Carbon capture power station unit with a FLUE gas cooler

Abstract

A carbon capture power station unit including a furnace (201), configured to burn fuel to produce heat and flue gas; and a boiler, configured to use the heat from the furnace to heat steam. A turbine is configured to use at least some of the steam from the boiler to generate electricity in one or more stages. A return path is configured to return the steam from the turbine to the boiler. The return path includes a condenser, configured to condense at least some of the steam from a stage of the turbine to produce a condensate. A flue gas cooler (222) is configured to transfer heat from the flue gas to at least a portion of the condensate. A carbon capture system (230) is configured to capture carbon from the flue gas.

Description

[0001] 64.173.172760 / 02

[0002] CARBON CAPTURE POWER STATION UNIT WITH A FLUE GAS COOLER TECHNICAL FIELD

[0003] This invention relates to carbon cazpture power station units, comprising a carbon capture system. In particular, this invention relates to the use of a flue gas cooler to transfer heat from flue gas, produced by burning fuel in a furnace, to a condensate so as to cool down the flue gas. Carbon is captured from the cooled flue gas by a carbon capture system.

[0004] BACKGROUND

[0005] Many power stations are designed to burn fuel to produce heat in order to create the steam used to drive a turbine to generate electricity. Flue gas is created as a by-product of burning various fuels, such as biomass. As flue gas contains carbon, it is desirable to capture at least some of the carbon from the flue gas before dispersion of the flue gas to the atmosphere, so as to reduce carbon emissions.

[0006] Carbon capture systems, which are used to capture carbon from flue gas, are typically designed to capture carbon from flue gas at a certain temperature or within an operating temperature range. However, in various circumstances, and particularly when carbon capture systems are retrofitted to a pre-existing power station unit, the flue gas produced by burning fuel may be at a higher temperature than the temperature(s) suitable for the carbon capture system. Thus, it may be desirable to cool down the flue gas before providing it to the carbon capture system.

[0007] There is often a reasonably high degree of freedom when designing a heat exchange process to cool down the flue gas for the carbon capture system. However, it is important to consider various criteria when designing such a process.

[0008] One of the criteria to consider is how to extract energy from the flue gas as “high grade” heat. For instance, if the heat from the flue gas is transferred to a fluid, it is often preferable for the fluid to be heated to a high temperature and / or high pressure as it is generally more difficult to produce high temperature and / or high pressure fluids which may be useful in the power station.

[0009] Another criterion to consider is how to re-integrate the energy removed from the flue gas, as there is a risk that the energy extracted from the flue gas may be wasted if it is not possible to identify how to re-integrate it into the power station processes.

[0010] A further criterion is how to reduce the mass flow rate of additional fluid (e.g. water or steam) required to extract energy from the flue gas. Additional fluid in this context means fluid that is not already required by another part of the power station. It may be desirable to reduce the amount of fluid required to reduce operational costs and the amount of infrastructure required to cool down the flue gas. In more general terms, it is desirable to reduce the amount of additional (e.g. dedicated) infrastructure required to cool down the flue gas for the carbon capture system.

[0011] Additionally, when retrofitting a carbon capture system to a pre-existing power station unit, it is desirable to minimise disruption to the operation of the power station. Thus, it is desirableto design a process for extracting the heat from the flue gas that does not cause significant disruption to the existing power station processes.

[0012] After carbon has been removed from the flue gas, it is referred to as depleted flue gas. In order to disperse the depleted flue gas effectively, it may be desirable to re-heat it to an appropriate temperature for dispersion. Thus, it may also be desirable to design a power station unit to heat the depleted flue gas in a manner that takes into consideration at least some of the previously mentioned criteria. It will be appreciated some of these criteria may be more relevant when the carbon capture system is retrofitted to a pre-existing power station. However, other criteria will be equally relevant for power stations where this is not the case.

[0013] SUMMARY

[0014] When viewed from a first aspect, the invention provides a carbon capture power station unit, comprising:

[0015] a furnace, configured to burn fuel to produce heat and flue gas;

[0016] a boiler, configured to use the heat from the furnace to heat steam;

[0017] a turbine, configured to use at least some of the steam from the boiler to generate electricity in one or more stages;

[0018] a carbon capture system, configured to capture carbon from the flue gas to produce depleted flue gas; and

[0019] a return path, configured to return the steam from the turbine to the boiler, the return path comprising:

[0020] a condenser, configured to condense at least some of the steam from a stage of the turbine to produce a condensate;

[0021] a flue gas cooler, configured to transfer heat from the flue gas to (e.g. at least) a first portion of the condensate; and

[0022] an evaporator, configured to evaporate (e.g. at least) the first portion of the condensate to produce steam for return to the boiler.

[0023] A carbon capture power station unit in accordance with the present invention is configured to transfer heat from flue gas to condensate to: (i) cool down the flue gas from the furnace for carbon capture; and (ii) heat the condensate on the return path to help return steam to the boiler at an appropriate temperature and / or pressure. Thus, a carbon capture power station unit in accordance with the present invention is configured to usefully re-integrate heat from the flue gas into the carbon capture power station unit’s steam / condensate cycle.

[0024] A power station may comprise one or more power station units. For instance, a power station may comprise one or more carbon capture power station units and / or any of a solar energy power station unit, wind energy power station unit, geothermal power station unit, hydro-electric power station unit, etc.. It will therefore be understood that the first aspect of the invention extends to a power station comprising the carbon capture power station unit. The term boiler is used herein for the part of the carbon capture station unit that is configured to use the heat from the furnace to heat steam. It will be appreciated that this is a term in the art that originates from when furnaces were used to boil water so as to providesteam, and that many (e.g. modern) boilers no longer actually boil water to provide steam, and instead merely heat (e.g. superheat) steam. Thus, it will be appreciated that, in embodiments of the present invention, the boiler may not actually boil water and thus may be understood to be a steam heater or a steam superheater.

[0025] The stage(s) of the turbine may be configured to receive steam and generate electricity by expanding the received steam. Expanding the received steam may reduce the temperature and / or the pressure of the received steam. Thus, the return path may be configured to increase the temperature and / or pressure of the steam from the turbine to return it to the boiler at an appropriate temperature and / or pressure for (e.g. further) heating. Thus, it may be possible for the turbine to re-use the steam (once it has been re-heated by the boiler) to generate more electricity.

[0026] In some embodiments, the carbon capture power station unit comprises a retrofitted carbon capture system. In other words, the power station unit may have previously been operated without a carbon capture system, however the carbon capture power station unit may now comprise a retrofitted carbon capture system (retrofitted to the existing power station unit). The present invention may be particularly useful for carbon capture power station units comprising a retrofitted carbon capture system. For instance, some of these power station units may have previously been configured to produce flue gas at a certain temperature for dispersion. However, the retrofitted carbon capture system may be designed to capture carbon from flue gas at a lower temperature than the temperature at which the flue gas was previously dispersed. Thus, it may be desirable (or even necessary) to cool down the flue gas before it is provided to the retrofitted carbon capture system. Various approaches could be used to cool down the flue gas, however re-integration of at least some of the heat from the flue gas into the return path may help to reduce the amount of heat that is wasted.

[0027] Leveraging the existing return path to cool down the flue gas for carbon capture may reduce the amount and / or cost of additional infrastructure required to cool down the flue gas.

[0028] The carbon capture power station unit may be configured to disperse the depleted flue gas. For instance, the carbon capture power station unit may comprise a chimney stack configured to disperse the depleted flue gas.

[0029] In some embodiments, the carbon capture power station unit comprises a gas-gas heat exchanger configured to transfer heat from the flue gas to the depleted flue gas, prior to dispersion of the depleted flue gas. It may be desirable to heat the depleted flue gas for dispersion to help ensure that it disperses effectively and / or to ensure compliance with relevant environmental emissions regulations. By using the flue gas to heat the depleted flue gas for dispersion, the carbon capture power station unit can usefully re-integrate at least some of the heat from the flue gas, which may help to reduce the amount of heat that is wasted. Use of the flue gas to heat the depleted flue gas for dispersion may reduce the amount and / or cost of additional infrastructure required to heat the depleted flue gas.

[0030] Similarly, use of the depleted flue gas to cool down the flue gas may reduce the amount and / or cost of additional infrastructure required to cool down the flue gas for the carbon capture system.

[0031] In some embodiments, the flue gas cooler is arranged to receive the flue gas before the gasgas heat exchanger such that, in use, heat is transferred from the flue gas to (e.g. at least) the first portion of the condensate before heat is transferred from the flue gas to the depleted flue gas. This may be particularly relevant for power station units that have a retrofitted carbon capture system, as the temperature used for dispersion of the depleted flue gas may be lower than the temperature at which the flue gas was previously dispersed (e.g. owing to the difference in the composition between the flue gas and the depleted flue gas and / orregulatory differences). This ordering of flue gas heat exchange processes may allow the flue gas to heat (e.g. at least) the first portion of the condensate to a higher temperature than would be possible if the order of heat exchange processes were reversed, while still heating the depleted flue gas to the desired temperature for dispersion.

[0032] In some embodiments, the return path is arranged to split downstream of the condenser into a first branch and a second branch. The return path may be configured to provide a first portion of the condensate from the condenser to the first branch. The return path may be configured to provide a second portion of the condensate (e.g. the remaining condensate) from the condenser to the second branch.

[0033] In some embodiments, the return path (e.g. the first branch of the return path) further comprises a condensate mixer, configured to: receive (e.g. at least) the first portion of the condensate, and a second condensate; and mix the first portion of the condensate with the second condensate so as to provide a condensate mix. The condensate mix will thus be understood to comprise (e.g. at least) the first portion of the condensate and the second condensate.

[0034] The first branch may comprise the flue gas cooler. The flue gas cooler may be arranged downstream of the condensate mixer. The flue gas cooler may be arranged to receive the condensate mix from the condensate mixer, so as to transfer heat from the flue gas to the condensate mix. Mixing of the first portion of the condensate with a second condensate may be useful for several reasons. For instance, the mass flow rates of the first portion of the condensate and the second condensate may be insufficient on their own to extract all of the energy as desired from the flue gas. Hence, this approach may be used to provide a condensate mix with a higher mass flow rate than either of the second condensate or the first portion of the condensate from the condenser on their own.

[0035] The condensate mixer may be configured to: receive the first portion of the condensate from the condenser at a first temperature, and the second condensate at a second temperature; and mix the first portion of the condensate with the second condensate so as to provide a condensate mix at a third temperature, which is between the first temperature and the second temperature. Thus, the mixing of the first portion of the condensate and the second condensate may be used to heat or cool the first portion of the condensate before it is used to extract energy from the flue gas. This may be helpful, for example, if cooling of the first portion of the condensate contributes to providing a condensate mix that is able to extract all of the energy as desired from the flue gas.

[0036] In some embodiments, the first temperature (of the first portion of the condensate) is lower than the second temperature (of the second condensate). Thus, the second condensate may be used to pre-heat the first portion of the condensate. While this may seem to be counterintuitive, pre-heating of the first condensate in this manner may enable the condensate mix to be heated to a higher temperature than the first portion of the condensate would otherwise be heated to. Condensate at a higher temperature is often considered to be more useful than condensate at a lower temperature. Thus, this approach may provide a more useful output from the flue gas cooler than merely heating of the first portion of the condensate on its own.

[0037] In some embodiments, the first temperature (of the first portion of the condensate) may be below the acid dew point of the flue gas (e.g. the temperature at which acid vapour in flue gas begins to condense) and both the second temperature (of the second condensate) and the third temperature (of the condensate mix) may be above the acid dew point of the flue gas. Increasing the temperature of the condensate mix to a temperature above the acid dewpoint of the flue gas may help to avoid condensation of acid vapour in the flue gas cooler. Thus, this may help to reduce corrosion of the flue gas cooler. This outlines a further example of why it may be useful to pre-heat the first portion of the condensate, by mixing it with the second condensate, before using the resulting condensate mix to extract energy from the flue gas.

[0038] In some embodiments, the second temperature (of the second condensate) is substantially the same as or higher than the temperature of the flue gas provided to the flue gas cooler. Thus, while it may appear to be counterintuitive, condensate at a similar temperature, or a higher temperature, than the flue gas may be used to help extract heat from the flue gas (e.g. when pre-heating of the first portion of the condensate is desired).

[0039] In some embodiments, the second temperature (of the second condensate) is substantially the same as a temperature of the condensate mix from the flue gas cooler (e.g. after heat has been transferred from the flue gas to the condensate mix). Thus, while it may appear to be counterintuitive, in some embodiments it is possible to (i) use the second condensate to heat the first portion of the condensate from the condenser to a temperature above the acid dew point of the flue gas; (ii) use the resulting condensate mix to extract heat from the flue gas; and (iii) provide at least some of the condensate mix at substantially the same temperature as the original temperature of the second condensate. This may be particularly relevant for power station units that have a retrofitted carbon capture system, as the second condensate can be tapped off at a certain position of a pre-existing process, and some of the condensate mix can be returned to the same position of the pre-existing process at substantially the same temperature as the second condensate. Thus, disruption to processes downstream of this position of the pre-existing processes may be reduced.

[0040] In some embodiments, the carbon capture system is configured to use an amine-based solvent to capture carbon from the flue gas. The carbon capture system may comprise an amine-based solvent heater, configured to receive at least some of the steam from the boiler (e.g. directly or indirectly), and transfer heat from the received steam to the amine-based solvent (e.g. after the amine-based solvent has been used to capture the carbon from the flue gas) so as to release the captured carbon. This process may allow re-use of the amine-based solvent to capture carbon from the flue gas. The carbon capture system may comprise a second condenser. The second condenser may be configured to receive the steam from the amine-based solvent heater (e.g. after heat has been transferred from the received steam to the amine-based solvent), and condense the received steam to form the second condensate. The second condensate may only be a portion of the condensate formed by the second condenser. This approach may provide an integrated steam / condensate cycle that can be used for both: (i) heating of the amine-based solvent; and (ii) generation of electricity. When compared with an approach that uses separate steam / condensate cycles, an integrated approach may be more cost effective and / or may reduce the amount of infrastructure required.

[0041] As previously mentioned, the return path may be arranged to split downstream of the condenser into a first branch and a second branch. The return path may be configured to provide a first portion of the condensate from the condenser to the first branch. The return path may be configured to provide a second portion of the condensate (e.g. the remaining condensate) from the condenser to the second branch.

[0042] The first branch of the return path may comprise the flue gas cooler, configured to transfer heat from the flue gas to (e.g. only) the first portion of the condensate. The second branch of the return path may comprise a heat exchanger, configured to transfer heat to a second portion of the condensate. The second branch may be considered to be arranged in parallelwith the first branch. The first branch and the second branch may be configured to merge, e.g. downstream of the heat exchanger and the flue gas cooler. The first branch and the second branch may be configured to merge upstream of the evaporator. The evaporator may be configured to evaporate the condensate to produce steam for return to the boiler after the first branch and the second branch of the return path merge.

[0043] The flue gas cooler may be configured to heat the first portion of the condensate to a (e.g. desired) temperature. The heat exchanger may be configured to heat the second portion of the condensate to a (e.g. desired) temperature. The heat exchanger may be configured to heat the second portion of the condensate to the same (e.g. desired) temperature that the flue gas cooler is configured to heat the first portion of the condensate to.

[0044] The provision of a parallel heat exchanger provides a solution whereby the second portion of the condensate (e.g. the remaining condensate) can be heated by the heat exchanger (e.g. instead of the flue gas cooler). This may allow adjustment of a mass flow rate of the first portion of the condensate without undesired downstream temperature variation (e.g. as a mass flow rate of the second portion of the condensate may be adjusted to account for this). In embodiments that include a heat exchanger arranged in parallel with the flue gas cooler, the flue gas cooler is configured to heat a first portion of the condensate (e.g. instead of the heat exchanger). Therefore, there may be a (e.g. corresponding) reduction of the amount of condensate that the heat exchanger is required to heat. This may reduce the energy demand of the heat exchanger. Thus, an efficiency improvement may be achieved, as the energy that would otherwise be used to heat the first portion of the condensate may now be used for another purpose, such as electricity generation.

[0045] In embodiments wherein the carbon capture system is a retrofitted carbon capture system, there may have been a pre-existing heat exchanger configured to transfer heat to at least some (e.g. all) of the condensate from the condenser prior to retrofitting of the carbon capture system. In these embodiments, the flue gas cooler may be arranged in parallel with the pre-existing heat exchanger. This may leverage the pre-existing heat exchanger to provide a heat exchanger arranged in parallel with the flue gas cooler. Use of existing infrastructure for retrofitted carbon capture power station units may reduce costs and / or the amount of additional infrastructure required. It will be understood that the provision of a retrofitted flue gas cooler arranged in parallel with the pre-existing heat exchanger may reduce the energy demand of the pre-existing heat exchanger.

[0046] The carbon capture power station unit may be configured to control a mass flow rate of the first portion of the condensate based on an amount of heat to be extracted from the flue gas (e.g. based on a mass flow rate or a temperature of the flue gas). Thus, the provision of a heat exchanger arranged in parallel with the flue gas cooler may provide improved adaptability to variation of (e.g. the mass flow rate or temperature of) the flue gas.

[0047] The amount of heat to be extracted from the flue gas may vary based on (i) the temperature of the flue gas and / or (ii) the mass flow rate of the flue gas. The mass flow rate of the flue gas and / or the temperature of the flue gas may be increased when more fuel is provided to the furnace. It may be desirable to increase the amount of fuel provided to the furnace when it is desirable to produce more electricity (e.g. when the electricity price is high). Conversely, it may be desirable to decrease the amount of fuel provided to the furnace when it is desirable to produce less electricity (e.g. when the electricity price is low). In some embodiments, the carbon capture power station unit may be configured to control the mass flow rate of the first portion of the condensate based on: (i) an amount of fuel burned by thefurnace and / or (ii) an electricity demand to be satisfied by the carbon capture power station unit (e.g. by the turbine).

[0048] In some embodiments, the carbon capture power station unit comprises a steam path, arranged between the boiler and the return path and configured to receive at least some of the steam from the boiler. The steam path may comprise (e.g. one or more stages of) the turbine. The steam path may be configured to split into a first steam path branch, comprising a stage of the turbine (which may be the same stage of the turbine that is configured to provide steam to the condenser, or alternatively a different stage of the turbine), and a second steam path branch, comprising the heat exchanger. The steam path may be configured to provide a first portion of steam to the first branch. The steam path may be configured to provide a second portion of steam to the second branch. Thus, the heat exchanger may be configured to transfer heat from the second portion of steam to the second portion of the condensate. It may be necessary to heat the condensate as part of the process to return the steam from the turbine to the boiler. Thus, it may be desirable to identify a suitable heat source to heat the condensate. The second portion of steam may provide a suitable heat source for heating the second portion of the condensate. As the flue gas cooler is configured to heat the first portion of the condensate (e.g. instead of the heat exchanger), use of the flue gas cooler may reduce the heat demand of the heat exchanger. In turn, this may reduce the amount of steam required by the heat exchanger. Thus, the use of the flue gas cooler to heat the first portion of the condensate may allow a higher proportion of steam to be provided to a stage of the turbine to generate electricity (e.g. instead of being used to heat the condensate).

[0049] In some embodiments, the steam path (e.g. a third steam path branch) comprises the amine-based solvent heater.

[0050] In some embodiments, the return path (e.g. a third branch of the return path) comprises the second condenser. The second condenser may be arranged downstream of the amine-based solvent heater. As previously mentioned, the second condensate may only be a portion of the condensate formed by the second condenser. The third branch of the return path may be configured to split downstream of the second condenser into a fourth branch and a fifth branch.

[0051] The return path may be configured to provide the second condensate (e.g. a portion of the condensate produced by the second condenser) to the fourth branch. The condensate mixer may be configured to merge the second branch with the fourth branch.

[0052] The return path may be configured to provide (e.g. at least some of) the remaining condensate from the second condenser to the fifth branch. The fifth branch may be configured to merge with the first and / or the second branch of the return path (e.g. downstream of the flue gas cooler, downstream of the heat exchanger, and / or upstream of the evaporator). Thus, the condensate formed by the second condenser may be integrated with the condensate formed by the (e.g. first) condenser for return to the boiler.

[0053] In some embodiments, the stage of the turbine that is configured to provide steam to the condenser is a low pressure stage, configured to receive steam (e.g. the first portion of steam) at a low pressure, and expand the received steam to a reduced (e.g. very low) pressure to generate electricity.

[0054] In some embodiments, turbine further comprises a second stage, upstream of the stage of the turbine that is configured to provide condensate to the condenser (e.g. upstream of where the steam path splits into the first steam path branch and the second path branch). The second stage of the turbine may be an intermediate pressure stage, configured toreceive steam at an intermediate pressure, and expand the received steam to a reduced (e.g. low) pressure to generate electricity.

[0055] Thus, the turbine may comprise an intermediate pressure stage configured to expand steam from an intermediate pressure to a low pressure, and a low pressure stage configured to expand the first portion of steam from a low pressure to a very low pressure. It may be difficult to design a single stage of the turbine that can optimise generation of electricity as the first portion of steam is expanded from an intermediate pressure to a very low pressure. On the other hand, if two turbine stages are used to expand the first portion of steam from the intermediate pressure to the very low pressure, each these stages can be designed to optimise generation of electricity as the first portion of steam is expanded through a smaller pressure range. Thus, efficiency of electricity generation from the first portion of steam may be improved.

[0056] The second portion of steam may be tapped off from the second stage of the turbine for use by the heat exchanger. Thus, it will be apparent that the provision of separate intermediate and low pressure turbine stages may allow steam to be tapped off between these stages at a suitable temperature and / or pressure for use by the heat exchanger.

[0057] In some embodiments, the turbine further comprises a third stage, upstream of the first and / or second stage of the turbine. The third stage of the turbine may be a high pressure stage, configured to receive steam at a high pressure, and expand the received steam to a reduced (e.g. intermediate) pressure to generate electricity.

[0058] The carbon capture power station unit may comprise a second boiler, arranged downstream of the third stage of the turbine. The third stage of the turbine may be configured to provide (e.g. at least some of) the steam at the reduced (e.g. intermediate) pressure to the second boiler. The reduced (e.g. intermediate) pressure of the steam may still be sufficiently high for it to be used to generate more electricity (e.g. without requiring the pressure of the steam to be increased). However, while the reduced (e.g. intermediate) pressure of the steam may be sufficiently high for it to be used to generate more electricity, re-heating of the steam may increase the amount of electricity that it can be used to generate.

[0059] In some embodiments, the furnace is configured to burn biomass to produce heat and flue gas. The production of biomass captures carbon from the atmosphere, and the carbon capture system is configured to capture carbon from the flue gas produced by burning biomass. Thus, embodiments of the carbon capture power station unit that are configured to burn biomass may be used to (i) generate electricity; and (ii) extract carbon from the atmosphere (e.g. so as to provide carbon negative electricity generation).

[0060] When viewed from a second aspect, the invention provides a biomass carbon capture power station unit, comprising:

[0061] a furnace, configured to burn biomass to produce heat and flue gas;

[0062] a boiler, configured to use the heat from the furnace to heat steam;

[0063] a turbine, configured to use at least some of the steam from the boiler to generate electricity in one or more stages;

[0064] a carbon capture system, configured to capture carbon from the flue gas to produce depleted flue gas; and

[0065] a return path, configured to return the steam from the turbine to the boiler, the return path comprising:a condenser, configured to condense at least some of the steam from a stage of the turbine to produce a condensate;

[0066] a flue gas cooler, configured to transfer heat from the flue gas to a first portion of the condensate; and

[0067] an evaporator, configured to evaporate the first portion of the condensate to produce steam for return to the boiler.

[0068] A biomass carbon capture power station unit in accordance with the present invention transfers heat from flue gas to condensate to: (i) cool down the flue gas from the furnace for carbon capture; and (ii) heat the condensate on the return path to help return steam to the boiler at an appropriate temperature and / or pressure. Thus, a carbon capture power station unit in accordance with the present invention usefully re-integrates heat from the flue gas into the carbon capture power station unit’s steam / condensate cycle.

[0069] Furthermore, a biomass carbon capture power station unit according to the present invention may be used to (i) generate electricity; and (ii) extract carbon from the atmosphere (e.g. so as to provide carbon negative electricity generation).

[0070] It will be appreciated that any of the (e.g. optional) features of the first aspect of the present invention can be applied equally to the second aspect. Similarly, any of the benefits of the first aspect of the present invention may apply equally to the second aspect.

[0071] The second aspect of the invention extends to a power station comprising the biomass carbon capture power station unit.

[0072] BRIEF DESCRIPTION OF DRAWINGS

[0073] One or more non-limiting examples will now be described, by way of example only, and with reference to the accompanying figures in which:

[0074] Figure 1 shows a schematic diagram of a power station 100 which has a carbon capture power station unit and another power station unit;

[0075] Figure 2 shows a schematic diagram of part of the carbon capture power station unit; and

[0076] Figure 3 shows a schematic diagram showing an overview of the carbon capture power station unit.

[0077] DETAILED DESCRIPTION

[0078] Figure 1 shows a schematic diagram of a power station 100 which has a carbon capture power station unit 200 and another power station unit 300. In this example, the power station unit 300 is a biomass power station unit which is not (or not yet) fitted with a carbon capture system. However, in other examples it may be a different type of power station unit. For instance, the power station unit 300 may be a wind power station unit, a solar power station unit, etc.. The power station 100 may of course include further power station units (not shown), such as one or more further carbon capture power station units.In this example, the carbon capture power station unit 200 is configured to generate electricity by burning biomass to heat steam, and using the heated steam to drive a turbine. While this carbon capture power station unit is designed to burn biomass, other types of carbon capture power station units may be designed to burn another type of fuel, e.g. natural gas or the like. In further examples, the power station 100 may only comprise a single power station unit, e.g. the carbon capture power station unit 200.

[0079] Figure 2 shows a schematic diagram of part of the carbon capture power station unit 200. In Figure 2, the flow of condensate is represented as a solid line, and the flow of flue gas is represented as a dotted line.

[0080] The carbon capture power station unit 200 includes a furnace 201 , which is configured to burn biomass to produce heat and flue gas, and a carbon capture system 230, which is configured to remove carbon from the flue gas to provide depleted flue gas before the flue gas is emitted via a stack (e.g. a chimney stack) 207.

[0081] The carbon capture power station unit 200 includes a flue gas cooler 222, which is arranged to receive flue gas from the furnace 201 and transfer heat from the flue gas to a condensate so as to help cool down the flue gas to a desired temperature (or temperature range) to be provided to the carbon capture system 230.

[0082] The carbon capture power station unit 200 optionally includes gas-gas heat exchanger 206 which is configured to receive the flue gas from the flue gas cooler 222, which has been partially cooled, and the depleted flue gas from the carbon capture system 230. The gas-gas heat exchanger 206 is configured to transfer heat from the flue gas to the depleted flue gas. This arrangement allows for the partially cooled flue gas from the flue gas cooler 222 to be cooled further to a desired temperature (or temperature range) to be provided to the carbon capture system 230, and for the depleted flue gas to be re-heated for effective dispersion by a stack 207 (e.g. a chimney stack).

[0083] The flue gas, which has now been cooled to a desired temperature (or temperature range), is provided to the carbon capture system 230 for depletion. The depleted flue gas, which has now been heated to an appropriate temperature for dispersion, is provided to the stack 207 to be dispersed.

[0084] Figure 3 shows a schematic diagram showing an overview of the carbon capture power station unit 200. In Figure 3, the flow of condensate is represented as a solid line, the flow of flue gas is represented as a dotted line, and the flow of steam is represented as a dashed line. The carbon capture power station unit 200 includes a furnace 201 , which is configured to burn biomass to produce heat and flue gas.

[0085] The carbon capture power station unit 200 includes a boiler 202, which is configured to receive steam and use heat produced by the furnace 201 to heat the received steam to a higher temperature.

[0086] The carbon capture power station unit 200 includes a turbine 210. The turbine 210 is a three-stage turbine, which has a high pressure turbine stage 211, an intermediate pressure turbine stage 212 and a low pressure turbine stage 213. The high pressure turbine stage 211 is configured to receive steam at a high temperature and a high pressure from the boiler 202 and expand the steam so as generate electricity. When the steam is expanded through the high pressure turbine stage 211 , the temperature and the pressure of the steam is reduced. The pressure of the steam is reduced to an intermediate pressure.The carbon capture power station unit 200 has a second boiler (“re-boiler”) 203, which is configured to receive the intermediate pressure steam from the high pressure turbine stage 211 , and use heat produced by the furnace 201 to heat the received steam to a higher temperature (known as “hot re-heat steam”).

[0087] While this is not how they are shown in the schematic diagram shown in Figure 3, the boiler 202 and the second boiler 203 are arranged at least partially within the furnace 201 so as to receive heat from the furnace when the biomass is combusted. It will be appreciated that the arrangement of the boiler 202 and the second boiler 203 are not shown in Figure 3 merely to help improve the clarity of the flow of steam, condensate and flue gas within the carbon capture power station unit 200.

[0088] The intermediate pressure stage 212 of the turbine 210 is configured to receive the intermediate pressure, high temperature, steam (“hot re-heat steam”) from the second boiler 203 and expand the steam so as generate electricity. When the steam is expanded through the intermediate pressure turbine stage 212, the temperature and the pressure of the steam is reduced. The pressure of the steam is reduced to a low pressure. Downstream of the intermediate pressure turbine stage 212, the path that the steam from the boiler 202 follows splits to form a first branch and a second branch.

[0089] The intermediate pressure turbine stage 212 is configured to provide a first portion of the low pressure steam to the first branch. The first branch continues to the low pressure stage 213 of the turbine 210.

[0090] The second branch of the path that the steam from the boiler 203 follows comprises a heat exchanger 204, and the intermediate pressure turbine stage 212 is configured to provide a second portion of the low pressure steam to the second branch. In other words, the intermediate pressure turbine stage 212 is configured to provide a second portion of the low pressure steam to the heat exchanger 204.

[0091] The low pressure stage 213 of the turbine 210 is configured to receive the low pressure steam from the intermediate pressure stage 212 of the turbine 210 and expand the steam so as generate electricity. When the steam is expanded through the low pressure turbine stage 213, the temperature and the pressure of the steam is reduced. The pressure of the steam is reduced to a very low pressure.

[0092] The carbon capture power station unit 200 includes a condenser 205, which is arranged downstream of the low pressure turbine stage 213. The low pressure turbine stage 213 is configured to provide the very low pressure steam to the condenser 205, and the condenser is configured to condense the very low pressure steam to form a condensate. The condensate follows a return path, which is configured to use the condensate to re-generate steam at an appropriate pressure and temperature to be provided back to the boiler 202 for re-use.

[0093] Downstream of the condenser 205, the return path splits to form two branches. A first portion of the condensate is provided to the first branch 217, and a second portion of the condensate is provided to the second branch 218. The first branch 217 of the return path includes a condensate mixer 221 and a flue gas cooler 222. The condensate mixer 221 is arranged upstream of the flue gas cooler 222. The second branch 218 of the return path includes the, previously mentioned, heat exchanger 204.

[0094] The carbon capture power station unit 200 also includes a carbon capture system 230. The carbon capture system 230 is configured to use an amine-based solvent to capture carbon from the flue gas produced by the furnace. The carbon capture system 230 comprises anamine-based solvent heater 231, which is configured to receive steam and transfer heat from the received steam to the amine-based solvent after it has captured carbon from the flue gas. When amine-based solvent is heated, it releases the carbon, which can then be stored. This allows the amine-based solvent to be re-used by the carbon capture system 230, to capture more carbon from the flue gas.

[0095] In this example, the steam provided to the amine-based solvent heater 231 to heat the amine-based solvent is tapped off from a point along the steam path followed by the steam from the boiler 202. However, in other examples the steam may be provided from another source.

[0096] The carbon capture system 230 includes a second condenser 232. The second condenser 232 is configured to receive the steam from the amine-based heater 231, once heat has been transferred from the steam to the amine-based solvent. The second condenser 232 is configured to condense the received steam so as to form a condensate.

[0097] The second condenser 232 is configured to provide the condensate to a third branch of the return path. The third branch is configured to split downstream of the second condenser 232 to form a fourth branch 219 and a fifth branch 220. Some of the condensate from the second condenser 232 is provided to the fourth branch 219, which comprises the, previously mentioned, condensate mixer 221.

[0098] The condensate mixer 221 is configured to mix the first portion of condensate received from the (first) condenser 205, and the portion of (second) condensate received from the second condenser 232 to form a condensate mix.

[0099] The flue gas cooler 222 is arranged to receive flue gas from the furnace 201 and the condensate mix from the condensate mixer 221. The flue gas cooler 222 is configured to transfer heat from the flue gas to the condensate mix, so as to help cool down the flue gas to a desired temperature (or temperature range) to be provided to the carbon capture system 230. The flue gas cooler 222 is configured to transfer heat from the flue gas to the condensate mix, so as to help the return path return steam to the boiler 202 at an appropriate pressure and temperature for re-use.

[0100] The, previously mentioned, heat exchanger 204 is configured to transfer heat from the low pressure steam, received from the intermediate pressure turbine stage 212, to the second portion of condensate, received from the condenser 205. The heat exchanger 204 is configured to heat the second portion of condensate to a similar temperature as the temperature that the flue gas cooler 222 heats the condensate mix. The first branch and the second branch of the return path are configured to merge downstream of the heat exchanger 204 and the flue gas cooler 222. As the temperatures of the condensate mix and the second portion of condensate downstream of the heat exchanger 204 and the flue gas cooler 222 are similar, it is relatively straightforward to merge the first and second branches.

[0101] In this example, the low pressure steam used by the heat exchanger 204 to heat the second portion of condensate is re-integrated into the steam / condensate cycle at a point along the return path. However, in other examples the low pressure steam used by the heat exchanger 204 may not necessarily be re-integrated into the steam / condensate cycle.

[0102] The first branch 217 and the second branch 218 of the return path are also configured to merge with the fifth branch 220 of the return path downstream of the heat exchanger 204 and the flue gas cooler 222. The temperature of the portion of condensate provided to the fifth branch 220 of the return path by the second condenser 232 is also similar to the temperature of the condensate from the heat exchanger 204 and the flue gas cooler 232. Asall of these condensate temperatures are similar, it is relatively straightforward to merge all three of these branches 217, 218, 220 of the return path.

[0103] The return path comprises an evaporator 208 configured to receive the condensate from the first, second and fifth branches 217, 218, 220 of the return path downstream of where they merge. The evaporator 208 is configured to change the phase of the received condensate from a liquid to a gas so as to produce steam. The steam is then provided (e.g. directly or indirectly) to the boiler 202 for re-use.

[0104] In this example, a gas-gas heat exchanger 206 is configured to receive the flue gas from the flue gas cooler 222, which has been partially cooled, and the depleted flue gas from the carbon capture system 230. This arrangement allows for the partially cooled flue gas from the flue gas cooler 222 to be cooled further to a desired temperature to be provided to the carbon capture system 230, and for the depleted flue gas to be re-heated for effective dispersion by a stack 207. Thus, the gas-gas heat exchanger 206 is configured to transfer heat from the flue gas to the depleted flue gas. The flue gas, which has now been cooled to a desired temperature, is provided to the carbon capture system 230 for depletion. The depleted flue gas, which has now been heated to an appropriate temperature for dispersion, is provided to the stack 207 (e.g. a chimney stack) to be dispersed.

[0105] In this example, the carbon capture system 230 has been retrofitted to a pre-existing power station unit 200. Thus, the demand on the pre-existing heat exchanger 204 has been reduced, as a (first) portion of condensate from the condenser 205 is heated by the flue gas cooler 222, as opposed to the pre-existing heat exchanger 204. This allows more of the steam from the intermediate pressure stage 212 of the turbine 210 to be provided to the low pressure stage 213 of the turbine 210, as less is required by the heat exchanger 204. As a result, the turbine 204 is able to generate more electricity, and so the efficiency of the power station unit 200 is improved.

[0106] The flue gas was previously provided by the furnace 201 at a temperature that was suitable for dispersion, which is higher than the temperature of flue gas suitable for the retrofitted carbon capture system 230. The flue gas cooler 222 also provides a means to partially cool the flue gas from the furnace 201 to a suitable temperature for the retrofitted carbon capture process. The remaining cooling of the flue gas is provided by the depleted flue gas, which anyway needs to be heated to an appropriate temperature for dispersion.

[0107] In this retrofitted arrangement, the hot flue gas needs to be transported from the stack 207, where it was previously dispersed, to the carbon capture system 230, and the depleted flue gas needs to be transported from the carbon capture system 230 back to the stack 207 for dispersion. Thus, as the flue gas and depleted flue gas are passing in opposite directions, there are relatively limited logistical challenges associated with providing a gas-gas heat exchanger to exchange heat between them.

[0108] The gas-gas heat exchanger 206 in this example has a rotary design, in which the flue gas and the depleted flue gas flow in opposite directions and are separated by a dividing wall. A metal mesh is placed in the flow path of the flue gases, and rotates so that each section of the mesh moves between the flow path of the hot flue gas (to heat the mesh) and the flow path of the depleted flue gas (so that the hot mesh heats the depleted gas). In other examples, alternative designs of gas-gas heat exchangers may be used instead.

[0109] The pressure, and velocity, of the flue gas drops as it passes through the gas-gas heat exchanger 206. A further pressure drop also occurs downstream of the gas-gas heat exchanger 206 when the flue gas passes through the carbon capture system 230. Therefore, a booster fan (not shown) can be provided between the gas-gas heat exchanger 206 andthe carbon capture system 230 to ‘push’ the flue gas through the carbon capture system 230. Another, secondary, booster fan can be provided after the carbon capture system 230 to ‘draw’ the flue gas through the carbon capture system 230 and ‘push’ the depleted flue gas through the other side of the gas-gas heat exchanger 206 and towards the stack 207 for dispersion.

[0110] The carbon capture power station unit 200 is configured to control a mass flow rate of the first portion of the condensate from the condenser 205 based on an amount of heat to be extracted from the flue gas. This depends on the mass flow rate of the flue gas. The mass flow rate of the flue gas is increased when more fuel is provided to the furnace 201. It may be desirable to increase the amount of fuel provided to the furnace 201 when it is desirable to produce more electricity (e.g. when the electricity price is high). Conversely, it may be desirable to decrease the amount of fuel provided to the furnace 201 when it is desirable to produce less electricity (e.g. when the electricity price is low). Thus, as they both affect the mass flow rate of flue gas, the carbon capture power station unit 200 is configured to control the mass flow rate of the first portion of the condensate from the condenser 205 based on: (i) an amount of fuel burned by the furnace and (ii) an electricity demand to be satisfied by the carbon capture power station unit 200.

[0111] Operation of the carbon capture power station unit 200 and some of the benefits provided will now be outlined in further detail, with continued reference to Figure 3.

[0112] Owing to the differences in composition of the flue gas and the depleted flue gas, the amount of energy that needs to be extracted from the flue gas to cool it down to an appropriate temperature for the carbon capture system 230 is greater than the amount of energy required to re-heat the depleted flue gas for effective dispersion. Therefore, even after the depleted flue gas has been heated to the minimum temperature suitable for effective dispersion, more energy can be extracted from the flue gas. Hence, the flue gas cooler 222 can be used to re-integrate this energy difference into the steam / condensate cycle.

[0113] In order to efficiently re-integrate the energy difference into the existing steam / condensate cycle, it is desirable for the temperature and the pressure of the steam / condensate after extracting the available energy from the flue gas, using the flue gas cooler 222, to match the temperature and the pressure of the steam / condensate at a point in the pre-existing steam / condensate cycle. While the condition matching may not need to perfect, the temperatures and pressures of the two fluids should ideally be very close.

[0114] The applicant has identified a point in the existing steam / condensate cycle where the condensate, from condenser 205, is at a relatively high pressure and is heated, by the preexisting heat exchanger 204, to a temperature that is close to the temperature of the flue gas from the furnace. Thus, it is a good candidate for extracting energy from the hot flue gas as high grade heat.

[0115] Using the existing steam / condensate cycle to extract the available energy from the hot flue gas provides several advantages, which include: re-integration of the energy removed from the hot flue gas directly into the steam / condensate cycle, a reduction of the amount of additional steam / condensate required to extract the available energy from the hot flue gas, and a reduced amount of new infrastructure required to extract the available energy from the hot flue gas.

[0116] While it would be convenient to heat the condensate from the condenser 205 directly, the acid dew point of the flue gas is higher than the temperature of the condensate from the condenser 205. Therefore, in order to mitigate the amount of corrosion caused bycondensation of the flue gas, the temperature of the condensate from the condenser 205 is increased to a temperature above the acid dew point of the flue gas before it is used by the flue gas cooler 222.

[0117] The condensate from the condenser 205 is pre-heated by mixing it, with the condensate mixer 221 , with condensate at the same pressure and a higher temperature. This mixture is then used by the flue gas cooler 222 to extract the available energy from the hot flue gas. In this example, the temperature of the condensate from the second condenser 232 is actually slightly higher than the temperature of the flue gas 201 from the furnace 201. Thus, while it may seem counterintuitive, condensate from the second condenser 232 at a higher temperature than the flue gas from the furnace 201 can be used to help cool down the flue gas by mixing it with the condensate from tapped off from the (first) condenser 205 to preheat the condensate mix to a temperature that is above the acid dew point of the flue gas, but still sufficiently cool to be used to extract the desired amount of heat from the flue gas. The carbon capture system 230 is designed so that if a reduced amount of condensate is required from the second condenser 232 (e.g. due to a reduced mass flow rate of flue gas from the furnace 201), the condensate is returned to the existing steam / condensate cycle downstream of the heat exchanger 204. Thus, the mass flow rate of condensate downstream of the heat exchanger 204 is unaffected by variation in the demand for condensate to extract heat from the flue gas using the flue gas cooler 222.

[0118] While in this example, the return path is represented as a relatively simple return path, it will be appreciated that the return path may comprise additional heat exchangers, condensers and / or evaporators that are not shown in Figure 3.

[0119] It will be appreciated by those skilled in the art that this disclosure has been illustrated by describing one or more specific examples thereof, but is not limited to these examples; many variations and modifications are possible, within the scope of the accompanying claims.

Claims

CLAIMS1. A carbon capture power station unit, comprising:a furnace, configured to burn fuel to produce heat and flue gas;a boiler, configured to use the heat from the furnace to heat steam;a turbine, configured to use at least some of the steam from the boiler to generate electricity in one or more stages;a carbon capture system, configured to capture carbon from the flue gas to produce depleted flue gas; anda return path, configured to return the steam from the turbine to the boiler, the return path comprising:a condenser, configured to condense at least some of the steam from a stage of the turbine to produce a condensate;a flue gas cooler, configured to transfer heat from the flue gas to at least a first portion of the condensate; andan evaporator, configured to evaporate at least the first portion of the condensate to produce steam for return to the boiler.

2. The carbon capture power station unit of claim 1 , further comprising a gas-gas heat exchanger configured to transfer heat from the flue gas to the depleted flue gas, prior to dispersion of the depleted flue gas.

3. The carbon capture power station unit of claim 2, wherein the flue gas cooler is arranged to receive the flue gas before the gas-gas heat exchanger such that, in use, heat is transferred from the flue gas to at least the first portion of the condensate before heat is transferred from the flue gas to the depleted flue gas.

4. The carbon capture power station unit of any preceding claim, wherein the return path further comprises:a condensate mixer, configured to:receive at least the first portion of the condensate from the condenser at a first temperature, and a second condensate at a second temperature; andmix the first portion of the condensate with the second condensate so as to provide a condensate mix at a third temperature;wherein the third temperature is between the first temperature and the second temperature; andwherein the flue gas cooler is arranged to receive the condensate mix from the condensate mixer, so as to transfer heat from the flue gas to the condensate mix.

5. The carbon capture power station unit of claim 4 wherein the condensate mixer is configured to:receive the first portion of the condensate from the condenser at a first temperature, and a second condensate at a second temperature; andmix the first portion of the condensate with the second condensate so as to provide a condensate mix at a third temperature;wherein the third temperature is between the first temperature and the second temperature; andwherein first temperature is lower than second temperature.

6. The carbon capture power station unit of claim 5, wherein the first temperature is below an acid dew point of the flue gas, and wherein both the second temperature and the third temperature are above the acid dew point of the flue gas.

7. The carbon capture power station unit of claim 5 or claim 6, wherein the temperature of the second condensate is higher than the temperature of the flue gas provided to the flue gas cooler.

8. The carbon capture power station unit of any of claims 5 to 7, wherein the temperature of the second condensate is substantially the same as a temperature of the condensate mix from the flue gas cooler.

9. The carbon capture power station unit of any of claims 4 to 8, wherein the carbon capture system is configured to use an amine-based solvent to capture carbon from the flue gas; andwherein the carbon capture system comprises:an amine-based solvent heater, configured to receive at least some of the steam from the boiler, and transfer heat from the received steam to the amine-based solvent so as to release the captured carbon for storage; anda second condenser, configured to receive the steam from the amine-based solvent heater, and condense the received steam to form the second condensate.

10. The carbon capture power station unit of any preceding claim, wherein the return path is arranged to split downstream of the condenser into a first branch and a second branch;wherein the return path is configured to provide a first portion of the condensate to the first branch, and to provide a second portion of the condensate to the second branch;wherein the first branch comprises the flue gas cooler, configured to transfer heat from the flue gas to the first portion of the condensate; andwherein the second branch comprises a heat exchanger, configured to transfer heat to a second portion of the condensate.

11. The carbon capture power station unit of claim 10, wherein the carbon capture power station unit is configured to control a mass flow rate of the first portion of the condensate based on an amount of heat to be extracted from the flue gas.

12. The carbon capture power station unit of claim 10 or claim 11 , further comprising a steam path arranged between the boiler and the return path, and configured to receive at least some of the steam from the boiler;wherein the steam path comprises the turbine;wherein the steam path is configured to split into a first steam path branch, comprising the stage of the turbine that is configured to provide steam to the condenser, and a second steam path branch, comprising the heat exchanger;wherein the steam path is configured to provide a first portion of steam to the first branch, and to provide a second portion of steam to the second branch; andwherein the heat exchanger is configured to transfer heat from the second portion of steam to the second portion of the condensate.

13. The carbon capture power station unit of any preceding claim, wherein the furnace is configured to burn biomass to produce heat and flue gas.

14. A biomass carbon capture power station unit, comprising:a furnace, configured to burn biomass to produce heat and flue gas;a boiler, configured to use the heat from the furnace to heat steam;a turbine, configured to use at least some of the steam from the boiler to generate electricity in one or more stages;a carbon capture system, configured to capture carbon from the flue gas to produce depleted flue gas; anda return path, configured to return the steam from the turbine to the boiler, the return path comprising:a condenser, configured to condense at least some of the steam from a stage of the turbine to produce a condensate;a flue gas cooler, configured to transfer heat from the flue gas to a first portion of the condensate; andan evaporator, configured to evaporate the first portion of the condensate to produce steam for return to the boiler.

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