EP2342429A2 - Centrale igcc (gazéification intégrée à un cycle combiné) avec recyclage des gaz de fumée et gaz de balayage - Google Patents

Centrale igcc (gazéification intégrée à un cycle combiné) avec recyclage des gaz de fumée et gaz de balayage

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Publication number
EP2342429A2
EP2342429A2 EP09776071A EP09776071A EP2342429A2 EP 2342429 A2 EP2342429 A2 EP 2342429A2 EP 09776071 A EP09776071 A EP 09776071A EP 09776071 A EP09776071 A EP 09776071A EP 2342429 A2 EP2342429 A2 EP 2342429A2
Authority
EP
European Patent Office
Prior art keywords
gas
membrane
power plant
hydrogen
igcc power
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Withdrawn
Application number
EP09776071A
Other languages
German (de)
English (en)
Inventor
Ernst Riensche
Reinhard Menzer
Ludger Blum
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Forschungszentrum Juelich GmbH
Original Assignee
Forschungszentrum Juelich GmbH
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Forschungszentrum Juelich GmbH filed Critical Forschungszentrum Juelich GmbH
Publication of EP2342429A2 publication Critical patent/EP2342429A2/fr
Withdrawn legal-status Critical Current

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Classifications

    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F01—MACHINES OR ENGINES IN GENERAL; ENGINE PLANTS IN GENERAL; STEAM ENGINES
    • F01K—STEAM ENGINE PLANTS; STEAM ACCUMULATORS; ENGINE PLANTS NOT OTHERWISE PROVIDED FOR; ENGINES USING SPECIAL WORKING FLUIDS OR CYCLES
    • F01K23/00—Plants characterised by more than one engine delivering power external to the plant, the engines being driven by different fluids
    • F01K23/02—Plants 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
    • F01K23/06—Plants 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
    • F01K23/067—Plants 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 the combustion heat coming from a gasification or pyrolysis process, e.g. coal gasification
    • F01K23/068—Plants 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 the combustion heat coming from a gasification or pyrolysis process, e.g. coal gasification in combination with an oxygen producing plant, e.g. an air separation plant
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B13/00—Oxygen; Ozone; Oxides or hydroxides in general
    • C01B13/02—Preparation of oxygen
    • C01B13/0229—Purification or separation processes
    • C01B13/0248—Physical processing only
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B3/00—Hydrogen; Gaseous mixtures containing hydrogen; Separation of hydrogen from mixtures containing it; Purification of hydrogen
    • C01B3/02—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen
    • C01B3/06—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of inorganic compounds containing electro-positively bound hydrogen, e.g. water, acids, bases, ammonia, with inorganic reducing agents
    • C01B3/12—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of inorganic compounds containing electro-positively bound hydrogen, e.g. water, acids, bases, ammonia, with inorganic reducing agents by reaction of water vapour with carbon monoxide
    • C01B3/16—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of inorganic compounds containing electro-positively bound hydrogen, e.g. water, acids, bases, ammonia, with inorganic reducing agents by reaction of water vapour with carbon monoxide using catalysts
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B3/00—Hydrogen; Gaseous mixtures containing hydrogen; Separation of hydrogen from mixtures containing it; Purification of hydrogen
    • C01B3/50—Separation of hydrogen or hydrogen containing gases from gaseous mixtures, e.g. purification
    • C01B3/501—Separation of hydrogen or hydrogen containing gases from gaseous mixtures, e.g. purification by diffusion
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F02—COMBUSTION ENGINES; HOT-GAS OR COMBUSTION-PRODUCT ENGINE PLANTS
    • F02C—GAS-TURBINE PLANTS; AIR INTAKES FOR JET-PROPULSION PLANTS; CONTROLLING FUEL SUPPLY IN AIR-BREATHING JET-PROPULSION PLANTS
    • F02C3/00—Gas-turbine plants characterised by the use of combustion products as the working fluid
    • F02C3/20—Gas-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
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F02—COMBUSTION ENGINES; HOT-GAS OR COMBUSTION-PRODUCT ENGINE PLANTS
    • F02C—GAS-TURBINE PLANTS; AIR INTAKES FOR JET-PROPULSION PLANTS; CONTROLLING FUEL SUPPLY IN AIR-BREATHING JET-PROPULSION PLANTS
    • F02C3/00—Gas-turbine plants characterised by the use of combustion products as the working fluid
    • F02C3/20—Gas-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
    • F02C3/26—Gas-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 solid or pulverulent, e.g. in slurry or suspension
    • F02C3/28—Gas-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 solid or pulverulent, e.g. in slurry or suspension using a separate gas producer for gasifying the fuel before combustion
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F02—COMBUSTION ENGINES; HOT-GAS OR COMBUSTION-PRODUCT ENGINE PLANTS
    • F02C—GAS-TURBINE PLANTS; AIR INTAKES FOR JET-PROPULSION PLANTS; CONTROLLING FUEL SUPPLY IN AIR-BREATHING JET-PROPULSION PLANTS
    • F02C6/00—Plural gas-turbine plants; Combinations of gas-turbine plants with other apparatus; Adaptations of gas-turbine plants for special use
    • F02C6/18—Plural 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
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F22—STEAM GENERATION
    • F22B—METHODS OF STEAM GENERATION; STEAM BOILERS
    • F22B1/00—Methods of steam generation characterised by form of heating method
    • F22B1/02—Methods of steam generation characterised by form of heating method by exploitation of the heat content of hot heat carriers
    • F22B1/18—Methods of steam generation characterised by form of heating method by exploitation of the heat content of hot heat carriers the heat carrier being a hot gas, e.g. waste gas such as exhaust gas of internal-combustion engines
    • F22B1/1807—Methods of steam generation characterised by form of heating method by exploitation of the heat content of hot heat carriers the heat carrier being a hot gas, e.g. waste gas such as exhaust gas of internal-combustion engines using the exhaust gases of combustion engines
    • F22B1/1815—Methods of steam generation characterised by form of heating method by exploitation of the heat content of hot heat carriers the heat carrier being a hot gas, e.g. waste gas such as exhaust gas of internal-combustion engines using the exhaust gases of combustion engines using the exhaust gases of gas-turbines
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F22—STEAM GENERATION
    • F22B—METHODS OF STEAM GENERATION; STEAM BOILERS
    • F22B1/00—Methods of steam generation characterised by form of heating method
    • F22B1/02—Methods of steam generation characterised by form of heating method by exploitation of the heat content of hot heat carriers
    • F22B1/18—Methods of steam generation characterised by form of heating method by exploitation of the heat content of hot heat carriers the heat carrier being a hot gas, e.g. waste gas such as exhaust gas of internal-combustion engines
    • F22B1/1838—Methods of steam generation characterised by form of heating method by exploitation of the heat content of hot heat carriers the heat carrier being a hot gas, e.g. waste gas such as exhaust gas of internal-combustion engines the hot gas being under a high pressure, e.g. in chemical installations
    • F22B1/1846—Methods of steam generation characterised by form of heating method by exploitation of the heat content of hot heat carriers the heat carrier being a hot gas, e.g. waste gas such as exhaust gas of internal-combustion engines the hot gas being under a high pressure, e.g. in chemical installations the hot gas being loaded with particles, e.g. waste heat boilers after a coal gasification plant
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/04—Integrated processes for the production of hydrogen or synthesis gas containing a purification step for the hydrogen or the synthesis gas
    • C01B2203/0465—Composition of the impurity
    • C01B2203/0475—Composition of the impurity the impurity being carbon dioxide
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2210/00—Purification or separation of specific gases
    • C01B2210/0043—Impurity removed
    • C01B2210/0046—Nitrogen
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F05—INDEXING SCHEMES RELATING TO ENGINES OR PUMPS IN VARIOUS SUBCLASSES OF CLASSES F01-F04
    • F05D—INDEXING SCHEME FOR ASPECTS RELATING TO NON-POSITIVE-DISPLACEMENT MACHINES OR ENGINES, GAS-TURBINES OR JET-PROPULSION PLANTS
    • F05D2220/00—Application
    • F05D2220/30—Application in turbines
    • F05D2220/31—Application in turbines in steam turbines
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F05—INDEXING SCHEMES RELATING TO ENGINES OR PUMPS IN VARIOUS SUBCLASSES OF CLASSES F01-F04
    • F05D—INDEXING SCHEME FOR ASPECTS RELATING TO NON-POSITIVE-DISPLACEMENT MACHINES OR ENGINES, GAS-TURBINES OR JET-PROPULSION PLANTS
    • F05D2220/00—Application
    • F05D2220/30—Application in turbines
    • F05D2220/32—Application in turbines in gas turbines
    • Y—GENERAL 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
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02E—REDUCTION OF GREENHOUSE GAS [GHG] EMISSIONS, RELATED TO ENERGY GENERATION, TRANSMISSION OR DISTRIBUTION
    • Y02E20/00—Combustion technologies with mitigation potential
    • Y02E20/16—Combined cycle power plant [CCPP], or combined cycle gas turbine [CCGT]
    • Y—GENERAL 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
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02E—REDUCTION OF GREENHOUSE GAS [GHG] EMISSIONS, RELATED TO ENERGY GENERATION, TRANSMISSION OR DISTRIBUTION
    • Y02E20/00—Combustion technologies with mitigation potential
    • Y02E20/16—Combined cycle power plant [CCPP], or combined cycle gas turbine [CCGT]
    • Y02E20/18—Integrated gasification combined cycle [IGCC], e.g. combined with carbon capture and storage [CCS]
    • Y—GENERAL 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
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
    • Y02P20/00—Technologies relating to chemical industry
    • Y02P20/10—Process efficiency
    • Y—GENERAL 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
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
    • Y02P20/00—Technologies relating to chemical industry
    • Y02P20/10—Process efficiency
    • Y02P20/129—Energy recovery, e.g. by cogeneration, H2recovery or pressure recovery turbines

Definitions

  • the invention relates to a power plant, in particular IGCC (Integrated Gasification Combined Cycle) power plant and a method for operating the same.
  • IGCC Integrated Gasification Combined Cycle
  • IGCC Integrated Gasification Combined Cycle.
  • IGCC power plants are gas and steam turbine power plants (CCGTs), which are preceded by a coal gasification stage.
  • CCGTs gas and steam turbine power plants
  • a combustible gas containing carbon monoxide and hydrogen is generated substoichiometrically from coal in a gasifier ( ⁇ approximately between 0.2 and 0.4).
  • oil, refinery residues, biomass or waste can be used.
  • the product gas is purified and fed to the gas and steam turbine process. With this method can be a carburetor efficiency of 0.6 and at residual heat use such a 0.8 reach.
  • the IGCC process enables the technically simple carbon dioxide separation before the actual combustion process, since physically favorable conditions for the separation in the form of a high total pressure and high concentrations of the gas components to be separated CO 2 or H 2 are present.
  • the carbon monoxide produced during the gasification can first be converted into carbon dioxide by means of steam in a shift stage and this can then be easily separated off due to the high pressure and sent to final storage. This is a significant advantage over techniques where the carbon dioxide needs to be removed from the flue gas.
  • the flue gas contains at atmospheric combustion over 80 percent nitrogen, the separation of which means considerable effort.
  • the IGCC technology can thus make a significant contribution to reducing carbon dioxide emissions and thus reducing the man-made greenhouse effect.
  • Another advantage of the IGCC is the use of a gas turbine with generator, which generates electrical energy from the combustion of the gas, and the combined use of the waste heat of this gas turbine in a downstream steam turbine. System efficiencies from 50 to 55 percent are achievable today and are well above the 40 to 45 percent of a normal coal-fired power plant.
  • a gas and steam combined cycle power plant is a power plant that combines the principles of a gas turbine power plant and a steam power plant.
  • a gas turbine serves as a heat source for a downstream waste heat boiler, which in turn acts as a steam generator for the steam turbine.
  • this coal gas is burned in the combustion chamber of the gas turbine and a part of the energy adhering to the gas is converted into mechanical energy by relaxation in a turbine process.
  • the existing sensible heat is utilized in a subsequent steam turbine process.
  • the concentration of carbon dioxide, CO 2 , in the flue gas of this process is low. It is typically less than 10% by volume.
  • a separation of the CO 2 from the flue gas can be carried out with the same method as is possible with today's conventional steam power plants. It should be noted that with decreasing concentration of CO 2 in the flue gas, the technical complexity for the separation of CO 2 increases. The technical effort to separate the CO 2 has a negative impact on the efficiency of the process.
  • Separation of the coal gas into a fuel gas containing no or only a small amount of carbon compounds CO (carbon monoxide) and CO 2 (carbon dioxide), and a gas stream containing exclusively or predominantly CO and CO 2 , is for the process of separation of the CO 2 and its conditioning for a disposal advantageous.
  • One possibility is to effect a separation of the hydrogen with a hydrogen membrane from a modified coal gas enriched by means of the shift reaction with hydrogen.
  • This leads to a residual gas, which, depending on the process, can contain such a high proportion of CO 2 , which makes it possible, if necessary, to liquefy the residual gas and thus to prepare it for disposal.
  • This goal can be achieved, for example, with an exclusively or predominantly hydrogen-permeable membrane.
  • the membrane is used without further flushing, that is, the hydrogen diffuses due to the reduced pressure on the permeate side by the natural driving force through the membrane. A strong reduction of the pressure is necessary to ensure sufficient driving force during the separation process and thus to achieve a sufficiently high degree of separation of the hydrogen.
  • the hydrogen produced in this way must first be compressed by very low pressures to pressures of approximately 25 bar, before it can be fed to the combustion chamber.
  • This H 2 recompression is energetically significantly complex and a major cause of the high efficiency losses of this procedure.
  • the purge gas has therefore changed at the exit from the membrane and now consists of about half of N 2 and H 2 .
  • the H 2 partial pressure has risen to a value about half the total permeate pressure.
  • the H 2 partial pressure is about half of the total pressure. This results in a hardly different from zero driving force in the membrane with the As a consequence, high degrees of separation for H 2 can at best only be achieved with intolerably large membrane areas.
  • DE 10 2008 011 771 describes another IGCC power plant with H 2 membranes, in which the first purge gas source in the form of the LZA is supplemented by a further, powerful purge gas source.
  • the flue gas from the downstream steam turbine can be returned to the combustion chamber of the gas turbine (see Figure 5).
  • the flue gas recirculation after stoichiometric air combustion represents a second possible purge gas source, which is characterized by a low oxygen content.
  • part of the already under high pressure exhaust gas of the combustion chamber of the gas turbine is guided to the permeate side of the membrane.
  • the exhaust gas from the combustion chamber regularly has temperatures above 1200 0 C, so that the flue gas must first be cooled before being fed to the H 2 membrane.
  • the high-temperature recuperators required for this are generally not cheap, or not available and may even cause energy losses by z.
  • B. Providing a final cooler at the end of the hot side of the recuperator, which adversely affects the energy balance of the entire system.
  • the object of the invention is to provide an improved IGCC power plant, in which a pressurized exhaust gas is generated, which consists almost exclusively of CO 2 , and can therefore be liquefied with only a small additional energy input. Furthermore, it is the object of the invention to provide such an IGCC power plant with simplified process control combined with an improved energy performance compared to the known state of the art. serten supply of purge gases to provide. Furthermore, it is the object of the invention to provide a method for operating such an IGCC power plant, which has the aforementioned properties.
  • the invention relates to an IGCC power plant with membranes for the separation of gases using purge gases and a method for operating the same, which advantageously allows the recovery of purge gases within the IGCC Pozesses.
  • the principle of the power plant according to the invention is based on the already known by divine [1] IGCC power plant with membrane, in which, however, advantageously the purge gas for the membrane is not external, z. B. is provided by an air separation plant, but this purge gas is taken mainly directly from the process itself.
  • the flue gas / exhaust gas of the combustion chamber of the gas turbine is used as a membrane purge gas, and further a flue gas recirculation of the exhaust gas from the waste heat boiler is provided back to the combustion chamber of the gas turbine
  • in the present invention advantageously a part of the exhaust gas of the gas turbine after passing through the waste heat boiler for the steam turbine now used directly as a purge gas for the H 2 membrane and compressed already before the membrane to the required pressure of the subsequent combustion.
  • the process according to the invention presented here is particularly advantageous over the usual IGCC processes because it leads to an exhaust gas which consists almost exclusively of CO 2 , which is also produced under pressure.
  • This exhaust gas can be liquefied with little additional energy input, and the pressure required for disposal can also be generated with liquid CO 2 with little additional energy.
  • the power plant according to the invention has the advantage that the purge gas for separating the hydrogen is likewise advantageously produced within the process, but not two cycles are needed, but only one.
  • the purge gas is not the high-temperature exhaust gas of the combustion chamber, but the moderately hot exhaust gas from the waste heat boiler is used.
  • the IGCC power plant according to the invention has, compared with the IGCC power plants known from the prior art, a circulation loop, comprising a hydrogen membrane for separating hydrogen from the process gas, a combustion chamber of the gas turbine, the gas turbine itself, and one of the gas turbine downstream waste heat boiler, for generating the steam for a steam turbine.
  • the lines of circulation extending from the exhaust side of the waste heat boiler to a "big" N 2 compressor, from there to the permeate side of the hydrogen membrane and from there back to the combustion chamber of the gas turbine and to the gas turbine and waste heat boiler.
  • the "big” N 2 Compressor is largely replaced the original "big” air compressor, but according to the only stoichiometric air supply is now only a "small” air compressor available.
  • a compressor is provided in the flue gas recirculation.
  • Kraftwerkes is the pressure level on the permeate side of the membrane with the pressure in the burner and this identical to the gas turbine inlet pressure, because an additional compression stage, alone for the membrane, does not make sense.
  • heat exchangers in front of and behind the hydrogen membrane, a blower or even an additional preheater can also be arranged in this circulation loop.
  • biomass or waste in a gasifier is gasified substoichiometrically ( ⁇ approximately between 0.2 and 0.4) to high-energy gas.
  • the resulting crude gas is cooled, the waste heat is already introduced into a steam turbine cycle.
  • the raw gas is purified and passes through desulfurization, filter u. a. Units.
  • the gas is burned in a gas turbine, wherein the combustion chamber is often integrated in the turbine housing.
  • the waste heat is used to evaporate liquid in a secondary circuit.
  • the steam itself is sent through a steam turbine and almost to
  • the residual heat can still be fed into a heat exchanger network.
  • the CO present in the crude gas is converted via a shift stage into CO 2 , which is subsequently separated off.
  • both physical scrubbers and membranes can be used.
  • a membrane selectively separating hydrogen is used.
  • the fuel in particular coal, is gasified by means of oxygen, advantageously from an air separation plant, over one Directed CO shift stage and the H 2 membrane fed.
  • the hydrogen transported through the membrane is fed to the combustion chamber of the gas turbine together with the nitrogen of the purge gas.
  • air is supplied in such a ratio that the resulting flue gas contains only small amounts of oxygen, so that the flue gas can be passed after passing through the waste heat boiler as purge gas to the permeate side of the H 2 membrane.
  • Small amounts in the sense of these inventions are to be understood as amounts of 0.1 to 1% by volume.
  • the air is supplied to the combustion chamber, in particular with an almost stoichiometric ratio ( ⁇ 1).
  • ⁇ stands for the combustion air ratio.
  • ⁇ > 1 means excess air and ⁇ ⁇ 1 air deficiency.
  • ⁇ ⁇ 1 in the
  • the predominantly N 2 -aus unde flue gas with temperatures around 400 0 C after recompression can be advantageous in the process according to the invention, without further intermediate heat exchanger, are fed directly to the H 2 membrane.
  • Known porous, ceramic membranes usually operate at temperatures between about 150 and 400 ° C. Above 400 ° C, sintering operations can adversely alter the pore structure. Below 150 ° C, water, which is present in most applications of membrane power plants on the feed or permeate side, can lead to a pore blockage.
  • part of the permeate stream (H 2 / N 2 gas ) could Mixing of the exiting purge stream) the incoming purge stream (N 2 ) by means of a circulation blower, which overcomes the pressure loss occurred in the membrane, are supplied, burned in a preheater, this proportion, and the heat generated directly to preheat the purge gas before entering the filter is used.
  • the heat of combustion could also be coupled via a heat exchanger, for. B. if the introduction of product water should be avoided in the membrane. In this case, the combustion gas would not get back into the membrane and fed directly to the burner of the gas turbine.
  • Hydrogen on the one hand, depends on the required final temperature of the purge gas and on the other hand on its mass flow. A typical case would be to increase the purge gas temperature from 400 to 600 ° C. For this purpose, about 15% by volume, or% by weight, of the permeate would have to be burned in the preheater (for comparison: according to FIG. 6, the entire permeate supplies so much heating heat that the temperature increase of about 1.5 times greater
  • N 2 -rich gas stream in the burner of the gas turbine is 4 times larger (400-1200 0 C)).
  • Such high operating temperatures for the purge gas are particularly desirable when a proton-electronic mixed conductor is used as a membrane. This usually requires temperatures between 500 and 700 0 C for optimum operation.
  • a polymer membrane is used for the hydrogen separation.
  • the optimum operating temperature of the H 2 - membrane is around 100 ° C, so that the purge gas is cooled before entering the membrane first through a recuperative heat exchanger to these temperatures.
  • this cooling is accompanied by a simultaneous heating of the permeate before it is introduced into the combustion chamber.
  • the process control according to the invention also allows additional support for the flushing gas flow rate by supplying DmCk-N 2 from an air separation plant.
  • N 2 is to be understood nitrogen gas under a pressure of at least about 20 bar, as typically by an air separation plant, which is specified for an IGCC, for
  • the invention advantageously combines a simplified process compared to the prior art for an IGCC power plant with an improved energy balance. It also allows adaptation to the use of different hydrogen membranes and related operating temperatures.
  • An essential component of the invention is that, in contrast to the standard IGCC, the exhaust gas of the gas turbine contains no or only very little oxygen and because of this property is suitable to be used as purge gas. The absence of oxygen is achieved by sufficiently low, only almost stoichiometric fresh air. The absence of oxygen in the purge gas ensures that the permeated through the membrane hydrogen does not burn when added to the purge gas, which would lead to an intolerable high temperature rise of the purge gas and the membrane.
  • the IGCC power plant according to the invention which is suitable for carrying out the process, therefore comprises a gasifier for the gasification of a solid fuel, a means for providing oxygen for the gasifier, at least one shift stage downstream of the gasifier for converting CO and water vapor into CO 2 and Hydrogen, at least one gas purification stage downstream of the gasifier, a hydrogen-selective membrane downstream of the gasifier, a means for providing purge gas for the permeate side of the membrane, and a gas turbine, with a conduit leading from the permeate side of the membrane to the combustion chamber of the gas turbine, and the means for providing the purge gas is the gas turbine, and another conduit is arranged from the gas turbine downstream waste heat boiler to the permeate side of the membrane.
  • FIG. 1 IGCC process with non-integrated air separation plant (LZA)
  • FIG. 2 IGCC process with integrated air separation plant (LZA)
  • FIG. 3 IGCC process with integrated air separation plant (LZA) and unpurged H 2
  • FIG. 4 IGCC process with integrated air separation plant (LZA) and weakly purged H 2 membrane for separating CO 2 , N 2 purging gas completely from LZA, from [1]
  • FIG. 5 IGCC process with integrated air separation plant (LZA) and highly purged H 2 membrane for separating CO 2, N 2 purging gas from exhaust gas of the combustion chamber of the gas turbine [from DE 10200801 1771]
  • LZA integrated air separation plant
  • H 2 membrane for separating CO 2, N 2 purging gas from exhaust gas of the combustion chamber of the gas turbine
  • FIG. 6 IGCC process according to the invention with integrated air separation plant (LZA) and highly purged H 2 membrane for separating off CO 2 , N 2 purging gas from exhaust gas of the waste heat boiler and optionally additionally from LZA
  • LZA integrated air separation plant
  • FIG. 7 IGCC process according to the invention with integrated air separation plant (LZA) and strongly purged H 2 membrane for separating off CO 2 , N 2 purging gas from exhaust gas of the waste heat boiler and optionally additionally from LZA, with additional preheating circuit for raising the purge gas temperature from approx. 400 to 500 - 700 ° C at the entrance to the membrane in order to be able to operate a diaphragm with a characteristic operating temperature of 500 - 700 ° C
  • LZA integrated air separation plant
  • H 2 membrane for separating off CO 2 , N 2 purging gas from exhaust gas of the waste heat boiler and optionally additionally from LZA
  • additional preheating circuit for raising the purge gas temperature from approx. 400 to 500 - 700 ° C at the entrance to the membrane in order to be able to operate a diaphragm with a characteristic operating temperature of 500 - 700 ° C
  • Figure 8 According to the invention IGCC process with integrated air separation plant (LZA) and heavily flushed H 2 membrane for separating CO 2 , N 2 purge gas from exhaust gas of the waste heat boiler and optionally additionally from LZA, with additional recuperative heat exchanger for lowering The purge gas temperature of about 400 ° C to about 100 - 300 ° C at the entrance to the membrane in order to operate membranes with characteristic operating temperatures of about 100 - 300 ° C.
  • LZA integrated air separation plant
  • coal gas conditioning possibly including shift stage 3 H 2 membrane
  • FIGS. 9 to 11 Example of a simulated hydrogen separation for a better understanding of the driving forces prevailing there are described in FIGS. 9 to 11.
  • FIG. 9 Example of an unspushed H 2 membrane (see concept according to FIG. 3)
  • FIG. 10 Example of a slightly rinsed H 2 membrane (see concept according to FIG. 4)
  • FIG. 11 Example of a strongly rinsed H 2 membrane (see Concepts according to FIGS. 5 to 8)
  • GT gas turbine
  • G generator
  • AHK waste heat boiler
  • DT steam turbine
  • the fuel in particular coal, is gasified in a gas stream which has only a small nitrogen content.
  • the ratio of the oxygen content to the proportion of nitrogen and argon should be advantageous in the
  • the gas stream can also contain steam and CO 2 in addition to oxygen.
  • the conditioned coal is in a gasifier (1) at high temperatures in the said gas stream at elevated pressure, preferably not less than 30 bar, transferred to a carbon monoxide-rich, hydrogen-containing process gas. This process takes place typical shear at temperatures between 800 and 1500 0 C. The resulting gas is cooled. The excess heat is utilized in the overall process.
  • a shift process (2) the carbon monoxide-rich process gas is subsequently converted into a hydrogen-rich product gas, which now contains the carbon dioxide to be separated off.
  • the process gas is subjected to various gas purification stages with solids and sulfur separation, which are not considered further here, in line with the individual process steps. These gas purification steps can be arranged before, behind, and between the individual shift stages. Even within the shift stages, steps necessary for gas purification can be arranged.
  • the coal gas is to be separated off from the CO 2 -containing gas stream by means of a membrane which operates specifically. This will be in another
  • H 2 hydrogen
  • the CO 2 -rich residual gas with only a small amount of H 2 remains below the operating pressure of the gasification and can be fed to a process for conditioning
  • the membrane (3) is preferably a membrane that conducts hydrogen ions, ie protons, and that is characterized by high selectivity for H 2 over CO 2 due to this transport mechanism. It is also possible to use another membrane suitable for the separation of hydrogen. Particularly suitable H 2 membranes are porous, ceramic membranes, protonic-electronic mixed conductors and polymer membranes.
  • a purge gas is used on the permeate side.
  • This purge gas normally has the same or similar pressure as the burner at the inlet of the gas turbine, since a subsequent compression of the purge gas leaving the membrane is not provided.
  • the process gas in the membrane normally has the same or similar pressure as the gasification, and the gasification normally has the same or similar pressure as the gas
  • polymer membranes are particularly suitable for use when high differential pressures occur.
  • Today, their application range extends from 1 to 150 bar on the process gas side and from 50 mbar to 20 bar on the permeate side (specification of the company BORSIG). So even today in membrane plants by means of polymer membranes CO 2 from natural gas, which is still under high pressure after promotion, separated.
  • the process gas which touches the membrane on the primary side (process gas side, retentate side), is deprived of hydrogen so that the hydrogen migrates through the membrane.
  • the driving potential here is the partial pressure difference of the hydrogen between the
  • the permeate side is the secondary side, i. H. the side of the membrane to which the hydrogen migrates. To maintain the hydrogen partial pressure difference, there must always be a sufficient supply of purge gas.
  • An essential step of the invention in this method is that the purge gas from the
  • Combustion product of the gas turbine (4a) itself is obtained, and only after the exhaust gas of the gas turbine (4b) has passed through the downstream waste heat boiler (4c). At this point, the combustion product is depressurized (about 1 bar) and has a low Temperature. There is always taken as much exhaust gas as is required to limit the combustion temperature in the combustion chamber (4a) of the gas turbine.
  • a combined compressor (6) to be operated under uniform pressure for both N 2 (recirculated flue gas) and for air brings the gas streams which are supplied in particular for the purpose of cooling the gas turbine combustion chamber (4 a) to the required pressure level the gas turbine.
  • the purge gas contains substantially nitrogen, water vapor and only a very small proportion of oxygen, since the combustion in the gas turbine (4a-4b) is usually carried out with a nearly stoichiometric oxygen-fuel ratio (as a further step essential to the invention in this process) ( ⁇ ⁇ 1), as well as small amounts of CO 2 and argon.
  • a possible gas composition would be, for example, as follows: N 2 : 65-75 vol% H 2 O: 25-30 vol% O 2 : 0.6-1 vol%
  • porous ceramic membranes work particularly advantageously around 400 ° C.
  • proton-electronic mixed conductors prefer higher temperatures between 500 and 700 ° C., in particular between 550 and 600 ° C.
  • polymer membranes should be used regularly at not more than 100 ° C.
  • the recirculated flue gas after the waste heat boiler and before the N 2 compressor (6) initially low temperatures.
  • the N 2 compressor (6) in the compression of 1 bar to about 25 bar (with intermediate cooling), it then experiences a temperature increase to about 400 ° C, so that when using a porous ceramic membrane advantageously no further temperature adjustment of the recirculated Flue gas / purge gas is necessary (see Figure 6).
  • the process can be adapted such that a portion of the hydrogen / nitrogen mixture produced in the permeate space of the membrane is combusted almost stoichiometrically with small amounts of oxygen in a partial combustion in a preheater (8) (see FIG. 7).
  • the heat generated in this way can be used to ensure that it is insufficiently tempered
  • H 2 membrane (3) Heat sufficient flue gas / purge gas on the permeate side of the H 2 membrane (3).
  • hydrogen for example in the form of protons, permeates from the process gas side, ie the feed and retentate side, to the permeate side and in this way is supplied to the purge gas.
  • the gas stream present on the permeate side behind the membrane contains, in addition to the purge gas, the substantial amount of hydrogen produced in the gas production process.
  • This gas consists essentially of nitrogen and hydrogen and is present at a pressure that allows this gas flows as coal gas into the combustion chamber of the gas turbine.
  • the H 2 separation is simulated by way of example as a function of different boundary conditions, in particular as a function of the total permeate pressure and of the N 2 purge gas used.
  • FIG. 9 shows the conditions for an unspurged H 2 membrane.
  • the driving force is high when entering the membrane, for example, 14.5 bar and the H 2 - separation is initially good. However, if the very high energy removal efficiency range is achieved during the separation process (90% separation and above), then the drive force will decrease to zero before reaching 100% separation efficiency. This means that only degrees of separation significantly below 100%, z. B. 90%, can be realized. 10% of the hydrogen is then not available for power generation in the gas and steam process.
  • the permeate pure hydrogen
  • the permeate only has a pressure of 0.5 bar and therefore must be disadvantageously compressed before entering the combustion chamber to the operating pressure. If one were to choose a higher permeate pressure than 0.5 bar in order to save compression energy, the driving force would be even lower, especially at the end of the separation process, and the achievable H 2 separation level would still be less than about 90%.
  • FIG. 10 shows a simulation with a weakly flushed H 2 membrane, as shown in FIGS.
  • the purge gas produced from the air separation plant pressure N 2 is used with a pressure of about 25 bar.
  • the flow ratio of N 2 to H 2 is at most about 1: 1.5, resulting in either no driving force for H 2 transport through the membrane or a driving force hardly different from zero. Accordingly, a high degree of separation will at most only be achievable with intolerably large membrane surfaces.
  • FIG. 11 shows the simulated separation of H 2 in the case of a strongly purged H 2 membrane, wherein the purge gas is provided on the one hand from the air separation plant (pressure N 2 at 25 bar), but on the other hand for the most part from the flue gas recirculation, also below 25 bar ,
  • the flow ratio of N 2 to H 2 is now approximately 4: 1, which was determined by simulation calculation with the commercial plant program PRO / II. Due to the vigorous rinsing, low H 2 partial pressures result in the purge gas on the permeate side. Correspondingly, high driving forces are present and, in particular at the end of the separation process, are the
  • Membrane must have only a small increase. The following considerations give an orientation.
  • the local permeate current density is proportional to the driving force, ie the H 2 partial pressure difference between the feed and permeate side. Since the required local membrane area is inverse to the permeate current density, it is also inversely proportional to the H 2 partial pressure difference. This is in the middle of the separation process at 50% separation about 5 bar and at 90% or 97% separation about 1 and 0.5 bar.
  • This retentate of the H 2 membrane (3) regularly remains only a small amount of hydrogen.
  • This retentate essentially contains the carbon dioxide generated in the gas production process, as well as water vapor and the already mentioned remainder of hydrogen.
  • This retentate has the pressure as dictated by the process. This pressure is preferably 20 -30 bar and is regularly reduced only by the pressure loss, as it results from the leadership of the gas flow through the apparatus and pipes.
  • a particularly advantageous embodiment of the invention provides that the remaining hydrogen in the retentate is burned in a combustion step.
  • the necessary Oxygen-containing gas can advantageously be taken from the oxidation gas upstream of the gasifier (1).
  • substantially pure oxygen can be taken off at an additional removal point downstream of the oxygen compression and used in the combustion.
  • the resulting during this combustion and under process pressure gas flow contains almost exclusively carbon dioxide (CO 2 ) and water vapor. Part of this gas stream can be separated and fed to the conditioning of the CO 2 after cooling with condensation and separation of the water.
  • CO 2 carbon dioxide
  • the option for such an increase in the CO 2 content in this gas is a significant advantage of this concept, which can lead to the more effective and cost-effective conditioning of CO 2 from this power plant.
  • a further advantageous embodiment of the invention provides that another part can optionally be used as purge gas for an oxygen membrane for the purpose of separating oxygen from air.
  • compressed air is taken behind the air compressor of the gas turbine and fed to an oxygen membrane on the primary side.
  • the purge gas advantageously a diverted stream from the residual gas, is fed to the secondary side, ie the permeate side of the membrane.
  • the O 2 membrane is preferably a membrane that conducts oxygen ions.
  • the driving potential in the separation process is the difference between the partial pressures of the oxygen of the air side and the permeate side.
  • the oxygen migrates through the membrane to the permeate side in the purge gas. In this way, a significant part or the total amount of oxygen required for coal gasification can be separated from the air by means of a membrane instead of a conventional air separation plant.
  • the gas stream on the permeate contains predominantly oxygen, purge gas, ie CO 2 -rich residual gas and foreign gases.
  • the foreign gases come mainly from the air, because they also permeate through the membrane to a small extent.
  • the ratio of the amount of oxygen to the amounts of these foreign gases is preferably in the vicinity of 20. Such a ratio regularly allows a content of carbon dioxide in the dried exhaust gas of the gasification process of more than 95% by volume.
  • a further advantageous embodiment of the invention as already partially described in DE 10200801 1771, provides that a further part of the amount of oxygen necessary for the gasification of the coal, which is largely free of foreign gases, in a further separation step via another Membrane can be recovered. Again, the ratio between the amount of oxygen and amount of foreign gas in the permeate should preferably in the
  • the resulting oxygen stream is compressed to the required pressure with a compressor for further use.
  • the oxygen thus obtained can be advantageously used by varying its amount for regulating the oxygen concentration for the gasification of the coal in the gasifier (1). If the oxygen membrane operated with purge gas can supply the amount of oxygen necessary for the overall process, this second oxygen membrane and the associated compressor can be dispensed with.
  • the retentate from the oxygen membranes can be supplied as the oxidant of the gas turbine. This reduces the need for fresh air, which is supplied to the gas turbine for the purpose of limiting the temperature.
  • the waste gas stream (residual gas) originating from the combustion of the residual hydrogen, of which a part is optionally separated off before the oxygen membrane, consists essentially of carbon dioxide and water vapor. Minor impurities can come in particular from the various gas separations.
  • This gas stream is at process pressure
  • FIG. 12 shows the flow rate ratios in the IGCC process according to the invention for better understanding.

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Abstract

L'invention concerne un procédé pour faire fonctionner une centrale IGCC, selon lequel du gaz de charbon produit par un gazéifieur et contenant du CO et de l'hydrogène est amené à au moins un niveau de conversion où il est converti principalement en CO2 et en hydrogène, le gaz de charbon étant soumis à au moins un lavage. Le gaz de charbon est amené par l'intermédiaire d'une membrane qui sépare au moins partiellement et de manière sélective l'hydrogène du gaz de charbon. Pour obtenir un potentiel d'entraînement au niveau de la membrane, un gaz de balayage est utilisé côté perméat. Le rétentat enrichi en hydrogène est acheminé vers un dispositif de conditionnement de CO2 et l'hydrogène séparé est amené avec le gaz de balayage dans une turbine à gaz où il sert de gaz combustible. Selon l'invention, une partie des effluents gazeux produits par la turbine à gaz sont utilisés comme gaz de balayage pour la membrane, à la sortie de la chaudière de récupération située en aval de la turbine à gaz. Dans la centrale selon l'invention, la turbine à gaz sert simultanément de moyen de production du gaz de balayage. Cette centrale comporte un conduit reliant la chaudière de récupération située en aval de la turbine à gaz et le côté perméat de la membrane.
EP09776071A 2008-09-19 2009-08-05 Centrale igcc (gazéification intégrée à un cycle combiné) avec recyclage des gaz de fumée et gaz de balayage Withdrawn EP2342429A2 (fr)

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DE102008048062A DE102008048062B3 (de) 2008-09-19 2008-09-19 IGCC-Kraftwerk mit Rauchgasrückführung und Spülgas
PCT/DE2009/001114 WO2010031366A2 (fr) 2008-09-19 2009-08-05 Centrale igcc (gazéification intégrée à un cycle combiné) avec recyclage des gaz de fumée et gaz de balayage

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TWI593878B (zh) * 2010-07-02 2017-08-01 艾克頌美孚上游研究公司 用於控制燃料燃燒之系統及方法
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DE102010049801A1 (de) 2010-10-27 2012-05-03 Technische Universität München IGCC Kraftwerk mit Post Combustion CO2 Abtrennung mittels Carbonate Looping (ES-CL Cycle)
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