WO2010141346A2 - Système de brûleur oxycombustible hybride - Google Patents

Système de brûleur oxycombustible hybride Download PDF

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Publication number
WO2010141346A2
WO2010141346A2 PCT/US2010/036551 US2010036551W WO2010141346A2 WO 2010141346 A2 WO2010141346 A2 WO 2010141346A2 US 2010036551 W US2010036551 W US 2010036551W WO 2010141346 A2 WO2010141346 A2 WO 2010141346A2
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WO
WIPO (PCT)
Prior art keywords
combustion
combustion chamber
gaseous
flue gas
fuel
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.)
Ceased
Application number
PCT/US2010/036551
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English (en)
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WO2010141346A3 (fr
Inventor
Hisashi Kobayashi
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.)
Praxair Technology Inc
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Praxair Technology Inc
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Filing date
Publication date
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Publication of WO2010141346A2 publication Critical patent/WO2010141346A2/fr
Anticipated expiration legal-status Critical
Publication of WO2010141346A3 publication Critical patent/WO2010141346A3/fr
Ceased legal-status Critical Current

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Classifications

    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
    • F23C—METHODS OR APPARATUS FOR COMBUSTION USING FLUID FUEL OR SOLID FUEL SUSPENDED IN  A CARRIER GAS OR AIR 
    • F23C6/00—Combustion apparatus characterised by the combination of two or more combustion chambers or combustion zones, e.g. for staged combustion
    • F23C6/04—Combustion apparatus characterised by the combination of two or more combustion chambers or combustion zones, e.g. for staged combustion in series connection
    • F23C6/042—Combustion apparatus characterised by the combination of two or more combustion chambers or combustion zones, e.g. for staged combustion in series connection with fuel supply in stages
    • 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
    • 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
    • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
    • F23C—METHODS OR APPARATUS FOR COMBUSTION USING FLUID FUEL OR SOLID FUEL SUSPENDED IN  A CARRIER GAS OR AIR 
    • F23C9/00—Combustion apparatus characterised by arrangements for returning combustion products or flue gases to the combustion chamber
    • F23C9/003—Combustion apparatus characterised by arrangements for returning combustion products or flue gases to the combustion chamber for pulverulent fuel
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
    • F23L—SUPPLYING AIR OR NON-COMBUSTIBLE LIQUIDS OR GASES TO COMBUSTION APPARATUS IN GENERAL ; VALVES OR DAMPERS SPECIALLY ADAPTED FOR CONTROLLING AIR SUPPLY OR DRAUGHT IN COMBUSTION APPARATUS; INDUCING DRAUGHT IN COMBUSTION APPARATUS; TOPS FOR CHIMNEYS OR VENTILATING SHAFTS; TERMINALS FOR FLUES
    • F23L7/00—Supplying non-combustible liquids or gases, other than air, to the fire, e.g. oxygen, steam
    • F23L7/007—Supplying oxygen or oxygen-enriched air
    • 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
    • F05D2220/70—Application in combination with
    • F05D2220/72—Application in combination with a steam turbine
    • F05D2220/722—Application in combination with a steam turbine as part of an integrated gasification combined cycle
    • 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
    • F05D2260/00—Function
    • F05D2260/60—Fluid transfer
    • F05D2260/61—Removal of CO2
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
    • F23J—REMOVAL OR TREATMENT OF COMBUSTION PRODUCTS OR COMBUSTION RESIDUES; FLUES 
    • F23J2215/00—Preventing emissions
    • F23J2215/50—Carbon dioxide
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
    • F23J—REMOVAL OR TREATMENT OF COMBUSTION PRODUCTS OR COMBUSTION RESIDUES; FLUES 
    • F23J2219/00—Treatment devices
    • F23J2219/70—Condensing contaminants with coolers
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
    • F23J—REMOVAL OR TREATMENT OF COMBUSTION PRODUCTS OR COMBUSTION RESIDUES; FLUES 
    • F23J2900/00—Special arrangements for conducting or purifying combustion fumes; Treatment of fumes or ashes
    • F23J2900/15061—Deep cooling or freezing of flue gas rich of CO2 to deliver CO2-free emissions, or to deliver liquid CO2
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
    • F23L—SUPPLYING AIR OR NON-COMBUSTIBLE LIQUIDS OR GASES TO COMBUSTION APPARATUS IN GENERAL ; VALVES OR DAMPERS SPECIALLY ADAPTED FOR CONTROLLING AIR SUPPLY OR DRAUGHT IN COMBUSTION APPARATUS; INDUCING DRAUGHT IN COMBUSTION APPARATUS; TOPS FOR CHIMNEYS OR VENTILATING SHAFTS; TERMINALS FOR FLUES
    • F23L2900/00—Special arrangements for supplying or treating air or oxidant for combustion; Injecting inert gas, water or steam into the combustion chamber
    • F23L2900/07001—Injecting synthetic air, i.e. a combustion supporting mixture made of pure oxygen and an inert gas, e.g. nitrogen or recycled fumes
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
    • F23L—SUPPLYING AIR OR NON-COMBUSTIBLE LIQUIDS OR GASES TO COMBUSTION APPARATUS IN GENERAL ; VALVES OR DAMPERS SPECIALLY ADAPTED FOR CONTROLLING AIR SUPPLY OR DRAUGHT IN COMBUSTION APPARATUS; INDUCING DRAUGHT IN COMBUSTION APPARATUS; TOPS FOR CHIMNEYS OR VENTILATING SHAFTS; TERMINALS FOR FLUES
    • F23L2900/00—Special arrangements for supplying or treating air or oxidant for combustion; Injecting inert gas, water or steam into the combustion chamber
    • F23L2900/07007—Special arrangements for supplying or treating air or oxidant for combustion; Injecting inert gas, water or steam into the combustion chamber using specific ranges of oxygen percentage
    • 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
    • Y02E—REDUCTION OF GREENHOUSE GAS [GHG] EMISSIONS, RELATED TO ENERGY GENERATION, TRANSMISSION OR DISTRIBUTION
    • Y02E20/00—Combustion technologies with mitigation potential
    • Y02E20/32—Direct CO2 mitigation
    • 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
    • Y02E20/34—Indirect CO2mitigation, i.e. by acting on non CO2directly related matters of the process, e.g. pre-heating or heat recovery

Definitions

  • the present invention relates to combustion systems such as boilers for generating steam and power, and relates especially to improvements in converting such systems to oxy-fuel operation to facilitate capture of carbon dioxide produced by the combustion.
  • One aspect of the present invention is a method of modifying a combustion system that comprises a first combustion chamber and that is capable of receiving fuel and air into said first combustion chamber and that is capable of combusting said fuel and said oxidant in said first combustion chamber, and a flue gas outlet from said first combustion chamber for gaseous products of combustion formed in said first combustion chamber, the method comprising
  • FIG. 1 Another aspect of the present invention is a combustion system that comprises (A) a first combustion unit that includes a first combustion chamber and that is capable of receiving fuel and gaseous oxidant having an oxygen content of 19 to 35 vol.% into said first combustion chamber and that is capable of combusting said fuel and said oxidant in said first combustion chamber, and a flue gas outlet from said first combustion chamber for gaseous products of said combustion,
  • a second combustion unit that includes a second combustion chamber and that is capable of receiving fuel and gaseous oxidant containing less than 10% nitrogen into said second combustion chamber and that is capable of combusting said fuel and said oxidant in said second combustion chamber, and a flue gas outlet from said second combustion chamber for gaseous products of said combustion,
  • Yet another aspect of the present invention is a method of combustion, comprising
  • A providing a combustion system that comprises (i) a first combustion unit that includes a first combustion chamber and that is capable of receiving fuel and gaseous oxidant into said first combustion chamber and that is capable of combusting said fuel and said oxidant in said first combustion chamber, and a flue gas outlet from said first combustion chamber for gaseous products of said combustion,
  • a second combustion unit that includes a second combustion chamber and that is capable of receiving fuel and gaseous oxidant into said second combustion chamber and that is capable of combusting said fuel and said oxidant in said second combustion chamber, and a flue gas outlet from said second combustion chamber for gaseous products of said combustion,
  • a preferred option is to provide for recycle of gaseous combustion products out of the first combustion chamber and then into the second combustion chamber, and more preferably removing sulfur oxide and nitrogen oxides from the gaseous combustion products after they pass out of the first combustion chamber before they are fed into the second combustion chamber.
  • Figure 1 is a flowsheet of one conventional combustion system.
  • Figure Ia is a flowsheet of a coal fired utility boiler system
  • Figure 2 is a flowsheet of another conventional combustion system.
  • Figure 3 is a flowsheet of one embodiment of the present invention.
  • Figure 4 is a flowsheet of another embodiment of the present invention.
  • Figure 8 is a flowsheet representing another preferred arrangement according to the present invention with a new oxy-coal fired boiler with cooled flue gas feeding into the existing boiler to eliminate flue gas recycle for the existing boiler.
  • Figure 9 is a flowsheet representing an alternative embodiment wherein a gas turbine topping cycle is employed with flue gas recirculation from the first boiler.
  • boiler 1 is of any known design to which fuel 2 and air 3 are fed and combusted within boiler 1 to produce heat and gaseous combustion products 4.
  • the heat is typically recovered by indirect convective and radiative heat transfer to water, which is converted to steam, and heat transfer to the steam.
  • the steam can then be used to operate turbines to produce electric power.
  • the gaseous combustion products 4 pass through heat recovery area 112, often know as convective banks, which may include superheaters, reheaters, and economizers to transfer heat to feed water 113 to produce steam and/or hotter water which are represented by 114.
  • the gaseous combustion products 42 are optionally fed to unit 51 such as a selective catalytic converter to reduce the amount of NOx species in the gaseous stream.
  • the resulting stream 43 of gaseous combustion products is then fed to an air heater 61 to preheat combustion air stream 3 to a temperature typically in a range of 500 to 800 F.
  • the resulting gaseous combustion products 44 then pass through an ash removal unit 52, typically an electrostatic precipitator, to remove solid particulates such as ash particles which are usually present in flue gas from coal combustion.
  • the resulting gaseous combustion products 45 are optionally treated in a desulfurization unit 53 to reduce the concentration of SOx species.
  • the resulting cleaned flue gas 6 is vented to the atmosphere through a stack, not shown.
  • the air pollution control unit disclosed here can comprise any one, or any combination, of units such as units 51, 52 and/or 53.
  • Figure 2 shows another conventional embodiment of a combustion system enabling the use of oxygen in place of air as the oxidant for combustion for a boiler designed to use for combustion.
  • Fuel 2 and oxygen 7 typically comprising at least 80 vol.% oxygen are fed to boiler 1 and are combusted.
  • the oxidant comprises at least 90 vol.% oxygen, and more preferably it contains at least 95 vol.% oxygen.
  • the gaseous products of this combustion leave boiler 1 as stream 4 which is preferably treated in unit 5 to remove pollutants such as particulates, sulfur oxides and nitrogen oxides.
  • a portion 8 of the cleaned flue gas 6 which leaves unit 5 is recycled to boiler 1.
  • a portion of water vapor contained in gaseous combustion products 4 is condensed and removed prior to recycle to boiler 1.
  • a portion of gaseous combustion products 4 are recycled to boiler 1 prior to the treatment in unit 5, which is not shown in Figure 2.
  • Another portion 9 of stream 6 is further cooled to condense and remove water vapor and recovered for storage or sequestration, optionally preceded by treatment to raise (enrich) the carbon dioxide content of the stream.
  • Such treatment can be implemented by any of several known processes such as cryogenic carbon dioxide separation processes and preferential absorption or adsorption of carbon dioxide followed by desorbtion or desorption.
  • Examples include preferential absorption of carbon dioxide into an aqueous solution of organic amines, followed by stripping the carbon dioxide from the aqueous solution.
  • Preferably carbon dioxide is separated from other gases by a cryogenic process.
  • the steps of water vapor condensation, recovery, storage and sequestration, and optional enrichment are represented by stage 10 in Figure 2.
  • Oxygen 7 is preferably premixed with recycled flue gas stream 8 prior to being fed to boiler 1.
  • a portion of oxygen 7 can be directly injected into boiler 1.
  • the amount of flue gas stream 8 recycled to boiler 1 is controlled so as to be able to operate boiler 1 with no or minimum modifications.
  • the average oxygen concentration of the mixture of oxygen and the recycled flue gas that enables the proper operation of boiler 1 is typically in a range of 23 and 30 vol. %.
  • FIG. 3 shows an embodiment of the present invention.
  • a second boiler 11 is provided, into which are fed fuel 12 and oxygen (preferably comprising at least 80 vol.% oxygen). Combustion of the fuel and oxygen in boiler 11 produces gaseous combustion products which exit boiler 11 as stream 14.
  • boiler 11 has a flue gas recycle loop 30 of its own, in which case oxygen and recycled flue gas are fed to the combustion chamber. In all cases described herein wherein oxidant and recycled flue gas are fed to a combustion chamber, they can be fed separately or as a premixed stream.
  • the combined content of oxygen, carbon dioxide and water vapor fed to the combustion chamber should be at least 80 vol.%.
  • fuel and oxidant being air or oxygen, with or without recycled flue gas
  • the fuel and oxidant can be fed into the combustion chamber as separate streams or can be premixed outside the combustion chamber to form a combined stream which is then fed into the combustion chamber.
  • streaml4 exiting boiler 11 when a bituminous coal is used as the fuel is typically: CO 2 , 59 to 66 vol.%; H 2 O, 26 to 31 vol.%; O 2 , 2 to 4 vol.%; N 2 , 1 to 10 vol.%; Ar, 0 to 4 vol.%; depending on the purity of oxygen used.
  • stream 14 also contains minor concentrations of sulfur oxides, nitrogen oxides, various ash particulates.
  • Oxygen stream 15 can be premixed with flue gas stream 14 from boiler 11 prior to being fed to boiler 1 which may allow the use of the existing burners designed for air without modifications. Converting an existing air- fired system to the system of the present invention may require providing a burner that can be used for combusting fuel, flue gas from boiler 11 and oxygen, and providing a connection of the burner to a source of oxygen having the desired high oxygen content.
  • sources are well known and include on-site plants such as cryogenic air separation plants, pressure swing adsorption and vacuum pressure swing adsorption units; alternatively, the connection is to an oxygen pipeline connected to a source of oxygen.
  • Boiler 11 is sized to produce a sufficient volume of flue gas to be fed to boiler 1 so as to eliminate the need for recycle of flue gas to boiler 1 as shown in Figure 2.
  • Combustion in boiler 1 produces the aforementioned stream 4 of gaseous combustion products, but in this embodiment the composition of stream 14, assuming boiler 1 is fired with a bituminous coal is typically: CO 2 , 59 to 66 vol.%; H 2 O, 26 to 31 vol.%; O 2 , 2 to 4 vol.%; N 2 , 1 to 10 vol.%; Ar, 0 to 4 vol.%; depending on the purity of oxygen used.
  • coal fired boilers stream 14 also contains minor concentrations of sulfur oxides, nitrogen oxides, various ash particulates..
  • the air heater shown in Figure Ia is no longer needed and is bypassed by gaseous combustion products 4.
  • an auxiliary feed water heater 31 is preferably installed to cool stream 4 to an appropriate temperature prior to being treated in unit 5.
  • the addition of an auxiliary feed water heater has a beneficial effect of increasing the amount of steam produced and hence can potentially increase the power output of steam turbines fed by steam produced by the boilers.
  • Stream 4 is treated in unit 5 to remove pollutants, such as sulfur oxides and nitrogen oxides, producing cleaned flue gas stream 6 which can be treated in unit 10 as described above for enrichment, storage and/or sequestration of the carbon dioxide.
  • Figure 4 shows another embodiment of the invention, identical to the embodiment as described above with reference to Figure 3, except that a portion 8 of stream 6 of gaseous combustion products is recycled and fed to boiler 11.
  • the recycled stream and the oxidant are fed to the combustion chamber separately or in a premixed stream.
  • the amount of recycled flue gas stream portion 8 recycled to boiler 1 is controlled so as to be able to operate boiler 1 properly with no or minimum modifications.
  • the average oxygen concentration of the mixture of oxygen, flue gas stream 14 from boiler 11 and recycled flue gas stream portion 8 that enables the proper operation of boiler 1 is typically in a range of 23 and 30 vol. %.
  • FIG. 9 represent graphically baseline combustion systems and combustion systems according to the present invention, together with representative input and output data.
  • Figure 5 shows an example representing a conventional conversion of an existing air fired furnace to oxy-fuel firing as described in Figure 2. Due to a large parasitic power requirement the fuel to power conversion efficiency of the plant is reduced from 34% for a sub-critical boiler with air-coal firing to 23% for oxy-coal firing with flue gas recirculation. The net power output is reduced from 300 MW to 197 MW, i.e. 34% reduction. The reduced power output has to be made up by building a new power plant capacity with carbon capture and storage capability which require a significant additional capital investment.
  • Figure 6 shows another example representing a prior art conversion of an existing air fired furnace to oxy-fuel firing by replacing the entire existing boiler and steam turbine with a new high efficiency boiler and steam cycle called ultra- super critical boiler with a conversion efficiency of 43%. Although much higher power efficiency of 31% is realized, the new boiler has to be sized to generate 417 MW to offset the parasitic power of 117 MMW. The capital investment becomes very large just to maintain the same power output as the existing plant.
  • Figure 7 shows an example of a preferred arrangement of the present invention with a new oxy-coal fired boiler with its flue gas feeding into the existing boiler to reduce the amount of the flue gas recycle for the existing boiler.
  • FIG. 8 shows another preferred arrangement according to the present invention with a new oxy-coal fired boiler with its cooled flue gas feeding into the existing boiler to eliminate the flue gas recycle for the existing boiler.
  • An auxiliary feed water heater is installed to recover heat from flue gas, bypassing the original air heater.
  • This process integration scheme produces a substantial additional power from the new boiler-steam turbine cycle (not shown), as it is sized to fully utilize the capacity of the existing boiler and flue gas pollution control units.
  • the size of the new boiler is 872 MW and the net power output of the plant, after subtracting the parasitic power required for the production of oxygen in the air separation unit and for the compression and separation Of CO 2 from flue gas, is 875 MW, an increase of 575 MW.
  • the overall efficiency of this hybrid configuration is 30.3% and this configuration may be a viable repowering option for the existing plant to meet the growing future demand for power while reducing emissions of CO 2 from the current source.
  • the second combustion boiler 11 was assumed to be an "ultra supercritical" (USC) PC boilers.
  • the second boiler can be of any type, including CFB boilers, cyclone boilers or tangentially fired boilers and the steam cycle pressure can be ultra super critical, or super critical or sub-critical.
  • Any fuel can be used as long as the oxidant has a high concentration of oxygen, preferably more than 90% O 2 , more preferably more than 95% O 2 concentration.
  • the combustion chambers should produce combustion flue gas containing more than 70 vol.% of (CO 2 plus H 2 O), preferably more than 90% (CO 2 plus H 2 O), and most preferably, more than 95% (CO 2 plus H 2 O).
  • the second combustion unit 11 can be any combustion unit that produces cooled flue gas containing 70% (CO 2 + H 2 O), preferably more than 90% (CO 2 + H 2 O), most preferably, more than 95% (CO 2 + H 2 O).
  • oxygen fired industrial furnaces such as cement kilns, petroleum heaters and steel heating furnaces can be utilized as the second combustion unit 11.
  • More than one combustion unit can be used as well, for example, three parallel upstream boilers feeding into an existing boiler.
  • Figure 9 shows an alternative embodiment wherein a gas turbine topping cycle is employed with flue gas recirculation from the first boiler 1.
  • the second combustion unit is gas turbine combustor 91 which is fired with gaseous fuel such as natural gas, and with oxidant which is a mixture of recycled flue gas and high-purity (> 90 vol.%) oxygen.
  • This process can optionally be employed in conjunction with a coal gasification unit 92 which produces gaseous fuel 93 for the combustor/gas turbine 91 and char 94 for the existing boiler 1.
  • the methods and apparatus of the present invention can provide additional power from the second boiler, a portion or all of which can be used to for the production of oxygen in an air separation unit and/or for the compression and separation Of CO 2 from flue gas.
  • the present invention enables a cost effective conversion of existing combustion units, such as utility boilers, to oxy-fuel (oxy-coal) firing with a reduced requirement for flue gas recirculation, while at the same time maintaining or increasing the power output from the plant. Since the existing pollutant control unit 5 already in place to treat the flue gas from the first combustion unit is utilized to control the emissions from the second combustion unit as well, a significant reduction in the capital cost of the new boiler system is realized compared to having to provide two separate pollutant control units..
  • the present invention also enables combustion, and power generation, to be carried out at a considerable gain in efficiency compared to other approaches to converting existing air- fired combustion units to oxy- fired, even taking into account the power requirements for providing the high-oxygen-content oxidant which replaces air in the existing combustion unit, and taking into account the power requirements for the carbon dioxide recovery unit 10 which often requires compression of the carbon dioxide to elevated pressure.
  • This gain in efficiency i.e. as overall energy input required for a given power output
  • cost effectiveness i.e. as incremental additional cost

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  • Engineering & Computer Science (AREA)
  • Chemical & Material Sciences (AREA)
  • Combustion & Propulsion (AREA)
  • Mechanical Engineering (AREA)
  • General Engineering & Computer Science (AREA)
  • Combustion Of Fluid Fuel (AREA)

Abstract

La présente invention concerne une unité de combustion à air, telle qu'un brûleur universel, transformée pour un fonctionnement à oxygène et une seconde unité de combustion à oxygène connectée fonctionnellement en amont de sorte que ses gaz d'évacuation sont introduits dans la chambre de combustion de la première unité.
PCT/US2010/036551 2009-06-01 2010-05-28 Système de brûleur oxycombustible hybride Ceased WO2010141346A2 (fr)

Applications Claiming Priority (2)

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US18279009P 2009-06-01 2009-06-01
US61/182,790 2009-06-01

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WO2010141346A2 true WO2010141346A2 (fr) 2010-12-09
WO2010141346A3 WO2010141346A3 (fr) 2012-08-30

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Cited By (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2012064577A3 (fr) * 2010-11-10 2013-10-03 Praxair Technology, Inc. Chaudière alimentée en oxy-combustible possédant une chambre de combustion alimentée séparément pour les fonctions de surchauffeur et de réchauffeur
EP2857749A1 (fr) * 2013-10-02 2015-04-08 Linde Aktiengesellschaft Procédé et système de production de dioxyde de carbone comme sous-produit d'un dégagement gazeux
NO20211394A1 (en) * 2021-11-23 2023-05-24 Aker Carbon Capture Norway As Plant and Method of Controlling an Industrial Plant having a Flue Gas Processing System

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