WO2024073846A1 - Système et procédé d'hydroconversion de biomasse en pétrole brut synthétique renouvelable - Google Patents

Système et procédé d'hydroconversion de biomasse en pétrole brut synthétique renouvelable Download PDF

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Publication number
WO2024073846A1
WO2024073846A1 PCT/CA2023/051310 CA2023051310W WO2024073846A1 WO 2024073846 A1 WO2024073846 A1 WO 2024073846A1 CA 2023051310 W CA2023051310 W CA 2023051310W WO 2024073846 A1 WO2024073846 A1 WO 2024073846A1
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WIPO (PCT)
Prior art keywords
hydrogen
produced
biochar
unit
biomass
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PCT/CA2023/051310
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English (en)
Inventor
Garry David Craig PICHACH
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Cleancarbon Energy Corporation
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Publication of WO2024073846A1 publication Critical patent/WO2024073846A1/fr

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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
    • C10G1/00—Production of liquid hydrocarbon mixtures from oil-shale, oil-sand, or non-melting solid carbonaceous or similar materials, e.g. wood, coal
    • C10G1/06—Production of liquid hydrocarbon mixtures from oil-shale, oil-sand, or non-melting solid carbonaceous or similar materials, e.g. wood, coal by destructive hydrogenation
    • 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
    • C10G3/00—Production of liquid hydrocarbon mixtures from oxygen-containing organic materials, e.g. fatty oils, fatty acids
    • C10G3/50—Production of liquid hydrocarbon mixtures from oxygen-containing organic materials, e.g. fatty oils, fatty acids in the presence of hydrogen, hydrogen donors or hydrogen generating compounds
    • 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
    • C10G3/00—Production of liquid hydrocarbon mixtures from oxygen-containing organic materials, e.g. fatty oils, fatty acids
    • C10G3/50—Production of liquid hydrocarbon mixtures from oxygen-containing organic materials, e.g. fatty oils, fatty acids in the presence of hydrogen, hydrogen donors or hydrogen generating compounds
    • C10G3/52—Hydrogen in a special composition or from a special source
    • 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
    • C10G45/00—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds
    • C10G45/44—Hydrogenation of the aromatic hydrocarbons
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
    • 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
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1011—Biomass
    • C10G2300/1014—Biomass of vegetal origin

Definitions

  • This disclosure generally relates to production of synthetic crude oil and related products.
  • the disclosure relates to a system and method for hydroconverting biomass into a renewable, synthetic crude oil.
  • Some embodiments of the present disclosure relate to a system for converting a biomass feedstock into a crude-oil product.
  • the system comprises a first processing unit that is configured to pressurize the biomass feedstock in preparation for direct injection into a superheated hydrogen stream followed by the removal of produced biochar and catalytic hydropyrolysis for making a combined product that comprises the hydrocarbon liquid product, a gas product, a hydrogen product and a biochar product.
  • the system also includes a steam gasification unit for receiving the biochar product and water for making a syngas product.
  • the system also includes a hydrotreating unit for receiving a non-recycled portion of the hydrocarbon liquid product and hydrogen for hydrotreating the hydrocarbon liquid product for making the crude -oil product.
  • Direct pressurization of the biomass into the superheated hydrogen stream may require forming a pressure-tight, biomass plug.
  • forming the pressure -tight, biomass plug can be accomplished with a mixing unit, that is configured to receive the biomass feedstock and an oil input for making a pumpable slurry or a batch slurry, which can be pressurized by a pump acting as a plug screw feeder and subjected to a flow of superheated hydrogen.
  • the slurry hydropyrolysis unit operates at a first predetermined pressure and the hydrotreating unit operates at a second predetermined pressure, and wherein the first predetermined pressure is lower than the second predetermined pressure.
  • the syngas product is processed to make a hydrogen rich stream that is conducted to the slurry hydropyrolysis unit, the hydrotreating unit or both.
  • the syngas product is processed to make a carbon dioxide rich stream that is sequestered.
  • Some embodiments of the present disclosure relate to a process for producing a liquid hydrocarbon product from a biomass feedstock in a self-recuperating renewable and low-carbon intensity system or process. To ensure that products are carbon balanced, or preferentially carbon negative, the system or process is closed and generates a biogenic carbon-dioxide stream that can be sequestered.
  • energy for the step of endothermic steam gasification is provided by combustion of at least a portion of the hydrocarbon vapor product and oxygen.
  • the hydrocarbon distillate has a boiling point above about 380 °C at atmospheric pressure.
  • the biomass is carbonaceous.
  • the first predetermined pressure is about 20 barg.
  • the hydropyrolyzing step is in the presence of hydrogen gas and a catalyst.
  • the hydropyrolyzing step is at a temperature between about 300 °C and about 500 °C.
  • the removing step further comprises removing the water-soluble organic from a partially hydrodeoxygenated low Total-Acid-Number (TAN) oil of the hydrocarbon liquid product.
  • TAN Total-Acid-Number
  • step of adding an acid to the slurry further comprises a step of adding an acid to the slurry.
  • the process further comprising a step of adding a sulfiding agent during the mixing step.
  • the sulfiding agent is a liquid, a gas or any combination thereof.
  • the sulfiding agent is at least one of sulfuric acid, bibutyl sulfide, and ter-butyl polysulfide.
  • the acid is at least one of acetic acid, sulfuric acid, and nitric acid.
  • At least some of the unreacted hydrogen is purified and recycled by a pressure swing adsorption process or a membrane separation process and the purified hydrogen is compressed.
  • Some embodiments of the present disclosure relate to a process for converting a biomass feedstock into a crude-oil product.
  • the process may directly pressurize the biomass and mix the pressurized biomass with superheated hydrogen to create a hot slurry in which hydropyrolysis occurs to generate produced vapors and biochar.
  • the process further comprises a step of separating the biochar within a reactor for performing a step of partially deoxygenating the hydrocarbon vapors through a reaction with excess hydrogen in the presence of a hydrogenolysis catalyst.
  • the process further comprises a step of cooling the vapors such that produced gas is separated from partially deoxygenated liquids and produced water and a step of purifying the unreacted hydrogen, for example by a membrane separation process, which is superheated and recycled.
  • a portion of the biochar or produced gas may be subjected to a step of reforming, for example a step of autothermal, cyclically reforming to generate make-up hydrogen.
  • Some embodiments of the present disclosure relate to a process for converting a biomass feedstock into a crude-oil product.
  • the process may directly pressurize the biomass and mix the pressurized biomass with superheated hydrogen to create a hot slurry in which hydropyrolysis occurs to generate produced vapors and biochar.
  • the process further comprises a step of separating the biochar within a reactor for performing a step of partially deoxygenating the hydrocarbon vapors through a reaction with excess hydrogen in the presence of a hydrogenolysis catalyst.
  • the process further comprises a step of cooling the vapors such that produced gas is separated from partially deoxygenated liquids and produced water and a step of purifying the unreacted hydrogen, for example by a membrane separation process, which is superheated and recycled.
  • At least a portion of the produced gas is subjected to a step of reforming, for example a step of autothermal, cyclical bi-reforming to generate make-up hydrogen.
  • the partially deoxygenated liquids may be subjected to a step of pressurizing and feeding into a higher-pressure reactor in the presence of hydrogen to fully deoxygenate and saturate aromatic compounds present therein prior to a step of cooling.
  • Some embodiments of the present disclosure relate to producing a liquid hydrocarbon product from a biomass feedstock in a self-recuperating, renewable and low- carbon intensity system or process. To ensure that products are carbon balanced, or preferentially carbon negative, the system or process is closed and generates a biogenic carbon-dioxide stream that can be sequestered.
  • Some embodiments of the present disclosure relate to utilizing an autothermal, cyclical reformer to convert gases produced by the hydropyrolysis process to a hydrogen-rich syngas without nitrogen dilution and without the need for an oxygen plant or a pre-reformer system.
  • the embodiments of the present disclosure also relate to the ability to gasify biochar by operating a reactor, such as a cyclical, steam gasifier, to produce a hydrogen-rich syngas without nitrogen dilution and without the need or the need for a purified oxygen plant.
  • the embodiments of the present disclosure may provide a source of renewable, drop-in fuel that uses abundant, renewable and sustainable cellulosic biomass feed stocks from agricultural residue, municipal organic waste, forestry residue and high-yield energy crops. Furthermore, the embodiments of the present disclosure may sequester carbon dioxide rich streams from the balanced conversion of biogenic biomass to drop-in renewable fuels.
  • the embodiments of the present disclosure may overcome the drawbacks of known thermal processing and hydrogenolysis technologies for biomass, while avoiding excessive catalyst fouling - due to the present of contaminants in the biomass catalyst loss and the expense associated with lock hopper feeding of solid biomass.
  • FIG. 1 is a schematic that represents a system for making a renewable fuel product, according to one embodiment of the present disclosure
  • FIG. 2 is a schematic that shows some features of the system of FIG. 1 in greater detail
  • FIG. 3 is a schematic that shows additional features that may be used with the system of FIG. 1 for high mineral and ash containing feedstocks.
  • FIG. 4 is a schematic that shows further features that are useful in systems for making a renewable fuel product, according to one embodiment of the present disclosure.
  • FIG. 5 is a schematic that shows steps in a process for making a renewable fuel product, according to embodiments of the present disclosure.
  • FIG. 6 is a schematic that shows further features that are useful in systems for making a renewable fuel product, according to one embodiment of the present disclosure.
  • FIG. 7 is a schematic that represents another system for making a renewable fuel product, according to embodiments of the present disclosure.
  • FIG. 8 is a graph that shows the calculated required hydrogen superheat temperature to achieve an adequate fast hydropyrolysis reaction temperature with a given biomass-to-hydrogen ratio.
  • FIG. 9 is a schematic that shows further features that are useful in systems for making a renewable fuel product, according to one embodiment of the present disclosure.
  • FIG. 10 is a schematic that represents another system for making a renewable fuel product, according to one embodiment of the present disclosure.
  • FIG. 11 is a schematic that shows some features of the system of FIG. 10 in greater detail.
  • the term “about” refers to an approximately +/-10% variation from a given value. It is to be understood that such a variation is always included in any given value provided herein, whether or not it is specifically referred to.
  • conduit refers to a pipe, fluid transmission line or other mechanism for providing fluid communication between at least two features of the present disclosure.
  • conduits are typically represented by an arrowed line that connects one or more components, features or units within a depicted system.
  • use of the singular “conduit” can include multiple “conduits”.
  • the term “conducting” may be used interchangeably with the terms “feeding” or “flowing” and these terms refer to the movement of a fluid, with or without entrained solids, through a conduit or otherwise between different components or units of a system, which is understood to also contemplate moving feed stocks, intermediate and final products between different steps of a process.
  • downstream refers to a position or a component within a system, apparatus, or a step within a process that follows a prior position, component or step.
  • upstream refers to a position or component within a system, apparatus, unit or a step within a process that precedes a subsequent position, component or step.
  • FIG. 1 shows one embodiment of a system 10 that can convert a biomass feedstock 12 into to renewable hydrocarbon fuel.
  • the system 10 comprises a mixing unit 14, a slurry hydropyrolysis unit 10B, a biochar steam gasification unit 10C and a hydrotreating unit 10D.
  • the system 10 may further include an optional fry-dryer unit 10B.
  • the biomass feedstock 12 is fed into a mixing unit 14 where it is blended with recycled renewable cycle oil 72 to produce a pumpable slurry.
  • the biomass feedstock 12 and recycled renewable cycle oil 72 are blended in the mixing unit 14 to produce a batch of slurry, also referred to herein as a batch slurry.
  • a batch slurry also referred to herein as a batch slurry.
  • any reference herein below to the “pumpable slurry” and the “slurry” may also be a reference to the batch slurry.
  • a sulfiding agent 13 may, optionally, be added into the mixing unit 14.
  • the sulfiding agent 13 may be a liquid sulfiding agent such as dibutyl sulfide and it may be added when sulfide gas in the form of hydrogen sulfide is not added to the mixing unit 14.
  • an acid 16 - such as sulfuric acid, acetic acid, nitric acid or any combination thereof, may be fed into the mixing unit 14 to promote conversion of metals present in the biomass into metal salts to avoid fouling of downstream catalysts and to facilitate in-situ metal removal from downstream catalysts.
  • the sulfiding agent 13 may be used with or without the acid 16.
  • At least a portion of a liquid hydrocarbon product produced in the slurry hydropyrolysis unit 10B can be transported, via a conduit 72A, back to the mixing unit 14 so that the pumpable slurry includes at least the biomass 12, some of the liquid hydrocarbon product and, optionally, one or both of the sulfiding agent 13 and the acid 16.
  • the biomass 12 may also be fed directly into a reactor 40 of the slurry hydropyrolysis unit 10B via a conduit 12A.
  • a conduit 16 can transport the pumpable slurry from the mixing unit 14 to the optional dryer unit 10A.
  • the dryer unit 10A may comprise a heat exchanger 18 and a cross- exchanger 20 for vaporizing at least some, most of or all of the water content of the pumpable slurry.
  • the dewatered pumpable slurry and the water vapor may be transported to a tank 22. Salts being insoluble in oil will settle in the tank 22 where they can be removed by a conduit X.
  • a conduit 22 may transport the water vapor to a compressor 24 and recycled back to the cross-exchanger 20 in order to conserve the water and heat energy of the fry drying unit 10A.
  • some water may be moved from the cross-exchanger 20, via a conduit 28, to the biochar steam gasification unit 10C.
  • the dewatered pumpable slurry may move from the tank 22 by a conduit 30 in to the slurry hydropyrolysis unit 10B where it is pressurized by a pump 31 above a first predetermined pressure.
  • the first predetermined pressure may be between about 5 barg and about 50 barg, or between about 10 barg and about 40 barg, or between about 20 barg and 30 barg. In some embodiments of the present disclosure, the first predetermined pressure is at least 20 barg. In some embodiments of the present disclosure, the first predetermined pressure is at least 25 barg.
  • the pressurized and dewatered pumpable slurry is moved into the reactor 40 to form a biomass plug where it is mixed with a flow of superheated hydrogen provided by a conduit 41.
  • the reactor 40 may also receive hydrogen sulfide.
  • the biomass is converted into produced vapors and a biochar.
  • the biochar is separated by a cyclone prior the vapors passing through a catalytic hydropyrolysis bed within the reactor 40.
  • the biomass is converted into a combined product of the hydrocarbon liquid product (for example a partially deoxygenated hydrocarbon cycle oil) one or more produced gas products, a hydrogen product, a biochar product and water.
  • the combined product may be moved from the reactor 40, via a conduit 42, to a catalyst retaining filter 43.
  • the remaining produced fluids of the combined product may be moved, via a conduit 47, to a condenser 50 for cooling.
  • the cooled, produced fluids may then be moved, via conduit 52, to a knock out vessel 54.
  • a vapor stream of the produced gas and unreacted hydrogen are separated from a liquid stream of the hydrocarbon liquid product and the water.
  • the vapor stream is fed, via a conduit 58, into a gas separation unit 60 where the unreacted hydrogen is separated from the produced gas.
  • the separated produced gas may leave the gas separation unit 60 by a conduit 64 for storage as a fuel gas 66, use in a generator 68 to produce power, delivery to the biochar steam gasification unit 10C or combinations thereof.
  • the separated unreacted hydrogen may be delivered from the gas separation unit 60, via a conduit 62, to the hydrotreating unit 10D, as discussed further below.
  • the hydrocarbon liquid product and the water are conducted, via a conduit 56, to be depressurized and delivered to a free-water knock out unit 70, where the hydrocarbon liquid product the and water are separated, for example, by gravity. The majority of the biochar will settle into the water phase. At least a portion of the separated hydrocarbon liquid product is delivered back to the mixing unit 14 by the conduit 72A.
  • the biochar-water from the conduit 28 may be received within a steam gasifier unit 76 whereby produced water is vaporized by indirect heat transfer and the biochar is gasified by superheated steam generated from the produced water, delivered to the gasifier unit 76 via the conduit 74.
  • the portion of the produced gas that is delivered to the gasifier unit 76, via the conduit 64, may be combusted within the steam gasifier unit 76, optionally in the presence of oxygen 77 to superheat the steam, for providing sufficient energy for endothermic steam-biochar gasification within the steam gasification unit 76.
  • water may be introduced for quenching within in the steam gasifier unit 76 to cool the gasified biochar and to produce additional steam.
  • the gasified biochar which forms part of a syngas product of the steam gasifier unit 76, may be fed via a conduit 78 to a water shift reactor 80 to process and convert carbon monoxide and water to hydrogen and carbon dioxide.
  • the syngas product may be cooled by a heat exchanger and fed into a knock out unit 82 to remove water 83.
  • the dehydrated syngas product is fed, via a conduit 84, into a gas separation unit 86 to produce a hydrogen rich stream and a carbon dioxide rich stream.
  • the gas separation unit 86 may be a pressure swing absorber (PSA) or a membrane-based process.
  • PSA pressure swing absorber
  • the carbon dioxide rich stream may be conducted from the gas separation unit 86 by a conduit 87.
  • the hydrogen rich stream may be conducted from the gas separation unit 86 to a compressor 90.
  • the compressor 90 will pressurize the hydrogen rich stream for delivery, via a conduit 41, to the slurry hydropyrolysis reactor 40 and, optionally, to the hydrotreating reactor.
  • the carbon dioxide rich stream within the conduit 86 may be sequestered by being fed into a compressor and disposed of into a depleted oil and gas formation, deep saline aquifer or basalt rock for the purposes of carbon sequestration and storage.
  • the compressor can be followed by a heat exchanger cooled to below -25 °C for the purposes of liquefying the carbon dioxide so that it can be sequestered.
  • the liquid hydrocarbon product may be fed, via the conduit 72, into the hydrotreating unit 10D.
  • the hydrotreating unit 10D operates at a higher pressure than the slurry hydropyrolysis unit 10B.
  • the higher pressure within the hydrotreating unit 10D may ensure substantially complete or complete deoxygenation and olefin saturation and distillation of the liquid hydrocarbon product into refined petroleum products. Examples of such refined petroleum products include, but are not limited to: renewable gasoline and renewable diesel.
  • the liquid hydrocarbon product within the conduit 72 is pressurized by a pump 72B to a pressure above a second predetermined pressure.
  • the contents of the conduit 72 may also pass through a filter 72C and a heat exchanger 72D so that the contents of the conduit 72 are filtered and heated to at least 230 °C prior to entering the hydrotreating unit 10D.
  • the second predetermined pressure is between about 30 barg and about 70 barg, between about 40 barg and about 60 barg. In some embodiments of the present disclosure, the second predetermined pressure is about or at least 50 barg.
  • the liquid hydrocarbon product that has been pressurized to the second predetermined pressure is mixed with hydrogen delivered by conduit 36.
  • hydrogen sulfide 34 may also be added to the pressurized liquid hydrocarbon prior to being fed into a hydrotreater reactor 94.
  • the hydrotreater reactor 94 comprises a fixed catalyst bed to produce a deoxygenated and saturated hydrocarbon synthetic renewable crude-oil product.
  • This crude-oil product is conducted from the hydrotreater reactor 94 by a conduit 96 to a condenser 98 and then the condensed oil product is fed, via a conduit 100, into a knock-out vessel 102.
  • vapors consisting of unreacted hydrogen and produced gas within the oil product are separated from the hydrocarbon and produced water liquids.
  • the vapors are conducted, via a conduit 104, into the hydropyrolysis reactor 40, with an optional depressurization step occurring and further conducting to the reactor 40 via a conduit 106.
  • the liquids of the crude-oil product may be conducted, via a conduit 108, from the knock-out vessel to a depressurization unit 110 and then to a distillation unit 112. Within the distillation unit 112, water and liquid hydrocarbons within the crude-oil product are separated and the liquid hydrocarbons may be further separated into various liquid products, such as renewable gasoline 114 and renewable diesel 116.
  • the crude-oil product may be transported to a conventional refinery for more complicated distillation into additional or alternative products such as renewable jet fuel and renewable naphtha.
  • FIG. 2 depicts further components and details of the system 10.
  • FIG. 2 shows further detail of the mixing unit 14, the dryer unit 16 and the slurry hydropyrolysis unit 10C.
  • the biomass 12 may have a particle size less than about 150 mm, less than about 100 mm or less than about 50 mm.
  • the biomass 12 may be mixed, within the mixing unit 14, in a mechanical contactor unit 202.
  • the liquid hydrocarbon product may be delivered to the contactor unit 202 by a conduit 294.
  • the liquid hydrocarbon product may have a boiling point less than about 500 °C, less than about 475 °C, less than about 450 °C, less than about 425 °C or less than about 400 °C.
  • the pumpable slurry may also comprise one or both of the sulfiding agent 13 and the acid 16.
  • the mixing unit 14 may also comprise an inline macerator 206 further reduce the particle size of the biomass 12 and to promote mixing of the biomass 12 and the liquid hydrocarbon product.
  • the optional dryer unit 10A may be a self-recuperating biomass fry drier that is useful for de-wetting wet feed stocks.
  • the pumpable slurry may be transferred to a tank 208 of the dryer unit 10A and heated to a temperature of about 101° C by means of a heater 201.
  • the tank 208 may also include a cross-exchanger 212 where any flashed water vapor (steam) can be conducted, via a conduit 214, to a blower 216 for compression to a pressure of about 0.5 barg, about 0.4 barg, about 0.3 barg, about 0.2 barg or about 0.1 barg.
  • the pressurized steam may be conducted, via conduit 218, to be further superheated by a heat exchanger 220.
  • the pressurized and super heated steam may be fed, via a conduit 222, back into the cross-exchanger 212 to recover sensible and latent heat.
  • the recovered water from the cross-exchanger 212 may be recovered and conducted from the tank 208 via the conduit 283.
  • the dewatered slurry may be moved by a pump 221 into a storage tank 228.
  • the dewatered slurry may then be conducted from the storage tank 228 by a conduit 230. Salts will be insoluble in the oil so that they can be removed by a conduit X.
  • the sulfiding agent 13 and the acid 16 may be added to the storage tank 228, rather than in the mixing unit 14.
  • a pump 232 may pressurize the dewatered slurry to above the first predetermined pressure where a biomass plug maybe purposely and continuously formed.
  • the pressurized plug may then be mixed with hydrogen, heated by heat exchanger X, via conduit X to raise the temperature of the biomass to over 350 °C, preferably 400 °C.
  • Hydrogen sulfide 34 may be added to the conduit 34 or generated in-situ within the reactor 240 by liquid sulfating agent 13 to maintain a concentration of H2S into the reactor 240 above 400 ppm to avoid catalyst fouling.
  • the biomass is converted into produced vapors and a biochar which is separated by gravity in the bed and by cyclone via conduit X such that downstream catalytic processes are not mixed with biochar.
  • the slurry hydropyrolysis reactor X is an up reactor that houses a hydrogenolysis catalyst such as 1/20” or 1/16” sized Copper-Molybdenum (C0M0) and/or Nickle -Molybdenum (NiMo) particles in a quantity providing a Weight Hourly Space Velocity of approximately 0.5-2 hr A -l.
  • the slurry hydropyrolysis reactor 240 is a continuously stirred, upflow reactor.
  • the slurry hydropyrolysis reactor 240 is heated by a heat fluid being either jacketed or with an internal tubular heat exchanger.
  • the slurry hydropyrolysis reactor 240 may be operated at a temperature over 300 °C, preferably 390 °C, but less than or equal to 500 °C as operating at temperatures above 500 °C may cause coke graphitization. Staged hydrogen injection can help avoid the temperature rising above 500° C. Acid in the dewatered slurry may promote converting phosphorous and potassium metals into salts with the fluidized biochar as opposed to those metals contributing to catalyst fouling. In some embodiments of the present disclosure the hydrogen injection is staged up into the reactor 240 for temperature control.
  • the reactor 240 will generate reactor products comprising: about 26% of the biomass 12 weight will be converted to a gas product, about 33% of the biomass 12 weight will be converted to an aqueous product and about 27% of the biomass 12 weight will be converted to atmospheric distillate liquid hydrocarbon product with the balance being produced biochar. Of the gases produced within the reactor 240, about 45% will be C1-C3 hydrocarbons with the balance being carbon monoxide and carbon dioxide.
  • a cooler 252 receives the further filtered reactor products to reduce the temperature of the fluids to less than about 100 °C, less than about 90 °C or less than about 80 °C.
  • the cooled reactor products are then fed, via a conduit 254, into a separator 256.
  • the separator 256 may be a High-Pressure, Low-Temperature (HPLT) separator.
  • HPLT High-Pressure, Low-Temperature
  • the separator 256 separates the constituents of the reactor products into vapors, including hydrogen and produced gas, and liquids.
  • the separated vapors may be conducted from the separator 256, via a conduit 258, to a gas separation unit 262.
  • the gas separation unit 262 may be a pressure swing absorption system to separate the produced gases into a conduit 270 and into a storage tank 272 and the unreacted hydrogen may be separated into a conduit 264 and then compressed by compressor 266 and then recycled back, via a conduit 268, into the reactor 240.
  • the produced gases within storage tank 272 may be combusted as a fuel gas for heaters, gasifiers and/or for power generators to power one or more components of the system 10. Excess heat and power may also be exported for use in other systems.
  • the recompressed hydrogen could also be conducted, via a conduit 267, to a further downstream process, such as a hydrotreater operating at a higher pressure than the slurry hydropyrolysis process.
  • the separated liquids may be conducted, via a conduit 274, from the separator 256, to be depressurized by a control valve 276, and the depressurized liquids are fed into a three-phase separator 278.
  • the liquids are separated into any residual gas, renewable hydrocarbon liquid product and a soluble organic containing aqueous stream.
  • the residual gas can be conducted, via a conduit 280 to fluidly communicate with the conduit 270.
  • the renewable hydrocarbon liquid product can be conducted, via a conduit 284, to a filter X to remove residual biochar prior to being conducted into a storage tank 286.
  • the renewable hydrocarbon liquid product may comprise various distillates with an atmospheric boiling point greater than about 360° C, an oxygen content less than 15 wt% and a Total Acid Number (TAN) less than about 20 mg KOH/g.
  • the renewable hydrocarbon liquid product may be conducted, via a conduit 288, from the tank 286 to be re-pressurized by a pump 290, cleaned of any residual biochar by filter XXX and then conducted, via a conduit 292, within a tank 296 for storage as a produced cycle oil.
  • a portion of the renewable cycle oil is diverted from the conduit 292 for recycling back upstream for mixing with new biomass 12 feedstock within the contactor 202.
  • the renewable cycle oil within the tank 296 may be exported as a product or for further downstream hydrotreating.
  • the soluble organic containing aqueous stream may be conducted, via a conduit 282, from the separator 278 to a storage tank 298.
  • the storage tank 298 may also receive water from the optional cross-exchanger 212, via the conduit 283. Water within the storage tank 298 may be used in upstream or further steam gasification processes.
  • FIG. 3 shows further optional components and details relating to the system 10.
  • the biomass 12 contains a large amount of ash and catalyst poisoning minerals, such as potassium.
  • the fry drying step of the biomass 12 (that contains ash and catalyst poisoning minerals) along with a cycle oil (for example as may be conducted by conduit 72A) may occur within the dryer unit 10A is followed by a demineralization step, performed within a demineralization unit 10E to reduce the catalyst poisoning minerals and reduce (or avoid) downstream catalyst poisoning.
  • the biomass-oil slurry is transferred by a pump into the demineralization unit 10E.
  • FIG. 4 shows further components and details relating to embodiments of the system 10.
  • an aqueous water stream containing >0.5wt% water-soluble organics 120 and over 20% biochar may be pressurized by a pump 124 to between about 5 barg and about 150 barg.
  • caustic 122 may be added to the organic containing aqueous water stream to ensure a pH above 9 to ionize silica and prevent fouling of downstream components.
  • the steam gasification reactor 300 may be the same as the reactor 76 shown in FIG. 1, or not.
  • the reactor 300 may comprise an upper end 300A and a lower end 300B.
  • the biochar-water is received within the lower end 300A, which is jacketed by a heat medium to generate steam and fluidize a bed of biochar X which rises into the upper end 300B.
  • the materials that make up the vessel wall 302 may have refractory properties to prevent heat loss and reduce the wall temperature for maintaining wall integrity.
  • the temperature of the lower end 300A will be at steam saturation temperature while the upper half 300A will be subject to a hot reaction zone such that a greater refractory thickness is utilized.
  • Biochar can be fed as a solid or as a pumpable slurry, for example via the conduit 46, into the second internal gap 305 preferably at the upper end 300A via a top nozzle 306 and/or into the second internal gap 305 directly.
  • the biochar may be delivered within the second internal gap 305 towards the lower end 300B via an extension to above a reaction zone 308.
  • the reaction zone 307 comprises a biochar and ash bed that sits above an inert media bed 310.
  • the inert media bed 310 may be is replaced with a metal, gas-diffusion plate.
  • the inert media bed 310 houses quartz, glass, alumina or similar high temperature inert media and ash.
  • a combustible fuel gas 312, such as methane, ethane, propane, carbon monoxide and/or a produced gas containing a combination of hydrocarbons, carbon monoxide, carbon dioxide may be fed into the inert media bed 310.
  • the fuel gas 312 may mixed with steam within an internal gap 303 and/or with oxygen 316 to facilitate oxidation reactions within in the reactor 300. The temperature of the steam may raise to over 1000 °C prior to entering the reaction zone 308, where steam gasification and dry reforming of the biochar takes place at temperatures over 700 °C.
  • the syngas that is produced within the reactor 300 is generally over 55 mol% hydrogen with the balance being split, approximately equally, between carbon monoxide and carbon dioxide.
  • ash may develop and become fluidized or it may drop into the inert bed 310.
  • quench water 116 may be injected into the second interior gap 305 at the upper end 300A to cool the produced syngas and generate additional steam for a downstream water-shift reactor. Syngas, unreacted steam, fluidized biochar particles and fluidized ash particles are collected as a produced vapor product at the upper end 300A.
  • excess fuel gas 312 is injected in excess to stoichiometric ratios for simple combustion such that partial oxidation, dry reforming and/or steam reforming of the hydrocarbons within the reaction zone 308 occurs for additional syngas production.
  • the produced vapor product may be fed, via a conduit 320, into a cyclone 322 whereby fluidized biochar and ash particles are removed from the produced vapor product via a conduit 324 for storage in a tank 326.
  • Ash may also be removed from the inert bed 310, via a conduit 328, for storage in the tank 326.
  • the produced vapor product may be conducted, via a conduit 330, from the cyclone 322, and cooled by optional cross-exchanger 332 and fed, via a conduit 334, into a water-shift -reactor 336.
  • the reactor 336 may utilize a supported catalyst to convert carbon monoxide and excess steam to hydrogen and carbon dioxide.
  • the converted produced vapor product may be conducted, via a conduit 338, from the reactor 336 for further cooling by a heat exchange 340 and/or a water quench 116A.
  • the water quench 116A may scrub the produced vapor product of remaining ash and organics.
  • a two- phase separator knockout unit 344 may receive the produced vapor product, via a conduit 342, for removing further water and ash (for storage in tank 348 or other use) to produce the hydrogen rich syngas, which can be stored in tank 346 or otherwise used, as described herein.
  • energy efficiency may be boosted within the reactor 300 by using a thermal fluid to recover energy that is otherwise being utilized to heat the jacketed reactor.
  • calcium oxide (CaO) may be added to the biochar 46 to be removed as calcium carbonate (CaCO;,) with the dry ash (e.g. via conduits 328 and/or 324). Calcium oxide would sequester carbon dioxide, catalyze the gasification reactions and promote the water shift reaction to convert carbon monoxide and water to hydrogen and calcium carbonate.
  • FIG. 5 provides a non-limiting example of the steps of a process 400 for making a renewable, synthetic oil.
  • the process 400 comprises the steps of mixing 402, hydropyrolyzing 404, steam gasifying 406 and hydrotreating 408.
  • the step of mixing 402 comprises mixing a biomass feedstock with a hydrocarbon liquid product for making a pumpable slurry.
  • the mixing step 402 may further comprise adding one or both of a sulfiding agent or an acid to the biomass feedstock and the hydrocarbon liquid product.
  • the step of mixing 402 comprises a step of creating a pressure-tight plug of the biomass feedstock and then pressurizing the plug and mixing the plug with superheated hydrogen.
  • the step of mixing 402 may also comprise a step of separating a biochar solid from a vapor-state product.
  • the step of hydropyrolyzing 404 comprises receiving the pumpable slurry (or the vapor-state product without biochar solids) within a reactor (for example, the fluidized catalyst bed reactor 40) where it is mixed with hydrogen (for example, as received from the hydrotreating unit 10D).
  • the hydropyrolyzing step 404 may also include adding hydrogen sulfide.
  • the biomass within the slurry (if present) is converted into a combined product of the hydrocarbon liquid product (for example a partially deoxygenated hydrocarbon cycle oil) one or more produced gas products, a hydrogen product, a biochar product and water.
  • the hydropyrolyzing step 404 may further comprise a step of further processing 410 to remove the biochar product from the combined product for conducting the biochar product for the step of steam gasifying 406.
  • the remaining produced fluids of the combined product may be cooled and then a vapor stream of the produced gas and unreacted hydrogen are separated from a liquid stream of the hydrocarbon liquid product and the water.
  • the hydropyrolyzing step 404 occurs at or above the first predetermined pressure.
  • the vapor stream is then subjected to separating step to separate the unreacted hydrogen from the produced gas.
  • the separated produced gas may be stored and/or used as a fuel gas and/or used in a generator to produce power and/or the separated produced gas may be used the steam gasifying step 406.
  • the separated unreacted hydrogen may be used in the hydrotreating step 408.
  • the hydrocarbon liquid product and the water are subjected to a separating step where the hydrocarbon liquid product and the water are separated from each other. At least a portion of the separated hydrocarbon liquid product may be used during the mixing step 402 to make the pumpable slurry.
  • the separated water may be used during the steam gasifying step 406.
  • the biochar product from the hydropyrolysis step 404 is gasified by superheated steam to form a syngas product.
  • a quenching step may be part of the steam gasifying step 406 to cool the gasified biochar and to produce additional steam.
  • the syngas product may be subjected to a converting step, whereby carbon monoxide and water within the syngas are converted to hydrogen and carbon dioxide.
  • the syngas product may then be subjected to a cooling step and a dewatering/dehydrated step.
  • the cooled and dehydrated syngas is then subjected to a separation step to produce a hydrogen rich stream and a carbon dioxide rich stream.
  • the separation step may be performed by a pressure swing absorber (PSA) or a membrane-based process.
  • PSA pressure swing absorber
  • the carbon dioxide rich stream may be subjected to sequestering step.
  • the hydrogen rich stream may be used in the hydropyrolyzing 404 and/or the hydrotreating step 408.
  • the liquid hydrocarbon product from the hydropyrolyzing step 402 is received and mixed with hydrogen (for example within the hydrotreating unit 10D).
  • hydrogen sulfide 34 may also be added to the liquid hydrocarbon product prior to being mixed with the hydrogen.
  • the received liquid hydrocarbon product and the hydrogen are exposed to a catalyst, for example a fixed catalyst bed, to produce the deoxygenated and saturated hydrocarbon synthetic renewable crude-oil product.
  • the crude-oil product then further processed, for example by a condensing step and/or a separating step, to separate the produced vapors from the produced liquids.
  • the produced vapors may comprise unreacted hydrogen and produced gas.
  • the produced liquids may comprise hydrocarbon liquids and produced water liquid.
  • the vapors may be used in the hydropyrolysis step 402.
  • the liquids of the crude -oil product may be separated into water and then subjected to a distilling step for separating the liquid hydrocarbons into various liquid products, such as renewable gasoline and renewable diesel.
  • the hydrotreating step 408 occurs at a second predetermined pressure.
  • the second predetermined pressure may be higher than the first predetermined pressure so that the operating pressure of the hydrotreating step 408 is higher than the hydropyrolysis step 404.
  • the process 400 may also include an optional step of drying 450 between the mixing step 402 and the hydropyrolyzing step 404 for producing a dewatered pumpable slurry.
  • drying step 450 at least some, most of or all of the water content of the pumpable slurry is vaporized.
  • the dewatered pumpable slurry may then be used in the hydropyrolyzing step 404 and the water vapor may be recycled back for use in the drying step 450 (for example, via the cross-exchanger 20) in order to conserve the water and heat energy of the drying step 405.
  • some of the water vapor may be used during the steam gasifying step 406.
  • the process 400 may also include an optional step of demineralization 452 (for example as described above regarding the demineralization unit 10E) between the drying step 450 and the hydropyrolyzing step 404 for producing a dewatered pumpable slurry.
  • demineralization 452 for example as described above regarding the demineralization unit 10E
  • the demineralization step 452 at least some, most of or all of the ash content of the pumpable slurry is removed.
  • the dewatered pumpable slurry may then be used in the hydropyrolyzing step 404.
  • the embodiments of the present disclosure relate to use of a pumpable, biomass-slurry feedstock, segregation of hydropyrolysis and hydrotreating processes and steam gasification of biochar for hydrogenrich syngas production and these features (alone or in combination) may overcome the limitations of known processes such as conventional pyrolysis, hydrothermal liquefaction, current integrated hydropyrolysis processes and the known high energy costs of conventional biomass drying.
  • large fluid catalytic cracking equipment, solid feeder systems and/or a large steam methane reformer are not required so that commercial deployments of the embodiments of the present disclosure can be of a scale matched to available low-cost biomass feed stocks.
  • the embodiments of the present disclosure can process accept both dry and wet biomass feed stocks including residual wood waste such as sawdust and hog fuel, organic municipal waste, organic agricultural waste such as bagasse, pulp and hulls and energy crops such as Poplar, Tumbleweed, Giant King Grass, Mallee, Switchgrass and Sargassum.
  • the embodiments of the present disclosure may avoid complications arising from conventional pyrolysis and pyrolysis oil hydrotreating.
  • Pyrolysis is a known process by which biomass is thermally decomposed in an oxygen deficient environment. Indirect heat is supplied electrically or through burners at a temperature of between about 400 °C to about 600 °C at near atmospheric pressure. Pyrolysis produces around 30-35% biochar with 65-70% wet pyro-vapors. The pyro vapors and free water is removed from the pyrolysis vessel through cooling of produced vapors and a three- phase separator.
  • Pyrolysis oil is produced from the condensing of the pyro vapors and two- phase separation from pyrolysis gas but it is of a low heating value, between 16-24MJ/L, due to high oxygen content over 40% by weight. Pyrolysis oil is generally unstable such that heating will result in coking, which results in a conversion of desirable products (or intermediate products) to undesirable solid carbon of little value. Upgrading by conventional fixed-bed catalyst results in excessive coking that can poison the catalyst. Slurry hydrotreating by conventional means will result mostly in vacuum oil production.
  • the embodiments of the present disclosure may also provide “drop-in products” without the need for ultra-high pressures (for example, above 100 barg) at supercritical temperature conditions (for example, over 250 barg at 320 °C) as required by typical hydrothermal liquefaction processes.
  • ultra-high pressures for example, above 100 barg
  • supercritical temperature conditions for example, over 250 barg at 320 °C
  • waste products such as hydrochar and water soluble organics are expensive to utilize to power the process or as a hydrogen source given HTL crude generally must be hydrotreated.
  • the feeding of the biomass with a renewable cycle oil produced by the embodiments of the present disclosure produce a pumpable raw biomass-cycle oil slurry reduces or eliminates the need for expensive solid pressurization systems. Larger and higher moisture particles of biomass maybe added to the renewable cycle oil which is then made pumpable by low-cost inline maceration.
  • the biomass may also be dried in a self- recuperative manner by fry-drying the slurry with compressed water vapor from the process.
  • the hydropyrolysis reactor being fed a pumpable slurry can operate as an ebullated bed reactor. Acid may also be added to the feedstock to wash the hydropyrolysis catalyst in-situ by chemical means.
  • the hydrogen for the hydrotreatment of the biomass can be generated by a novel process utilizing water, biochar and waste water-soluble-organics derived by the process utilizing steam gasification and water-shift-reactors. Hydrogen yields can be enhanced through the addition of produced gas, carbon dioxide and carbon monoxide to promote both steam and dry reforming.
  • Off-gas, excess hydrogen and selected distillates can be combusted as fuel gas to power the process such that the fuels are carbon balanced.
  • FIG. 6 shows a similar arrangement as that shown in FIG. 4, with an alternative version of the reactor 300, shown as reactor 301.
  • FIG. 7 shows one embodiment of a system 500 that can convert a biomass feedstock 511 into to renewable hydrocarbon fuel.
  • the system 500 comprises a slurry hydropyrolysis unit 510B, an autothermal cyclical reformer gasifier 510C and a hydrotreating unit 510D.
  • the biomass feedstock 511 is fed and pressurized by a mixing unit 512, for example a plug screw feeder 512, which is configured to form a pressure-tight plug.
  • a mixing unit 512 for example a plug screw feeder 512, which is configured to form a pressure-tight plug.
  • the pressure-tight plug may prevent back flow such that a thermal barrier exists.
  • any back flow within the unit 512 is at a temperature below the auto-ignition temperature of hydrogen to ensure safe operation.
  • the mixing unit 512 may pressurize the biomass feed stock 511 to a first predetermined pressure that may be between about 5 barg and about 50 barg, or between about 10 barg and about 40 barg, or between about 20 barg and 30 barg. In some embodiments of the present disclosure, the first predetermined pressure is at least 15 barg.
  • the pressurized biomass is blended with superheated hydrogen 513 to produce a slurry mixture of a temperature greater than 350°C in a conduit 514.
  • a pressure above 15 barg and a temperature above 350°C the slurry is converted into produced gas, water vapor and solid biochar all in the presence of excess hydrogen.
  • a solid-gas separation unit 515 the biochar is removed by conduit 516.
  • a cyclone may be used to facilitate removing the biochar.
  • the combined product from the reactor 520 may be conducted from the reactor 520, via a conduit 521, to a condenser 522 for cooling.
  • the cooled, produced fluids may then be conducted, via conduit 522, to a knock-out vessel 524.
  • a knock-out vessel 524 Within the knockout vessel 524, a vapor stream of the produced gas and unreacted hydrogen are separated from a liquid stream of the hydrocarbon liquid product and water.
  • the vapor stream of produced gas is fed, via a conduit 525, into a gas separation unit 526 where the unreacted hydrogen is separated from the produced gas.
  • a portion of the produced gas is fed to conduit 528 and pressurized by a compressor 530 to feed the autothermal cyclical reformer 510C via conduits 536, 538.
  • Excess produced gas may be utilized as a fuel gas stream 531.
  • the gas separation unit 526 is a pressure swing absorber.
  • the separated unreacted hydrogen is delivered from the gas separation unit 526, via a conduit 532, and recycled by compressor 533 into a superheater 534 to mix with make-up hydrogen, via a conduit 535, to be superheated to the desired temperature.
  • the compressor 533 is a liquid jet compressor using water or oil as a motive fluid.
  • the hydrocarbon liquid product and the water are conducted, via a conduit 526, to be depressurized and delivered to a free-water knock out unit 536, where the hydrocarbon liquid product the and water are separated, for example, by gravity.
  • a portion of the contents of the compressed produced gas conduit 536 maybe pre-heated by exchanger 537 and received within an autothermal cyclical reformer unit 5 IOC.
  • An autothermal cyclical reformer gasifier 540 contains a bed of biochar, nickel catalyst or a combination of both. The reformer gasifier bed 540 is pre-heated to over 750°C by hot air delivered by a conduit 541 heated by combustion of added biochar 542 and/or added fuel gas 543 and the reaction of nickel oxide with the hot air. Some or all of any coke formed in the reactor 520 may be oxidized during the heating process.
  • Flue gas from the reactor during heating 546 is cooled by quenching and heat exchanger 547 prior to being released to the atmosphere 548 as a flue gas.
  • An excess amount of biochar 544 can be added to the autothermal cyclical reformer gasifier 540 such that the unit can be operated as a steam gasifier.
  • To maintain the bed level excess ash and catalyst is removed by a conduit 549.
  • a portion of the produced water is conducted by a conduit 550 for being pressurized above 8 barg by pump 551 with steam generated by a heat exchanger 552. Additional steam or carbon dioxide may be added to conduit 538 by a conduit 553.
  • a portion of the produced gas 529 is compressed by a compressor 530 to a pressure above 8 barg and fed into a conduit 536 for pre-heating by an exchanger 537.
  • Both the steam and produced gas vapors are fed by a conduit 538 into an autothermal cyclical reforming bed 540 when heated to a temperature over 750°C and at a pressure of 8 barg such that the produced gas containing C1-C3 hydrocarbons and excess biochar in the presence of carbon dioxide and steam are bi-reformed to hydrogen and carbon monoxide while cooling the bed by an endothermic reaction.
  • two or more beds 540 may be utilized so that at least one bed 540 can preforming the reforming process while another other bed 540 is being regenerated.
  • pressurized and reforming water may be introduced for quenching on the outlet of the bed 540 to cool produced syngas and to produce additional steam.
  • the gasified syngas product of the autothermal cyclical reformer unit may be fed via a conduit 550 to a water shift reactor 551 to process and convert carbon monoxide and water to hydrogen and carbon dioxide.
  • the syngas product may be cooled by a heat exchanger and fed into a knock out unit 552 to remove water, which is conducted away from the unit 552 by a conduit 553 for other uses.
  • the dehydrated syngas product is fed, via a conduit 554, into a gas separation unit 555 to produce a hydrogen rich stream (contained within a conduit 535) and a carbon dioxide rich stream (conducted within a conduit 556).
  • the gas separation unit 555 may be a pressure swing absorber (PSA) or a membrane-based gas separation unit.
  • PSA pressure swing absorber
  • the hydrogen rich stream may be conducted from the gas separation unit 555 to the compressor 533 to provide make up hydrogen to the hydrogen superheater 534.
  • the compressor 533 will pressurize the hydrogen rich stream for delivery, via a conduit 557, to the slurry hydrogen superheater 534 and, optionally, to the hydrotreating reactor 510D.
  • the carbon dioxide rich stream within the conduit 556 may be sequestered by being fed into a compressor and disposed of into a depleted oil and gas formation, deep saline aquifer, a basalt rock formation or elsewhere suitable for the purposes of carbon sequestration and storage.
  • the compressor can be followed by a heat exchanger cooled to below -25 °C by a refrigeration loop and fed into a low temperature separator such that lost hydrogen can be recovered back into the hydropyrolysis process and for the purposes of liquefying the carbon dioxide so that it can be sequestered.
  • the liquid hydrocarbon product may be fed, via the conduit 558, into the hydrotreating unit 510D.
  • a sulfiding agent 559 may, optionally, be added.
  • the sulfiding agent 559 may be a liquid sulfiding agent such as dibutyl sulfide.
  • the hydrotreating unit 10D operates at a higher pressure than the slurry hydropyrolysis unit 510B.
  • the higher pressure within the hydrotreating unit 510D may ensure substantially complete or complete deoxygenation and olefin saturation and distillation of the liquid hydrocarbon product into refined petroleum products. Examples of such refined petroleum products include, but are not limited to: gasoline and diesel.
  • the liquid hydrocarbon product within the conduit 558 is pressurized by a pump 559 to a pressure above a second predetermined pressure in conduit 560. A portion of the recycled and make up hydrogen 561 are fed into a compressor 562 to a second predetermined pressure in conduit 563 and are mixed with the liquid hydrocarbon feed 560.
  • the contents of the conduit 546 pass through a heat exchanger 564 and heated to at least 230 °C prior to entering the hydrotreating unit 565.
  • the second predetermined pressure is between about 30 barg and about 70 barg or between about 40 barg and about 60 barg. In some embodiments of the present disclosure, the second predetermined pressure is about or at least 50 barg.
  • the hydrotreater reactor 565 comprises a fixed catalyst bed to produce a deoxygenated and saturated hydrocarbon synthetic renewable crude-oil product. This crude -oil product is conducted from the hydrotreater reactor 565 by a conduit 566 to a condenser 567 and then the condensed oil product is fed, via a conduit 568, into a knock-out vessel 569.
  • vapors comprising unreacted hydrogen and produced gas within the oil product are separated from the hydrocarbon and produced water liquids.
  • the vapors are conducted, via a conduit 570, back into the lower pressure slurry hydropyrolysis unit 510B feeding the hydrogen superheater 534.
  • the liquids of the crude-oil product may be conducted, via a conduit 571, from the knock-out vessel to a depressurization unit 572 and then to a distillation unit 573.
  • water and liquid hydrocarbons within the crude-oil product are separated and the liquid hydrocarbons may be further separated into various liquid products, such as gasoline 574 and diesel 575.
  • the crude-oil product may be transported to a conventional refinery for more complicated distillation into additional or alternative products such as jet fuel and naphtha.
  • the liquid products are derived from a biomass feedstock, the liquid products may also be referred to as renewable.
  • the terms renewable crude -oil product, renewable gasoline, renewable diesel, renewable get fuel and renewable naptha are applicable to the products created by the systems and processes described herein.
  • the exchangers 518, 522, 537, 552, 547, 564, 567 exchange with a steam loop. Excess steam may be depressurized by a steam turbine to generate electrical power with the low pressure steam heat recovered from a biomass drying unit.
  • FIG. 8 highlights a target hydrogen superheat temperature to be achieved by heater 534 in conduit 513 to provide the required temperature for hydropyrolysis reactions whereby the required temperature will equal the (Target Slurry Temperature - Biomass Inlet Temperature ) x (Biomass-to-hydrogen ratio) x Specific heat of biomass / Specific heat of hydrogen + Target Slurry Temperature.
  • the specific heat of biomass is 0.9kJ/kg-K heating from 30C to 400-425C will require approx. 333-355kJ/kg.
  • the specific heat of hydrogen is approx. 14.1 to 14.7 kJ/kg-K at 400-600C. Provisions may be made to vaporize and superheat residual moisture.
  • the hydrogen heater be fired no more than 650°C at a pressure of 30 barg such that the biomass-to-hydrogen ratio be adjusted through hydrogen recycling of excess hydrogen.
  • the target slurry temperature can be adjusted between 350°C and 425°C to adjust the liquid yields, boiling point curve and oxygen content of the produced hydrocarbon vapors.
  • the upper line represents a slurry temperature of 400°C and the lower line represents a slurry temperature of 375°C.
  • the slurry hydropyrolysis reactor 520 is an up flow reactor that houses a hydrogenolysis catalyst such as 1/20” or 1/16” sized Copper-Molybdenum (CoMo) and/or Nickle-Mo lybdenum (NiMo) particles in a quantity providing a Weight Hourly Space Velocity of approximately 0.5-2 hr A -l.
  • the slurry hydropyrolysis reactor 520 may be operated at a temperature over 300 °C, preferably 390 °C. Staged hydrogen injection can help avoid the temperature rising above 500° C.
  • Acid in the dewatered slurry may promote converting phosphorous and potassium metals into salts with the fluidized biochar as opposed to those metals contributing to catalyst fouling.
  • the hydrogen injection is staged up into reactor 520 for temperature control.
  • the reactor 520 will generate reactor products comprising: about 26% of the biomass 512 weight will be converted to a gas product, about 33% of the biomass 512 weight will be converted to an aqueous product and about 27% of the biomass 512 weight will be converted to atmospheric distillate liquid hydrocarbon product with the balance being produced biochar.
  • the gases produced within the reactor 520 about 45% will be C1-C3 hydrocarbons with the balance being carbon monoxide and carbon dioxide.
  • the embodiments of the present disclosure may also provide “drop-in products” without the need for ultra-high pressures (for example, above 100 barg) at supercritical temperature conditions (for example, over 250 barg at 320 °C) as required by typical hydrothermal liquefaction processes.
  • ultra-high pressures for example, above 100 barg
  • supercritical temperature conditions for example, over 250 barg at 320 °C
  • the pumping of biomasswater slurries at such high pressures and the use of heat exchangers is made difficult given potential plugging. Avoidance of plugging through water dilution results in excessive energy costs. Waste products such as hydrochar and water soluble organics are expensive to utilize to power the process or as a hydrogen source given HTL crude generally must be hydrotreated.
  • the hydrogen for the hydrotreatment of the biomass can be generated by a novel process utilizing water, biochar and waste watersoluble-organics derived by the process utilizing steam gasification and water-shift-reactors. Hydrogen yields can be enhanced through the addition of produced gas, carbon dioxide and carbon monoxide to promote both steam and dry reforming.
  • FIG. 9 shows further components and details relating to embodiments of the system 510 in which an autothermal cyclical reformer is modified such that it can be used to produce a hydrogen rich syngas from hydropyrolysis biochar with or without the addition of produced hydropyrolysis gases.
  • the system 510 may comprise a reactor 600 with an upper end 600A and a lower end 600B.
  • the reactor 600 may be operated in such a manner such that the upper end 600A and the lower end 600B are not subjected to ultra-high temperatures above 700°C and only the internal portion need be refractory lined to sustain temperatures around 300°C.
  • biochar with or without nickel catalyst 601 is added to the bed by screw feeder 602.
  • Hot air is 603 added to oxidize nickel catalyst and biochar to heat the reaction zone to over 800°C with flow discontinued prior to the lower end 600B reaching ultra-high temperatures over 700°C.
  • a combustible fuel gas 604, such as methane, ethane, propane, carbon monoxide and/or a produced gas containing a combination of hydrocarbons, carbon monoxide, carbon dioxide may also be fed into the reaction zone to heat up the bed by combustion.
  • the vapors are vented y an open conduit 605 to atmosphere 606.
  • To maintain the bed level bed particles are removed by screw 607 and conduit 608 to remove ash and nickel catalyst 609.
  • the heated reactor 600 is purged of air by the closing of conduits 608 and 305 with steam or gas injection 609 from conduit 610 preheated by exchanger 611 and fed through conduit 612 into the upper portion of the reactor 600A to pressurized to over 1 barg, preferably over 4 barg.
  • Produced hydrocarbon vapors at pressure may be injected with the steam and carbon dioxide 610 in conduit 611 to produce a hydrogen rich syngas by means of dry reforming using the biochar as a catalyst.
  • Steam is injected to reform produced gas in the presence of a nickel catalyst and to steam gasify the biochar.
  • steam gasification and dry reforming of the biochar takes place at temperatures over 700 °C while produced gas reforming will occur over 600 °C.
  • syngas that is produced within the reactor 600 is generally over 55 mol% hydrogen with the balance being split, approximately equally, between carbon monoxide and carbon dioxide.
  • quench water 612 may be injected into the second interior gap at the lower end 600B to cool the produced syngas and generate additional steam for a downstream water-shift reactor.
  • Syngas, unreacted steam, fluidized biochar particles and fluidized ash particles are collected as a produced vapor product 613 from the bottom of the reactor 600B by conduit 614.
  • conduit 614 As the endothermic reactions proceed the reaction zone will cool to under 600 °C such that syngas production will halt.
  • Syngas production is halted with conduit 614 and pressurized produced gas injection 612 closed. Following purging with steam or carbon dioxide 609 the reactor is depressurized by opening conduit 605 to vent 606. The heating process is repeated.
  • the system 500 provides the ability to generate a pressurized plug of feedstock, to mix the plug with the flow of superheated hydrogen and to separate the biochar from the other products of the mixing unit 512, it reduces or prevents a flow of biochar solids into the reactor 520. This may reduce catalyst loss by eroded particles of catalyst becoming entrained or embedded in the solids. This may also reduce catalyst fouling that may occur if any coking occurs on the surface of the solid biochar. Furthermore, conducting only vapors into the reactor 520 may provide an enhanced process flow, as opposed to conducting a mixed phase of vapors and solids.
  • FIG. 10 and FIG. 11 show further alternative arrangements of the system 500.
  • the feedstock was then blended such that the sulfur concentration was about 460 ppm and sufficient acid was available for reacting with potassium in the feedstock.
  • the dried biomass-oil slurry was mixed with about 0.3 tpd of sulphuric acid and about 0.4 tpd of dibutyl disulfide.
  • a conventional screw pump was used to pressurize the fluid to a pressure of about 26 barg and mixed with about 16.7 tpd of hydrogen.
  • the dibutyl disulfide was replaced with a hydrogen sulfide injection.
  • the fluid was heated by thermal oil to about 350 °C and some or all of the biochar solids were removed by a cyclone with the produced vapors being fed into a catalyst bed with a 1/20* inch CoMo catalyst with a Weight Hourly Space Velocity of approximately 1 providing sufficient retention time for the hydropyrolysis of the biomass.
  • Approximately 6.4 tpd of hydrogen was consumed and a cycle oil with an oxygen content less than 10% was produced.
  • the produced gas was made up of about 6.1 tpd methane, about 5.1 tpd ethane, about 5.5 tpd propane, about 19.9 tpd of carbon monoxide and about 29 tpd of carbon dioxide.
  • the Total Acid Number of the synthetic crude was less than about 10 mg KOH/g.
  • a 440 micron filter kept the catalyst within the reactor.
  • the produced gases off the HPLT separator was fed into a high-pressure Pressure Swing Absorption (PSA) unit to recover about >85% or about 7.5 tpd of the unreacted hydrogen.
  • PSA Pressure Swing Absorption
  • the remaining produced gas was about 15 mol% methane, about 8 mol% ethane, about 5 mol% propane, about 28 mol% carbon monoxide, about 26 mol% carbon dioxide with the balance being the lost unreacted hydrogen.
  • About 7.5 tpd of the hydrogen was compressed to the 55 barg pressure of the hydrotreater.
  • the 70 tpd of soluble organics containing aqueous water was used for steam gasification through use of the system shown in FIG. 4. About 40 tpd of additional recycle water was utilized from the recovered water from the drying process to provide about 110 tpd of feed water. About 110 tpd of the feed water with the biochar is pressurized by a pump to about 10 barg and fed into the lower section of the gasifier reactor and vaporized by indirect heat transfer.
  • VPSA Vacuum Pressure Swing Absorption
  • About 50 tpd of oxygen purified from the air by a Vacuum Pressure Swing Absorption (VPSA) unit was compressed to about 10 barg and injected in a mixture with 20 tpd of the produced gas which was oxy-combusted in the unit to raise the reactor temperature to over 800 °C in an interior gap.
  • Quench water was added to the upper outlet to cool the syngas stream to less than about 500 °C after which ash was removed by an outlet cyclone.
  • the cross-exchanger was used to cool the syngas-steam mixture to about 200 °C which was fed into a Water-Shift-Reactor to convert carbon monoxide and steam to carbon dioxide and hydrogen which was cooled by heat exchanger and water quenching.
  • a two-phase separator removed the black water from the syngas, which was recycled.
  • a Pressure Swing Absorption unit was used to remove about 170 tpd of carbon dioxide which was compressed and sequestered at 100 bar into a depleted gas formation via a well.
  • the 9.2 tpd of produced hydrogen was compressed to about 30 bar and injected into the slurry hydropyrolysis reactor.
  • the produced renewable cycle oil was re-pressurized by a pump to about 50 barg and heated to over 250 °C by a heat exchanger. About 7.5 tpd of hydrogen was added prior to feeding a conventional hydrotreater to reduce the oxygen content to less than about 3000 ppm and saturate any olefins.
  • the upgraded liquids were flashed to atmospheric pressure where they were distilled by conventional atmospheric crude distillation tower.
  • the fixed hydrotreater catalysts were selected to promote conversion to about 20 tpd of renewable gasoline and about 35 tpd of renewable diesel.
  • the 5.6 tpd of unreacted hydrogen and produced gas was fed into the slurry hydropyrolysis reactor.
  • a plug screw feeder pressurizes the biomass to 26 barg and mixed with about 17 tpd of hydrogen at 530°C that the biomass-slurry temperature was heated to 400°C.
  • About 22.8 tpd of biochar is removed by cyclone.
  • the produced vapors at 400°C were fed into a reactor with CoMo catalyst with a Weight Hourly Space Velocity of approximately 1 providing sufficient retention time for the hydropyrolysis of the biomass.
  • Approximately 5.2 tpd of hydrogen was consumed and a cycle oil with an oxygen content less than 7% was produced.
  • the produced gas was made up of about 5.2 tpd methane, about 5.2 tpd ethane, about 4.9 tpd propane, about 10.1 tpd of carbon monoxide and about 10.1 tpd of carbon dioxide.
  • HPLT High- Pressure, Low-Temperature
  • the produced gases off the HPLT separator is fed into a high-pressure Pressure Swing Absorption (PSA) unit to recover about >87% or about 10.9 tpd of the unreacted hydrogen.
  • PSA Pressure Swing Absorption
  • the remaining produced gas was about 17 mol% methane, about 9 mol% ethane, about 6 mol% propane, about 18 mol% carbon monoxide, about 12 mol% carbon dioxide with the balance being the lost unreacted hydrogen.
  • Quench water was added to the upper outlet to cool the syngas stream to less than about 500 °C and generate additional steam.
  • the cross-exchanger was used to cool the syngas-steam mixture to about 200 °C which was fed into a Water-Shift-Reactor to convert carbon monoxide and steam to carbon dioxide and hydrogen which was cooled by heat exchanger. Approximately 7.5 tpd of hydrogen and 55.6 tpd of carbon dioxide of syngas is produced.
  • a Pressure Swing Absorption unit was used to remove the 55.6 tpd of carbon dioxide with 0.9 tpd of hydrogen losses. The off-gas is compressed to 20 barg and cooled by cross-exchanger, propane refrigeration loop and low temperature separator. The 0.8 tpd of hydrogen is recovered by an additional Pressure Swing Absorption Unit. Approximately 50 tpd of liquefied CO2 is pressurized to supercritical conditions and sequestered in a suitable geologic formation.
  • the partially deoxygenated hydrocarbon liquids were pumped to 50 barg and mixed with 2.8 tpd of hydrogen feeding a conventional hydrotreater to reduce the oxygen content to less than about 3000 ppm and saturate any olefins.
  • the vapors were cooled that produced gas could be separated from the hydrocarbon product liquids which were recycled into the hydropyrolysis reactor.
  • the upgraded liquids were boiled to atmospheric pressure where they were distilled by batch atmospheric crude distillation.
  • the fixed hydrotreater catalysts were selected to promote conversion to about 15.9 tpd of renewable gasoline and about 15.9 tpd of renewable diesel.
  • the remaining produced gas and biochar is utilized as a fuel gas for process heaters. Cooling in the process is used to generate steam which is utilized in a steam turbine to generate electrical power. Excess power was sold to the grid.
  • the resulting carbon intensity is approximately -62g CO2e/MJ in contrast to 94 g Coe/MJ for fossil fuel derived gasoline and 93g CO2e/MJ for fossil fuel derived diesel.

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  • Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Engineering & Computer Science (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • General Chemical & Material Sciences (AREA)
  • Organic Chemistry (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Wood Science & Technology (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)

Abstract

Les modes de réalisation de la présente divulgation concernent un système et un procédé d'hydroconversion de biomasse carbonée en vue de produire des produits hydrocarbonés renouvelables à faible point d'ébullition, à faible teneur en soufre et à faible teneur en oxygène. Dans certains modes de réalisation, la biomasse carbonée est mise sous pression pour former un bouchon étanche à la pression et mélangée avec de l'hydrogène surchauffé, le biocharbon ainsi produit étant récupéré avant d'être introduit dans un réacteur contenant un catalyseur d'hydrogénolyse à une température supérieure à 300°C. Les hydrocarbures organiques, l'eau et le biocharbon sont produits par hydropyrolyse en suspension et séparés. L'hydrogène pour le procédé peut être généré par gazéification à la vapeur, de préférence par gazéification cyclique à la vapeur, de biocharbon issu de biomasse.
PCT/CA2023/051310 2022-10-03 2023-10-03 Système et procédé d'hydroconversion de biomasse en pétrole brut synthétique renouvelable WO2024073846A1 (fr)

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Citations (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4978369A (en) * 1987-06-11 1990-12-18 Veba Oel Entwicklungs-Gesellschaft Mbh Process for feeding carbonaceous material into reaction spaces
WO2014133486A1 (fr) * 2013-02-26 2014-09-04 G4 Insights Inc. Procédé d'hydrogazéification de biomasse en méthane présentant peu de goudrons à rejeter

Patent Citations (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4978369A (en) * 1987-06-11 1990-12-18 Veba Oel Entwicklungs-Gesellschaft Mbh Process for feeding carbonaceous material into reaction spaces
WO2014133486A1 (fr) * 2013-02-26 2014-09-04 G4 Insights Inc. Procédé d'hydrogazéification de biomasse en méthane présentant peu de goudrons à rejeter

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