WO2022017829A1 - Réduction des émissions de co et de co2 à partir d'un ccf dans une combustion partielle avec co-production de h2 - Google Patents

Réduction des émissions de co et de co2 à partir d'un ccf dans une combustion partielle avec co-production de h2 Download PDF

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WO2022017829A1
WO2022017829A1 PCT/EP2021/069136 EP2021069136W WO2022017829A1 WO 2022017829 A1 WO2022017829 A1 WO 2022017829A1 EP 2021069136 W EP2021069136 W EP 2021069136W WO 2022017829 A1 WO2022017829 A1 WO 2022017829A1
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gas
stream
process according
adsorbent
mol
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Luis Manuel CRAVO PEREIRA
Luis Angel Robles Macias
Maxime Lacroix
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Totalenergies Se
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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
    • C10G11/00—Catalytic cracking, in the absence of hydrogen, of hydrocarbon oils
    • C10G11/14—Catalytic cracking, in the absence of hydrogen, of hydrocarbon oils with preheated moving solid catalysts
    • C10G11/18—Catalytic cracking, in the absence of hydrogen, of hydrocarbon oils with preheated moving solid catalysts according to the "fluidised-bed" technique
    • C10G11/182—Regeneration
    • 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
    • B01D53/864—Removing carbon monoxide or hydrocarbons
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B3/00—Hydrogen; Gaseous mixtures containing hydrogen; Separation of hydrogen from mixtures containing it; Purification of hydrogen
    • C01B3/02—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen
    • C01B3/22—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by decomposition of gaseous or liquid organic compounds
    • C01B3/24—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by decomposition of gaseous or liquid organic compounds of hydrocarbons
    • C01B3/26—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by decomposition of gaseous or liquid organic compounds of hydrocarbons using catalysts
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B3/00—Hydrogen; Gaseous mixtures containing hydrogen; Separation of hydrogen from mixtures containing it; Purification of hydrogen
    • C01B3/02—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen
    • C01B3/32—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air
    • C01B3/34—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air by reaction of hydrocarbons with gasifying agents
    • C01B3/48—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air by reaction of hydrocarbons with gasifying agents followed by reaction of water vapour with carbon monoxide
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10K—PURIFYING OR MODIFYING THE CHEMICAL COMPOSITION OF COMBUSTIBLE GASES CONTAINING CARBON MONOXIDE
    • C10K1/00—Purifying combustible gases containing carbon monoxide
    • C10K1/002—Removal of contaminants
    • C10K1/003—Removal of contaminants of acid contaminants, e.g. acid gas removal
    • C10K1/005—Carbon dioxide
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10K—PURIFYING OR MODIFYING THE CHEMICAL COMPOSITION OF COMBUSTIBLE GASES CONTAINING CARBON MONOXIDE
    • C10K1/00—Purifying combustible gases containing carbon monoxide
    • C10K1/32—Purifying combustible gases containing carbon monoxide with selectively adsorptive solids, e.g. active carbon
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10K—PURIFYING OR MODIFYING THE CHEMICAL COMPOSITION OF COMBUSTIBLE GASES CONTAINING CARBON MONOXIDE
    • C10K3/00—Modifying the chemical composition of combustible gases containing carbon monoxide to produce an improved fuel, e.g. one of different calorific value, which may be free from carbon monoxide
    • C10K3/02—Modifying the chemical composition of combustible gases containing carbon monoxide to produce an improved fuel, e.g. one of different calorific value, which may be free from carbon monoxide by catalytic treatment
    • C10K3/04—Modifying the chemical composition of combustible gases containing carbon monoxide to produce an improved fuel, e.g. one of different calorific value, which may be free from carbon monoxide by catalytic treatment reducing the carbon monoxide content, e.g. water-gas shift [WGS]
    • 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
    • B01D2256/16—Hydrogen
    • 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
    • B01D2256/22—Carbon dioxide
    • 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
    • B01D2257/304—Hydrogen sulfide
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2257/00—Components to be removed
    • B01D2257/40—Nitrogen compounds
    • B01D2257/404—Nitrogen oxides other than dinitrogen oxide
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2257/00—Components to be removed
    • B01D2257/50—Carbon oxides
    • B01D2257/502—Carbon monoxide
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2257/00—Components to be removed
    • B01D2257/50—Carbon oxides
    • B01D2257/504—Carbon dioxide
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2258/00—Sources of waste gases
    • B01D2258/02—Other waste gases
    • B01D2258/0283—Flue gases
    • 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
    • B01D53/02—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 by adsorption, e.g. preparative gas chromatography
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/04—Integrated processes for the production of hydrogen or synthesis gas containing a purification step for the hydrogen or the synthesis gas
    • C01B2203/042—Purification by adsorption on solids
    • C01B2203/0425—In-situ adsorption process during hydrogen production
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/04—Integrated processes for the production of hydrogen or synthesis gas containing a purification step for the hydrogen or the synthesis gas
    • C01B2203/0465—Composition of the impurity
    • C01B2203/0475—Composition of the impurity the impurity being carbon dioxide
    • 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
    • C10G2300/40—Characteristics of the process deviating from typical ways of processing
    • C10G2300/4043—Limiting CO2 emissions
    • 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
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
    • Y02P20/00—Technologies relating to chemical industry
    • Y02P20/10—Process efficiency
    • Y02P20/129—Energy recovery, e.g. by cogeneration, H2recovery or pressure recovery turbines
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
    • Y02P20/00—Technologies relating to chemical industry
    • Y02P20/151—Reduction of greenhouse gas [GHG] emissions, e.g. CO2
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
    • Y02P30/00—Technologies relating to oil refining and petrochemical industry
    • Y02P30/40—Ethylene production

Definitions

  • the disclosure relates to a method of reducing carbon monoxide (CO) and carbon dioxide (CO2) emissions and co-producing hydrogen (H2) from fluid catalytic cracking (FCC) regenerators of a fluid catalytic cracking unit operated in partial combustion mode through novel integration with adsorptive water-gas-shift reactor producing separate CO2 and H2 streams.
  • CO carbon monoxide
  • CO2 carbon dioxide
  • H2 co-producing hydrogen
  • the chemical industry is a major source of greenhouse gas emissions, via the generation of energy required for its conversions through combustion, via emission of co-products, or end- of-life incineration of its products.
  • FCC units Emissions from FCC units can account between 20 to 35% of the total refinery CO2 emissions, depending on the design of the refinery. FCC units are present in half of the refining schemes and it is challenging to find technologies to manage their emissions. On the other hand, 5 to 20% of the total CO2 emissions could be from hydrogen productions units.
  • FCC regenerators are sometimes also running under partial combustion mode.
  • a problem associated with partial combustion regenerator operation is the formation of a dilute flue gas containing both CO and CO2. Whilst CO2 may be removed from the stream of flue gas via an amine wash, bulk CO emissions reduction would require a plurality of downstream treatment units or changes in the operation of the regenerator of the FCC to effectively reduce the emissions of CO.
  • Typical strategies for reducing CO emissions from FCC regenerators involve further processing or combusting, before venting the regenerator flue gas through a stack.
  • a CO combustor with a boiler is usually used to oxidize the CO to CO2 to meet environmental regulations while facilitating the recovery of valuable energy from the stream of flue gas.
  • US6776607 describes a process and apparatus to inject steam into the dilute phase with an FCC regenerator to promote the combustion of CO before it enters the regenerator cyclones, the plenum, or the flue gas transfer lines.
  • WO2009155138 discloses a process by which a hot oxygen stream containing radicals is fed into a gas stream, such as a catalyst regenerator flue gas stream, that contains carbon monoxide to convert it to CO2.
  • W02007064626 describes a catalytic composition for converting CO to CO2 while minimizing NOx emissions from FCC regenerators.
  • US20090050529 describes platinum-based CO promoters that can improve the CO oxidation activity along with
  • WGS single sorption enhanced water-gas shift
  • an apparatus containing adsorbent material is used for removing CO2 from the compressed feed gases and for shifting CO and H2O towards hydrogen and carbon dioxide.
  • the WGS reaction i.e. CO + H2O CO2 + H2
  • the reaction is shifted to the right-hand side (hydrogen) as a result of adsorption of the CO2 product, hence the name sorption enhanced water-gas shift.
  • WGS processes are typically carried out at high pressures and relatively high temperatures (from 200 to 600°C).
  • US20040081614 describes a process for producing a high-temperature CO x -lean product gas from a high-temperature CO x -containing feed gas.
  • the process includes providing a sorption enhanced reactor containing a first adsorbent, a shift catalyst and a second adsorbent; feeding into the reactor a feed gas containing H2, H2O, CO and CO2; contacting the feed gas with the first adsorbent to provide a CO2 depleted feed gas; contacting the CO2 depleted feed gas with the shift catalyst to form a product mixture comprising CO2 and H2; and contacting the product mixture with a mixture of second adsorbent and shift catalyst to produce the product gas, which contains at least 50 vol.% H2, and less than 5 vol.% combined CO2 and CO.
  • the adsorbent is a high-temperature adsorbent for a Sorption Enhanced Reaction process, such as K 2 CO 3 promoted hydrotalcites, modified double-layered hydrox
  • US5520894 describes a process for removing carbon dioxide regeneratively from a hot gas stream, containing flue gases or fuel gases, wherein the gas stream is successively: a) used for heating and/or desorbing a solid absorbent loaded with carbon dioxide; b) optionally used for generating energy; c) passed through an absorber in which carbon dioxide from the gas stream is absorbed on the absorbent, and: d) is discharged, and wherein: e) the absorbent from step c) is desorbed in a desorber at least partially and optionally under elevated pressure and is then returned to step c).
  • the process and the system are suitable for removing carbon dioxide from combustion gases and for shifting (coal) gasification gases toward hydrogen.
  • WO2010/059055 describes a water-gas shift process comprising a reaction stage.
  • the reaction stage comprises (a) providing a gas mixture comprising CO, H2O and an acid gas component to a reactor containing an adsorbent, and (b) subjecting the gas mixture to water- gas shift reaction conditions to perform the water-gas shift reaction.
  • WO2013/122467 describes a process for reducing the CO2 emissions from processing syngas by a water-gas shift process which comprises, in alternating sequence: (a) a reaction stage wherein a feed gas comprising CO and H2O is fed into a water-gas shift reactor containing a sorbent material capable of adsorbing H2O and CO2 and wherein a product gas issuing from the reactor is collected, (b) a regeneration stage wherein CO2 is removed from the reactor, (c) a loading stage, wherein H2O is fed into the reactor; wherein said feed gas mixture has a molar ratio of H2O to CO below 1.2, and the loading stage is performed at a lower pressure than the pressure of the reaction stage.
  • US2017/0129776 describes a process for the production of high-quality syngas rich in hydrogen during the process of upgrading the residual hydrocarbon oil feedstock by rejuvenating the spent upgrading material in a reformer in absence of air/oxygen without supplying an external heat source other than the heat generated inside the process during combustion of residual coke deposited on the upgrading material.
  • US 4,207,167 describes a process in which a used hydrocarbon cracking catalyst having coke laydown thereon is regenerated under conditions to produce a gas rich in carbon monoxide which together with steam is subject to a shift reaction to produce carbon dioxide and hydrogen.
  • the present disclosure offers a novel integration of adsorptive water-gas shift reactor for the co-production of H2 and removal of CO2 and CO from FCC regenerator of flue gas of an FCC unit operated in a partial combustion mode.
  • the present disclosure provides for the integration of a combined water-gas-shift and adsorption process with an FCC unit.
  • the disclosure relates to a process to produce two separate streams containing respectively carbon dioxide (CO2) and hydrogen (H2) from the stream of flue gas of a fluid catalytic cracking (FCC) regenerator, said process is remarkable in that it comprises the following steps: a) providing a fluid catalytic cracking unit (FCC unit) operated in partial combustion mode and having a fluid catalytic cracking regenerator (FCC regenerator) operated at a temperature ranging from 650 to 850°C, and at a pressure ranging from 0.1 MPa to 0.4 MPa; b) recovering, from said fluid catalytic cracking regenerator, a stream of flue gas comprising at least 5 mol. % to at most 25 mol.
  • FCC unit fluid catalytic cracking unit operated in partial combustion mode and having a fluid catalytic cracking regenerator (FCC regenerator) operated at a temperature ranging from 650 to 850°C, and at a pressure ranging from 0.1 MPa to 0.4 MPa
  • FCC regenerator fluid catalytic
  • step (b) compressing the stream of flue gas obtained at step (b) or step (c) to provide a gas mixture, wherein the compression is conducted to obtain a stream of flue gas having a pressure of at least 0.4 MPa and a temperature ranging from 30 to 450°C; e) subjecting the gas mixture obtained at step (d) to a water-gas shift reaction to convert the carbon monoxide into carbon dioxide and hydrogen on a catalyst with the adsorption of carbon dioxide on an adsorbent at a pressure ranging from 0.4 to 8.0 MPa and recovering a hydrogen-rich stream containing at least 1 mol.
  • step (e) regenerating said adsorbent of step (e) with a pressure less than half of the pressure of step (e) to obtain a carbon dioxide -stream containing at least 50 mol. % of carbon dioxide based on the total molar content of the stream on a dry basis.
  • the process allows achieving high carbon capture ratios from the stream of flue gas of a fluid catalytic cracking (FCC) regenerator, wherein the CO2 captured is originated from both original CO2 and the CO2 generated from CO-shift while producing a hydrogen-rich stream suitable for combustion processes since said hydrogen-rich stream is having high pressure and high temperature with low content of CO2.
  • a CC>2-stream is also recovered and is suitable for storing and/or further utilization.
  • the application of the present disclosure to an FCC flue gas containing CO is “blue” concerning hydrogen production as the CO2 is captured from the process (“blue” concerning hydrogen means that hydrogen for which the CO2 emitted during its production is captured and stored or reused). Additionally, conversion and separation of H2 and CO2 are performed in a single step with a steam consumption that is lower than prior state- of-art technologies for H2 production with CO2 capture.
  • steps (b) to (e) can be integrated into an existing FCC unit.
  • any FCC unit which is already present in a refinery may perform the process of the present disclosure.
  • the process further comprises a step (g) of using the hydrogen-rich stream recovered at step (e) in the production of chemicals; for example, in the production of methane, methanol, higher hydrocarbons, ammonia and/or alcohols or for combustion processes.
  • the process further comprises a step (h) of using the CC>2-stream recovered at step (f) in the production of chemicals; for example, in the production of methane, methanol, higher hydrocarbons and/or alcohols.
  • the CC>2-stream recovered at step (f) is stored.
  • the regenerator of the FCC unit is operated at a temperature ranging from 680°C to 800°C; preferably, from 710°C to 750°C.
  • the regenerator of the FCC unit is operated at a pressure ranging from 0.14 MPa to 0.32 MPa; preferably from 0.18 MPa to 0.23 MPa.
  • the partial combustion mode of the fluid catalytic cracking unit of step (a) is carried out by operating in an excess of carbon monoxide, and/or a CO/O2 molar ratio superior to 1.0, preferably superior to 1.5, more preferably superior to 2.0.
  • the fluid catalytic cracking regenerator is supplied by a regeneration gas, preferably by air or by an oxygen-enriched gas.
  • said oxygen-enriched gas has an oxygen content ranging between at least 10 and less than 60 vol.% based on the total volume of said oxygen-enriched gas, preferably between 15 and 55 vol.%, more preferably between 20 and 50 vol.%, even more preferably between 25 and 45 vol.%; and/or is produced within an air separation unit (ASU).
  • ASU air separation unit
  • carbon monoxide is added to said oxygen-enriched gas and said oxygen-enriched gas has a carbon monoxide content ranging between 1 vol.% and 25 vol.% based on the total volume of said oxygen-enriched gas, preferably between 5 vol.% and 20 vol.%.
  • the stream of flue gas recovered in step (b) further comprises one or more components selected from the group comprising H2, H2S, N2, H2O, SO x , HCN, COS, CS2, NO x and HCI.
  • the stream of flue gas recovered in step (b) comprises from 1 to 10 mol. % of carbon monoxide (CO) based on the total molar content of the stream, preferably from 3 to 9 mol. %, more preferably from 5 to 8 mol. %.
  • CO carbon monoxide
  • the stream of flue gas recovered in step (b) comprises from 5 to 25 mol. % or from 8 to 25 mol. % of carbon dioxide (CO2) based on the total molar content of the stream, preferably from 10 to 22 mol. %, more preferably from 15 to 20 mol. %.
  • CO2 carbon dioxide
  • the stream of flue gas recovered in step (b) comprises from 0 to 5 mol. % of hydrogen (H2) based on the total molar content of the stream, preferably from 0.25 to 4.5 mol. %, more preferably from 0.5 to 4 mol. %.
  • the stream of flue gas recovered in step (b) comprises hydrogen sulfide (H2S) at a concentration of less than 5 mol. % based on the total molar content of the stream, preferably less than 4 mol. %, more preferably less than 3 mol. %.
  • H2S hydrogen sulfide
  • the stream of flue gas recovered in step (b) comprises from 10 to 80 mol. % of dinitrogen (N2) based on the total molar content of the stream, preferably from 15 to 75 mol. %, more preferably from 20 to 70 mol. %, even more preferably from 25 to 65 mol. %.
  • the stream of flue gas recovered in step (b) comprises from 0.1 to 50 mol. % of water (H2O) based on the total molar content of the stream, preferably from 1 to 45 mol. %, more preferably from 5 to 40 mol. %.
  • the molar ratio of H2O to CO in the stream of flue gas recovered in step (b) is ranging from 0.1 to 5.0, preferably from 0.5 to 1.2, even more preferably from 0.8 to 1.0.
  • the pressure is reduced to 0.1 MPa, preferably to 0.01 MPa.
  • step (c) is followed by a step of recovering heat, in the form of steam, in a waste heat recovery sub-unit by reducing the temperature of the stream of flue gas to a temperature in the range of 150 to 350°C.
  • step (c) is followed by a step of removing impurities, such as SO x , NO x and dust particles, from said stream of flue gas.
  • impurities such as SO x , NO x and dust particles
  • Step (d) is carried out at a pressure of at least 0.5 MPa, preferably of at least 0.8 MPa, more preferably of at least 1.0 MPa, even more preferably of at least 1.5 MPa or at least 2.0 MPa.
  • step (d) is carried out at a pressure of at most 5.0 MPa.
  • step (d) is carried out at a temperature ranging between 40°C and 430°C, preferably between 50°C and 350°C, more preferably between 60°C and 150°C.
  • step (d) is adiabatic or the compression of step (d) produces heat that is recovered in one or more intercoolers.
  • the content of the gas mixture obtained in step (d) is adapted before being subjected to step (e) so that the molar ratio of H2O to CO is ranging from 1 to 5.
  • the temperature of the gas mixture obtained in step (d) is adapted before being subjected to step (e) so that the temperature is between 200 to 500 °C.
  • Said water-gas shift reaction and/or said adsorption of CO2 on an adsorbent is carried out at a temperature above 200°C, preferably ranging from 200 to 500°C, more preferably from 300 to 500°C, most preferably from 350 to 450°C.
  • step (e) The catalyst and the adsorbent of step (e) are part of the same material or are different materials loaded in the same reactor.
  • the hydrogen-rich stream obtained at step e) comprises from 1 to 20 mol.% of H2 based on the total molar content of the stream on a dry basis, preferably from 3 to 17 mol.%, more preferably from 5 to 15 mol.%.
  • the adsorbent used in step (e) is or comprises an inorganic oxide comprising one or more trivalent metal oxides; with preference: said one or more trivalent metal oxides are one or more trivalent metal hydroxides and/or one or more trivalent metal carbonates; and/or one or more trivalent metal oxides have a metal selected from one or more of Al, Fe, Mn, Cr, Ti and Zn; more preferably the metal of said one or more trivalent metal oxides is Al.
  • the adsorbent used in step (e) is or comprises an inorganic oxide comprising one or more trivalent metal oxides and further comprising one or more alkali metals oxides, hydroxides and/or carbonates; with preference: said one or more alkali metals are one or more selected from Li, Na, K, Rb and Cs; preferably selected from Na and K; the molar ratio of alkali metal to the metal of said one or more trivalent metal oxides is ranging between 0.10 and 1.00, preferably between 0.20 and 0.90, more preferably between 0.25 and 0.75.
  • the adsorbent used in step (e) is or comprises an inorganic oxide comprising one or more trivalent metal oxides and further comprising one or more divalent metals oxides, hydroxides and/or carbonates; with preference: said one or more divalent metals are one or more selected from Mg, Ca, Sr, Ba, Co, Ni, Cu, Zn, Cd and Pb; more preferably selected from Mg, Ca and Zn.
  • the molar ratio of divalent metals to the metal of said one or more trivalent metal oxides is ranging between 0.25 and 1.50, more preferably between 0.30 and 1.25, even more preferably between 0.40 and 1.00.
  • the adsorbent used in step (e) is or comprises an inorganic oxide comprising one or more trivalent metal oxides with aluminium as the metal of said one or more trivalent metal oxides, said inorganic oxide further comprising one or more alkali metals, with preference one or more alkali metals selected from Na and K, and the molar ratio of said one or more alkali metals to the metal of said one or more trivalent metal oxides is ranging between 0.1 and 1.0, preferably between 0.20 and 0.90, more preferably between 0.25 and 0.75.
  • the adsorbent used in step (e) is or comprises an inorganic oxide comprising one or more trivalent metal oxides with aluminium as the metal of said one or more trivalent metal oxides, said inorganic oxide further comprising one or more divalent metals, with preference one or more divalent metals selected from Mg, Ca and Zn, and the molar ratio of said one or more divalent metals to the metal of said one or more trivalent metal oxides is ranging between 0.25 and 1.50, preferably between 0.30 and 1.25, more preferably between 0.40 and 1.00.
  • the adsorbent used in step (e) is or comprises an inorganic oxide comprising one or more trivalent metal oxides with aluminium and zinc as metals of said one or more trivalent metal oxides, the molar ratio of zinc to aluminium is ranging between 0.02 to 4.00, preferably between 0.05 to 1.50.
  • the adsorbent used in step (e) is or comprises an inorganic oxide comprising one or more trivalent metal oxides with aluminium and zinc as metals of said one or more trivalent metal oxides, said inorganic oxide further comprising one or more divalent metals, with preference one or more divalent metals selected from Mg, Ca and Zn; the molar ratio of said one or more divalent metals to the metals of said trivalent metal oxides is ranging between 0.25 and 1.50, preferably between 0.30 and 1.25, more preferably between 0.40 and 1.00; the molar ratio of zinc to aluminium is ranging between 0.02 to 4.00, preferably between 0.05 to 1.50.
  • the adsorbent used in step (e) is or comprises an inorganic oxide comprising one or more trivalent metal oxides with aluminium and zinc as metals of said one or more trivalent metal oxides, said inorganic oxide further comprising divalent metals being Mg, Ca and Zn; the molar ratio of said divalent metals to the metals of said trivalent metal oxides is ranging between 0.25 and 1.50, preferably between 0.30 and 1.25, more preferably between 0.40 and 1.00; and/or the molar ratio of zinc to aluminium is ranging between 0.02 to 4.00, preferably between 0.05 to 1.50.
  • the adsorbent used in step (e) is or comprises an inorganic oxide comprising one or more trivalent metal oxides with aluminium as the metal of said one or more trivalent metal oxides, said inorganic oxide further comprising one divalent metal being Mg, and the molar ratio of said divalent metal to the content of aluminium and magnesium is ranging between 0.05 and 0.95, preferably between 0.10 and 0.80, more preferably between 0.20 and 0.60.
  • the adsorbent used in step (e) is or comprises an inorganic oxide represented by the chemical formula
  • M' is one or more alkali metals selected from Li, Na, K, Rb and Cs; preferably selected from Na and K;
  • M" is one or more divalent metals selected from Ca, Sr, Ba, Co, Ni, Cu, Zn, Cd and Pb; preferably selected from Ca, Sr, Ba, Ni, Cu, and Zn; more preferably selected from Ni, Cu and Zn; even more preferably from Zn; M m is one or more trivalent metals selected from Fe, Mn, Cr, Ti and Zr;
  • the adsorbent used in step (e) is or comprises an inorganic oxide represented by the chemical formula
  • M' is one or more alkali metals selected from Li, Na, K, Rb and Cs; preferably selected from Na and K;
  • M" is one or more divalent metals selected from Mg, Mn, Cu, Co, Fe, Cd and Cr;
  • M m is optionally one or more trivalent metals selected from Fe, Cr and Mn;
  • step (f) the adsorbent of step (e) is rinsed with a rinsing gas comprising steam or nitrogen or a combination thereof to avoid the contamination of the hydrogen-rich stream with carbon monoxide (CO) or hydrogen sulfide (H 2 S).
  • a rinsing gas comprising steam or nitrogen or a combination thereof to avoid the contamination of the hydrogen-rich stream with carbon monoxide (CO) or hydrogen sulfide (H 2 S).
  • step (f) the adsorbent of step (e) is rinsed with a rinsing gas comprising water or carbon dioxide or a combination thereof to avoid the contamination of the hydrogen- rich stream with carbon monoxide (CO) or hydrogen sulfide (H2S).
  • step (f) comprises subjecting the adsorbent of step (e) to a purging gas comprising steam.
  • step (f) comprises the step of feeding water to the said adsorbent.
  • step (f) is carried out at a pressure ranging between 0.001 and 0.4 MPa.
  • step (f) is carried out at a pressure less than 2/3 of the pressure of step (e).
  • step (f) is carried out with steam.
  • step (f) is performed firstly by reducing the pressure and secondly by injecting a gas comprising at least 50 mol. % of steam based on the total molar content of said gas, preferably at least 75 mol. %, more preferably at least 80 mol. %, even more preferably at least 90 mol. %, wherein the remaining part of the gas is preferably one or more diluent gas, such as dinitrogen, argon and/or helium, preferably dinitrogen.
  • a gas comprising at least 50 mol. % of steam based on the total molar content of said gas, preferably at least 75 mol. %, more preferably at least 80 mol. %, even more preferably at least 90 mol. %, wherein the remaining part of the gas is preferably one or more diluent gas, such as dinitrogen, argon and/or helium, preferably dinitrogen.
  • step (f) is performed firstly by reducing the pressure and secondly by injecting a gas comprising at most 100 mol. % of steam.
  • the carbon dioxide-stream obtained at step (f) comprises from 60 to 100 mol. % of CO2 based on the total molar content of the stream on a dry basis, preferably from 60 to 95 mol.% or 65 to 95 mol. %.
  • the carbon dioxide-stream obtained at step (f) comprises at least 65 mol. % CO2 based on the total molar content of the stream on a dry basis, preferably at least 68 mol. % CO2 based on the total molar content of the stream on a dry basis.
  • the carbon dioxide-stream obtained at step (f) comprises at most 98 mol. % CO2 based on the total molar content of the stream on a dry basis, preferably at most 95 mol. % CO2 based on the total molar content of the stream on a dry basis.
  • step (f) comprises a step of feeding water to the catalyst and a step of feeding water to the adsorbent wherein both steps are performed simultaneously.
  • the process further comprises a step (i) of recovering a fluid catalytic cracking catalyst exiting said fluid catalytic cracking regenerator, wherein the fluid catalytic cracking catalyst has a carbon content of at least 1 wt.% based on the total weight content of said fluid catalytic cracking catalyst as measured according to the UOP Method 961 , preferably of at least 2 wt.%, more preferably of at least 5 wt.%.
  • the fluid catalytic cracking catalyst has a carbon content ranging between 5 wt.% and 50 wt.% based on the total weight content of said fluid catalytic cracking catalyst as measured according to the UOP Method 961.
  • the process of the first aspect is conducted in an installation according to the second aspect.
  • the disclosure relates to an installation to perform a process to produce two separate streams containing respectively carbon dioxide (CO2) and hydrogen (H2) from the stream of flue gas of a fluid catalytic cracking regenerator according to the first aspect, said installation is remarkable in that it comprises
  • a fluid catalytic cracking unit comprising a fluid catalytic cracking regenerator
  • the fluid catalytic cracking unit, the compressing unit and the water-gas shift unit are fluidically connected in series; the compressing unit being downstream of said fluid catalytic cracking unit and upstream to said water-gas shift unit; and wherein the water-gas shift unit comprises a water-gas shift reactor and a CC>2-adsorption bed.
  • the catalyst and the adsorbent of step (e) are part of the same material or are different materials loaded in the same reactor.
  • the CC>2-adsorption bed is comprised within said water-gas shift reactor.
  • the water-gas shift unit is a multiple-bed unit, advantageously comprising at least two water-gas shift reactors in series or in parallel, preferably at least three water-gas shift reactors in series or in parallel, more preferably at least four water-gas shift reactors in series or in parallel. This ensures that the process is operated continuously.
  • the multiple-bed unit comprises a single regeneration gas split over the reactors to be regenerated and/or a single loading gas split over the reactors to be loaded.
  • the process further comprises the step (j) of feeding water into at least one of said multiple reactor beds, said step (j) preferably coinciding with or following said regeneration stage (f).
  • said step (j) is performed at a pressure of less than 2/3 of the pressure of step (e).
  • said step (f) and/or said step (j) are performed simultaneously in at least two of said reactor beds in series or in parallel, while said step (e) is performed at the same time in at least one other of said multiple beds run in series or in parallel.
  • said installation further comprises a cooling unit downstream of said fluid catalytic cracking unit, the cooling unit comprising a turbo-expander and/or a waste heat recovery sub-unit.
  • said installation further comprises a gas pre-treatment unit disposed upstream of the compressing unit.
  • the cooling unit is upstream of said gas pre-treatment unit.
  • said installation further comprises an air separation unit upstream of said fluid catalytic cracking unit.
  • wt.% refers to a weight, volume, or molar percentage of a component, respectively, based on the total weight, the total volume of material, or total moles, that includes the component.
  • 10 grams of a component in 100 grams of the material is 10 wt. % of components.
  • ASU Air Separation Unit
  • WGS Water-Gas Shift.
  • FCC Fluid Catalytic Cracking
  • Figure 1 describes a simplified scheme of an FCC unit.
  • the air used in the regeneration section is enriched with O2 with the help of an air separation unit.
  • Figure 2 describes a possible configuration of the process and installation according to the disclosure.
  • Figure 3 describes a configuration of the process according to example 1.
  • Figure 4 describes a configuration of the process according to example 2.
  • Figure 5 describes a comparative example not according to the present disclosure where the flue gas exiting the FCC regenerator is sent to a CO-boiler instead of an adsorptive water-gas shift reactor according to example 1 and example 2.
  • the disclosure relates to a process to produce two separate streams containing respectively carbon dioxide and hydrogen from the stream of flue gas of a fluid catalytic cracking regenerator 7, the process is remarkable in that it comprises the following steps: a) providing a fluid catalytic cracking unit 1 operated in partial combustion mode and having a fluid catalytic cracking regenerator 7 operated at a temperature ranging from 650 to 850°C and at a pressure ranging from 0.1 to 0.4 MPa; b) recovering, from said fluid catalytic cracking regenerator 7, a stream of flue gas comprising at least 5 mol. % to at most 25 mol. % of carbon dioxide based on the total molar content of the stream, and at least 1 mol. % to at most 20 mol.
  • step (b) optionally reducing the pressure from said stream of flue gas in a turbo-expander to recover electricity; d) compressing the stream of flue gas obtained at step (b) or step (c) to provide a gas mixture, wherein the compression is conducted to obtain a stream of flue gas having a pressure of at least 0.4 MPa and a temperature ranging from 30 to 450°C; e) subjecting the gas mixture obtained at step (d) to a water-gas shift reaction to convert the carbon monoxide into carbon dioxide and hydrogen on a catalyst with the adsorption of carbon dioxide on an adsorbent at a pressure ranging from 0.4 to 8.0 MPa and recovering a hydrogen-rich stream containing at least 1 mol.
  • step (e) regenerating said adsorbent of step (e) with a pressure less than half of the pressure of step (e) to obtain a carbon dioxide- stream containing at least 50 mol. % of carbon dioxide based on the total molar content of the stream on a dry basis.
  • a fluid catalytic cracking unit 1 comprising a fluid catalytic cracking regenerator 7;
  • the fluid catalytic cracking unit 1 , the compressing unit 31 and the water-gas shift unit are fluidically connected in series; the compressing unit 31 being downstream of said fluid catalytic cracking unit 1 and upstream to said water-gas shift unit; and wherein the water-gas shift unit comprises a water-gas shift reactor 35 and a carbon dioxide -adsorption bed.
  • said installation further comprises a cooling unit downstream of said fluid catalytic cracking unit, the cooling unit comprising a turbo-expander and/or a waste heat recovery sub unit 27; and/or in that said installation further comprises a gas pre-treatment unit 29 disposed upstream of the compressing unit 31.
  • FIG 1 wherein a simplified FCC unit 1 according to the disclosure is provided.
  • the feed of the FCC unit 1 is charged via line 3 to riser reactor 5.
  • Hot regenerated catalyst removed from the FCC regenerator 7 via line 9 vaporizes fresh feed in the base of the riser reactor 5, and cracks the feed.
  • Cracked products and spent catalyst are discharged into the vessel of the FCC reactor 11 and separated.
  • Spent catalyst is stripped in a stripping means not shown in the base of the vessel of the FCC reactor 11 , then stripped catalyst is charged via line 13 to the FCC regenerator 7.
  • Cracked products are removed from the vessel of the FCC reactor 11 via line 15 and charged to an FCC main column (not shown).
  • Spent catalyst is maintained as a bubbling, dense phase fluidized bed in the vessel of the FCC regenerator 7.
  • Regeneration gas preferably air, sometimes air enriched with oxygen or oxygen-enriched gas, is added via line 17 to the base of the vessel of the FCC regenerator 7. Airflow is controlled by flow control valve 19.
  • the regenerated catalyst is removed via line 9 and recycled to the base of the riser reactor 5.
  • Flue gas 21 is removed from the FCC regenerator 7 via a line.
  • the flue gas 21 contains a mixture of CO and CO2 that are further separated and converted according to the process of the disclosure.
  • FIG 2 a possible configuration of the process and installation according to the disclosure is illustrated, wherein air or oxygen-enriched gas, preferably supplied by an air separation unit 25 (ASU), is used to burn the coke on the FCC catalyst in the FCC regenerator 7.
  • the FCC unit 1 is operated in partial combustion mode meaning that the quantity of O2 is not sufficient to transform all the coke into CO2.
  • the partial combustion mode of the fluid catalytic cracking unit 1 is operated with an excess of carbon monoxide, and/or with a CO/O2 molar ratio superior to 1.0, preferably superior to 1.5, more preferably superior to 2.0.
  • the oxygen-enriched gas preferably added via line 17 to the fluid catalytic cracking regenerator 7, has an oxygen content ranging between at least 10 and less than 60 vol.% based on the total volume of said oxygen-enriched gas, preferably between 15 and 55 vol.%, more preferably between 20 and 50 vol.%, even more preferably between 25 and 45 vol.%.
  • carbon monoxide can be added to said oxygen-enriched gas to be at a concentration ranging from 1 vol. % to 25 vol. %, preferably from 5 vol.% to 20 vol.%. Partial combustion is done so that part of the coke is converted into CO. This combustion leads to heat production.
  • Stream A of flue gas 21 exiting the FCC regenerator 7 is cooled down in a cooling unit comprising a turbo-expander (not shown) and/or waste heat recovery (WHR) sub unit 27.
  • This energy recovery leads to the formation of electricity and/or steam that can be exported, used in the adsorptive water-gas shift reactor 35 or used to drive the flue gas compressor.
  • the stream then enters a gas pre-treatment unit 29 to remove, if required by downstream processes, contaminants such as SO x , NO x and dust particles.
  • the stream is then compressed in a compressor within the compressing unit 31 to be used in the adsorptive water- gas shift (WGS) reactor 35.
  • WHS waste heat recovery
  • the temperature of the feed gas can be adjusted to the optimal conditions for the shift and CO2 adsorption step in a heat exchanger 33 and the H2O: CO ratio can be fine-tuned by the addition of steam 41.
  • the stream enters then the adsorptive WGS reactor 35 where CO and H2O are shifted into H2 and CO2.
  • CO2 is simultaneously trapped in the adsorption bed of the adsorptive WGS reactor 35.
  • the CO2 is desorbed with the help of steam or nitrogen to form a carbon dioxide-rich stream (I) and heat can be recovered in a heat exchanger 37.
  • H2 is produced in a separated stream at high temperature so that a hydrogen-rich stream (H) is produced wherein heat can be recovered in a heat exchanger 39.
  • the overall process and/or installation are remarkable in that heat and electricity recovery is maximized.
  • the overall process is particularly energy- efficient. Heat and electricity are recovered whenever it is possible.
  • the produced H2- containing gas is suitable for combustion processes with low emissions or as feedstock for chemical processes.
  • the exhaust gas (stream A) exiting the FCC regenerator 7 of an FCC unit 1 operated in partial combustion mode is sent via a line to a waste heat recovery (WHR) sub-unit 27, the temperature of the exhaust gas may be reduced to 200-350°C with water (stream B) charged via a line and the heat is utilized to produce steam (stream C) which is recovered via another line.
  • WHR waste heat recovery
  • the cooled exhaust gas (stream D) is sent via a line to the gas pre-treatment unit (29) where contaminants such as SOx, NOx and dust particles are removed and the temperature and/or the pressure of the exhaust gas (stream E) is adjusted before being charged via a line into the adsorptive water-gas shift reactor 35, where CO and H2O are shifted to H2 and CO2, and the CO2 is separated.
  • Rinse steam (stream F) and purge steam (stream G) are charged via separated lines, and Fh-rich stream (stream H) and C0 2 -rich stream (stream I) produced are recovered in separated lines.
  • FIG 4 a simplified scheme is used to illustrate the methods and apparatus to recover energy in the form of steam from the product streams of the adsorptive water-gas shift reactor.
  • the H2-rich stream H discharged is sent for combustion in a gas boiler 45, wherein air (stream J) is supplied and wherein the steam (stream K) produced is recovered.
  • the C0 2 -rich stream (stream I) discharged is cooled in a waste heat recovery (WHR) sub-unit 27 and the heat is recovered and used to pre-heat boiler feed water (stream L) charged.
  • Stack gas (stream N) is recovered.
  • FIG 5 a simplified scheme not according to the present disclosure to recover energy from the exhaust gas exiting the FCC regenerator 7 of an FCC unit 1 operated in partial combustion mode is provided.
  • the exhaust gas feed (stream A) from the FCC regenerator 7 is charged into a CO-boiler 49, where the gas is combusted with a supplementary fuel gas (stream M) charged and air (stream J) supplied, and steam (stream K) produced from the boiler feed water (stream L) supplied is recovered.
  • Stack gas (stream N) is recovered.
  • the present disclosure relates to a process and installation used for CO2 removal and co production of H2 downstream of an FCC regenerator 7 of an FCC unit 1 operated in a partial combustion mode.
  • the FCC regenerator flue gas 21 (or stream A) is treated in an adsorptive WGS reactor 35, whereby CO and H2O are converted into H2 and CO2 and the reaction products, together with the original CO2, are simultaneously recovered in separated streams.
  • each mole of carbon monoxide produces approximately one mole of hydrogen and one mole of carbon dioxide.
  • the hydrogen-rich stream H produced has a hydrogen concentration ranging from 1 to approximately 15 mol.% based on the total molar content of the stream on a dry basis.
  • the carbon dioxide-rich stream I produced is in a form suitable for storage or utilization. The present disclosure can advantageously treat from 10 to 1000 t/h of flue gas 21.
  • the regenerator 7 of the FCC unit 1 in step (a) is operated at a temperature ranging from 680°C to 800°C; preferably, from 710°C to 750°C.
  • the regenerator 7 of the FCC unit 1 in step (a) is operated at a pressure ranging from 0.14 MPa to 0.32 MPa; preferably from 0.18 MPa to 0.23 MPa.
  • the partial combustion mode of the fluid catalytic cracking unit 1 of step (a) is carried out by operating in an excess of carbon monoxide, and/or a CO/O2 molar ratio superior to 1.0, preferably superior to 1.5, more preferably superior to 2.0.
  • the fluid catalytic cracking regenerator 7 is supplied by a regeneration gas, preferably by air or by an oxygen-enriched gas.
  • said oxygen-enriched gas has an oxygen content ranging between at least 10 and less than 60 vol.% based on the total volume of said oxygen-enriched gas, preferably between 15 and 55 vol.%, more preferably between 20 and 50 vol.%, even more preferably between 25 and 45 vol.%; and/or is produced within an air separation unit (ASU).
  • ASU air separation unit
  • carbon monoxide is added to said oxygen-enriched gas and said oxygen-enriched gas has a carbon monoxide content ranging between 1 vol.% and 25 vol.% based on the total volume of said oxygen-enriched gas, or between 5 vol.% and 25 vol.%.
  • a preferred dry feed gas composition for the process of the disclosure is a stream (A) of flue gas which comprises one or more selected from: one or more components selected from the group comprising H2, H2S, N2, H2O, SO x , HCN, COS, CS 2 , NO x and HCI. from 1 to 10 mol. % of carbon monoxide (CO) based on the total molar content of the stream, preferably from 3 to 9 mol. %, more preferably from 5 to 8 mol. %. from 5 to 25 mol. % or from 8 to 25 mol. % of carbon dioxide (CO2) based on the total molar content of the stream, preferably from 10 to 22 mol. %, more preferably from 15 to 20 mol.
  • CO carbon monoxide
  • CO2 carbon dioxide
  • %. from 0 to 5 mol. % of hydrogen (H2) based on the total molar content of the stream, preferably from 0.25 to 4.5 mol. %, more preferably from 0.5 to 4 mol. %. comprises hydrogen sulfide (H2S) at a concentration of less than 5 mol. % based on the total molar content of the stream, preferably less than 4 mol. %, more preferably less than 3 mol. %. from 10 to 80 mol. % of dinitrogen (N2) based on the total molar content of the stream, preferably from 15 to 75 mol. %, more preferably from 20 to 70 mol. %, even more preferably from 25 to 65 mol. %.
  • H2S hydrogen sulfide
  • H2O water
  • the remainder may be minor components such as H S and inert gases such as N and trace components.
  • the molar ratio of H O to CO in the stream of flue gas recovered in step (b) is ranging from 0.1 to 5.0, preferably from 0.5 to 1.2, even more preferably from 0.8 to 1.0.
  • the molar ratio of H O to CO in the feed gas mixture has a molar ratio of H O to CO of up to 1.2, exceptionally up to about 2, or up to 5.
  • An advantage of the present disclosure is that the flue gas of FCC regenerator 7 often contains appreciable levels of residual steam that can be used in the shift reactor, saving on expensive high-pressure steam.
  • a step (c) of reducing the pressure from said stream of flue gas in a turbo-expander to recover electricity can be optionally carried out.
  • the pressure is reduced to 0.1 MPa, preferably to 0.01 MPa.
  • step (c) is followed by a step of recovering heat, in the form of steam, in a waste heat recovery sub-unit by reducing the temperature of the stream of flue gas to a temperature in the range of 150 to 350°C.
  • step (c) is followed by a step of removing impurities from said stream (A) of flue gas 21 , such as SO x , NO x and dust particles, from said stream of flue gas.
  • the step (d) of compressing the stream of flue gas obtained at step (b) or step (c) may be carried out at a pressure of at least 0.5 MPa, preferably of at least 0.8 MPa, more preferably of at least 1.0 MPa, even more preferably of at least 1.5 MPa or at least 2.0 MPa. For example, it is carried out at a pressure of at most 5.0 MPa.
  • the step (d) is carried out at a temperature ranging between 40°C and 430°C, preferably between 50°C and 350°C, more preferably between 60°C and 150°C.
  • the compression of step (d) is adiabatic or the compression of step (d) produces heat that is recovered in one or more intercoolers.
  • the content of the gas mixture obtained in step (d) is adapted before being subjected to step (e) so that the molar ratio of H O to CO is ranging from 1 to 5.
  • the temperature of the gas mixture obtained in step (d) is adapted before being subjected to step (e) so that the temperature is between 200 to 500 °C.
  • the reaction stage of said step (e) and/or the adsorption of carbon dioxide on an adsorbent can be performed under various conditions of temperature and pressure and the like.
  • the reaction stage and/or the adsorption of carbon dioxide on an adsorbent is performed at an average reactor temperature above 200°C, preferably ranging from 200 to 500°C, more preferably between 300 and 500°C, most preferably between 350 and 450°C.
  • the pressure can be atmospheric but is preferably super-atmospheric, in particular above 0.4 MPa, more preferably above 1.0 MPa, even more preferably above 1.5 MPa, up to e.g. 8.0 MPa, preferably up to 5.0 MPa, most preferably up to 4.0 MPa, e.g. from 2.0 to 3.0 MPa.
  • said water-gas shift reaction comprises the step of feeding water to the said catalyst.
  • the water-gas shift reaction and said adsorption of CO2 on an adsorbent are simultaneous.
  • the water-gas shift reaction and said adsorption of CO2 on an adsorbent are performed in the same reactor.
  • catalyst and the adsorbent of step (e) are part of the same material or are different materials loaded in the same reactor.
  • the hydrogen-rich stream (H) obtained at step e) comprises from 1 to 20 mol.% of H2 based on the total molar content of the stream on a dry basis, preferably from 3 to 17 mol.%, more preferably from 5 to 15 mol.%.
  • the gas mixture to be fed is preferably prepared by removing contaminants such as SO x , NO x and dust particles, and adjusting the pressure and temperature for downstream processes.
  • a possible configuration may comprise up to four systems:
  • a waste-heat recovery sub-unit or a turbo-expander or a combination of both may be used to decrease the temperature by recovering thermal and electrical energy before the gas cleaning step at a lower temperature.
  • a turbo-expander usually comprises four parts: the expander, a motor/generator, an air blower, and a steam turbine.
  • the steam turbine is primarily used for start-up and often to supplement the expander to generate electricity.
  • the motor/generator works as a speed controller and flywheel; it can produce or consume power. In some FCC units, the expander horsepower exceeds the power needed to drive the air blower and the excess power is output to the refinery electrical system.
  • the motor/generator provides the power to hold the power train at the desired speed.
  • the flue gas at the expander outlet could be sent to a waste-heat boiler to recover residual heat and generate steam.
  • a typical wet gas treatment system could comprise an electrostatic precipitator at 250°C, followed by a catalytic DeNO x scrubbing at 250°C with an injection of ammonia solution (NH 4 OH) 25 wt.% and then DeSO x scrubbing at 50°C with an injection of caustic soda.
  • a typical dry gas treatment system could comprise on a dry DeSO x reactor using sodium bicarbonate (NaHCCh) at 200°C, followed by an electrostatic precipitator at 200°C and then catalytic DeNO x scrubbing at 200°C with an injection of ammonia solution (NhUOH).
  • a flue gas compression system and/or 4) one or more intercoolers adjust the pressure and/or the temperature to the optimal conditions for the sorption-enhanced water-gas shift step. Steam may also be added to fine-tune the steam to CO ratio.
  • the temperature of the flue gas increases.
  • the presence of one or more intercoolers allows cooling the compressed flue gas. The heat can then be recovered from said intercoolers.
  • the compression of the stream of flue gas is adiabatic.
  • SEWGS Supplemental Enhanced Water-Gas Shift
  • the composition of the regeneration gas obtained at step (f) depends on the gas used during the regeneration of the adsorbent i.e. during the desorption of the CO2 adsorbed on the adsorbent.
  • Regeneration can be done using a gas that is low in steam, such as nitrogen, air.
  • regeneration is preferably done with a gas that is rich in steam.
  • the gas used for the regeneration contains sufficient steam to load the adsorbent with water under the process conditions.
  • the concentration of CO2 should be sufficiently low to effectively remove CO2 from the adsorbent.
  • the level of CO2 is preferably less than 2 vol.%, more preferably less than 0.5 vol.%, most preferably less than 0.1 vol.% (1000 ppm) in the gas used for the regeneration.
  • the single- step regeneration gas process preferably comprises predominantly of water (steam) and/or nitrogen.
  • the level of steam is preferably at least 25 vol.%, preferably at least 50 vol.%, the remainder, if any, being non-acidic gases such as nitrogen, air, argon or the like.
  • the regeneration gas comprises at least 50 vol.% of steam together with nitrogen.
  • the regeneration and the loading of water on the adsorbent are performed consecutively, i.e. in separate steps, the regeneration gas can contain similar levels of CO2 as above, while the regeneration gas need not contain substantial levels of steam.
  • the regeneration gas in the case of a two-step regeneration process, largely comprises inert, non-acidic gases such as nitrogen, air, argon or the like, and preferably less than 50 vol.% of steam, more preferably less than 25 vol.% of steam.
  • the loading gas then preferably comprises predominantly of water (steam) and/or nitrogen.
  • the level of steam is preferably at least 25 vol.%, preferably at least 50 vol.%, the remainder, if any, being non-acidic (inert) gases such as nitrogen or the like.
  • the regeneration and loading stages are preferably performed at a lower pressure than the pressure of the reaction step (e) during which the CO is converted into CO2 and H2.
  • the pressure of the regeneration step is less than half of the reaction stage pressure, more preferably less than 1/3 thereof.
  • the regeneration stage pressure is at least 0.2 MPa, more preferably at least 0.5 MPa, and most preferably at least 1.0 MPa lower than the reaction stage pressure.
  • the pressure at the regeneration stage is preferably below 1.5 MPa, more preferably below 10 MPa, especially between 0.001 and 0.4 MPa, for example, 0.1 MPa.
  • an optional rinsing stage may be applied.
  • a rinsing gas comprising H2O and/or CO2 is then fed into the reactor.
  • a rinsing step allows full displacement of H2 product gas from the reactor before it is conditioned for the regeneration stage, to avoid H2 contamination of the CC>2-rich stream product or the presence of undesired levels of CO or other components such as CO2 or H2S in the hh-rich stream product.
  • Rinsing can be performed at essentially the reaction stage pressure of step (e), in which case steam is not an attractive rinsing gas from a cost point of view.
  • CO2 or nitrogen or air or mixtures CO2 and nitrogen or air can then advantageously be used.
  • no rinsing is performed before regeneration (purging) of the adsorbent bed.
  • rinsing may coincide with depressurization ("blowdown") of the reactor bed to the pressure of the regeneration and/or loading stage.
  • rinsing may be performed after depressurization; in which case it is feasible to use steam or mixtures of steam with CO2 or nitrogen as a rinsing gas since lower pressure steam is less expensive than high-pressure steam.
  • Re-pressurization between the loading stage and the subsequent reaction stage can be done using any gas, including feed gas and inert gases such as nitrogen.
  • the re pressurization gas may be fed co-current or counter-current compared to the feed direction of the feed gas into the bed.
  • the water-gas shift reaction of step (e) can be performed in multiple reactor beds, in series or parallel.
  • one or more beds can then be under reaction conditions, i.e. be productive, while one or more other beds are being regenerated and/or loaded at the same time, thus enhancing total efficiency.
  • the regeneration is kinetically hindered, meaning that an increased regeneration flow (and decreased time) does not lead to a proportional increase in the speed of regeneration.
  • a lower feed flow (with longer time) will be more efficient in regeneration, thus resulting in higher efficiency in terms of the total feed flow required per desorbed amount of CO2, i.e. required amount of steam per CO2.
  • regeneration (purging) and/or loading is performed on two or more reactor beds in parallel, using a single regeneration (and/or loading) gas split over the reactors to be regenerated (and/or loaded) thus saving on the amount of regeneration (and/or loading) gas to be used.
  • the optionally simultaneous reaction stage can then be performed in a single or two or more other beds. This allows an advantageous longer regeneration/loading phase than with separate regeneration/ loading of single reactor beds. For example, in a parallel set of four reactor beds, regeneration/loading can be performed consecutively over the first and second bed simultaneously, then over the second and third bed simultaneously, then third and fourth, then fourth and first, etc. while at least one of the other beds is in the production mode.
  • the 1 st , 2 nd and 3 rd bed, then the 2 nd , 3 rd and 4 th bed, etc. of a multiple bed reactor unit can be in the regeneration/loading mode, while the remaining beds are in production, taking into account depressurization and re-pressurization.
  • the water-gas shift reaction of step (e), in a preferred embodiment, pertains to a water- gas shift process using a water-gas shift reactor comprising multiple reactor beds, preferably three or more, more preferably four or more reactor beds, containing an adsorbent capable of adsorbing H2O and CO2.
  • the water-gas shift reaction of step (e) is performed on a feed gas comprising CO and H2O into at least one of said multiple reactor beds and wherein a product gas issuing from the reactor is collected.
  • a regeneration step (f) is performed wherein CO2 is removed from at least one of said multiple reactor beds.
  • a loading step (j) is performed during which H2O is fed into at least one of said multiple reactor beds.
  • This loading step (j) is preferably coinciding with or following said regeneration stage (f). More preferably said loading step (j) is performed at a pressure of less than 2/3 of the pressure of step (e).
  • said regeneration step (f) and/or said loading step (j) are performed simultaneously in at least two of said reactor beds in parallel, while said reaction step is performed at the same time in at least one other of said multiple beds run in parallel.
  • the regeneration and/or loading gas fed through said at least two reactor beds being regenerated and/or loaded may preferentially be a single gas flow divided over said two or more reactor beds.
  • the regeneration and loading stages are carried out simultaneously, i.e. as a single step, in said at least two reactor beds.
  • the feed gas mixture preferably has a molar ratio of H2O to CO of below 2, down to 0, more preferably below 1.2, most preferably the molar ratio of H2O to CO is of 1.
  • a molar ratio H2O to CO of 1 is particularly advantaging because it is the stoichiometric ratio. This stoichiometric ratio minimizes the steam consumption to its minimum, this implies limited needs for separation of an excess of steam and recycle.
  • the process with a molar ratio H2O to CO of 1 requires then less energy and fewer investments.
  • the further preferred process parameters, including temperatures, pressures, adsorbents, gas compositions as described herein with reference to the process of the disclosure can also preferably apply to the process of this multiple bed embodiment.
  • the adsorbent for shifting the WGS reaction towards hydrogen is a material that is capable of adsorbing both H2O and CO2 and preferably also H2S and other gaseous acidic components.
  • a suitable adsorbent comprises, for instance, alkali-promoted alumina.
  • the adsorbent to be used in the process of the disclosure is preferably an inorganic oxide, which comprises a trivalent metal oxide, in particular alumina, alumina oxide hydroxide or aluminum hydroxide.
  • a trivalent metal oxide in particular alumina, alumina oxide hydroxide or aluminum hydroxide.
  • aluminum hydroxide instead of or in addition to aluminum, other metals capable of adopting a trivalent state may be present, such as Fe, Mn, Cr, Ti and Zr.
  • the adsorbent furthermore comprises one or more alkali metal oxides, hydroxides and/or carbonates.
  • Any alkali metal can be used, including Li, Na, K, Rb and Cs.
  • Preferred alkali metals are Na and K.
  • the molar ratio of alkali metal to the metal of said one or more trivalent metal oxides is ranging between 0.10 and 1.00, preferably between 0.20 and 0.90, more preferably between 0.25 and 0.75.
  • the adsorbent may advantageously further comprise one or more divalent metal oxides, hydroxides and/or carbonates.
  • the divalent metals can be an alkaline earth metal (Mg, Ca, Sr, Ba) or Co, Ni, Cu, Zn, Cd, Pb.
  • Preferred divalent metals are Mg, Ca, Sr, Ba, Zn, Ni and Cu; more preferably selected from Mg, Ca and Zn.
  • the adsorbent comprises calcium oxide and/or magnesium oxide and/or zinc oxide.
  • the molar ratio of divalent metals to the metal of said one or more trivalent metal oxides is ranging between 0.25 and 1.50, more preferably between 0.30 and 1.25, even more preferably between 0.40 and 1.00.
  • the adsorbent comprises magnesium oxide (magnesia) and has a molar (atomic) Mg to Al+Mg ratio of between 0.05 and 0.95, more preferably between 0.1 and 0.8, most preferably between 0.2 and 0.6.
  • alumina, magnesia and the like these include the oxides, but also hydroxides and other equivalents of the oxides of aluminum, magnesium, respectively.
  • Magnesium is particularly preferred for feed gas mixtures containing significant amounts of sulphur-containing contaminants such as H2S, as further detailed below, since the magnesium- based adsorbents were found to be insensitive to the sulphur compounds.
  • Aluminas also containing alkali metals, possibly in addition to other metals and counterions, are referred to herein as "alkali-promoted aluminas".
  • Aluminas, also containing magnesium and/or other divalent metals, and also containing alkali metals, possibly with other metals and counterions, are referred to herein as "alkali-promoted hydrotalcites".
  • the aluminas may be used in a manner known per se, which may comprise admixing metals oxides and further additives with the alumina or hydrotalcite or other base material in a dry state or in a solution or in a slurry, and optionally drying and calcining the resulting mixture.
  • the alumina may be any form of alumina that can be rehydrated, in particular, which has a level of hydroxyl groups. Examples include gamma-alumina, boehmite, gibbsite, bayerite.
  • inorganic oxides which can be used as an adsorbent can be represented by the following chemical formula:
  • M 1 is one or more metals selected from Li, Na, K, Rb and Cs; preferably selected from Na and K;
  • M" is one or more metals selected from Ca, Sr, Ba, Co, Ni, Cu, Zn, Cd and Pb, preferably Ni, Cu, Zn; more preferably Zn;
  • M m is one or more metals selected from Fe, Mn, Cr, Ti and Zr;
  • x 0.05-1, preferably 0.05-0.95, more preferably 0.20-0.90;
  • a 0-1 , preferably 0.5-1 ;
  • b 0-1 preferably 0.25-1 , more preferably 0.5-1 ;
  • the adsorbent used in step (e) is or comprises an inorganic oxide represented by the chemical formula
  • M' is one or more alkali metals selected from Li, Na, K, Rb and Cs; preferably selected from Na and K;
  • M" is one or more divalent metals selected from Mg, Mn, Cu, Co, Fe, Cd and Cr;
  • M m is optionally one or more trivalent metals selected from Fe, Cr and Mn;
  • x may be e.g. 0.3-0.8.
  • hydrotalcites of the above formula are referred to herein as KMG30 having a MgO: AI2O3 weight ratio of 30:70 and having the formula [Mgo .35 Alo .65 (OH) 2 ][CC> 3 2 ]o .325 * 0.5H 2 q 0.32K(CC> 3 2 ) O.5 with a molar ratio K: Mg: Al of about 1.0: 1.1: 2.0; and as KMG50 having a MgO: AI2O3 weight ratio of 50:50 with a molar ratio K: Mg: Al of about 1.0: 1.7: 1.4, and having the formula [Mgo.55 AI0.45 (0H) 2 ][C0 3 2 ]o.225 0.5H 2 0-0.32K(C0 3 2 ) 0. s.
  • the anions in the complex metal oxides preferably comprise hydroxide and/or carbonate anions to ensure sufficient alkalinity for effective adsorption of acidic gas species.
  • at least 50% of the anions (expressed in monovalent equivalents) comprise hydroxide and/or carbonate.
  • Suitable inorganic oxides can have a layered structure, wherein part of the anions is arranged in layers interposed between layers containing the cations.
  • suitable layered oxides include the hydrotalcites having proportional formulas such as Mg6Al2(OH)i6 (CO3) 4H2O or similar combinations with different Mg: Al ratios.
  • suitable oxides include analogues wherein magnesium is absent (e.g. scarbroite) or is replaced by calcium (e.g. alumohydrocalcites), strontium (e.g. montroyalite) or barium (e.g. dreserrites), as well as Mg/Fe, Mg/Cr, Mg/Mn, Ni/AI etc. analogues (pyroaurite, stichtite, desautelsite, takovite).
  • the adsorbent preferably contains an alkali metal compound.
  • alkali-containing materials are referred to also as 'alkali-promoted'.
  • the base material of the adsorbent can be alkali- promoted alumina.
  • the alkali promoters may be in the form of oxides, hydroxides or, preferably carbonates. Especially, the alkali content is > 5 wt.% calculated as alkali metal, preferably 5- 30 wt.%, relative to the final mixed oxide composition.
  • the adsorbent may have been thermally treated, i.e. it may have been heated at a temperature above about 200°C, even more especially above about 400°C.
  • a hydrotalcite when heating this hydrotalcite in the reactor before the WGS reaction or during the WGS reaction, the hydrotalcite modifies to a promoted alumina, such as K2CO3 and MgO promoted alumina, since, at elevated temperatures, the hydrotalcites may at least partially rearrange in mixed oxides while losing hydrotalcite crystalline structure and layered double hydroxide structure. This is well known in the art and is for instance described in US 5,358,701 , US 6,322,612 and WO 2005/102916.
  • the reactor may further contain a (conventional) water-gas shift catalyst, wherein preferably the weight ratio of the adsorbent to catalyst is in the range of about 2-50, such as about 5-20, especially about 10-20, or in the range of about 20-100, such as 20- 50, especially about 25-50.
  • a (conventional) water-gas shift catalyst wherein preferably the weight ratio of the adsorbent to catalyst is in the range of about 2-50, such as about 5-20, especially about 10-20, or in the range of about 20-100, such as 20- 50, especially about 25-50.
  • steps (e) and (f) is particularly advantaging in that feed gases containing, in addition to the WGS components, impurities, especially acidic impurities especially H2S can be treated.
  • impurities especially acidic impurities especially H2S
  • This is particularly advantaging for the treatment of gases exiting the FCC.
  • Possible acidic impurities comprise sulphur oxides, nitrogen oxides, hydrogen chloride (hydrochloric acid) and other hydrogen halides, hydrogen cyanide, and the like.
  • Carbonyl sulphide (COS) and carbon disulphide (CS2) which can be converted to H2S under conditions of adsorption and/or desorption, are considered as equivalents of H2S and are therefore also included in the term “acidic impurities” or “acidic components”.
  • the acidic component such as H2S is also adsorbed to the adsorbent in the reaction stage and is selectively removed from the adsorbent in the regeneration stage or loading stage.
  • the level of H2S or its equivalents COS and CS2 in the feed gas can be between 100 and 10,000 ppm of H2S.
  • the sorbent should preferably be capable of also adsorbing H2S and the like, in particular alkali-promoted alumina, more in particular alkali-promoted magnesium-containing alumina as defined above, e.g. with reference to the above formula.
  • the regeneration step (f) then comprises a plurality of steps: after the reaction step( e) wherein the adsorbent has been contacted with the feed gas containing the acidic component, a rinsing step may be applied, which ensures that the desired product such as hydrogen, is not spoilt with the acidic impurities; in such a rinsing step, the adsorbent is contacted with a rinsing gas, which does not contain high levels of CO2; in particular, CO2 is present at a partial pressure which is lower than the partial pressure in the feed gas; preferably, the rinsing gas is steam or nitrogen or a combination thereof, which may contain low levels of CO2; the absolute pressure applied in the rinsing step is preferably the same as the absolute pressure of the adsorption step, or lower pressure.
  • the adsorbent can be contacted with a first purging gas; this first purging gas may contain CO2 at a partial pressure which is at least the partial pressure of CO2 in the feed gas.
  • the adsorbent may be subjected to a second purging gas, which is the regeneration gas or the combined regeneration and loading gas as described above; this second purging gas may or may not contain CO2 and, if so, it contains CO2 at a partial pressure which is lower than the partial pressure in the feed gas.
  • a second purging gas which is the regeneration gas or the combined regeneration and loading gas as described above; this second purging gas may or may not contain CO2 and, if so, it contains CO2 at a partial pressure which is lower than the partial pressure in the feed gas.
  • the rinsing gas and both purging gases are essentially free of the acidic impurities, i.e. have levels of less than 50 ppm, in particular, less than 5 ppm, thereof.
  • the first purging gas should contain a sufficient level of CO2 to prevent substantial desorption of the CO2 at this stage, and thus to allow separate selective desorption.
  • the partial pressure of CO2 should preferably be higher than the partial pressure in the feed gas, more preferably at least 50% higher.
  • the first purging gas should contain at least 20 vol.%, preferably at least 30 vol.% of CO2, if the two gases are used at the same pressure. If the feed gas contains 20 vol.% of CO2 and is applied at a pressure of e.g. 2.0 MPa, and the purging gas is applied at a pressure of 1.0 MPa, the first purging gas should contain at least 40 vol.%, preferably at least 60 vol.% of CO2.
  • the remainder of the purging gas preferably comprises other, in particular non-acidic gases, especially nitrogen, oxygen (air, flue gas), water (steam) or methane.
  • the composition of the second purging gas is less critical than that of the first purging gas. However, it is preferred that the second purging gas does not contain appreciable levels of H2S and CO2.
  • the level of CO2 is preferably lower than the partial pressure of CO2 in the feed gas and less than half the level of CO2 in the first purging gas. Alternatively, or in addition, the level of CO2 is preferably less than 2 vol.%, more preferably less than 0.5 vol.%, most preferably less than 0.1 vol.%.
  • the second purging gas preferably comprises predominantly of water (steam) and/or nitrogen as described above for the regeneration gas.
  • the second purging step can coincide with or precede the loading stage as described above. Depending on whether the second purging step (regeneration step) and the loading step coincide or not, the level of steam can be adjusted.
  • a counter-current purging is particularly advantageous, especially in the regeneration or first purging step. Since H2S adsorption will typically occur in the upstream part of the adsorbent bed, counter-current purging will lead to a more effective and/or quicker or simpler desorption process. Another advantage is a reduced slip of H2S in the product for counter-current operation.
  • a counter-current purging only purges part of the adsorbent, i.e. the part which is loaded with the first acidic component (H2S) which is the upstream part of the adsorption step.
  • a pressure swing mode i.e. a cycle comprising relatively high-pressure adsorption and relatively low-pressure desorption is also advantageous.
  • Re-pressurization can be done with pressure equalization gas from other reactors in a different part of the pressure cycle.
  • Such equalization steps can be introduced to reduce pressure losses and improve product separation.
  • a particular embodiment of the water-gas shift step (e) uses a broader range of H2O to CO ratios and is a multi-step process.
  • Such step comprises further steps: (e1) a reaction step wherein a feed gas comprising CO and H2O is fed into a water-gas shift reactor containing a sorbent material capable of adsorbing H2O and CO2 and wherein a product gas issuing from the reactor is collected, (f) a regeneration step wherein CO2 is removed from the reactor, (f1) a loading step, wherein H2O is fed into the reactor, said loading stage following said regeneration stage (f); said reaction stage, regeneration stage and loading stage being performed in alternating sequence, wherein said feed gas mixture has a molar ratio of H2O to CO 0-2.0.
  • a purging step and/or an H2S removal step may be inserted between steps (e) and (f).
  • one or more can be advantageously used to further define the step (f) of the process:
  • step (f) comprises subjecting the adsorbent of step (e) to a purging gas comprising steam.
  • step (f) comprises the step of feeding water to the said adsorbent.
  • step (f) is carried out at a pressure ranging between 0.001 and 0.4 MPa.
  • step (f) is carried out at a pressure less than 2/3 of the pressure of step (e).
  • step (f) is carried out with steam.
  • step (f) is performed firstly by reducing the pressure and secondly by injecting a gas comprising at least 50 mol. % of steam based on the total molar content of said gas, preferably at least 75 mol. %, more preferably at least 80 mol. %, even more preferably at least 90 mol. %, wherein the remaining part of the gas is preferably one or more diluent gas, such as dinitrogen, argon and/or helium, preferably dinitrogen.
  • a gas comprising at least 50 mol. % of steam based on the total molar content of said gas, preferably at least 75 mol. %, more preferably at least 80 mol. %, even more preferably at least 90 mol. %, wherein the remaining part of the gas is preferably one or more diluent gas, such as dinitrogen, argon and/or helium, preferably dinitrogen.
  • step (f) is performed firstly by reducing the pressure and secondly by injecting a gas comprising at most 100 mol. % of steam.
  • the carbon dioxide-stream obtained at step (f) comprises from 60 to 100 mol. % of CO2 based on the total molar content of the stream on a dry basis, preferably from 60 to 95 mol.% or 65 to 95 mol. %.
  • the carbon dioxide-stream obtained at step (f) comprises at least 65 mol. % CO2 based on the total molar content of the stream on a dry basis, preferably at least 68 mol. % CO2 based on the total molar content of the stream on a dry basis.
  • the carbon dioxide-stream obtained at step (f) comprises at most 98 mol. % CO2 based on the total molar content of the stream on a dry basis, preferably at most 95 mol. % CO2 based on the total molar content of the stream on a dry basis.
  • step (f) comprises a step of feeding water to the catalyst and a step of feeding water to the adsorbent wherein both steps are performed simultaneously.
  • the process further comprises a step (i) of recovering a fluid catalytic cracking catalyst exiting said fluid catalytic cracking regenerator, wherein the fluid catalytic cracking catalyst has a carbon content of at least 1 wt.% based on the total weight content of said fluid catalytic cracking catalyst as measured according to the UOP Method 961 , preferably of at least 2 wt.%, more preferably of at least 5 wt.%.
  • the fluid catalytic cracking catalyst has a carbon content ranging between 5 wt.% and 50 wt.% based on the total weight content of said fluid catalytic cracking catalyst as measured according to the UOP Method 961.
  • the process of the disclosure using relatively low H2O to CO ratios can be used to produce hydrogen for combustion or synthesis purposes at a lower cost and higher efficiency from an FCC unit working in partial combustion mode.
  • no deposition of carbon on the adsorbent appears to occur, which would be expected in the case of using conventional WGS catalysts under high-temperature conditions and with low H2O to CO ratios.
  • the hydrogen-rich stream (H) can be used in an additional step (g) for the production of chemicals such as methane, methanol, higher hydrocarbons, ammonia and/or alcohols or for combustion processes.
  • chemicals such as methane, methanol, higher hydrocarbons, ammonia and/or alcohols or for combustion processes.
  • the carbon dioxide stream (I) can also be used in an additional step (h) for the production of chemicals such as methane, methanol, higher hydrocarbons and/or alcohols.
  • FCC regenerator 7 of an FCC unit 1 operated in partial combustion mode it refers to the regenerator 7 of the Fluid Catalytic Cracker (FCC) running in partial combustion operation, namely with an excess of CO.
  • FCC Fluid Catalytic Cracker
  • Partial combustion operation means using less oxygen than stoichiometrically required for complete coke combustion.
  • the main products of coke combustion in the FCC regenerator flue gas are water, CO and CO2. Hydrogen in coke is oxidized to water, but there is insufficient oxygen to burn all carbon to CO2, so a part of the carbon from coke is converted to CO.
  • the FCC regenerator flue gas contains therefore relatively high levels of air pollutants such as CO (1 to 5 mol.%, dry basis) and CO2 (10 to 20 mol.%, dry basis).
  • the FCC flue gas (21 , A) is treated in the adsorptive WGS reactor 35 according to the present disclosure.
  • the composition and the physical properties of various streams are presented in the following table. The streams are those presented in figure 3.
  • the example assumes 97% CO conversion rates and 98% CO2 capture.
  • the H2O: CO at the inlet of the adsorptive WGS reactor and H2O: carbon (CO+CO2) ratio for the rinse and purge steps are set to 4.8, 0.29 and 0.31, respectively.
  • This is consistent with the thermodynamic analysis of an adsorptive WGS reactor presented in Gazzani et al., International Journal of Greenhouse Gas Control 41 (2015) 249-267. Performance, component distribution and outlet conditions of the adsorptive WGS reactor are estimated based on extrapolation of mass and energy balances described also in the work of Gazzani et al.
  • Example 2 energy is recovered in the form of steam from the product streams of adsorptive WGS reactor 35 described in example 1.
  • the composition and the physical properties of various streams are presented in the following table.
  • the streams are those presented in figure 4.
  • Heat recovery ( ⁇ 13 MWth) from C0 2 -rich stream from adsorptive WGS reactor and combustion of H2-rich stream from adsorptive WGS reactor in a boiler with heat recovery ( ⁇ 62 MWth) allow producing additional 5065 kmol/h of steam (91.3 t/h) at 7.0 MPa and 375 ° C.
  • a total of -116 MWth of thermal energy is recovered to produce a total of 7879 kmol/h of steam (sum of steams C and K) (142.0 t/h) at 7.0 MPa and 375 ° C with the direct emission of 81 kmol/h (4 t/h) of CO2 to the atmosphere.
  • Example 3 In this example, the reference case illustrated in figure 5 is described. It consists of using only a boiler 49 to burn the CO originating from the FCC regenerator 7 with heat recovery to produce steam.
  • the composition and the physical properties of various streams are presented in the following table.
  • the CO product from the FCC flue gas is combusted together with an additional 83 kmol/h of CH4-fuel (1.3 t/h) in a boiler with heat recovery (-116 MWth) to produce 7879 kmol/h of steam (142.0 t/h) at 7.0 MPa and 375 C.
  • 1965 kmol/h of CO2 (87 t/h) are emitted to the atmosphere in the form of a stack gas.

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Abstract

L'invention divulgue un procédé de production d'un courant (H) riche en hydrogène et d'un courant (I) riche en dioxyde de carbone à partir du courant de gaz de carneau (21) d'un régénérateur CCF (7) d'une unité CCF exploitée en mode de combustion partielle, le procédé étant remarquable en ce qu'il comprend : (b) la récupération du gaz de carneau à partir dudit régénérateur CCF ; et (d) sa compression pour donner un mélange gazeux, ladite étape de compression étant mise en œuvre sous une pression d'au moins 0,4 MPa et à une température dans la plage de 200 °C à 500 °C ; (e) le fait de soumettre le mélange gazeux obtenu dans l'étape (d) à une réaction de conversion du gaz à l'eau pour convertir le CO en CO2 et H2 sur un catalyseur avec adsorption du CO2 par un adsorbant sous une pression dans la plage de 0,4 à 8,0 MPa et récupération d'un courant d'hydrogène ; (f) régénération dudit adsorbant de l'étape précédente pour obtenir un courant de CO2.
PCT/EP2021/069136 2020-07-24 2021-07-09 Réduction des émissions de co et de co2 à partir d'un ccf dans une combustion partielle avec co-production de h2 WO2022017829A1 (fr)

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