WO2010057222A2 - Génération de puissance à haut rendement intégrée à des processus chimiques - Google Patents

Génération de puissance à haut rendement intégrée à des processus chimiques Download PDF

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WO2010057222A2
WO2010057222A2 PCT/US2009/064876 US2009064876W WO2010057222A2 WO 2010057222 A2 WO2010057222 A2 WO 2010057222A2 US 2009064876 W US2009064876 W US 2009064876W WO 2010057222 A2 WO2010057222 A2 WO 2010057222A2
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steam
syngas
hrsg
chemical conversion
conversion process
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PCT/US2009/064876
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WO2010057222A3 (fr
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William Rollins
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William Rollins
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    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2/00—Production of liquid hydrocarbon mixtures of undefined composition from oxides of carbon
    • C10G2/30—Production of liquid hydrocarbon mixtures of undefined composition from oxides of carbon from carbon monoxide with hydrogen
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10J—PRODUCTION OF PRODUCER GAS, WATER-GAS, SYNTHESIS GAS FROM SOLID CARBONACEOUS MATERIAL, OR MIXTURES CONTAINING THESE GASES; CARBURETTING AIR OR OTHER GASES
    • C10J3/00—Production of combustible gases containing carbon monoxide from solid carbonaceous fuels
    • C10J3/46—Gasification of granular or pulverulent flues in suspension
    • C10J3/48—Apparatus; Plants
    • C10J3/485—Entrained flow gasifiers
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10K—PURIFYING OR MODIFYING THE CHEMICAL COMPOSITION OF COMBUSTIBLE GASES CONTAINING CARBON MONOXIDE
    • C10K1/00—Purifying combustible gases containing carbon monoxide
    • C10K1/002—Removal of contaminants
    • C10K1/007—Removal of contaminants of metal compounds
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10K—PURIFYING OR MODIFYING THE CHEMICAL COMPOSITION OF COMBUSTIBLE GASES CONTAINING CARBON MONOXIDE
    • C10K1/00—Purifying combustible gases containing carbon monoxide
    • C10K1/08—Purifying combustible gases containing carbon monoxide by washing with liquids; Reviving the used wash liquors
    • C10K1/10—Purifying combustible gases containing carbon monoxide by washing with liquids; Reviving the used wash liquors with aqueous liquids
    • C10K1/12—Purifying combustible gases containing carbon monoxide by washing with liquids; Reviving the used wash liquors with aqueous liquids alkaline-reacting including the revival of the used wash liquors
    • C10K1/14—Purifying combustible gases containing carbon monoxide by washing with liquids; Reviving the used wash liquors with aqueous liquids alkaline-reacting including the revival of the used wash liquors organic
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10K—PURIFYING OR MODIFYING THE CHEMICAL COMPOSITION OF COMBUSTIBLE GASES CONTAINING CARBON MONOXIDE
    • C10K1/00—Purifying combustible gases containing carbon monoxide
    • C10K1/20—Purifying combustible gases containing carbon monoxide by treating with solids; Regenerating spent purifying masses
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10K—PURIFYING OR MODIFYING THE CHEMICAL COMPOSITION OF COMBUSTIBLE GASES CONTAINING CARBON MONOXIDE
    • C10K3/00—Modifying the chemical composition of combustible gases containing carbon monoxide to produce an improved fuel, e.g. one of different calorific value, which may be free from carbon monoxide
    • C10K3/02—Modifying the chemical composition of combustible gases containing carbon monoxide to produce an improved fuel, e.g. one of different calorific value, which may be free from carbon monoxide by catalytic treatment
    • C10K3/04—Modifying the chemical composition of combustible gases containing carbon monoxide to produce an improved fuel, e.g. one of different calorific value, which may be free from carbon monoxide by catalytic treatment reducing the carbon monoxide content, e.g. water-gas shift [WGS]
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10K—PURIFYING OR MODIFYING THE CHEMICAL COMPOSITION OF COMBUSTIBLE GASES CONTAINING CARBON MONOXIDE
    • C10K3/00—Modifying the chemical composition of combustible gases containing carbon monoxide to produce an improved fuel, e.g. one of different calorific value, which may be free from carbon monoxide
    • C10K3/06—Modifying the chemical composition of combustible gases containing carbon monoxide to produce an improved fuel, e.g. one of different calorific value, which may be free from carbon monoxide by mixing with gases
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10J—PRODUCTION OF PRODUCER GAS, WATER-GAS, SYNTHESIS GAS FROM SOLID CARBONACEOUS MATERIAL, OR MIXTURES CONTAINING THESE GASES; CARBURETTING AIR OR OTHER GASES
    • C10J2300/00—Details of gasification processes
    • C10J2300/16—Integration of gasification processes with another plant or parts within the plant
    • C10J2300/164—Integration of gasification processes with another plant or parts within the plant with conversion of synthesis gas
    • C10J2300/1643—Conversion of synthesis gas to energy
    • C10J2300/1646—Conversion of synthesis gas to energy integrated with a fuel cell
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10J—PRODUCTION OF PRODUCER GAS, WATER-GAS, SYNTHESIS GAS FROM SOLID CARBONACEOUS MATERIAL, OR MIXTURES CONTAINING THESE GASES; CARBURETTING AIR OR OTHER GASES
    • C10J2300/00—Details of gasification processes
    • C10J2300/16—Integration of gasification processes with another plant or parts within the plant
    • C10J2300/164—Integration of gasification processes with another plant or parts within the plant with conversion of synthesis gas
    • C10J2300/1643—Conversion of synthesis gas to energy
    • C10J2300/165—Conversion of synthesis gas to energy integrated with a gas turbine or gas motor
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10J—PRODUCTION OF PRODUCER GAS, WATER-GAS, SYNTHESIS GAS FROM SOLID CARBONACEOUS MATERIAL, OR MIXTURES CONTAINING THESE GASES; CARBURETTING AIR OR OTHER GASES
    • C10J2300/00—Details of gasification processes
    • C10J2300/16—Integration of gasification processes with another plant or parts within the plant
    • C10J2300/164—Integration of gasification processes with another plant or parts within the plant with conversion of synthesis gas
    • C10J2300/1643—Conversion of synthesis gas to energy
    • C10J2300/1653—Conversion of synthesis gas to energy integrated in a gasification combined cycle [IGCC]
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10J—PRODUCTION OF PRODUCER GAS, WATER-GAS, SYNTHESIS GAS FROM SOLID CARBONACEOUS MATERIAL, OR MIXTURES CONTAINING THESE GASES; CARBURETTING AIR OR OTHER GASES
    • C10J2300/00—Details of gasification processes
    • C10J2300/16—Integration of gasification processes with another plant or parts within the plant
    • C10J2300/164—Integration of gasification processes with another plant or parts within the plant with conversion of synthesis gas
    • C10J2300/1656—Conversion of synthesis gas to chemicals
    • C10J2300/1659—Conversion of synthesis gas to chemicals to liquid hydrocarbons
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10J—PRODUCTION OF PRODUCER GAS, WATER-GAS, SYNTHESIS GAS FROM SOLID CARBONACEOUS MATERIAL, OR MIXTURES CONTAINING THESE GASES; CARBURETTING AIR OR OTHER GASES
    • C10J2300/00—Details of gasification processes
    • C10J2300/16—Integration of gasification processes with another plant or parts within the plant
    • C10J2300/1671—Integration of gasification processes with another plant or parts within the plant with the production of electricity
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10J—PRODUCTION OF PRODUCER GAS, WATER-GAS, SYNTHESIS GAS FROM SOLID CARBONACEOUS MATERIAL, OR MIXTURES CONTAINING THESE GASES; CARBURETTING AIR OR OTHER GASES
    • C10J2300/00—Details of gasification processes
    • C10J2300/16—Integration of gasification processes with another plant or parts within the plant
    • C10J2300/1671—Integration of gasification processes with another plant or parts within the plant with the production of electricity
    • C10J2300/1675—Integration of gasification processes with another plant or parts within the plant with the production of electricity making use of a steam turbine
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10J—PRODUCTION OF PRODUCER GAS, WATER-GAS, SYNTHESIS GAS FROM SOLID CARBONACEOUS MATERIAL, OR MIXTURES CONTAINING THESE GASES; CARBURETTING AIR OR OTHER GASES
    • C10J2300/00—Details of gasification processes
    • C10J2300/16—Integration of gasification processes with another plant or parts within the plant
    • C10J2300/1678—Integration of gasification processes with another plant or parts within the plant with air separation
    • 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
    • Y02P20/129—Energy recovery, e.g. by cogeneration, H2recovery or pressure recovery turbines

Definitions

  • the invention is the field power plants, in conjunction with chemical processes, including the Fischer-Tropsch (FT) process.
  • FT Fischer-Tropsch
  • the synthesis gas created by gasification, steam methane reforming (SMR), or other processes can be utilized to produce both chemicals and fuels.
  • the FT process produces ultra-clean fuels that are low in sulfur content, have excellent combustion characteristics, and can be derived from domestic sources. This helps to lower the cost of transportation fuels, creates jobs domestically, and reduces the reliance on imported oil.
  • Other processes such as methanol-to-gasoline (MTG) can also be employed to produce gasoline. In this process, syngas is first converted into methanol, and then subsequently converted into gasoline.
  • MTG methanol-to-gasoline
  • IGCC integrated gasification combined cycle
  • chemical production and FT processes are of interest, they can be very capital intensive, and therefore can be somewhat expensive compared to traditional methods of power generation, chemical production, and oil production. This makes these plants less attractive to potential developers, as less costly competitive methods of power generation or a drop in crude oil prices can lead to economic disaster for these projects.
  • coal-to-liquids (CTL) process and other chemical processes can be very similar to IGCC, in that many of these processes start with gasification (see Fig. 9).
  • this process is referred to as "coal-to-liquids", it is not meant to preclude the use of petroleum coke, biomass, municipal solid waste, and other carbonaceous fuels.
  • coal in the embodiment is meant to include coal and/or other fuels that can be utilized in the process (with the possibility of 2 or more fuels co-fired simultaneously).
  • pulverized coal is injected into the gasification vessel along with a supply of air or high purity oxygen (95% or higher purity). Steam may also be injected into the gasifier. These streams react to create a synthesis gas or syngas. With an oxygen supply, the syngas is comprised of mostly carbon monoxide (CO), hydrogen (H 2 ), carbon dioxide (CO 2 ), and water vapor (H 2 O), with smaller amounts of hydrogen sulfide (H 2 S), carbonyl sulfide (COS), nitrogen (N 2 ), and other compounds.
  • H 2 S hydrogen sulfide
  • COS carbonyl sulfide
  • N 2 nitrogen
  • hydrocarbons such as octane (CsHi 8 ) and decane (CioH 22 ). These hydrocarbons are the essential liquids found in gasoline and diesel fuel, respectively.
  • the FT reaction it is important to eliminate as many of the non-essential species in the syngas, and provide as much of a pure CO/H 2 stream as possible.
  • the ratio of H 2 to CO should be within a specified range for the catalyst to provide optimal conversion to liquid fuel.
  • sulfur can contaminate the catalyst, the vast majority of it must be removed from the syngas. To help meet EPA standards and provide for less pollution when burned, the lower sulfur content of the syngas equates to an FT fuel that contains less sulfur.
  • One method employed to achieve the proper syngas for the FT reactors involves syngas cooling, a shift reaction, further syngas cooling, a process for syngas clean-up, mercury removal, CO 2 removal, and finally an H 2 removal process to provide H 2 for product upgrade at a downstream stage in the process.
  • the syngas cooling can be accomplished in several ways, but the two common methods are through a syngas cooler or a quench.
  • a syngas cooler is essentially a heat exchanger that transfers the heat from the syngas to another fluid.
  • the other fluid is pressurized water, which boils into saturated steam in the syngas cooler (although some superheating may also be accomplished). This steam can be used to generate electricity.
  • the syngas coolers are large pieces of equipment that are capital intensive, and a simpler method is the use of a quench.
  • the quench process involves spraying pressurized water directly into the syngas stream. The water evaporates into steam, and in doing so, cools the syngas/water mixture to a lower temperature. This is also advantageous, as the shift reaction requires a mixture of steam (H 2 O) to CO of about 2.5 on a molar basis.
  • the syngas/steam mixture is passed through a catalyst and the following reaction occurs:
  • the process is designed such that the proper ratio of H 2 to CO will be available upon entry to the FT reactors.
  • the syngas is cooled further to approximately 100° F. Since the temperatures after the shift reaction are typically less than 1000° F, it is standard practice to cool this syngas with coolers that produce lower pressure saturated steam, since lower pressure steam boils at lower temperatures. Therefore, the syngas stream after the shift reaction may produce steam at a nominal 400 psia and/or 80 psia to reduce its temperature to about 250° F. From 250° F to 100° F, cooling water may be used, and the heat in this cooling water will likely be rejected to ambient. More than 99% of the steam contained in the syngas will be condensed in this cooling process.
  • the 100° F syngas which is now very dry, proceeds to a syngas clean-up process.
  • the purpose of the clean-up process is to reduce the sulfur content of the syngas to about 1 ppm, remove NH 3 , HCN, and other undesired species, and also to reduce the CO 2 content.
  • a secondary bed such as ZnO
  • the syngas will typically pass through a filter bed, which will absorb at least 90% of the mercury vapor in the syngas.
  • Methanol production would favor a 2:1 H 2 /CO ratio, while diesel or naphtha production may favor a ratio closer to 1 :1.
  • the DOE has completed a study of a 50,000 barrel-per-day (BPD) CTL design.
  • the optimum H 2 /CO ratio is essentially 1 :1 in this example. See Fig. 1 for a general process schematic of this CTL facility (which is Figure ES-1 in the DOE/NETL-2007/1260 report which is hereby incorporated by reference).
  • a tail-gas is produced.
  • an off-gas is produced in the product upgrade portion of the process. Both the tail-gas and the off-gas can be combusted in a gas turbine (GT), boiler, duct burner, or other device designed to combust fuel.
  • GT gas turbine
  • boiler boiler
  • duct burner or other device designed to combust fuel.
  • a CTL plant designed to produce 50,000 barrels per day (BPD) of FT liquids can also produce a net power output of 124 MW.
  • the energy utilization factor for this plant is 47%, meaning that 47% of the input energy of the fuel (coal in this example) ends up as a final product, either liquid fuel or electricity.
  • the CTL process is one example where a stream of syngas is created, cleaned, and subsequently converted into a final product.
  • Other processes include, but are not limited to, the production of methanol, synthetic natural gas, ammonia, gasoline, and other fuels and/or chemicals.
  • syngas is created through gasification, steam methane reforming (SMR), pyrolysis, or another process, these processes typically occur at high temperatures, and the possibility exists to reclaim energy from these streams prior to the actual chemical conversion process.
  • SMR steam methane reforming
  • pyrolysis or another process
  • the preferred embodiment of the present invention seeks to capture more of this energy and utilize it to co-generate electricity and make the overall energy conversion more efficient.
  • IGCC Integrated Gasification Combined Cycle
  • the sulfur emissions of the IGCC plant are somewhat high, as the sulfur content of the syngas is approximately 30 ppm (parts per million). This is significantly higher than the 50 ppb (parts per billion) or less that is attained in the syngas for the CTL facility (note that the DOE CTL report used a ZnO bed to reduce sulfur content of the syngas to 1 ppb).
  • this higher level of sulfur in the fuel results in high SO x content in the GT exhaust gas. This prevents the use of SCR (Selective Catalytic Reduction) in the HRSG, as the SO x reacts with injected ammonia from the SCR and forms ammonia salts downstream of the SCR. These salts foul the downstream heat exchange surfaces in the HRSG. Therefore, NO x must be controlled in the GT, as downstream treatment with SCR is not feasible with the higher syngas sulfur content. Current GT combustion technologies reduce NO x to about 15 ppm.
  • this gas Since this gas is at a low pressure of 20 psia, it requires a great deal of compression power (24,709 kW in this example) to pressurize this fuel to the extent required for use in the GTs 106.
  • the exhaust gases of the GTs 106 are utilized to superheat some of the steam from the process, and may generate some additional steam as well, at the various pressures, HP, MP, and LP. This steam is heated only to the extent possible with the GT exhaust gas energy. This equates to a less than optimal steam cycle. It may be possible to produce more steam from more efficient heat recovery, but this would reduce steam temperatures to the steam turbine.
  • the GTs in the example from the prior art produce only 250.7 MW, while the STs 108 produce 401.3 MW. Therefore, the majority of the power is emanating from the inefficient steam cycle.
  • the overall energy conversion rate for this CTL process from the prior art is approximately 47%. From an environmental perspective, this method of fuel production may produce more CO2 emissions than refining crude oil into similar petroleum products, even with the use of CO2 separation.
  • an IGCC plant could be built per the designs indicated in the report labeled DOE/NETL-2007/1281.
  • the IGCC plant shown in Case 6 identifies a plant that produces 517 MW of net power. It too, utilizes Carbon Capture and Sequestration (CCS) to achieve low CO2 emissions. Its efficiency, however, is only 32%. It also has relatively high SO x and NO x emissions (compared to the case 14 natural gas-fired facility) and will be considerably expensive to construct.
  • CCS Carbon Capture and Sequestration
  • Duke has announced a 630 MW IGCC plant in Indiana that does not include CCS (similar to Case 1 of DOE/NETL-2007/1281 ) that is projected to cost $2.35 billion. So the prior art can provide both CTL and IGCC facilities, however, the conversion efficiencies need improvement, the high costs of construction need to be reduced, and the environmental performance can be better.
  • this embodiment demonstrates an integrated, state-of-the-art facility that is more efficient than separate conventional chemical conversion and IGCC processes, can readily be designed for ultra-low emissions, and yet is economical to construct. For an incremental increase in cost and fuel consumption, the systems and methods of this invention can produce significantly more products such as electricity, fuels, and chemicals.
  • Fig. 1 is a flow chart of the conventional CTL process, Fig. ES-1 from DOE/NETL-2007/1260.
  • Fig. 2 is a cost and performance summary for power plants, Fig. ES-2 from DOE/NETL-2007/1281.
  • Fig. 3 depicts a method for optimizing the H 2 /CO ratio of feed gas with H 2 stripping.
  • Fig. 4 depicts a method for optimizing the H 2 /CO ratio of feed gas with minimal shift.
  • Fig. 5 is a comparison of power cycles with and without steam superheating.
  • Fig. 6 is a general arrangement of the present invention for an FT process.
  • Figs. 7A and 7B depict the syngas cooling and shift for the example of the present invention.
  • Figs. 8A, 8B, 8C, and 8D together make up a flow schematic of the power island for the example of the present invention.
  • Fig. 9 is a general flow chart for gasification processes and end products
  • Fig. 10 depicts a conventional ASU air compression arrangement
  • Fig. 11 depicts an ASU air compression arrangement for the present invention
  • Fig. 12 is a general arrangement of the present invention
  • a new, high efficiency integrated facility that produces electricity in conjunction with fuels and/or chemical production can be constructed by utilizing state-of-the-art techniques that demonstrate synergistic relationships.
  • One of these new techniques is described in US Patent #6,230,480 (the '480 patent), and subsequent patents.
  • a description of this integrated facility, its features, and novel concepts, is described herein.
  • the gasification, SMR, or other process may include syngas coolers that produce steam that can be utilized in the power island
  • Boiler feedwater (BFW) can be preheated by some process flows to provide preheated BFW to the steam producing sections of the plant 8) CO2 from the process can be removed
  • Some carbon may be captured in the final products 10)With a low ratio of nitrogen diluent to total Air Separation Unit (ASU) air supply, some or all nitrogen diluent for the GT may be removed as liquid from a cryogenic separation process and pumped rather than compressed, saving additional parasitic power.
  • ASU Air Separation Unit
  • Power is provided to the plant.
  • Steam may be required at several pressure levels in these plants. Steam can be extracted from the steam turbine to supply some or all of these requirements.
  • Tail gases, off gases, and other streams do not have to be flared, but can be used as fuel in the power island.
  • Steam heating may be employed in lieu of fired heaters that consume fuel (syngas, tailgas, offgas, etc.), increasing overall efficiency.
  • Syngas coolers in lieu of the quench process may reduce the amount of water consumed by the plant.
  • Fig. 12 is a general arrangement of the preferred embodiment of the present invention.
  • a feedstock 220 including natural gas, coal, biomass, petroleum coke, municipal solid waste, or other carbonaceous material, or combination thereof, is fed to a device 222 that converts said feedstock into a synthesis gas 224.
  • Such devices include gasifiers, SMR's, pyrolysis chambers, and others.
  • syngas cooler 226 accepts pressurized boiler feedwater 280, preferably preheated since this will increase the steam production, and subsequently cools the syngas, while the heat given up by the syngas boils the BFW into steam 282. This steam can then be used in the power island.
  • the cooled syngas 228 leaves the syngas cooler and continues to a cleanup process 230.
  • the preferred embodiment cools this portion of the process with cold BFW 284. This preheats the BFW 286, which can then be used to generate steam in other portions of the integrated plant.
  • the clean syngas 232 can be directed to the conversion process 238. This includes SNG, FT, methanol, or other conversion processes. Some of the clean syngas can also be directed to the power island to be used as fuel 234. As the syngas reacts in the conversion process, heat is generated. This heat can be captured as steam 290. Again, preheated BFW 288 is the preferred supply, as it will result in more steam generation. Some BFW may be preheated in the conversion process.
  • the conversion process which may consist of multiple steps, produces the final products 240 from the process. In addition to these final products, byproduct fuels, sometimes referred to as tailgas, offgas, or other names, may be produced.
  • These fuels may be produced at higher pressures 242 and/or lower pressures 244, and can be utilized in the power island to generate electricity.
  • This preheated feedwater when directed to the syngas cooler and conversion process, generates greater steam flows, as available energy from these processes can be used to boil said water, versus heating cold BFW up to boiling temperature.
  • the synergistic power island 250 accepts the higher-pressure tailgas 242 for supply to the GT 252, and in addition may also utilize some of the syngas 234 from upstream of the conversion process. These fuels, at higher pressure, are ideally suited for use in the GT; however, some compression may still be required to meet the fuel pressure requirements of the GT.
  • Lower pressure fuels 244 are ideally suited for use in the duct burners 254 in the HRSG 270, as the fuel pressure requirement for duct burners is much lower than that of a GT.
  • syngas 234 from prior to the conversion process may also be used as supplemental fuel in the duct burners.
  • a mix of fuel preferably at higher pressure, is supplied by streams, 242, 234, and possibly 244. This mix is used as a fuel supply 246 to the GT.
  • a mix of fuel preferably from the lower pressure sources, is supplied by streams, 244, 234, and possibly 242. This mix is used as a fuel supply 248 to the duct burners.
  • HP steam 256 recovered from the plant is directed to the HRSG.
  • This steam is combined with HP steam generated from within the HRSG and directed to the superheater section 258 of the HRSG.
  • This superheated steam is sent to the HP section 260 of the ST, where it expands to a lower pressure.
  • the steam exiting the HP section referred to as "cold reheat steam”
  • This steam can be reheated in the reheat section 264 of the HRSG (although preferable, it is not necessary) and subsequently directed to the IP section 266 of the ST. From this point, the steam expands to lower pressure, and in many instances, to the pressure in the condenser.
  • Some steam 268 may be extracted from the ST, at any point or pressure; to supply steam needs for the plant or process.
  • Preheated BFW is preferable, as it will allow for more steam production.
  • Preheated BFW is also produced in the HRSG.
  • Cold BFW 272 enters the HRSG and is preheated in the economizer section 276 downstream of the evaporator 278. Some of this preheated BFW is directed to the evaporator section, however, some preheated BFW 274 is diverted to other sections of the plant to aid in the production of steam.
  • a specially designed ASU provides preheated BFW 298 to the plant for increased power production and increased integrated plant efficiency.
  • One method is to make excess syngas (more than is required by the FT process), and create two separate streams.
  • the first stream is the primary stream, while the second is the secondary stream.
  • isolate and remove the needed specie typically H 2
  • stream X Next mix this highly pure stream X with the primary stream to achieve the necessary flow, composition, and H 2 /CO ratio needed in the downstream process.
  • the secondary stream now depleted of some of its flow, can be used as fuel elsewhere in the plant.
  • the syngas from the gasification process can be directed to syngas coolers to extract heat, and produce steam that can be used in the process or in the power island.
  • syngas coolers to extract heat, and produce steam that can be used in the process or in the power island.
  • H 2 /CO ratio either H 2 or CO can be stripped from a secondary flow stream and supplied to the primary stream (Fig. 3), or the use of quench and/or the shift reaction may be used to adjust the ratio of a portion of the syngas, which can again be mixed with the primary syngas stream (Fig. 4).
  • syngas to the FT system should contain no more than 50 ppb of sulfur bearing compounds.
  • the H 2 and CO react to form final products, such as methanol, methane, FT liquids, and others.
  • final products such as methanol, methane, FT liquids, and others.
  • Some CO2 and H 2 O may be generated in the process.
  • these processes are exothermic, and considerable heat is generated.
  • heat exchange tubes may be embedded in the appropriate place in the process. These tubes typically contain water that is pressurized to the appropriate pressure such that steam is created at the desired temperature to ultimately control the reaction temperature. As a result, large quantities of saturated steam at medium pressure may be produced as a byproduct of the reaction.
  • this medium pressure saturated steam 154 along with high-pressure saturated steam from the syngas coolers 130, can be directed to a highly fired HRSG 156 as described in US patent 6,230,480 et al.
  • the high firing temperatures in the HRSG provide the necessary heat to superheat and reheat the HP steam 130, and to superheat the medium pressure steam 154. This is an important step to achieving higher efficiencies. It is well known in the industry that superheated steam is more efficient in a power cycle than saturated steam. See Figure 5, case 1 for a depiction of a steam cycle. Saturated steam at 438 psia (453.57° F) 116 is admitted to the steam turbine 118.
  • the incremental heat rate is defined as the added energy (344.3 MMBtu) divided by the incremental power (52.604 MW). This equates to 6545 Btu/kWh. This equates to an efficiency of 52.1 %, and is significantly better than the heat rate of 10,674 Btu/kWh (32.0%) listed in Fig. 2 for Case 6. Therefore, this use of heat addition to the saturated steam flows can enhance performance and efficiency.
  • a power island 134 consisting of a GT, HRSG, and a ST. See Fig. 6 for a general arrangement of the present invention used with an FT process. It also could include a Boiler in lieu of a GT and HRSG.
  • Some fuel from the FT process or syngas is directed to the GT 126 for power production, while some fuel is utilized in the duct burners 128 of the HRSG.
  • High-pressure steam 130 from the syngas coolers 132 which is typically saturated, is directed to the superheaters in the HRSG 170. This superheats the HP steam flow. This superheated steam is sent to the HP section136 of the steam turbine.
  • steam from the FT process 154 which is typically saturated and at medium pressure, can be directed the cold reheat line exiting the HP section of the steam turbine.
  • These steam flows are mixed 172 and directed to the reheater sections 174 of the HRSG. In these sections, the mixed steam flow is superheated and directed to the Intermediate Pressure (IP) section of the steam turbine 144.
  • IP Intermediate Pressure
  • higher temperature boiler feedwater (BFW) 138 can be provided to the syngas coolers and the FT process coolers.
  • the HRSG, the low temperature syngas coolers 140, and FT process coolers 142 can supply this higher temperature boiler feedwater 138.
  • a feedwater-heating loop, consisting of a series of feedwater heater(s) can be employed to preheat water prior to its introduction into one of the boiling devices.
  • BFW can be preheated in a specially designed ASU.
  • Cryogenic ASU's compress atmospheric air prior to the cryogenic separation process. This air compression consumes a great deal of power, so steps are taken to minimize these power requirements, including the use of intercooling between stages of compression.
  • Fig. 10 illustrates a conventional ASU arrangement from the prior art.
  • the ASU To provide oxygen, the ASU first compresses and cools air. Ambient air 300 enters a compressor 302 and is compressed to an intermediate pressure. After this compression process, the air temperature is increased. Since it takes more energy to compress hot air than it does to compress cooler air, this intermediate pressure air is then cooled in an intercooler 304. A supply of coolant, 312, is used to cool this air. This coolant is typically water.
  • the cooled intermediate pressure air it subsequently compressed in another compressor 306 to the final required pressure.
  • This air also heated by the compression process, is now directed to an aftercooler 308 that again uses a coolant 314.
  • the cooled and compressed air 310 is directed to the cryogenic separation process.
  • Fig. 10 depicts a simple 2-stage system. This may be a multiple stage system, with multiple compressors and multiple coolers.
  • the coolant is typically water directly from the cooling tower of the plant, or may be from a separate auxiliary cooling loop. The energy from these coolers is ultimately rejected to ambient without assisting in the power generation process.
  • the preferred embodiment will utilize the energy from the ASU to its advantage in generating power.
  • Ambient air 320 is drawn into a compressor 322. This air is compressed to an intermediate pressure and then directed to a 2 nd compressor 326. This elevates the temperature of the air as well as its pressure. This air is subsequently directed to a cooler 324.
  • This cooler utilizes cold BFW 332 as a coolant, and the preheated BFW 336 is used in the process to generate additional steam in the steam generating devices (syngas coolers, process coolers, HRSG, and other).
  • the compressed air is sent to a secondary cooler 328 that cools the compressed air 330 to the same temperature as the conventional ASU prior to its introduction to the cryogenic process.
  • Table 9 provides data that corresponds with the labeled data on each stream identified in Fig. 10.
  • the conventional ASU from the prior art requires 276.4 MW of power for compression in this example. All energy from the coolers is rejected to ambient.
  • the conventional ASU from the prior art requires 13.5 million Ib/hr of cooling water flow at a supply temperature of 71 ° F, and a return temperature that is between 135° and 140° F. This equates to 27,000 gallons per minute (gpm).
  • Table 10 provides data that corresponds with the labeled data on each stream identified in Fig. 11.
  • the air is compressed and subsequently cooled first with BFW. This cooling process captures 956 MMBtu in the BFW preheat. This is equivalent to about 980 tons per day of coal, or about 3.3% of the total energy input of the fuel in said CTL example.
  • this new invention provides 2 million Ib/hr of preheated
  • 70 MW would be used to provide the added power for air compression in the present invention ASU and the added load for an additional 1000 tpd of coal throughput.
  • the new ASU from the preferred embodiment of the present invention only requires 2.0 million Ib/hr of cooling water flow at a supply temperature of 71 ° F, and a return temperature that is less than 125°. This equates to only 4,000 gpm. Thus the ASU from the present invention utilizes less cooling water, and rejects less heat to atmosphere.
  • the power island is the power generation portion of the plant.
  • gases and other fuels from the process are fed to a GT and duct burners contained within the HRSG.
  • High-pressure steam from the various aforementioned sections of the plant, along with steam from the HRSG, is superheated in the HRSG prior to its introduction to the ST.
  • Higher temperatures yield higher efficiencies, so temperatures of 1000° F or greater are preferred.
  • the exiting steam (cold reheat steam) can be combined with the medium pressure steam from the process. This combined steam flow may then be reheated in the HRSG prior to its introduction into the IP section of the ST. Steam may be extracted from the ST at one of more pressures for use in the plant.
  • the overall concept of this integrated plant is to create more steam, and more efficient steam for the production of power. Since the power island utilizes an HRSG where the heat input to the duct burners is 30% or more of the input to the GT, a great deal of steam superheating and reheating can be accomplished.
  • the other advantage to this arrangement is the heat recovery aspects. Since this integrated process, with its high duct burner input, creates a larger quantity of steam, more BFW is needed for this steam production. Therefore, in lieu of production low-pressure steam to recoup process heat, the large quantities of cold BFW from the condenser can be utilized to recover lower temperature energy.
  • An example would be the HRSG, which primarily produces steam at high pressure, and uses cold BFW to cool the exhaust gases from the GT to industry standard temperatures (near 200° F for the aforementioned example)
  • the power island provides a step change in cost and efficiency for chemical conversion and power generation.
  • the off gases can be directed to the duct burners, which may only need a fuel supply pressure of 50 psia.
  • Higher-pressure fuel such as the tail gases (recycle gases from DOE/NETL-2007/1260), as well as clean syngas, can be used in the GTs.
  • Large, modern GTs require fuel pressures in the vicinity of 450 psia.
  • the benefits to the deployment of the present invention are numerous and significant.
  • the first benefit is greater efficiency. Since more energy is captured and utilized in the present invention, the overall conversion efficiency is increased.
  • overall conversion efficiency of comparable conventional facilities CTL & IGCC
  • CTL & IGCC overall conversion efficiency of comparable conventional facilities
  • the present invention demonstrates an overall conversion efficiency of 50.2%. This represents an 18.4% increase in efficiency for the present invention.
  • the present invention also achieves lower environmental impact.
  • IGCC can employ technologies for deep sulfur removal (such as the present invention), these technologies increase the cost of an already expensive method for power generation.
  • the conventional equivalent plants emit a nominal 0.10 Ib/MWh of SO2 emissions, versus almost zero sulfur emissions for the present invention. In nominal numbers, this is a 100:1 reduction in sulfur emissions as compared to conventional technology.
  • the conventional IGCC controls this pollutant by combustion techniques within the GT. Downstream SCR control cannot be employed due to the high levels of sulfur in the GT exhaust. For the CTL example contained herein, calculated NO x emissions are 0.768 Ib/MWh. Due to the use of SCR, and the use of fewer GT's (less exhaust gas to treat), the projected emissions for the present invention are 0.077 Ib/MWh. So the NO x emissions are reduced by a nominal 10:1 factor.
  • CO2 emissions are also reduced.
  • CO2 emissions for the conventional plants are 6,085 tons per day, versus only 5,045 per day for the present invention.
  • the conventional plants require 56,464 tons per day of CO 2 be sent to sequestration, while the present invention requires only 41 ,437 tons per day.
  • the present invention can utilize less equipment to achieve the same rate of production.
  • the present invention can utilize fewer and/or smaller gasifiers than the prior art. This equates to both a lower up front capital cost, as well as lower on going maintenance costs. This same principle also applies to the ASU's, which are used in conjunction with gasifiers.
  • the preferred embodiment of the present invention increases efficiency and reduces capital costs by exploiting the low costs benefits of supplemental firing in a combined cycle, but also be using said supplemental firing to increase the efficiency of the steam cycle.
  • the CTL plant from the DOE report included 251 MW of GT output and 401 MW of ST output.
  • Two IGCC plants from Case 6 include 927 MW of GT output and 460 MW of ST power (gross power generation). This is a total of 1 ,178 MW of GT power and 861 MW of ST power.
  • the ratio of ST to GT power in the prior art is 0.73. Even with a great deal of supplemental firing, it would be difficult for this ratio to be greater than 1.0. So for a CTL plant, with little export power, the ST/GT ratio is 1.6. As more power is added, this ratio is diminished in the prior art, to a ratio of 0.73 when 1034 MW of power is added.
  • the prior art is limited to ST/GT ratios of 1.6 or less when small amounts of export power are included.
  • the ST/GT ratio is 1.6.
  • the ST/GT ratio is 0.73.
  • an additional GT could be used. This would actually increase GT and ST power, approximately 83 MW for the GT and 50 MW for the ST. This would actually decrease the ST/GT ratio to 1.35.
  • the FP/P ratio will be less than
  • Fig. 1 herein, reveals that the combined flows (streams 10, 11 , plus 16) into the F-T Synthesis Block contain 80,464 Ib-moles (referred to as moles) of H 2 and 82,077 moles of CO.
  • Other species such as CO 2 , CH 4 , N 2 , Ar, and others are considered to be inert in the F-T reaction. Therefore, by providing the same flows of H 2 and CO to the F-T Synthesis Block 102, the same amount of F-T products should be produced.
  • Stream 14 from the CTL process can now be utilized as fuel in the power island.
  • CH 4 in stream 14 (which will now be referred to as "Tail Gas”). This will equate to less energy content in this stream.
  • 1085 moles of CH 4 are created in the F-T synthesis. Therefore, with a different syngas supply, and the creation of 1085 moles of CH 4 in the F-T process, the corrected flow at stream 14 is shown in Table 1.
  • the inert gases (including CH 4 ) will end up in the Off Gas (referred to as Fuel Gas 104 in Fig. 1 ).
  • Table 2 shows the corrected flows and composition for this Off Gas, which will be used in the power island as fuel.
  • the preferred embodiment of the present invention includes using saturated HP steam 130 from the gasification process and other processes, and superheating this steam to higher temperature. It also includes the design of the ST 134 such that the cold reheat steam from the HP section of the steam turbine 136 is reheated in the HRSG, and saturated steam from the F-T process 154 is also superheated in the HRSG. It may be possible to mix both of these steam lines and then superheat the combined flow in the HRSG, as shown in Fig. 6. This superheated/reheated steam is then directed to the IP section 144 of the ST.
  • the amount of energy in the exhaust streams of the GTs must be determined, and the amount of energy required to superheat/reheat steam must also be determined. From this data, the number of GTs, their size, and the degree of supplemental firing in the HRSG can be determined. Note that there may be many different combinations of GTs and supplemental firing rates; however, one of these combinations can usually be selected on the basis of capital cost, performance, equipment constraints, etc. For this example, two (2) GE Frame 7FB gas turbines were selected with two (2) GE Frame 7FB gas turbines.
  • Fig. 7A and Fig. 7B show a simplified schematic of the syngas cooling and shift process for this new stream, which is 1.85 times the flow tabulated in Case 6.
  • Table 3 shows the data process, including pressure, temperatures, and flows.
  • the shift process although done in progressive stages, is shown here as only one stage for simplicity. Note that high pressure saturated steam is generated in the process and directed to the power island. This is in contrast to the prior art, where steam from the shift reaction is generated at medium pressure.
  • the present invention primarily uses BFW and LP steam to cool the syngas. This HP steam production has efficiency advantages over the production of medium pressure steam.
  • the gasification process now consists of generating 3.563 times the syngas that is created in Case 5, stream 17 (non-shifted syngas). Also, 1.85 times the amount of syngas is created as compared to Case 6, stream 18 (shifted syngas). Of this shifted stream, 1.135 times the Case 6 flow is directed to the F-T synthesis block. This is combined with the non-shifted syngas (3.563 times Case 5) to yield the proper flow and composition into the F-T synthesis block. A portion of the remaining shifted syngas is combined with the Tail Gas (corrected flow and composition in Table 1 ) and used as high-pressure fuel for the GTs.
  • Figs. 8A through 8D make up a schematic of one-half of the power island for this integrated CTL/IGCC facility. Therefore, one half of the steam flows from the F-T process, syngas cooling, and other sections of the plant are indicated. Also, one-half of the fuel is used in this section of the power island, and one-half of the steam required for the process (export steam) is extracted. The net power is the gross power generated in this half of the power island minus one-half of the auxiliary loads. Therefore, total power generated is twice that of the number indicated in Fig. 8, or 1100 MW. Table 4 includes the data for the various streams included in Fig. 8.
  • GTEX3 DB1 RHT2 2160.624268 12.97649193 4343266.5 623.9285889 2.65841 1264
  • TAI L3 EVAP2 M9 641.0136108 499.9999695 169510 331.9559021 3.090374231
  • Table 8 is a DOE provided compilation of the steam data for the various sections of the CTL facility. The negative numbers indicate steam production, while positive numbers indicate steam consumption. The far right hand column provides the net sum of the steam production for the various steam "headers" or steam supply lines. This steam must be supplied from a source in the integrated CTL/IGCC for the F-T process to function properly.
  • Table 5 details the calculations for the auxiliary loads. It does not include the auxiliary loads for the pumps, cooling tower, and other equipment included in the Fig. 8 schematic, as these loads are calculated by the GateCycle® program (a GE software that calculates performance of combined cycle power plants). Note that the total coal flow is 5.50 times the Case 5 example, therefore, items such as coal grinding, slag handling, and other related loads are taken from Case 5 and scaled by the 5.50 factor. Some items, such as fuel gas compression have been calculated. Table 5
  • Tail Gas Recycle 0 0 1.00 0
  • the design is significantly different than the IGCC cases.
  • Case 5 and 6 from the IGCC study a significant portion of the nitrogen from the cryogenic separation process is needed as diluent to the GTs to suppress the formation of NO x in the combustors.
  • a large quantity of oxygen is required for gasification, yet, only a relatively small portion of the nitrogen is required by the GTs (since only a minor portion of the syngas is used by the power island, with the vast majority used in the F-T process). Therefore, the design is such that it may allow some nitrogen from the cryogenic process to be pumped as a liquid rather than compressed as a gas. This saves considerable power.
  • the net result for the present invention is lower fuel consumption, lower emissions, and lower cost. Lower maintenance costs are also anticipated, as there is less overall equipment as compared to practice in the prior art.
  • the present invention like a cogeneration facility, makes excellent use of the heat and energy from the CTL plant in the power island, while the power island provides superheating of steam, preheated feedwater, and power to the CTL/gasification facility. Some of the carbon from the feedstock is captured in the F- T liquids, while a large portion of the remaining carbon (as CO2) is captured for sequestration. This arrangement is far superior to the prior art method of constructing separate IGCC and CTL plants.
  • Table 7 provides a comparison of the major pieces of equipment that are required in the prior art versus the present invention.
  • the power island for the present invention utilizes the '480 patent combined cycle technology and consists of 2 GTs (GE Frame 7FB or equal), 2 - highly fired HRSG's, and two (2) moderate sized 600 MW steam turbines (ST's).
  • 2 GTs GE Frame 7FB or equal
  • HRSG's 2 - highly fired HRSG's
  • ST's moderate sized 600 MW steam turbines
  • One large 1200 MW ST could possibly be utilized in lieu of the moderate-sized units. Because of the size and design for these steam turbines, the possibility also exists to use this concept to repower existing coal-fired assets.
  • the present invention provides the means to efficiently and cost-effectively convert coal into both liquid fuels and electricity. It utilizes more of the coal's energy in the end products, has lower emissions of SO x , NO x , mercury, and CO2, and only needs to sequester 73% of the CO2 that conventional plants of similar output would require.

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Abstract

L'invention concerne une installation CTL/IGCC intégrée qui est plus efficace que des procédés CTL et IGCC séparés conventionnels, et qui peut être aisément conçue pour des émissions ultra-basses, tout en étant de construction économique. Pour une augmentation incrémentale du coût et de la consommation de combustible, les systèmes et les procédés de la présente invention peuvent produire considérablement plus de produits tels que de l'électricité et des combustibles FT.
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CN103380198A (zh) * 2011-01-14 2013-10-30 Vapo有限公司 用于利用生物质制油工厂中产生的气体的热能的方法
WO2015068088A1 (fr) 2013-11-07 2015-05-14 Sasol Technology Proprietary Limited Procédé et installation pour la cogénération de chaleur et d'énergie
WO2015068087A1 (fr) 2013-11-07 2015-05-14 Sasol Technology Proprietary Limited Procédé et installation pour la cogénération de chaleur et d'énergie
WO2015068086A1 (fr) 2013-11-07 2015-05-14 Sasol Technology Proprietary Limited Procédé et installation de génération conjointe de chaleur et de courant

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WO2006070018A1 (fr) * 2004-12-30 2006-07-06 Shell Internationale Research Maatschappij B.V. Ameliorations relatives a des procedes de conversion de charbon en liquide
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US8105403B2 (en) * 2007-09-14 2012-01-31 Rentech, Inc. Integration of an integrated gasification combined cycle power plant and coal to liquid facility
CN103380198A (zh) * 2011-01-14 2013-10-30 Vapo有限公司 用于利用生物质制油工厂中产生的气体的热能的方法
EP2663619A1 (fr) * 2011-01-14 2013-11-20 Vapo Oy Procédé d'utilisation de l'énergie thermique des gaz en produit dans une usine appartenant à la filière btl
EP2663619A4 (fr) * 2011-01-14 2014-06-25 Vapo Oy Procédé d'utilisation de l'énergie thermique des gaz en produit dans une usine appartenant à la filière btl
WO2015068088A1 (fr) 2013-11-07 2015-05-14 Sasol Technology Proprietary Limited Procédé et installation pour la cogénération de chaleur et d'énergie
WO2015068087A1 (fr) 2013-11-07 2015-05-14 Sasol Technology Proprietary Limited Procédé et installation pour la cogénération de chaleur et d'énergie
WO2015068086A1 (fr) 2013-11-07 2015-05-14 Sasol Technology Proprietary Limited Procédé et installation de génération conjointe de chaleur et de courant
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AU2014347766B2 (en) * 2013-11-07 2018-01-25 Sasol Technology Proprietary Limited Method and plant for co-generation of heat and power
US10233789B2 (en) 2013-11-07 2019-03-19 Sasol Technology Proprietary Limited Method and plant for co-generation of heat and power
US10302296B2 (en) 2013-11-07 2019-05-28 Sasol Technology Proprietary Limited Method and plant for co-generation of heat and power
US10502408B2 (en) 2013-11-07 2019-12-10 Sasol Technology Proprietary Limited Method and plant for co-generation of heat and power

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