WO2023147523A1 - Procédés, systèmes et appareil de capture, d'utilisation et de stockage de carbone - Google Patents

Procédés, systèmes et appareil de capture, d'utilisation et de stockage de carbone Download PDF

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Publication number
WO2023147523A1
WO2023147523A1 PCT/US2023/061521 US2023061521W WO2023147523A1 WO 2023147523 A1 WO2023147523 A1 WO 2023147523A1 US 2023061521 W US2023061521 W US 2023061521W WO 2023147523 A1 WO2023147523 A1 WO 2023147523A1
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Prior art keywords
gas
stream
systems
liquid
methods
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PCT/US2023/061521
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English (en)
Inventor
Paul E. YELVINGTON
John Anthony DEAN
Joshua B. BROWN
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M2X Energy Inc.
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Priority claimed from US17/746,942 external-priority patent/US11649201B2/en
Priority claimed from US17/953,056 external-priority patent/US20230212098A1/en
Priority claimed from US17/984,126 external-priority patent/US20230279802A1/en
Application filed by M2X Energy Inc. filed Critical M2X Energy Inc.
Priority to AU2023211693A priority Critical patent/AU2023211693A1/en
Publication of WO2023147523A1 publication Critical patent/WO2023147523A1/fr

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    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B32/00—Carbon; Compounds thereof
    • C01B32/50—Carbon dioxide
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/34—Chemical or biological purification of waste gases
    • B01D53/74—General processes for purification of waste gases; Apparatus or devices specially adapted therefor
    • B01D53/86—Catalytic processes
    • B01D53/869—Multiple step processes
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B32/00—Carbon; Compounds thereof
    • C01B32/40—Carbon monoxide
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2255/00—Catalysts
    • B01D2255/10—Noble metals or compounds thereof
    • B01D2255/102—Platinum group metals
    • B01D2255/1021—Platinum
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2255/00—Catalysts
    • B01D2255/10—Noble metals or compounds thereof
    • B01D2255/102—Platinum group metals
    • B01D2255/1023—Palladium
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2255/00—Catalysts
    • B01D2255/20—Metals or compounds thereof
    • B01D2255/207—Transition metals
    • B01D2255/20738—Iron
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2255/00—Catalysts
    • B01D2255/20—Metals or compounds thereof
    • B01D2255/207—Transition metals
    • B01D2255/20792—Zinc
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2256/00—Main component in the product gas stream after treatment
    • B01D2256/24—Hydrocarbons
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2257/00—Components to be removed
    • B01D2257/10—Single element gases other than halogens
    • B01D2257/104—Oxygen
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2257/00—Components to be removed
    • B01D2257/30—Sulfur compounds
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/34—Chemical or biological purification of waste gases
    • B01D53/74—General processes for purification of waste gases; Apparatus or devices specially adapted therefor
    • B01D53/86—Catalytic processes
    • B01D53/8603—Removing sulfur compounds
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/34—Chemical or biological purification of waste gases
    • B01D53/74—General processes for purification of waste gases; Apparatus or devices specially adapted therefor
    • B01D53/86—Catalytic processes
    • B01D53/8671—Removing components of defined structure not provided for in B01D53/8603 - B01D53/8668
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F02—COMBUSTION ENGINES; HOT-GAS OR COMBUSTION-PRODUCT ENGINE PLANTS
    • F02B—INTERNAL-COMBUSTION PISTON ENGINES; COMBUSTION ENGINES IN GENERAL
    • F02B37/00—Engines characterised by provision of pumps driven at least for part of the time by exhaust
    • F02B37/004—Engines characterised by provision of pumps driven at least for part of the time by exhaust with exhaust drives arranged in series
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F02—COMBUSTION ENGINES; HOT-GAS OR COMBUSTION-PRODUCT ENGINE PLANTS
    • F02B—INTERNAL-COMBUSTION PISTON ENGINES; COMBUSTION ENGINES IN GENERAL
    • F02B37/00—Engines characterised by provision of pumps driven at least for part of the time by exhaust
    • F02B37/013—Engines characterised by provision of pumps driven at least for part of the time by exhaust with exhaust-driven pumps arranged in series
    • 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
    • Y02C—CAPTURE, STORAGE, SEQUESTRATION OR DISPOSAL OF GREENHOUSE GASES [GHG]
    • Y02C20/00—Capture or disposal of greenhouse gases
    • Y02C20/40—Capture or disposal of greenhouse gases of CO2

Definitions

  • the present inventions relate to new and improved methods, devices and systems for recovering and converting waste gases, such as flare gas, into useful and economically viable materials and to separate, capture and utilize CO2, H2 or both from process, waste or exhaust gas streams.
  • waste gases such as flare gas
  • flare gas should be given their broadest possible meaning, and would include gas generated, created, associated or produced by or from oil and gas production, hydrocarbon wells (including conventional and unconventional wells), petrochemical processing, refining, landfills, wastewater treatment, dairies, livestock production, and other municipal, chemical and industrial processes.
  • flare gas and waste gas would include stranded gas, associated gas, landfill gas, vented gas, biogas, digester gas, small-pocket gas, and remote gas.
  • the composition of flare gas is a mixture of different gases. The composition can depend upon the source of the flare gas. For instance, gases released during oil and gas production mainly contain natural gas.
  • Natural gas is more than 90% methane (CH4) with ethane and smaller amounts of other hydrocarbons, water, N2 and CO2 may also be present.
  • Flare gas from refineries and other chemical or manufacturing operations typically can be a mixture of hydrocarbons and in some cases H2.
  • Landfill gas, biogas or digester gas typically can be a mixture of CH4 and CO2, as well as small amounts of other inert gases.
  • flare gas can contain one or more of the following gases: methane, ethane, propane, n-butane, isobutane, n-pentane, isopentane, n-hexane, ethylene, propylene, 1 -butene, carbon monoxide, carbon dioxide, hydrogen sulfide, hydrogen, oxygen, nitrogen, and water.
  • flare gas is produced from smaller, individual point sources, such as a number of oil or gas wells in an oil field, a landfill, or a chemical plant.
  • flare gas Prior to the present inventions flare gas, and in particular flare gas generated from hydrocarbon producing wells, and other smaller point sources, was burned to destroy it, and in some instances may have been vented directly into the atmosphere. This flare gas could not be economically recovered and used. The burning or venting of flare gas, both from hydrocarbon production and other endeavors, raises serious concerns about pollution and the production greenhouse gases.
  • gas and “synthesis gas” and similar such terms should be given their broadest possible meaning and would include gases having as their primary components a mixture of H2 and CO; and may also contain CO2, N2, and water, as well as, small amounts of other materials.
  • product gas and similar such terms should be given their broadest possible meaning and would include gases having H2, CO and other hydrocarbons, and typically significant amounts of other hydrocarbons, such as methane.
  • the term “reprocessed gas” includes “syngas”, “synthesis gas” and “product gas”.
  • the terms “partial oxidation”, “partially oxidizing” and similar such terms mean a chemical reaction where a sub- stoichiometric mixture of fuel and air (i.e., fuel-rich mixture) is partially reacted (e.g., combusted) to produce a syngas.
  • the term partial oxidation includes both thermal partial oxidation (TPOX), which typically occurs in a non-catalytic reformer, and catalytic partial oxidation (CPOX).
  • TPOX thermal partial oxidation
  • CPOX catalytic partial oxidation
  • CC>2e is used to define carbon dioxide equivalence of other, more potent greenhouse gases, to carbon dioxide (e.g., methane and nitrous oxide) on a global warming potential basis of 20 or 100 years, based on Intergovernmental Panel on Climate Change (IPCC) Fifth Assessment Report (AR5) methodology.
  • carbon intensity is taken to mean the lifecycle CO2e generated per unit mass of a product.
  • the term “crude methanol” is defined as methanol produced in a methanol synthesis loop prior to the removal of water, dissolved gases, or other contaminants. Crude methanol often contains 5-20 wt% water, dissolved gases (e.g., 1-2 wt% CO2) and trace contaminants (e.g., ethanol).
  • the term “stabilized methanol” is defined as crude methanol that has passed through a flash operation (e.g., a single-stage flash drum) to reduce the concentration of dissolved gases and other light components. Often stabilized methanol will have ⁇ 1% CO2 and most typically about 0.5 wt% CO2.
  • source methanol refers to “crude methanol”, “stabilized methanol” or both.
  • grade methanol is defined as methanol that meets a purity standard such as the ASTM AA standard (D1152) or IMPCA methanol reference specifications.
  • % and mol % are used interchangeably and refer to the moles of a first component as a percentage of the moles of the total, e.g., formulation, mixture, material or product.
  • weight % (abbreviated wt%) and mass % refer to the weight of a first component as a percentage of the weight of the total, e.g., formulation, mixture, material or product.
  • the terms “fuel-to-air equivalence ratio”, “equivalence ratio”, “fuel/air equivalence ratio”, “ ⁇ t>” or “ER”, and similar such terms have the same meaning and are to be given their broadest meaning and would include the ratio of the actual fuel/air ratio to the stoichiometric fuel/air ratio.
  • the stoichiometric air/fuel ratio is that need for ideal, stoichiometric combustion to occur, which is when all the fuel and oxygen is consumed in the reaction, and the products are carbon dioxide and water.
  • systems and methods for a gas-to-liquids plant having: a primary synthesis loop at a pressure above about 30 bar; a high-pressure, process stream containing CO2, after condensation and collection of liquid or easily condensable products; a CO2 separator, wherein the CO2 separator operates based on mechanical separation of condensed-phase (solid or liquid) CO2; and capture of the CO2- rich stream for subsequent use or sequestration.
  • gas-to-liquid plant is small scale having one or a plurality of syngas engines, targeting 600,000 scfd (standard cubic feet per day) of inlet gas.
  • the size of such a plant could vary from 50,000 scfd to 3,000,000 scfd, or 20,000 scfd to 100,000 scfd or 250,000 scfd to 25,000,000 scfd; wherein the mechanical CO2 separator comprises heat exchangers, a turbo-expander, a throttling valve, and gassolid separator and a pump; Recycle of a CC>2-depleted stream to the downstream synthesis process or upstream reformer; wherein the high-pressure process stream is one of the gas-phase effluent of the product condensation and collection step or the retentate of the hydrogen separation step; wherein the CO2 separator is used for syngas ratio adjustment and therefore eliminating the hydrogen separation step and replacing it with a simple splitter and purge stream; wherein the CO2 separator in Figures 2 and 3 delivers the CC>2-depleted stream at high-pressure and can be recycled to the downstream synthesis process without substantial recompression; wherein the mechanical separation of condensed phase CO2 uses expansion
  • systems and methods having a small- scale gas-to-liquids plant with primary synthesis loop at a pressure above about 30 bar; a CO2 separator that removes CO2 from a high-pressure process stream after condensation and collection of liquid or easily condensable products, wherein the CO2 separator operates based on chemical/physical separation of CO2; recycle of a CO2- depleted stream to the downstream synthesis process or upstream reformer; and capture and sequestration of the CC>2-rich stream for one or more uses.
  • the high-pressure process stream being one of the gas-phase effluent of the product condensation and collection step or the retentate of the hydrogen separation step; wherein the use of the CO2 separator for syngas ratio adjustment and therefore eliminating the hydrogen separation step and replacing it with a simple splitter and purge stream; wherein the CO2 separator delivers the CC>2-depleted stream at high-pressure and can be recycled to the downstream synthesis process without substantial recompression; wherein the chemical/physical CO2 separation method being one of membrane separation, absorption (e.g., amine stripping), adsorption, or chemical reaction (e.g., carbonate formation); wherein the re-injection of the liquid CO2 at the well site for sequestration and/or enhanced oil recovery or transport of the liquid CO2 via pipeline, rail tank car, tanker truck, or the like for other uses; wherein the use of inlet air separation or syngas nitrogen rejection to reduce the amount of nitrogen carried through the
  • the monetization of stranded gas resources generally requires that the gas be converted to a product or intermediate that is a liquid (e.g., methanol, FT liquids) or easily condensable gas (e.g., ammonia) at ambient temperatures.
  • a liquid e.g., methanol, FT liquids
  • easily condensable gas e.g., ammonia
  • the recycle ratio may be kept low resulting in lower overall carbon efficiency compared to convention, large-scale plants.
  • carbon efficiencies defined as the fraction of carbon in the incoming natural gas that is fixed in the product (e.g., methanol), may be about 50%. Of the remaining carbon balance, about 25% is CO in the unreacted syngas and 25% is CO2 in the unreacted syngas.
  • CO2 is captured and used for enhanced oil recovery (EOR) at or near the wellsite and the unreacted CO is oxidized in an emissions control device.
  • EOR enhanced oil recovery
  • Removing CO2 also has the advantage that it improves the stoichiometry number, S, of the recycled syngas and improves the yield and selectivity of the downstream synthesis reactor. Besides improving the reactor performance and reducing the carbon footprint of the process, carbon capture may also generate an additional revenue stream of the distributed process (CO2 for EOR costs about $1-3/Mscf [thousand standard cubic feet] delivered to the wellsite) and may generate additional revenue through tax credits, incentives (e.g., US 45Q tax credit), and the like.
  • CO2 for EOR costs about $1-3/Mscf [thousand standard cubic feet] delivered to the wellsite
  • incentives e.g., US 45Q tax credit
  • the system has a monitoring, control and data storage system that is configured to collect, record, store and transmit the amount of carbon, (as CO2, C (in other forms) or both) that is sequestered, and thus not released into the atmosphere.
  • a monitoring, control and data storage system configured to collect, record, store and transmit the amount of carbon, (as CO2, C (in other forms) or both) that is sequestered, and thus not released into the atmosphere.
  • CO2, C in other forms
  • data is obtained in a manner that can be used to obtain and support the issuance of tax credits, carbon credits and other carbon-based exchanges and trading activities.
  • a gas-to-liquid system with primary synthesis loop at a pressure above about 30 bar including: a means for providing a high-pressure, process stream containing CO2, after condensation and collection of liquid or easily condensable products; a CO2 separator, wherein the CO2 separator operates based on mechanical separation of condensed-phase (solid or liquid) CO2; and, a means for providing for a capture of the CC>2-rich stream for subsequent use or sequestration.
  • these systems and methods having one or more of the following features: including a means to recycle of a CC>2-depleted stream to the downstream synthesis process or upstream reformer; wherein the high-pressure process stream is one of the gas-phase effluent of the product condensation and collection step or the retentate of the hydrogen separation step; wherein the CO2 separator is for syngas ratio adjustment and therefore eliminating the hydrogen separation step and replacing it with a simple splitter and purge stream; wherein the CC>2-depleted stream is at high-pressure and can be recycled to the downstream synthesis process without substantial recompression; including the mechanical separation of condensed phase CO2 using expansion through a turbo-expander and/or valve to promote condensation/deposition via the cooling effect of gas expansion; including the use of one or more recuperating heat exchangers to pre-cool the gas to the turbo-expander and promote melting of the dispersed-phase, solid CO2; including the use of a pump (e.g., progressive cavity pump or the
  • a method to operate a gas-to-liquid system with primary synthesis loop at a pressure above about 30 bar including: providing a high-pressure, process stream containing CO2, after condensation and collection of liquid or easily condensable products; separating CO2 based on mechanical separation of condensed-phase (solid or liquid) CO2; and, providing for a capture of the CC>2-rich stream for subsequent use or sequestration.
  • a small-scale gas-to-liquid plant with primary synthesis loop at a pressure above about 30 bar including: a CO2 separator that removes CO2 from a high-pressure process stream after condensation and collection of liquid or easily condensable products, wherein the CO2 separator operates based on chemical/physical separation of CO2; recycle of a CC>2-depleted stream to the downstream synthesis process or upstream reformer, and; capture and sequestration of the CC>2-rich stream for one or more uses.
  • these systems and methods having one or more of the following features: including wherein the high-pressure process stream is one of the gas-phase effluent of the product condensation and collection step or the retentate of the hydrogen separation step; including the use of the CO2 separator for syngas ratio adjustment and therefore eliminating the hydrogen separation step are replacing it with a simple splitter and purge stream; wherein the CC>2-depleted stream is at high-pressure and can be recycled to the downstream synthesis process without substantial recompression; wherein the chemical/physical CO2 separation method is one of membrane separation, absorption (e.g., amine stripping), adsorption, or chemical reaction (e.g., carbonate formation); wherein the liquid CO2 is re-injected at the well site for sequestration and/or enhanced oil recovery or transported via pipeline, rail tank car, tanker truck, or the like for other uses; including the use of inlet air separation or syngas nitrogen rejection to reduce the amount of nitrogen carried through the process and therefore increase the CO2 concentration, reducing
  • FIG. 1 is a schematic and process flow diagram of an embodiment of a system for converting otherwise uneconomic hydrocarbon-based fuel, e.g., flare gas to methanol, which may further have carbon capture, utilization & storage (“CCUS”) (not shown in the figure), in accordance with the present inventions.
  • CCUS utilization & storage
  • FIG. 2 is a schematic and process flow diagram of an embodiment of a system for converting otherwise uneconomic hydrocarbon-based fuel, e.g., flare gas to methanol having an embodiment of CCUS having a hydrogen separator downstream from the CO2 separator, where the separated CO2 is used for re-injection for stimulating the production well for enhanced oil recovery (EOR) or transport via pipeline (or other mode of shipment) for storage or other uses and where the permeate (hydrogen-rich) stream (low pressure) from the hydrogen separation is used to adjust the syngas gas ratio in accordance with the present inventions.
  • EOR enhanced oil recovery
  • pipeline or other mode of shipment
  • FIG. 3 is a schematic and process flow diagram of an embodiment of CCUS (without the unit operation of hydrogen separation) where the CO2-depleted effluent stream is used to adjust the syngas ratio and the CO2-enriched effluent stream is used for re-injection for stimulating the production well for enhanced oil recovery (EOR) or transport via pipeline (or other mode of shipment) for storage or other uses in accordance with the present inventions.
  • EOR enhanced oil recovery
  • FIG. 4 is a schematic and process flow diagram of an embodiment of CCUS with hydrogen separation upstream of the CO2 separation, where the recovered CO2 is used for re-injection to stimulate the production well for enhanced oil recovery (EOR) or transport via pipeline (or other mode of shipment) for storage or other uses and where the permeate (hydrogen-rich) stream (low pressure) is used to adjust the syngas gas ratio in accordance with the present inventions and the retentate (hydrogen- depleted) stream (high pressure) is used to feed the CO2 separation unit.
  • EOR enhanced oil recovery
  • FIG. 4 is a schematic and process flow diagram of an embodiment of CCUS with hydrogen separation upstream of the CO2 separation, where the recovered CO2 is used for re-injection to stimulate the production well for enhanced oil recovery (EOR) or transport via pipeline (or other mode of shipment) for storage or other uses and where the permeate (hydrogen-rich) stream (low pressure) is used to adjust the syngas gas ratio in accordance with the present inventions and the retentate
  • FIG. 5 is schematic and process flow diagram of an embodiment of a CO2 separation unit for use in CCUS, for an embodiment of a CO2 separator block using deposition-based carbon capture (DBCC), consisting of mechanical CO2 separation via a turbo-expander and throttle valve to reduce the stream temperature such that CO2 is converted directly from gas phase to solid form, in accordance with the present inventions.
  • DBCC deposition-based carbon capture
  • the CCUS may be used with any system, such as the embodiments of FIGS. 2 to 4, that can provide a CO2 rich process stream.
  • FIG. 6 is a Map of CO2 pipelines (light blue) in the Permian basin, an oil and gas producing region of Texas and the gulf coast of the United States, for use with embodiments in accordance with the present inventions.
  • FIG. 7 is a graph showing a phase diagram for pure CO2for use with embodiments in accordance with the present inventions.
  • FIG. 8 is a graph showing a phase diagram for CO2 overlaid with pressure required for onset of frost/dew formation and for 90% CO2 removal for a gas mixture containing nominally 6 mol% CO2, in accordance with an embodiment of the present inventions.
  • FIG. 9 is a graph showing a phase diagram for CO2 overlaid with state points and processes for a deposition-based carbon capture strategy, in accordance with an embodiment of the present inventions.
  • FIG. 10 is a graph showing a Pxy diagram showing vapor-liquid equilibrium for a N2 + CO2 mixture calculated with the Peng-Robinson equation of state, in accordance with an embodiment of the present inventions.
  • FIG. 11 is a table showing global warming potential values.
  • the present inventions relate to carbon capture, utilization & storage (“CCUS”) devices, systems and methods.
  • CCUS carbon capture, utilization & storage
  • embodiments of the present inventions generally relate to systems, devices and methods to recover and utilize CO2 from gas streams, and in particular process, exhaust or waste gas streams containing C0 2 , and in particular containing high amounts of CO 2 .
  • the present inventions relate to the separation and recovery of CO2 from gas streams created during the conversion of an otherwise uneconomic hydrocarbon-based feedstock e.g., flare gas, to a high value product, e.g., methanol.
  • the present inventions relate to hydrogen capture, utilization & storage devices, systems and methods.
  • embodiments of the present inventions generally relate to systems, devices and methods to recover and utilize H 2 from gas streams, and in particular exhaust or waste gas streams containing hydrocarbons and CO2, and in particular containing high amounts of CO2.
  • the present inventions relate to the separation and recovery of H 2 , CO2, or both from gas streams created during the conversion of an otherwise uneconomic hydrocarbon-based feedstock, e.g., flare gas, to a high value product, e.g., methanol.
  • an otherwise uneconomic hydrocarbon-based feedstock e.g., flare gas
  • a high value product e.g., methanol.
  • Any of the CCUS systems, devices and methods disclosed herein can be used with systems, devices and methods to convert otherwise uneconomic hydrocarbon-based feedstocks (e.g., stranded, associated, non-associated, landfill, flared, small-pocket, remote gas, waste water treatment) to value-added, easily transported products (such as methanol, ethanol, ammonia, dimethyl-ether, F-T liquids, and other fuels or chemicals).
  • the present inventions generally find considerable advantages in their application to gas streams having about 3% CO2 to about 85% CO2, about 5% CO2 to about 50% CO2, about 15% CO2 to about 65% CO2, about 25% CO2 to about 75% CO2, more that about 5% CO2, more than about 15% CO2, more than about 25% CO2, more than about 35% CO2, and lower and higher amounts.
  • the present inventions generally find considerable advantages in their application to gas streams having about 3% H 2 to about 85% H 2 , about 5% H 2 to about 50% H 2 , about 15% H 2 to about 65% H 2 , about 25% H 2 to about 75% H 2 , more that about 5% H 2 , more than about 15% H 2 , more than about 25% H2, more than about 35% H2, and lower higher amounts.
  • the present inventions also generally find considerable advantages in their application to gas streams having both of any one of the foregoing amounts of CO2 and H2.
  • Embodiments of the present invention provide for reduced or zero CO2 emissions by capturing the CO2 that would otherwise go up the exhaust stack.
  • a turboexpander due to the high pressure of the synthesis process, a turboexpander can be used to simultaneously lower the pressure to near ambient and reduce the temperature below the solidus line of CO2 (dry ice temperature of -78.5 °C at ambient pressure) or liquidus line of CO2 forming a condensed CO2 phase that can be separated for the bulk gas
  • Chemical/Physical separation prior to the exhaust stack, the CO2 is removed by chemical process such as an amine-based solvent and the like.
  • the separated CO2 can be sequestered on-site (via re-injection) optionally for enhanced oil recovery (EOR), or sold as a commercial product (EOR, refrigeration, industrial processes (surface processing), chemical synthesis, beverages, etc.).
  • an embodiment of the present inventions reduces the carbon emissions for synthesis of methanol (or other downstream product such as ammonia, DME or F-T liquids) in an integrated system with an engine-based reformer for small, modular, distributed conversion of stranded gas to products, such as those taught and disclosed in US patent publication no. 2022/0388930 and in US patent application serial number 17/953,056 (filed 09/26/2022) and 17/984,126 (filed 11/152022), the entire disclosure of each of which is incorporated herein by reference.
  • CO2 carbon dioxide
  • Reducing the carbon emissions reduces the environmental footprint of the process and supports efforts to mitigate climate change.
  • carbon emissions are reduced by separating carbon dioxide (CO2) from the exhaust gas byproduct and either sequestering the CO2 or using it for another purpose.
  • CO2 has many industrial uses, with EOR principal among them, and is estimated to have a value of $1-3/Mscf delivered to a well site. As such, CO2 can represent a revenue generating co-product if the added value of capturing the carbon can be justified by the additional capital and operating costs.
  • Capturing and sequestering carbon can also provide revenue through tax credits and the sale of commercial or governmental carbon offsets.
  • embodiments relate to processes for reducing carbon emissions that exploit inherent features of the integrated system with the enginebased reformer, such as the availability of power (e.g., shaft power, electrical power, or pneumatic/hydraulic pressure) from the reformer and the high pressure in the exhaust byproduct stream of the downstream synthesis process.
  • power e.g., shaft power, electrical power, or pneumatic/hydraulic pressure
  • embodiments of the present CCUS methods and systems find application in, and can be used with or in conjunction with, systems and methods for the conversion of otherwise uneconomic hydrocarbon-based fuel (e.g., stranded, associated, landfill, flared, small-pocket, remote gas) to value-added, easily transported products (such as methanol, ethanol, mixed alcohols, ammonia, dimethyl-ether, F-T liquids, and other fuels or chemicals) using an autonomous, modular system.
  • embodiments of the present invention can apply to conversion of economic (e.g., pipeline natural gas) as well as uneconomic hydrocarbon-based fuels.
  • FIG. 1 there is shown a generalized embodiment of a system and method for the conversion of a waste gas, e.g., flare gas, into a value-added product, e.g., methanol, without CCUS.
  • the system 100 has a reformer stage 101 and a synthesis stage 102.
  • the system 100 has an air intake 110, that feeds air through into a compressor 111 , which compresses the air.
  • the compressed air is feed through heat exchanger 120a into a mixer 113.
  • the system has a waste gas, e.g., flare gas, intake 114.
  • the waste gas flows through a heat exchanger 120b into the mixer 113.
  • the mixer 113 provides a predetermined mix of air and waste gas, as taught and disclosed in this specification, to a reformer 114.
  • the fuel-air mixture that is formed in mixer 113 is preferably rich, more preferably having an overall fuel/air equivalence ratio ( t> or ER) greater than 1 , greater than 1 .5, greater than 2, greater than 3, from about 1 .5 to about 4.0, about 1 .1 to about 3.5, about 2 to about 4.5, and about 1 .1 to about 3, and greater values.
  • t> or ER overall fuel/air equivalence ratio
  • oxygen can be added to the air.
  • Water or steam may also be injected into the mixture of air and fuel, or to air or fuel individually. From about 1 to about 20% (molar) water can be injected, from about 10 to about 15% (molar water), from about 5 to about 17% (molar) water, more than 5% (molar) water, more than 10% (molar) water, more than 15% (molar) water, and less than 25% (molar) water, water can be injected. Following oxygen enrichment, the combustion air can have from about 21 % (molar) to about 90% (molar) oxygen.
  • “Air-breathing” reformers, and air breathing engines as used herein are understood to also include engines using air modified with the addition of water, oxygen or both.
  • the reformer 114 partially combusts the predetermined mixture of waste gas and air (e.g., flare gas and air) to form a reprocessed gas (e.g., syngas).
  • a reprocessed gas e.g., syngas
  • the syngas flows through heat exchangers 120a, 120b and into a filter 115, e.g., a particulate filter.
  • the reprocessed gas (e.g., syngas) flows to a guard bed reactor assembly 116, optionally having two guard bed reactors 116a, 116b.
  • the guard bed reactor 116 has materials, e.g., catalysts, that remove contaminates and other materials from the syngas that would harm, inhibit or foul later apparatus and processes in the system.
  • the guard bed reactor 116 may contain catalyst, adsorbents, or other materials to remove sulfur (e.g., iron sponge, zinc oxide or similar) and halogenated compounds.
  • the guard bed can instead be placed in the waste gas intake line 114.
  • the reprocessed gas (e.g., syngas) flows to a deoxygenation (deoxo) reactor 117.
  • the deoxo reactor 117 removes excess oxygen from the reprocessed gas (e.g., syngas) by oxidizing combustible compounds in the mixture such as methane, CO, and H2, where the oxygen is converted to water.
  • Catalyst for the deoxo reaction are platinum, palladium, and other active materials supported on alumina or other catalyst support materials.
  • the system 100 has a cooling system 150, which uses a cooling fluid, e.g., cooling water, that is flow through cooling lines, e.g., 151 .
  • Other means of cooling for example direct air cooling, are also contemplated.
  • the reprocessed gas (e.g., syngas) flows to heat exchanger 120c.
  • the reprocessed gas (e.g., syngas) then flows from heat exchanger 120c to a water removal unit 118, e.g., a water knockout drum, demister, dryer, membrane, cyclone, desiccant or similar devices, where water is removed from the reprocessed gas (e.g., syngas).
  • a water removal unit 118 e.g., a water knockout drum, demister, dryer, membrane, cyclone, desiccant or similar devices, where water is removed from the reprocessed gas (e.g., syngas).
  • the reprocessed gas e.g., syngas
  • the reprocessed gas upon leaving unit 118 should have less than about 5% water by weight, less than about 2%, less than about 1 % and less than about 0.1 % water.
  • syngas minor constituents in the gas exiting the reformer can include water vapor, CO 2 , and various unburned hydrocarbons.
  • the now dry reprocessed gas (e.g., syngas) is in the synthesis stage 102.
  • the now dry reprocessed gas e.g., syngas
  • Assembly 130 provides for the controlled addition of hydrogen from line 131 into the now dry reprocessed gas (e.g., syngas). In this manner the ratio of the syngas components can be adjusted and controlled to a predetermined ratio.
  • the hydrogen is provided from hydrogen separation unit 139.
  • the ratio-adjusted dry reprocessed gas leaves assembly 130 and flow to compressor 132.
  • Compressor 132 compresses the reprocessed gas (e.g., syngas) to an optimal pressure as taught and disclosed in this specification, for use the synthesis unit 133.
  • the synthesis unit 133 is a two-stage unit with a first reactor unit 133a and a second reactor unit 133b.
  • Each reactor is a pressure vessel where process gas flows through a catalyst bed in an exothermic reaction.
  • the catalyst bed tubes are typically emersed in a pool of cooling water at a controlled temperature and pressure.
  • Synthesis unit 133 also has heat exchanger 120e.
  • the synthesis unit 133 converts the ratio-adjusted dry reprocessed gas (e.g., syngas) into a value-added product (e.g., methanol, ethanol, mixed alcohols, ammonia, dimethyl-ether, F-T liquids, and other fuels or chemicals).
  • a value-added product e.g., methanol, ethanol, mixed alcohols, ammonia, dimethyl-ether, F-T liquids, and other fuels or chemicals.
  • the value-added product e.g, methanol, etc.
  • the value-added product flows to a collection unit 140.
  • the collection unit 140 collects the value-added product (e.g, methanol, etc.) and flows it through line 141 for sale, holding, or further processing.
  • the syngas is compressed to a pressure of about 15 to about 100 bar and preferably 30-50 bar, and about 25 to about 80 bar, at least about 10 bar, at least about 25 bar and at least about 50 bar, and greater and lower pressures.
  • the temperature of the pressurized syngas is adjusted to a temperature of about 150 °C to about 350 °C and preferably 250 °C, about 200 °C to about 300 °C, about 250 °C to about 375 °C, greater than 125 °C, greater than 150 °C, greater than 200 °C, greater than 250 °C, greater than 350 °C, and less than 400 °C, and higher and lower temperatures.
  • methanol is produced using the reaction of syngas to methanol, reactions for hydrogenation of CO, hydrogenation of CO2, and reverse water-gas shift using actively cooled reactors, such as a heat-exchanged reactor or boiling water reactor, and a copper containing catalyst such as Cu/ZnO/AhOs or the like.
  • methanol synthesis can use the following reactions:
  • the characteristic length scale of the reactors used in this system are sufficiently small (e.g., micro-channel or mini-channels) that they can be shaped into unconventional shapes and topologies using new 3D printing techniques for metals and other high-temperature materials, thus allowing compact packaging and tight control over reaction conditions.
  • Other strategies for intensification of the downstream synthesis reactions can also be considered, such as selectively removing the product from the reactor in-situ, or in a closely coupled fashion, to shift the equilibrium-limited reaction to higher conversion. This process intensification may minimize the need for large recycle streams or allow the reaction to proceed at milder conditions (e.g., lower pressure) thereby increasing process safety margins and providing other benefits.
  • unreacted H2 is also produced.
  • the H2 can be collected and sold, or used to power the gas turbine or a second generator to produce additional electric power.
  • the ratio of H2/CO in the syngas produced by the engine can be tailored to the downstream conversion process.
  • the ideal H2/CO ratio is 2-3.
  • the maximum possible H2/CO ratio is desirable and can be enhanced by, for example, steam addition to promote the water-gas shift reaction.
  • the CO is not required by the downstream synthesis. As such, CO and CO2 byproducts can be collected, sequestered, stored or utilized for other purposes.
  • the collection unit 140 also has a line that flows gas separated from the value-added product (e.g, methanol, etc.) to valve 135, where it is sent to hydrogen separation unit 139, to a recycle loop 136 or both.
  • the recycle loop has compressor 134 and tee-connector 138 to feed the unreacted gas back into the synthesis unit 133.
  • Hydrogen separation can be achieved by via membrane separation or pressure swing absorption (PSA) or the like in the hydrogen separation unit 139.
  • PSA pressure swing absorption
  • an air-breathing engine reformer (having one or more reciprocating engines, turbines or both) produces a syngas intermediate that is further converted to methanol in a downstream synthesis step.
  • a syngas intermediate that is further converted to methanol in a downstream synthesis step.
  • roughly half of the carbon in the incoming natural gas is converted to methanol, a quarter is CO in the unreacted tailgas stream marked “To Exhaust” and a quarter is CO2 in the same stream. Therefore, the carbon efficiency of the baseline process is roughly 50%.
  • the methanol synthesis step takes place at high pressure (nominally 50 bar), and so the downstream streams are available at high pressure, e.g., nominally about 50 bar, at least about 30 bar, from about 20 to about 100 bar, and higher and lower pressures.
  • the hydrogen separation unit 139 is, for example, a pressure-driven device (e.g., membrane or PSA unit) and therefore involves a substantial pressure drop, so the permeate (hydrogen-rich) stream 131 is at relatively low-pressure (nominally 10 bar, and can be from about 5 bar to about 20 bar, less than 3 bar, less than 1 bar and higher and lower pressures), while the retentate (hydrogen-depleted) stream remains at high pressure.
  • Availability of the retentate stream at high pressure are leveraged for use with embodiments of the present CO2 separation units to form CCUS systems.
  • the CCUS systems and processes of FIGS. 2 to 4, and the CO2 separation unit of FIG. 5, and combinations and variations of these can be used with the system of FIG. 1.
  • Hydrogen separation can be achieved by via membrane separation or pressure swing absorption (PSA) or the like in a Hydrogen Separation Unit. Criteria for selection of the technology for a particular gas-to-liquids systems include scale, cost, maintenance, and overall separation efficiency. Separation using membrane results in the hydrogen-rich stream at lower pressure compared to a PSA and requires additional recompression work when used as part of a recycle loop, however the membrane is mechanically simpler and may be less expensive at some scales.
  • PSA pressure swing absorption
  • FIG. 2 there is shown a generalized embodiment of a CCUS system and method 200 having the gas-to-liquid system and process of FIG. 1 (like structures having like numbers).
  • an air-breathing engine reformer (having one or more reciprocating engines, turbines or both) produces a syngas intermediate that is further converted to methanol in a downstream synthesis step.
  • An injection well 271 for injecting the recovered CO2 and a production well 271 for providing the flare gas are shown.
  • the CCUS system 200 has a CO2 separator 260 that receives the gas-phase effluent stream (high pressure) of the methanol condensation and collection step and separates this stream into two streams, a CO2-rich stream 261 (e.g., about 50 bar pressure) for use in EOR, storage or both and a CO2 depleted stream (e.g., less than 2% CO2, less than 1 % CO2, less than 0.1% CO2), which is high pressure (e.g., nominally about 50 bar, at least about 30 bar, from about 20 to about 100 bar, and higher and lower pressures), and used to feed the hydrogen separation unit 139.
  • a CO2-rich stream 261 e.g., about 50 bar pressure
  • CO2 depleted stream e.g., less than 2% CO2, less than 1 % CO2, less than 0.1% CO2
  • high pressure e.g., nominally about 50 bar, at least about 30 bar, from about 20 to about 100 bar, and higher and lower pressures
  • CO2 separation methods that do not lead to a substantial pressure drop are preferred because the hydrogen separation requires high pressure and recompression of the recycle syngas is undesirable.
  • this embodiment favors chemical/physical CO2 separation methods over mechanical CO2 separation methods.
  • compressors can be used to achieve the desired pressure for the H2-rich recycle stream 131 from the hydrogen separation unit 139, based upon the type of CO2 separation unit and hydrogen separation unit.
  • the CO2 product can be re-injected on-site (injection well 271 ) or transported via pipeline, rail tank car, or tanker truck for industrial or other use.
  • the CO2 is used substantially close to the wellsite to minimize transportation costs.
  • the CC>2-depleted stream feeds the hydrogen separation process, which improves its performance and minimizes its capital costs.
  • the retentate stream 261 for the hydrogen separator in FIG. 2 is at high pressure and can be used as additional source of electrical or shaft power through use of a turbo-expander.
  • FIG. 3 there is shown a generalized embodiment of a CCUS system and method 301 having gas-to-liquid system and process 300 of the type general shown and described in FIG. 1.
  • the CCUS system 301 has a CO2 separator 360 that receives the gas-phase effluent stream (at near-reactor pressure) of the methanol condensation and collection step and separates this stream into two streams, a CO2 rich stream 361 (about 50 bar pressure) for use in EOR (e.g., with injection well 371 ), storage or both and a CO2 depleted stream (e.g., less than 2% CO2, less than 1 % CO2, less than 0.1 % CO2), which is at moderate-to-high (e.g., about 50 bar, at least about 30 bar, at least 10 bar, at least 5 bar, from about 20 to about 100 bar, and higher and lower pressure) and used to adjust the syngas ratio (lines 362, 363).
  • moderate-to-high e.g., about 50 bar, at least about 30
  • the flare gas is received from well 372.
  • This CO2 depleted stream will have constituents including nitrogen, hydrogen, and carbon monoxide.
  • the hydrogen separation is not used with the CO2 separator, as thus the CO2 separator also provides a gas stream that is used in performing syngas ratio adjustment.
  • Proper ratio of H2, CO, and CO2 is useful for performance (i.e., yield and selectivity) of the methanol synthesis process. This ratio is quantified by the stoichiometry number, S, defined as
  • the numbers on the right are molar flow rates or mole fractions for the syngas stream entering the methanol synthesis reactor.
  • this ratio reduces to the H2/CO ratio.
  • partial-oxidation reformers such as air-breathing engine reformers
  • the CO2 fraction is non-negligible.
  • Stoichiometry numbers slightly above 2 (S > 2) are preferred to ensure good selectivity and yield of the methanol synthesis process.
  • Lower stoichiometry numbers (S ⁇ 2) lead to the formation of byproducts and complicate the downstream separations.
  • Nascent syngas from the reformer has a lower value of S than desired.
  • Syngas ratio adjustment refers to separations or other methods to adjust S.
  • the hydrogen separation for example as shown in the embodiment of FIG. 1 serves to increase S by enriching the recycle stream (i.e., the permeate stream) in hydrogen, such that when it mixes with the incoming syngas from the reformer, S is substantially equal to 2 in the reactor feed.
  • CO2 can be removed from the syngas recycle stream to increase S, by both increasing the term in the numerator and decreasing the term in the denominator.
  • the CO2 separator functions both for carbon capture and for syngas ratio adjustment.
  • the hydrogen separator has been eliminated and replaced with a simple stream splitter and purge stream.
  • the purge stream is required to eliminate inert gases (e.g., nitrogen) and surplus CO and other gases from the process.
  • the exhaust/purge stream in FIG. 3 is at high pressure and can be used as additional source of electrical or shaft power through use of a turbo-expander, or similar device.
  • FIG. 4 here is shown a generalized embodiment of a CCUS system and method 401 having gas-to-liquid system and process 400 of the type general shown and described in FIG. 1.
  • the CCUS system 401 has a Hydrogen separator that receives the gas-phase effluent stream (near-reactor pressure) of the methanol condensation and collection step and separates this stream into two streams, the hydrogen-rich, low-pressure permeate stream that is recycled back into the process to adjust the syngas ratio; and, the hydrogen-depleted, high-pressure retentate stream that feeds the CO2 separator 460.
  • the CO2 separator 460 separates the hydrogen-depleted, high-pressure retentate stream into two streams, a CO2 rich stream 461 (at about 50 bar pressure) for use in EOR (e.g., injection well 471), storage or both (higher pressures may also help in economics of transport through pipelines, filling tanker trucks/rail cars and other downstream activities) and a CO2 depleted stream (e.g., less than 2% CO2, less than 1 % CO2, less than 0.1% CO2), that is exhausted.
  • the flare gas is received from well 472.
  • the exhaust/purge stream in FIG. 3 is at high pressure and can be used as additional source of electrical or shaft power through use of a turbo-expander, or similar device.
  • the hydrogen separator is upstream from the CO2 separator 460; incorporating CO2 separation in the retentate stream of the hydrogen separation step.
  • the high pressure in the retentate stream can be exploited to minimize the energy requirements for the CO2 separation.
  • this stream is exiting the process and requires expansion to near atmospheric pressure anyway, no recompression is required.
  • this configuration is particularly well-suited to processes with a substantial pressure drop, such as the mechanical separation process described in detail in FIG. 5.
  • the CO2 product can be re-injected on-site or transported via pipeline, rail tank car, or tanker truck for industrial or other use.
  • the CO2 is used substantially close to the wellsite to minimize transportation costs. This embodiment does not affect the syngas recycle stream and therefore does not impact the stoichiometry number, S.
  • FIG. 5 there is shown an embodiment of a mechanical CO2 separator unit and process.
  • the embodiment of FIG. 5 is an example of units that can be used as the “CO2 separator” in the embodiments of the CCUS systems of FIGS. 2-4, and preferably in the embodiment of the CCUS system of FIG. 4. Further, this CO2 separator can be used with any of the systems and methods taught and disclosed in US patent publication no. 2022/0388930 and in US patent application serial number 17/953,056 (filed 09/26/2022), the entire disclosure of each of which is incorporated herein by reference.
  • a CO2-rich stream 501 such as the retentate from the hydrogen separation step, e.g., the retentate from the hydrogen separator of the embodiment of FIG. 4, is first cooled in a series of two recuperators 520a, 520b. The pre-cooled gas is then expanded through a turboexpander 521 . Work produced in the turbo-expander can be used in other parts of the process (e.g., to power syngas compressors).
  • a throttling valve 522 can be used downstream of the turbo-expander 521 to perform the final part of the expansion to avoid deposition of solid CO2 in the turbo-expander 521 , which may impact the maintenance interval of the turbomachine.
  • the low temperatures e.g., ⁇ 100°C
  • the solid CO2 particles i.e., “dry ice snow”
  • the solid-gas separator 523 may be a cyclone, impactor, electrostatic precipitator, or the like.
  • the solid CO2 particles are then conveyed away (line 502) and compressed to high pressure.
  • the solid CO2 compression device and step 524 may be a ram feeder, screw feeder, piston pump, or slurry pump.
  • the work of compression begins to melt the CO2 producing a slurry that is more easily pumped in a slurry pump such as a progressive cavity pump.
  • the compression work is minimal given the low compressibility of condensed phases.
  • the solid CO2 particles or solid/liquid CO2 slurry is passed (via line 503) through the other side of a recuperator 520b to pre-cool the incoming stream.
  • the gas- phase stream (line 505) exiting the solid-gas separator 523 is also passed through the other side of a recuperator 520a to pre-cool the incoming stream.
  • Solid CO2 melts completely in the recuperator and liquid CO2 is produced for re-injection or other purposes described previously.
  • This CO2 separation strategy is intended to exploit high pressure available in the process stream.
  • This part of the process is a net exporter of shaft power (i.e., the power produced in the turbo-expander more than offsets the power required in the pump).
  • the cooling duty is provided by recuperation of the exit streams. As such, it is expected that no external utilities are required in this portion of the process, rather the stored energy in the high-pressure process stream is used to perform the separation.
  • the captured CO2 leaves the system (via line 504) for utilization/storage as described herein.
  • embodiments of the present CCUS methods and system are a part of a small, modular, distributed, self-sufficient plant for conversion of stranded gas to fungible, easily transportable products using an enginebased reformer and syngas intermediate.
  • Such plants and systems are disclosed and taught in US patent publication no. 2022/0388930 and in US patent application serial number 17/953,056 (filed 09/26/2022), the entire disclosure of each of which is incorporated herein by reference.
  • FIGS 7 to 10 there is provided graphs showing general and optimal teachings for the efficient and enhanced operation of embodiments of CCUS systems and processes. These FIGS, among other things, provide for phase diagrams demonstrating mechanical separation of CO2 by forming a separate CO2 condensed (liquid or solid) phase.
  • FIG. 7 shows a phase diagram for CO2.
  • the phase diagram shows the regions of temperature and pressure where gaseous, liquid, and solid phases exist.
  • the lines separating the phases show where two phase are in equilibrium (e.g., liquid and gas).
  • a system containing pure CO2 has a single degree of freedom according to the Gibbs phase rule (i.e., if temperature is specified, pressure is fixed and vice versa).
  • the gas-liquid line corresponds to vaporization/condensation
  • the liquid-solid line represents melting/freezing
  • the gas-solid line represents sublimation/deposition. Deposition is also sometimes referred to as a de-sublimation or frosting.
  • the triple point (-56.6°C, 5.1 bar) is the point where all three phases (gas, liquid, and solid) coexist and the degrees of freedom are zero (i.e., the independent intensive properties, such as T and P, are fixed).
  • CO2 is fairly unique in that it has a fairly high triple point. As a result, deposition becomes a consideration for mechanical separation from gaseous CO2 mixtures. In general, high pressures and low temperatures favor the formation of condensed phases, either liquid or solid.
  • FIG. 8 shows a CO2 phase diagram overlaid with curves for deposition/frosting and for 90% CO2 removal from a gas mixture nominally containing 6 mol% CO2 with the balance being substantially non-condensing gases (e.g., nitrogen).
  • the dashed curves in this figure assume an ideal gas mixture that follows ideal mixture theory. In reality, there are some significant deviations from the ideal behavior, especially for condensation from dilute CO2 mixture as will be discussed later, however the general trends are instructive, particularly for deposition of solid CO2 from gas mixtures. In this ideal scenario, the CO2 begins to deposit (or frost) from a gas mixture when its partial pressure equals the pressure of the gas-solid line (Pdep) on the phase diagram.
  • Pdep gas-solid line
  • FIG. 9 shows a version of FIG. 8 further overlaid with state points corresponding to the stream numbers in FIG. 5.
  • State point 1 (30°C, 50 bar) is nominally the conditions of the syngas exhaust stream of Figure 4.
  • the curve connecting State points 1 and 2 is indicative of an isentropic expansion process.
  • State point 2 is beyond the frost point line, indicating that solid CO2 would form at these conditions.
  • the temperature could be further reduced using recuperative heat exchangers as shown in FIG. 5.
  • the line connecting States 2 and 3 represents pressurization of the solid CO2 dispersed phase in a pump, such as a progressive cavity pump or the like. The work associated with the pressurization is minimal because of the low compressibility of the solid.
  • the final leg of the cycle connects States 3 and 4 and represents the melting of the solid CO2 in the CC>2-side of the recuperator. Although not depicted in this diagram, optionally some melting may occur in the pump, forming a slurry and improving the pumpability of the dispersed solid CO2.
  • the end state, State 4 is liquid CO2 at nominally ambient temperature that may be easily transported and used for a variety of purposes as described above.
  • FIG. 10 shows a Pxy diagram showing vapor-liquid equilibrium (VLE) for a mixture of N2 and CO2 calculated with the Peng-Robinson equation of state (PR EOS).
  • PR EOS Peng-Robinson equation of state
  • the PR EOS is known to be in good agreement with experimental VLE data for this system. While N2 is used in this example, the results are substantially similar for other non-condensable gases.
  • the vertical axis shows the system pressure, and the horizontal axis shows the mole fraction of N2. Curves are shown for temperatures of 0, - 25, -40, and -55°C. The curve for -55°C is very near the minimum temperature for this VLE behavior as it is just above the triple point temperature (-56.6°C), below which vapor and liquid CO2 do not coexist.
  • each curve on the right shows the dew point pressure and the portion on the left shows the bubble point pressure.
  • the region inside the “dome” or locus of points defining the bubble/dew points, is the two- phase liquid-vapor region.
  • a tie line drawn across the vapor-liquid dome intersects the bubble point dew point curves at the equilibrium liquid (x) and vapor (y) mole fractions of N2.
  • liquid CO2 will not condense at any temperature and pressure for a mixture containing more than about 84 mol% N2 (or conversely less than 14% CO2).
  • the typical syngas exhaust stream contains about 6% CO2
  • This surprising result underlies the approach of exploiting deposition to solid CO2, rather than condensation of liquid CO2, in the process described in FIG. 9.
  • direct condensation of liquid CO2 would be possible because the CO2 mole fraction would be higher without the nitrogen dilution.
  • CO2 is separated from a process stream using mechanical separation based on different phases of matter.
  • this embodiment is used on the retentate stream from the hydrogen separator.
  • the stream is expanded and cooled so that CO2 separates into a condensed phase (either liquid or solid).
  • One or more recuperators can be used to pre-cool the stream prior to the expansion process.
  • a turbo-expander is used to expand and cool the high-pressure stream while recovering useful work that can be used elsewhere in the process.
  • deposition also called frosting or desublimation
  • liquid CO2 can be used for local re-injection to stimulate the well (EOR) or transported via pipeline, rail tank car, tanker truck, or the like for a variety of industrial uses.
  • the mechanical separation can also be used on the gas- phase effluent of the product (e.g., methanol) condensation and collection process. In that case, the CO2 separation can also provide syngas ratio adjustment.
  • CO2 is separated from a process stream using chemical/physical separation.
  • this embodiment is used on the effluent from the product (e.g., methanol) product condensation and collection step.
  • product e.g., methanol
  • low- pressure drop through the CO2 separation is preferred to minimize the work required to recompress the recycle stream.
  • the chemical/physical separation can be used in addition to or in place of the hydrogen separation step. Both the hydrogen separation and the CO2 separation are methods to perform syngas ratio adjustment as a way to modify the stoichiometry number of the syngas entering the downstream synthesis step. Ratio adjustment is required because the nascent syngas from the reformer will likely not have the proper stoichiometry number when using a partial-oxidation reformer.
  • the chemical/physical CO2 separation method may be one of membrane separation, absorption (e.g., amine stripping), adsorption, or chemical reaction (e.g., carbonate formation). Separation of CO2 from process streams using these operating principles are known in the art.
  • a unique feature of this invention is that the high-pressure stream is used improve the energy efficiency and separations performance of the CO2 separation and recovery step.
  • a further unique feature of the invention is that the unique topology of the engine-based reformer process is leveraged to provide power (e.g., electrical, shaft, pneumatic/hydraulic pressure) to provide the energy inputs for the CO2 separation and recovery process.
  • the captured CO2 can be recovered (e.g., in a desorber) to recover the CO2 while regenerating the sorbent.
  • the liquid CO2 can be used for local re-injection to stimulate the well (EOR) or transported via pipeline, rail tank car, tanker truck, or the like for a variety of industrial uses.
  • this invention can be used with air separation on the inlet air or rejecting nitrogen from the syngas to reduce the energy intensity and capital intensity of the separation.
  • FIG. 6 there is shown a map of CO2 pipelines in the state of Texas, principally in the Permian basin and the gulf coast areas.
  • the delivered price for CO2 for EOR at well sites in the Permian basin is estimated to be $1-3/Mscf.
  • Anthropogenic CO2 captured from the byproducts of conversion of flare gas to liquid products could provide a distributed, local source of CO2 for EOR at a significantly reduced delivered price.
  • the existing CO2 pipeline infrastructure could serve to distribute CO2 among re-injection sites in the Permian basin.
  • the CO2 in the existing pipeline infrastructure is in the liquid phase.
  • the liquid CO2 produced from the deposition-based mechanical CO2 separator can be directly injected into these pipelines without additional compression. This is a considerable advantage given that the pressure in the pipelines is at or above the vapor pressure of CO2 at the prevailing temperature, for example above about 60 bar at 25 °C.
  • present inventions may lead to new, and heretofore unknown theories to explain the conductivities, fractures, drainages, resource production, chemistries, and function-features of embodiments of the methods, articles, materials, devices and system of the present inventions; and such later developed theories shall not limit the scope of protection afforded the present inventions.
  • the various embodiments of devices, systems, activities, methods and operations set forth in this specification may be used with, in or by, various processes, industries and operations, in addition to those embodiments of the figures and disclosed in this specification.
  • the various embodiments of devices, systems, methods, activities, and operations set forth in this specification may be used with other processes industries and operations that may be developed in the future; with existing processes industries and operations, which may be modified, in-part, based on the teachings of this specification; and with other types of gas recovery systems and methods.
  • the various embodiments of devices, systems, activities, methods and operations set forth in this specification may be used with each other in different and various combinations.
  • the configurations provided in the various embodiments of this specification may be used with each other.
  • the components of an embodiment having A, A’ and B and the components of an embodiment having A”, C and D can be used with each other in various combination, e.g., A, C, D, and A, A” C and D, etc., in accordance with the teaching of this specification.
  • the scope of protection afforded the present inventions should not be limited to a particular embodiment, configuration or arrangement that is set forth in a particular embodiment, example, or in an embodiment in a particular figure.
  • the invention may be embodied in other forms than those specifically disclosed herein without departing from its spirit or essential characteristics.
  • the described embodiments are to be considered in all respects only as illustrative and not restrictive.

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  • Chemical Kinetics & Catalysis (AREA)
  • Inorganic Chemistry (AREA)
  • Environmental & Geological Engineering (AREA)
  • Biomedical Technology (AREA)
  • Analytical Chemistry (AREA)
  • General Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Health & Medical Sciences (AREA)
  • Gas Separation By Absorption (AREA)
  • Organic Low-Molecular-Weight Compounds And Preparation Thereof (AREA)
  • Output Control And Ontrol Of Special Type Engine (AREA)
  • Electrical Control Of Air Or Fuel Supplied To Internal-Combustion Engine (AREA)
  • Hydrogen, Water And Hydrids (AREA)

Abstract

L'invention concerne des systèmes et des procédés de mise au point comprenant des systèmes et des procédés gaz-liquide, par exemple, pour traiter un gaz de torche en méthanol. Dans ces systèmes, un reformeur de moteur aérobie produit un intermédiaire de gaz de synthèse qui est en outre converti en méthanol dans une étape de synthèse en aval. Le système CCUS comprend un séparateur de CO2 qui reçoit un flux en phase gazeuse et sépare ledit flux en deux flux, un flux riche en CO2 et un flux appauvri en CO2. Les systèmes CCUS peuvent en outre avoir un séparateur d'hydrogène qui reçoit un flux en phase gazeuse et sépare ledit flux en un flux riche en hydrogène et un flux appauvri en hydrogène. Le flux riche en CO2 peut être utilisé pour une utilisation dans l'EOR, le stockage ou les deux.
PCT/US2023/061521 2022-01-28 2023-01-28 Procédés, systèmes et appareil de capture, d'utilisation et de stockage de carbone WO2023147523A1 (fr)

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US202263304475P 2022-01-28 2022-01-28
US202263304463P 2022-01-28 2022-01-28
US202263304471P 2022-01-28 2022-01-28
US63/304,463 2022-01-28
US63/304,471 2022-01-28
US63/304,475 2022-01-28
US17/746,942 2022-05-17
US17/746,942 US11649201B2 (en) 2021-05-18 2022-05-17 Autonomous modular flare gas conversion systems and methods
US17/953,056 2022-09-26
US17/953,056 US20230212098A1 (en) 2021-09-26 2022-09-26 Modular Methanol Upgrading Hub Methods and Systems
US17/984,126 US20230279802A1 (en) 2021-11-09 2022-11-09 Pre-Chamber Combustion Systems and Methods
US17/984,126 2022-11-09

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PCT/US2023/061523 WO2023147525A2 (fr) 2022-01-28 2023-01-28 Systèmes, dispositifs et procédés de gestion de pression d'entrée et de sortie de reformeurs de moteur aérobie
PCT/US2023/061522 WO2023147524A2 (fr) 2022-01-28 2023-01-28 Systèmes, dispositifs et procédés de commande de moteur riche
PCT/US2023/061521 WO2023147523A1 (fr) 2022-01-28 2023-01-28 Procédés, systèmes et appareil de capture, d'utilisation et de stockage de carbone

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PCT/US2023/061522 WO2023147524A2 (fr) 2022-01-28 2023-01-28 Systèmes, dispositifs et procédés de commande de moteur riche

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WO2023147525A2 (fr) 2023-08-03
WO2023147524A2 (fr) 2023-08-03
AU2023213005A1 (en) 2024-08-22
WO2023147524A3 (fr) 2023-08-31
WO2023147525A3 (fr) 2023-10-12
AU2023211693A1 (en) 2024-08-08

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