Carbon capture system including a gas turbine with two burners

Abstract

A carbon capture system including a CO2-containing flue gas from any CO2 generation source connected to a first flue gas compressor of a gas turbine having a corresponding first turbine expander and a generator driven by the gas turbine, the gas turbine including a first burner and a second burner, the second burner utilizing at least a non-carbon fuel such as hydrogen (H2) or ammonia (NH3), thereby raising the temperature of the first relatively hot compressed CO2-lean flue gas to a second relatively hotter compressed CO2-lean flue gas that is supplied to the first expander.

Description

[Technical Field]

[0001] The present invention relates to the field of carbon capture technology, where CO2 extraction is performed in a so-called hot potassium carbonate (HPC) unit on a CO2-generating flue gas source that is directed to the flue gas compressor section of a gas turbine to raise the flue gas partial pressure for the carbon capture process.

[0002] More specifically, it is a CO2 capture process using a gas turbine that includes two burners with combustion chambers: a first burner, the preburner, designed to further combust the oxygen-depleted, CO2-rich compressed flue gas from the flue gas compressor before feeding it further into a heat exchanger on the way to the HPC unit, and a second burner, the afterburner, designed to heat the CO2-lean flue gas returning from the heat exchanger after the HPC unit and before the turbine expander. [Background technology]

[0003] The applicant has been working on carbon capture systems utilizing hot potassium carbonate in the process for several decades and has published two patent applications, U.S. Pat. No. 5,629,992 and U.S. Pat. No. 5,629,992, which use a gas turbine design including a flue gas compressor, one burner with a combustion chamber, and a turbine expander, where the flue gas is directed to the burner after the flue gas compressor and then to a heat exchanger on the way to the HPC unit. [Prior art documents] [Patent documents]

[0004] [Patent Document 1] International Publication No. 2019 / 172772 [Patent Document 2] International Publication No. 2021 / 210989 Summary of the Invention [Problem to be solved by the invention]

[0005] A known challenge of today's high temperature potassium carbonate CO2 extraction plants is increasing the partial pressure of the CO2 rich gas, which can be solved by utilizing a gas turbine compressor, but other challenges arise, such as maintaining a sustainable efficiency of this gas turbine, especially due to heat losses, and maintaining the mass balance of the gas turbine.

[0006] The present invention is generally directed to overcoming at least one, and preferably several, problems present in the prior art. More specifically, it is an object of the present invention to develop [Means for solving the problem]

[0007] The invention is defined by independent claim 1, which comprises: a carbon capture system including a CO2-containing flue gas source connected to a first flue gas compressor of a gas turbine having a corresponding first turbine expander and a generator driven by the gas turbine, -Gas turbines are a first burner having a first combustion chamber arranged to combust the compressed flue gas; a second burner having a second combustion chamber arranged for post-combustion of the relatively hot compressed CO2-lean flue gas; the second burner receives compressed flue gas from the compressor, the compressed flue gas cools a second combustion chamber shell of the second combustion chamber; the second combustion chamber shell via a coaxial piping with a coaxial piping shell for further transport of the compressed flue gas flow; - further connected to the first combustion chamber shell of a first burner for cooling the first combustion chamber, the first burner being supplied to the first combustion chamber for combustion with compressed air and fuel to generate first compressed pre-combusted flue gas; the first compressed pre-combusted flue gas is fed to a first heat exchanger for cooling and transferring heat to the relatively cool compressed CO2-lean flue gas produced downstream to form a first compressed pre-combusted cooled flue gas; the first compressed pre-combusted cooled flue gas is sent to a hot potassium process CO2 absorption plant, and the relatively low temperature compressed CO2-lean flue gas is returned to the first heat exchanger and heated to a first relatively high temperature compressed CO2-lean flue gas which is fed to a second burner; a carbon capture system in which the first relatively hot compressed CO2-lean flue gas is mixed with a compressed air stream and a non-carbon fuel such as at least hydrogen or ammonia by a second burner and post-combusted, thereby raising the temperature of the first relatively hot compressed CO2-lean flue gas to a second relatively hotter compressed CO2-lean flue gas that is supplied to a first expander.

[0008] Further embodiments of the invention are defined in the dependent claims. Embodiments of the present invention will now be described, by way of example only, with reference to the following figures: [Brief explanation of the drawings]

[0009] [Figure 1] 1 is a schematic diagram of the three main parts of the present invention: the gas turbine, the two burners and heat exchangers, and the HPC unit. [Figure 2] Shows a schematic diagram of the three main parts mentioned in Figure 1, but also showing the branch lines from the gas line returning from the HPC unit to the gas turbine for cooling and the afterburner (B2) for the thermal barrier. [Figure 3a] Principle flow diagram of a typical gas turbine (GT) burner and a carbon afterburner (B2). [Figure 3b] Schematic diagram of the principle of a typical gas turbine (GT) burner and a carbon afterburner (B2). [Figure 4]Karbon's afterburner (second burner - B2) and preburner (first burner - B1) and the connection between these two burners. [Figure 5] Schematic general diagram of a carbon capture system with a first burner (B1) and a second burner (B2). [Figure 6] Schematic expanded view of a carbon capture system with a first burner (B1) and a second burner (B2). [Figure 7] Schematic diagram of a carbon capture system with two burners (B1, B2), two turbine expanders (TE1, TE2) and branch piping for external cooling of the turbine expanders (TE1, TE2) and for a temperature barrier for the second burner (B2).

[0010] Embodiments of the present invention will now be described, by way of example only, with reference to the above figures. DETAILED DESCRIPTION OF THE INVENTION

[0011] The present invention provides a carbon capture system including a CO2-containing flue gas (FG) source (1) connected to a first flue gas compressor (FGC) of a gas turbine (GT) having a corresponding first turbine expander (TE1) and a generator (G) driven by the gas turbine (GT), -Gas turbines (GT) a first burner (B1) having a first combustion chamber (CC1) arranged for burning (e.g. heating) compressed flue gas (CFG); a second burner (B2) having a second combustion chamber (CC2) arranged for post-combustion (e.g., post-heating) of the relatively hot compressed CO2-lean flue gas (CLFG1H), in which - the second burner (B2) receives compressed flue gas (CFG) from the flue gas compressor (FGC), the compressed flue gas (CFG) cools a second combustion chamber shell (CC2S) of the second combustion chamber (CC2); - the second combustion chamber shell (CC2S) via a coaxial piping (P12) with a coaxial piping shell (PS12) for further transport of the compressed flue gas flow (CFG), - further connected to a first combustion chamber shell (CC1S) of a first burner (B1) for cooling the first combustion chamber (CC1), and supplied to the first combustion chamber (CC1) for combustion with compressed air (CA1) and fuel (G) to generate first compressed pre-combusted flue gas (CFG1); - the first compressed pre-combusted flue gas (CFG1) is fed to a first heat exchanger (HE1) for cooling and transferring heat to a downstream generated relatively low temperature compressed CO2-lean flue gas (CLFG1C) to form a first compressed pre-combusted cooled flue gas (CFG1C); - the first compressed pre-combusted cooled flue gas (CFG1C) is sent to a hot potassium process CO2 absorption plant (HPC), and the relatively cold compressed CO2-lean flue gas (CLFG1C) is returned to the first heat exchanger (HE1) and heated to a first relatively hot compressed CO2-lean flue gas (CLFG1H) which is fed to a second burner (B2); The first relatively hot compressed CO2-lean flue gas (CLFG1H) is mixed with a compressed air stream (CA2) and a non-carbon fuel such as at least hydrogen (H2) or ammonia (NH3) by a second burner (B2) and post-combusted, thereby raising the temperature of the first relatively hot compressed CO2-lean flue gas (CLFG1H) to a second relatively hotter compressed CO2-lean flue gas (CLFG2H) that is fed to the first turbine expander (TE1). The advancement behind this arrangement is to increase the inlet gas temperature to the first turbine expander (TE1) and thereby increase the efficiency of the gas turbine (GT). Simulation examples have shown that the efficiency of a gas turbine of type "SGT6-2000E" can be increased from approximately 25% to approximately 34% using a second burner (B2) that raises the inlet gas temperature from 750°C to approximately 1150°C before the turbine expander. Another advancement is that the inlet temperature of the first heat exchanger (HE1) can be controlled and adjusted so that the first heat exchanger (HE1) is not exposed to temperatures above about 900°C.

[0012] FIG. 5 shows a schematic embodiment of the invention described above, where CO2-containing flue gas (FG) from any flue gas source (1) is directed to a gas turbine (GT) flue gas compressor (FGC) and is compressed to approximately 1 barg (10 5 Pa) to about 12-13 barg (1.2-1.3 × 10 6The compressed flue gas (CFG) is then compressed to a temperature of approximately 900°C (Pa) to become compressed flue gas (CFG). The compressed flue gas is then directed to the second combustion chamber shell (CCS2) of the second burner (B2) as a cooling aid, and then returned to the first combustion chamber shell (CCS1) of the first burner (B1) as a cooling aid, and then enters the combustion chamber shell (CCS1) of the first burner through an opening and is burned with a fuel, for example, natural gas such as methane, to form first compressed pre-combusted flue gas (CFG1) at a temperature of approximately 900°C. The compressed flue gas (CFG) can optionally also be applied as a cooling aid to the first heat exchanger (HE1), in which case the compressed flue gas (CFG) is directed to the heat exchanger shell after the second combustion chamber shell (CCS2) and before the first combustion chamber shell (CCS1) (not shown in FIG. 5, but shown in FIG. 4). The first compressed pre-combusted flue gas (CFG1) is then cooled to about 135°C through a first heat exchanger (HE1) to form a first compressed pre-combusted cooled flue gas (CFG1C), which is then further led to a hot potassium process CO2 absorption plant (HPC) to extract CO2 from the CO2-containing flue gas (FG), and the relatively cold compressed CO2-lean flue gas (CLFG1C) with a temperature of about 95°C is returned to the first heat exchanger (HE1) to be converted into a relatively cold compressed C The O2-lean flue gas (CLFG1C) is heated to approximately 750°C to produce a relatively hot compressed CO2-lean flue gas (CLFG1H) that is supplied to a second burner, and mixed with at least a non-carbon fuel, such as ammonia (NH3) or hydrogen (H2), to heat the first relatively hot compressed CO2-lean flue gas (CLFG1H) to produce a second relatively hotter compressed CO2-lean flue gas (CLFG2H) at a temperature of approximately 1300°C that is supplied to the first turbine expander (TE1). The use of a non-carbon fuel or a mixture of a non-carbon fuel and a low-carbon fuel in the second burner improves the efficiency of the first turbine expander (TE1) of the gas turbine and results in zero or low CO2 emissions. Figure 5 further shows that after the first turbine expander (TE1), the first expanded relatively hot CO2-lean flue gas is directed to the stack or atmosphere.

[0013] In one embodiment of the present invention, the second combustion chamber (CC2) forms part of the coaxial piping (P12) that supplies the first turbine expander (TE1). The coaxial piping (P12) extends from the first heat exchanger (HE1) to the second combustion chamber (CC2), and the coaxial piping (P12) has a piping shell (PS12). The reason for this arrangement is to supply compressed flue gas to cool the coaxial shell around the second combustion chamber, the coaxial piping, the heat exchanger, and the first combustion chamber. This reduces the surface temperature of the combustion chamber pressure shell and piping.

[0014] 4 shows a schematic diagram of an embodiment of the present invention, in which the second burner (B2), an afterburner, is designed as an inlet burner integrated into the coaxial piping (P12) with the coaxial piping shell (P12S). The diagram shows a fuel supply pipe for single or mixed gases of NG, NH3, and / or H2, and a supply pipe for second compressed air (CA2), both connected to the nozzle part of the mixture, spraying gas into a second combustion chamber (CC2) to combust the first relatively hot compressed CO2-lean flue gas (CLFG1H) and heat it to a second relatively hotter compressed CO2-lean flue gas (CLFG2H) at a temperature of about 850 °C to about 1300 °C. The diagram shows that compressed flue gas (CFG) enters the second combustion chamber shell (CCS2), annulus of the second burner (B2), and proceeds to the first heat exchanger (HE1) in the coaxial piping shell (P12S), annulus.

[0015] In one embodiment of the present invention, the coaxial piping shell (PS12) is connected to a heat exchanger shell (HE1S) of a first heat exchanger (HE1), which is further connected to a first combustion chamber shell (CC1S) of a first combustion chamber (CC1), and the first combustion chamber shell (CC1S) is arranged to supply compressed flue gas (CFG) to the first combustion chamber (CC1). The reason for this arrangement is to heat the compressed flue gas (CFG) before entering the first combustion chamber (CC1) to burn residual unburned gas from the CO2-containing flue gas source, and to heat the compressed flue gas (CFG) to about 900°C before the first heat exchanger (HE1) to generate first compressed pre-combusted flue gas (CFG1).

[0016] FIG. 4 further shows a schematic diagram of a first combustion chamber (CC1) having a combustion chamber shell (CC1S) directly connected to a first burner (B1), a preburner, and a first heat exchanger (HE1), where a coaxial piping (12) is connected to a second burner (B2) and receives a first relatively hot compressed CO2-lean flue gas (CLFG1H), and the first heat exchanger receives the compressed flue gas (CFG) from the coaxial piping shell (P12S), annulus, and directs the compressed flue gas (CFG) through the piping into the first heat exchanger shell (HE1S), further into the combustion chamber shell (CC1S), and then into the opening of the first combustion chamber (CC1) for combustion with natural gas (NG) and first compressed air (CA1).

[0017] In one embodiment of the present invention, the relatively cool compressed CO2-lean flue gas (CLFG1C) stream is partially split and sent to a second burner (B2) as a temperature barrier (10). This arrangement provides a nozzle obstruction to flashback into the fuel supply line (FSL), which is particularly important when utilizing hydrogen (H2) and / or ammonia (NH3) as fuel. FIG. 4 also shows that the relatively low temperature compressed CO2-lean flue gas (CLFG1C) of about 95°C does not rise enough to self-ignite in the fuel supply line (FSL) returning after the hot potassium process CO2 absorption plant (HPC) because it acts as a temperature barrier or shield in the second burner (B2), such as the temperature in the fuel supply nozzle (FSN), e.g., hydrogen (H2) and ammonia (NH3).

[0018] In one embodiment of the present invention, the relatively low temperature compressed CO2-lean flue gas (CLFG1C) stream is partially split and sent to the first gas turbine expander (TE1) as a coolant. Using the relatively low temperature compressed CO2-lean flue gas (CLFG1C) stream at about 95°C as the coolant source for the gas turbine (GT) and replacing the internal cooling by utilizing carbon-rich compressed flue gas (CFG) with the relatively low temperature compressed CO2-lean flue gas (CLFG1C) stream reduces CO2 emissions because the coolant is sent directly to the atmosphere after cooling the first turbine expander (TE1).

[0019] Figure 7 shows a schematic diagram in which branch piping from the relatively low temperature compressed CO2-lean flue gas (CLFG1C) at about 95°C is directed towards the first turbine expander (TE1) and the second turbine expander (TE2) as a coolant. Figure 7 also shows that a third branch from the relatively low temperature compressed CO2-lean flue gas (CLFG1C) is directed to the second burner as a temperature barrier / shield.

[0020] In one embodiment of the present invention, the second relatively hotter compressed CO2-lean flue gas (CLFG2H) is fed to a first turbine expander (TE1) to drive a shaft connected to a generator (G) and to produce a first expanded relatively hot CO2-lean flue gas (ELFGH) which is further connected to a first heat recovery and steam generation unit (HRSG1). This arrangement is for further utilization of the first expanded relatively hot CO2-lean flue gas (ELFGH) exiting the first turbine expander (TE1) at about 500°C.

[0021] In a further embodiment of the present invention, the first heat recovery and steam generation unit (HRSG1) is for producing first steam (ST1), which is further connected to a heat exchanger in a strip unit included in a high temperature potassium process CO2 absorption unit (HPC), the strip unit being shown in Figures 1 and 2.

[0022] In another embodiment of the present invention, the first heat recovery and steam generation unit (HRSG1) is for generating second steam (ST2), which is further connected to a steam generator (SG) for generating electrical power.

[0023] Figure 6 shows a schematic diagram in which the first expanded relatively high temperature CO2-lean flue gas (ELFGH) is discharged from the turbine expander (TE1) at about 500°C to the first heat recovery and steam generator unit (HRSG1), which further supplies the first steam (ST1) to the hot potassium process CO2 absorption plant (HPC), and the second steam (ST2) to the steam turbine generator (STG) to generate electricity.

[0024] In one embodiment of the present invention, the first turbine expander (TE1) is configured to expand the additional mass flow from the second burner (B2). If additional mass flow is added to the process after the flue gas compressor (FGC), an oversized expander can be the solution to maintain mass balance if needed.

[0025] In one embodiment of the present invention, the second relatively hotter compressed CO2-lean flue gas (CLFG2H) is fed to a first turbine expander (TE1) and a second turbine expander (TE2) in parallel with the first turbine expander (TE1). This is another solution to maintain mass balance between the compressed flue gas, extracted CO2, and added fuel and air at the first and second burners (B1, B2) when additional mass flow is added to the process after the flue gas compressor [FGC].

[0026] In one embodiment, the second expander (TE2) is installed in parallel with the first turbine expander (TE1) operating at the same inlet pressure and temperature. This is necessary to avoid excessive flow and pressure into the first turbine expander (TE1) which could lead to surge in the flue gas compressor.

[0027] In one embodiment, the first turbine expander (TE1) can be used to generate electricity and the second expander (TE2) can be used to generate steam for heat exchangers in a strip unit included in the HPC unit.

[0028] Figure 7 shows a schematic diagram of an embodiment with two turbine expanders (TE1, TE2) receiving a second, relatively hotter, compressed CO2-lean flue gas (CLFG2H) of the same pressure and temperature. The diagram further shows that it is sent to a first heat recovery and steam generation unit (HRSG1). A second heat recovery and steam generation unit (HRSG2) is shown as an option, connected after the first heat exchanger (HE1) to receive the first compressed pre-combusted cooled flue gas (CFG1C) and return the second compressed pre-combusted cooled flue gas (CFG2C) to the hot potassium carbonate CO2 absorption unit (HPC).

[0029] FIG. 7 shows two air compressors, a first air compressor (AC1) compresses a first compressed air (CA1) to a first burner (B1), and a second air compressor (AC2) compresses a second compressed air (CA2) to a second burner (B2).

[0030] In one embodiment of the present invention, a relatively cool compressed CO2-lean flue gas (CLFG1C) stream is partially split and sent as coolant to a first gas turbine expander (TE1) and a second turbine expander (TE2), see particularly Figure 7.

[0031] In one embodiment of the present invention, the first compressed pre-combusted cooled flue gas (CFG1C) is directed to a second heat recovery unit and steam generator (HRSG2) to further cool the first compressed pre-combusted cooled flue gas (CFG1C) into a second compressed pre-combusted cooled flue gas (CFG2C), which is then directed to a hot potassium carbonate CO2 absorption unit (HPC). This configuration contributes to lowering the gas temperature of the relatively low temperature compressed CO2 lean flue gas (CLFG1C) even further below 95°C. This is advantageous for both utilizing the relatively low temperature compressed CO2 lean flue gas (CLFG1C) as a coolant for the turbine expanders (TE1, TE2) and for the first heat exchanger (HE1). In another scenario, the relatively cold compressed CO2-lean flue gas (CLFG1C) has a temperature set point of 95°C after the hot potassium carbonate CO2 absorption unit (HPC), and the use of a second heat recovery and steam generation unit (HRSG2) can reduce the heat transfer in the first heat exchanger (HE1) and simplify the heat balance of the first heat exchanger (HE1). See Figure 7.

[0032] In one embodiment of the present invention, the CO2 extracted by a hot potassium carbonate CO2 absorption unit (HPC) is directed to a CO2 compressor, then cooled and utilized for enhanced oil recovery sequestration (EOR / S). Referring to Figure 6, a schematic diagram of the extracted CO2 is shown.

[0033] In one embodiment of the present invention, the second burner (B2) uses only non-carbon fuels such as hydrogen (H2) or ammonia (NH3), eliminating any further CO2 emissions. Figure 1 is a schematic diagram of an embodiment of the invention using two burners. The diagram also shows the temperature difference after each unit and the initial partial pressure after the gas turbine compressor. Figure 1 shows three main elements: the gas turbine, the burners and heat exchangers, and the HPC unit.

[0034] Figure 2 shows a schematic diagram of an embodiment of the invention using two burners and a cooling line after the absorption unit. The diagram further shows that the exhaust gas, CO2-containing flue gas, can vary in CO2 content from 3% to 12%, depending on the CO2 emission source.

[0035] Figures 3a and 3b show the principle flow diagram and schematic of a typical gas turbine burner, where oxidant is internally introduced into the burner from the gas turbine compressor, and coolant is also internally introduced from the gas turbine compressor.

[0036] Figures 3a and 3b also show the principle flow diagram and schematic of an afterburner embodiment of the present invention, where the oxidant is taken from separately compressed air. The diagram further shows that a thermal barrier / shield is tapped after the HPC unit, and CO2-lean (depleted) flue gas from the first heat exchanger (HE1) is fed to a second combustion chamber (CCS2), referred to here as a gas mixer, due to the use of gas impellers in this embodiment. [Explanation of symbols]

[0037] 1...any CO2 source, 10...temperature barrier, GT...gas turbine, FGC...flue gas compressor, TE1...first turbine expander, TE2...second turbine expander, G...generator, HPC...high temperature potassium carbonate-CO2 absorption unit, STG...steam turbine generator, HRU...heat recovery unit, HRSG...heat recovery and steam generator, HRSG1...first heat recovery unit and steam generator, HRSG2...second Heat recovery unit and steam generator, EOR / S...Enhanced Oil Recovery Sequestration, AC1...First air compressor, AC2...Second air compressor, B1...First burner / preburner, B2...Second burner / afterburner, CC1...First combustion chamber, CC2...Second combustion chamber, CC1S...First combustion chamber shell, CC2S...Second combustion chamber shell, P12...Coaxial piping, PS12...Coaxial piping shell, HE1...First Heat exchanger, HE1S...first heat exchanger shell, CA1...compressed air from the first air compressor, CA2...compressed air from the second air compressor, ST1...first steam, ST2...second steam, NG...natural gas fuel, H2...hydrogen fuel, NH3...ammonia fuel, CO2...carbon dioxide, FG...flue gas, CFG...compressed flue gas, CFG1...first compressed pre-combusted flue gas, CFG1C...first compressed pre-combusted cooled flue gas, CFG2C...second compressed pre-combusted cooled flue gas, CLFG1H...first relatively hot compressed CO2-lean flue gas, CLFG2H...second relatively hotter compressed CO2-lean flue gas, ELFGH...first expanded relatively hot CO2-lean flue gas, FSN...fuel delivery nozzle, FSL...fuel delivery line.

Claims

1. 1. A carbon capture system comprising: Any CO2 gas turbine connected to a first flue gas compressor of said gas turbine having a corresponding first turbine expander and a generator driven by said gas turbine. ２ CO from the source ２ containing flue gas, The gas turbine comprises: a first burner having a first combustion chamber positioned to combust the compressed flue gas; Hot compressed CO ２ a second burner having a second combustion chamber arranged for post-combustion of the lean flue gases, the second burner receives compressed flue gas from the first flue gas compressor, the compressed flue gas enters a second combustion chamber shell of the second combustion chamber and cools a coaxial piping shell of the second combustion chamber; the second combustion chamber shell via a coaxial piping with the coaxial piping shell for further transporting the compressed flue gas flow; further connected to a first combustion chamber shell of a first burner for cooling the first combustion chamber, and the compressed flue gas is supplied to the first combustion chamber for combustion with compressed air and fuel to produce first compressed pre-combusted flue gas; The first compressed pre-combusted flue gas is fed to a first heat exchanger for cooling and releasing the cold compressed CO produced downstream. ２ - transferring heat to the lean flue gas to form a first compressed pre-combusted cooled flue gas; The first compressed pre-combusted cooled flue gas is then compressed into hot potassium process CO ２ is sent to an absorption plant to convert the cold compressed CO 2 into lean flue gas, ２ - Lean flue gas is returned to the first heat exchanger and converted into a first hot compressed CO2 for supply to the second burner. ２ - heated by lean flue gases, the first hot compressed CO ２ The lean flue gas is mixed with a compressed air stream and at least a carbon-free fuel by the second burner and post-burned to produce the first hot compressed CO ２ - Raising the temperature of the lean flue gas to a second, warmer, compressed CO ２ - Carbon capture system to raise the level to lean flue gas.

2. 2. The carbon capture system of claim 1, wherein the second combustion chamber forms part of the coaxial piping that feeds the first turbine expander, the coaxial piping extending from the first heat exchanger to the second combustion chamber, and the coaxial piping having the coaxial piping shell.

3. 3. The carbon capture system of claim 2, wherein the coaxial piping shell is connected to a heat exchanger shell of the first heat exchanger, the heat exchanger shell is further connected to a first combustion chamber shell of the first combustion chamber, the first combustion chamber shell being positioned to supply the compressed flue gas to the first combustion chamber.

4. the cold compressed CO ２ A carbon capture system as claimed in claim 1, wherein the lean flue gas stream is split and a portion thereof is sent to the second burner as a temperature barrier.

5. the cold compressed CO ２ 2. A carbon capture system as claimed in claim 1, wherein the lean flue gas stream is split and a portion thereof is sent as a coolant to said first turbine expander.

6. the second higher temperature compressed CO ２ The lean flue gas is fed to the first turbine expander, driving a shaft connected to the generator, and a first expanded relatively hot CO 2 gas is further connected to a first heat recovery and steam generation unit. ２ - A carbon capture system according to claim 1, which produces lean flue gas.

7. The first heat recovery and steam generation unit is for generating first steam, and the high temperature potassium process CO ２ 7. The carbon capture system of claim 6, wherein the absorption unit is connected to the heat exchanger unit by a strip unit.

8. 7. The carbon capture system of claim 6, wherein the first heat recovery and steam generation unit is for generating second steam and is connected to a steam generator for generating electrical power.

9. The carbon capture system of claim 1 , wherein the first turbine expander is configured to expand additional mass flow from the second burner.

10. the second higher temperature compressed CO ２ 2. The carbon capture system of claim 1, wherein lean flue gas is supplied to the first turbine expander and to a second turbine expander in parallel with the first turbine expander.

11. the cold compressed CO ２ The carbon capture system of claim 10, wherein a lean flue gas stream is directed as a coolant towards the first turbine expander and the second turbine expander.

12. The first compressed pre-combusted cooled flue gas is directed to a second heat recovery unit and a steam generator to further cool the first compressed pre-combusted cooled flue gas to produce the hot potassium carbonate CO ２ 10. The carbon capture system of claim 1, wherein the second compressed pre-combusted cooled flue gas is directed to an absorption unit.

13. The hot potassium carbonate CO ２ CO extracted by the absorption unit ２ is CO ２ 10. The carbon capture system of claim 1, wherein the carbon capture system is directed to a compressor, cooled, and then utilized for enhanced oil recovery sequestration.

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