use different types of fuels: hydrogen, methane, coal, biomass fuel or indeed fuel produced using C02 (see e.g. http://www.wired.com/sciencefdiscoveries/news/20O8/0l/S2P). In the latter case, a plant that uses CO2 to produce fuel could be built dose to the OFCO2-energy storage avoiding the need of other fuel sources, reducing the dependency to fliel supplier and fuel costs increment, When using methane as a fuel, the amount of C02 released at the outlet of the process will be higher than the amount withdrawn from the cavern reservoir.. This is because, in a combustion with methane, the by-products are represented by water and C02: CH4+20 >C02+2T420 Il This extra C02 produced in the present invention is collected and re-injected underground in order to create a source of revenue in the next generation phase. This "green" aspect represents a significant benefit for this energy storage/peak generator.

In oxy-fuel combustion with hydrogen the amount of C02 released is equal to the amount withdrawn in the beginning, the only by-product of an oxy-friel combustion with hydrogen being water that can simply be extracted using.a condenser, indicated at 120 in figure 2.

Various operating scenarios 1 16 are set out in tables 1 and 2. The value of pressure assumed in the storage, in order to cover the actual values of injection and also the benefits of higher pressure, are respectively 1 0.5MPa, 1 5MPa, 2OMPa, 25MPa and 3OMPa. As explained above, the cavern is put underground and the area chosen will be characterised by a certain temperature gradient and pressure gradient. In the calculations a temperature gradient of 30°C/km and a pressure gradient of I 8.549kPaJm have been assumed. For the storage operating in the range 1 0.5-2OMPa a cavern 1.5Km deep has been assumed; so, the value of temperature and maximum pressure will be respectively 333K and 27.8MPa, that permits a maximum allowable pressure of about 22.25MPa. For the pressure of 25MPa, a storage 2Km deep has been chosen; temperature and pressure values are 348K, 37.1 MPa (maximum pressure) and 29.7MPa (max allowable pressure). In the end, for 3OMPa, a storage 2.5Km deep, characterised by temperature and pressure values of 363K, 46.4MPa (maximum pressure) and 37MPa (max allowable pressure). At this point a 3% pressure losses have been considerate through the pipes that transfer the fluid from the storage to the aboveground plant. The pressure values will be respectively reduced to 1 0.2MPa, 14.6MPa, 1 9.4MPa, 24.3MPa and 29.1 MPa. Dimensions and relative evaluation of the storage will be provided at the end of the generation train analysis.

The first component of the generation train is the recuperator, that increases the temperature of the cold C02 withdrawn from the underground storage using the LP turbine exhaust gas. The exhaust gas temperature will depend on the turbine inlet temperatures (TITs) and it will transfer more or less energy to the cold fluid. In the calculation performed, an effectiveness of 0.9 has been assumed in order to calculate the temperature at the outlet of the recuperator and inlet of the HP combustor. On exiting the recuperator, the C02 flow goes into the HP combustor where oxygen and fuel injection at high pressure happens. The amount of oxygen.and fuel injected depends on the difference of temperature at the inlet and the lIT required, and also on the Lower Heating Value (LHV) of the fuel.

The fuels considerate are the hydrocarbon methane with a LHV of 50015 kJ/kg and hydrogen with LI-TV of 120086 kJlkg. Because the hydrogen has higher LHY and less fuel flow i.s required, the total mass flow that circulates through the turbines is reduced and, compared with combustion with methane and the same C02 withdrawn, the power produced is a little bit lower. But, as mentioned, the benefit of hydrogen combustion is that produces only water, creating a balance between C02 in input and in output of the system.

Values of TITs used are in the range 1473K to 1973K.

Reference is made to scenario 1 in table I, with the first lIT equal to 1473K and the others equal to 1773K. Because the fluid from the recuperator arrives with a temperature of about 1262K, the amount of oxygen burnt in the HP combustor is about 2.5% of the C02 flow withdrawn, while the amount of methane is about 0.56% of the C02 flow. At the exit of the HP combustor the flow goes through the HP turbine producing power, smaller compared to the two turbines operating with gas, also because of the small expansion ratio.

In the calculation, mechanical losses for the turbines equal to 3% have been considered.

The HP turbine expands to 7MPa, just under the critical pressure; here the MP combustor with the second injection of oxygen and methane takes place. In this ease the bigger variation of temperature to reach the second TIT requires higher consumptions: 5% of the flow for the oxygen and 1.2% of the flow for the methane. If hydrogen was used, the percentage would be reduced to 0.5%. At the exit of the MP turbine, the last combustion, characterized by an oxygen consumption of about 4.8% of the flow and a methane consumption of 1.1% of the flow. After the LP turbine the hot fluid goes into recuperator releasing most of the energy to the cold C02 withdrawn. At this stage the hot stream needs to be cooled, because the C02 has to be separated from the water and stored temporarily; also in order to maximise the storage efficiency, the density of the C02 has to be the highest possible. A condenser followed by a C02/H20 separator that extracts the water from the flow are provided; only C02 goes into the temporarily volume while water is extracted from the closed cycle.

Comparison of the different cases presented in tables 1 and 2 confirms the benefits introduced by combustion, namely that for the same output power, the amount of C02 required is reduced, In other words, for the same amount of C02 withdrawn, the combustion with its higher temperature increases the output power (cf. cases 5 and 12).

As previously explained, the C02-energy storage concept depends on the geographical position, the storage availability, its depth and a series of economic elements have to be evaluated. Thanks to the combustion introduced in accordance with the present invention, most of them could be overcome. This i*s illustrated by the following comparison between a plant where the C02 withdrawn from the storage does not go into combustor and the present invention. Another problem in the plant without combustion is that at the outlet of the turbines, the temperature reaches very low value with the consequent risk that the materials become brittle. Decreasing the expansion ratio reduces this problem but less power is produced with the same mass flow.. Assuming a cavern 1.5km deep, charged with C02 at maximum pressure of 1 5MPa and a temperature of 443K (the latter value of temperature being derived from the already presented geothermal map of the USA), it has been found that if a turbine (only one has been considered) expands from 1 5MPa to 1MPa the temperature reaches about 248K and the mass flow required for 300MW is about 2400kg/s that increases to about 2750kg/s for I OMPa. If a salt cavern with a volume of 500 000m3 was assumed with pressure equal to I 5MPa, it could produce 300MW for more than 2 hours. The main risk for this plant is the expansion ratio, because at the outlet of the turbine the temperature could reach very low value.

Using a combustion instead (cf. case 3 in table 1) and the same salt cavern characteristics, the power produced would reach 908.5MWe (instead of 1 GWe, with a compression train having a pressure ratio of 5 before the temporarily storage) supplied to the grid for more than 6 hours, With combustion there are no problems of brittleness for the material, but oxygen and fuel consumption are required. hi order to reach the same amount of output energy a mass flow of more than 7200kg/s will be required, and to guarantee an autonomy of 6 hours, about 12 caverns would be required. As regards the temporary storage, the system without combustion would require about 7 million m3, while the system with combustion about 2 million m3. For these reasons the plant with combustion looks better than the other in order to supply high peak power.

Assuming a geothermal gradient of 47°C/km (as has been registered in Germany) and a 4.5km deep formation, the temperature could reach 476K (203°C). Assuming a turbine that expands from 2OMPa to 1.25MPa, the mass flow required to produce 300MW is about 2200kg/s, with an outlet temperature calculated closed to 263K. If IGWe was required, more than 7300kg/s would be necessary.

In the description of the plant, it has been said how the cavern dimensions can change, changing the generation performance. In order to see the behaviour of the storage dimension, some examples are presented; first of all a volume of 500000m3 (typical for salt caverns), followed by two volumes able to store 2OMt and 500Mt of C02. Assuming that the storage is 1.5km deep and the fluid has a pressure of 2OMPa and a temperature of 333K, the density is 724.6kg/rn3. This means that in a volume of 500000 m3 the mass stored is about 362300 tons, while the others have volume respectively about 27.6milion m3 and ó9Omilion rn3. For the second and third storage the hypothesis that no changes in the underground pressure will take place during the withdrawn, may be done. Differently, for the salt cavern, due to its smaller capacity, the pressure falls down and the slope depends on the mass flow withdrawn; from simple calculations done, the pressure falls under 1 5MPa after 4.5 hours of withdrawing at a rate of 800kg/s, and to 1 OMPa after 9 hours with the same rate. The output power produced decreases and this process is much faster when more mass flow is required; combustion help to reduce this problem and increase the output energy. So while for the two big volumes theoretically there are no limitations in the generation and the pressure may be considerate constant (the only problems come from the temporarily storage), for the salt cavern if a certain output power needs to be provided, this will be feasible increasing the mass flow withdrawn, due to the fall of the pressure (from 800kg/s at 2OMPa to 845kg/s at 1 SM? a, cases 4 and 6). In the big volumes the fall does not happen and mass flow does not change.

Figure 3 shows an arrangement in which the HP combustor has been eliminated and only the recuperator provides the energy to the cold C02 fluid before expanding through the HP turbine, corresponding to cases 10, 14 and 15 in table 2. In other words, a combustor is configured to heat the flow entering second, MP, turbine but there is no combustor to heat the flow into the first, HP, turbine. This is possible when the TITs of the MI? and LP turbines are high enough to transfer, by means of the exhaust gas, the necessary energy to the cold stream. In fact, again, the increment in the ITs introduces improvements in the output power that can be reached with lower mass flow rate: considering ease 14 and 15, the increment from 1773K to 1973K reduces the mass flow of about 12%, while the variation of pressure from 1 5MPa to 2OMPa reduces the mass flow of about 4%. However, introducing this concept, the amount of C02 flow needed to generate the same power increases; in particular if the TITs is not high enough, the risk is that a significant increment of fuel consumption may happen (50% between cases 6 and 14). Considering 14 and 15 instead, one sees again how the increment of temperature, reduces the mass flow required and the fuel consumption as well (fuel consumption of the same order of case 6).

As previously explained, the capacity of the temporary storage 119 defines the maximum C02 that can be stored and consequently the maximum output energy.

Considering case 3 with its 845kgC02/s expelled, the volume required for storing C02 at 298K and lOl.5kPa is equal to 1.6 million m3 for ihour, 8.1 million m3 for 5 hours, 16.2 million m3 for 10 hours and 32.4 million m3 for 20 hours. This means that if a salt cavern of 0.5 million in3 is considered, 3.2 caverns would be necessary to store lhour of C02, 17 caverns for 5hours, 33 for 10 hours and 65 for 20 hours. Reducing the C02 temperature to 290K will reduce the volume by about 3%.

Even if the concept on which this plant is based is to avoid the compression during the generation in order to maximise the amount of electricity sold to the grid, the possibility to run a small compressor train composed by two compressors with intereooling able to increase the pressure of C02 up to 52SkPa (pressure ratio of 5) could be considered. This idea brings some significant variations in the temporarily storage dimensions, where the volume required becomes much smaller. In the end this work is not wasted, because later, when the compression train needs to pump the C02 underground, the inlet pressure is higher. The only problem is that, applying this concept, another percentage of the power produced is consumed during the on-peak request instead of being sold. Considering case 3 with a mass flow of 845kg/s that needs to be stored, the introduction of the compression train will consume about 95MW injecting C02 at 290K or 91.5MW if 2 98K; this means that about 9.5% of the output power produced is used in order to reduce the volume, if an isothermal compression was applied, the power required would be reduced to about 84.5MW. Table 3 presents the benefit of a small compression in the temporarily volume.

The value chosen is only to provide the concept; different values might be chosen and they will depends on all the economic aspect of the specific plant (costs of electricity, space to build the volume, and so on). As one can see, if a generation for 20 hours at 908.5MWe (instead of I GWe, because of the compression) was done, it would require a volume of 6.35 million m3, smaller than the abandoned limestone mine of 9.6 million m3 that will be used in the Compressed Air Energy Storage facility in Norton, Ohio, and much smaller than the volume otherwise required.

The idea to expand the C02 up to low pressure derives from the idea to get the maximum output power possible for a certain mass flow withdrawn. Of course this creates problems in terms of temporarily storage. If instead of 101.5kPa as LP turbine outlet pressure (case 3), an higher pressure was chosen, 525kPa for example, the power produced would be 669.93MW with the same mass flow; in order to reach 1GWe a mass flow of 1260kg/s would be required. increasing the LP pressure to higher value will decrease more and more the output power produced for a certain mass flow; higher mass flow rate will be necessary if a certain power needs to be supplied to the grid.

On the basis of the generation time chosen, the output power of the plant and the amount of C02 re-injected underground, the compression train will require different characteristics of power and mass flow. Another variable is the pressure of injection inside the cavern, even if after the critical point pumps are used that require less power than compressors.

In table 4, values of input power required for different compressor mass flow rate are presented -the solution chosen will depend inter alia on the energy available and the time of off-peak electricity, surplus electricity or electricity that need to be stored, Considering case 3 in Table I and the value of compressor power in table 4, one sees that, if a closed cycle was realized, the compressor will consume 27.3% of the power produced, that instead can be sold to the grid in a period of peak power. This value is reduced if a novel technology of the kind previously discussed was applied, also with an isothermal compression where the value would be equal to 24% of the output power. Looking at table 5, one can see the reduction in the input power required to compress the CO2 when a first compression up to 525kPa has been done. Tn this case, the power obtained by the sum of the compressor power required before the temporarily volume and the power required for the injection, produces a lower value of a unique compression. The reason is, because in the end, more compressors and intercoolers are used, reducing the total power required.

If case 3 is chosen with a mass flow of 845kg/s able to generate l001.MWe for 5 hours, this will produce 15210 tons of C02 that requires a temporary storage volume of about 8,11 million m3. Introducing instead the concept of small compression, less than 4 salt caverns of 500000 m3 each would be adequate. During the off-peak period, a possibility to re-inject the amount of CO2 withdrawn in 10 hours, requires a compressor train with 425kg/s of mass flow that has a consumption of about 141MW (or 121MW if an isothermal compressor is used).

As is known, the mass flow rate to/from the underground reservoir may be limited, typically by porosity or the permeability of the aquifer, necessitating a large number of wells if a high mass flow is required. Coal bed storage in particular is characterised both by low mass flow rate of injection and by C02 in a gas state. The present invention allows the power generation from such reservoirs to be raised to a viable level.

Consider for example a coal bed 500 meter deep, with geothermal gradient of 30°C/km (surface temperature equal to 1 5°C) and able to contain C02 at a pressure of 7MPa. The temperature assumed is 30°C (303K). It has been assumed 1% pressure losses along the pipes and 2% losses in the recuperator. Pressure will be respectively 6.93 MPa at surface level and 6.79MPa at the exit of the recuperator where the temperature is about 1259K. Since, in this particular instance, the C02 comes from the reservoir in a gaseous state, only two turbines -high pressure (HP) and low pressure (LP) are required. The TITs are both 1773K and the amount of oxygen needed is equal to 6% of the flow in the HP combustor and 4.67% in the LP combustor; for the fbel (hydrogen with LHV=I20086kJ/kg) 0.57% of the flow in the HP combustor and 0.45% in the LP combustor are burnt. For combustors 3% of pressure losses are used, turbines with 3% mechanical losses and generator with I % medhanical losses are considerate. Assuming a mass flow of C02 equal to 300kg/s, the net power produced is equal to 301.8MW, resulting from 341.7MW of gross power minus 39.9MW consumed by the air separation unit (33.5MW) and the oxygen compression (6.4MW).

As explained above with regard to the compressor train, when the C02 reaches the critical point and becomes supercritical a pump can be used to increase the pressure of the C02 in order to be transmitted along the pipelines to the storage.

One or more pumps can also be interposed between the reservoir and the plant to offset flow losses, as indicated at 150 in figure 4. Assuming a pump efficiency of 80% and a mass flow equal to 845kg/s of C02, the results reported in table 6 have been found.

Because for a certain temperature (equal to 333K, from a cavern 1.5km deep and geothermal gradient equals to 40°C/km) the density increases increasing the pressure, the pump will work with less power increasing the pressure to higher values.

The increment of the pressure at the inlet to the recuperator, produces the improvements reported in table 7 (the boost has to be done before the recuperator, because lower is the temperature, higher is the density and lower the power consumed to pump).

The plant in question has combustors with 3% pressure losses, HP TIT equal to 1473K, MP and LP TJTs equal to 1773K, recuperator with 2% pressure losses, and the NIP is fixed at 7MPa just under the critical point; the LP turbine expanding to 101.5kPa.

If a certain power is required from the grid (for example 1 GWe) the boost of pressure using pumps permits to reduce the amount of C02 withdrawn, increasing the autonomy of the plant in generation. In particular, after the overcoming of the critical point, if the C02 needs to reach a certain pressure value., it is only used a pump that requires much less power than a compressor, so significant increment of pressure can be obtained with low expense of power.

Figure 5 shows detail of another arrangement in which the pressurised C02 flow that comes directly from the CCS of a carbon-burning power plant is used as extra mass flow in addition to the flow of carbon dioxide from the pressurised reservoir. Rather than being fed into the reservoir first, the pressurised carbon dioxide from the CCS flows directly to the turbines, via the combustors etc. as outlined above.

This is enabled by a valve 200 having an inlet 210 connected (via booster pump 220) to the supply of pressurised carbon dioxide from a carbon-burning power plant 110, a first outlet 230 connected to the reservoir wells 102 and a second outlet 240 connected (at station 4) to the turbine via pump 150 and recuperator 118 as appropriate. A controller 250 receives a signal 260 indicative of whether the power demanded of the turbine is high (peak) or low (off peak) and controls the valve so as to supply the C02 from the CCS to the turbine at times of peak demand. At other (off peak) limes, the C02 is supplied to the sequestration reservoir 101 as normal.

The C02 from the CCS pipeline is used as extra mass flow and is fed to the turbine simultaneously with that from the reservoir. A pump 220 between the CCS pipeline 110 and plant 99 may be necessary in order to adapt the pressure characteristic of the C02 stream from the CCS to the C02 stream from the reservoir before it is passed to the generation train. This pressure adaptation can be achieved with low power consumption.

Indeed, rather than using another pump 220, the pumps 134 used in the compressor train 127 shown in figure 1 might be used since they are not used during generation.

Using C02 directly from the CCS reduces the C02 mass flow that needs to be withdrawn from the cavern reservoir and thus the number of wells (with their associated costs of building) while introduces an increment of the output power produced. In particular, if C02 had to be injected into the reservoir at the same time as C02 was being extracted from the reservoir for peak power generation, more wells (to allow both injection and extraction) would be necessary.

Moreover, in the period of high request of electricity, higher mass flow through the generation means higher power and higher revenues. So the idea to connect the main flow to the system represent benefits for the plant. The connection of the flow happens before the recuperator, that subsequently warms up all the stream with the LP turbine exhaust gas.

For example, assuming a CCS plant that injects 200kg/s of C02 underground and a power generation system designed with a mass flow rate of 835 kg/s (case 3 in table 1), then the main stream from the storage will be 635kg/s and the remaining 200kg/s will be supplied by the CCS. The characteristic of the mass flow withdrawn from the reservoir will depend on the characteristics of the storage: permeability and reservoir thickness will determine the deliverability of the reservoir and together with the porosity will determine the number of wells needed to achieve the desired total flow.

Because some plants could be built just on the top of carbon geological storages, the peak generator/energy storage could be close to the existing plant and use the compressor train of the CCS to inject the C02 underground. Thus in the particular embodiment of figure 1, the carbon dioxide from the carbon-burning power plant 110 may be supplied under pressure by means of a first compressor 98, with the same compressor subsequently being used in place of compressor train 127 to supply pressurised carbon dioxide back to the reservoir 101 (station 15 in figure 2).

This is enabled by the fact that, during the off peak periods, the amount of output power produced by a carbon-burning power plant may also be low, resulting in less C02 to inject underground and thus free capacity in the CCS compressor train. In this way a reduction in the cost of the machinery is realized. Where a compressor train is however required for the plant, it might have lower mass flow.

If the storage is used for C02 geological sequestration and is huge, the concept proposed is more a system to provide peak power generation; the re-injection is needed in order to dispose the flow previously used. Instead, if the cavern used is not a huge cavern (salt cavern) the concept is more an energy storage that operates using off-peak power for the compression and release through the generation train the mass flow in order to produce on peak power. A storage initially used for C02 carbon sequestration can become subsequently similar to an energy storage, because it may be charged and discharged on the basis of the electricity market.

Figures 6 and 7 illustrate the use of ocean storage with the release of C02 in a gaseous form, known per se from B. Metz, 0. Davidson, H. de Coninck, M. Loos, L. Meyer, "IPCC Special Report on Carbon Dioxide Capture and Storage", Cambridge University, 2005. This would avoid the need of a temporary storage and the re-injection of C02 underground. The feasibility of this concept might be correlated to the distance between the plants and the sea or ocean; as already done, a pipeline where the C02 is transmitted in a gaseous phase may overcome the problem with some losses. Similarly to the previous configurations there is the injection of C02 in the storage (underground or salt cavern for example) from a pipeline used for CCS. When there is a request of on-peak electricity the C02 is extracted and released trough the generation train with oxy-fuel combustion. The combustion will supply the energy to the C02 in order to be expanded and to produce high output power.

Referring to figure 6, the expansion ratio through the turbines is reduced such that the C02 exhausts at a pressure greater than ambient and sufficient to be injected via pipeline 300 in gaseous phase in water up to 500m deep (considering a water gradient of 9.74kPa, at this depth the water pressure is about 4.87MPa). No temporarily volume and compression train is required. For example, a plant with 2 turbines (in series) that expand from 1 5MPa to 3MPa could be built. With TITs for both turbines equal to 1773K, a C02 flow of 1290kg/s, a fuel flow of 5.7kg/s and 58.6kg/s of oxygen, the power produced is 501.8MW. if the expansion was between 1 5MPa and 4MPa, a mass flow increment would happen; in order to produce a net power of 499.8MW, a mas.s flow of 1590kg/s is required.

Referring to figure 7, full expansion takes place in the turbines (to a minimum pressure of 101.5kPa) but at the exit of the generation train, after the recuperator, there is provided a compression train 310 to compress the exhaust flow to the necessary pressure for the injection into the ocean (the compression will require about 16% to 19% of the output power produced). The fluid at pressure of 101,5kPa will be subsequently compressed at pressure higher than 4MPa. in the case of 540kg/s of C02 with compression at 4MPa, the net power produced is 501MW (the turbines power is 723.2MW, 138.4MW for C02 compressor, 69.7 for ASU and 13.6MW for oxygen compression).

It should be understood that this invention has been described by way of examples only and that a wide variety of modifications can be made without departing from the scope of the invention.

Table I

casestudy ija I 516 i 8 storage pressure [MPa] (1) 15 20 25 30 recuperator inlet pressure [Mpa] (2) 14,55 14,55 14,55 14,55 19,4 19,4 24,25 29,1 HP combustor inlet pressure [MpaJ (3) 14,3 14,3 14,3 14,3 19 19 23,8 28,5 Fuel CH4 CH4 H2 H2 CH4 H2 1-12 H2 H! turbine inlet temperature [K] 1473 1473 1473 1473 1473 1473 1473 1473 MP turbine inlet temperature [K] 1773 1773 1773 1773 1773 1773 1773 1773 LI' turbine inlet temperature [K] 1773 1773 1773 1773 1773 1773 1773 1773 C02 mass flow withdrawn [kg/s] 420,0 835,0 845,0 1265,0: 790,0 800,0 770,0 750,0 oxygen mass flow [kg/si 54,08 107,52 108,25 162,05 106,9S 107,73 107,08 106,80 fuel flow [kg/sI 12,40 24,65 10,25 15,35 24,44 10,17 10,11 10,05 Net output power [MW] 503,0 999,9 1001,4 14994 996,7 998,8 998,6 1001,1' HP turbine power [MW] 73,2 145,6 146,9 219,9 189,4 191,2 222,3 245,8 MP turbine power [MWJ 241,4 480,0 481,1 720,3 457,3 458,4 443,0 432,9 LP turbine power [MWJ 254,3 505,6 503,7 754,0 481,7 479,9 463,8 453,2 Total ouput power [MW) 559,0!? 1131,7 1694,2 1128,3 1129,4 1129,2 1131,9 ASU consumption power [MW] 54,51 108,38 109,11 163,35 107,80 108,59 107,94 107,65 oxygen compression power [MW) 10,57 21,01 21,21 31,75 21,80 22,01 22,60 23,12 fuel compression power [MW] 0,95 1,88 /1/ /// 2,07 11/ /// /// C02 exhaust [kg/s] 458,6 911,7 845,0 1265,0 866,4 800,0 770,D 750,0

Table 2

casestudy. 9 10 11 [ 12 J 13 14 15 16 storage pressure [MPa] (1) 10,5 15 _______ _______ 20_-_______ _______ 25 recuperator inlet pressure [Mpa] (2) 10,2 14,55 19,4 19,4 19,4 19,6 19,6 24,25 HP combustor inlet pressure [Mpa) (3) 10 14,55 19 19 19 19,6 19,6 23,8 Fuel H2 H2 0-14 CH4 1-12 H2 H2 H2 HP turbine inlet temperature [K] 1873 /1/ 1873 1873 1873 /1/ 1/1 1873 MP turbine Inlet temperature [K] 1973 1973 1973 1973 1973 1773 1973 1973 LPturbineinletternperature[K] 1973 1973 1973 1973 1973 1773 1973 1973 C02 mass flow withdrawn [kg/s] 800,0 755,0 680,0 790,0 690,0 820,0 725,0 660,0 oxygen mass flow [kg/si 108,57 105,98 104,52 121,43 105,39 107,10 105,47 104,78 fuel flow [kg/s) 10,35 10,23 24,38 28,32 10,11 15,06 9,85 10,09 Net output power 1MW] 1002,6 1001,7 998,3 1159,7 1000,5 998,5 999,7 999,9 HP turbine power [MWI 92,7 121,3 214,5 249,2 216,1 166,2 160,4 250,6 MP turbine power [MW] 506,6 490,5 442,9 514,5 444,1 468,0 -470,4 427,2 LP turbine power [MW] 535,6 516,4 471,5 547,8 469,5 492,5 495,2 451,7 Total ouput power [MW) 1134,9 1128,2 1128,9 1311,5 1129,7 1126,B 1126,0 1129,5 ASU Consumption power [MW] 109,44 106,82 105,36 122,40 106,23 107,96 106,31 105,77 oxygen compression power [MW) 22,87 19,67 22,71 -26,38 22,97 20,36 19,97 23,96 flcompressionpower,IMwI 11/ /// 2,53 2,94 /// //7 //J /// C02 exhaust [kg/si 800,0 755,0 754,0 876,0 690,0 820,0 725,0 650,0 Table 3 Benefits of compression on temporarily volume generation time [hours] 1 2 3 5 10 15 20 volume (without compression) 1,62 3,24 4,86 841 16,22 24,33 32,45 [million m I ______ ______ volume (with compression) 0,31 0,63 0,95 1,58 3,17 4,76 6,35 Table 4 Compression power from 101.SkP.a C02 mass flow [kg/s] 400 500 600 700 800 845 900 1000 1100 1200 1300 Compressor Power [MW] 122,5 153,2 183,8 214,4 245,1 258,9 275,7 306,3 337,0 367,6 398,2 maximum pressure _____ _____ 15Mpa Pumps Power [MW) 7,1 8,8 l0J12,4 14,1 14,9 15,9 17,7 19,4 21,2 23,0 Total Power [MW) 129,6 162,0 194,41226,8 259,2 273,8 291,6 324,0 356,4 388,8 421,2 maximum pressure _____ 2OMpa Pumps Power [MW] 10,1 12,7 15,2 17,7 20,2 21,4 22,8 25,3: 27,8 30,4 32,9 Total Power [MW] 132,7 165,8 199,0 232,2 265,3 280,2 298,5 331,6 354,8 398,0 431,1 nal camp on 114 142,5 171 199,5 228 240,8 256,5 285 313,5 342 370,3 Table S Compression power if compression with PR5 is provided C02 mass flow [kg/sI 400 500 600 700 800 845 900 1000 1100 1200 1300 Compressor Power [MW] 70,0 87,5 105,0 122,5 140,0 147,9 157,5 175,0 192,5 210,0 227,5 maximum pressure _____ _____ _____ _____ ______ l5Mpa Pumps Power [MW) 7,1 8,8 10,6 12,4 14,1 14,9 15,9 17,7: 19,4 21,2 23,0 Total Power [MW] 77,1 96,3 115,6 134,9 154,1 152,8 173,4 192,7 211,9 231,2 250,5 maximum pressure _____ _____ _____ _____ _____ 2OMpa _____ _____ _____ _____ Pumps Power [MW] 10,1 12,7 15,2 17,7 20,2 21,4 22,8 25,3 27,8 30,4 32,9 Total Power [MW] 80,1 100,2 120,2 140,2 160,3 169,3 180,3 200,3 220,3 240,4 260,4 Table 6 Power required if a pump is used to boost the pressure minimum pressure 15 20 25 MPa maximum pressure 20 -25 30 MPa power required 10,3 7,1 6,7 MW

Table 7 Gained power

pressure 15 20 25 30 Mpa ouput power 1005,3 1059,9 1102,4 1133,8 MW pump power /1/ 10,3 10,3 + 7,1 10,3+7,1+6,7: MW gained power 1/1 44,3 79,7 104,4 MW

Claims (3)

1. CLAIMSI, Method of power generation comprising the steps of: supplying carbon dioxide from a carbon-burning power plant to a reservoir, providing a flow of pressurised carbon dioxide from the reservoir, thereafter supplying heat energy to the flow from a source external to said flow, and thereafter feeding the heated flow to a power-generating turbine.
2. 2. Method according to claim 1, wherein the step of supplying heat energy to the flow from a source external to said flow comprises the step of adding reactants to the flow and initiating a reaction therebetween so as to generate heat.
3. 3. Method according to claim 2, wherein the step of supplying heat energy comprises adding gaseous reactants to the flow, 4, Method according to claim 3, wherein the step of supplying heat energy comprises adding substantially pure gaseous oxygen and a gaseous fuel to the flow, 5. Method according to claim 4, wherein the step of supplying heat energy comprises adding hydrogen to the flow.6. Method according to claim 4, wherein the step of supplying heat energy comprises adding a hydrocarbon to the flow, 7. Method according to any one of claims 2 to 6 and comprising the step of supplying the flow of pressurised carbon dioxide from the turbine to a further store and removing reaction products other than carbon dioxide from said flow prior to the flow entering the store.8. Method according to claim 7 and comprising the step of removing water from the flow of carbon dioxide prior to its entering the store.9. Method according to any one of claims 1 to 8 and comprising the steps of: supplying pressurised carbon dioxide from the carbon-burning power plant by means of a first compressor, and supplying pressurised carbon dioxide from the turbine to the reservoir by means of said first compressor.10. Method according to any one of claims 1 to 9 and comprising the step of supplying the pressurised carbon dioxide from the turbine to a further store at a pressure greater than ambient pressure.11. System for generating power comprising: a reservoir configured to receive carbon dioxide from a carbon-burning power plant and to supply a flow of pressurised carbon dioxide, a power-generating turbine, arid *a heater configured to receive a flow of carbon dioxide from the reservoir and energy from a source external to said flow, to heat said flow using said energy and thereafter supply said heated flow to the turbine.12. System according to claim 11, wherein the heater is configured to add reactants to the flow and initiate a reaction therebetween so as to generate heat.13. System according to claim 12, wherein the heater is configured to add gaseous reactants to the flow.14, System according to claim 13 and comprising a first source of substantially pure gaseous oxygen, the heater being configured to add oxygen from the first source to the flow.15. System according to claim 14 arid comprising a second source of fuel, the heater being configured to add fuel from the second source to the flow.16. System according to claim 15, wherein the second source is a source of hydrogen.17. System according to claim 15, wherein the second source is a source of hydrocarbon.18. System according to any one of claims 11 to 17 and comprising first and second turbines, said heater being configured to heat the flow entering the second turbine but no said heater being configured to heat the flow entering the first turbine.19. System according to any one of claims 11 to 17 and comprising a pump interposed between the reservoir and the heater and configured to pump a flow of pressurised carbon from the reservoir to the heater.20. Method of power generation comprising the steps of: feeding a first flow of carbon dioxide from a pressurised reservoir into a power-generating turbine; and simultaneously feeding a second flow of pressurised carbon dioxide from a carbon-burning power plant directly into the power-generating turbine.21. Method of power generation comprising the steps of: providing a flow of pressurised carbon dioxide from a carbon-burning power plant, a reservoir for storing carbon dioxide under pressure and a power-generating turbine; and selectively feeding the flow directly to the reservoir or directly to the turbine.22, System for generating power comprising: a valve having an inlet configured to be connected to a supply of pressurised carbon dioxide from a carbon-burning power plant, a first outlet configured to be connected to a reservoir for storing carbon dioxide under pressure, and a second outlet configured to be connected to a power-generating turbine; and a controller configured to receive a signal indicative of whether the power demanded of the turbine is high or low and to control the valve so as to supply pressurised carbon dioxide to the reservoir when the power demand is low and supply pressurised carbon dioxide to the turbine when the power demand is high.23. System according to claim 22 and comprising a pump configured to be connected to the supply of prcssurised carbon-dioxide upstream of the inlet to said valve.