US20120291351A1 - Reforming methane and higher hydrocarbons in syngas streams - Google Patents

Reforming methane and higher hydrocarbons in syngas streams Download PDF

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Publication number
US20120291351A1
US20120291351A1 US13/468,189 US201213468189A US2012291351A1 US 20120291351 A1 US20120291351 A1 US 20120291351A1 US 201213468189 A US201213468189 A US 201213468189A US 2012291351 A1 US2012291351 A1 US 2012291351A1
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United States
Prior art keywords
syngas
stream
oxygen
fuel
raw syngas
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US13/468,189
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English (en)
Inventor
Lawrence Bool
Shrikar Chakravartt
Stefan E.F. Laux
Raymond F. Drnevich
Dante P. Bonaquist
David R. Thompson
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Praxair Technology Inc
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Praxair Technology Inc
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Priority to US13/468,189 priority Critical patent/US20120291351A1/en
Priority to RU2013155468/05A priority patent/RU2600373C2/ru
Priority to PCT/US2012/037562 priority patent/WO2012158536A1/en
Priority to CA2836270A priority patent/CA2836270C/en
Priority to ES12727183T priority patent/ES2734478T3/es
Priority to PL12727183T priority patent/PL2710095T3/pl
Priority to EP12727183.1A priority patent/EP2710095B1/en
Priority to BR112013029511A priority patent/BR112013029511B1/pt
Priority to MX2013013452A priority patent/MX364832B/es
Priority to PT12727183T priority patent/PT2710095T/pt
Priority to KR1020137032937A priority patent/KR20140043751A/ko
Priority to JP2014511420A priority patent/JP2014518924A/ja
Priority to CN201280035295.5A priority patent/CN103857772A/zh
Assigned to PRAXAIR TECHNOLOGY, INC. reassignment PRAXAIR TECHNOLOGY, INC. ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: BOOL, LAWRENCE, CHAKRAVARTI, SHRIKAR, LAUX, STEFAN EF, THOMPSON, DAVID R., BONAQUIST, DANTE P., DRNEVICH, RAYMOND F.
Publication of US20120291351A1 publication Critical patent/US20120291351A1/en
Priority to US14/973,774 priority patent/US20160102259A1/en
Abandoned legal-status Critical Current

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    • 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
    • C01B3/32—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air
    • C01B3/34—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air by reaction of hydrocarbons with gasifying agents
    • C01B3/36—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air by reaction of hydrocarbons with gasifying agents using oxygen or mixtures containing oxygen as gasifying agents
    • C—CHEMISTRY; METALLURGY
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    • C10J3/00—Production of combustible gases containing carbon monoxide from solid carbonaceous fuels
    • C10J3/72—Other features
    • C10J3/82—Gas withdrawal means
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
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    • C10J3/00—Production of combustible gases containing carbon monoxide from solid carbonaceous fuels
    • 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
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    • C10J3/00—Production of combustible gases containing carbon monoxide from solid carbonaceous fuels
    • C10J3/46—Gasification of granular or pulverulent flues in suspension
    • C10J3/463—Gasification of granular or pulverulent flues in suspension in stationary fluidised beds
    • 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
    • C10K1/003—Removal of contaminants of acid contaminants, e.g. acid gas removal
    • C10K1/004—Sulfur containing contaminants, e.g. hydrogen sulfide
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
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    • C10K1/00—Purifying combustible gases containing carbon monoxide
    • C10K1/002—Removal of contaminants
    • C10K1/003—Removal of contaminants of acid contaminants, e.g. acid gas removal
    • C10K1/005—Carbon dioxide
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
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    • 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
    • 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
    • C10K3/001—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 thermal treatment
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
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    • 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
    • C10K3/001—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 thermal treatment
    • C10K3/003—Reducing the tar content
    • C10K3/005—Reducing the tar content by partial oxidation
    • 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]
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    • 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
    • C01B2203/02—Processes for making hydrogen or synthesis gas
    • C01B2203/025—Processes for making hydrogen or synthesis gas containing a partial oxidation step
    • C01B2203/0255—Processes for making hydrogen or synthesis gas containing a partial oxidation step containing a non-catalytic partial oxidation step
    • C—CHEMISTRY; METALLURGY
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    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/06—Integration with other chemical processes
    • C01B2203/062—Hydrocarbon production, e.g. Fischer-Tropsch process
    • 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
    • C10J2300/09—Details of the feed, e.g. feeding of spent catalyst, inert gas or halogens
    • C10J2300/0913—Carbonaceous raw material
    • C10J2300/0916—Biomass
    • 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
    • C10J2300/09—Details of the feed, e.g. feeding of spent catalyst, inert gas or halogens
    • C10J2300/0913—Carbonaceous raw material
    • C10J2300/0916—Biomass
    • C10J2300/092—Wood, cellulose
    • 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
    • C10J2300/09—Details of the feed, e.g. feeding of spent catalyst, inert gas or halogens
    • C10J2300/0913—Carbonaceous raw material
    • C10J2300/0946—Waste, e.g. MSW, tires, glass, tar sand, peat, paper, lignite, oil shale
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
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    • 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
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    • C10J2300/00—Details of gasification processes
    • C10J2300/16—Integration of gasification processes with another plant or parts within the plant
    • C10J2300/1681—Integration of gasification processes with another plant or parts within the plant with biological plants, e.g. involving bacteria, algae, fungi
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
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    • C10J2300/00—Details of gasification processes
    • C10J2300/18—Details of the gasification process, e.g. loops, autothermal operation
    • C10J2300/1807—Recycle loops, e.g. gas, solids, heating medium, water
    • 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
    • Y02E50/00—Technologies for the production of fuel of non-fossil origin
    • Y02E50/30—Fuel from waste, e.g. synthetic alcohol or diesel
    • 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
    • Y02P20/141—Feedstock
    • Y02P20/145—Feedstock the feedstock being materials of biological origin

Definitions

  • the present invention relates to treating syngas streams, especially syngas streams derived from gasification of carbonaceous feed material such as biomass.
  • the carbonaceous feed material is treated to produce a gaseous stream that contains compounds which can be chemically converted into compounds that are useful as, for instance, liquid transportation fuels.
  • the present invention is useful in the treatment of the gaseous stream (referred to herein as “syngas”), that is formed upon gasification of carbonaceous feed material such as biomass, to enhance the efficiency of production of liquid transportation fuels from the syngas.
  • One aspect of the invention is a method of syngas treatment, comprising
  • biomass means algae or material containing any of cellulose or hemicellulose or lignin, including but not limited to Municipal Solid Waste (MSW), wood (including wood chips, cut timber; boards, other lumber products, and finished wooden articles, and wood waste including sawdust, and pulpwood from a variety of trees including birch, maple, fir, pine, spruce), and vegetable matter such as grasses and other crops, as well as products derived from vegetable matter such as rice hulls, rice straw, soybean residue, corn stover, and sugarcane bagasse.
  • MSW Municipal Solid Waste
  • wood including wood chips, cut timber; boards, other lumber products, and finished wooden articles, and wood waste including sawdust, and pulpwood from a variety of trees including birch, maple, fir, pine, spruce
  • vegetable matter such as grasses and other crops, as well as products derived from vegetable matter such as rice hulls, rice straw, soybean residue, corn stover, and sugarcane bagasse.
  • carbonaceous feed material means biomass, coal of any rank (including anthracite, bituminous, and lignite), coke produced from coal of any rank, petroleum coke, or bitumen.
  • foil fuel means product useful as fuel that is either found in deposits in the earth and used in the form as found, or produced by separatory and/or chemical processing of product that is found in deposits in the earth.
  • product fuel means hydrocarbon material (which includes oxygenated hydrocarbon material) useful as fuel and containing product selected from the group consisting of alkanes liquid at 25 C and atmospheric pressure, alkenes liquid at 25 C and atmospheric pressure, alkanols liquid at 25 C and atmospheric pressure, and mixtures thereof.
  • tars means any hydrocarbon with a boiling temperature at ambient conditions greater than or equal to that of benzene, and includes mixtures of two or more such hydrocarbons.
  • FIG. 1 is a flowsheet of a process for converting biomass to fuel, with which the present invention can be practiced.
  • FIG. 2 is a cross-sectional view of a hot oxygen generator useful in the practice of the present invention.
  • FIG. 3 is a partial cross-sectional view of a reformer unit useful in the practice of the present invention.
  • FIG. 4 is a graph of incremental combined yield of hydrogen plus carbon monoxide against stoichiometric ratio.
  • FIG. 5 is a graph of incremental combined yield of hydrogen plus carbon monoxide against residence time in a reformer unit.
  • FIG. 1 is a flowsheet that shows the typical steps of such an operation, also including a process step that incorporates the present invention.
  • biomass feed material is treated by gasification to produce fuels and especially alcohols and diesel.
  • this embodiment can be suitably extended to other carbonaceous feedstocks, e.g. coal, coke, petroleum coke, as well as to the production of gasoline and other Fischer Tropsch liquids.
  • this invention can be adapted to treatment of syngas derived from biomass by reaction technology other than gasification of the biomass, such as by pyrolysis. Where the following description refers to gasification of biomass, it should not be limited to gasification or to biomass except where specifically indicated.
  • stream 1 of biomass is fed to gasification unit 2 .
  • Stream 1 may previously have been treated to lower the moisture content of the biomass, such as by heating the biomass.
  • Gasification stream 3 is also fed to gasification unit 2 .
  • Stream 3 typically contains air, steam, or oxygen, or two or all three of air, steam and oxygen.
  • Unit 2 may comprise one gasification reactor or a connected series of stages which overall achieve the desired gasification, that is, the formation of a gaseous stream 5 which contains (at least) hydrogen and carbon monoxide and which typically contains other substances such as carbon dioxide, water vapor, hydrocarbons (including methane), volatilized tars, particulate matter, and sulfides.
  • unit 2 comprises a moving bed gasifier, such as Lurgi® gasifiers or a fluidized bed gasifier.
  • fluidized bed gasifiers include the indirect dual-bed gasifier developed by Silvagas (current technology provider—Rentech) or the direct O 2 -blown gasifier developed by Gas Technology Institute (current technology providers—Synthesis Energy Systems, Andritz-Carbona).
  • Silvagas current technology provider—Rentech
  • O 2 -blown gasifier developed by Gas Technology Institute
  • a discussion of biomass gasifiers can be found in the open literature, e.g. A Survey of Biomass Gasification by Reed & Gaur, 2001.
  • These biomass gasifiers produce synthesis gas which includes hydrogen and carbon monoxide at a molar ratio (hydrogen:carbon monoxide) of less than 2:1.
  • Gasification stream 3 which preferably contains steam and oxygen, is fed into the bed so that it passes through the biomass and contacts the biomass, heats the biomass, and promotes the aforementioned breakdown of the biomass material.
  • Gasification stream 3 is typically fed at a temperature in the range of 100° F. to 750° F. and a pressure of 30 psia to 550 psia.
  • reaction zones may be present from top to bottom, namely a drying zone where moisture is released, a devolatilization zone where pyrolysis of biomass takes place, a gasification zone where mainly the endothermic reactions occur, an exothermic oxidation or combustion zone, and an ash bed at the bottom of the gasifier.
  • a drying zone where moisture is released
  • a devolatilization zone where pyrolysis of biomass takes place
  • a gasification zone where mainly the endothermic reactions occur
  • an exothermic oxidation or combustion zone an ash bed at the bottom of the gasifier.
  • hot dry devolatilized biomass reacts with the relatively cold incoming gasification stream, and hot raw gas before exiting as stream 5 exchanges heat with relatively cold incoming biomass.
  • the temperature profile in each part of a gasifier varies as the biomass moves through different zones in the gasifier. In the gasification zone, the temperature may vary between 1400° F. and 2200° F.
  • fluid bed gasifiers the biomass solids are effectively completely mixed.
  • the temperature in all parts of the bed are essentially the same and can range from about 1200° F. and 1600° F.
  • the primary benefits of a fluidized bed gasifier are high heat transfer rates, fuel flexibility and the ability to process feedstock with high moisture content.
  • a variety of fluidized bed gasifiers have been and continue to be used/developed for biomass gasification. Key process parameters include type of particle, size of particle and manner of fluidization. Examples of configurations deployed for the biomass gasification application include the bubbling fluidized bed, where bubbles of gas pass through the solids, to circulating fluidized bed, where the particles are carried out with the gas, subsequently separated by a cyclone and returned to the gasifier.
  • Fluidized bed gasifiers may be operated below the ash fusion temperature of the feedstock, or may have areas of the bed that are above the ash fusion temperature to help agglomerate ash before it leaves the gasifier.
  • the generated syngas will contain impurities and thus will require conditioning similar to the moving bed gasifier described above. Tar levels may be less but still sufficient to cause problems with downstream heat exchangers and processing units.
  • Low temperature gasifiers such as fluidized bed gasifiers are likely to be more prevalent in biomass gasification applications.
  • the syngas can contain 5-15 vol. % CH 4 , 1-5 vol. % C 2 s (that is, hydrocarbons containing 2 carbon atoms), and 1-100 g tar/Nm 3 syngas on a wet basis.
  • the CH 4 that is present will act as an inert in the downstream process for production of product fuels, be it catalytic, i.e., Fischer-Tropsch, or fermentation.
  • CH 4 formation in the gasifier reduces the overall fraction of carbon in the biomass being converted to liquids/product fuel.
  • Tars are produced by thermal decomposition or partial oxidation of any organic material. Given the high boiling points of these species they will condense from the syngas stream as it is cooled before downstream processing, causing many operational issues. Conventional syngas cleanup units typically contain a tar scrubbing system which is expensive and maintenance intensive.
  • the gas stream 5 that is produced in gasification unit 2 typically leaves the gasification unit 2 at a temperature of between about 1000° F. and 1600° F.
  • Stream 5 is then treated in unit 4 in accordance with the present invention (as more fully described herein) to reduce the amounts of methane that are present in the stream and to produce additional amounts of hydrogen and carbon monoxide (CO). If tars are present in the stream, some or all of tars present can also be converted to lower molecular weight products.
  • Stream 13 which is produced in unit 4 is preferably cooled and treated to remove substances that should not be present when the stream is fed to reactor 10 (described herein) that produces fuel.
  • Unit 6 represents a unit which cools stream 13 , for instance by heat exchange to feed water 25 to produce stream 29 of heated water and/or steam.
  • Unit 6 can also comprise a shift conversion reactor in which carbon monoxide in stream 13 is reacted with water vapor to produce hydrogen, thereby providing a way to adjust the ratio of hydrogen to carbon monoxide in the stream.
  • Unit 8 represents a conditioning stage to remove impurities 49 that may be present such as particulates, acid gases including CO 2 , ammonia, sulfur species, and other inorganic substances such as alkali compounds. Impurities may be removed in one unit or in a series of units each intended to remove different ones of these impurities that are present or to reduce specific contaminants to the desired low levels. Unit 8 represents the impurities removal whether achieved by one unit or by more than one unit. Cooling and impurities removal are preferably performed in the sequence shown, but may be performed in the reverse sequence, or all in one unit. Details are not shown, but should be obvious to those skilled in the art.
  • Unit 8 typically includes operations for final removal of particulates, NH 3 , sulfur species and CO 2 removal.
  • the CO 2 removal is typically a performed by solvent-based process, which either uses a physical solvent, e.g. methanol, or a chemical solvent, e.g. amine.
  • solvent-based process which either uses a physical solvent, e.g. methanol, or a chemical solvent, e.g. amine.
  • a physical solvent e.g. methanol
  • a chemical solvent e.g. amine
  • the resulting cooled, conditioned gaseous stream 15 contains at least hydrogen and carbon monoxide.
  • the exact composition can vary widely depending on the biomass feedstock, gasifier type, intermediate processing steps, and operating conditions.
  • Stream 15 typically contains (on a dry basis) 20 to 50 vol. % of hydrogen, and 10 to 45 vol. % of carbon monoxide.
  • Stream 15 typically also contains carbon dioxide in amounts from ⁇ 1 to 35 vol. %.
  • Stream 15 is then fed to reactor 10 wherein product fuel is produced.
  • product fuel is produced by a catalytic conversion process, e.g. Fischer-Tropsch process.
  • the present invention is advantageous also when the product fuel is produced by fermentation or other conversion mechanisms.
  • stream 15 may require some compression before being fed to reactor 10 depending on the pressure of stream 15 .
  • the end-product is a diesel-type of fuel, a single stage of compression may suffice. For alcohols, e.g. methanol, ethanol, 2-3 stages of compression may be required.
  • the Fischer-Tropsch reaction may be carried out in any reactor that can tolerate the temperatures and pressures employed.
  • the pressure in the reactor is typically between 300 psia and 1500 psia, while the temperature may be between 400° F. and 700° F.
  • the reactor will thus contain a Fischer-Tropsch catalyst, which will be in particulate form.
  • the catalyst may contain, as its active catalyst component, Co, Fe, Ni, Ru, Re and/or Rh.
  • the catalyst may be promoted with one or more promoters selected from an alkali metal, V, Cr, Pt, Pd, La, Re, Rh, Ru, Th, Mn, Cu, Mg, K, Na, Ca, Ba, Zn and Zr.
  • the catalyst may be a supported catalyst, in which case the active catalyst component, e.g. Co, is supported on a suitable support such as alumina, titania, silica, zinc oxide, or a combination of any of these.
  • the hydrogen and carbon monoxide in stream 15 react under pressure in the presence of a catalyst at reaction temperature in the indicated range to yield a mixtures of alkanols, or mixtures of alkanes and alkenes, which may contain 1 to greater than 60 carbon atoms. Water and carbon dioxide are also produced.
  • steam-producing cooling coils are preferably present in the Fischer-Tropsch reactors to remove the heat of reaction.
  • fresh catalyst is preferably added to reactor 10 when required without disrupting the process to keep the conversion of the reactants high and to ensure that the particle size distribution of the catalyst particles is kept substantially constant.
  • such fresh catalyst addition is not necessary; instead, catalyst is removed and replaced on a periodic basis
  • the catalytic conversion is operated in any manner known to favor the formation of methanol, such as carrying out the reaction with a copper-zinc catalyst.
  • the optimal molar ratio of hydrogen to carbon monoxide in the syngas is 2:1.
  • a slightly lower ratio is compensated somewhat by the catalysts used in for mixed alcohol production (e.g. molybdenum sulfide), which are known to provide some water-gas shift activity. Occurrence of the water-gas shift reaction, shown here:
  • Stream 15 can if desired be fed into one or more than one location in the reactor or reactors that form the desired fuel (not shown).
  • the mixture of products formed in reactor 10 is represented in FIG. 1 as stream 17 .
  • This stream 17 is treated in product recovery unit 12 to recover stream 21 of the desired product fuel, such as ethanol, as well as stream 23 of liquid and/or solid by-products (such as longer-chain alkanes and/or alkanols, e.g. naphtha), and stream 19 of gaseous byproducts.
  • Stage 12 is shown separate from reactor 10 but in practice the Fischer-Tropsch/catalytic reaction and the ensuing separation of products may be carried out in one overall processing unit which includes a series of more than one operation. Recovery of the desired product in stage 12 is carried out by distillation or other separatory techniques which are familiar to those experienced in this field.
  • components of stream 17 may also be subjected to treatment such as hydrocracking, hydrotreating, and isomerization, depending on the desired end-products and their desired relative amounts.
  • treatment such as hydrocracking, hydrotreating, and isomerization
  • Another configuration could involve use of a fermentation reactor in unit 10 .
  • the final product in this case is typically ethanol.
  • unit 12 will typically include a gas-liquid separator, a distillation column and a molecular sieve.
  • the unreacted tail gas from the gas-liquid separator constitutes stream 19 , and where employed, stream 25 .
  • Gaseous stream 19 comprises at least one of hydrogen, carbon monoxide, water vapor, and light hydrocarbons such as methane and/or C2-C8 hydrocarbons with 0 to 2 oxygen atoms.
  • the entire amount thereof may have been formed in reactor 10 , or the entire amount may have been fed to reactor 10 and not reacted therein, or the amount of the component may be a combination of amounts formed and amounts fed to reactor 10 and not reacted therein.
  • Stream 25 which is at least a portion or possibly all of stream 19 , can be employed in unit 4 , as a fuel that is combusted or otherwise reacted to provide heat, as described herein with respect to the present invention.
  • Stream 25 or a portion of stream 25 can be fed as fuel 205 (see FIG. 2 ) that is fed to hot oxygen generator 202 and combusted in hot oxygen generator 202 as described herein.
  • Stream 25 , or a portion of stream 25 can be fed into stream 5 that is then fed into unit 4 .
  • Stream 23 can be used as a reactant in other operations, can be used as fuel in other process steps, or flared.
  • Steam (stream 31 ) formed from water stream 30 that is used to remove heat from reactor 10 can be optionally fed to unit 4 or gasification unit 2 .
  • unit 4 also referred to herein as a reformer
  • the present invention furnishes oxygen and supplemental heat to the syngas stream 5 .
  • Supplemental heat can be provided in any of various ways, as described herein.
  • the supplemental heat can be provided by direct heat transfer of heat of combustion of supplementary fuel and oxidant added to the syngas (i.e., products of combustion are contained within the syngas stream).
  • electrical heating (plasma) or indirect heat transfer of heat of combustion (generated separately) can be used to transfer heat to the syngas.
  • An oxidant preferably oxygen in a stream comprising at least 90 vol. % oxygen, is also added to the syngas for partial oxidation of methane and tars.
  • secondary reactants such as steam or hydrocarbons, could be added to the reformer to tailor the final syngas characteristics to the downstream processing.
  • the supplemental heat is provided simultaneously with the oxidant for partial oxidation by the use of a hot oxygen generator.
  • a hot oxygen generator By injecting both the heat and the oxidant into the syngas simultaneously with the hot oxygen generator, it is possible to enhance mixing, accelerate oxidation kinetics and accelerate the kinetics of the reforming of methane and tars in the syngas stream.
  • stream 203 of oxidant having an oxygen concentration of at least 30 volume percent and preferably at least 85 volume percent is provided into a hot oxygen generator 202 which is preferably a chamber or duct having an inlet 204 for the oxidant 203 and having an outlet nozzle 206 for the stream 201 of hot oxygen.
  • the oxidant 203 is technically pure oxygen having an oxygen concentration of at least 99.5 volume percent.
  • the oxidant 203 fed to the hot oxygen generator 202 has an initial velocity which is generally within the range of from 50 to 300 feet per second (fps) and typically will be less than 200 fps.
  • Stream 205 of fuel is provided into the hot oxygen generator 202 through a suitable fuel conduit 207 ending with nozzle 208 which may be any suitable nozzle generally used for fuel injection.
  • the fuel may be any suitable combustible fluid examples of which include natural gas, methane, propane, hydrogen and coke oven gas, or may be a process stream such as stream 25 obtained from stream 19 .
  • the fuel is a gaseous fuel.
  • Liquid fuels such as number 2 fuel oil or byproduct stream 23 may also be used, although it would be harder to maintain good mixing and reliable and safe combustion with the oxidant with a liquid fuel than with a gaseous fuel.
  • the fuel 205 provided into the hot oxygen generator 202 combusts therein with oxidant 203 to produce heat and combustion reaction products such as carbon dioxide and water vapor.
  • the combustion reaction products generated in the hot oxygen generator 202 mix with the unreacted oxygen of the oxidant 203 , thus providing heat to the remaining oxygen and raising its temperature.
  • the fuel 205 is provided into the hot oxygen generator 202 at a velocity that is suitable to sustain a stable flame for the particular arrangement of nozzle 208 within generator 202 .
  • the velocity of the fuel at nozzle 208 serves to entrain oxidant into the combustion reaction thus establishing a stable flame.
  • the fuel velocity enables further entraining of combustion reaction products and oxidant into the combustion reaction, this improving the mixing of the hot combustion reaction products with the remaining oxygen within the hot oxygen generator 202 and thus more efficiently heating the remaining oxygen.
  • the temperature of remaining oxidant within the hot oxygen generator 202 is raised by at least about 500° F., and preferably by at least about 1000° F.
  • the hot oxygen stream 201 obtained in this way is passed from the hot oxygen generator 202 into unit 4 through a suitable opening or nozzle 206 as a high velocity hot oxygen stream having a temperature of at least 2000° F.
  • the velocity of the hot oxygen stream will be within the range of from 500 to 4500 feet per second (fps), and will typically exceed the velocity of stream 203 by at least 300 fps.
  • composition of the hot oxygen stream depends on the conditions under which the stream is generated, but preferably it contains at least 50 vol. % O 2 .
  • the formation of the high velocity hot oxygen stream can be carried out in accordance with the description in U.S. Pat. No. 5,266,024.
  • supplemental heat in combination with an oxidant the partial oxidation reactions of the reforming can proceed while consuming less of the CO and H 2 that are in the raw syngas which is fed to the reformer unit 4 .
  • the supplemental heat must be higher than that provided by simply preheating oxygen to 600° F., (e.g. more than 125 Btu/lb of oxygen added). Increasing the temperature in the reformer by use of supplementary heat enhances the reforming kinetics, and therefore increases the effectiveness of the reformer in converting tar and methane to syngas.
  • the injection rate of the supplementary oxidant is preferably controlled to reform the methane and tars to form species such as CO and H 2 while reducing the formation of CO 2 and H 2 O which represents consumption of desirable species.
  • the hot oxidant stream acts as a heat carrier to inject heat into the raw syngas.
  • the hot oxidant stream contains radicals from the combustion of the fuel, which has been shown to enhance reaction kinetics and tar reforming.
  • the extremely high velocity, high momentum hot oxidant jet also enhances mixing between the oxidizer and the syngas.
  • the high velocity jet can also be used to inject secondary reactants such as steam by using the high velocity jet to mix oxidizer with the secondary reactants as it also reacts with the syngas.
  • FIG. 3 depicts a preferred specially designed reformer 301 in which a stream 201 of hot oxygen (which optionally also contains steam) can be mixed with the syngas 5 from biomass gasification.
  • This reformer 301 would be designed to provide long residence time while minimizing capital cost requirements.
  • the reformer design should facilitate mixing of stream 201 with the raw syngas 5 , as well as reaction of the mixture of streams 201 and 5 .
  • One way to accomplish this would be to provide a transitional turbulent mixing zone 303 in which the hot oxygen fed as stream 201 and syngas fed as stream 5 mix and ignite.
  • This zone 303 could be simply a well designed refractory lined duct or passage.
  • the optimal design of the transitional zone 303 may depend on the size of the reformer 4 .
  • this zone 303 should be designed to minimize ‘short circuiting’ of the raw syngas around the oxidant jet(s). Raw syngas that short circuits the mixing zone will pass into and out of the reformer unreacted and reduce the overall reformer effectiveness. Common design tools, such as computational fluid dynamics (CFD) can be used to ensure correct mixing.
  • CFD computational fluid dynamics
  • the transitional zone 303 should also be designed to minimize heat loss.
  • the resulting hot gas mixture enters a reforming section 305 where reforming reactions, such as the methane reforming and water gas shift reactions, are allowed to take place.
  • This reformer may or may not contain a reforming catalyst. Additional heat or oxidant can be supplied to the reformer to optimize the overall reforming effectiveness. Residence time in the reformer should be as long as possible (2-3 seconds). Further, both the transitional zone 303 and reforming section 305 should be designed such that deposition of char/ash carried over from the gasifier is minimized unless provisions are included to remove the ash during operation.
  • One alternative is to add the supplemental heat as heat of combustion produced by combusting fuel and oxidant having an oxygen content of at least 90 vol. % within the reformer unit 4 , using a suitable burner (referred to as an oxy-fuel burner) while separately feeding into the reformer unit oxygen required for the partial oxidation/reforming reactions.
  • a suitable burner referred to as an oxy-fuel burner
  • the oxy-fuel burner fired into the syngas stream is used to raise the temperature of the syngas.
  • Oxygen is injected separately for the partial oxidation of the methane and/or tars. Since the radicals from oxy-fuel combustion are injected separately from the oxygen for partial oxidation, initiation of the partial oxidation reactions may be delayed. This would lead to a longer residence time requirement to achieve a given level of reforming.
  • Separate injection of heat (oxy-fuel burner) and oxygen could be used to avoid hot spots in the reformer.
  • Another embodiment of the current invention is to add supplementary fuel and oxygen directly into the syngas in reformer unit 4 , without the use of a burner.
  • the fuel and oxygen will combust in the reformer and raise the reformer temperature.
  • Enough oxygen would need to be fed in order to combust the added fuel and to partially oxidize the methane and/or tars. Since heat release in this mode is more ‘diffuse’ it would require fairly long residence times to be effective.
  • Experimental data obtained for this embodiment suggest that for a long residence time reformer this alternate mode can provide incremental syngas yields comparable to the optimal embodiment (hot oxygen injection).
  • the fuel is less reactive (such as methane) then the supplementary oxygen may actually react with more reactive syngas components, such as hydrogen, before it can react with the target fuel.
  • Heat can also be added to the syngas by indirect methods, by which is meant that the heat generating device or combustion products are not in direct contact with the syngas.
  • Examples include combustion of a supplemental fuel with an oxidant, which could be air or a gaseous stream having an oxygen content higher than that of air, in tubes placed in the syngas stream.
  • This process may be attractive from an operating standpoint since any fuel could be used (including solids) and any oxidant could be used (including air).
  • this is the least efficient method for heating the syngas as the outlet temperature of the heater will be fairly high (even with air preheating). The high process temperatures will also create significant materials restrictions and may make this method impractical.
  • Secondary reagents injection can be integrated with the current invention in order to tailor the characteristics of the final syngas.
  • kinetic modeling suggests that injection of steam (particularly steam that has been heated with an oxy-fuel burner) has been shown to increase the yield of hydrogen while significantly increasing the H2/CO ratio.
  • injection of hydrocarbons, such as methane or large quantities of stream 19 tail gas can also increase the hydrogen yield while also increasing the overall syngas (CO+H 2 ) amount.
  • the increase in syngas yield associated with hydrocarbon addition reduces the concentration of the CO 2 in the final syngas, which reduces CO2 removal costs.
  • the current invention By enhancing the reforming kinetics (through the use of supplementary heat) the current invention enables reforming of tars and methane in devices where cold oxidants would be less effective.
  • the heat and oxidants can be injected into headspace above the gasifier, or in a duct downstream from the gasifier, where the residence time would be very short. Under these conditions it would be possible to g a significant improvement in reforming with the current invention compared to injection of oxygen without heat.
  • the temperature and quantity of the preheated oxidant can be optimized based on the final use of the ‘cleaned’ syngas.
  • One extreme is mild reforming of tars with high condensation temperatures to facilitate use of ‘dirty’ syngas in combustion systems. Since tars are more easily reformed than methane, less oxygen will be required for reforming just tar. The other extreme is the full conversion of methane and tars to CO+H 2 for use in downstream chemicals/fuels processing systems.
  • CO 2 in the syngas is a diluent in the conversion step.
  • the final cleanup step could involve CO 2 removal—an expensive unit operation for small scale gasification systems.
  • Such a system is commercially available and typically deploys the use of physical solvents, e.g. methanol, or chemical solvents, e.g. amines.
  • the current invention is expected to significantly reduce the CO 2 content in the syngas coming from the biomass gasifier.
  • this reduction in CO 2 flowrate will significantly reduce the energy consumption (recycle rates and regeneration energy) from the CO 2 removal system or potentially eliminate the need for CO 2 removal altogether.
  • the current invention has several advantages over the prior art.
  • the prior art essentially uses a portion of the syngas as ‘fuel’ to preheat the remainder to the operating temperature of the reformer.
  • this consumption of syngas is avoided by providing an alternate means of heating the syngas.
  • the heat and oxygen are injected into the syngas simultaneously through the use of a hot oxygen generator such as is described herein.
  • the resulting hot, reactive, jet of oxygen from the hot oxygen generator can dramatically reduce the time for mixing and accelerate the oxidation and reforming kinetics. This accelerated oxidation and reforming with hot oxygen also allows tar and methane reforming to occur in much shorter residence times and lower temperatures than with cold oxygen in the prior art.
  • Another benefit of the current invention is related to the increased operational flexibility of the process.
  • the inherent flexibility of the invention allows an operator to easily adjust parameters, such as the total supplemental heat, amount of oxidizer, and amount of secondary reactants in response to changes in gasifier feedstock, raw syngas composition, or desired reformed syngas composition.
  • the current invention can increase the incremental hydrogen production over the state of the art while using the same amount of oxidant.
  • the proposed concept does an effective job of reforming CH 4 , tar and other hydrocarbon species to H 2 and CO, as measured in terms of incremental H 2 and combined CO and H 2 .
  • there is a significant reduction in CO 2 levels in the syngas which could ultimately translate to an increase in the overall conversion levels of carbon in the biomass to the desired liquid fuel.
  • the reduction in the CO 2 concentration can also be accomplished through the use of secondary reactants coupled with supplementary heat and oxygen.
  • a fuel such as methane or stream 19 tail gas could be used to increase the syngas volume, and potentially reform some of the existing CO 2 , such that the CO 2 levels in the resulting syngas are reduced.
  • the current invention increases the overall process efficiency of converting biomass to alternate fuels, such as transportation fuels.
  • up to 50% of the energy in the syngas from a biomass gasifier is contained in tars, CH 4 and other hydrocarbon species. Reforming the tar, methane, and other hydrocarbons, increases the syngas flow-rate and allows more product fuel to be produced for a given amount of biomass.
  • the operator can either use less oxidant and therefore lower their costs, or use the same amount of oxidant and get a higher specific yield.
  • the higher specific yield allows the operator to either reduce the biomass firing rate (if the ethanol production portion of the process is limiting) or produce more bio-derived transportation fuels. Both of these strategies will increase revenue for the operator.
  • the inherent flexibility of the invention also allows the operator to better optimize the system based on the feedstock being used so that only the minimum amount of oxidant is used. Finally, by reducing the mixing and enhancing kinetics it may be possible to reduce the size of the secondary reformer as compared to using air or cold oxygen alone.
  • FIG. 4 illustrates the effectiveness of hot oxygen for reforming, based on the incremental CO+H 2 formed. As can be seen from the figure the addition of heat to the oxygen increases the reforming effectiveness for a given reformer stoichiometric ratio.
  • This reformer stoichiometric ratio (also referred to as “SR”) is defined as the free oxygen injected into the syngas divided by the amount of oxygen required to completely combust the syngas. Note: the reformer SR as defined here does not include the oxygen consumed by the supplementary fuel to generate the heat. Although slightly more total oxygen is injected for a given reformer SR, if oxygen consumed to generate heat is included, the amount is small compared to the value of the added syngas.
  • the oxygen temperature was assumed to be 77° F., and no secondary reactants were used so the heat input from preheat is zero.
  • the fuel input was 1,780 Btu (lower heating value) per lb of total oxygen injected.
  • the sensible heat at 1500° F. of the reaction products from the fuel and the oxygen was 473 Btu/lb total oxygen. Therefore in this case the supplemental heat was 1,307 Btu/lb total oxygen. If a secondary reactant, such as steam, had been included the enthalpy of the steam at the injection temperature would have been included as an input.
  • Table 3 shows the results from the kinetic model for the optimal oxygen injection rate for this particular case.
  • Another aspect of the optimal embodiment is the opportunity to minimize the size of the reformer device, or eliminate the separate reformer completely.
  • a substantial part of the reforming takes place in the first 1 ⁇ 2 to 1 second.
  • hot oxygen A is defined as having a stoichiometric ratio (total oxygen fed divided by the amount required to burn the injected fuel) of 6.
  • Hot oxygen B has a stoichiometric ratio of 3. In fact, the amount of reforming with hot oxidant is much higher than with cold oxygen at short residence times.
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US13/468,189 US20120291351A1 (en) 2011-05-16 2012-05-10 Reforming methane and higher hydrocarbons in syngas streams
BR112013029511A BR112013029511B1 (pt) 2011-05-16 2012-05-11 método de tratamento de gás de síntese
MX2013013452A MX364832B (es) 2011-05-16 2012-05-11 Oxidacion parcial de metano y de hidrocarburos superiores en las corrientes de gas de sintesis.
CA2836270A CA2836270C (en) 2011-05-16 2012-05-11 Partial oxidation of methane and higher hydrocarbons in syngas streams
ES12727183T ES2734478T3 (es) 2011-05-16 2012-05-11 Oxidación parcial de metano e hidrocaburos pesados en corrientes de gas de síntesis
PL12727183T PL2710095T3 (pl) 2011-05-16 2012-05-11 Częściowe utlenianie metanu i wyższych węglowodorów w strumieniach gazu syntezowego
EP12727183.1A EP2710095B1 (en) 2011-05-16 2012-05-11 Partial oxidation of methane and higher hydrocarbons in syngas streams
RU2013155468/05A RU2600373C2 (ru) 2011-05-16 2012-05-11 Частичное окисление метана и высших углеводородов в потоках синтез-газа
PCT/US2012/037562 WO2012158536A1 (en) 2011-05-16 2012-05-11 Partial oxidation of methane and higher hydrocarbons in syngas streams
PT12727183T PT2710095T (pt) 2011-05-16 2012-05-11 Oxidação parcial de metano e hidrocarbonetos superiores em correntes de gás de síntese
KR1020137032937A KR20140043751A (ko) 2011-05-16 2012-05-11 합성 가스 스트림 중 메탄 및 고급 탄화수소의 부분적 산화 방법
JP2014511420A JP2014518924A (ja) 2011-05-16 2012-05-11 合成ガス流におけるメタン及びより高級な炭化水素の部分酸化
CN201280035295.5A CN103857772A (zh) 2011-05-16 2012-05-11 合成气流中的甲烷和更高级烃的部分氧化
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