WO2023073389A1 - Procédé de purification d'un mélange gazeux comprenant du dioxyde de carbone et éventuellement du sulfure d'hydrogène - Google Patents

Procédé de purification d'un mélange gazeux comprenant du dioxyde de carbone et éventuellement du sulfure d'hydrogène Download PDF

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WO2023073389A1
WO2023073389A1 PCT/IB2021/000728 IB2021000728W WO2023073389A1 WO 2023073389 A1 WO2023073389 A1 WO 2023073389A1 IB 2021000728 W IB2021000728 W IB 2021000728W WO 2023073389 A1 WO2023073389 A1 WO 2023073389A1
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absorbent solution
carbon dioxide
hydrogen sulfide
gas mixture
loaded
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PCT/IB2021/000728
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English (en)
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Frédérick DE MEYER
Karen GONZALEZ-TOVAR
Bénédicte POULAIN
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Totalenergies Onetech
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Priority to PCT/IB2021/000728 priority Critical patent/WO2023073389A1/fr
Priority to CA3235954A priority patent/CA3235954A1/fr
Publication of WO2023073389A1 publication Critical patent/WO2023073389A1/fr

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    • 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
    • B01D53/14—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 absorption
    • B01D53/1456—Removing acid components
    • B01D53/1462—Removing mixtures of hydrogen sulfide and 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
    • B01D53/14—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 absorption
    • B01D53/1456—Removing acid components
    • B01D53/1468—Removing hydrogen sulfide
    • 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
    • B01D53/14—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 absorption
    • B01D53/1456—Removing acid components
    • B01D53/1475—Removing 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
    • B01D53/14—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 absorption
    • B01D53/1493—Selection of liquid materials for use as absorbents
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
    • C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
    • C10L3/10—Working-up natural gas or synthetic natural gas
    • C10L3/101—Removal of contaminants
    • C10L3/102—Removal of contaminants of acid contaminants
    • C10L3/103—Sulfur containing contaminants
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
    • C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
    • C10L3/10—Working-up natural gas or synthetic natural gas
    • C10L3/101—Removal of contaminants
    • C10L3/102—Removal of contaminants of acid contaminants
    • C10L3/104—Carbon dioxide
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
    • B01D2252/20—Organic absorbents
    • B01D2252/202—Alcohols or their derivatives
    • B01D2252/2023—Glycols, diols or their derivatives
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
    • B01D2252/20—Organic absorbents
    • B01D2252/202—Alcohols or their derivatives
    • B01D2252/2023—Glycols, diols or their derivatives
    • B01D2252/2026—Polyethylene glycol, ethers or esters thereof, e.g. Selexol
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
    • B01D2252/20—Organic absorbents
    • B01D2252/204—Amines
    • B01D2252/20431—Tertiary amines
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
    • B01D2252/20—Organic absorbents
    • B01D2252/204—Amines
    • B01D2252/20478—Alkanolamines
    • B01D2252/20484—Alkanolamines with one hydroxyl group
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
    • B01D2252/20—Organic absorbents
    • B01D2252/204—Amines
    • B01D2252/20478—Alkanolamines
    • B01D2252/20489—Alkanolamines with two or more hydroxyl groups
    • 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
    • B01D2256/20—Carbon monoxide
    • 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
    • B01D2256/245—Methane
    • 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
    • B01D2257/306—Organic sulfur compounds, e.g. mercaptans
    • 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
    • B01D2257/308—Carbonoxysulfide COS
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L2290/00—Fuel preparation or upgrading, processes or apparatus therefore, comprising specific process steps or apparatus units
    • C10L2290/54—Specific separation steps for separating fractions, components or impurities during preparation or upgrading of a fuel
    • C10L2290/541—Absorption of impurities during preparation or upgrading of a fuel
    • 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 invention relates to a method for the purification of a gas mixture comprising hydrogen sulfide at an amount equal to or less than 20 volume % and carbon dioxide at an amount equal to or less than 20 volume %.
  • impurities and contaminants may include “acid gases” such as, for example, carbon dioxide (CO2), and hydrogen sulfide (H2S); other sulfur compounds such as carbonyl sulfide (COS) and mercaptans (R-SH, where R is an alkyl group); water; and certain hydrocarbons.
  • acid gases such as, for example, carbon dioxide (CO2), and hydrogen sulfide (H2S); other sulfur compounds such as carbonyl sulfide (COS) and mercaptans (R-SH, where R is an alkyl group); water; and certain hydrocarbons.
  • Carbon dioxide and hydrogen sulfide may represent a significant part of the gas mixture from a natural gas field, typically from 3 to 70 % by volume, while COS may be present in smaller amounts, typically ranging from 1 to 100 ppm by volume, and mercaptans may be present at a content generally less than 1000 ppm by volume, for example between 5 and 500 ppm by volume.
  • LPG liquefied petroleum gas
  • the specifications on the acid gas content in the treated gas are specific to each of the considered products. For example, levels of a few ppm are usually imposed for H2S, while specifications for CO2 may range up to a few %, generally 2 % by volume.
  • a well known technology used for acid gas separation and thus for gas purification is absorption by an absorbent solution, typically an aqueous amine.
  • a major disadvantage regarding the implementation of this technology on industrial sites is its high cost due to the large amount of energy required for the regeneration of the absorbent solution loaded with acid gases. In other words, energy is required to heat and vaporize part of the loaded absorbent solution for its regeneration and for the desorption of the acid gases.
  • Document EP 3083012 relates to a method for the capture of at least one acid gas in a composition, the release of said gas from said composition, and the subsequent regeneration of said composition for re-use, said method comprising performing, in order, the steps of: (a) capturing the at least one acid gas by contacting said at least one gas with a capture composition comprising at least one salt of a carboxylic acid and at least one water-miscible non-aqueous solvent; (b) releasing said at least one acid gas by adding at least one protic solvent or agent to said composition; and (c) regenerating the capture composition by partial or complete removal of said added protic solvent or agent from said composition.
  • Document US 2016/0193563 relates to a solvent for recovery of carbon dioxide from gaseous mixture, having alkanolamine, reactive amines acting as promoter or activators, glycol, and a carbonate buffer.
  • Document WO 2012/034921 relates to a process for CO2 capture from gas mixtures and for CO2 removal from gaseous wastes of industrial processes or combustion gases, which is carried out by bringing into contact the gas mixtures with an absorbent solution of amines in anhydrous alcohols; this process comprising CO2 absorption at room temperature and atmospheric pressure and CO2 absorption and amine regeneration at temperatures lower than the boiling temperature of the solution and at atmospheric pressure.
  • the glycol is present in the absorbent solution at a content from 20 to 45 mol % and preferably from 20 to 40 mol % relative to the absorbent solution.
  • the absorbent solution has a boiling temperature from 105 to 140°C, and preferably 130 to 135°C.
  • the tertiary amine is chosen from N- methyldiethanolamine, 2-(2-diethylaminoethoxy)ethanol, (2,2'- (((methylazanediyl)bis(ethane-2,1-diyl))bis(oxy))diethanol), 3,9-dimethyl-6-oxa- 3,9-diaza-undecane-1 ,11 -diol and 4-morpholin-4-ylpentan-1-ol, and mixtures thereof.
  • the glycol compound is ethylene glycol.
  • the step of putting in contact the gas mixture with an absorbent solution is carried out at a temperature from 25 to 100°C and/or at an absolute pressure from 1 to 170 bar.
  • the step of putting in contact the gas mixture with an absorbent solution is carried out in an absorption column or in a rotating packed bed.
  • the gas mixture comprises at least one hydrocarbon, and is preferably natural gas.
  • the step of regenerating the absorbent solution loaded with carbon dioxide and/or hydrogen sulfide is carried out in a regeneration column (9).
  • regenerating the absorbent solution loaded with carbon dioxide and/or hydrogen sulfide is carried out by heating the absorbent solution loaded with carbon dioxide and/or hydrogen sulfide preferably at a temperature from 100 to 200°C, and more preferably from 110 to 140°C.
  • regenerating the absorbent solution loaded with carbon dioxide and/or hydrogen sulfide is carried out at an absolute pressure from 1 to 3 bar.
  • the energy consumption is from 80 to 200 MJ/m 3 of absorbent solution.
  • the regenerated absorbent solution is recycled in the step of putting in contact the gas mixture with an absorbent aqueous solution.
  • the present invention enables to meet the abovementioned need.
  • the invention provides a method which makes it possible to separate acid gases such as carbon dioxide and hydrogen sulfide from a gas mixture and to efficiently regenerate the solution used for the separation method, with low energetic consumption and without deteriorating the other process parameters (such as absorption capacity, thermal degradation).
  • the gas mixture to be purified comprises hydrogen sulfide at an amount equal to or less than 20 volume % and carbon dioxide at an amount equal to or less than 20 volume %
  • the absorbent solution used for the separation of acid gases comprises a tertiary amine, a glycol compound and water
  • a gas stream comprising carbon dioxide (CO2) and optionally hydrogen sulfide (H2S) with an absorbent solution comprising a tertiary amine, a glycol compound and water makes it possible to separate the carbon dioxide and optionally the hydrogen sulfide from the rest of the gas mixture. Furthermore, the absorbent solution loaded with the acid gases will be regenerated by heating and vaporizing the solvent so as to desorb the acid gases.
  • CO2 carbon dioxide
  • H2S hydrogen sulfide
  • the specific combination of components in the absorbent solution makes it possible to reduce the energy required for the desorption of the acid gases from the absorbent solution and also the energy used to heat up the solvent in order to attain a temperature at which the water present in the solvent can be vaporized during the regeneration step (relative to an absorbent solution devoid of glycol for example).
  • a glycol compound should decrease the absorption capacity and the absorption rate of the solution, due to the hydroxy groups of such molecule, it seems that the glycol is involved in the chemical absorption of the acid gases, therefore affecting less the absorption capacity of the absorbent solution than other co-solvents (such as cosolvents devoid of hydroxy groups).
  • initial gas mixtures comprising specific amounts of acid gases and more particularly comprising an amount of hydrogen sulfide equal to or less than 20 volume % and an amount of carbon dioxide equal to or less than 20 volume %.
  • the energy gain is less significant than the energetic gain during the purification of a gas mixture comprising an amount of hydrogen sulfide equal to or less than 20 volume %.
  • Figure 1 illustrates an installation used for the implementation of the method according to one embodiment of the invention.
  • Figure 2 illustrates H2S concentration profiles in the vapor phase of the absorption column in tests 1 and 3 (see below).
  • the number of column segments can be read on the Y-axis and the CO2 concentration (in mol%) can be read on the X-axis.
  • Figure 3 illustrates CO2 concentration profiles in the vapor phase of the absorption column in tests 1 and 3 (see below).
  • the number of column segments can be read on the Y-axis and the CO2 concentration (in mol%) can be read on the X-axis.
  • Figure 4 illustrates H2S concentration profiles in the vapor phase of the absorption column in tests 2 and 4 (see below).
  • the number of column segments can be read on the Y-axis and the H2S concentration (in mol%) can be read on the X-axis.
  • Figure 5 illustrates CO2 concentration profiles in the vapor phase of the absorption column in tests 2 and 4 (see below).
  • the number of column segments can be read on the Y-axis and the CO2 concentration (in mol%) can be read on the X-axis.
  • the present invention makes it possible to treat a gas mixture.
  • the gas mixture of the present invention is natural gas.
  • Natural gas may be provided at various pressures, which can range for example from 10 to 100 bar, and various temperatures which can range from 20 to 60°C.
  • the gas mixture of the present invention may be a refinery gas, a biomass fermentation gas, a tail gas obtained at the outlet of sulfur chains (CLAUS installation).
  • the gas mixture of the present invention comprises at least carbon dioxide.
  • the gas mixture according to the present invention comprises carbon dioxide in a content equal to or less than 20 % by volume, preferably equal to or less than 10 % by volume, preferably from 0.1 to 10 % by volume, and more preferably from 0.5 to 10 % by volume relative to the volume of the gas mixture.
  • This content may be for example from 0.1 to 0.2 %; or from 0.2 to 0.5 %; or from 0.5 to 1 %; or from 1 to 2 %; or from 2 to 3 %; or from 3 to 4 %; or from 4 to 5 %; or from 5 to 6 %; or from 6 to 7 %; or from 7 to 8%; or from 8 to 9 %; or from 9 to 10 %; or from 10 to 1 1 %; or from 1 1 to 12 %; or from 12 to 13 %; or from 13 to 14 %; or from 14 to 15 %; or from 15 to 16 %; or from 16 to 17 %; or from 17 to 18 %; or from 18 to 19 %; or from 19 to 20 % by volume relative to the volume of the gas mixture.
  • the gas mixture of the present invention comprises hydrogen sulfide in a content equal to or lower than 20 % by volume, preferably equal to or lower than 10 % by volume, more preferably equal to or lower than 5 % by volume, and more preferably equal to or lower than 3 % by volume relative to the volume of the gas mixture.
  • This content may be for example from 0.001 to 0.01 %; or from 0.01 to 0.5 %; or from 0.5 to 1 %; or from 1 to 2 %; or from 2 to 4 %; or from 6 to 6 %; or from 6 to 8 %; or from 8 to 10 %; or from 10 to 12 %; or from 12 to 14 %; or from 14 to 16 %; or from 16 to 18 %; or from 18 to 20 % by volume relative to the volume of the gas mixture.
  • This content can be measured by gas phase chromatography.
  • the gas mixture of the present invention may also comprise other compounds such as carbonyl sulfide, carbon disulfide, sulfur dioxide, and/or one or more mercaptans such as methyl mercaptan, ethyl mercaptan, propyl mercaptans and butyl mercaptans.
  • other compounds such as carbonyl sulfide, carbon disulfide, sulfur dioxide, and/or one or more mercaptans such as methyl mercaptan, ethyl mercaptan, propyl mercaptans and butyl mercaptans.
  • the gas mixture may contain at least one mercaptan at a content generally less than 1000 ppm by volume, preferably between 5 and 500 ppm by volume relative to the volume of the gas mixture.
  • the gas mixture may contain carbonyl sulfide at a content generally less than 200 ppm by volume, preferably between 1 and 100 ppm by volume relative to the volume of the gas mixture.
  • the gas mixture according to the present invention may preferably be a hydrocarbon gas mixture, in other words it contains one or more hydrocarbons.
  • hydrocarbons are for example saturated hydrocarbons, for example C1 to C4 alkanes such as methane, ethane, propane and butane, unsaturated hydrocarbons such as ethylene or propylene, or aromatic hydrocarbons such as benzene, toluene or xylene.
  • the absorbent solution according to the present invention makes it possible to separate CO2 and optionally H2S from the gas mixture described above.
  • the absorbent solution according to the invention is an aqueous solution that comprises at least one tertiary amine and at least one glycol compound.
  • the absorbent solution is a mixture of a tertiary amine, a glycol compound and water.
  • the tertiary amine may be for example aliphatic, cyclic or aromatic.
  • the tertiary amine is selected from tertiary alkanolamines. It may be reminded that the alkanolamines or amino alcohols are amines comprising at least one hydroxyalkyl group (comprising for example from 1 to 10 carbon atoms) bound to the nitrogen atom.
  • the tertiary amine may further comprise at least one oxygen and/or at least one sulfur atom.
  • the tertiary amine may be an ethoxyethanolamine, such as 2-(2-diethylaminoethoxy)ethanol (DEAE-EO), (2,2'- (((methylazanediyl)bis(ethane-2,1-diyl))bis(oxy))diethanol).
  • DEAE-EO 2-(2-diethylaminoethoxy)ethanol
  • the tertiary amine may be a tertiary amine comprising a morpholinone function, such as 4-morpholin-4- ylpentan-1 -ol.
  • the tertiary amine may be a tertiary polyamine such as 3,9-dimethyl-6-oxa-3,9-diaza-undecane-1 ,11-diol.
  • the tertiary alkanolamines can be trialkanolamines, alkyldialkanolamines or dialkylalkanolamines.
  • the alkyl groups and the hydroxyalkyl groups can be linear, cyclic, or branched and generally comprise from 1 to 10 carbon atoms, preferably the alkyl groups comprise from 1 to 4 carbon atoms, and the hydroxyalkyl groups comprise from 2 to 4 carbon atoms.
  • tertiary amine and in particular of tertiary alkanolamines are given in US 2008/0025893, the description of which can be referred to. More particular examples include N-methyldiethanolamine (MDEA), N,N- diethylethanolamine (DEEA), N,N-dimethylethanolamine (DMEA), 2- diisopropylaminoethanol (DIEA), N,N,N',N'-tetramethylpropanediamine (TMPDA), N,N,N',N'-tetraethylpropanediamine (TEPDA), dimethylamino-2- dimethylamino-ethoxyethane (Niax), and N,N-dimethyl-N',N'- diethylethylenediamine (DMDEEDA).
  • MDEA N-methyldiethanolamine
  • DEEA N,N- diethylethanolamine
  • DMEA N,N-dimethylethanolamine
  • DIEA 2- diisoprop
  • tertiary alkanolamines examples include tris(2-hydroxyethyl)amine (triethanolamine, TEA), tris(2-hydroxypropyl)amine (triisopropanol), tributylethanolamine (TEA), bis(2-hydroxyethyl)methylamine
  • methyldiethanolamine, MDEA 2-diethylaminoethanol
  • DEEA diethylethanolamine
  • DMEA 2-dimethylaminoethanol
  • 3- dimethylamino-1 -propanol 3-diethylamino-1 -propanol
  • DIEA 2- diisopropylaminoethanol
  • MDIPA N,N-bis(2-hydroxypropyl)methylamine or methyldiisopropanolamine
  • tertiary alkanolamines that can be used in the process according to the invention are given in US 5,209,914, the description of which can be referred to. More particular examples N-methyldiethanolamine, triethanolamine, N-ethyldiethanolamine, 2-dimethylaminoethanol, 2- dimethylamino-1 -propanol, 3-dimethylamino-1 -propanol, 1 -dimethylamino-2- propanol, N-methyl-N-ethylethanolamine, 2-diethylaminoethanol, 3- dimethylamino-1 -butanol, 3-dimethylamino-2-butanol, N-methyl-N- isopropylethanolamine, N-methyl-N-ethyl-3-amino-1 -propanol, 4-dimethylamino- 1 -butanol, 4-dimethylamino-2-butanol, 3-dimethylamino-2-methyl-1 --
  • tertiary amines that can be mentioned include the bis(tertiary diamines) such as N,N,N',N'-tetramethylethylenediamine, N,N-diethyl-N',N'- dimethylethylenediamine, N,N,N',N'-tetraethylethylenediamine, N,N,N',N'- tetramethyl-1 ,3-propanediamine (TMPDA), N,N,N',N'-tetraethyl-1 ,3- propanediamine (TEPDA), N,N-dimethyl-N',N'-diethylethylenediamine (DMDEEDA), 1 -dimethylamino-2-dimethylaminoethoxy-ethane (bis[2- dimethylamino)ethyl]ether) mentioned in U.S. Patent Publication No. 2010/0288125.
  • TPDA N,N,N',N'-tetramethyl
  • the tertiary amine may be chosen from N-methyldiethanolamine (MDEA), 2-(2-diethylaminoethoxy)ethanol (DEAE- EO), (2,2'-(((methylazanediyl)bis(ethane-2,1 -diyl))bis(oxy))diethanol), 3,9- dimethyl-6-oxa-3,9-diaza-undecane-1 ,11 -diol and 4-morpholin-4-ylpentan-1 -ol and their mixtures.
  • MDEA N-methyldiethanolamine
  • DEAE- EO 2-(2-diethylaminoethoxy)ethanol
  • the tertiary amine may be present in the absorbent solution at a total content from 5 to 20 mol %, and preferably from 5 to 15 mol % relative to the absorbent solution.
  • such content may be from 5 to 10 mol %; or from 10 to 15 mol %; or from 15 to 20 mol % relative to the absorbent solution.
  • the absorbent solution further comprises at least one glycol.
  • glycoF is meant a molecule that comprises two hydroxy (-OH) groups.
  • the glycol compound is preferably miscible with the tertiary amine and with water.
  • miscible is meant that the glycol compound forms a homogeneous mixture when mixed with water.
  • the glycol compound has a boiling temperature higher than 100°C, and more preferably from 120 to 250°C.
  • the glycol compound may be chosen from ethylene glycol, propylene glycol, diethylene glycol, ethylene glycol monobutyl ether (EGBE), and ethylene glycol monomethyl ether (EGME).
  • EGBE ethylene glycol monobutyl ether
  • EGME ethylene glycol monomethyl ether
  • the glycol compound is ethylene glycol.
  • the glycol compound may be present in the absorbent solution at a total content from 20 to 45mol %, and preferably from 20 to 40 mol % relative to the absorbent solution.
  • such content may be from 20 to 25 mol %; or from 25 to 30 mol %; or from 30 to 35 mol %; or from 35 to 40 mol %; or from 40 to 45 mol % relative to the absorbent solution.
  • the water may be present in the absorbent solution in an amount from 10 to 75 mol %, and preferably from 40 to 70 mol % relative to the absorbent solution.
  • the absorbent solution may consist of the tertiary amine, the glycol compound and water.
  • the absorbent solution may comprise one or more other additional compounds.
  • the absorbent solution has a boiling temperature from 105 to 140°C, and preferably from 130 to 135°C.
  • this temperature may be from 105 to 110°C; or from 110 to 115°C; or from 115 to 120°C; or from 120 to 125°C; or from 125 to 130°C; or from 130 to 135°C; or from 135 to 140°C.
  • the regeneration should be performed at a temperature lower than the temperature at which the amine may start degrading. For this reason, it is advantageous if the boiling temperature of the absorbent solution is not more than 135°C or 130°C.
  • the method according to the present invention makes it possible to separate CO2 and optionally H2S from the gas mixture described above by using the absorbent solution described above.
  • the method according to the invention comprises a first step of putting the gas mixture in contact with the absorbent solution.
  • This contacting (absorption) step may be carried out in any apparatus for gas-liquid contact.
  • this step can be carried out in an absorption column.
  • Any type of column can be used in the context of the present invention, and in particular a column with perforated plate trays, valve trays or cap trays. Columns with bulk or structured packing can also be used.
  • this step can be carried out in a static in-line solvent mixer.
  • a RPB comprises an element which is permeable to the fluids to be separated, which has pores which present a tortuous path to the fluids to be separated.
  • the RPB is rotatable about an axis such that the fluids to be separated are subjected to a mean acceleration of at least 300 m/s 2 as they flow through the pores with the first fluid flowing radially outwards away from the said axis.
  • the RPB further comprises means for charging the fluids to the permeable element and at least means for discharging one of the fluids or a derivative thereof from the permeable element.
  • absorption column or “column” are used hereinafter to designate the gas-liquid contact apparatus, but of course any apparatus for gas-liquid contact can be used for carrying out the absorption step.
  • the gas mixture entering the absorption column 1 from the bottom part of the absorption column 1 (gas feeding line 2) is put into contact with a stream of the absorbent solution according to the invention entering the absorption column 1 from the top of the absorption column 1.
  • This contact is preferably made in a counter-current mode.
  • the gas mixture may have a flow rate during this step from 300 to 56 x 10 6 kg/h.
  • the gas mixture entering the absorption column 1 may have a temperature from 25 to 100°C.
  • the absorbent solution may have a flow rate during this step from 800 to 1000000 kg/h.
  • the absorbent solution entering the absorption column 1 may have a temperature from 25 to 100°C.
  • the step of putting in contact the gas mixture with an absorbent solution may be carried out at a temperature from 25 to 100°C.
  • the step of putting in contact the gas mixture with an absorbent solution may be carried out at an absolute pressure from 1 to 170 bar, and preferably from 1 to 80 bar.
  • the gas mixture may be put in contact with the absorbent solution for a time period from 10 to 500 seconds, and preferably from 10 to 300 seconds.
  • a stream of gas mixture depleted in carbon dioxide and optionally hydrogen sulfide may be collected from the top (gas collecting line 3) of the absorption column 1 while a stream of absorbent solution loaded with carbon dioxide and optionally hydrogen sulfide may be recovered at the bottom of the absorption column 1 (loaded solution collecting line 4).
  • the (initial) gas mixture comprises one or more hydrocarbons (which is a preferred embodiment of the present invention)
  • the stream of gas mixture collected from the top of the absorption column 1 predominantly contains the hydrocarbons while the stream of absorbent solution recovered from the bottom of the absorption column 1 contains no hydrocarbons or only a residual amount of hydrocarbons.
  • this step makes it possible to separate on the one hand the gas comprising hydrocarbons and on the other hand the absorbent solution and (most of the) CO2 and optionally (most of the) H2S.
  • 1 may have a content in H2S equal to or lower than 100 ppm by volume, preferably equal to or lower than 20 ppm by volume, and more preferably equal to or lower than 15 ppm by volume.
  • This content can be measured by gas phase chromatography. For example, this content may be from 0 to 1 ppm; or from 1 to
  • the stream of gas mixture collected from the top of the absorption column 1 may have a content in CO2 lower than 5 %, and preferably from 0.5 to 4 % by volume relative to the volume of the stream of gas mixture depleted in hydrogen sulfide.
  • the initial gas mixture comprises one or more mercaptans
  • such mercaptans are predominantly recovered in the absorbent solution loaded with carbon dioxide and optionally hydrogen sulfide.
  • the method according to the present invention may further comprise an optional step of removing residual hydrocarbon from the absorbent solution loaded with carbon dioxide and optionally hydrogen sulfide.
  • This step may be carried out for example by passing said solution from the absorption column 1 , via the loaded solution collecting line 4 and into a flash tank 5 (as illustrated in figure 1). This step may be carried out at a temperature from 50°C to 90°C and at an absolute pressure from 4 to 15 bar.
  • the stream of absorbent solution loaded with carbon dioxide and optionally hydrogen sulfide may exit the absorption column 1 from the bottom of the absorption column 1 and enter the flash tank 5 via the loaded solution collecting line 4.
  • the hydrocarbons removed at this step may be used for example as fuel gas or may be recycled in the method according to the present invention for example by mixing these hydrocarbons with the (initial) gas mixture (not illustrated in the figures) for example after a compression step.
  • the loaded absorbent solution is collected from the flash tank 5 in a loaded solution feeding line 6.
  • the absorbent solution loaded with carbon dioxide and optionally hydrogen sulfide can be regenerated in order to collect a stream comprising carbon dioxide and optionally hydrogen sulfide on the one hand and a regenerated absorbent solution on the other hand.
  • This step may be carried out in a regeneration column 9, preferably comprising a reboiler (for example at the lower (bottom) part of the regeneration column 9) (not illustrated in the figures).
  • a reboiler for example at the lower (bottom) part of the regeneration column 9 (not illustrated in the figures).
  • Any type of column can be used in the context of the present invention, and in particular a column with perforated plate trays, valve trays, or cap trays. Columns with bulk or structured packing can also be used.
  • the loaded solution feeding line 6 may be connected to an inlet of the regeneration column 9, so as to feed the absorbent solution loaded with carbon dioxide and optionally hydrogen sulfide to the regeneration column 9 (for example from the bottom of the regeneration column 9).
  • the reboiler located in the regeneration column 9 may generate water steam by heating the absorbent solution loaded with carbon dioxide and optionally hydrogen sulfide and promote desorption of the carbon dioxide and optionally the hydrogen sulfide and recovery of a gas enriched in carbon dioxide and optionally hydrogen sulfide at the top of the regeneration column 9.
  • the steam ascends in a counter-current mode in the regeneration column 9, entraining the CO2 and optionally the H2S and optionally other impurities (such as mercaptans) remaining in the absorbent solution loaded with carbon dioxide and optionally hydrogen sulfide.
  • This desorption is promoted by the low pressure and high temperature prevailing in the regenerator.
  • heating of the absorbent aqueous solution loaded with carbon dioxide and optionally hydrogen sulfide in the regeneration column 9 may be carried out at a temperature from 100 to 200°C, and more preferably from 110 to 140°C and at an absolute pressure from 1 bar to 3 bar.
  • the absorbent solution loaded with carbon dioxide and optionally hydrogen sulfide may have a content in carbon dioxide from 5 kg/m 3 to 45 kg/m 3 , and preferably from 10 kg/m 3 to 30 kg/m 3 .
  • the absorbent solution loaded with carbon dioxide and optionally hydrogen sulfide may have a content in hydrogen sulfide from 10 kg/m 3 to 45 kg/m 3 , and preferably from 10 kg/m 3 to 30 kg/m 3 .
  • the energy consumption is from 80 to 200 MJ/m 3 of absorbent solution (notably: from 80 to 100 MJ/m 3 , or from 100 to 120 MJ/m 3 , or from 1200 to 160 MJ/m 3 , or from 160 to 180 MJ/m 3 , or from 180 to 200 MJ/m 3 ).
  • this energy consumption it is possible to obtain a regenerated absorbent solution comprising an amount of 0.0015 wt% CO2 or lower and of 0.03 wt% H2S or lower.
  • this energy consumption it is possible to recover CO2 and H2S with a minimum recovery rate of 75 % for CO2 and 99.95 % for H2S.
  • Such energy consumption is preferably the energy consumption in the reboiler of the regeneration column 9.
  • the energy consumption (duty) is calculated from the measured vapor flow rate and the latent heat of vaporization of water at the steam supply pressure according to the following equation (and is then converted into MJ/h): .
  • F m mass flow rate (vapor) in kg/h
  • the CO2 and optionally the H2S and optionally impurities may be recovered as a gaseous stream at the top of the regeneration column 9 (CO2 and optionally H2S collecting line 10).
  • the steam generated in the column (deriving from the absorbent solution therefore comprising the tertiary amine, the glycol compound and water) may be cooled in a condenser present in the regeneration column 9.
  • the condensed regenerated absorbent solution may exit the regeneration column 9 via a lean solution collecting line 11 preferably at the bottom of the regeneration column 9.
  • the condensed regenerated absorbent solution stream may comprise an amount equal to or less than 0.03 % by weight, and preferably equal to or less than 0.01 % by weight of H2S relative to the weight of the condensed regenerated absorbent solution.
  • the condensed regenerated absorbent solution stream exiting the regeneration column 9 may also comprise an amount equal to or less than 0,0015 % by weight, and preferably equal to or less than 0,001 % by weight of CO2 relative to the weight of the condensed regenerated absorbent solution.
  • a heat exchanger 7 may be provided in order to preheat the absorbent solution loaded with carbon dioxide and/or hydrogen sulfide before feeding it to the regeneration column 9.
  • the heat exchanger 7 may transfer heat from the lean solution collecting line 11 to the loaded solution feeding line 6.
  • the regenerated absorbent solution may then be recycled in the step of putting in contact the gas mixture with an absorbent solution, for example by entering the absorption column 1 via the lean solution collecting line 11 .
  • Example 1 Two absorbent solutions were used in this example, as detailed in the table below: Four tests were carried out. Tests 1 and 2 are according to the invention
  • tests 3 and 4 are comparative tests (using absorbent solution B).
  • the ratio kg vapor/ kg CO2 captured was reduced of about 85 % when comparing the absorbent solution according to the invention A (test 1 and 2) with the comparative absorbent solution B (tests 3 and 4). This also indicates a decrease in energy consumption when using the absorbent solution A.

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Abstract

La présente invention concerne un procédé de purification d'un mélange gazeux comprenant du dioxyde de carbone et éventuellement du sulfure d'hydrogène. Ledit procédé comprend les étapes consistant à : mettre en contact un mélange gazeux initial comprenant du sulfure d'hydrogène à une quantité égale ou inférieure à 20 % en volume et du dioxyde de carbone à une quantité égale ou inférieure à 20 % en volume, avec une solution absorbante de manière à obtenir un mélange gazeux appauvri en dioxyde de carbone et/ou en sulfure d'hydrogène, et une solution absorbante chargée de dioxyde de carbone et/ou de sulfure d'hydrogène, la solution absorbante comprenant au moins une amine tertiaire, au moins un composé glycol et de l'eau ; et régénérer la solution absorbante chargée avec du dioxyde de carbone et/ou du sulfure d'hydrogène de façon à collecter un flux comprenant du dioxyde de carbone et/ou du sulfure d'hydrogène et une solution absorbante régénérée.
PCT/IB2021/000728 2021-10-26 2021-10-26 Procédé de purification d'un mélange gazeux comprenant du dioxyde de carbone et éventuellement du sulfure d'hydrogène WO2023073389A1 (fr)

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PCT/IB2021/000728 WO2023073389A1 (fr) 2021-10-26 2021-10-26 Procédé de purification d'un mélange gazeux comprenant du dioxyde de carbone et éventuellement du sulfure d'hydrogène
CA3235954A CA3235954A1 (fr) 2021-10-26 2021-10-26 Procede de purification d'un melange gazeux comprenant du dioxyde de carbone et eventuellement du sulfure d'hydrogene

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EP3083012A2 (fr) 2013-12-19 2016-10-26 C-Capture Ltd. Système de capture et de libération de gaz acides
WO2018164705A1 (fr) * 2017-03-06 2018-09-13 Dow Global Technologies Llc Processus écoénergétique de séparation de sulfure d'hydrogène de mélanges gazeux à l'aide d'un mélange de solvants hybrides

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