KR20160062139A - Power generation and co_2 capture with turbines in series - Google Patents

Power generation and co_2 capture with turbines in series Download PDF

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Publication number
KR20160062139A
KR20160062139A KR1020167011211A KR20167011211A KR20160062139A KR 20160062139 A KR20160062139 A KR 20160062139A KR 1020167011211 A KR1020167011211 A KR 1020167011211A KR 20167011211 A KR20167011211 A KR 20167011211A KR 20160062139 A KR20160062139 A KR 20160062139A
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South Korea
Prior art keywords
anode
fuel cell
fuel
exhaust gas
combustion
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KR1020167011211A
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Korean (ko)
Inventor
티모시 에이 발크홀츠
프랭크 허쉬코위츠
폴 제이 벌로위츠
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엑손모빌 리서치 앤드 엔지니어링 컴퍼니
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Priority to US61/884,635 priority Critical
Priority to US201361884635P priority
Priority to US201361884586P priority
Priority to US201361884565P priority
Priority to US201361884545P priority
Priority to US201361884605P priority
Priority to US201361884376P priority
Priority to US61/884,586 priority
Priority to US61/884,565 priority
Priority to US61/884,605 priority
Priority to US61/884,376 priority
Priority to US61/884,545 priority
Priority to US61/889,757 priority
Priority to US201361889757P priority
Priority to US14/197,551 priority patent/US20140272615A1/en
Priority to US14/197,430 priority patent/US20140272614A1/en
Priority to US14/197,613 priority
Priority to US14/197,391 priority patent/US20140272613A1/en
Priority to US14/197,551 priority
Priority to US14/197,430 priority
Priority to US14/197,391 priority
Priority to US14/197,613 priority patent/US9774053B2/en
Priority to US14/207,687 priority patent/US9941534B2/en
Priority to US14/207,699 priority patent/US20140272635A1/en
Priority to US14/207,693 priority
Priority to US14/207,691 priority
Priority to US14/207,721 priority patent/US9520607B2/en
Priority to US14/207,690 priority
Priority to US14/207,697 priority patent/US9923219B2/en
Priority to US14/207,708 priority
Priority to US14/207,714 priority patent/US9343764B2/en
Priority to US14/207,728 priority patent/US20140261090A1/en
Priority to US14/207,686 priority patent/US20140272633A1/en
Priority to US14/207,693 priority patent/US9786939B2/en
Priority to US14/207,699 priority
Priority to US14/207,706 priority patent/US9455463B2/en
Priority to US14/207,708 priority patent/US9647284B2/en
Priority to US14/207,712 priority patent/US9343763B2/en
Priority to US14/207,687 priority
Priority to US14/207,726 priority patent/US9263755B2/en
Priority to US14/207,686 priority
Priority to US14/207,711 priority
Priority to US14/207,710 priority
Priority to US14/207,711 priority patent/US9735440B2/en
Priority to US14/207,698 priority
Priority to US14/207,697 priority
Priority to US14/207,706 priority
Priority to US14/207,710 priority patent/US9362580B2/en
Priority to US14/207,712 priority
Priority to US14/207,690 priority patent/US9553321B2/en
Priority to US14/207,721 priority
Priority to US14/207,726 priority
Priority to US14/207,691 priority patent/US9257711B2/en
Priority to US14/207,698 priority patent/US9419295B2/en
Priority to US14/207,714 priority
Priority to US14/207,728 priority
Priority to US14/315,419 priority patent/US9178234B2/en
Priority to US14/315,439 priority patent/US9077005B2/en
Priority to US14/315,439 priority
Priority to US14/315,479 priority patent/US9077006B2/en
Priority to US14/315,507 priority patent/US9077007B2/en
Priority to US14/315,527 priority
Priority to US14/315,507 priority
Priority to US14/315,419 priority
Priority to US14/315,479 priority
Priority to US14/315,527 priority patent/US9077008B2/en
Priority to US14/486,200 priority patent/US9556753B2/en
Priority to US14/486,200 priority
Application filed by 엑손모빌 리서치 앤드 엔지니어링 컴퍼니 filed Critical 엑손모빌 리서치 앤드 엔지니어링 컴퍼니
Priority to PCT/US2014/058020 priority patent/WO2015048628A1/en
Publication of KR20160062139A publication Critical patent/KR20160062139A/en

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    • CCHEMISTRY; METALLURGY
    • C01INORGANIC CHEMISTRY
    • C01BNON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B3/00Hydrogen; Gaseous mixtures containing hydrogen; Separation of hydrogen from mixtures containing it; Purification of hydrogen
    • C01B3/02Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen
    • C01B3/32Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air
    • C01B3/34Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air by reaction of hydrocarbons with gasifying agents
    • C01B3/38Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air by reaction of hydrocarbons with gasifying agents using catalysts
    • FMECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F01MACHINES OR ENGINES IN GENERAL; ENGINE PLANTS IN GENERAL; STEAM ENGINES
    • F01DNON-POSITIVE DISPLACEMENT MACHINES OR ENGINES, e.g. STEAM TURBINES
    • F01D13/00Combinations of two or more machines or engines
    • FMECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F01MACHINES OR ENGINES IN GENERAL; ENGINE PLANTS IN GENERAL; STEAM ENGINES
    • F01KSTEAM ENGINE PLANTS; STEAM ACCUMULATORS; ENGINE PLANTS NOT OTHERWISE PROVIDED FOR; ENGINES USING SPECIAL WORKING FLUIDS OR CYCLES
    • F01K23/00Plants characterised by more than one engine delivering power external to the plant, the engines being driven by different fluids
    • F01K23/02Plants characterised by more than one engine delivering power external to the plant, the engines being driven by different fluids the engine cycles being thermally coupled
    • F01K23/06Plants characterised by more than one engine delivering power external to the plant, the engines being driven by different fluids the engine cycles being thermally coupled combustion heat from one cycle heating the fluid in another cycle
    • F01K23/10Plants characterised by more than one engine delivering power external to the plant, the engines being driven by different fluids the engine cycles being thermally coupled combustion heat from one cycle heating the fluid in another cycle with exhaust fluid of one cycle heating the fluid in another cycle
    • FMECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F02COMBUSTION ENGINES; HOT-GAS OR COMBUSTION-PRODUCT ENGINE PLANTS
    • F02CGAS-TURBINE PLANTS; AIR INTAKES FOR JET-PROPULSION PLANTS; CONTROLLING FUEL SUPPLY IN AIR-BREATHING JET-PROPULSION PLANTS
    • F02C3/00Gas-turbine plants characterised by the use of combustion products as the working fluid
    • F02C3/20Gas-turbine plants characterised by the use of combustion products as the working fluid using a special fuel, oxidant, or dilution fluid to generate the combustion products
    • F02C3/22Gas-turbine plants characterised by the use of combustion products as the working fluid using a special fuel, oxidant, or dilution fluid to generate the combustion products the fuel or oxidant being gaseous at standard temperature and pressure
    • FMECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F02COMBUSTION ENGINES; HOT-GAS OR COMBUSTION-PRODUCT ENGINE PLANTS
    • F02CGAS-TURBINE PLANTS; AIR INTAKES FOR JET-PROPULSION PLANTS; CONTROLLING FUEL SUPPLY IN AIR-BREATHING JET-PROPULSION PLANTS
    • F02C6/00Plural gas-turbine plants; Combinations of gas-turbine plants with other apparatus; Adaptations of gas- turbine plants for special use
    • FMECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F02COMBUSTION ENGINES; HOT-GAS OR COMBUSTION-PRODUCT ENGINE PLANTS
    • F02CGAS-TURBINE PLANTS; AIR INTAKES FOR JET-PROPULSION PLANTS; CONTROLLING FUEL SUPPLY IN AIR-BREATHING JET-PROPULSION PLANTS
    • F02C6/00Plural gas-turbine plants; Combinations of gas-turbine plants with other apparatus; Adaptations of gas- turbine plants for special use
    • F02C6/18Plural gas-turbine plants; Combinations of gas-turbine plants with other apparatus; Adaptations of gas- turbine plants for special use using the waste heat of gas-turbine plants outside the plants themselves, e.g. gas-turbine power heat plants
    • HELECTRICITY
    • H01BASIC ELECTRIC ELEMENTS
    • H01MPROCESSES OR MEANS, e.g. BATTERIES, FOR THE DIRECT CONVERSION OF CHEMICAL ENERGY INTO ELECTRICAL ENERGY
    • H01M8/00Fuel cells; Manufacture thereof
    • H01M8/06Combination of fuel cells with means for production of reactants or for treatment of residues
    • H01M8/0606Combination of fuel cells with means for production of reactants or for treatment of residues with means for production of gaseous reactants
    • H01M8/0612Combination of fuel cells with means for production of reactants or for treatment of residues with means for production of gaseous reactants from carbon-containing material
    • H01M8/0618Reforming processes, e.g. autothermal, partial oxidation or steam reforming
    • HELECTRICITY
    • H01BASIC ELECTRIC ELEMENTS
    • H01MPROCESSES OR MEANS, e.g. BATTERIES, FOR THE DIRECT CONVERSION OF CHEMICAL ENERGY INTO ELECTRICAL ENERGY
    • H01M8/00Fuel cells; Manufacture thereof
    • H01M8/06Combination of fuel cells with means for production of reactants or for treatment of residues
    • H01M8/0606Combination of fuel cells with means for production of reactants or for treatment of residues with means for production of gaseous reactants
    • H01M8/0612Combination of fuel cells with means for production of reactants or for treatment of residues with means for production of gaseous reactants from carbon-containing material
    • H01M8/0625Combination of fuel cells with means for production of reactants or for treatment of residues with means for production of gaseous reactants from carbon-containing material in a modular combined reactor/fuel cell structure
    • HELECTRICITY
    • H01BASIC ELECTRIC ELEMENTS
    • H01MPROCESSES OR MEANS, e.g. BATTERIES, FOR THE DIRECT CONVERSION OF CHEMICAL ENERGY INTO ELECTRICAL ENERGY
    • H01M8/00Fuel cells; Manufacture thereof
    • H01M8/06Combination of fuel cells with means for production of reactants or for treatment of residues
    • H01M8/0606Combination of fuel cells with means for production of reactants or for treatment of residues with means for production of gaseous reactants
    • H01M8/0612Combination of fuel cells with means for production of reactants or for treatment of residues with means for production of gaseous reactants from carbon-containing material
    • H01M8/0637Direct internal reforming at the anode of the fuel cell
    • HELECTRICITY
    • H01BASIC ELECTRIC ELEMENTS
    • H01MPROCESSES OR MEANS, e.g. BATTERIES, FOR THE DIRECT CONVERSION OF CHEMICAL ENERGY INTO ELECTRICAL ENERGY
    • H01M8/00Fuel cells; Manufacture thereof
    • H01M8/06Combination of fuel cells with means for production of reactants or for treatment of residues
    • H01M8/0662Treatment of gaseous reactants or gaseous residues, e.g. cleaning
    • H01M8/0668Removal of carbon monoxide or carbon dioxide
    • HELECTRICITY
    • H01BASIC ELECTRIC ELEMENTS
    • H01MPROCESSES OR MEANS, e.g. BATTERIES, FOR THE DIRECT CONVERSION OF CHEMICAL ENERGY INTO ELECTRICAL ENERGY
    • H01M8/00Fuel cells; Manufacture thereof
    • H01M8/14Fuel cells with fused electrolytes
    • H01M8/144Fuel cells with fused electrolytes characterised by the electrolyte material
    • H01M8/145Fuel cells with fused electrolytes characterised by the electrolyte material comprising carbonates
    • CCHEMISTRY; METALLURGY
    • C01INORGANIC CHEMISTRY
    • C01BNON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/02Processes for making hydrogen or synthesis gas
    • C01B2203/0205Processes for making hydrogen or synthesis gas containing a reforming step
    • C01B2203/0227Processes for making hydrogen or synthesis gas containing a reforming step containing a catalytic reforming step
    • C01B2203/0233Processes for making hydrogen or synthesis gas containing a reforming step containing a catalytic reforming step the reforming step being a steam reforming step
    • FMECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F05INDEXING SCHEMES RELATING TO ENGINES OR PUMPS IN VARIOUS SUBCLASSES OF CLASSES F01-F04
    • F05DINDEXING SCHEME FOR ASPECTS RELATING TO NON-POSITIVE-DISPLACEMENT MACHINES OR ENGINES, GAS-TURBINES OR JET-PROPULSION PLANTS
    • F05D2260/00Function
    • F05D2260/60Fluid transfer
    • F05D2260/61Removal of CO2
    • FMECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F05INDEXING SCHEMES RELATING TO ENGINES OR PUMPS IN VARIOUS SUBCLASSES OF CLASSES F01-F04
    • F05DINDEXING SCHEME FOR ASPECTS RELATING TO NON-POSITIVE-DISPLACEMENT MACHINES OR ENGINES, GAS-TURBINES OR JET-PROPULSION PLANTS
    • F05D2260/00Function
    • F05D2260/60Fluid transfer
    • F05D2260/611Sequestration of CO2
    • HELECTRICITY
    • H01BASIC ELECTRIC ELEMENTS
    • H01MPROCESSES OR MEANS, e.g. BATTERIES, FOR THE DIRECT CONVERSION OF CHEMICAL ENERGY INTO ELECTRICAL ENERGY
    • H01M8/00Fuel cells; Manufacture thereof
    • H01M8/14Fuel cells with fused electrolytes
    • H01M2008/147Fuel cells with molten carbonates
    • HELECTRICITY
    • H01BASIC ELECTRIC ELEMENTS
    • H01MPROCESSES OR MEANS, e.g. BATTERIES, FOR THE DIRECT CONVERSION OF CHEMICAL ENERGY INTO ELECTRICAL ENERGY
    • H01M2250/00Fuel cells for particular applications; Specific features of fuel cell system
    • H01M2250/40Combination of fuel cells with other energy production systems
    • H01M2250/402Combination of fuel cell with other electric generators
    • YGENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02EREDUCTION OF GREENHOUSE GAS [GHG] EMISSIONS, RELATED TO ENERGY GENERATION, TRANSMISSION OR DISTRIBUTION
    • Y02E20/00Combustion technologies with mitigation potential
    • Y02E20/10Combined combustion
    • Y02E20/14Combined heat and power generation [CHP]
    • YGENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02EREDUCTION OF GREENHOUSE GAS [GHG] EMISSIONS, RELATED TO ENERGY GENERATION, TRANSMISSION OR DISTRIBUTION
    • Y02E20/00Combustion technologies with mitigation potential
    • Y02E20/10Combined combustion
    • Y02E20/16Combined cycle power plant [CCPP], or combined cycle gas turbine [CCGT]
    • YGENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02PCLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
    • Y02P20/00Technologies relating to chemical industry
    • Y02P20/10General improvement of production processes causing greenhouse gases [GHG] emissions
    • Y02P20/12Energy input
    • Y02P20/129Energy recovery

Abstract

In various embodiments, a method of producing electricity by operating two or more turbines in series is provided. The method may include introducing at least a portion of the exhaust gas from a turbine upstream of the process into a combustion chamber of a downstream turbine. In one embodiment, the exhaust gas from a turbine located in front of the process is introduced into the combustion chamber of the turbine, which is located behind the process, via the compression chamber of the turbine located behind the process.

Description

POWER GENERATION AND CO₂ CAPTURE WITH TURBINES IN SERIES "

In various aspects, the invention relates to a power generation method using a gas turbine integrated with a fuel cell.

Gas turbines are commonly used for power generation because of their small size, high efficiency and low capital cost. Gas turbines can be deployed in an integrated cycle system that pairs heat recovery water vapor ("HRSG") and combustion turbine generators ("CTGs"). In an integrated cycle system, the CTG produces electricity, and the exhaust gas from the CTG is then used by the HRSG to generate water vapor that can be introduced into the steam turbine to generate additional electricity.

The CTG can use a compression chamber to compress the air to high and high temperatures. The compressed air is then introduced into the compression chamber where the constant pressure combustion of the fuel takes place. The hot exhaust gas then expands across the turbine to relax the pressure and reduce the temperature. The work of the CTG is to rotate the shaft connected to the generator generating the alternating current. The hot exhaust gas from the gas turbine can be used to form water vapor in the RSG, which can be used to rotate the steam turbine generator or STG to form more electricity.

Molten carbonate fuel cells generate electricity using hydrogen and / or other fuels. Hydrogen can be provided by reforming methane or other reformable fuel in a steam reformer that is either in front of the fuel cell or in the fuel cell. The reformable fuel may include a hydrocarbonaceous material capable of reacting with steam and / or oxygen at elevated temperature and / or pressure to produce a gaseous product comprising hydrogen. Alternatively or additionally, the fuel can be reformed in an anode cell of a molten carbonate fuel cell (which can be operated to form conditions suitable for reforming the fuel at the anode). Alternatively or additionally, reforming can be done both outside and inside the fuel cell.

Traditionally, molten carbonate fuel cells are operated to maximize the production of electricity per unit fuel input (which may be referred to as the fuel efficiency of the fuel cell). This maximization may be based only on the fuel cell or on a fuel cell with other power generation systems. To increase electrical production and manage heat generation, the fuel utilization rate in the fuel cell is typically maintained at 70% to 75%.

U.S. Patent Publication No. 2011/0111315 describes a fuel cell system having significant hydrogen content in the anode inlet stream and a method of operating the system. The technique of '315 relates to providing sufficient fuel to the anode inlet so that sufficient fuel remains for the oxidation reaction when the fuel is near the anode outlet. To make the fuel suitable, the '315 provides fuel with high H 2 concentration. H 2 not used for the oxidation reaction is recycled to the anode for use in the next pass. On a one pass basis, the H 2 utilization may be between 10% and 30%. The '315 reference does not describe a significant modification in the anode, but instead mainly depends on the external modification.

U.S. Patent Publication No. 2005/0123810 describes a system and method for simultaneously generating hydrogen and electrical energy. The co-production system includes a fuel cell and a separation unit (which is configured to receive the anode exhaust gas and separate the hydrogen). A portion of the anode exhaust gas is also recycled to the anode inlet. The operating range given in the '810 publication appears to be based on solid oxide fuel cells. A molten carbonate fuel cell is described as an alternative.

U.S. Patent Publication No. 2003/0008183 describes a system and method for simultaneous production of hydrogen and electric power. Fuel cells are mentioned in the general form of chemical conversion devices for the conversion of hydrocarbon-type fuels to hydrogen. The fuel cell system also includes an external reformer and a high temperature fuel cell. An embodiment of a fuel cell system is described which has an electrical efficiency of about 45% and a compound production rate of about 25%, which shows a system simultaneous production efficiency of about 70%. '183 does not appear to describe the electrical efficiency of the fuel cell isolated from the system.

A paper by Journal of Fuel Cell Science and Technology [G. Manzolini et al., J. Fuel Cell Sci. and Tech. , Vol. 9, February 2012] describes a power generation system that combines a combustion generator and a molten carbonate fuel cell. Various arrangements and operating parameters of fuel cells are described. The combustion output from the combustion generator is used, in part, as input to the cathode of the fuel cell. One objective of the simulation in the Manzolini paper is to separate the CO 2 from the generator's exhaust using an MCFC. The simulation described in the Manzolini paper points to a maximum exit temperature of 660 ° C, and the inlet temperature should be sufficiently low due to the temperature increase across the fuel cell. In the base model, the electrical efficiency (ie, generated electricity / fuel input) of the MCFC fuel cell is 50%. The electrical efficiency for a test model optimized for CO 2 sequestration is also 50%.

Desideri et al . [ Intl. J. of Hydrogen Energy , Vol. 37, 2012] describes a method for modeling the performance of a power generation system using a fuel cell to separate CO 2 . The anode exhaust gas is recycled to the anode inlet and the cathode exhaust gas is recirculated to the cathode inlet to improve the performance of the fuel cell. The model parameter describes the MCFC electrical efficiency of 50.3%.

In one aspect, a method is provided for producing electricity by operating two or more turbines in series. The method may include introducing at least a portion of the exhaust gas from a turbine upstream of the process into a combustion chamber of a downstream turbine. In one embodiment, the exhaust gas from a turbine located in front of the process is introduced into the combustion chamber of the turbine, which is located behind the process, via the compression chamber of the turbine located behind the process. When two or more turbines are operated in series, the exhaust gas from the turbine located in front of the process can be a source of oxygen for combustion in the turbine (s) located behind the process. Running two or more turbines in series may produce a final exhaust stream having a higher CO 2 concentration and a lower O 2 concentration than that produced by the separate operation or parallel operation of the combustion turbine. In general, a higher CO 2 concentration can cause CO 2 to be more efficiently removed from the exhaust gas.

1 schematically shows an example of the configuration of a molten carbonate fuel cell and its associated reforming and separation stages.
Fig. 2 schematically shows another example of the configuration of the molten carbonate fuel cell and its accompanying reforming and separation stages.
Figure 3 schematically shows an example of the operation of a molten carbonate fuel cell.
Figure 4 schematically illustrates an example of a serial turbine system and a molten carbonate fuel cell for generating electricity based on combustion of carbon-based fuel.
5 schematically shows an example of a serial turbine system for generating electricity based on the combustion of carbon-based fuels.
Figure 6 shows the results of a simulation of a serial turbine system for generating electricity.
Figure 7 schematically shows an example of a single turbine system for generating electricity based on the combustion of carbon-based fuels.
Figure 8 shows the results of a simulation of a system for generating electricity.
Figure 9 schematically illustrates an example of a parallel turbine system for generating electricity based on the combustion of carbon-based fuels.
Figure 10 shows the results of a simulation of a system for generating electricity.
Figure 11 schematically illustrates an example of a combined cycle system with exhaust gas recirculation for generating electricity based on combustion of carbon-based fuel.
Figure 12 schematically illustrates an example of a combined cycle system with exhaust gas recirculation for generating electricity based on combustion of carbon-based fuel.
Figure 13 shows the results of a simulation of a system for generating electricity.

summary

In one aspect, a method is provided for producing electricity by operating two or more combustion turbines in series. The method includes introducing at least a portion of the exhaust gas from the turbine located in front of the process into the combustion chamber of the turbine located behind the process. In one embodiment, the exhaust gas from a turbine located in front of the process is introduced into the combustion chamber of the turbine, which is located behind the process, via the compression chamber of the turbine located behind the process. When two or more turbines are operated in series, the exhaust gas from the turbine located in front of the process can be a source of oxygen for combustion in the turbine (s) located behind the process. Running two or more turbines in series may produce a final exhaust stream having a higher CO 2 concentration and a lower O 2 concentration than that produced by the separate operation or parallel operation of the combustion turbine. In general, a higher CO 2 concentration can cause CO 2 to be more efficiently removed from the exhaust gas.

Series operation of combustion turbines

In various embodiments, two or more combustion turbines are operated in series to produce electricity. The series operation used herein involves introducing a significant portion of the CO 2 from the turbine's exhaust gas located in the process front into the combustion chamber of the turbine, which is located behind the process. The exhaust gas may be introduced into the combustion chamber of the turbine, which is located behind the process via the compression chamber of the turbine, which is located behind the process. In one aspect, the exhaust gas turbine of which is located in front of the process a number of CO 2 above about 50% of CO 2 is introduced into the combustion chamber of the turbine located behind the process. For example, the amount of CO 2 introduced into the combustion chamber of the turbine, which is located downstream from the exhaust of the turbine located in front of the process, may be greater than about 50% of the CO 2 in the exhaust of the turbine located in front of the process, , Greater than about 60%, greater than about 70%, greater than about 80%, greater than about 90%, greater than about 95%, greater than about 99%, greater than about 99.5% 100%.

In one embodiment, a number of O 2 of less than about 50% of O 2 in the exhaust gas of a turbine which is located in front of the process is introduced into the combustion chamber of the turbine located behind the process. For example, the amount of O 2 introduced into the combustion chamber of the turbine, which is located downstream of the process gas turbine exhaust gas, may be greater than about 50% of the O 2 in the exhaust gas of the turbine located in front of the process, , Greater than about 60%, greater than about 70%, greater than about 80%, greater than about 90%, greater than about 95%, greater than about 99%, greater than about 99.5%.

In one embodiment, oxygen may be added to the exhaust gas of the turbine located in the process prior to introduction of the exhaust gas into the combustion chamber of the turbine, which is located behind the process. By introducing air into the exhaust gas, oxygen can be added. To facilitate the desired turbine performance, air may be added, for example, to allow near-perfect combustion of the fuel introduced into the combustion chamber or reduction of NO x production. In one embodiment, the ratio of exhaust gas to air is from about 1: 1 to about 100: 1. For example, the ratio of exhaust gas to air may be about 10: 1, or about 25: 1, or about 50: 1, or about 75: 1, or about 90: In one embodiment, the ratio of the amount provided by the oxygen to the air provided to the combustion chamber located behind the process by the exhaust gas is from about 1: 1 to about 50: 1. For example, the ratio of the amount of oxygen provided to the combustion chamber located behind the process by the exhaust gas to the amount provided by the air is about 5: 1, or about 15: 1, or about 25: 1, 1, or about 45: 1. As such, the oxygen from the exhaust of the turbine located in front of the process may occupy more than about 50% of the oxygen supplied to the combustion chamber of the turbine, which is located behind the process. For example, oxygen from the exhaust of a turbine located in front of the process may be at least about 50%, or at least about 60%, or at least about 70%, or at least about 70% of the oxygen supplied to the combustion chamber of the turbine, , About 75% or more, or about 80% or more, or about 85% or more, or about 90% or more, or about 95% or more, or about 100% or less.

In one embodiment, the exhaust gas or flue gas produced by operating two or more combustion turbines in series may have a higher CO 2 concentration than that obtained by operation of a single combustion turbine or multiple combustion turbines operating in parallel. For example, the exhaust gas from the second turbine of the serial turbine may be at least about 6.0 mole percent, such as at least about 6.5 percent, or at least about 7.0 percent, or at least about 7.5 percent, or at least about 8 percent, or at least about 8.5 percent , Or about 9.0% or more, or about 9.5% or more, or about 10% or more, or about 11% or more, or about 12% or more, or about 15% or more CO 2 . This is in contrast to the CO 2 concentration in the exhaust gas from the (first) turbine located in the process front, which can be up to about 7.5 mol%, or up to about 6.5 mol%, or up to about 5.5 mol% . The increased CO 2 concentration can have several advantages including improved efficiency of some CO 2 removal processes using, for example, amine scrubbers. Higher CO 2 concentrations can reduce operating costs and lower capital expenditure per captured CO 2 mole. Additionally or alternatively, the amount of CO 2 in the exhaust gas from the turbine or first turbine located in the process front may be expressed as a ratio of the amount of CO 2 in the exhaust gas from the turbine or the second turbine, . In various embodiments, the process phase in front of the (first) the exhaust gas of CO (2) to position the process the back of the amount of the second exhaust gas in the amount of about 1.3 CO 2: 1, or at least about 1.4: 1 or higher , Or about 1.5: 1 or more, or about 1.6: 1 or more, or about 1.7: 1 or more, or about 1.8: 1 or more. For turbines operating similar types of combustion reactions (e.g., based on similar fuels), the ratio of CO 2 in the second exhaust gas to CO 2 in the first exhaust gas is typically less than 2.0: 1.

In one embodiment, the exhaust gas or flue gas produced by operating two or more combustion turbines in series may have a lower O 2 concentration than that obtained by operation of a single combustion turbine or a multiple combustion turbine operating in parallel. For example, the exhaust gas from the second turbine of the serial turbine may be less than about 8.0 mol%, such as less than about 7.0%, or less than about 6%, or less than about 5%, or less than about 4% , or it may have less than about 2.0%, or less than about 1.5%, or less than about 1%, or O 2 concentration of less than about 0.5%. The reduced oxygen stream can be an important input to the process using an inert gas (e. G., Maintaining pressure when forming an underground gas). In one embodiment, the desired O 2 level can be achieved by mixing rather fresh air with the turbine exhaust gas feed to the turbine behind the process. In one embodiment, the desired O 2 concentration can be obtained by mixing the exhaust gas of the turbine located behind the process and the air before supplying the exhaust gas to the process using O 2 depleted gas. The temperature of the additional air added to adjust the O 2 level can be selected to heat or cool the exhaust gas to a temperature suitable for the process behind the process.

In embodiments, water may optionally be removed from the exhaust gas of the turbine located in the process prior to introduction of the exhaust gas into the turbine located behind the process. Thus, in one embodiment, the exhaust gas introduced into the second turbine of the serial turbine is less than about 6.0 mol%, such as less than about 5.0%, or less than about 4%, or less than about 3%, or less than about 2% , or it may have less than about 1.0%, or less than about 0.5% H 2 O concentration.

FIG. 5 schematically illustrates an example of an integrated power generation system 500 including two combustion turbines operating in a cascade arrangement. Embodiments of the present invention are not limited to serial use of two turbines. In various embodiments, more than two turbines may be used in series, but for simplicity, the system 500 describes two turbines. In various embodiments, turbines of the same or different capacities may be arranged in series. For example, a turbine positioned in front of a process may have a larger capacity than a turbine located behind the process, or a turbine positioned in front of the process may have a smaller capacity than a turbine located behind the process, It can have the same capacity. 5, the exhaust gas 592 from the first turbine 501 is introduced into the second turbine 541 as a source of oxygen for combustion of the fuel.

The first turbine 501 may include a compressor 502, an axis 504, an expander 506 and a combustion zone 515. The oxygen source 511 (e.g., air and / or oxygen enriched air) may be compressed and heated in the compressor 502 before entering 513 the combustion zone 515. Fuel 512, such as CH 4, may be delivered to combustion zone 515. The fuel and the oxidant may react in zone 515 and optionally but preferably pass 516 through the expander 506 to rotate the shaft 504 connected to the generator to generate power have. Exhaust gases 592 may be used as inputs to the heat recovery and steam generator system 590 and this system may generate water vapor 594 for the steam turbine 595 to generate additional electricity, for example.

Stream 520 includes water that is removed from the exhaust gas of the first turbine before being introduced into the second turbine.

The second turbine 541 may include a compressor 542, an axis 544, an expander 546 and a combustion zone 545. The oxygen source 541 (e.g., air and / or oxygen enriched air) may be compressed and heated in the compressor 545 prior to entering 553 the combustion zone 545. Fuel 552, such as CH 4, may be delivered to combustion zone 545. The fuel and oxidant may react in zone 545 and optionally but preferably pass 555 through expander 546 to rotate shaft 544 connected to the generator to generate power have. Exhaust gases 558 may be used as inputs to the heat recovery and steam generator system 560 and this system may generate steam 562 for the steam turbine 595 that generates additional electricity, for example. Optionally, each HRSG 560, 590 can supply a feed to a separate steam turbine instead of the single steam turbine 595 shown.

Flue gas 570 may be introduced into a system (e.g., an amine scrubber) that removes CO 2 before it is released to the atmosphere. In one embodiment, flue gas 570 is introduced into the fuel cell cathode as shown in FIG.

As an example, a simulation was performed using a configuration similar to the system shown in Fig. The material balance results from the simulation are shown in Fig. We used General Electric's frame 9Fb.05 turbine as the basis for the simulation. The simulation results shown in FIG. 6 show the concentrations as pound mol / hour and mole fraction. For simplicity, the simulations are described in mole fractions.

The air 511 enters the compressor 502 substantially without CO 2 . The air 511 in the simulation contained about 20.8% oxygen. The fuel 512 supplied into the combustion chamber of the turbine in the simulation contained about 93% methane. During combustion, the simulated methane combined with O 2 to form CO 2 and water. Simulation was carried out so that methane was completely burned. The air to methane ratio in the simulation was about 24.6: 1.

The exhaust gas 592 of the first turbine in the simulation had a CO 2 concentration of about 4.2% and an O 2 concentration of about 11.7% when entering the HRSG 590. Therefore, the CO 2 concentration in the simulation increased from about 0% to 4.2%, and the O 2 concentration decreased from about 20.8% to about 11.7%. In the simulation, nitrogen passed through the combustion chamber, mostly unreacted, although a small amount of NO x gas was formed.

The HRSG 590 in the simulation cooled exhaust gas 592 from 1052 ℉ to 134 지만, but did not otherwise change the composition of the exhaust gas (hence the low temperature flue gas 514). Removal of water 520 reduced the concentration of water from about 8.7% to about 0.5%, resulting in exhaust gas 517. Although not simulated in this case, the presence of a duct burner in the HRSG 590 can further increase the concentration of CO 2 and further reduce the concentration of oxygen.

The exhaust gas 517 was combined with the additional air 540 to create an exhaust gas input 519 into the second turbine 541 in the simulation. The exhaust gas input 519 contains about 4.4% CO 2 and about 13.1% O 2 . The fuel 552 fed into the combustion chamber of the turbine in the simulation was about 93% methane. During combustion, methane combined with O 2 to form CO 2 and water. Simulations were run to ensure complete combustion of methane. In the simulation, the air to methane ratio was about 24.6: 1.

In the simulation, the exhaust gas 558 of the second turbine had a CO 2 concentration of about 8.3% and an O 2 concentration of about 4.4% as it entered the HRSG 560. Therefore, in the simulations, the CO 2 concentration increased from 4.4% to 8.32%, and the O 2 concentration decreased from about 13.1% to about 4.4%. In the simulation, nitrogen passed through the combustion chamber, mostly unreacted, though a small amount of NO x gas was formed. In the simulation, the HRSG 560 cooled the exhaust gas 558 from 1052 134 to 134 으나, but did not otherwise change the composition of the exhaust gas.

Based on the simulations, operating the two combustion turbines in series, it was possible to form a combustion exhaust stream having almost twice the CO 2 concentration of a single combustion turbine. Higher CO 2 concentrations may be beneficial to the operation of subsequent molten carbonate fuel cells. For example, molten carbonate fuel cells can typically be limited in removing CO 2 from the cathode stream because it is desirable to have at least about 0.3 mole percent, or at least about 0.5 mole percent, This is because, or about 0.8 mole%, or at least about 1 mole%, or at least about 1.2 mol% or more, or may require at least about 1.5 mol% CO 2 concentration. When the cathode inlet stream has an input concentration of about 4.5 mol%, reducing the CO 2 concentration to about 1.5 mol% corresponds to transporting about 66% of the cathode's CO 2 to the anode. In contrast, when the cathode inlet stream has an input concentration of about 7.5 mole percent, reducing the CO 2 concentration to about 1.5 mole percent corresponds to transporting about 80 percent of the cathode's CO 2 to the anode. Therefore, the use of exhaust gas from two cascaded combustion turbines can provide a significantly improved opportunity for CO 2 removal compared to removing CO 2 from two separate combustion exhaust streams.

Combustion Turbine Generator with Heat Recovery Water Vapor Generator

FIG. 7 schematically illustrates an example of an integrated power generation system 700 that includes a combustion turbine, a heat recovery and steam generator system, and a steam turbine. The system 700 shown in FIG. 7 can be referred to as a " 1x1 "system, which uses one combustion turbine generator to produce electricity, uses one HRSG to generate water vapor, Which means to drive the turbine generator. System 700 is included herein to illustrate exemplary characteristics of system exhaust from a single turbine. These features are described in more detail with reference to the simulation results shown in Fig.

In Figure 7, the turbine may include a compressor 702, an axis 704, an expander 706, and a combustion zone 715. The oxygen source 711 (e.g., air enriched with air and / or oxygen) can be compressed and heated in the compressor 702 before entering the combustion zone 715 (713). It is possible to transfer fuel 712 such as CH 4 to the combustion zone 715. The fuel and oxidant may react in zone 715 and optionally but preferably pass through expander 706 716 to rotate shaft 717 connected to the generator to generate power have. The exhaust gases 792 can be used as inputs to the heat recovery and steam generator system 790 and this system can generate water vapor 794 for the steam turbine 795 generating additional electricity, for example. Flue gas 796 exits the HRSG 790.

As an example, a simulation was performed using a configuration similar to the system shown in Fig. The results from the simulation are shown in FIG. As the basis of the simulation, we used a general electric frame 9Fb.05 turbine. The simulation results shown in FIG. 8 show the concentrations as pound mol / hour and mole fraction. For simplicity, the simulations are described in mole fractions.

In the simulation, the air 711 enters the compressor 702 substantially without CO 2 . Air 711 contained about 20.8% oxygen. In the simulation, the fuel supplied into the combustion chamber of the turbine was about 93% methane. During the combustion of this simulation, methane combined with O 2 to form CO 2 and water. Simulation was carried out so that methane was completely burned. In the simulation shown, the air to methane ratio was about 24.6: 1.

The exhaust gas 792 of the turbine in the simulation had a CO 2 concentration of about 4.2% and an O 2 concentration of about 11.7% when entering the HRSG. Therefore, the CO 2 concentration increased from about 0% to 4.2%, and the O 2 concentration decreased from about 20.8% to about 11.7%. Nitrogen, though a small amount of NO x gas was formed, was mostly passed through the combustion chamber unreacted in the simulation.

In the simulation, the HRSG cooled the exhaust gas from 1052 ° F to 134 ° F, but did not otherwise change the composition of the exhaust gas (which flows out as flue gas 796). In this simulation water is not removed, but in other arrangements the HRSG can condense and remove water from the exhaust gas. Although not simulated in this case, the presence of a duct burner in the HRSG can further increase the concentration of CO 2 and further reduce the concentration of oxygen.

Parallel operation of two combustion turbine generators

Figure 9 schematically illustrates an example of an integrated power generation system 900 including two combustion turbines operating in a parallel arrangement. The system 900 includes two combustion turbine generators that produce electricity. Both gas turbines may be the same size or model, or they may be different sizes or models. In practice, most installations can use the same set of CTGs. Each turbine has a dedicated HRSG for water vapor generation, but instead of driving two steam turbine generators, the steam is combined and only one steam turbine generator is used. The use of a single steam turbine increases reliability and makes maintenance schedule better, and the economics of standardization for steam turbines are achieved. This system can be referred to as a " 2x1 "configuration. The system 900 used herein is described as a 2 (p) x 1 operation, where "p" indicates parallel operation. System 900 is included herein as another basic case to illustrate exemplary characteristics of system exhaust gas from multiple turbines operating in parallel. These features are described in more detail with reference to the simulation results shown in FIG.

In Figure 9, the first turbine 901 may include a compressor 902, an axis 904, an expander 906, and a combustion zone 915. The oxygen source 911 (e.g., air and / or oxygen enriched air) can be compressed and heated in the compressor 902 before entering the combustion zone 915 (913). Fuel 912, such as CH 4, may be delivered to combustion zone 915. The fuel and oxidant may react in zone 915 and optionally but preferably pass 916 through expander 906 to rotate shaft 917 connected to the generator to generate power have. Exhaust gases 918 may be used as inputs to the heat recovery and steam generator system 920 and this system may generate water vapor 994 for the steam turbine 995 to generate additional electricity, for example. Exhaust gas 918 exits HSRG 920 as flue gas 997.

The second turbine 930 may include a compressor 932, an axis 934, an expander 936, and a combustion zone 945. The oxygen source 941 (e.g., air and / or oxygen enriched air) can be compressed and heated in the compressor 932 before entering 943 the combustion zone 945. Fuel 942, such as CH 4, may be delivered to combustion zone 945. The fuel and oxidant may react in zone 945 and optionally, but preferably pass (946) through expander 936 to rotate shaft 947 connected to the generator to generate power have. Exhaust gas 948 can be used as an input to heat recovery and steam generator system 950 and this system can generate water vapor 993 for a steam turbine 995 that generates additional electricity, for example. Optionally, each HRSG 990, 950 can supply a feed to a separate steam turbine instead of the single steam turbine 995 shown. Exhaust gas 948 exits HRSG 990 as flue gas 998.

As an example, a simulation was performed using a configuration similar to the system shown in Fig. The results from the simulation are shown in FIG. As the basis of the simulation, we used a general electric frame 9Fb.05 turbine. The simulation results shown in FIG. 10 show the concentrations as pound mol / hour and mole fraction. For simplicity, the simulations are described in mole fractions.

In the simulation, air 911, 941 enters compressors 902, 932 substantially without CO 2 . Air 911, 941 contained about 20.8% oxygen. In the simulation, the fuel supplied into the combustion chamber of the turbine contained about 93% methane. During combustion, methane combined with O 2 to form CO 2 and water. Simulation was carried out so that methane was completely burned. The air to methane ratio in the simulation was about 24.6: 1.

In the simulation, the exhaust gases 918, 948 of the turbine had a CO 2 concentration of about 4.2% and an O 2 concentration of about 11.7% when entering the HRSG. Therefore, the CO 2 concentration increased from about 0% to 4.2%, and the O 2 concentration decreased from about 20.8% to about 11.7%. Nitrogen passed through the combustion chamber with little NO x gas formation, but mostly unreacted in the simulation.

The HRSGs 920 and 950 in the simulations cooled the exhaust gas from 1052 ° F to 134 ° F, but did not otherwise change the composition of the exhaust gas. The HRSG did not remove water from the exhaust in this simulation, but in other arrangements the HSRG can condense and remove water from the exhaust gas. Although not simulated in this case, the presence of a duct burner in the HRSG can further increase the concentration of CO 2 and further reduce the concentration of oxygen. Since each turbine is simulated as having the same performance, the combined turbine exhaust gases appear to have exactly the same concentration as the individual exhaust gases produced by each turbine.

Exhaust gas recirculation with combustion turbine generators

11 and 12 schematically illustrate an example of an integrated power generation system 1100 that includes exhaust gas recirculation. In Figure 11, the turbine 1101 may include a compressor 1102, an axis 1104, an expander 1106, and a combustion zone 1115. An oxygen source 1111 (e.g., air and / or oxygen enriched air) may be mixed with anhydrous EGR recycle 1151 to form a combined oxygen source 1152. The mixed oxygen source 1152 may be compressed and heated in the compressor 1102 before entering the combustion zone 1115 (1113). It is possible to transfer the fuel 1112 such as CH 4 to the combustion zone 1115. The fuel and oxidant may react in zone 1115 and optionally but preferably pass 1116 through expander 1106 to rotate shaft 1117 connected to the generator to generate power have. Exhaust gases 1118 can be used as inputs to the heat recovery and steam generator system 1120 and this system can generate water vapor 1194 for the steam turbine 1195, for example, generating additional electricity. Flue gas 1156 may be fed into the atmosphere or into another process (not shown), such as an amine scrubber for CO 2 stripping. A portion of the HRSG 1190 exhaust gas is recirculated 1198 to the turbine 1101. In one embodiment, 35% of the exhaust gas is recycled. Stream 1150 may be water that falls off recycle loop 1198.

Figure 12 includes a number of components that are the same as those already described in Figure 11. However, instead of supplying substantially all of the exhaust gas of the turbine into the HRSG 1190, the exhaust gas is split before the HRSG 1190 and is instead introduced into the HRSG 1290, which cools the exhaust gases, The water can be removed before recirculating 1198 back to the first portion 1101.

As an example, a simulation was performed using a configuration similar to the system shown in Figs. 11 and 12. Fig. The results from the simulation are shown in Fig. As the basis of the simulation, we used a general electric frame 9Fb.05 turbine. The simulation results shown in Figure 13 show the concentrations as pound mol / hour and mole fraction. For simplicity, the simulations are described in mole fractions.

The air 1111 entered the simulator compressor 1102 substantially without CO 2 . Air 1111 contained about 20.8% oxygen. When combined with EEG recirculation in the simulations, the CO 2 concentration increased to about 2.4% and the oxygen decreased to about 16.7%. Water 1150, which has been removed, reduced the concentration of water in the raw turbine exhaust gas from about 8.7% to about 0.5% in the simulation.

In the simulation, the fuel supplied into the combustion chamber of the turbine was about 93% methane. During combustion, methane combined with O 2 to form CO 2 and water. Simulation was carried out so that methane was completely burned. In the simulation shown, the air to methane ratio was about 24.6: 1.

The exhaust gas 1192 of the turbine in the simulation had a CO 2 concentration of about 6.4% and an O 2 concentration of about 7.8% when entering the HRSG. Therefore, the CO 2 concentration increased from 2.4% to 6.4%, and the O 2 concentration decreased from about 16.7% to about 6.4%. Nitrogen, though a small amount of NO x gas was formed, was mostly passed through the combustion chamber unreacted in the simulation.

The HRSG 1190 in the simulation cooled the exhaust gas, but did not otherwise change the composition of the exhaust gas. In this simulation, the HRSG did not remove water from the exhaust, but in other arrangements the HRSG could condense and remove water from the exhaust gas. Although not simulated in this case, the presence of a duct burner in the HRSG can further increase the concentration of CO 2 and further reduce the concentration of oxygen.

CO 2  Comparison of elimination

In various embodiments, it may be desirable to remove CO 2 from the flue gas. Using an amine scrubber that can provide a convenient way to compare, CO 2 was typically separated from the flue gas (or combustion exhaust gas) from the combustion turbine. Instead of using an amine scrubber, the use of flue gas as at least a portion of the cathode inlet stream for the MCFC allows CO 2 to be transported from the cathode to the anode, where CO 2 at the anode is much higher in the anode exhaust gas 2 concentration. ≪ / RTI >

The increased CO 2 concentration achieved by operating the combustion turbines in series can typically increase the efficiency of the process for separating CO 2 . The simulation shown in Figures 5 to 13 shows how many total gases need to be treated by the amine scrubber in each arrangement, assuming 90% removal, and how much CO 2 is captured on a material basis Lt; / RTI > Table 1 shows the 2 (s) x 1 simulation described above with reference to Figures 5 and 6, the 1x1 simulation described above with reference to Figures 7 and 8, the 2 (p) simulation described above with reference to Figures 9 and 10, × 1 simulation, and CO 2 capture results of the 35% EGR simulation described above with reference to FIGS. 11-13. Table 1 shows the total exhaust gas generated with the CO 2 concentration of the exhaust gas. Table 1 also shows the amount of CO 2 removed at 90% capture ratio in the amine scrubber and the CO 2 capture ratio in each simulation.

[Table 1]

Comparison of CO 2 capture results

Figure pct00001

The simulation results in FIG. 6 show that at 90% capture rate one amine scrubber tower processes 211,319 lbmol / hour total gas flow and captures about 15,835 lb mole / hour CO 2 (or 13.3: 1 ratio) Show. This shows that it can capture a similar amount of CO 2 by handling significantly less total gas volume compared to the example where two separately operated combustion turbines are used. This may have an additional advantage for the MCFC because the 8.3 mole% exhaust CO 2 concentration shown in Figure 6 is sufficient to maintain the CO 2 concentration in the cathode sufficient for the operation of the MCFC in the preferred operating regime, This means that about 80% or more of the CO 2 in the exhaust gas can be transferred from the cathode stream to the anode stream in the MCFC.

The simulation results shown in FIG. 8 show that, in the basic case of a single turbine configuration, one amine scrubbing tower with 90% capture ratio processes 211,779 Ib mol / hr total gas flow and produces approximately 7,946 Ib mol / 2 (or a ratio of 26.7: 1). In view of the above, the exhaust gas from the simulated single turbine in FIG. 8 produced a CO 2 concentration of 4.2%.

The simulation results of FIG. 10 show that for the basic case of a parallel turbine configuration, one amine scrubbing tower with a capture ratio of 90% would handle a total gas flow of 423,559 Ib / hr and a CO 2 of about 15,892 Ib / (Or a ratio of 26.7: 1). In this regard, the exhaust gas from the simulated parallel turbine in FIG. 10 produced a CO 2 concentration of 4.2%.

The simulation results of FIG. 13 showing the basic case of running a turbine with 35% EGR show that at 90% capture rate, one amine scrubbing tower treats a total gas flow of 137,667 lb mole / hour and produces about 7,925 lb mole / 2 (or a ratio of 17.4: 1).

Thus, in one embodiment, when two turbines are operated in series, the ratio of the treated flue gas to the captured CO 2 is increased from about 26.7: 1 using a single turbine (or about 17.4: 1 using 35% EGR) It can be improved to about 13.3: 1. More generally, operating the two turbines in series results in a ratio of treated flue gas to captured CO 2 of about 15: 1 or more, or about 17: 1 or more, or about 20: 1 or more to about 14.5: 1 or less , Or about 14: 1 or less, or about 13.5: 1 or less. The improved ratio can lower the operating cost per 1 mole CO 2 trapped and reduce the expenditure of the work.

Fuel cell operation strategy for treating series-connected multiple turbine exhaust gases

As shown in FIG. 4, the exhaust gas from a series of combustion turbines operating in series may be introduced into the fuel cell cathode for further processing. The following is a description of the various strategies for operating molten carbonate fuel cells to treat CO 2 .

In addition to, and / or as an alternative to, the fuel cell operating strategy described herein, a molten carbonate fuel cell can be operated to select an amount for an oxidation amount to obtain a desired temperature ratio for the fuel cell . As used herein, the "temperature ratio" is defined as the heat generated by the exothermic reaction in the fuel cell assembly, divided by the endothermic heat demand of the reforming reaction occurring in the fuel cell assembly. Mathematically speaking, the temperature ratio (TH) = Q EX / Q EN . Where Q EX is the sum of the heat generated by the exothermic reaction and Q EN is the sum of the heat consumed by the endothermic reaction in the fuel cell. Note that the heat generated by the exothermic reaction corresponds to any heat in the cell due to the reforming reaction, the water gas-phone reaction, and the electrochemical reaction. The heat generated by the electrochemical reaction can be calculated based on the ideal electrochemical potential of the fuel cell reaction across the electrolyte minus the actual output voltage of the fuel cell. For example, it is believed that the ideal electrochemical potential of the reaction in the MCFC is about 1.04V based on the net reaction in the cell. During operation of the MCFC, the cell typically has an output voltage of less than 1.04 V due to various losses. For example, a typical output / operating voltage may be about 0.7V. The heat generated is equal to [the electrochemical potential of the cell (i.e., about 1.04 V) - the operating voltage]. For example, the heat generated by an electrochemical reaction in a cell is about 0.34 V when the output voltage is about 0.7V. Thus, in this scenario, the electrochemical reaction produces about 0.7 V of electricity and about 0.34 V of thermal energy. In this example, an electrical energy of about 0.7 V is not included as part of Q EX . In other words, thermal energy is not electrical energy.

For various convenient fuel cell structures, such as fuel cell stacks, individual fuel cells in a fuel cell stack, fuel cell stacks with integrated reforming stages, fuel cell stacks with integrated endothermic reaction stages, or combinations thereof, The ratio can be determined. The temperature ratio can be calculated for different unit devices in a fuel cell stack such as, for example, an assembly of fuel cells or a fuel cell stack. For example, a fuel cell stack with an integrated reforming stage and / or an integrated endothermic reaction stage element that is close enough to a single anode in a single fuel cell, an anode zone within the fuel cell stack, or an anode zone integrated in terms of heat integration, Lt; / RTI > can be calculated for the anode zone in the < / RTI > The term "anode zone" as used herein includes an anode in a fuel cell stack that shares a common inlet or outlet manifold.

In various aspects of the invention, the operation of the fuel cell can be characterized based on a temperature ratio. When the fuel cell is operated to have the desired temperature ratio, the molten carbonate fuel cell may have a temperature of about 1.5 or less, such as about 1.3 or less, or about 1.15 or less, or about 1.0 or less, or about 0.95 or less, Or about 0.85 or less, or about 0.80 or less, or about 0.75 or less. Additionally or alternatively, the temperature ratio can be about 0.25 or more, or about 0.35 or more, or about 0.45 or more, or about 0.50 or more. Additionally or alternatively, in some embodiments, the fuel cell may be operated to have a temperature rise between the anode inlet and the anode outlet of about 40 캜 or less, such as about 20 캜 or less, or about 10 캜 or less. Additionally or alternatively, the fuel cell may be operated to have an anode outlet temperature from about 10 [deg.] C lower than the anode inlet temperature to about 10 [deg.] C higher. Additionally or alternatively, an anode can be provided that is higher than the anode outlet temperature, such as greater than about 5 degrees Celsius, or greater than about 10 degrees Celsius, or greater than about 20 degrees Celsius, The fuel cell can be operated to have an inlet temperature. Additionally or alternatively, the anode outlet temperature can be about 100 캜 or lower, such as about 80 캜 or lower, or about 60 캜 or lower, or about 50 캜 or lower, or about 40 캜 or lower, or about 30 캜 or lower, Lt; RTI ID = 0.0 > anode < / RTI >

In addition to, and / or in lieu of, the fuel cell operating strategy described herein, a molten carbonate fuel cell (e. G., A fuel cell assembly) may reduce or minimize the amount of CO 2 leaving the fuel cell in the cathode exhaust stream While increasing the production of syngas (or hydrogen). Syngas may be a valuable input for various processes. In addition to having calorific values, syngas can be used as a raw material for forming other, more expensive products, such as, for example, using syngas as a feed for Fischer-Tropsch synthesis and / or methanol synthesis processes. One option to produce syngas may be to modify fuels such as hydrocarbons or hydrocarbons, such as methane or natural gas. In many types of industrial processes, syngas with H 2 to CO ratios close to (or even lower than) 2: 1 can often be desirable. If additional CO 2 is available, such as that generated at the anode, a H2 gas-to-CO ratio can be used to reduce the H 2 to CO ratio in the synthesis gas.

Of synthesis gas production with the molten carbonate, one way to characterize the overall advantages provided by incorporating the use of fuel cells is get out of sunryang for the cathode exhaust gas of the fuel cell of the synthesis gas exiting from the anode exhaust of the fuel cell CO 2 Can be based on a positive ratio. This characterization method measures the effect of generating power at low emissions and high efficiency (both in electrical and chemical terms). In this description, the net amount of the syngas in the anode exhaust gas is defined as the sum of the number of moles of H 2 present in the anode exhaust gas and the number of moles of CO, canceled by the amount of H 2 and CO present at the anode inlet . Since this ratio is based on the net amount of syngas in the anode exhaust gas, simply passing excess H 2 into the anode does not change the value of this ratio. However, H 2 and / or CO generated due to the modification in the internal reforming stage accompanied by the anode and / or anode can make this ratio higher. Hydrogen oxidized at the anode can lower this ratio. The water gas shift reaction is exchange H 2 for CO, independently of the ratio and that of the synthesis gas required to ultimately of H 2 dae CO, the combined number of moles of H 2 and CO, the total synthesis gas available in the anode exhaust gas . Then, the syngas content (H 2 + CO) of the anode exhaust gas can be compared with the CO 2 content of the cathode exhaust gas. This can provide an efficiency value of a type that can account for the amount of carbon capture. This can be expressed equally by the following equation:

Ratio of pure syngas to cathode CO 2 in the anode effluent = (H 2 + CO) net mole number of the anode / (CO 2 ) mole number of the cathode

In various embodiments, the ratio of the net moles of syngas in the anode exhaust gas to the mole number of CO 2 in the cathode exhaust gas may be at least about 2.0, such as at least about 3.0, or at least about 4.0, or at least about 5.0. In some embodiments, the ratio of the amount of CO 2 in the pure syngas to the cathode exhaust in the anode exhaust gas may be higher, such as about 10.0 or higher, or about 15.0 or higher, or about 20.0 or higher. A value of about 40.0 or less, for example, about 30.0 or less, or about 20.0 or less, can be obtained in addition or in a different manner. In embodiments where the amount of CO 2 at the cathode inlet is less than or equal to about 6.0 vol.%, Such as less than or equal to about 5.0 vol., A non-value greater than or equal to about 1.5 may be sufficient / practical. This molar ratio of the amount of CO 2 in the pure syngas to the cathode exhaust gas in the anode exhaust gas may be greater than the value of the fuel cell operated in the conventional manner.

In addition to, and / or as an alternative to, the fuel cell operating strategy described herein, a molten carbonate fuel cell (e.g., a fuel cell assembly) may have a CO 2 utilization value of, for example, greater than about 60% Such as the fuel consumption rate of the engine. In this type of construction, the molten carbonate fuel cell can be effective for carbon capture, because the CO 2 utilization can advantageously be high enough. Rather than attempting to maximize electrical efficiency, this type of configuration can improve or increase the total efficiency of the fuel cell based on the combined electrical and chemical efficiencies. The chemical efficiency may be based on the recovery of the hydrogen and / or syngas stream from the anode exhaust as an output for use in other processes. The electrical efficiency may be reduced compared to some conventional configurations, but it may be possible to use the chemical energy output in the anode exhaust gas to achieve the desired total efficiency of the fuel cell.

In various embodiments, the fuel utilization rate in the fuel cell anode may be about 50% or less, such as about 40% or less, or about 30% or less, or about 25% or less, or about 20% or less. In various embodiments, the fuel utilization rate in the fuel cell may be at least about 5%, such as at least about 10%, or at least about 15%, or at least about 20%, or at least about 25% Or about 30% or more. Additionally or alternatively, the CO 2 utilization may be at least about 60%, such as at least about 65%, or at least about 70%, or at least about 75%.

In addition to, and / or as an alternative to, the fuel cell operating strategy described herein, the molten carbonate fuel cell may be operated under conditions that increase or maximize syngas production, possibly impairing electricity generation and electrical efficiency . Instead of selecting operating conditions of the fuel cell to improve or maximize the electrical efficiency of the fuel cell, it is desirable to establish operating conditions, possibly including the amount of reformable fuel passed into the anode, to increase the chemical energy output of the fuel cell . These operating conditions can lead to lower electrical efficiency of the fuel cell. Despite the reduced electrical efficiency, optionally, but preferably, the operating conditions can increase the total efficiency of the fuel cell based on the sum of the electrical efficiency and the chemical efficiency of the fuel cell. The chemical energy content of the anode output can be increased by increasing the ratio of reformable fuel introduced into the anode to fuel actually oxidized electrochemically in the anode.

In some embodiments, the reformable fuel content of the reformable fuel in the feed stream delivered to the reforming stage followed by the anode and / or anode is at least about 50%, such as at least about 75% greater than the net amount of hydrogen reacting at the anode , Or greater than about 100%. Additionally or alternatively, the reformable hydrogen content of the fuel in the feed stream delivered to the reforming stages followed by the anode and / or anode may be at least about 50%, such as at least about 75%, or more than the net amount of reacting hydrogen at the anode, or Can be about 100% larger. In various embodiments, the ratio of the modifiable hydrogen content of the reformable fuel to the amount of hydrogen reacting at the anode is at least about 1.5: 1, or at least about 2.0: 1, or at least about 2.5: 1, : It can be more than 1. Alternatively or in addition, the ratio of the reformable fuel's hydrogen content in the fuel stream to the amount of hydrogen reacting at the anode may be up to about 20: 1, for example up to about 15: 1 or up to about 10: 1 . In one embodiment, it is believed that less than 100% of the reformable hydrogen content in the anode inlet stream can be converted to hydrogen. For example, at least about 80%, such as at least about 85%, or at least about 90%, of the reformable hydrogen content in the anode inlet stream can be converted to hydrogen in the anode and / or its associated reforming stage (s) have. Additionally or alternatively, the amount of reformable fuel delivered to the anode can be characterized based on the LHV of the reformable fuel relative to the lower calorific value (LHV) of the hydrogen oxidized at the anode. This can be referred to as a fuelable excess fuel ratio. In various embodiments, the fuelable excess fuel ratio may be greater than or equal to about 2.0, such as greater than or equal to about 2.5, or greater than or equal to about 3.0, or greater than or equal to about 4.0. Additionally or alternatively, the fuelable excess fuel ratio can be about 25.0 or less, such as about 20.0 or less, or about 15.0 or less, or about 10.0 or less.

In addition to, and / or as an alternative to, the fuel cell operating strategy described herein, molten carbonate fuel cells (e.g., fuel cell assemblies) can also be used to improve or optimize the combined electrical and chemical efficiencies of fuel cells Lt; / RTI > Instead of selecting conventional conditions to maximize the electrical efficiency of the fuel cell, the operating conditions may enable the production of excess syngas and / or hydrogen in the anode exhaust of the fuel cell. Syngas and / or hydrogen may be used for a variety of applications including chemical synthesis and collection of hydrogen for use as "clean" fuel. In an embodiment of the present invention, it is possible to achieve a high overall efficiency by reducing the electrical efficiency, which is the chemical efficiency based on the chemical energy value of the syngas and / or hydrogen produced for the energy value of the fuel input of the fuel cell .

In some embodiments, the operation of the fuel cell can be characterized based on electrical efficiency. When the fuel cell is operated to have a low electrical efficiency (EE), the molten carbonate fuel cell may be less than about 40%, such as less than about 35% EE, less than about 30% EE, less than about 25% , About 15% EE or less, or about 10% EE or less. Additionally or alternatively, the EE may be at least about 5%, or at least about 10%, or at least about 15%, or at least about 20%. Additionally or alternatively, the operation of the fuel cell may be characterized based on total fuel cell efficiency (TFCE) such as the combined electrical and chemical efficiencies of the fuel cell (s). When the fuel cell is operated to have a high total fuel cell efficiency, the molten carbonate fuel cell may be operated at a temperature of at least about 55%, such as at least about 60%, or at least about 65%, or at least about 70%, or at least about 75% Or about 80% or more, or about 85% or more TFCE (and / or combined electrical and chemical efficiency). For total fuel cell efficiency and / or combined electrical efficiency and chemical efficiency, any additional electricity generated from the use of excess heat generated by the fuel cell may be excluded from the efficiency calculation.

In various embodiments of the invention, the operation of the fuel cell may be characterized based on a desired electrical efficiency of about 40% or less and a desired total fuel cell efficiency of about 55% or more. When the fuel cell is operated to have the desired electrical efficiency and the desired total fuel cell efficiency, the molten carbonate fuel cell has an electrical efficiency of about 40% or less and a TFCE of about 55% or greater, for example, about 35% About 60% or more TFCE, about 30% or less EE and about 65% or more TFCE, about 25% or less EE and about 70% or more TFCE, about 20% or less EE, about 75% or more TFCE, And about 80% or more TFCE, or about 10% or less EE and about 85% or more TFCE.

In addition to, and / or as an alternative to the fuel cell operating strategy described herein, a molten carbonate fuel cell (e. G., A fuel cell assembly) can be operated under conditions that can increase the power density. The power density of the fuel cell corresponds to the actual operating voltage V A multiplied by the current density I. In the case of a molten carbonate fuel cell operated at voltage V A , the fuel cell may also tend to generate waste heat, and the waste heat is based on the difference between V A of the fuel cell providing the current density I and the ideal voltage V 0 Is defined as (V 0 -V A ) * I. A part of the waste heat can be consumed by reforming the reformable fuel in the anode of the fuel cell. The remaining portion of the waste heat is absorbed by the surrounding fuel cell structure and the gas flow, so that a temperature difference across the fuel cell can be generated. Under conventional operating conditions, the power density of the fuel cell can be limited based on the amount of waste heat that the fuel cell can tolerate without sacrificing the integrity of the fuel cell.

In various embodiments, the amount of waste heat that a fuel cell can tolerate can be increased by performing an endothermic reaction in an effective amount in the fuel cell. One example of an endothermic reaction involves steam reforming of the reformable fuel in the fuel cell anode and / or its subsequent reforming stage, such as an integrated reforming stage of the fuel cell stack. By providing additional reformable fuel to the anode (or integrated / subsequent reforming stage) of the fuel cell, further reforming can be performed such that additional waste heat can be consumed. This can reduce the amount of temperature difference across the fuel cell, allowing the fuel cell to operate under operating conditions with larger amounts of waste heat. Loss of electrical efficiency can be offset by the formation of additional product streams such as syngas and / or H 2 that can be used for a variety of purposes, including further development, further extending the power range of the system.

In various embodiments, the amount of waste heat (V 0 -V A ) * I generated by the fuel cell as defined above is greater than or equal to about 30 mW / cm 2 , such as greater than or equal to about 40 mW / cm 2 , 2, or at least about 60mW / cm 2 or more, or from about 70mW / cm 2 or more, or from about 80mW / cm 2 or more, or from about 100mW / cm 2 or more, or from about 120mW / cm 2 or more, or from about 140mW / cm 2 or more , or from about 160mW / cm 2 may be at least, or about 180mW / cm 2. Alternatively an additional, or is, the fuel cell is less than 2, the amount 250mW / cm of the waste heat generated by, for example, from about 200mW / cm 2 or less, or from about 180mW / cm 2 or less, or from about 165mW / cm 2 or less, or from about 150mW / cm 2 < / RTI >

Although the amount of waste heat generated may be relatively high, such waste heat may not necessarily indicate that the fuel cell operates with poor efficiency. Instead, waste heat can be generated by operating the fuel cell at a high power density. Some of the improvements in the power density of the fuel cell may include operating the fuel cell at a sufficiently high current density. In various embodiments, the current density generated by the fuel cell is about 150mA / cm 2 or more, for example, about 160mA / cm 2, or at least about 170mA / cm 2, or at least about 180mA / cm 2, or at least about 190mA / cm 2, or at least about 200mA / cm 2, or at least about 225mA / cm 2, or at least about 250mA / cm 2 or more can. In addition or alternatively, the current density generated by the fuel cell is about 500mA / cm 2 or less, for example, 450mA / cm 2 or less, or 400mA / cm 2 or less, or 350mA / cm 2 or less, or 300mA / cm 2 or less .

In various embodiments, an effective amount of an endothermic reaction (e. G., A reforming reaction) may be performed to operate the fuel cell while increasing power generation and increasing waste heat generation. Alternatively, waste heat can be utilized by placing a "plate" or stage into the fuel cell array to be in thermal communication (but not fluid communication) using another endothermic reaction not related to anode operation. An effective amount of an endothermic reaction can be performed in a subsequent reforming stage, an integrated reforming stage, an integrated stacking element for performing an endothermic reaction, or a combination thereof. An effective amount of the endothermic reaction may be achieved by increasing the temperature increase from the fuel cell inlet to the fuel cell outlet to about 100 캜 or less, such as about 90 캜 or less, or about 80 캜 or less, or about 70 캜 or less, About 50 DEG C or less, or about 40 DEG C or less, or about 30 DEG C or less. Additionally or alternatively, an effective amount of endothermic reaction may be conducted at a temperature of about 100 占 폚 or lower, such as about 90 占 폚 or lower, or about 80 占 폚 or lower, or about 70 占 폚 or lower, or about 60 占 폚 or lower, 40 DEG C or less, or about 30 DEG C or less, or about 20 DEG C or less, or about 10 DEG C or less, to the fuel cell outlet. When the effective amount of the endothermic reaction exceeds the waste heat generated, a temperature decrease may occur from the fuel cell inlet to the fuel cell outlet. Additionally or alternatively, it consumes at least about 40% of the waste heat generated by the fuel cell, for example at least about 50% of the waste heat, or at least about 60% of the waste heat, or at least about 75% (S) (e. G., A combination of reforming and other endothermic reactions). ≪ / RTI > Additionally or alternatively, the endothermic reaction (s) may consume less than about 95% of the waste heat, such as less than about 90% of the waste heat, or less than about 85% of the waste heat.

In addition to, and / or as an alternative to, the fuel cell operating strategy described herein, a molten carbonate fuel cell (e.g., a fuel cell assembly) can be operated under conditions corresponding to a reduced operating voltage and a lower fuel utilization rate . In various embodiments, the fuel cell may be operated at a voltage V A less than about 0.7 volts, for example less than about 0.68 volts, less than about 0.67 volts, less than about 0.66 volts, or about 0.65 volts. Additionally or alternatively, the fuel cell may be operated at a voltage V A greater than or equal to about 0.60, such as greater than or equal to about 0.61, greater than or equal to about 0.62, or greater than or equal to about 0.63. In doing so, the energy that leaves the fuel cell as electrical energy at a high voltage can remain as heat in the cell as the voltage is lowered. This additional heat can increase the conversion of synthesis gas of CH 4, for example by making up more of the endothermic reaction.

Justice

Combustion Turbines: In this application, a combustion turbine is defined as a turbine in which a combustion product (e.g., hot pressurized steam) is used directly to rotate the turbine. This definition excludes steam turbines in which the combustion products produce separate fluids, such as water, to produce water vapor (which is used directly to rotate the turbine).

Syngas. In this definition, synthesis gas is defined as a mixture of any ratio of the H 2 and CO. Optionally, H 2 O and / or CO 2 may be present in the syngas. Optionally, an inert compound (e.g., nitrogen) and the remaining reformable fuel compound may be present in the synthesis gas. When the components other than H 2 and CO are present in the syngas, the combined volume percentages of H 2 and CO in the syngas are at least 25 vol%, such as at least 40 vol%, or at least 50 vol% Or 60% by volume or more. Alternatively, or alternatively, the combined volume percentage of H 2 and CO in the syngas may be up to 100 vol%, for example up to 95 vol%, or up to 90 vol%.

Modifiable fuel: A fuel that can be reformed is defined as a fuel containing carbon-hydrogen bonds that can be reformed to generate H 2 . As is the case with other hydrocarbonaceous compounds (such as alcohols), hydrocarbons are an example of a fuel that can be reformed. CO and H 2 O may participate in water gas-phos- phonation reactions to form hydrogen, but CO is not considered a reformable fuel under this definition.

Modifiable hydrogen content: The reformable hydrogen content of the fuel is defined as the number of H 2 molecules that can be derived from the fuel by maximizing H 2 production by allowing the water gas conversion to be completed after reforming the fuel. Note that H 2 by this definition has a reformable hydrogen content of 1, but H 2 itself is not defined herein as a reformable fuel. Similarly, CO has a reformable hydrogen content of 1. CO is not strictly modifiable, but exchanges CO with H 2 by allowing the water gas-phonetic reaction to be completed. As an example of the reformable hydrogen content of the reformable fuel, the reformable hydrogen content of methane is four H 2 molecules while the reformable hydrogen content of ethane is seven H 2 molecules. More generally, if the fuel has a composition of C x H y O z , then the reformable hydrogen content of the fuel at 100% reforming and water gas switching is n (maximal reforming H 2 ) = 2x + y / 2-z. Based on this definition, the fuel utilization rate in the cell can be expressed as n (H 2 O 2 ) / n (maximum reforming H 2 ). Of course, the reformable hydrogen content of the mixture of components can be determined based on the reformable hydrogen content of the individual components. Modifiable hydrogen content of compounds containing other heteroatoms such as oxygen, sulfur or nitrogen can also be calculated in a similar manner.

Oxidation reaction: In this discussion, the oxidation reaction in the anode of the fuel cell is defined as a reaction to oxidize the H 2 by the reaction of the CO 3 2- Sikkim corresponding to generate H 2 O and CO 2. Note that the reforming reaction in the anode in which a compound containing carbon-hydrogen bonds is converted to H 2 and CO or CO 2 is excluded from this definition of the oxidation reaction at the anode. The water gas-phonetic reaction is similarly excluded from this definition of the oxidation reaction. Citation of the combustion reaction refers to the reaction in which a compound containing H 2 or carbon-hydrogen bond (s) reacts with O 2 in a non-electrochemical burner, such as the combustion zone of a generator that draws power from combustion, to form H 2 O and carbon dioxide It is also noted that it is defined as a quotation of.

Aspects of the present invention can adjust the anode fuel parameters to achieve the desired operating range of the fuel cell. The anode fuel parameters may be characterized directly with respect to other fuel cell processes in the form of and / or one or more ratios. For example, the anode fuel parameters can be controlled to obtain one or more ratios including fuel utilization, fuel cell heat utilization, fuel surplus ratio, reformable fuel surplus ratio, reformable hydrogen content fuel ratio, and combinations thereof.

Fuel Utilization: The fuel utilization rate is an option that characterizes the operation of the anode based on the amount of oxidized fuel relative to the reformable hydrogen content of the feed stream that can be used to define the fuel utilization of the fuel cell. In this discussion, the "fuel utilization rate" is defined as the ratio of the amount of hydrogen oxidized at the anode to the reformable hydrogen content of the anode input (including any subsequent reforming stage) for power generation (as described above). The reformable hydrogen content is defined above as the number of H 2 molecules that can be derived from the fuel by maximizing H 2 production by allowing the water gas conversion to be completed after reforming the fuel. For example, each methane that is introduced into the anode and exposed to the steam reforming process produces four H 2 molecules at maximum production. (Depending on the modification and / or the anode conditions, modified products may correspond to a water gas non-phone product, this time is one or more H 2 molecule is present instead in the form of CO molecules.) Thus, the methane is four H 2 Is defined as having a reformable hydrogen content of the molecule. As another example, under this definition ethane has a seven-modified available hydrogen content H 2 molecules.

The rate of utilization of the fuel at the anode is determined by the ratio of the lower calorific value of hydrogen oxidized at the anode due to the fuel cell anode reaction to the lower heating value of all the fuel delivered to the reforming stage accompanied by the anode and / By defining the heating value utilization rate based on the heating value. As used herein, the "fuel cell calorific value utilization rate" can be calculated using the flow rate and the low calorific value (LHV) of the fuel component entering and leaving the fuel cell anode. Thus, the fuel cell calorific utilization rate can be calculated as (LHV (anocd_in) -LHV (anode_out)) / LHV (anode_in), where LHV (anode_in) and LHV (anode_out) are the anode inlet and outlet streams, Refers to the LHV of a component (e.g., H 2 , CH 4, and / or CO). In this definition, the LHV of the stream or stream can be calculated as the sum of the values of each fuel component in the input and / or output stream. The contribution of each fuel component to the sum may correspond to the flow rate (e.g., mol / hour) of the fuel component multiplied by the LHV of the fuel component (e.g., J / mol).

Low calorific value: The low calorific value is defined as the enthalpy in which the fuel component is burned into the completely oxidized products of the gas phase (ie, gaseous CO 2 and H 2 O products). For example, any CO 2 present in the anode input stream does not contribute to the fuel content of the anode charge, since CO 2 is already fully oxidized. In this definition, the amount of oxidation generated at the anode due to the anode fuel cell reaction is defined as the H 2 oxidation at the anode as part of the electrochemical reaction at the anode, as defined above.

The only fuel for anode input flow in a special case of H 2, only the reaction containing the fuel component that may occur in the anode is noticed indicating the transition to H 2 O of H 2. In this special case, the fuel utilization is simplified as feed rate of the / H 2 (-H 2 feed rate calculated rate of the H 2). In this case, H 2 is the only fuel component, and so H 2 LHV falls out of the equation. If a more general, the anode feed may for example contain a CH 4, H 2 and CO in various amounts. Since these materials are typically present in different amounts at the anode outlet, the sum described above may be necessary to determine the fuel utilization rate.

In addition to the fuel utilization rate, or in addition to the fuel utilization rate, the utilization rate of other reactants of the fuel cell can be characterized. For example, the operation of the fuel cell may be further or alternatively characterized in terms of "CO 2 utilization" and / or "oxidant" utilization. CO 2 availability and / or oxidant utilization rate values may also be defined in a similar manner.

Fuel excess ratio: Another method of characterizing the reaction in a molten carbonate fuel cell is to determine the amount of hydrogen that is to be oxidized in the anode due to the fuel cell anode reaction, the amount of all the fuel that is delivered to the anode and / The utilization rate is limited based on the ratio of the low calorific value of the fuel. This amount is referred to as fuel surplus. Thereby, the fuel excess ratio can be calculated as (LHV (anode_in) / (LHV (anode_in) -LHV (anode_out), where LHV (anode_in) and LHV (anode_out) are the anode inlet and outlet streams, Refers to the LHV of a component (e.g., H 2 , CH 4, and / or CO). In various embodiments of the present invention, the molten carbonate fuel cell has an LHV of at least about 1.0, such as at least about 1.5, About 2.5 or more, or about 3.0 or more, or about 4.0 or more. In addition, or alternatively, the fuel excess ratio can be about 25.0 or less.

It is noted that not all of the reformable fuel in the input stream of the anode can be reformed. Preferably, at least about 90%, such as at least about 95%, or at least about 98%, of the reformable fuel in the feed stream to the anode (and / or the subsequent reforming stage) can be reformed before leaving the anode. In some other embodiments, the amount of reformable fuel that is modified may be from about 75% to about 90%, such as about 80% or more.

The above definition of an excess fuel ratio provides a method for characterizing the amount of reforming done in the reforming stage (s) followed by the anode and / or the fuel cell, relative to the amount of fuel consumed in the fuel cell anode for power generation .

Optionally, the excess fuel ratio may be changed due to the situation where the fuel is recycled from the anode output to the anode input. When fuel (e. G., H 2 , CO and / or unmodified or partially reformed hydrocarbons) is recycled from the anode output to the anode input, such recycled fuel components can be converted to reformable or reformable fuels Of the < / RTI > Instead, these recycled fuel components only represent a demand to reduce the fuel utilization in the fuel cell.

Modifiable fuel surplus ratio: Calculating the reformable fuel surplus ratio is one option to account for this recycled fuel composition and narrows the definition of excess fuel so that only the LHV of the reformable fuel is included in the input stream to the anode . As used herein, "reformable fuel excess ratio" is defined as the lower calorific value of the reformable fuel delivered to the reforming stage followed by the anode and / or anode, relative to the lower calorific value of hydrogen oxidized at the anode due to the fuel cell anode reaction. do. Under the definition of a reformable fuel excess ratio, any H 2 or CO LHV in the anode charge is excluded. The LHV of such a reformable fuel can be measured by characterizing the actual composition entering the fuel cell anode, so there is no need to distinguish between recycled and new components. Although some unmodified or partially reformed fuel can also be recycled, in most embodiments, the majority of the fuel recycled to the anode may correspond to a modified product such as H 2 or CO. Mathematically speaking, the reformable fuel excess ratio (R RFS ) = LHV RF / LHV OH , where LHV RF is the lower calorific value (LHV) of the reformable fuel and LHV OH is the lower calorific value LHV). The LHV of the oxidized hydrogen at the anode can be calculated (e.g., LHV (anode_in) -LHV (anode_out)] by subtracting the LHV of the anode exit stream from the LHV of the anode inlet stream. In various embodiments of the present invention, the molten carbonate fuel cell has a melting point of at least about 0.25, such as at least about 0.5, or at least about 1.0, or at least about 1.5, or at least about 2.0, or at least about 2.5, or at least about 3.0, Can be operated to have a reformable fuel excess ratio. Additionally or alternatively, the fuelable excess fuel ratio can be about 25.0 or less. Note that this narrower definition based on the amount of reformable fuel delivered to the anode relative to the amount of oxidation at the anode can distinguish between two types of fuel cell operating methods with lower fuel utilization. Some fuel cells achieve a low fuel utilization rate by recirculating a significant amount of anode output back to the anode input. This recycle may allow any of the anode inputs to be used again as an input to the anode. This can reduce the amount of reforming because at least a portion of the unused fuel is recycled for use in subsequent passes even though the fuel utilization rate is low once passed through the fuel cell. Therefore, a fuel cell having various fuel utilization values may have the same ratio of hydrogen oxidized in the reformable fuel to anode reaction delivered to the anode reforming stage (s). In order to change the ratio of the amount of oxidation at the anode to the amount of reformable fuel delivered to the anode reforming stage, it is necessary to identify the anode feed having a natural content of the fuel that can not be reformed, There is a need to reclaim for, or both.

Modifiable hydrogen excess ratio: Another option to characterize the operation of a fuel cell is based on a "reformable hydrogen excess ratio ". The above-defined modifiable fuel excess ratio is defined based on the calorific value of the reformable fuel component. The modifiable hydrogen excess ratio is defined as the modifiable hydrogen content of the reformable fuel that is delivered to the reforming stage followed by the anode and / or anode for the hydrogen reacting at the anode due to the fuel cell anode reaction. As such, the "reformable hydrogen excess ratio" can be calculated as (RFC (reformable_anode_in) / (RFC (reformable_anode_in) -RFC (anode_out)) where the reformable_anode_in is the reforming of the anode inlet stream, Refers to the possible hydrogen content, while RFC (anode_out) refers to the reformable hydrogen content of the anode inlet and outlet streams or the hydrotreating fuel components (e.g., H 2 , CH 4 and / or CO) Mol / hour, etc. An example of a method of operating a fuel cell with a large ratio of reformable fuel to anode amount of oxidation delivered to the anode reforming stage (s) is a balance of heat generation and consumption in the fuel cell The reforming of the reformable fuel to form H 2 and CO is an endothermic reaction. The solution can resist the endothermic reaction, which generates a correspondingly large amount of heat (approximately) to the difference between the amount of heat generated by the anode oxidation reaction and the carbonate formation reaction and the energy exiting the fuel cell in the form of current Excess heat per mole of hydrogen contained in the anode oxidation reaction / carbonate production reaction may be larger than the heat absorbed by the reforming to generate 1 mole of hydrogen. As a result, the fuel cell Instead of this type of conventional operation, it is possible to increase the amount of fuel to be reformed in the reforming stage that accompanies the anode. For example, it may be caused by an exothermic fuel cell reaction (Almost) the heat consumed by the reforming, or even the heat consumed by the reforming In excess of the excess heat generated by the charges oxide to be a temperature drop across the fuel cell occurs, it is possible to modify the additional fuel, which may produce a considerable excess of hydrogen compared to the amount necessary for power generation. As an example, the anode inlet of the fuel cell or the feed to the subsequent reforming stage may be substantially composed of a reformable fuel, such as a substantially pure methane feed. During operation in a conventional manner for power generation using such fuel, the molten carbonate fuel cell can be operated at a fuel utilization rate of about 75%. This means that about 75% (or ¾) of the fuel delivered to the anode is used to form hydrogen, which reacts with the carbonate ion at the anode to form H 2 O and CO 2 . In conventional operation, the remaining about 25% of the fuel content is reformed into H 2 in the fuel cell (or may pass through the fuel cell without reacting in the case of any CO or H 2 in the fuel) It is possible to provide heat to the cathode inlet to the fuel cell by burning outside the cell to form H 2 O and CO 2 . In this situation, the reformable hydrogen excess ratio may be 4 / (4-1) = 4/3.

Electrical Efficiency: As used herein, the term "electrical efficiency"("EE") is defined as the electrochemical power produced by a fuel cell divided by the low calorific value ("LHV") ratio of the fuel input to the fuel cell. The fuel input to the fuel cell includes both the fuel delivered to the anode, as well as any fuel used to maintain the temperature of the fuel cell (e.g., fuel delivered to the fuel cell). In this description, the power generated by the fuel can be described in terms of the LHV (el) fuel rate.

Electrochemical Power: As used herein, the term "electrochemical power" or LHV (el) is the power generated by a circuit in a fuel cell that connects a cathode to an anode and transports carbonate ions across the electrolyte of the fuel cell. The electrochemical power excludes the power generated or consumed by equipment located in front of or behind the fuel cell. For example, the current generated from heat in the fuel cell exhaust stream is not considered part of the electrochemical power. Similarly, the power generated by a gas turbine or other device located in front of the fuel cell is not part of the generated electrochemical power. "Electrochemical power" does not take into account the power consumed during operation of the fuel cell, or take into account any losses caused by the conversion of the direct current to alternating current. In other words, the power supplied to the fuel cell operation or otherwise used to operate the fuel cell is not subtracted from the DC voltage generated by the fuel cell. The power density used herein is the current density multiplied by the voltage. As used herein, the term total fuel cell power is the power density multiplied by the fuel cell area.

Fuel Input : The term "anode fuel input", as used herein, referred to as LHV (anode_in), is the amount of fuel in the anode inlet stream. The term "fuel input " referred to as LHV (in) is the total amount of fuel delivered to the fuel cell, including both the amount of fuel in the anode inlet stream and the amount of fuel used to maintain the temperature of the fuel cell. The fuel may include both a reformable fuel and a non-reformable fuel based on the definition of the reformable fuel provided herein. Fuel inputs are not the same as fuel utilization.

Total Fuel Cell Efficiency: The term "total fuel cell efficiency"("TFCE") as used herein refers to the ratio of the electrochemical power generated by the fuel cell to the LHV of the syngas produced by the fuel cell to the fuel input LHV < / RTI > In other words, TFCE = (LHV (el) + LHV (sg net)) / LHV (anode_in) where LHV (anode_in) is the fuel component (eg, H 2 , CH 4 and / or CO) and LHV (sg net) indicates the rate at which the synthesis gas (H 2 , CO) is produced at the anode, which is the difference between the synthesis gas input to the anode and the synthesis gas output from the anode. LHV (el) describes the electrochemical evolution of fuel cells. Total fuel cell efficiency excludes heat generated by the fuel cell, which is advantageously used outside the fuel cell. In operation, the heat generated by the fuel cell can be advantageously used by devices located behind the process. For example, heat can be used to generate additional electricity or to heat water. When used separately from the fuel cell, these applications are not part of the total fuel cell efficiency when this term is used herein. Total fuel cell efficiency only applies to fuel cell operation and does not include power generation, or consumption before or after the fuel cell.

Chemical Efficiency: As used herein, the term "chemical efficiency" is defined as the LHV (sg out) of H 2 and CO in the anode exhaust of a fuel cell divided by the fuel input or LHV (in).

Electricity efficiency and total system efficiency also do not take into account the efficiency of processes located either before or after the process. For example, it may be advantageous to use the turbine exhaust gas as the source of CO 2 of the fuel cell cathode. In this arrangement, the efficiency of the turbine is not considered to be part of the calculation of electric efficiency or total fuel cell efficiency. Similarly, the output of the fuel cell can be recycled as an input to the fuel cell. Recirculation loops are not considered when calculating the electrical efficiency or the total fuel cell efficiency in a one-pass mode.

Synthetic gas produced: The term "produced syngas" as used herein is the difference between a syngas input to the anode and a synthesis gas output from the anode. The syngas can be used, at least in part, as an anode charge or fuel. For example, the system may include an anode recycle loop that returns syngas from the anode exhaust gas to the anode inlet (where syngas is supplemented with natural gas or other suitable fuel). Wherein the LHV (sg in) and LHV (sg out) are the LHV of the synthesis gas at the anode inlet and the LHV of the anode at the anode inlet, respectively, Gt; LHV < / RTI > of the syngas in the outlet stream or flow. It is noted that at least some of the syngas produced by the reforming reaction in the anode can typically be used in the anode to generate electricity. Hydrogen used to generate electricity is not included in the definition of "produced syngas" since it does not exit the anode. As used herein, the term "syngas ratio" is the LHV, or LHV (sg net) / LHV (anode in), of the produced pure syngas divided by the LHV of the fuel input to the anode. The molar flow rate of the syngas and fuel can be used instead of LHV to express the resulting syngas based on mole-based syngas ratios and moles.

Water vapor to carbon ratio (S / C): The steam to carbon ratio (S / C) used herein is the molar ratio of water vapor in flow to reformable carbon in flow. Carbon in the form of CO and CO 2 is not included in the reformable carbon in this definition. The water vapor to carbon ratio can be measured and / or controlled at different points in the system. For example, the composition of the anode inlet water vapor can be manipulated to obtain S / C suitable for reforming at the anode. S / C can be given as the molar flow rate of H 2 O divided by the product of the molar flux of fuel and the number of carbon atoms in the fuel (for example, one for methane). Therefore, in the S / C = f H20 / ( f CH4 × # C) and, here, f H2O is the molar flow rate of water, f CH4 is the mole flow rate of methane (or other fuel), #C is the carbon in the fuel Number.

EGR ratio: An aspect of the present invention can use a turbine in cooperation with a fuel cell. The integrated fuel cell and turbine system may include exhaust gas recirculation ("EGR"). In the EGR system, at least a part of the exhaust gas generated by the turbine can be sent to the heat recovery generator. Other parts of the exhaust gas can be sent to the fuel cell. The EGR ratio describes the amount of exhaust gas sent to the fuel cell versus the exhaust gas to the fuel cell or heat recovery generator. As used herein, the "EGR ratio" is the flow rate of the fuel cell-related portion of the exhaust gas divided by the combined flow rate of the fuel cell related portion and the recovery related portion (which is sent to the heat recovery generator).

In various aspects of the present invention, while also generating additional power using a molten carbonate fuel cell (MCFC) CO 2 - may facilitate the separation of CO 2 from the containing stream. The CO 2 separation can be further improved by taking advantage of the synergy with the combustion-based generator which can provide at least a portion of the feed feed to the cathode portion of the fuel cell.

Fuel Cell and Fuel Cell Components: In this discussion, a fuel cell may correspond to a single cell having an anode and a cathode separated by an electrolyte. The anode and cathode can accept an incoming gas flow to facilitate individual anode and cathode reactions for charge transport and generation across the electrolyte. The fuel cell stack may represent a plurality of cells in an integrated unit. Although the fuel cell stack can include a plurality of fuel cells, the fuel cells can typically be connected in parallel and (almost) the whole can act as a single size fuel cell. When the input flow is transferred to the anode or cathode of the fuel cell stack, the fuel cell stack may include a flow channel for dividing the incoming flow between each cell of the stack and a flow channel for combining the output flow from the individual cells . In this discussion, a plurality of fuel cells (e.g., a plurality of fuel cell stacks) arranged in series, in parallel, or in any other convenient manner (e.g., in series and parallel combination) Lt; / RTI > The fuel cell array may include one or more stages of a fuel cell and / or a fuel cell stack, wherein the anode / cathode output from the first stage may serve as an anode / cathode input of the second stage . Note that the anode of the fuel cell array need not be connected in the same manner as the cathode of the array. Conveniently, the input of the fuel cell array to the first anode stage may be referred to as the anode input of the array, and the input to the first cathode stage of the fuel cell array may be referred to as the cathode input of the array. Similarly, the output from the final anode / cathode stage may be referred to as the anode / cathode output from the array.

It should be appreciated that references to the use of fuel cells herein typically refer to the "fuel cell stack" consisting of individual fuel cells, and more generally to the use of one or more fuel cell stacks in fluid communication. Individual fuel cell elements (plates) can be "laminated" together in a rectangular array, typically referred to as a "fuel cell stack ". The fuel cell stack may typically have a feed stream, distribute the reactants among all the individual fuel cell elements, and collect the product from each of these elements. When viewed as a unit, the fuel cell stack to be operated can be taken as a whole despite being composed of a plurality of (often dozens or hundreds) individual fuel cell elements. These individual fuel cell elements can typically have similar voltages (because reactants and product concentrations are similar), and the total power output is calculated from the sum of all currents at all battery elements when the elements are electrically connected in series Lt; / RTI > The stacks may also be arranged in a tandem arrangement to produce a high voltage. The parallel arrangement can boost the current. The system and method described herein can be used with a single molten carbonate fuel cell stack when treating a given exhaust gas flow with a sufficiently large volume of the fuel cell stack. In another aspect of the invention, a plurality of fuel cell stacks may be desirable or necessary for various reasons.

In the present invention, unless otherwise specified, the term "fuel cell" refers to a reference to a fuel cell stack consisting of a set of one or more individual fuel cell elements in which a single input and output are present, (Since this is how the fuel cell is typically used in practice). Similarly, it should be appreciated that the term fuel cell (s) is defined to refer to / indicate or include a plurality of separate fuel cell stacks, unless otherwise specified. In other words, all citations within this disclosure may interchangeably refer to the operation of the fuel cell stack as a "fuel cell" unless otherwise specifically indicated. For example, the volume of exhaust gas generated by a commercial scale combustion generator may be too large to be processed by a conventional sized fuel cell (e.g., a single stack). To treat the entire exhaust gas, a plurality of fuel cells (i.e., two or more separate fuel cells or fuel cell stacks) may be arranged in parallel to allow each fuel cell to treat (approximately) the same amount of combustion exhaust gas have. Although multiple fuel cells can be used, each fuel cell can typically be operated in a substantially similar manner given (approximately) the same amount of combustion exhaust gas.

"Internal reforming" and "external reforming": The fuel cell or fuel cell stack may include one or more internal reforming zones. As used herein, the term "internal reforming" refers to fuel reforming occurring in a fuel cell body, a fuel cell stack, or alternatively, a fuel cell assembly. External reforming, often used with fuel cells, is performed in a separate device located outside the fuel cell stack. In other words, the external reformer body is not in direct physical contact with the fuel cell or the body of the fuel cell stack. In a typical setup, an output from an external reformer can be supplied to the anode inlet of the fuel cell. Unless specifically stated otherwise, the modifications described herein are internal modifications.

Internal reforming may occur within the fuel cell anode. The internal reforming may additionally or alternatively be carried out in an internal reforming element incorporated in the fuel cell assembly. The integrated reforming element may be located between the fuel cell elements within the fuel cell stack. In other words, one of the trays of the stack may be a reforming zone instead of the fuel cell element. In one embodiment, the flow arrangement within the fuel cell stack directs fuel into the internal reforming element and then into the anode portion of the fuel cell. Therefore, from the viewpoint of flow, the internal reforming element and the fuel cell element can be arranged in series in the fuel cell stack. The term "anode reforming" as used herein is a fuel reforming done in the anode. As used herein, the term "internal reforming" is a modification that takes place in the integrated reforming element, not in the anode region.

In some aspects, a reforming stage that is internal to the fuel cell assembly can be thought of as being carried on the anode (s) in the fuel cell assembly. In some other embodiments, in the case of a reforming stage of a fuel cell stack that can be accompanied by an anode (e.g., to be associated with a plurality of anodes), a flow path may be used so that the output flow from the reforming stage passes into one or more anodes. This may correspond to having an initial zone of the fuel cell plate that is not in contact with the electrolyte and may instead serve as a reforming catalyst. Another option of the subsequent reforming stage may be to have a separate integrated reforming stage as one of the elements of the fuel cell stack wherein the product from the integrated reforming stage is returned to the input side of one or more fuel cells of the fuel cell stack .

From the heat integration point of view, the characteristic height of the fuel cell stack can be the height of the individual fuel cell stack elements. Note that a separate reforming stage and / or a separate endothermic reaction stage may have a different height than the fuel cell in the stack. In such a scenario, the height of the fuel cell element can be used as the characteristic height. In some embodiments, an integrated endothermic reaction stage can be defined as a stage that is thermally integrated with one or more fuel cells, such that the integrated endothermic reaction stage can use heat from the fuel cell as a heat source for the endothermic reaction. This integrated endothermic reaction stage can be defined as being located less than five times the height of the stack element from any fuel cell that provides heat to the integrated stage. For example, an integrated endothermic reaction stage (e.g., a reforming stage) may be located less than five times the height of the stack element from any heat-integrated fuel cell, for example, less than three times the height of the stack element . In this discussion, the integrated reforming stage and / or the integrated endothermic reaction stage representing the stack elements adjacent to the fuel cell element can be defined as being less than or equal to about one stack element height away from adjacent fuel cell elements.

In some embodiments, a separate reforming stage that is thermally integrated with the fuel cell element may correspond to a reforming stage followed by the fuel cell element. In such an embodiment, the integrated fuel cell element may provide at least a portion of the heat to the subsequent reforming stage, and the subsequent reforming stage may provide at least a portion of the reforming stage output to the integrated fuel cell as a fuel stream. In another aspect, a separate reforming stage can be integrated with the fuel cell for heat exchange without involving the fuel cell. In this type of situation, a separate reforming stage can receive heat from the fuel cell, but can be determined not to use the product of the reforming stage as an input to the fuel cell. Instead, one can decide to use the output of this modification stage for other purposes, such as adding the product directly to the anode exhaust stream and / or forming a separate output stream from the fuel cell assembly.

More generally, a separate stack element of the fuel cell stack can be used to perform any convenient type of endothermic reaction that can take advantage of the waste heat provided by the integrated fuel cell stack element. Instead of a plate suitable for carrying out the reforming reaction on the hydrocarbon fuel stream, a separate stack element may have a plate suitable for promoting another type of endothermic reaction. Different arrangements of manifolds or inlet conduits of the fuel cell stack can be used to provide a suitable input flow to each stack element. A similar manifold or other arrangement of outlet conduits may be used additionally or otherwise to recover the output flow from each stack element. Optionally, the output flow from the endothermic reaction stage of the stack can be recovered from the fuel cell stack without passing the output flow through the fuel cell anode. In this optional embodiment, therefore, the product of the exothermic reaction can exit the fuel cell stack without passing through the fuel cell anode. Examples of other types of endothermic reactions that may be performed in the stack elements of the fuel cell stack may include, but are not limited to, ethanol dehydration and ethane classification to form ethylene.

Recirculation: Recirculating a portion of the fuel cell output (eg, a stream separated or recovered from the anode exhaust gas or the anode exhaust gas) defined herein to the fuel cell inlet may correspond to a direct or indirect recycle stream. Direct recirculation of the stream to the fuel cell inlet is defined as recirculation of the stream that is not passed through the intermediate process, while indirect recirculation includes recirculation after passing the stream through one or more intermediate processes. For example, if the anode exhaust gas passes through a CO 2 separation stage before it is recirculated, it is thought to be indirect recirculation of the anode exhaust gas. If a portion of the anode exhaust gas, such as the H 2 stream recovered from the anode exhaust gas, is passed into the vaporizer to convert the coal to fuel suitable for introduction into the fuel cell, this is also considered indirect recirculation.

Anode inputs and outputs

In various embodiments of the present invention, MCFC arrays include, but are not limited to, hydrocarbons, such as hydrocarbons such as hydrocarbons or hydrocarbons, which may contain hydrogen and methane (or alternatively may contain heteroatoms other than C and H) Acceptable fuel can be supplied. The majority of methane (or other hydrocarbon or hydrocarbon compounds) fed to the anode may typically be fresh methane. In this document, new fuels, such as fresh methane, refer to fuels that are not recycled from other fuel cell processes. For example, methane recycled back to the anode inlet from the anode outlet stream can not be thought of as "fresh" methane, but instead can be described as regenerated methane. The fuel source used may be shared with other components, such as turbines, that provide a CO 2 -containing stream to the cathode input using a portion of the fuel source. The fuel source input may include water in proportion to the fuel suitable to reform the hydrocarbon (or hydrocarbon) compound in the reforming zone that generates hydrogen. For example, if the fuel input for reforming to generate H 2 is methane, the molar ratio of water to fuel may be from about 1: 1 to about 10: 1, such as greater than about 2: 1. A ratio of at least 4: 1 is typical for external reforming, but a lower value for internal reforming may be typical. To the extent that H 2 is part of the fuel source, in some optional embodiments, no additional water may be required for the fuel, because the oxidation of H 2 in the anode tends to produce H 2 O that can be used to modify the fuel This can happen. The fuel source may also optionally contain additional components to the fuel source (e.g., the natural gas feed may contain some CO 2 content as an additional component). For example, the natural gas feed may contain CO 2 , N 2 , and / or another inert gas (noble gas) as an additional component. Optionally, in some embodiments, the fuel source may also contain CO, such as CO from the recycled portion of the anode exhaust gas. An additional or other possible source of CO in the fuel into the fuel cell assembly may be CO generated by steam reforming of the hydrocarbon fuel performed on the fuel prior to entering the fuel cell assembly.

More generally, various types of fuel streams may be suitable for use as an input stream of an anode of a molten carbonate fuel cell. Some fuel streams may correspond to a stream containing hydrocarbons and / or compounds such as hydrocarbons which may also contain heteroatoms different from C and H. [ In this discussion, unless stated otherwise, a reference to a hydrocarbon-containing fuel stream for an MCFC anode is defined to include a fuel stream containing such a hydrocarbon-like compound. Examples of hydrocarbons (including compounds such as hydrocarbons) fuel streams include not only streams containing natural gas, C1-C4 carbon compounds (e.g., methane or ethane), and heavier C5 + hydrocarbons (including compounds such as hydrocarbons) And combinations thereof. Yet another or additional example of a fuel stream for use in the anode input may comprise a biogas-type stream such as methane produced from natural (biological) degradation of organic material.

In some embodiments, a molten carbonate fuel cell can be used to treat a feed fuel stream, such as a natural gas and / or hydrocarbon stream having a low energy content due to the presence of a diluent compound. For example, some sources of methane and / or natural gas are sources that can contain significant amounts of CO 2 or other inert molecules (e.g., nitrogen, argon or helium). Due to the presence of increasing amounts of CO 2 and / or inert compounds, the energy content of the fuel stream based on the source can be reduced. There may be difficulties in using a fuel with a low energy content in the combustion reaction (e.g., to provide power to a turbine that is powered by combustion). However, molten carbonate fuel cells can generate power based on a fuel source with a low energy content, with little or no effect on the efficiency of the fuel cell. The presence of an additional gas volume may require additional heat to raise the temperature of the fuel to the temperature of the reforming and / or anode reaction. In addition, due to the equilibrium state characteristic of the aqueous gas-phonetic reaction in the fuel cell anode, the presence of additional CO 2 can affect the relative amounts of H 2 and CO present in the anode product. However, inert compounds can only have a direct effect on the reforming and the anode reaction. When present, the amount of CO 2 and / or inert compound in the fuel stream of the molten carbonate fuel cell may be greater than about 1 volume%, such as greater than about 2 volume%, or greater than about 5 volume%, or greater than about 10 volume% Or about 15% by volume, or about 20% by volume or more, or about 25% by volume or more, or about 30% by volume or more, or about 35% by volume or more, or about 40% by volume or more, or about 45% About 50% by volume or more, or about 75% by volume or more. Additionally or alternatively, the amount of CO 2 and / or inert compound in the fuel stream of the molten carbonate fuel cell may be less than or equal to about 90 vol%, such as less than or equal to about 75 vol%, alternatively less than or equal to about 60 vol%, alternatively less than or equal to about 50 vol% Or about 40% by volume, or about 35% by volume or less.

Another example of a possible source for the anode input stream may correspond to refining and / or other industrial process output streams. For example, coking is a common process in many refinements to convert heavy compounds into a low-cost range. Coking typically produces an off-gas containing various compounds that are gases at room temperature, including CO and various < RTI ID = 0.0 > C1-C4 < / RTI > hydrocarbons. This off-gas can be used as at least a portion of the anode input stream. Other scouring off-gas streams, such as hard-terminated (C1-C4), generated during sorting or other scouring processes may additionally or alternatively be suitable for inclusion in the anode input stream. Another suitable refining stream may additionally or alternatively comprise a CO or CO 2 -containing refining stream containing H 2 and / or a reformable fuel compound.

Other possible sources of anode input may additionally or alternatively comprise a stream of high water content. For example, an ethanol output stream from an ethanol plant (or other type of fermentation process) may contain significant amounts of H 2 O prior to final distillation. Such H 2 O can typically only have a minimal impact on the operation of the fuel cell. Therefore, a fermentation mixture of alcohol (or other fermentation product) and water may be used as at least a portion of the anode input stream.

The biogas, or digester gas, is an additional or other possible source of anode input. Biogas can include mainly methane and CO 2 , and is typically produced by destruction or digestion of organic materials. Anaerobic bacteria can be used to digest organic materials and produce biogas. Impurities such as sulfur-containing compounds may be removed from the biogas prior to use as the anode input.

The output stream from the MCFC anode may contain H 2 O, CO 2 , CO and H 2 . Optionally, the anode output stream may also have unreacted fuel (e.g., H 2 or CH 4 ), or an inert compound in the feed as an additional output component. Instead of using this output stream as the fuel source providing heat for the reforming reaction or as the combustion fuel for heating the cell, one or more separations can be carried out on the anode output stream to provide an effluent stream as an input to another process such as H 2 or CO CO 2 can be separated from the expected value component. H 2 and / or CO may be used as synthesis gas for chemical synthesis, as a hydrogen source, and / or the greenhouse gas emissions are reduced fuel for reaction.

In various embodiments, the composition of the output stream from the anode can be influenced by several factors. Factors that can affect the anode output composition may include the composition of the input stream to the anode, the amount of current generated by the fuel cell, and / or the temperature at the outlet of the anode. The temperature at the anode outlet may be related due to the equilibrium state characteristic of the water gas telephone reaction. In a typical anode, one or more of the plates forming the walls of the anode may be suitable for promoting the water gas-phonetic reaction. B) knowing the degree of modification of the reformable fuel in the anode input stream; c) determining the amount of carbonate transported from the cathode to the anode (corresponding to the amount of generated current) Knowing that, the composition of the anode output can be determined based on the equilibrium constant of the water gas-phonetic reaction:

K eq = [CO 2 ] [H 2 ] / [CO] [H 2 O]

In the above equation, K eq is the equilibrium constant of the reaction at a predetermined temperature and pressure, and [X] is the partial pressure of the component X. On the basis of the water gas-phosphating reaction, increased CO 2 concentration in the anode charge may tend to cause additional CO formation (consuming H 2 ), while increased H 2 O concentration causes additional H 2 formation (CO Of the total amount of money spent).

To determine the composition in the anode output, the composition of the anode input may be used as a starting point. This composition can then be varied to reflect the degree of modification of any reformable fuel that may occur in the anode. Such a modification can reduce the hydrocarbon content of the anode charge instead of increasing the hydrogen and CO 2 . Then, based on the amount of current produced, the amount of H 2 in the anode charge can be reduced instead of the additional H 2 O and CO 2 . The outlet concentration of H 2 , CO, CO 2 and H 2 O can then be determined by adjusting this composition based on the equilibrium constant of the aqueous gas-phonetic reaction.

Table 2 shows the anode exhaust composition at different fuel utilization rates of a typical type of fuel. The anode exhaust gas composition may reflect the combined result of the anode reforming reaction, the water gas telephone reaction and the anode oxidation reaction. About 2: By estimating the water vapor of 1 (H 2 O) to carbon (available fuel reforming) anode inputs to have the composition ratio was calculated to output the composition given in table 1. The reformable fuel was assumed to be methane, which was assumed to be reformed to 100% hydrogen. The initial CO 2 and H 2 concentrations in the anode feeds were assumed to be negligible, while the feed N 2 concentrations were approximately 0.5%. As shown in the table, the fuel utilization U f (as defined herein) could be varied from about 35% to about 70%. The exit temperature of the fuel cell anode was estimated to be about 650 ° C to determine the correct equilibrium constant value.

[Table 2]

Anode exhaust gas composition

Figure pct00002

Table 2 shows the anode product composition in a particular set of conditions and anode charge composition. More generally, in various embodiments, the anode product may comprise from about 10% by volume to about 50% by volume of H 2 O. The amount of H 2 O can vary greatly, because H 2 O in the anode can be generated by the anode oxidation reaction. If an excess of H 2 O is introduced into the anode than is necessary for the reforming, the excess H 2 O will mostly not react except for H 2 O, which is typically consumed (or generated) by the fuel reforming and water gas- Can pass without. The CO 2 concentration in the anode effluent may vary widely, for example from about 20% by volume to about 50% by volume of CO 2 . The amount of positive current is generated for CO 2, as well as may be influenced by the amount of anode In yudongjung CO 2. The amount of H 2 in the anode effluent may additionally or alternatively be from about 10% H 2 to about 50% H 2 by H 2 depending on the fuel utilization at the anode. In the anode output, the amount of CO may be from about 5% by volume to about 20% by volume. Note that the amount of CO with respect to the amount of H 2 in the anode product of a given fuel cell can be determined in part by the equilibrium constant of the water gas conversion at the temperature and pressure present in the fuel cell. The anode output is then in addition or alternatively a is N 2, CH 4 - may include various other components, such as (or other unreacted carbon-containing fuel) and / or other components to less than 5% by volume.

Optionally, if desired, one or more aqueous gas-phonetic reactions can be included after the anode product to convert CO and H 2 O in the anode product to CO 2 and H 2 . The amount of H 2 present in the anode product can be increased, for example, by converting H 2 O and CO present in the anode product to H 2 and CO 2 using a water gas-phonetic reaction at a lower temperature. Alternatively, the temperature can be raised and the water gas-phosphating reaction reversed to produce more CO and H 2 O from H 2 and CO 2 . Water is the predicted output of the reaction in the anode, and thus the anode output typically can have an excess of H 2 O relative to the amount of CO present in the anode product. Alternatively, H 2 O may be added to the stream after the anode outlet, but prior to the water gas-phonetic reaction. CO is converted to equilibrium state equilibrium (i.e., water gas equilibrium) of the reaction between H 2 O, CO, H 2 and CO 2 under conditions that are incomplete carbon conversion during the reforming and / or during the reforming conditions or during the anode reaction May be present in the anode output. The water gas-phone reactor can be operated under conditions that allow it to move equilibrium further in the direction of forming CO 2 and H 2 while consuming CO and H 2 O. Higher temperatures may tend preferred for the formation of CO and H 2 O. Thus, one option for operating a water gas-phosgene reaction is to expose the anode output stream to a suitable catalyst such as a catalyst including iron oxide, zinc oxide, copper oxide on zinc oxide, etc. at a suitable temperature, for example from about 190 캜 to about 210 캜 It can be done. Optionally, the water gas telephone reactor may comprise two stages for reducing CO concentration in the anode output stream, wherein the first stage of higher temperature is operated at about 300 ° C to about 375 ° C, and the second, The stage is operated at about 225 캜 or less, such as about 180 캜 to about 210 캜. In addition to increasing the amount of H 2 present in the anode effluent, the water gas-phonetic reaction can also or alternatively consume CO and increase the amount of CO 2 . This can turn carbon monoxide (CO), which is difficult to remove, into carbon dioxide which can be more easily removed by condensation (e. G., Cryogenic removal), chemical reaction (e. G., Amine removal) and / or other CO 2 removal methods. Additionally or alternatively, it may be desirable to increase the CO content present in the anode exhaust gas to obtain the desired H 2 to CO ratio.

After passing through an optional aqueous gas-phased reaction stage, the anode product can be passed through one or more separation stages to remove water and / or CO 2 from the anode output stream. For example, one or more CO 2 output streams can be formed by performing CO 2 separation on the anode product using one or more methods separately or together. Using this method, it is possible to produce a 90% by volume or more, for instance 95 vol% or 98 vol% or more of CO 2 output stream having a CO 2 content (s). This method can save more than 70% of the CO 2 content of the anode outputs, for example, about 80% of the CO 2 content of the anode outputs, or at least about 90% or more. Alternatively, in some embodiments, it may be desirable to recover at least a portion of the CO 2 in the anode output stream, wherein the recovered CO 2 portion is from about 33% to about 90% of the CO 2 in the anode product, 40% or more, or about 50% or more. For example, it may be desirable to have some CO 2 in the anode output stream so that the desired composition can be achieved in a subsequent aqueous gas telephone stage. Suitable separation methods include, but are not limited to, physical solvents (e.g., Selexol ™ or Rectisol ™); Amine or other base (e.g., MEA or MDEA); Freezing (e. G., Cryogenic separation); Pressure swing adsorption; Vacuum swing adsorption; And combinations of these. A cryogenic CO 2 separator may be an example of a suitable separator. As the anode product cools, most of the water in the anode product can be separated as a condensed (liquid) phase. Additional cooling and / or pressurization of the water-depleted anode output stream can separate high purity CO 2 , since other residual components of the anode output flow (eg, H 2 , N 2 , CH 4 ) It tends not to be easily formed. The cryogenic CO 2 separator can recover from about 33% to about 90% of the CO 2 present in the flow depending on operating conditions.

Before CO 2 separation, during or after performing a separate CO 2 CO 2 separation, to removing water from the anode exhaust gas to form one or more output streams of water may also be advantageous. The amount of water in the anode effluent may vary depending on the operating conditions selected. For example, the water vapor-to-carbon ratio established at the anode inlet can affect the water content in the anode exhaust, since high water vapor-to-carbon ratios are typically unreacted and / or due to water gas equilibrium at the anode And generates a large amount of water that can pass through the anode while reacting. According to an embodiment, the water content in the anode exhaust gas may correspond to at least about 30% of the volume of the anode exhaust gas. Alternatively or in addition, the water content can be about 80% or less of the volume of the anode exhaust gas. Such water can be removed by cooling due to condensation that is compressed and / or produced, but removal of such water may require additional compressor power and / or heat exchange surface area and excess cooling water. One advantageous way of removing a portion of this excess water is to capture moisture from the humid anode effluent and to be " regenerated " using dry anode feed gas to provide additional water to the anode feed Lt; RTI ID = 0.0 > adsorbent. ≪ / RTI > HVAC-style (heating, venting and air conditioning) adsorption wheel designs can be applied because the anode exhaust gas and inlet can be similar in pressure and the minute leaks from one stream to the other stream Because it can have a minimal impact on. In embodiments where CO 2 removal is performed using a cryogenic process, removal of water prior to or during CO 2 removal, including removal by a triethylene glycol (TEG) system and / or a desiccant, may be desirable. In contrast, in the case of using an amine wash to remove CO 2, the process can be later than the CO 2 removal stage to remove the water from the anode exhaust gas.

Unlike or in addition to the CO 2 output stream and / or the water output stream, the anode output can be used to form one or more product streams containing the desired compound or fuel product. These product streams or streams may correspond to a syngas stream, a hydrogen stream, or both a syngas product and a hydrogen product stream. For example, a hydrogen product stream may be formed that contains at least about 70 vol% H 2 , such as at least about 90 vol% H 2 or at least about 95 vol% H 2 . Additionally or alternatively, a syngas stream containing a total of about 70% by volume of H 2 and CO, for example about 90% by volume of H 2 and CO, can be formed. The at least one product stream may have a gas volume corresponding to at least about 75% by volume of the combined H 2 and CO gas volumes in the anode product, such as at least about 85% or about 90% of the combined H 2 and CO gas volumes have. It is noted that the relative amounts of H 2 and CO in the product stream may differ from the H 2 to CO ratio in the anode product based on the use of a water gas conversion stage to convert between products.

In some embodiments, it may be desirable to remove or separate a portion of the H 2 present in the anode product. For example, in some embodiments, the H 2 to CO ratio in the anode exhaust gas may be greater than about 3.0: 1. In contrast, processes using syngas such as Fischer-Tropsch synthesis can consume H 2 and CO at different ratios, such as a ratio close to 2: 1. One alternative could be to use a water gas-to-gas conversion to change the content of the anode output to have a H 2 to CO ratio that is closer to the desired syngas composition. Another alternative could be to use membrane separation to remove a portion of the H 2 present in the anode product to obtain the desired H 2 to CO ratio, or alternatively to utilize a combination of membrane separation and water gas-phonetic reaction. One advantage of using membrane separation to remove only a portion of the H 2 in the anode output may be that it is capable of performing the desired separation under relatively mild conditions. Pure hydrogen permeate can be produced by membrane separation without the need for extreme conditions, since one objective may still be to produce a retentate with a substantial H 2 content. For example, rather than having a pressure of about 100 kPa or less (e.g., ambient pressure) on the permeate side of the membrane, the permeate side may be at pressurization rather than ambient pressure while still having sufficient driving force to perform membrane separation. Additionally or alternatively, a sweep gas such as methane may be used to provide a driving force for membrane separation. This may reduce the purity of the H 2 permeate stream, but may be advantageous depending on the intended use of the permeate stream.

In various embodiments of the present invention, at least a portion of the anode exhaust gas stream (preferably after separation of CO 2 and / or H 2 O) may be used as a process external to the fuel cell and as a feed to the subsequent reforming stage. In various embodiments, the anode exhaust gas may have a ratio of H 2 to CO of at least about 1.5: 1 to about 10: 1, such as at least about 3.0: 1, or at least about 4.0: 1, or at least about 5.0: . A syngas stream can be generated or recovered from the anode exhaust gas. Optionally, after separation of CO 2 and / or H 2 O and optionally also water gas-phonetic reaction and / or membrane separation to remove excess hydrogen, the anode exhaust gas contains a significant amount of H 2 and / or CO ≪ / RTI > In the case of a stream having a relatively low CO content, such as a stream having a H 2 to CO ratio of about 3: 1 or greater, the anode exhaust gas may be suitable for use as an H 2 feed. Examples of processes that can take advantage of H 2 feeds include, but are not limited to, a refining process, an ammonia synthesis plant, a turbine in a (different) power generation system, or a combination thereof. Depending on the application, lower CO 2 content may be desirable. In the case of a stream having a H 2 to CO ratio of less than about 2.2: 1 and greater than about 1.9: 1, the stream may be suitable for use as a syngas feed. Examples of processes that can take advantage of syngas feeds include gas liquefied fuel plants (e.g., plants that use a Fischer-Tropsch process with a non-conversion catalyst) and / or methanol synthesis plants, But are not limited thereto. The amount of anode exhaust gas used as a feed for the external process may be any convenient amount. Optionally, if some of the anode exhaust is used as a feed for an external process, it may be recycled to the combustion zone of a generator that recycles the second portion of the anode exhaust gas to the anode charge and / have.

A feed stream useful in different types of Fischer-Tropsch synthesis processes can provide an example of a different type of product stream that may be desired to be produced from the anode product. In a Fischer-Tropsch synthesis reaction system using a morphology catalyst such as an iron-based catalyst, the desired feed stream to the reaction system may include CO 2 in addition to H 2 and CO. If a sufficient amount of CO 2 is not present in the feed stream, the Fischer-Tropsch catalyst with water gas-phos- phoretic activity can produce a syngas that may be lacking in CO by consuming CO to produce additional CO 2 . In order to integrate this Fischer-Tropsch process with the MCFC fuel cell, the separation stage of the anode product can be operated to maintain the desired amount of CO 2 (and optionally H 2 O) in the syngas product. In contrast, in the case of a Fischer-Tropsch catalyst based on a non-transformed catalyst, any CO 2 present in the product stream can serve as an inert component in the Fischer-Tropsch reaction system.

In embodiments where the membrane is swept with a sweep gas such as a methane sweep gas, the methane sweep gas may correspond to the methane stream used as an anode fuel or in a different low pressure process such as a boiler, furnace, gas turbine or other fuel-consuming device. In this embodiment, low CO 2 permeation levels across the membrane can have minimal results. Such CO 2, which may be permeated across the membrane, may have minimal effect on the reaction in the anode, and such CO 2 may remain retained in the anode product. Therefore, CO 2 (if present) lost across the membrane due to permeation does not need to be passed back across the MCFC electrolyte. This can greatly reduce the separation selectivity condition in the hydrogen permeable membrane. This makes it possible, for example, to use a higher permeability membrane with lower selectivity, which makes it possible to utilize lower pressure and / or reduced membrane surface area. In this aspect of the invention, the volume of the sweep gas can be several times the volume of hydrogen in the anode exhaust gas, which can keep the effective hydrogen concentration on the permeate side close to zero. The thus separated hydrogen can be incorporated into the turbine-fed membrane, which can improve the turbine combustion characteristics as described above.

Excess H 2 generated at the anode is noted that the number represent a greenhouse gas that is already separated fuel. Any CO 2 from the anode output, for example by using an amine wash, the cryogenic CO 2 separator and / or a pressure or vacuum swing adsorption processes can be easily separated from the anode product. Some of the components (H 2 , CO, CH 4 ) of the anode product are not easily removed, whereas CO 2 and H 2 O can usually be easily removed. According to an embodiment, at least about 90% by volume of CO 2 in the anode effluent can be separated to form a relatively high purity CO 2 output stream. Therefore, any CO 2 generated in the anode can be efficiently separated to form a high purity CO 2 -containing stream. After separation, the remainder of the anode product may correspond to a reduced amount of CO 2 and / or H 2 O, as well as components having predominantly chemical and / or calorific value values. Since a significant amount of CO 2 produced by the original fuel (before reforming) may have been isolated, the amount of CO 2 generated by subsequent combustion of the remainder of the anode output may be reduced. In particular, additional greenhouse gases may not typically be generated by the combustion of this fuel, up to the limit that the fuel of the remainder of the anode output is H 2 .

The anode exhaust gas can be applied to a variety of gas processing options including water gas phones and separation of components from each other. Two general anode processing methods are shown in Figures 1 and 2.

Figure 1 schematically illustrates an example of a reaction system for operating a fuel cell array of a molten carbonate fuel cell with a chemical synthesis process. 1 supplies a fuel stream 105 to a reforming stage (or stages) 110 that is followed by an anode 127 of a fuel cell 120 such as a fuel cell that is part of the fuel cell stack in a fuel cell array. The reforming stage 110 that accompanies the fuel cell 120 may be inside the fuel cell assembly. In some optional embodiments, an external reforming stage (not shown) may also be used to reform some of the reformable fuel in the input stream before the input stream passes into the fuel cell assembly. The fuel stream 105 may preferably comprise a reformable fuel such as methane, other hydrocarbons and / or other compounds such as hydrocarbons (e.g., organic compounds containing carbon-hydrogen bonds). The fuel stream 105 may also contain H 2 and / or CO, such as H 2 and / or CO, optionally provided by an optional anode recycle stream 185. The anode recycle stream 185 is optional and may in some embodiments be indirectly recirculated from the anode exhaust gas 125 directly to the anode 127 or through a combination of the fuel stream 105 or the reformed fuel stream 115 Lt; / RTI > is not provided. After reforming, the reformed fuel stream 115 may be passed into the anode 127 of the fuel cell 120. The CO 2 and O 2 -containing stream 119 may also be passed into the cathode 129. The flow of carbonate ions 122 CO 3 2- from the cathode portion 129 of the fuel cell can provide the remainder of the reactants needed for the anode fuel cell reaction. Based on the reaction at the anode 127, the generated anode exhaust gas 125 is at least one of H 2 O, CO 2 , one or more components corresponding to the incompletely reacted fuel (H 2 , CO, CH 4 , other equivalent components to the fuel), and optionally may include one or more additional non-reactive component such as N 2, part, and / or other contaminants in the fuel stream (105). The anode exhaust gas 125 may then be passed into one or more separation stages. For example, the CO 2 removal stage 140 may include a cryogenic CO 2 removal system, an amine cleaning stage to remove acid gas, such as CO 2 , or another suitable type for separating the CO 2 output stream 143 from the anode exhaust gas Lt; RTI ID = 0.0 > CO 2 < / RTI > separation stage. Optionally, the anode exhaust gas may first be passed through a water gas-catalyzed reactor 130 to remove any CO (with some H 2 O) present in the anode exhaust gas, optionally in an aqueous gas- 135) to CO 2 and H 2 . Depending on the nature of the CO 2 removal stage, a water condensation or removal stage 150 may be preferred to remove the water output stream 153 from the anode exhaust gas. Although shown in FIG. 1 after the CO 2 separation stage 140, it may optionally be located before the CO 2 separation stage 140. In addition, it is possible to use the optional membrane separation stage 160 for separating the H 2 produced a high purity permeate stream 163 of H 2. The resulting retentate stream 166 can then be used as an input to the chemical synthesis process. Stream 166 is additionally or alternatively dialyzed in a second water gas telephony reactor 131 to adjust the H 2 , CO and CO 2 content to different ratios to produce an output stream 168 for further use in the chemical synthesis process Can be generated. Although anode recycle stream 185 is shown as being withdrawn from retentate stream 166 in Figure 1, anode recycle stream 185 may also or alternatively be withdrawn from various convenient stages, Can be recovered. The separation stage and the telephone reactor (s) may also or alternatively be arranged in different orders and / or in a parallel configuration. Finally, a stream 139 having a reduced CO 2 content can be generated as an output from the cathode 129. For simplicity, not only the various stages of compression and heat addition / removal useful in the process but also the addition or removal of water vapor are not shown.

As indicated above, various types of separations performed on the anode exhaust gas may be performed in any convenient order. Figure 2 shows an example of another sequence of performing separation on the anode exhaust gas. In FIG. 2, the anode exhaust gas 125 may first be passed into the separation stage 260 for removing a portion 263 of hydrogen content from the anode exhaust gas 125. This can, for example, reduce the H 2 content of the anode exhaust gas to provide a retentate 266 with a ratio of H 2 to CO close to 2: 1. The ratio of H 2 to CO in the water gas telephone stage 230 can then be further adjusted to achieve the desired value. The water gas product 235 is then passed through a CO 2 separation stage 240 and a water removal stage 250 to produce an output stream 275 suitable for use as an input to the desired chemical synthesis process . Optionally, the output stream 275 may be exposed to an additional water gas telephone stage (not shown). A portion of the output stream 275 may optionally be recycled to the anode input (not shown). Of course, another separation stage combination and sequence can be used to generate a stream based on the anode product with the desired composition. For simplicity, not only the various stages of compression and heat addition / removal useful in the process but also steam addition or removal are not shown.

Cathode inputs and outputs

Typically, the molten carbonate fuel cell can be operated based on the desired load while consuming a portion of the fuel in the fuel stream delivered to the anode. The voltage of the fuel cell can be determined by the load, the fuel input to the anode, the air and CO 2 provided to the cathode, and the internal resistance of the fuel cell. In part, it is possible to typically provide CO 2 to the cathode by using the anode exhaust gas as at least a portion of the cathode feed stream. In contrast, the present invention may use separate / different sources for anode inputs and cathode inputs. By eliminating any direct connection between the anode charge flow and the composition of the cathode charge flow, it is possible to reduce the total efficiency (electrical + chemical power) of the fuel cell, in particular by generating and / or increasing the amount of syngas, An additional option is available to operate the fuel cell to improve the fuel cell.

In a molten carbonate fuel cell, the transport of carbonate ions across the electrolyte of the fuel cell may provide a way to transport CO 2 from the first flow path to the second flow path, enabling further transport to the high concentration (anode) from the cathode), which thus can facilitate the capture of CO 2. Some of the selectivity of the fuel cell for CO 2 separation may be based on an electrochemical reaction that causes the cell to generate power. In the case of a non-reactive material (e.g., N 2 ) that does not participate effectively in the electrochemical reaction in the fuel cell, the reaction and the transport from the cathode to the anode may be present in negligible amounts. In contrast, the potential (voltage) difference between the cathode and the anode can provide a strong driving force for the transport of carbonate ions across the fuel cell. As a result, the transport of carbonate ions in the molten carbonate fuel cell can cause CO 2 to be transported from the cathode (lower CO 2 concentration) to the anode (higher CO 2 concentration) with relatively high selectivity. However, a difficulty in using a molten carbonate fuel cell for carbon dioxide removal may be that the fuel cell has limited ability to remove carbon dioxide from a relatively dilute cathode feed. The voltage and / or power generated by the carbonate fuel cell may begin to plunge as the CO 2 concentration falls below about 1 mol%. As the CO 2 concentration decreases at some point to less than about 0.3 mol%, for example, the voltage across the fuel cell becomes sufficiently low that the fuel cell will stop operating with little or no additional transport of carbonate . Therefore, at least some of the CO 2 will be present in the exhaust gas from the cathode stage of the fuel cell under commercially viable operating conditions.

The amount of carbon dioxide delivered to the fuel cell cathode (s) may be determined based on the CO 2 content of the source at the cathode inlet. An example of a CO 2 -containing stream suitable for use as a cathode feed stream may be an output from an combustion source or an exhaust gas stream. Examples of combustion sources include, but are not limited to, sources based on combustion of natural gas, combustion of coal, and / or combustion of other hydrocarbon-type fuels (including fuel derived from an organism). Additional or other sources may include other types of devices that burn carbon-containing fuels to heat other types of boilers, flammable heaters, furnaces, and / or other components (e.g., water or air). Approximately, the CO 2 content of the output flow from the combustion source can be small in the flow. Even in the case of a higher CO 2 content of exhaust gas flow, such as a coal-flamed combustion source, the CO 2 content from most commercial coal-fired power plants can be less than about 15% by volume. More generally, the CO 2 content of the product or exhaust gas flow from the combustion source is greater than or equal to about 1.5%, or greater than or equal to about 1.6%, or greater than or equal to about 1.7%, or greater than or equal to about 1.8% , Or at least 2 vol%, or at least about 4 vol%, or at least about 5 vol%, or at least about 6 vol%, or at least about 8 vol%. Additionally or alternatively, the CO 2 content of the product or exhaust gas flow from the combustion source can be up to about 20 vol%, for example up to about 15 vol%, or up to about 12 vol%, or up to about 10 vol% About 9 vol% or less, or about 8 vol% or less, or about 7 vol% or less, or about 6.5 vol% or less, or about 6 vol% or less, or about 5.5 vol% May be less than or equal to 4.5 vol%. The given concentration is a drying criterion. Note that there may be lower CO 2 content values in some natural gas or exhaust gases from a methane combustion source, such as generators that are part of a power generation system that may or may not be included in the exhaust gas recycle loop.

Other possible sources of cathode input streams may additionally or alternatively comprise a source of biologically generated CO 2 . This example, as CO 2 is generated during the ethanol production organisms may include a CO 2 generated during the processing of the derived compound. Additional or other examples may include CO 2 generated by the combustion of bio-generated fuel, such as combustion of lignocellulosic. Another additional or other possible CO 2 source CO 2 generated by the plant for the production of steel, cement and / or paper-may correspond to the output or the exhaust gas streams from various industrial processes on the same bearing stream.

Another additional or other possible sources of CO 2 is CO 2 from the fuel cell may be a containing stream. The CO 2 -containing stream from the fuel cell may be a cathode output stream from a different fuel cell, an anode output stream from a different fuel cell, a recycle stream from the cathode product of the fuel cell to the cathode input, and / May correspond to a recycle stream from the anode output to the cathode input. For example, an MCFC operating in a stand-alone manner under conventional conditions can produce a cathode exhaust gas having a CO 2 concentration of at least about 5 vol%. Such CO 2 -containing cathode exhaust gases may be used as cathode inputs to MCFCs operated in accordance with embodiments of the present invention. More generally, other types of fuel cells that produce CO 2 output from cathode exhaust gases, as well as CO 2 -containing streams that are not generated by a "combustion" reaction and / Other types may be used additionally or otherwise. Optionally, but preferably, the CO 2 -containing stream from another fuel cell can be from another molten carbonate fuel cell. For example, in the case of a molten carbonate fuel cell connected in series with a cathode, the output from the cathode of the first molten carbonate fuel cell can be used as an input to the cathode of the second molten carbonate fuel cell.

For various types of CO 2 -containing streams from sources other than combustion sources, the CO 2 content of the stream can vary widely. CO 2 content in the input stream of the cathode draw may contain from about 2 vol.% Or more, such as about 4% by volume or more, preferably about 5% by volume or more, or about 6% by volume, or at least about 8% by volume or more of CO 2 . Additionally or alternatively, the CO 2 content in the feed stream to the cathode may be up to about 30% by volume, such as up to about 25% by volume, or up to about 20% by volume, or up to about 15% by volume, Or about 8% by volume, or about 6% by volume or less, or about 4% by volume or less. For some higher CO 2 content streams, the CO 2 content may be greater than about 30% by volume, such as a stream substantially consisting of CO 2 and other compounds in balance. As an example, a gas-fired turbine without exhaust gas recirculation can produce an exhaust gas stream having a CO 2 content of about 4.2 vol.%. Using EGR, the gas-fired turbine can produce an exhaust gas stream having a CO 2 content of about 6 to 8% by volume. The stoichiometric combustion of methane can produce an exhaust stream having a CO 2 content of about 11% by volume. Combustion of coal can produce an exhaust stream having a CO 2 content of about 15 to 20% by volume. A flammable heater using refining off-gas can produce an exhaust stream having a CO 2 content of about 12 to 15 vol.%. A gas turbine operating on low BTU gas without any EGR can produce an exhaust gas stream with a CO 2 content of about 12% by volume.

In addition to CO 2 , the cathode feed stream must contain O 2 to provide the components needed for the cathode reaction. Some cathode input streams may be based on having air as a constituent. For example, combustion exhaust gas streams can be formed by burning hydrocarbon fuel in the presence of air. Other types of cathode feed streams having an oxygen content based on the inclusion of such combustion exhaust gas streams or air may have an oxygen content of up to about 20 vol%, such as up to about 15 vol%, or up to about 10 vol%. Additionally or alternatively, the oxygen feed rate of the cathode feed stream can be at least about 4 vol.%, Such as at least about 6 vol.%, Or at least about 8 vol.%. More generally, the cathode input stream may have an oxygen content suitable for performing the cathode reaction. In some embodiments, it may correspond to an oxygen content of from about 5% by volume to about 15% by volume, for example from about 7% by volume to about 9% by volume. For many types of cathode feed streams, the combined amount of CO 2 and O 2 may correspond to less than about 21% by volume of the feed stream, such as less than about 15% by volume of the stream, or less than about 10% by volume of the stream. The oxygen-containing air stream can be combined with a CO 2 source having a low oxygen content. For example, the exhaust gas stream generated by burning coal may include a low oxygen content that can mix with air to form a cathode inlet stream.

In addition to CO 2 and O 2 , the cathode feed stream may also be composed of inert / non-reactive materials such as N 2 , H 2 O, and other typical oxidant (air) components. For example, in the case of cathode inputs derived from the exhaust gas from the combustion reaction, if air is used as part of the oxidant source of the combustion reaction, the exhaust gas can include N 2 , H 2 O, and trace amounts of other Lt; RTI ID = 0.0 > air. ≪ / RTI > Depending on the nature of the fuel source of the combustion reaction, additional substances present after combustion based on the fuel source may be present in the fuel such as H 2 O, oxides of nitrogen (NO x ) and / or oxides of sulfur (SO x ) Or other compounds that are part or completely combustion products of the compounds present in the fuel. These materials may be present in an amount that can reduce overall cathode activity but not contaminate the cathode catalyst surface. This reduction in performance can be tolerated, or the material interacting with the cathode catalyst can be reduced to a level acceptable by known contaminant removal techniques.

The amount of O 2 present in the cathode feed stream (e.g., the cathode feed stream based on the combustion exhaust gas) may advantageously be sufficient to provide the oxygen required for the cathode reaction of the fuel cell. Therefore, the volume percentage of O 2 can advantageously be at least 0.5 times the amount of CO 2 in the exhaust gas. Optionally, additional air can be added to the cathode feed, if necessary, to provide sufficient oxidant for the cathode reaction. When some type of air is used as the oxidant, the amount of N 2 in the cathode exhaust gas may be at least about 78 vol%, such as at least about 88 vol%, and / or at least about 95 vol%. In some embodiments, the cathode feed stream may additionally or alternatively contain a compound that is typically seen as a contaminant (e.g., H 2 S or NH 3 ). In another embodiment, the cathode input stream can be cleaned to reduce or minimize the content of such contaminants.

In addition to the reaction to form carbonate ions for transport across the electrolyte, the conditions of the cathode may also be suitable for the conversion of nitrogen oxides to nitrates and / or nitrate ions. Hereinafter, for convenience, only nitrate ions are referred to. The resulting nitrate ions may also be transported across the electrolyte for reaction at the anode. The NO x concentration in the cathode feed stream can typically be in the order of ppm and thus this nitrate transport reaction can have a minimal impact on the amount of carbonate transported across the electrolyte. However, this NO x removal method may be advantageous for a cathode input stream based on combustion exhaust gas from a gas turbine because it can provide a mechanism for reducing NO x emissions. The conditions of the cathode may additionally or alternatively be suitable for the conversion of unburned hydrocarbons (with O 2 in the cathode feed stream) to typical combustion products (e.g., CO 2 and H 2 O).

Suitable temperatures for operation of the MCFC may be from about 450 캜 to about 750 캜, such as about 500 캜 or higher, the inlet temperature is about 550 캜, and the outlet temperature is about 625 캜. Before entering the cathode, heat may be applied to the combustion exhaust gas, if necessary, or heat may be removed from the combustion exhaust gas to provide heat for other processes such as, for example, reforming the fuel input of the anode. For example, when the source of the cathode input stream is a combustion exhaust stream, the combustion exhaust stream may have a temperature higher than the desired temperature of the cathode inlet. In this embodiment, heat may be removed from the combustion exhaust gas prior to use as a cathode feed stream. Alternatively, the combustion exhaust gas may be at a very low temperature, for example after a wet gas scrubber on a coal-fired boiler, in which case the combustion exhaust gas may be below about 100 ° C. Alternatively, the combustion exhaust gas may be an exhaust gas of a gas turbine operating in a combined cycle mode, and in a combined cycle mode, the gas may be cooled by rising steam to operate the steam turbine for further power generation. In this case, the gas may be less than about 50 캜. Heat can be applied to the combustion exhaust gas, which is colder than required.

Fuel cell arrangement

In various embodiments, configuration options of the fuel cell (e. G., A fuel cell array containing a plurality of fuel cell stacks) may be to partition the CO 2 -containing stream between the plurality of fuel cells. Some types of sources of CO 2 -containing streams can produce a large volume flow rate relative to the capacity of individual fuel cells. For example, a CO 2 -containing output stream from an industrial combustion source can typically correspond to a large flow volume compared to the operating conditions desired for a single MCFC of appropriate size. Instead of treating the entire flow in a single MCFC, it is possible to divide the flow between a plurality of MCFC unit devices (usually at least some of which may be connected in parallel) so that the flow rate at each unit device can be within the desired flow range .

The second configuration option can use the fuel cell in series to continuously remove CO 2 from the flow stream. Regardless of the number of initially connected parallel fuel cells capable of distributing the CO 2 -containing stream, after each initial fuel cell, one or more additional cells may be connected in series to further remove additional CO 2 . Attempts to remove CO 2 from the cathode input stream at the desired level in a single fuel cell or fuel cell stage at a desired level when the required amount of CO 2 in the cathode output is sufficiently low may cause a low and / It can cause output. Rather than attempt to remove it from a single fuel cell or fuel cell stage until the desired level of CO 2, until the desired level is achieved, which can remove CO 2 from the continuous battery. For example, each cell of a series of fuel cells can be used to remove a portion (e.g., about 50%) of the CO 2 present in the fuel stream. In this example, if three fuel cells are used in series, the CO 2 concentration can be reduced (e.g., up to about 15% of the original amount present, 2 < / RTI > concentration from about 6% to about 1% or less).

In other configurations, the operating conditions may be selected in the initial fuel stage connected in series to provide the desired output voltage, while the array of stages may be selected to achieve the desired carbon separation level. As an example, an array of fuel cells in which three fuel cells are connected in series can be used. The first two cascaded fuel cells can be used to remove CO 2 while maintaining the desired output voltage. The final fuel cell can then be operated to remove CO 2 from the lower voltage to the desired concentration.

In another configuration, the anode and cathode in the fuel cell array may be separately connected. For example, where a fuel cell array includes fuel cells connected in series, the corresponding anode may be connected in any convenient manner without necessarily being matched to the same arrangement as, for example, the corresponding cathode. This may be achieved, for example, by connecting the anodes in parallel so that each anode accepts the same type of fuel feed and / or reversing the anode so that the highest fuel concentration of the anode corresponds to a cathode with the lowest CO 2 concentration .

In another configuration, the amount of fuel delivered to one or more anode stages and / or the amount of CO 2 delivered to one or more cathode stages may be controlled to improve performance of the fuel cell array. For example, the fuel cell array may have a plurality of cascaded cathode stages. In an array comprising three cascaded cathode stages, this is because the output from the first cathode stage may correspond to the input of the second cathode stage and the output from the second cathode stage may correspond to the output of the third cathode stage Lt; RTI ID = 0.0 > of < / RTI > In this type of construction, the CO 2 concentration can be reduced in each successive cathode stage. To supplement this reduced CO 2 concentration, additional hydrogen and / or methane may be delivered to the anode stage corresponding to the subsequent cathode stage. The additional hydrogen and / or methane at the anode corresponding to the subsequent cathode stage may at least partially cancel the loss of voltage and / or current caused by the reduced CO 2 concentration, , Thus increasing the net power. In another example, the cathodes of the fuel cell array may be connected in series and some in parallel. In this type of example, instead of passing the total combustion product through the cathode of the first cathode stage, at least a portion of the combustion exhaust gas may be passed into the subsequent cathode stage. This can provide increased CO 2 content in subsequent cathode stages. Another option is to use a variety of feeds to the anode stage or cathode stage, if desired.

The cathode of the fuel cell may correspond to a plurality of cathodes from the fuel cell array as already described. In some embodiments, the fuel cell array may be operated to improve or maximize the amount of carbon delivered from the cathode to the anode. In this aspect, for cathode artifacts from the final cathode (s) in the array sequence (typically including at least a series arrangement, or the last cathode (s) and the initial cathode (s) are the same) The output composition may include at least about 2.0 vol% CO 2 and / or at least about 0.5 vol%, or at least about 1.0 vol% carbon dioxide, and / or at least about 1.2 vol% carbon dioxide (eg, about 1.5 vol% Or about 1.5% by volume or more of CO 2 . Because of this limitation, the net efficiency of CO 2 removal when using molten carbonate fuel cells can vary depending on the amount of CO 2 in the cathode feed. In a cathode feed stream having a CO 2 content of at least about 6 vol%, such as at least about 8%, the limit on the amount of CO 2 that can be removed is not critical. However, for combustion reactions with excess air using natural gas as the fuel, as typically found in gas turbines, the amount of CO 2 in the combustion exhaust gas is less than about 5% by volume of CO 2 in the cathode feed ≪ / RTI > concentration. Exhaust gas recirculation may be used to increase the amount of CO 2 in the cathode feed to at least about 5% by volume, such as at least about 6% by volume. If natural gas is used as the fuel to produce a CO 2 concentration of greater than about 6% by volume, as the EGR increases, the flammability of the combustor may be reduced and the gas turbine may become unstable. However, when H 2 is added to the fuel, the flammability window is significantly increased, further increasing the amount of exhaust gas recirculation to achieve a CO 2 concentration in the cathode feed of at least about 7.5% by volume or at least about 8% by volume . By way of example, it is to cache on the basis of the removal threshold of about 1.5% by volume of the cathode exhaust gas, to increase the CO 2 content in the cathode inputs to from about 5.5 vol% to about 7.5% by volume of the fuel for eventual CO 2 separation Can correspond to about 10% increase in the amount of CO 2 that can be captured using the cell and transported to the anode loop. The amount of O 2 in the cathode product may be further or alternatively reduced in an amount proportional to the amount of CO 2 that is typically removed, which is the amount of another (non-cathode-reactive) substance at the cathode outlet ) Can be correspondingly increased by a small amount.

In another aspect, the fuel cell array may be operated to improve or maximize the energy output of the fuel cell, such as total energy output, electrical energy output, syngas chemical energy output, or combinations thereof. For example, in a variety of situations, a molten carbonate fuel cell can be operated using an excess of modifiable fuel, for example, for the production of a syngas stream for use in a compound synthesis plant and / have. The syngas stream and / or the hydrogen stream may be used as a syngas source, as a hydrogen source, as a clean fuel source, and / or in any other convenient application. In this embodiment, the amount of CO 2 in the cathode exhaust gas may be related to the amount of CO 2 in the cathode feed stream and the CO 2 utilization in operating conditions required to improve or maximize the fuel cell energy output.

Additionally or alternatively, depending on the operating conditions, the MCFC may comprise up to about 5.0 vol%, such as up to about 4.0 vol%, or up to about 2.0 vol%, or up to about 1.5 vol%, of the CO 2 content in the cathode exhaust stream. , Or up to about 1.2% by volume. Additionally or alternatively, the CO 2 content in the cathode exhaust gas stream may be greater than or equal to about 0.9 vol%, such as greater than or equal to about 1.0 vol%, or greater than or equal to about 1.2 vol%, or greater than or equal to about 1.5 vol%.

Molten carbonate fuel cell operation

In some embodiments, the fuel cell may be operated in a single pass or perfusion mode. In the one pass system, the reformed product in the anode exhaust gas is not returned to the anode inlet. Therefore, in a single pass operation, some other products from syngas, hydrogen, or an anode product are not recycled directly to the anode inlet. More generally, in one pass operation, the reformed product in the anode exhaust gas is not indirectly returned to the anode inlet, for example, by treating the fuel stream subsequently introduced into the anode inlet using the modified product. Optionally, the CO 2 from the anode outlet can be recycled to the cathode inlet during operation of the MCFC in a one-pass mode. More generally, in some other embodiments, recirculation from the anode outlet to the cathode inlet can be made when operating the MCFC in a one-pass manner. In the one-pass mode, the heat from the anode exhaust gas or the product can be recycled, additionally or otherwise. For example, the anode output flow can be passed through a heat exchanger that cools the anode output and warms up an input stream of another stream, such as an anode and / or a cathode. The recirculation of heat from the anode to the fuel cell is consistent in one pass or perfusion operation. Optionally, but undesirably, the components of the anode product may be fired to provide heat to the fuel cell during the single pass mode.

Figure 3 shows a schematic example of the operation of the MCFC for generating power. In Figure 3, the anode portion of the fuel cell can receive fuel and water vapor (H 2 O) as inputs, and can contain water, CO 2 , and optionally H 2 , CH 4 (or other hydrocarbons) and / CO. The cathode portion of the fuel cell the output corresponding to CO 2 and some of the oxidant (e.g., air / O 2) of the received, there might be, O 2 is reduced in the depleted oxidant (air), the amount CO 2 as inputs . In the fuel cell, CO 3 2- ions formed at the cathode side can be transported across the electrolyte to provide the carbonate ions necessary for the reaction at the anode.

Several reactions can be made in a molten carbonate fuel cell, such as the exemplary fuel cell shown in FIG. The reforming reaction may be arbitrary and the reforming reaction may be reduced or eliminated if sufficient H 2 is provided directly to the anode. To the reaction but is based on CH 4, a similar reaction can take place when the other fuel is used in a fuel cell.

(1) <Anode modification> CH 4 + H 2 O => 3H 2 + CO

(2) <water gas phone> CO + H 2 O => H 2 + CO 2

(3) <Complex Modification and Water Gas Telephone> CH 4 + 2H 2 O => 4H 2 + CO 2

(4) <Anode H 2 oxidation> H 2 + CO 3 2- => H 2 O + CO 2 + 2e -

(5) <Cathode> ½O 2 + CO 2 + 2e - => CO 3 2-

Reaction (1) represents a basic hydrocarbon reforming reaction that generates H 2 for use in an anode of a fuel cell. The CO produced in reaction (1) can be converted to H 2 by water gas-catalyzed reaction (2). The combination of reactions (1) and (2) is shown as reaction (3). Reactions (1) and (2) may occur outside the fuel cell and / or the reforming may be performed within the anode.

Reactions (4) and (5) in the anodes and cathodes, respectively, indicate reactions that can generate power in the fuel cell. Reaction (4) combines H 2 generated by reactions (1) and / or (2) with carbonate ions either present in the feed or optionally in reaction (2) to form H 2 O, CO 2 and electrons to the circuit . Reaction (5) combines the electrons from O 2 , CO 2 , and the circuit to produce carbonate ions. Carbonate ions produced by the reaction (5) can be transported across the electrolyte of the fuel cell to provide the carbonate ions needed for the reaction (4). With the transport of carbonate ions across the electrolyte, a closed current loop can be formed by providing an electrical connection between the anode and the cathode.

In various embodiments, the purpose of fuel cell operation may be to improve the total efficiency of the fuel cell and / or the total efficiency of the chemical synthesis process integrated with the fuel cell. This is in contrast to the conventional operation of a fuel cell, which may typically be aimed at operating the fuel cell with high electrical efficiency to use the fuel provided to the cell for power generation. As defined above, the total fuel cell efficiency can be determined by dividing the sum of the electricity generation of the fuel cell and the low calorific value of the fuel cell output by the low calorific value of the input component of the fuel cell. In other words, LHV (in) and LHV (sg out) are the fuel components transferred to the fuel cell (for example, H 2 (in) , CH 4 and / or CO) and the anode means the LHV of the outlet stream flow or synthesis gas (H 2, CO and / or CO 2) of the. This can provide a measure of the sum of electrical and chemical energy generated by the fuel cell and / or the integrated chemical process. It is noted that under this definition of total efficiency, the thermal energy used in fuel cell / chemical synthesis systems used and / or integrated in fuel cells can contribute to total efficiency. However, any excess heat exchanged or otherwise recovered from a fuel cell or an integrated fuel cell / chemical synthesis system is excluded from this definition. Therefore, when excess heat is used from a fuel cell to generate water vapor, for example, for power generation by a steam turbine, this excess heat is excluded from the definition of total efficiency.

Several operating parameters can be manipulated to operate the fuel cell with an excess of modifiable fuel. Some parameters may be similar to the parameters currently recommended for fuel cell operation. In some embodiments, the cathode conditions and the temperature input to the fuel cell may be similar to those recommended in the literature. For example, the desired electrical efficiency and the desired total fuel cell efficiency can be achieved in a molten carbonate fuel cell over a typical fuel cell operating temperature range. In typical operation, the temperature can be increased across the fuel cell.

In another aspect, the operating parameters of the fuel cell may be deviated from typical conditions to operate the fuel cell such that the temperature is reduced from the anode inlet to the anode outlet and / or from the cathode inlet to the cathode outlet. For example, a reforming reaction that converts hydrocarbons to H 2 and CO is an endothermic reaction. The net thermal equilibrium in the fuel cell may be endothermic if a sufficient amount of modification relative to the oxidation amount of hydrogen generating the current is performed in the fuel cell anode. This may result in a temperature drop between the inlet and outlet of the fuel cell. During the endothermic operation, the temperature drop in the fuel cell can be controlled to keep the electrolyte in the fuel cell in a molten state.

The parameters that can be manipulated in such a manner as to differ from those currently recommended are the amount of fuel provided to the anode, the composition of the fuel provided to the anode, and / or the anode charge or cathode charge of the syngas from the anode exhaust The separation and capture of syngas in the anode effluent without significant recycle of the synthesis gas. In some embodiments, the syngas or hydrogen from the anode exhaust may not be directly or indirectly recycled to the anode input or the cathode input. In additional or other embodiments, a limited amount of recirculation may be achieved. In this embodiment, the amount recycled from the anode exhaust gas to the anode input and / or the cathode input may be less than about 10%, such as less than about 5% or less than about 1% by volume of the anode exhaust gas.

Additionally or alternatively, the operating purpose of the fuel cell may be to separate the CO 2 from the output stream of another process which, in addition to permitting generation, produces a combustion reaction or a CO 2 output stream. In such an embodiment, the combustion reaction (s) may be used to provide power to one or more generators or turbines, which may provide most of the power generated by the integrated generator / fuel cell system. Rather than operating the fuel cell to optimize power generation by the fuel cell, the system can be operated to improve the capture of carbon dioxide from the generator that is powered by combustion while reducing or minimizing the number of fuel cells required for carbon dioxide capture have. By selecting the appropriate configuration for the input and output flows of the fuel cell and also by selecting the appropriate operating conditions for the fuel cell, a desirable combination of total efficiency and carbon capture can be enabled.

In some embodiments, the fuel cell of the fuel cell array may be arranged such that only a single stage of the fuel cell (e.g., fuel cell stack) may be present. In this type of embodiment, the single-stage anode fuel utilization rate may represent the anode fuel utilization of the array. Another option may be that the fuel cell array may contain a plurality of anode stages and a plurality of cathode stages, wherein each anode stage has the same range of fuel utilization, for example, And has a fuel utilization rate within 10% of the value, for example, within 5% of the specified value. Another option may be that each anode stage has the same fuel utilization rate or a fuel utilization rate that is less than a specified value less than a specified amount, e.g., each anode stage is less than 10%, such as less than 5% It has a lower value than the specified value. As an illustrative example, a fuel cell array having a plurality of anode stages may have a respective anode stage within about 10% of the 50% fuel utilization, since each anode stage has a fuel utilization rate of about 40% to about 60% . As another example, a fuel cell array having a plurality of stages may have each anode stage with a maximum deviation of less than about 5% and less than or equal to 60% anode fuel utilization, with each anode stage having about 55% to about Equivalent to having a fuel utilization rate of 60%. In yet another example, at least one stage of the fuel cell in the fuel cell array may be operated at a fuel utilization rate of from about 30% to about 50%, for example, a plurality of fuel cell stages of the array may be operated at about 30% to about 50% Fuel ratio. More generally, any range of this type may be concurrent with any anode fuel utilization rate value defined herein.

Another additional or alternative option may include specifying a fuel utilization rate for a portion of the anode stage. For example, in some aspects of the invention, the anode fuel utilization rate for a first anode stage in a cascade arrangement, a second anode stage in a cascade arrangement, a final anode stage in a cascade arrangement, or any other convenient anode stage in a cascade arrangement The fuel cell / stack may be at least partially arranged in one or more tandem arrangements for clarification. The "first" stage of the tandem arrangement, as used herein, corresponds to a stage (or set of stages, where the arrangement also includes a parallel stage) in which the inputs are fed directly from the fuel source (s) , "Third &quot;," final &quot;, etc.) stages are not directly fed from the individual fuel source (s) but represent stages where the output from one or more previous stages is supplied. (Or a first set of stages) and a "final" stage (or a final set of stages) may be present if the direct input from the previous stage and the direct input from the fuel source , But other stages ("second", "third", etc.) may be difficult to establish order between them (for example, in this case, Quot; can be determined by the concentration level of one or more components, such as CO 2 , in the composite feed feed composition, with approximately similar composition differences representing the same order level).

Another additional or alternative option may be to specify an anode fuel utilization rate corresponding to a particular cathode stage (again, the fuel cell / stack may be arranged at least partially in one or more tandem arrangements). As indicated above, based on the direction of flow in the anode and cathode, the first cathode stage may not correspond to the first anode stage (from across the same fuel cell membrane). Therefore, in some aspects of the invention, an anode fuel cell is provided for a first cathode stage in a cascade arrangement, a second cathode stage in a cascade arrangement, a final cathode stage in a cascade arrangement, or any other convenient cathode stage in a cascade arrangement. You can specify the usage rate.

Another additional or alternative option may be to define the overall average of fuel utilization across all fuel cells of the fuel cell array. In various embodiments, the overall average of the fuel utilization of the fuel cell array may be less than or equal to about 65%, such as less than or equal to about 60%, less than or equal to about 55%, less than or equal to about 50%, or less than or equal to about 45% , The overall average of the fuel utilization of the fuel cell array may be at least about 25%, such as at least about 30%, at least about 35%, or at least about 40%. This average fuel utilization rate does not necessarily have to limit the fuel utilization rate for any single stage, as long as the array of fuel cells satisfies the desired fuel utilization rate.

After capture CO 2  Uses of Output

In various aspects of the invention, the systems and methods described above can produce carbon dioxide as a pressurized fluid. For example, CO 2 generated from a cryogenic separation stage may initially be pressurized CO 2 having a purity of at least about 90%, such as at least about 95%, at least about 97%, at least about 98%, or at least about 99% Liquid. The pressurized CO 2 stream can be used for injection into the wells to further improve oil or gas recovery, such as in a secondary refinery. When performed in the vicinity of a facility encompassing a gas turbine, the overall system may have the advantage of additional synergies through the use of power / mechanical power and / or thermal integration with the overall system.

Alternatively, in the case of a system dedicated to oil recovery enhancement (EOR) applications (ie, not mixed with pipeline systems with strict compositional criteria), the CO 2 separation conditions can be substantially mitigated. EOR applications may be in the sensitivity to the presence of O 2, O 2 thus may not be present in the CO 2 stream to be used for EOR in some embodiments. However, EOR applications may tend having a low sensitivity for the dissolved CO, H 2 and / or CH 4. In addition, pipelines carrying CO 2 may be susceptible to these impurities. These dissolved gases may typically have only a perceivable effect on the solubilising ability of CO 2 used in the EOR. Injecting a gas such as CO, H 2 and / or CH 4 as an EOR gas may cause some loss in calorie value recovery, but such gas is commercially available for EOR applications.

Additionally or alternatively, the possible use of CO 2 as a pressurized liquid may be a nutrient in a biological process such as algae cultivation / harvest. The use of MCFCs for CO 2 sequestration reduces the levels of most biologically important contaminants to an acceptable low level, leaving trace amounts of other "contaminated" gases (eg, toxic gases) that can not have a material adverse effect on the growth of photosynthetic organisms it is possible to produce a stream containing -, CO 2 with CO, H 2, N 2, etc., and combinations thereof). This can be contrasted with the output stream generated by most industrial sources (which may contain substances that can be highly toxic, often heavy metals).

In this type of embodiment of the present invention, the CO 2 stream generated by the separation of CO 2 in the anode loop can be used to produce biofuels and / or compounds as well as precursors thereof. Additionally or alternatively, CO 2 can be produced as a dense fluid, making it much easier to pumped and transport across a large distance, for example, over a large area of a photosynthetic organism. Conventional exhaust sources can release hot gases containing moderate amounts of CO 2 (e.g., about 4 to 15%) mixed with other gases and contaminants. These materials usually need to be pumped as a gas diluted with an algae pond or biofuel "farm &quot;. In contrast, the MCFC system according to the present invention can be enriched to 95% + (e.g., 96% +, 97% +, 98% +, or 99% +) 2 stream (about 60-70% by volume on a dry basis). This stream can then be easily and efficiently transported over long distances at relatively low cost and can be effectively distributed over a large area. In these embodiments, the residual heat from the combustion source / MCFC can be integrated into the overall system.

Other embodiments may be applied where the CO 2 source / MCFC and the biological / chemical production site are located together. In this case, minimal compression may be required (i.e., providing sufficient CO 2 pressure for use in biological production, such as from about 15 psig to about 150 psig). Several new arrangements may be possible in this case. By applying a second modification for the anode exhaust gas, optionally it is possible to reduce the CH 4 content, optionally is to perform the water gas shift additionally or alternatively to create any remaining CO into CO 2 and H 2.

The components from the anode output stream and / or the cathode output stream can be used for a variety of purposes. One option may be to use the anode product as a source of hydrogen as described above. For MCFCs that are integrated or co-located with the refinery, hydrogen can be used as a hydrogen source for a variety of refining processes such as hydro-processing. Another option may be to use hydrogen as fuel source, additionally or otherwise, if CO 2 from combustion is already "captured &quot;. Such hydrogen can be used as fuel for a boiler, furnace and / or flame heater in a refinery or other industrial facility, and / or hydrogen can be used as a feed for a generator such as a turbine. Hydrogen from an MCFC fuel cell may be additionally or otherwise used as an input stream for other types of fuel cells requiring hydrogen as input, possibly including vehicles that obtain power by the fuel cell. Another option may be to additionally or otherwise use the syngas generated as an output from the MCFC fuel cell as a fermentation input.

Another option may be to use additional or different syngas generated as the anode output. Of course, syngas based on fuel may still cause some CO 2 production when burned as fuel, but syngas can be used as fuel. In another embodiment, a syngas output stream may be used as the input for the chemical synthesis process. One option may be to use a Fischer-Tropsch type process, and / or to add or otherwise use syngas to another process in which larger hydrocarbon molecules are formed from the synthesis gas feed. Another option may be to use additional or different syngas to form an intermediate product such as methanol. Methanol can be used as the final product, but in other embodiments, methanol produced from the synthesis gas can be used to produce larger compounds such as gasoline, olefins, aromatics and / or other products. Note that a small amount of CO 2 may be allowed in the synthesis gas feed to the Fischer-Tropsch process using the methanol synthesis process and / or the morphology conversion catalyst. Hydroformylation is an additional or alternative example of another synthesis process in which synthesis gas feeds can be used.

One variation on the use of MCFCs to produce syngas is the use of MCFCs as part of a system for processing methane and / or natural gas recovered by coastal oil drilling platforms or other production systems with considerable distance from the ultimate market. It should be noted that fuel cells may be used. Instead of attempting to transport the meteorological product from the well, or attempting to store the meteorological product for an extended period of time, the meteorological product from the well can be used as an input to the MCFC fuel cell array. This can lead to various advantages. First, the power generated from the fuel cell array can be used as a power source for the platform. Additionally, the syngas product from the fuel cell array can be used as feed for the Fischer-Tropsch process at the production site. This can lead to the formation of liquid hydrocarbon products that are more easily transported from the production site to, for example, a land plant or larger terminal by pipeline, ship or motor vehicle.

Another integration option may additionally or otherwise include the use of cathode artifacts as a source of higher purity heated nitrogen. Cathode inputs can often contain large amounts of air, which means that a significant amount of nitrogen can be included in the cathode input. The fuel cell transports CO 2 and O 2 from the cathode to the anode across the electrolyte and the cathode product has a higher concentration of N 2 than the lower concentrations of CO 2 and O 2 , . This nitrogen product can be used as an input to produce ammonia, or other nitrogen-containing compounds (e.g., urea, ammonium nitrate, and / or nitric acid), with subsequent removal of residual O 2 and CO 2 . It is noted that the urea synthesis can use CO 2 separated from the anode product as an addition feed or additionally or otherwise.

Integrated example: for integration with combustion turbines

In some aspects of the invention, a combustion source for generating power or for exhausting CO 2 -containing exhaust gas may be integrated with the operation of the molten carbonate fuel cell. An example of a suitable combustion source is a gas turbine. Preferably, the gas turbine is capable of combusting natural gas, methane gas, or other hydrocarbon gas in a combined cycle mode integrated with steam recovery and heat recovery for additional efficiency. Currently, natural gas combined cycle efficiency is the largest and is about 60% of the latest design. It can be produced containing the exhaust stream - MCFC CO 2 generated by the operation and compatible elevated temperature, for example 700 to 300 ℃ ℃, preferably from 500 ℃ to 650 ℃. Prior to introduction into the turbine, sulfur-like contaminants that can contaminate the MCFC may be optionally but preferably cleaned from the gas source. Alternatively, the gas source may be a coal-fired generator, which in this case typically flushes the exhaust after combustion, due to the higher level of pollutants in the exhaust. In this alternative, some heat exchange from / to the gas may be needed to allow cleaning at low temperatures. In additional or alternative embodiments, the source of CO 2 -containing exhaust gas may be a boiler, combustor, or other heat source that burns carbon-rich fuel. In other additional or alternative embodiments, the source of the CO 2 -containing exhaust gas may be bio-generated CO 2 combined with other sources.

To integrate with a combustion source, several other configurations for treating the fuel cell anode may be desirable. For example, another configuration may be to recycle at least a portion of the exhaust gas from the fuel cell anode to the input of the fuel cell anode. The output stream from the MCFC anode may contain H 2 O, CO 2 , optionally CO, and optionally but typically unreacted fuel (eg, H 2 or CH 4 ) as the main output component. Instead of using this output stream as an external fuel stream and / or an input stream for integration with other processes, it is also possible to separate the CO 2 from components having a potential calorific value (e.g., H 2 or CO) One or more separations may be performed on the output stream. The component having the calorific value can then be recycled to the anode input.

This type of configuration can provide one or more advantages. First, it is possible to separate CO 2 from the anode product, for example, by using a cryogenic CO 2 separator. Some of the components of the anode output (H 2 , CO, CH 4 ) are components that can not be easily condensed, whereas CO 2 and H 2 O can be separated separately as condensed phases. According to an embodiment, at least about 90% by volume of CO 2 in the anode effluent can be separated to form a relatively high purity CO 2 output stream. Alternatively, in some embodiments, less CO 2 is removed from the anode product so that from about 50% to about 90%, such as less than about 80%, or less than about 70%, by volume of CO 2 in the anode product can be isolated can do. After separation, the remainder of the anode output may correspond to a component having primarily a calorific value, and a reduced amount of CO 2 and / or H 2 O. This portion of the anode output after separation may be recycled for use as part of the anode charge with additional fuel. In this type of configuration, the fuel utilization of the first pass through the MCFC (s) may be low, but the unused fuel may be advantageously recirculated for another pass through the anode. As a result, the one-pass fuel utilization rate may be at a reduced level while avoiding the loss (discharge) of unburned fuel to the environment.

In addition to or in lieu of recycling some of the anode exhaust gas to the anode input, another configuration option may be used as an input for the combustion reaction of a turbine or other combustion device (e.g., a boiler, furnace and / It may be using part of the gas. The relative amount of anode exhaust gas recycled to the anode input and / or as input to the combustion apparatus may be any convenient or desirable amount. When the anode exhaust gas is recycled only to one of the anode input and the combustion device, the amount of recycle may be adjusted to any convenient amount, for example up to 100% of the remaining anode exhaust gas fraction after removal of CO 2 and / or H 2 O by separation Lt; / RTI &gt; When a portion of the anode exhaust gas is recycled to both the anode input and the combustion apparatus, the total amount recycled by definition may be less than 100% of the remainder of the anode exhaust gas. Alternatively, any convenient split of the anode exhaust gas may be used. In various embodiments of the present invention, the amount of recycle into the anode input may be at least about 10%, such as at least about 25%, at least about 40%, at least about 50%, at least about 60% About 75% or more, or about 90% or more. In addition to or in addition to these embodiments, the amount of recycle into the anode input may be less than about 90%, such as less than about 75%, less than about 60%, less than about 50% of the remaining anode exhaust gas , About 40% or less, about 25% or less, or about 10% or less. Additionally or alternatively, in various embodiments of the present invention, the amount of recycle to the combustion apparatus can be at least about 10%, such as at least about 25%, at least about 40%, at least about 50% About 60% or more, about 75% or more, or about 90% or more. In addition to or in addition to these embodiments, the amount of recycle to the combustion apparatus may be less than about 90%, such as less than about 75%, less than about 60%, less than about 50% About 40% or less, about 25% or less, or about 10% or less.

In another embodiment of the present invention, the fuel for the combustion apparatus may additionally or alternatively be inert and / or a fuel having an increased amount of the component acting as a diluent in the fuel. CO 2 and N 2 are examples of components of a natural gas feed that can be relatively inert during the combustion reaction. Once the amount of inert components in the fuel feed reaches a sufficient level, the performance of the turbine or other combustion sources may be affected. The effect may be due in part to the ability of the inert component to absorb heat (which may tend to quench the combustion reaction). An example of a fuel feed with sufficient levels of inert components is a fuel feed containing about 20 vol% or more CO 2 , or a fuel feed containing about 40 vol% or more N 2 , It may comprise a fuel feed containing a combination of CO 2 and N 2 having a heat capacity inert. (Note that CO 2 has a greater heat capacity than N 2 , so lower CO 2 concentrations can have an effect similar to higher N 2 concentrations. CO 2 also participates in the combustion reaction more easily than N 2 number, and may do so to remove the H 2 from the combustion while. consumption of such a H 2 can reduce the flame speed and by narrowing the flammable range of the air-fuel mixture have a great influence on the combustion of fuel.) more Generally, for a fuel feed containing an inert component that affects the flammability of the fuel feed, the inert component in the fuel feed is at least about 20 vol%, such as at least about 40 vol%, or at least about 50 vol% Can be at least 60 vol.%. Preferably, the amount of inert component in the fuel feed may be less than about 80% by volume.

If a sufficient amount of inert component is present in the fuel feed, the resulting fuel feed may be outside the flammable window of the fuel component of the feed. In this type of situation, H 2 from the recycled portion of the anode exhaust gas can be added to the combustion zone of the generator to expand the flammability window of the combination of fuel feed and H 2 , for example, about 20 vol% Or more of CO 2 or about 40% by volume or more of N 2 (or another combination of CO 2 and N 2 ) can be successfully burned.

For the total volume of fuel feed and H 2 delivered to the combustion zone, the amount of H 2 to expand the flammable window is at least about 5% by volume, such as at least about 10% by volume of the total volume of fuel feed and H 2 , / Or about 25% by volume or less. Another option to characterize the amount of H 2 added to expand the flammable window may be based on the amount of fuel component present in the fuel feed prior to the addition of H 2 . The fuel component may correspond to methane, natural gas, other hydrocarbons, and / or other components commonly seen as a fuel for turbines or other generators powered by combustion. The amount of H 2 added to the fuel feed is about one-third (1: 3 ratio of H 2 : fuel component) of the volume of the fuel component in the fuel feed, eg, about 1/2 of the volume of the fuel component 1: 2 ratio). Additionally or alternatively, the amount of H 2 added to the fuel feed may be approximately equal to or less than the volume of the fuel component in the fuel feed (ratio of 1: 1). For example, in the case of a feed containing about 30 vol.% CH 4 , about 10% N 2, and about 60% CO 2 , an amount sufficient to attain a H 2 to CH 4 ratio of about 1: 2 Of the anode exhaust gas may be added to the fuel feed. H 2 only in the case of the idealized anode exhaust gas containing, 1: Addition of H 2 for obtaining a ratio of 2 is about 26% by volume of CH 4, 13% by volume of H 2, 9% by volume of N 2 and 52 Yielding a feed containing vol.% CO 2 .

Example of Integrated System

Figure 4 schematically illustrates an example of a serial turbine system integrated with a molten carbonate fuel cell. The system includes introducing both H 2 or CO from the CO 2 -containing recycle exhaust gas and the fuel cell anode exhaust gas into the combustion reaction to provide power to the turbine. The serial turbine system 402 is connected in series to introduce the exhaust gas from the turbine located in front of the process into the combustion chamber of the turbine, which is located behind the process, preferably through a compression zone of the turbine, And at least two turbines arranged. The serial turbine system is described in greater detail herein with reference to FIG. The serial turbine system generates a final exhaust gas 422 comprising at least CO 2 . In contrast to the system 500 shown in FIG. 5, the HRSG 560 can be optionally removed from the system when the exhaust gas 422 is introduced into the fuel cell, taking advantage of the increased temperature of the exhaust gas. Alternatively, the exhaust gas 422 may be heated before leaving the HRSG 560 and entering the fuel array 425.

The CO 2 -containing stream 422 may pass into the cathode portion (not shown) of the molten carbonate fuel cell array 425. Based on the reaction in the fuel cell array 425, CO 2 can be separated from the stream 422 and transported to the anode portion (not shown) of the fuel cell array 425. This can produce a CO 2 depleted cathode output stream 424. The cathode output stream 424 may then be subjected to heat recovery (and any optional heat recovery) for further development using a heat exchange and / or steam turbine 454 (which may optionally be identical to the steam turbine 494 described above) Steam generator) system 450 as shown in FIG. After passing through the heat recovery and steam generator system 450, the resulting flue gas stream 456 may be discharged to the environment and / or may be passed through other types of carbon capture techniques such as amine scrubbers.

After transport of CO 2 from the cathode side to the anode side of the fuel cell array 425, the anode output 435 may optionally be passed into the water gas telephone reactor 470. CO (and H 2 O) present in the anode output 435 can be used to generate additional H 2 and CO 2 using a water gas telephone reactor 470. The output from the optional water gas telephone reactor 470 can then be passed into one or more separation stages 440, such as a low temperature box or a cryogenic separator. Which can separate the H 2 O stream 447 and the CO 2 stream 449 from the remainder of the anode product. The remainder of the anode output 485 may be generated by reforming but may include unreacted H 2 not consumed in the fuel cell array 425. The first portion 445 of the H 2 -containing stream 485 may be recycled to the anode (s) input of the fuel cell array 425. A second portion 487 of stream 485 may be used as the input for the combustion zone of the first or second turbine of the serial turbine system 402. The third portion 465 may be used for other purposes and / or may be processed for subsequent uses. It is contemplated that FIG. 4 and the description of this disclosure outline the details of the three parts, but only one of these three parts can be utilized, only two can be utilized, or all three can be utilized in accordance with the present invention .

In various embodiments of the present invention, the process begins with a combustion reaction to provide power to the turbine, the internal combustion engine, or other systems in which the heat and / or pressure generated by the combustion reaction can be converted to other types of power Can be approached. The fuel for the combustion reaction may or may not include hydrogen, hydrocarbons, and / or any other compounds containing carbon that can be oxidized (burned) to release energy. Except in cases where the fuel contains only hydrogen, the composition of the exhaust gas from the combustion reaction may have a wide range of CO 2 content (for example, from about 2 vol% to about 25 vol%) depending on the nature of the reaction . Thus, in certain embodiments where the fuel is carbonaceous, the CO 2 content of the exhaust gas may be greater than or equal to about 2 vol%, such as greater than about 4 vol%, greater than about 5 vol%, greater than about 6 vol%, greater than about 8 vol% Or more, or about 10% by volume or more. In addition to or in addition to such carbonaceous fuel embodiments, the CO 2 content may be up to about 25% by volume, such as up to about 20% by volume, up to about 15% by volume, up to about 10% by volume, up to about 7% 5% by volume or less. The exhaust gas having a lower relative CO 2 content (in the case of carbonaceous fuel) may correspond to the exhaust gas from the combustion reaction in the fuel, such as natural gas, which exhibits lean (excess air) combustion. Exhaust gases with higher relative CO 2 contents (in the case of carbonaceous fuels) may correspond to combustion of an optimized natural gas combustion reaction, such as having exhaust gas recirculation and / or fuels such as coal.

In some aspects of the present invention, the fuel for combustion reaction may contain at least about 90 vol%, such as at least about 95 vol%, of compounds containing no more than five carbons. In this embodiment, the CO 2 content of the exhaust gas may be at least about 4% by volume, such as at least about 5% by volume, at least about 6% by volume, at least about 7% by volume, or at least about 7.5% by volume. Additionally or alternatively, the CO 2 content in the exhaust gas may be less than or equal to about 13 vol%, such as less than or equal to about 12 vol%, less than or equal to about 10 vol%, less than or equal to about 9 vol%, less than or equal to about 8 vol%, less than or equal to about 7 vol% Or about 6% by volume or less. The CO 2 content in the exhaust gas can represent a wide range of values depending on the configuration of the generator that is powered by combustion. Recirculation of exhaust gas, but may be advantageous in obtaining about 6% by volume or more of CO 2 content, the addition of hydrogen in the combustion reaction can be obtained from about 7.5% by volume or more of CO 2 content of the CO 2 content is increased further.

Additional embodiments

1. Introduction of a first oxygen stream and a first combustion fuel stream into a combustion chamber of a first combustion turbine; And generating electricity and a first exhaust gas by burning the first combustion fuel stream in the first combustion turbine wherein the first exhaust gas has a first exhaust O 2 concentration and a first exhaust CO 2 concentration, ; Introducing from the first exhaust gas at least about 50 mole percent of O 2 and at least about 50 mole percent of CO 2 into the combustion chamber of the second combustion turbine; Introducing a second combustion fuel stream into the combustion chamber of the second combustion turbine; Wherein the second exhaust gas has a second exhaust O 2 concentration and a second exhaust CO 2 concentration, wherein the second exhaust gas has a second exhaust O 2 concentration and a second exhaust CO 2 concentration, The ratio of the second exhaust CO 2 concentration to the first exhaust CO 2 concentration is at least about 1.3: 1); Wherein at least about 60 mole percent, or at least about 70 mole percent, or at least about 80 mole percent of O 2 is removed from the first exhaust gas, optionally separating CO 2 from at least a portion of the second exhaust gas At least about 60 mole percent, or at least about 70 mole percent, or at least about 80 mole percent of the CO 2 from the first exhaust gas may be introduced into the combustion chamber of the second combustion turbine, Which can be introduced into the combustion chamber of the turbine.

Embodiment 2. The method of Embodiment 1 wherein said first exhaust gas has a CO 2 mole fraction of at least about 3%, or at least about 4%, or at least about 5%, and optionally at least about 10%.

Embodiment 3. The method of Embodiment 1 or Embodiment 2 wherein the second exhaust gas has a CO 2 mole fraction of at least about 6%, or at least about 7%, or at least about 8%, and optionally at least about 20% Gt;

Embodiment 4. The method of any one of embodiments 1 to 6, wherein the method further comprises introducing the first exhaust gas into a heat recovery and steam generator before introducing at least a portion of the exhaust gas into the second combustion turbine. Lt; RTI ID = 0.0 &gt; 3, &lt; / RTI &gt;

5. The method embodiments is, the first prior to the introduction of the exhaust gas from at least about 50% of O 2 and about 50 mole% or more of CO 2 into the combustion chamber of the second combustion turbine wherein the first exhaust gas air &Lt; RTI ID = 0.0 &gt; 4. &Lt; / RTI &gt;

6. The method of embodiment 6 wherein the ratio of the second exhaust CO 2 concentration to the first exhaust CO 2 concentration is at least about 1.4: 1, such as at least about 1.5: 1, at least about 1.6: 1, at least about 1.7: : 1 or more, and / or optionally, about 2.0: 1 or less.

Embodiment 7. The first exhaust O 2 concentration is not more than about 15 mol%, for example about 14 mol% or less, about 12 mol% or less, or about 10 mol%, and the second exhaust O 2 concentration is about 7 mol% or less, such as about 6 mol% or less, or about 5 mol% or less.

Embodiment 8. The method of claim 8, wherein separating CO 2 from at least a portion of the second exhaust gas introduces at least a portion of the second exhaust gas into a cathode of the molten carbonate fuel cell; Introducing an anode fuel stream comprising a reformable fuel into an anode of the molten carbonate fuel cell, an internal reforming element entrained in the anode, or a combination thereof; Generating electricity in the molten carbonate fuel cell; The method of any one of embodiments 1 to 7, comprising generating an anode exhaust gas comprising H 2 , CO and CO 2 from the molten carbonate fuel cell.

Embodiment 9. The method of Embodiment 8, wherein the method further comprises performing a water gas telephone process on at least a portion of the anode exhaust gas.

Embodiment 10. The method of Embodiment 8 or Embodiment 9, wherein the method further comprises separating CO 2 from at least a portion of the anode exhaust gas.

Embodiment 11. The first combustion fuel stream, the second embodiment the combustion fuel stream, reforming, which can anode fuel stream comprising fuel, or a combination thereof from about 10% by volume or more of CO 2 embodiment 8 to embodiment 10 of the The method of any one embodiment.

Embodiment 12. The method of any of embodiments 8 to 11, further comprising forming the H 2 -containing stream from at least a portion of the anode exhaust gas.

Embodiment 13. An apparatus according to any of embodiments 8 to 12, wherein methane occupies at least about 90% by volume of the first combustion fuel stream, the second combustion fuel stream, the anode fuel stream comprising a reformable fuel, or a combination thereof. The method of one embodiment.

Embodiment 14. The method of any one of embodiments 8 to 13, wherein the fuel cell is operated at a temperature ratio of from about 0.25 to about 1.3, optionally up to about 1.0, or up to about 0.9.

15. The method of embodiment 15 wherein the amount of reformable fuel introduced into the anode, the internal reforming entities associated with the anode, or combinations thereof is greater than the amount of hydrogen that reacts in the molten carbonate fuel cell to generate electricity. %, Or more than about 100%. &Lt; RTI ID = 0.0 &gt; 14. &lt; / RTI &gt;

16. The method of claim 1 wherein the fuel cell is operated to generate power at a current density of at least about 150 mA / cm 2 and a waste heat of at least about 40 mW / cm 2 , the method comprising: 15. The method of any one of embodiments 8 to 15, further comprising performing an endothermic reaction in an amount effective to maintain the temperature at or below about &lt; RTI ID = 0.0 &gt;&lt; / RTI &gt;

Embodiment 17. The method of embodiment 8 wherein the electrical efficiency of the fuel cell is from about 10% to about 40% and the total fuel cell efficiency of the fuel cell is at least about 55%, such as at least about 65% or at least about 75% &Lt; RTI ID = 0.0 &gt; 16. &lt; / RTI &gt;

Embodiment 18. The method of any one of Embodiments 1 to 6, wherein at least about 90 mole percent, for example at least about 95 mole percent, or at least about 99 mole percent of the CO 2 from the first exhaust gas is introduced into the combustion chamber of the second combustion turbine. The method of any one of embodiment &lt; RTI ID = 0.0 &gt; 17. &lt; / RTI &

Embodiment 19. The method of any one of embodiments 1 to 18, wherein the remaining portion of O 2 and CO 2 is recycled from the first exhaust gas to the combustion zone of the first combustion turbine.

Claims (19)

  1. Introducing a first oxygen stream and a first combustion fuel stream into a combustion chamber of a first combustion turbine;
    And generating electricity and a first exhaust gas by burning the first combustion fuel stream in the first combustion turbine wherein the first exhaust gas has a first exhaust O 2 concentration and a first exhaust CO 2 concentration, ;
    Introducing from the first exhaust gas at least about 50 mole percent of O 2 and at least about 50 mole percent of CO 2 into the combustion chamber of the second combustion turbine;
    Introducing a second combustion fuel stream into the combustion chamber of the second combustion turbine;
    Wherein the second exhaust gas has a second exhaust O 2 concentration and a second exhaust CO 2 concentration, wherein the second exhaust gas has a second exhaust O 2 concentration and a second exhaust CO 2 concentration, The ratio of the second exhaust CO 2 concentration to the first exhaust CO 2 concentration is at least about 1.3: 1);
    Separating CO 2 from at least a portion of the second exhaust gas
    / RTI &gt;
    Optionally, at least about 60 mole percent, or at least about 70 mole percent, or at least about 80 mole percent of O 2 may be introduced into the combustion chamber of the second combustion turbine from the first exhaust gas, Wherein at least about 60 mole percent, or at least about 70 mole percent, or at least about 80 mole percent of the CO 2 from the first exhaust gas can be introduced into the combustion chamber of the second combustion turbine.
  2. The method according to claim 1,
    Wherein the first exhaust gas has a CO 2 mole fraction of at least about 3%, or at least about 4%, or at least about 5%, and / or optionally at least about 10%.
  3. 3. The method according to claim 1 or 2,
    Wherein the second exhaust gas has a CO 2 mole fraction of at least about 6%, such as at least about 7%, or at least about 8%, and / or optionally at least about 20%.
  4. 4. The method according to any one of claims 1 to 3,
    Wherein the method further comprises introducing the first exhaust gas into a heat recovery and steam generator before introducing at least a portion of the exhaust gas into the second combustion turbine.
  5. 5. The method according to any one of claims 1 to 4,
    That the said method is, wherein the addition of the first exhaust air prior to introduction into the combustion chamber of the first exhaust gas from at least about 50% of O 2 and the second combustion turbine wherein about 50 mole% or more of CO 2 &Lt; / RTI &gt;
  6. 6. The method according to any one of claims 1 to 5,
    Wherein the ratio of the second exhaust CO 2 concentration to the first exhaust CO 2 concentration is at least about 1.4: 1, such as at least about 1.5: 1, at least about 1.6: 1, at least about 1.7: And / or optionally about 2.0: 1 or less.
  7. 7. The method according to any one of claims 1 to 6,
    The first exhaust O 2 concentration is less than or equal to about 15 mol%, such as less than or equal to about 14 mol%, less than or equal to about 12 mol%, or less than or equal to about 10 mol%, and the second exhaust O 2 concentration is less than or equal to about 7 mol% , Such as up to about 6 mole percent, or up to about 5 mole percent.
  8. 8. The method according to any one of claims 1 to 7,
    Separating CO 2 from at least a portion of the second exhaust gas,
    Introducing at least a portion of the second exhaust gas into a cathode of the molten carbonate fuel cell;
    Introducing an anode fuel stream comprising a reformable fuel into an anode of the molten carbonate fuel cell, an internal reforming element entrained in the anode, or a combination thereof;
    Generating electricity in the molten carbonate fuel cell;
    Generating an anode exhaust gas containing H 2 , CO and CO 2 from the molten carbonate fuel cell
    &Lt; / RTI &gt;
  9. 9. The method of claim 8,
    Wherein the method further comprises performing a water gas telecommunication process on at least a portion of the anode exhaust gas.
  10. 10. The method according to claim 8 or 9,
    Wherein the method further comprises separating CO 2 from at least a portion of the anode exhaust gas.
  11. 11. The method according to any one of claims 8 to 10,
    Wherein the first combustion fuel stream, the second combustion fuel stream, the anode fuel stream comprising a reformable fuel, or a combination thereof comprises at least about 10% by volume CO 2 .
  12. 12. The method according to any one of claims 8 to 11,
    Wherein the method further comprises forming an H 2 -containing stream from at least a portion of the anode exhaust gas.
  13. 13. The method according to any one of claims 8 to 12,
    Methane accounts for at least about 90% by volume of the first combustion fuel stream, the second combustion fuel stream, the anode fuel stream comprising the reformable fuel, or a combination thereof.
  14. The method according to any one of claims 8 to 13,
    Wherein the fuel cell is operated at a thermal ratio of from about 0.25 to about 1.3, optionally up to about 1.0, or up to about 0.9.
  15. 15. The method according to any one of claims 8 to 14,
    Wherein the amount of reformable fuel introduced into the anode, the internal reforming element followed by the anode, or a combination thereof is at least about 75% greater than the amount of hydrogen reacting in the molten carbonate fuel cell to generate electricity, or More than 100% more, way.
  16. The method according to any one of claims 8 to 15,
    The fuel cell was operated to about 150mA / cm 2 or more, and the current density of power generation of about 40mW / cm 2 or more waste heat,
    Wherein the method further comprises performing an endothermic reaction in an amount effective to maintain a temperature difference between the anode inlet and the anode outlet at about 100 DEG C or less.
  17. 17. The method according to any one of claims 8 to 16,
    Wherein the fuel cell has an electrical efficiency of about 10% to about 40% and a total fuel cell efficiency of the fuel cell is at least about 55%, such as at least about 65% or at least about 75%.
  18. 18. The method according to any one of claims 1 to 17,
    Introducing at least about 90 mole percent, for example at least about 95 mole percent, or at least about 99 mole percent, of the CO 2 from the first exhaust gas into the combustion chamber of the second combustion turbine.
  19. 19. The method according to any one of claims 1 to 18,
    And recycling the remaining portion of O 2 and CO 2 from the first exhaust gas to the combustion zone of the first combustion turbine.
KR1020167011211A 2013-03-15 2014-09-29 Power generation and co_2 capture with turbines in series KR20160062139A (en)

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US201361884635P true 2013-09-30 2013-09-30
US201361884586P true 2013-09-30 2013-09-30
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US201361884545P true 2013-09-30 2013-09-30
US201361884605P true 2013-09-30 2013-09-30
US201361884376P true 2013-09-30 2013-09-30
US61/884,586 2013-09-30
US61/884,565 2013-09-30
US61/884,605 2013-09-30
US61/884,376 2013-09-30
US61/884,545 2013-09-30
US61/884,635 2013-09-30
US201361889757P true 2013-10-11 2013-10-11
US61/889,757 2013-10-11
US14/197,430 US20140272614A1 (en) 2013-03-15 2014-03-05 Integrated power generation and carbon capture using fuel cells
US14/197,613 2014-03-05
US14/197,391 US20140272613A1 (en) 2013-03-15 2014-03-05 Integrated power generation and carbon capture using fuel cells
US14/197,551 2014-03-05
US14/197,430 2014-03-05
US14/197,391 2014-03-05
US14/197,613 US9774053B2 (en) 2013-03-15 2014-03-05 Integrated power generation and carbon capture using fuel cells
US14/197,551 US20140272615A1 (en) 2013-03-15 2014-03-05 Integrated power generation and carbon capture using fuel cells
US14/207,699 US20140272635A1 (en) 2013-03-15 2014-03-13 Mitigation of NOx in Integrated Power Production
US14/207,693 2014-03-13
US14/207,691 2014-03-13
US14/207,721 US9520607B2 (en) 2013-03-15 2014-03-13 Integration of molten carbonate fuel cells with fermentation processes
US14/207,687 US9941534B2 (en) 2013-03-15 2014-03-13 Integrated power generation and carbon capture using fuel cells
US14/207,697 US9923219B2 (en) 2013-03-15 2014-03-13 Integrated operation of molten carbonate fuel cells
US14/207,708 2014-03-13
US14/207,714 US9343764B2 (en) 2013-03-15 2014-03-13 Integration of molten carbonate fuel cells in methanol synthesis
US14/207,728 US20140261090A1 (en) 2013-03-15 2014-03-13 Integration of Molten Carbonate Fuel Cells in Cement Processing
US14/207,686 US20140272633A1 (en) 2013-03-15 2014-03-13 Integrated power generation and carbon capture using fuel cells
US14/207,693 US9786939B2 (en) 2013-03-15 2014-03-13 Integrated power generation and chemical production using fuel cells
US14/207,699 2014-03-13
US14/207,714 2014-03-13
US14/207,708 US9647284B2 (en) 2013-03-15 2014-03-13 Integration of molten carbonate fuel cells in Fischer-Tropsch synthesis
US14/207,712 US9343763B2 (en) 2013-03-15 2014-03-13 Integration of molten carbonate fuel cells for synthesis of nitrogen compounds
US14/207,687 2014-03-13
US14/207,726 US9263755B2 (en) 2013-03-15 2014-03-13 Integration of molten carbonate fuel cells in iron and steel processing
US14/207,686 2014-03-13
US14/207,711 2014-03-13
US14/207,710 2014-03-13
US14/207,711 US9735440B2 (en) 2013-03-15 2014-03-13 Integration of molten carbonate fuel cells in fischer-tropsch synthesis
US14/207,698 2014-03-13
US14/207,697 2014-03-13
US14/207,706 2014-03-13
US14/207,710 US9362580B2 (en) 2013-03-15 2014-03-13 Integration of molten carbonate fuel cells in a refinery setting
US14/207,712 2014-03-13
US14/207,690 US9553321B2 (en) 2013-03-15 2014-03-13 Integrated power generation and carbon capture using fuel cells
US14/207,721 2014-03-13
US14/207,726 2014-03-13
US14/207,691 US9257711B2 (en) 2013-03-15 2014-03-13 Integrated carbon capture and chemical production using fuel cells
US14/207,698 US9419295B2 (en) 2013-03-15 2014-03-13 Integrated power generation and chemical production using fuel cells at a reduced electrical efficiency
US14/207,690 2014-03-13
US14/207,728 2014-03-13
US14/207,706 US9455463B2 (en) 2013-03-15 2014-03-13 Integrated electrical power and chemical production using fuel cells
US14/315,439 US9077005B2 (en) 2013-03-15 2014-06-26 Integration of molten carbonate fuel cells in Fischer-Tropsch synthesis
US14/315,439 2014-06-26
US14/315,479 US9077006B2 (en) 2013-03-15 2014-06-26 Integrated power generation and carbon capture using fuel cells
US14/315,507 US9077007B2 (en) 2013-03-15 2014-06-26 Integrated power generation and chemical production using fuel cells
US14/315,527 2014-06-26
US14/315,527 US9077008B2 (en) 2013-03-15 2014-06-26 Integrated power generation and chemical production using fuel cells
US14/315,419 2014-06-26
US14/315,479 2014-06-26
US14/315,419 US9178234B2 (en) 2013-03-15 2014-06-26 Integrated power generation using molten carbonate fuel cells
US14/315,507 2014-06-26
US14/486,200 US9556753B2 (en) 2013-09-30 2014-09-15 Power generation and CO2 capture with turbines in series
US14/486,200 2014-09-15
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US7396603B2 (en) * 2004-06-03 2008-07-08 Fuelcell Energy, Inc. Integrated high efficiency fossil fuel power plant/fuel cell system with CO2 emissions abatement
US7266940B2 (en) * 2005-07-08 2007-09-11 General Electric Company Systems and methods for power generation with carbon dioxide isolation
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