WO2022129975A1 - Procédé pour l'élimination sélective du sulfure d'hydrogène à partir d'un courant de gaz - Google Patents

Procédé pour l'élimination sélective du sulfure d'hydrogène à partir d'un courant de gaz Download PDF

Info

Publication number
WO2022129975A1
WO2022129975A1 PCT/IB2020/001110 IB2020001110W WO2022129975A1 WO 2022129975 A1 WO2022129975 A1 WO 2022129975A1 IB 2020001110 W IB2020001110 W IB 2020001110W WO 2022129975 A1 WO2022129975 A1 WO 2022129975A1
Authority
WO
WIPO (PCT)
Prior art keywords
functional group
molecule
polar
aprotic
hydrogen sulfide
Prior art date
Application number
PCT/IB2020/001110
Other languages
English (en)
Inventor
Frédérick DE MEYER
Claire Weiss
Original Assignee
Totalenergies Onetech
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Totalenergies Onetech filed Critical Totalenergies Onetech
Priority to PCT/IB2020/001110 priority Critical patent/WO2022129975A1/fr
Publication of WO2022129975A1 publication Critical patent/WO2022129975A1/fr

Links

Classifications

    • 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
    • B01D53/1493—Selection of liquid materials for use as absorbents
    • 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
    • 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
    • B01D2252/205—Other organic compounds not covered by B01D2252/00 - B01D2252/20494
    • B01D2252/2056—Sulfur compounds, e.g. Sulfolane, thiols
    • 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
    • B01D2252/50—Combinations of absorbents
    • B01D2252/502—Combinations of absorbents having two or more functionalities in the same molecule other than alkanolamine
    • 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
    • B01D2257/304—Hydrogen sulfide
    • 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 selective separation of hydrogen sulfide relative to carbon dioxide from a gas mixture comprising at least hydrogen sulfide and carbon dioxide.
  • 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
  • Document WO 2013/174902 relates to a process for the selective removal of hydrogen sulfide with respect to carbon dioxide in a gas mixture containing at least hydrogen sulfide and carbon dioxide.
  • the process comprises a step of putting said gas mixture into contact with an absorbent solution comprising at least one amine, water and at least one C2 to C4 thioalkanol.
  • Document WO 87/01961 relates to a method for the selective removal of H2S from a H2S-containing gas. This method comprises contacting the gas in an absorption area with a selective absorbing liquid which absorbs the H2S and regenerating, by heating, the absorbing liquid loaded with H2S in a regeneration area.
  • Document US 2008/187485 relates to a method of extracting the hydrogen sulfide contained in a gas comprising aromatic hydrocarbons, wherein the following stages are carried out: a) contacting said gas with an absorbent solution so as to obtain a gas depleted in hydrogen sulfide and an absorbent solution loaded with hydrogen sulfide, b) heating and expanding the hydrogen sulfide- loaded absorbent solution to a predetermined temperature and pressure so as to release a gaseous fraction comprising aromatic hydrocarbons and to obtain an absorbent solution depleted in aromatic hydrocarbons, said temperature and pressure being so selected that said gaseous fraction comprises at least 50% of the aromatic hydrocarbons and at most 35% hydrogen sulfide contained in said hydrogen sulfide-loaded absorbent solution, c) thermally regenerating the absorbent solution depleted in aromatic hydrocarbon compounds so as to release a hydrogen sulfide-rich gaseous effluent and to obtain a regenerated absorbent solution.
  • 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 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 EP 2613867 relates to a CO2 scrubbing process which uses an absorbent mixture combination of an amine CO2 sorbent in combination with a non-nucleophilic, relatively stronger, typically nitrogenous, base.
  • Document WO 2015/066807 relates to a process for removing sulfur dioxide from a feed gas stream, which comprises (i) contacting the feed gas stream with an aqueous lean absorbing medium comprising a chemical solvent comprising a regenerable absorbent, a physical solvent, and one or more heat stable salts.
  • the regenerable absorbent is an amine.
  • Document US 10525404 relates to a process for removing acid gases from a fluid stream, wherein the fluid stream is contacted with an absorbent comprising a morpholine based amine, to obtain a treated fluid stream and a laden absorbent.
  • Document US 4545965 relates to a process for selectively separating hydsogen sulfide from gaseous mixtures which also contain carbon dioxide by chemical absorption with a substantially anhydrous solution of a tertiary amine, such as methyl diethanolamine, and an auxiliary organic solvent, such as sulfolane.
  • a tertiary amine such as methyl diethanolamine
  • an auxiliary organic solvent such as sulfolane
  • Document US 2015/0027055 relates to a process for increasing the selectivity of an alkanolamine absorption process for selectively removing hydrogen sulfide from a gas mixture which also contains carbon dioxide and possibly other acidic gases such as COS, HCN, CS2 and sulfur derivatives of Ci to C4 hydrocarbons.
  • Such method comprises contacting the gas mixture with a liquid absorbent which is a severely sterically hindered capped alkanolamine or more basic sterically hindered secondary and tertiary amine.
  • a first advantage of the selective elimination of H2S is related to energy consumption.
  • the minimization of the quantity of co-absorbed CO2 directly leads to minimizing the size and the operating costs of the installation.
  • minimizing the co-absorption of CO2 is important as the recovered H2S may then be sent to units implementing the Claus reaction in order to transform H2S into sulfur.
  • the performance of these “Claus" units is closely linked to the H2S concentration in the acid gas recovered at the outlet of the natural gas deacidification units: the more the H2S is concentrated, the more efficient these processes are.
  • the gas sent to the Claus installation should generally comprise at least 30 % by volume of H2S.
  • the polar, aprotic molecule is chosen from an organic compound comprising an amide functional group, a thioamide functional group, a di-amide (urea) functional group, a thiourea functional group, a tri-amide functional group, a phosphoramide functional group, a thiophosphoramide functional group or a sulfoxide functional group, and preferably the polar, aprotic molecule is chosen from N-methylpyrrolidone, dimethylformamide, caprolactams, dimethylacetamide, 1 ,3-dimethyl-2- imidazolidinone, N,N, dimethylpropyleneurea , hexamethylphosphoramide, dimethyl sulfoxide, dimethyl-thio-formamide, hexamethylphosphorothiotic triamide, and mixtures thereof.
  • the polar, aprotic molecule is present in the absorbent solution at a content from 10 wt% to 80 wt%, and preferably from 20 wt% to 50 wt%.
  • the amine compound is a tertiary amine, preferably 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 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 150 bar.
  • the step of putting in contact the gas mixture with an absorbent solution is carried out in an absorption column.
  • the gas mixture comprises at least one hydrocarbon, and is preferably natural gas.
  • the method further comprises a step of regenerating the absorbent solution loaded with hydrogen sulfide so as to collect a hydrogen sulfide stream and a regenerated absorbent solution.
  • regenerating the absorbent solution loaded with hydrogen sulfide is carried out by heating the absorbent solution loaded with hydrogen sulfide preferably at a temperature from 100 to 200°C, and more preferably from 110 to 150°C.
  • regenerating the absorbent solution loaded with hydrogen sulfide is carried out at an absolute pressure from 1 to 3 bar.
  • the regenerated absorbent solution is recycled in the step of putting in contact the gas mixture with an absorbent aqueous solution.
  • ratio of the carbon dioxide volume content in the gas mixture after the contacting step to carbon dioxide volume content in the gas mixture before the contacting step may be from 0.4 to 0.95 and preferably from 0.7 to 0.9 and/or wherein the ratio the hydrogen sulfide volume content in the gas mixture after the contacting step to hydrogen sulfide volume content in the gas mixture before the contacting step may be lower than 0.001 , and preferably lower than 0.0001 .
  • the invention further relates to a composition
  • a composition comprising: at least one polar, aprotic molecule; at least one amine compound; and water.
  • the at least one polar, aprotic molecule chosen from an organic compound comprising an amide functional group, a thioamide functional group, a di-amide (urea) functional group, a thiourea functional group, a tri-amide functional group, a phosphoramide functional group, a thiophosphoramide functional group or a sulfoxide functional group, and preferably the polar, aprotic molecule is chosen from N-methylpyrrolidone, dimethylformamide, caprolactams, dimethylacetamide, 1 ,3-dimethyl-2- imidazolidinone, N,N, dimethylpropyleneurea, hexamethylphosphoramide, dimethyl sulfoxide, dimethyl-thio-formamide, hexamethylphosphorothiotic triamide, and mixtures thereof.
  • the at least one amine compound is a tertiary amine, preferably 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 at least one polar, aprotic molecule is present in the composition at a content from 10 wt% to 80 wt%, and preferably from 20 wt% to 50 wt%.
  • the at least one amine compound is present in the composition at a content from 10 wt% to 60 wt%, and preferably from 15 wt% to 50 wt%.
  • the composition consistes of: the at least one polar, aprotic molecule; the at least one amine compound; and water.
  • the invention also relates to the use of a polar, aprotic molecule, for increasing the selectivity of hydrogen sulfide absorption relative to carbon dioxide absorption in the acid gas purification of a gas mixture comprising at least hydrogen sulfide and carbon dioxide carried out by contacting the gas mixture with an amine compound.
  • the polar, aprotic molecule is chosen from an organic compound comprising an amide functional group, a thioamide functional group, a di-amide (urea) functional group, a thiourea functional group, a tri-amide functional group, a phosphoramide functional group, a thiophosphoramide functional group or a sulfoxide functional group, and preferably the polar, aprotic molecule is chosen from N-methylpyrrolidone, dimethylformamide, caprolactams, dimethylacetamide, 1 ,3-dimethyl-2- imidazolidinone, N,N, dimethylpropyleneurea , hexamethylphosphoramide, dimethyl sulfoxide, dimethyl-thio-formamide, hexamethylphosphorothiotic triamide, and mixtures thereof.
  • the polar, aprotic molecule and the amine compound are present in an aqueous solution.
  • the amine compound is a tertiary amine, preferably 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 invention further relates to the use of a polar, aprotic molecule for inhibiting a chemical reaction converting a reactant to a product in an aqueous medium, wherein the polar aprotic molecule is put in contact with the aqueous medium.
  • the polar, aprotic molecule is chosen from an organic compound comprising an amide functional group, a thioamide functional group, a di-amide (urea) functional group, a thiourea functional group, a tri-amide functional group, a phosphoramide functional group, a thiophosphoramide functional group or a sulfoxide functional group, and preferably the polar, aprotic molecule is chosen from N-methylpyrrolidone, dimethylformamide, caprolactams, dimethylacetamide, 1 ,3-dimethyl-2- imidazolidinone, N,N, dimethylpropyleneurea , hexamethylphosphoramide, dimethyl sulfoxide, dimethyl-thio-formamide, hexamethylphosphorothiotic triamide, and mixtures thereof.
  • the present invention makes it possible to address the need expressed above.
  • the invention provides a method which makes it possible to separate hydrogen sulfide relative to carbon dioxide from a gas mixture comprising at least hydrogen sulfide and carbon dioxide with a high selectivity for hydrogen sulfide, and which makes it possible to efficiently regenerate the solution used for the separation method.
  • H2S hydrogen sulfide
  • CO2 carbon dioxide
  • an absorbent aqueous solution comprising at least one polar, aprotic molecule and at least one amine compound
  • H2S is selectively absorbed by the absorbent solution, relative to CO2. This is due to the fact that water is involved in the absorption of CO2, whereas it is to a lower degree involved in the absorption of H2S.
  • the present inventors believe that the polar, aprotic molecule interacts with the water present in the absorbent solution by the formation of hydrogen bonds. As a result, the water molecules become less available to react with the CO2. Such conditions favor the capture of H2S relative to the capture of CO2.
  • Figure 1 illustrates an installation used for the implementation of the method according to one embodiment of the invention.
  • Figure 2 shows vapor-liquid equilibrium data for CO2 (A, B, C) and H2S (D, E, F) in the presence of 2-(2-diethylaminoethoxy)ethanol, with and without a polar aprotic molecule.
  • the partial pressure of the gas (Pa) can be read on the Y-axis and the liquid-phase acid gas loading (mole of acid gas / mole of amine) can be read on the X-axis.
  • Figure 3 shows vapor-liquid equilibrium data for CO2 (A, B) and H2S (C, D) in the presence of 2-(2-diethylaminoethoxy)ethanol, with and without a polar protic molecule.
  • the partial pressure of the gas (Pa) can be read on the Y-axis and the liquid-phase acid gas loading (mole of acid gas / mole of amine) can be read on the X-axis.
  • Figure 4 shows vapor-liquid equilibrium data for CO2 (A, B, C) and H2S (D, E, F) in the presence of methyldiethanolamine, with and without a polar aprotic molecule.
  • the partial pressure of the gas (Pa) can be read on the Y-axis and the liquid-phase acid gas loading (mole of acid gas / mole of amine) can be read on the X-axis.
  • Figure 5 shows vapor-liquid equilibrium data for CO2 (A, B, C) and H2S (D, E, F) in the presence of an amine compound (methyldiethanolamine or 2-(2- diethylaminoethoxy)ethanol), and with and without a polar aprotic molecule.
  • the partial pressure of the gas (Pa) can be read on the Y-axis and the liquid-phase acid gas loading (mole of acid gas / mole of amine) can be read on the X-axis.
  • Figure 6 illustrates the absorption of CO2 (A, B) and H2S (C, D) over time in the presence of an amine compound (methyldiethanolamine or 2-(2- diethylaminoethoxy)ethanol), and with and without a polar aprotic molecule.
  • the fraction of acid gas absorbed can be read on the Y-axis and the time (seconds) 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. According to other embodiments, 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 hydrogen sulfide and carbon dioxide.
  • the gas mixture of the present invention may for example comprise hydrogen sulfide in a content from 30 ppm to 40 % by volume, and preferably from 0.5 to 10 % 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 comprise carbon dioxide in a content from 0.5 to 80 % by volume, preferably from 1 to 50 % by volume, and more preferably from 1 to 15 % 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 selectively separate H2S relative to CO2 from the gas mixture described above.
  • the absorbent solution according to the invention is an aqueous solution that comprises at least one polar, aprotic molecule and at least one amine compound.
  • the amine compound of the absorbent solution may react with H2S.
  • the amine compound may also react with CO2.
  • the amine compound is a tertiary amine. In fact, while primary and secondary amines react rapidly with both H2S and CO2, tertiary amines react rapidly with H2S but more slowly with CO2.
  • the amine compound may be for example aliphatic, cyclic or aromatic.
  • the amine compound is selected from the 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 amine compound may further comprise at least one oxygen and/or at least one sulfur atom.
  • the amine compound 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
  • (2,2'-(((methylazanediyl)bis(ethane-2,1 -diyl))bis(oxy))diethanol 2-(2-diethylaminoethoxy)ethanol
  • the amine compound may be a tertiary amine comprising a morpholinone function, such as 4-morpholin-4- ylpentan-1 -ol.
  • the amine compound 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.
  • amine compound 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- diisopropylaminoethanol
  • TMPDA N,N,N',N'-tetramethylpropanediamine
  • TEPDA N,N,N'
  • 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 --
  • amine compounds 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'-tetramethylethylenediamine
  • the amine compound 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 amine compound may be (or comprise) a demixing amine.
  • demixing amine is meant an amine or mixture of amines which, under specific conditions (for example in a certain temperature range or depending on the concentration of absorbed compound), makes it possible to form two immiscible liquid phases.
  • the phenomenon of demixing can be induced by an increase of the loading rate of the absorbent solution and/or by an increase or decrease of the temperature.
  • the demixing amine may be chosen from an amine described in documents EP 2889073, EP 1996313, EP 3017857 and EP 2193833.
  • the demixing amine can be chosen from N-methylpiperidine, 2- methylpiperidine, N-ethylpiperidine, 2-(diethylamino)-ethanol (DEEA), 2- (ethylamino)ethanol (EAE), 2-(methylamino)ethanol(MMEA), 2- (ethylamino)ethanol (EMEA), N-methyl-1 ,3-diaminopropane (MAPA), N,N- dimethylcyclohexylamine (DMCA), diethylenetriamine (DETA), 1 ,4- butanediamine (BDA), N,N,N,N,N, pentamethyldiethylenetriamine (PMDETA), N,N,N',N',N”-pentamethyldipropylenetriamine (PMDPTA), N,N,N',N'-tetramethyl- 1 ,6-hexanediamine (TMHDA), potassium prolinate (ProK), as well as their combinations.
  • DEEA dieth
  • the amine compound(s) may be present in the absorbent solution at a total content from 10 wt% to 60 wt%, and preferably from 15 wt% to 50 wt% relative to the weight of the absorbent solution.
  • the amine compound may have a pKa from 8.5 to 14, and preferably from 8.5 to 12. It has been found that a better selectivity can be achieved when the amine compound is more basic, and in particular more basic than MDEA.
  • the absorbent solution further comprises a polar, aprotic molecule.
  • polyi is meant a molecule that has a dipole moment equal to or higher than 1 .5 D at 25°C, and preferably equal to or higher than 3 D, or 4 D, or 4.5 D, or 5 D at 25°C.
  • the dipole moment can be measured by using a dipole meter and by interpretation of the results using the Debey equation.
  • aprotic is meant a molecule which does not contain any acidic hydrogen and thus does not act as a hydrogen bond donor.
  • the aprotic molecule is free of -OH, -NH, -SH, and -PH groups.
  • the polar, aprotic molecule acts as a co-solvent together with water, in the aqueous solution.
  • its molecular weight is less than 500 g/mol, more preferably it is less than 300 g/mol, and even more preferably it is less than 200 g/mol.
  • the polar, aprotic molecule may be chosen from an organic compound comprising an amide functional group, a thioamide functional group, a di-amide (urea) functional group, a thiourea functional group, a tri-amide functional group, a phosphoramide functional group, a thiophosphoramide functional group or a sulfoxide functional group.
  • the polar aprotic compound can be chosen from a monoamide such as N- methylpyrrolidone (NMP), caprolactams, dimethylformamide (DMF), dimethylacetamide (DMA), a diamide such as 1 ,3-dimethyl-2-imidazolidinone (DMI) and N,N, dimethylpropyleneurea (DMPA), a triamide such as hexamethylphosphoramide (HMPA), dimethyl sulfoxide (DMSO), the thio- structural analogues of the above molecules (wherein oxygen is replaced by sulfur) such as dimethyl-thio-formamide, hexamethylphosphorothiotic triamide, and mixtures thereof.
  • NMP N- methylpyrrolidone
  • DMF dimethylformamide
  • DMA dimethylacetamide
  • DMA diamide
  • DMA diamide
  • DMA diamide
  • DMA diamide
  • DMA diamide
  • DMA diamide
  • DMA diamide
  • DMA di
  • the polar, aprotic molecule(s) may be present in the absorbent solution at a total content from 10 wt% to 80 wt%, and preferably from 20 wt% to 50 wt% relative to the weight of the absorbent solution.
  • the polar, aprotic molecule are involved in strong hydrogen bonding with the water which acts as a solvent of the absorbent solution. Some strongly polar aprotic molecules can bind several water molecules at once. Due to the so-called hydrophobic effect, some polar, aprotic molecules form organized structures which surround the water molecules. As a result of one or both described mechanisms, the water molecules are “immobilized” and become less available to react with other components (such as the CO2 molecules for example).
  • the water may be present in the absorbent solution in an amount from 1 wt% to 60 wt%, and preferably from 10 wt% to 50 wt% relative to the weight of the absorbent solution.
  • the absorbent aqueous solution may consist of the amine compound, the polar, aprotic molecule and water.
  • the absorbent solution may comprise one or more other additional compounds.
  • the method according to the present invention makes it possible to selectively separate H2S relative to CO2 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 aqueous 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 aqueous 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 0.23 x 10 6 to 56 x 10 6 Nm 3 /day.
  • the absorbent aqueous solution may have a flow rate during this step from 800 to 50000 m 3 /day.
  • the step of putting in contact the gas mixture with an absorbent aqueous 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 aqueous 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 absorption solution for a time period from 10 to 500 seconds, and preferably from 10 to 300 seconds.
  • a stream of gas mixture depleted in 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 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 aqueous solution recovered from the bottom of the absorption column 1 contains no hydrocarbons or only a residual amount of hydrocarbons.
  • the CO2 contained in the initial gas mixture is predominantly recovered in the stream of gas mixture collected from the top of the absorption column 1
  • this step makes it possible to separate on the one hand the gas comprising hydrocarbons and (most of the) CO2 and on the other hand the absorption aqueous solution and (most of the) H2S.
  • the stream of gas mixture collected from the top of the absorption column 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 5 ppm by volume.
  • This content can be measured by gas phase chromatography.
  • this content may be from 0.1 to 1 ppm; or from 1 to 2 ppm, or from 2 to 5 ppm; or from 5 to 20 ppm, or from 20 to 50 ppm; or from 50 to 100 ppm by volume relative to the volume of the gas mixture depleted in hydrogen sulfide.
  • the stream of gas mixture collected from the top of the absorption column 1 may have a content in CO2 from 0.1 to 10 %, and preferably from 0.5 to 5 % by volume relative to the volume of the stream of gas mixture depleted in hydrogen sulfide.
  • the ratio Rs of the H2S volume content in the gas mixture after the contacting step to H2S volume content in the gas mixture before the contacting step may be lower than 0.001 , and preferably lower than 0.0001 .
  • the ratio Rc of the CO2 volume content in the gas mixture after the contacting step to CO2 volume content in the gas mixture before the contacting step may be from 0.4 to 0.95, and preferably from 0.7 to 0.9.
  • the ratio Rc/Rs representing the selective removal of H2S relative to CO2 in the gas mixture may range from 400 to 1000, and preferably from 7000 to 9000. This ratio may notably be from 400 to 1000; or from 1000 to 2000; or from 2000 to 3000; or from 3000 to 4000; or from 4000 to 5000; or from 5000 to 6000; or from 6000 to 7000; or from 7000 to 8000; or from 8000 to 9000; or from 9000 to 10000.
  • the method according to the present invention may further comprise an optional step of removing residual hydrocarbon from the absorbent aqueous solution loaded with 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 aqueous solution loaded with 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 aqueous solution loaded with hydrogen sulfide can be regenerated in order to collect a hydrogen sulfide stream 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 aqueous solution loaded with 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 aqueous solution loaded with hydrogen sulfide and promote desorption of the hydrogen sulfide and recovery of a gas enriched in 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 H2S and optionally other impurities (such as residual CO2, mercaptans) remaining in the absorbent aqueous solution loaded with 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 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 150°C and at an absolute pressure from 1 bar to 3 bar.
  • the H2S and optionally impurities may be recovered as a gaseous stream at the top of the regeneration column 9 (H2S collecting line 10).
  • the gaseous stream exiting the regeneration column 9 may comprise from 40 to 97 % by volume, and preferably from 70 to 97 % by volume of H2S relative to the volume of the gaseous stream exiting the regeneration column 9.
  • the gaseous stream exiting the regeneration column 9 may comprise from 0 to 60 % by volume and preferably from 0 to 30 % by volume of CO2 relative to the volume of the gaseous stream exiting the regeneration column 9.
  • the ratio of H2S volume concentration to CO2 volume concentration in the gaseous stream exiting the regeneration column 9 may be equal to or higher than 0.6 and preferably from equal to or higher than 2.5.
  • the steam generated in the column (deriving from the absorbent solution therefore comprising the amine compound, the polar, aprotic molecule 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.
  • a heat exchanger 7 may be provided in order to preheat the absorbent solution loaded with 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 aqueous solution, for example by entering the absorption column 1 via the lean solution collecting line 11 .
  • the above detailed method for selectively removing H2S relative to CO2 can be implemented to purify a gas (gas mixture described above), for example in order to render the gas available for the gas distribution network.
  • the purification of the gas mixture may include removing H2S and CO2 and other possible impurities.
  • H2S and CO2 are essentially removed separately, it is possible to recover high-purity CO2 and use it in other applications.
  • the stream of gas mixture depleted in hydrogen sulfide recovered from the top of the absorption column 1 and the H2S recovered at the top of the regeneration column 9 can be treated separately and independently from one another.
  • the stream of gas mixture depleted in hydrogen sulfide can first be treated in order to separate gas impurities, notably CO2, from the gas mixture.
  • this step may be carried out in an AGR (Acid Gas Removal) Unit.
  • the AGR unit may comprise an absorption column (similar to the absorption column used above) or any other unit configured for gasliquid contact.
  • the AGR unit may also comprise a regeneration column (similar to the regeneration column used above).
  • the gas mixture depleted in hydrogen sulfide may be put in contact with an absorption solution comprising an absorbent compound capable of capturing CO2.
  • the absorbent compound may preferably include an amine compound such as for example diethanol amine (DEA), methyl-di-ethanol amine (MDEA), activated MDEA or any other amine known in the art for absorbing CO2 with optionally an activator such as piperazine and/or other additional compounds such as TDG.
  • DEA diethanol amine
  • MDEA methyl-di-ethanol amine
  • activated MDEA any other amine known in the art for absorbing CO2 with optionally an activator such as piperazine and/or other additional compounds such as TDG.
  • the absorbent solution may have a content in the amine compound from 20 to 50 % by weight relative to the total weight of the absorbent solution.
  • the absorbent solution may further comprise a solvent such as water.
  • the gas mixture depleted in hydrogen sulfide may have a flow rate from 0.23 x 10 6 to 56 x 10 6 Nm 3 /day.
  • the absorbent solution may have a flow rate from 800 to 50000 m 3 /day.
  • the step of putting the gas mixture depleted in hydrogen sulfide in contact with an absorption solution may be carried out at a temperature from 25 to 100°C.
  • the step of putting the gas mixture depleted in hydrogen sulfide in contact with an absorption solution may be carried out at an absolute pressure from 1 to 150 bar, and preferably from 1 to 80 bar.
  • a gas stream depleted in CO2 (and other gas impurities) is recovered on the one hand (for example from the top of the column) and an absorbent solution loaded with CO2 is recovered on the other hand (for example at the bottom of the column).
  • the gas stream depleted in CO2 may have a content in CO2 equal to or lower than 10 % by volume, and preferably lower than 2 % by volume relative to the volume of the gas stream depleted in CO2.
  • the gas stream depleted in CO2 may undergo other treatments such as drying (dehydration).
  • the gas stream depleted in CO2 may directly be available for the gas distribution network.
  • the absorbent solution loaded with CO2 may undergo a treatment in order to regenerate the absorbent solution and recover the captured CO2. This may be carried out for example in the regeneration column (wherein the absorbent solution loaded with CO2 may be heated in order to generate steam and promote desorption of the CO2 and recovery of a gas enriched in CO2 at the top of the column.
  • the regenerated absorbent may then be recycled in the gas purification method for example in the step of putting the gas mixture depleted in hydrogen sulfide in contact with the absorbent solution, thus the regenerated absorbent may be fed to the absorption column.
  • heating the absorbent solution loaded with CO2 in the regeneration column may be carried out at a temperature from 100 to 200°C, and more preferably from 110 to 150°C and at an absolute pressure from 1 to 3 bar.
  • the gas enriched in CO2 may comprise less than 2000 ppm, and preferably less than 200 ppm of H2S relative to the volume of the gas enriched in CO2.
  • the CO2 stream may then be dehydrated, pressurized and optionally filtered, so as it can be used in enhanced oil recovery (EOR) or so as it can be stored.
  • the H2S recovered (as explained above) after exiting the regeneration column 9 may be converted into elemental sulfur, for example in a Claus unit.
  • a Claus unit operates with an oxidizer, such as air, pure oxygen or mixtures of oxygen and nitrogen, in a combustion chamber.
  • the Claus unit makes it possible to covert H2S into elemental sulfur in two steps, a thermal step (wherein H2S is partially oxidated to generate SO2) and a catalytic step (wherein the generated SO2 reacts with the remaining H2S to produce sulfur).
  • a first stream comprising elemental sulfur is recovered on the one hand.
  • This stream may also comprise polysulfides and some H2S.
  • This stream may be degassed in order to transform polysulfides to H2S and then remove H2S.
  • a second, tail gas stream comprising sulfur compounds is recovered.
  • This stream may comprise for example H2S and/or SO2 that have not reacted in the Claus unit. It may also comprise mercaptans, COS compounds, residues of methane and other hydrocarbons and residues of CO2.
  • the tail gas stream may be fed into a TGT (Tail Gas Treatment) unit.
  • Treatment in such unit allows to convert the various sulfur species contained in the tail gas stream into H2S which may then be removed from the tail gas and recycled in the Claus unit. This makes it possible to achieve a high sulfur recovery, notably higher than 90 %, preferably higher than 95 %, and more preferably higher than 99 %.
  • a typical TGT unit may include a reducing gas generator, a hydrogenation reactor, a quench tower, and an absorber unit. More particularly, in the reducing gas regenerator (RGG), gas, notably methane, may be burnt in the presence of steam in order to produce hydrogen (H2) and carbon monoxide (CO) which are then mixed with the tail gas stream.
  • RMG reducing gas regenerator
  • This mixture may then enter the hydrogenation reactor wherein the sulfur compounds are converted into H2S.
  • the hydrogenation reactor may comprise a catalyst bed with hydrogenation catalysts such as C0M0 on which the hydrogenation is carried out.
  • the tail gas mixture exiting the hydrogenation reactor may enter the quench tower wherein said mixture is cooled.
  • the gas may be cooled for example at a temperature from 30 to 60°C.
  • the cooled tail gas mixture exiting the quench tower may be treated so as to separate the sulfur compounds from other constituents of the cooled tail gas mixture thereby producing a treated tail gas stream on the one hand and a gas stream enriched in hydrogen sulfide on the other hand. This step may be carried out in the absorber unit.
  • the absorber in the absorber unit may be an amine or any other compound capable of capturing the hydrogen sulfide.
  • the cooled tail gas mixture may be contacted counter-currently with the absorber so as to capture the hydrogen sulfide present in the mixture.
  • the absorber unit may comprise an absorption column and a regeneration column (in order to regenerate the absorber from the hydrogen sulfide).
  • the gas stream enriched in hydrogen sulfide may be recycled to the Claus unit.
  • the treated tail gas stream may be burned, for example in an incinerator, in order to produce a flue gas.
  • the present invention makes it possible to capture and recover CO2 in a cost-effective way, which can be efficientlyzed in various applications, such as enhanced oil recovery.
  • the present invention further relates to the use of the polar, aprotic molecule (as described above) for inhibiting a chemical reaction converting a reactant to a product in an aqueous medium, wherein the polar aprotic molecule is put in contact with the aqueous medium.
  • the polar, aprotic molecule creates hydrogen bonds with the water molecules of the aqueous medium. As a result, it is believed that the water molecules are “immobilized” and become less available to react with other components. Thus, a reaction that is carried out in the presence of water, is inhibited when such polar, aprotic molecule is present in the aqueous medium.
  • reaction between CO2, and the amine compound described above requires the presence of water.
  • water becomes less available to participate in the reaction and thus the CO2 capture by the amine compound is inhibited.
  • a “static-synthetic" technique based on a closed-circuit method is used for the determination of acid gas solubility in the different solvents.
  • the equilibrium cell is equipped with pressure transducers. Temperature is given by two platinum probes located at the upper and lower flanges (possibility to determine the gradient of temperature).
  • An internal stirring system with external motor reduced the time required to reach equilibrium. In case of mixture, the vapor phase is analyzed.
  • the apparatus is equipped with at least one online capillary sampler (ROLSI®) which is capable of withdrawing and sending micro samples to a gas chromatograph without perturbing the equilibrium conditions over numerous samplings, thus leading to repeatable and reliable results.
  • ROLSI® online capillary sampler
  • Analytical work was carried out using a gas chromatograph (PERICHROM model PR2100, France) equipped with a thermal conductivity detector (TCD) connected to a data software system. Helium is used as the carrier gas in this experiment.
  • DMI also tends to reduce H2S absorption, but to a lesser degree than CO2 absorption.
  • the H2S absorption also becomes almost purely physical (straight line).
  • the physical thermodynamic selectivity being much larger than the chemical thermodynamic selectivity, the addition of DMI therefore also gradually increases the thermodynamic selectivity.
  • DMI as a polar aprotic molecule makes it possible to more selectively absorb H2S relative to CO2.
  • vapor-liquid equilibrium experiments were performed in order to examine the influence of a polar aprotic molecule (hexamethylphosphoramide or HMPA, having a dipole moment of approx. 5.4 D at 25°C) on the absorption of CO2 and H2S, in the presence of N- methyldiethanolamine (MDEA).
  • HMPA hexamethylphosphoramide
  • MDEA N- methyldiethanolamine
  • HMPA For H2S absorption, HMPA only slightly reduces or even increases H2S absorption, depending on conditions.
  • HMPA as a polar aprotic molecule makes it possible to more selectively absorb H2S relative to CO2. HMPA is believed to be even more effective than DM I.
  • Example 4 influence of the choice of amine compound in the presence of HMPA on CO2 and H2S equilibrium absorption
  • Example 2 The same experimental set-up as the one described in Example 1 was used. However, a second gas chromatograph has been added in parallel to be able to frequently analyze the composition of the gas phase as a function of the time.

Abstract

L'invention concerne un procédé de séparation sélective de sulfure d'hydrogène par rapport au dioxyde de carbone à partir d'un mélange gazeux comprenant au moins du sulfure d'hydrogène et du dioxyde de carbone, le procédé comprenant la mise en contact du mélange gazeux avec une solution aqueuse absorbante comprenant au moins un solvant polaire, aprotique et au moins un composé aminé, de manière à obtenir un mélange gazeux appauvri en sulfure d'hydrogène, et une solution aqueuse absorbante chargée en sulfure d'hydrogène. L'invention concerne en outre une composition comprenant au moins une molécule polaire, aprotique ; au moins un composé aminé ; et de l'eau. L'invention concerne en outre l'utilisation d'un composé polaire, molécule aprotique, pour augmenter la sélectivité de l'absorption de sulfure d'hydrogène par rapport à l'absorption de dioxyde de carbone dans la purification de gaz acide d'un mélange gazeux comprenant au moins du sulfure d'hydrogène et du dioxyde de carbone réalisé par mise en contact du mélange gazeux avec un composé amine et également sur l'utilisation pour inhiber une réaction chimique convertissant un réactif en un produit dans un milieu aqueux, la molécule aprotique polaire étant mise en contact avec le milieu aqueux.
PCT/IB2020/001110 2020-12-17 2020-12-17 Procédé pour l'élimination sélective du sulfure d'hydrogène à partir d'un courant de gaz WO2022129975A1 (fr)

Priority Applications (1)

Application Number Priority Date Filing Date Title
PCT/IB2020/001110 WO2022129975A1 (fr) 2020-12-17 2020-12-17 Procédé pour l'élimination sélective du sulfure d'hydrogène à partir d'un courant de gaz

Applications Claiming Priority (1)

Application Number Priority Date Filing Date Title
PCT/IB2020/001110 WO2022129975A1 (fr) 2020-12-17 2020-12-17 Procédé pour l'élimination sélective du sulfure d'hydrogène à partir d'un courant de gaz

Publications (1)

Publication Number Publication Date
WO2022129975A1 true WO2022129975A1 (fr) 2022-06-23

Family

ID=74587077

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/IB2020/001110 WO2022129975A1 (fr) 2020-12-17 2020-12-17 Procédé pour l'élimination sélective du sulfure d'hydrogène à partir d'un courant de gaz

Country Status (1)

Country Link
WO (1) WO2022129975A1 (fr)

Citations (21)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4545965A (en) 1980-07-04 1985-10-08 Snamprogetti, S.P.A. Process of selective separation of hydrogen sulfide from gaseous mixtures containing also carbon dioxide
WO1987001961A1 (fr) 1985-10-04 1987-04-09 Societe Nationale Elf Aquitaine (Production) Procede et dispositif pour l'extraction selective de l'h2s d'un gaz en contenant
US5209914A (en) 1988-05-24 1993-05-11 Elf Aquitaine Production Liquid absorbing acidic gases and use thereof of in deacidification of gases
US20080025893A1 (en) 2004-03-09 2008-01-31 Basf Aktiengesellschaft Method For The Removal Of Carbon Dioxide From Gas Flows With Low Carbon Dioxide Partial Pressures
US20080187485A1 (en) 2006-02-06 2008-08-07 Julia Magne-Drisch Method of extracting the hydrogen sulfide contained in a hydrocarbon gas
EP1996313A1 (fr) 2006-03-10 2008-12-03 Ifp Procede de desacidification d'un gaz par solution absorbante avec regeneration fractionnee par chauffage
EP2193833A1 (fr) 2008-11-20 2010-06-09 Ifp Procédé de désacidification d'un gaz par solution absorbante avec démixtion en cours de régénération
US20100288125A1 (en) 2009-05-12 2010-11-18 Gerald Vorberg Absorption medium for the selective removal of hydrogen sulfide from fluid streams
EP2613867A1 (fr) 2010-09-09 2013-07-17 ExxonMobil Research and Engineering Company PROCÉDÉ D'ÉPURATION DU CO2 PAR UNE AMINE-BASE NON NUCLÉOPHILE EN MÉLANGE POUR UNE ADSORPTION AMÉLIORÉE À DES TEMPÉRATURES PLUS ÉLEVÉES& xA;
WO2013174902A1 (fr) 2012-05-25 2013-11-28 Total S.A. Procede d'elimination selective du sulfure d'hydrogene de melanges gazeux et utilisation d'un thioalcanol pour l'elimination selective du sulfure d'hydrogene
US20140030177A1 (en) * 2012-07-30 2014-01-30 Exxonmobil Research And Engineering Company High cyclic capacity amines for high efficiency co2 scrubbing processes
US20150027056A1 (en) * 2013-07-25 2015-01-29 Exxonmobil Research And Engineering Company Separation of hydrogen sulfide from natural gas
US20150027055A1 (en) 2013-07-29 2015-01-29 Exxonmobil Research And Engineering Company Separation of hydrogen sulfide from natural gas
WO2015066807A1 (fr) 2013-11-07 2015-05-14 Cansolv Technologies Inc. Procédé de capture de dioxyde de soufre dans un courant de gaz
EP2889073A1 (fr) 2013-12-25 2015-07-01 Kabushiki Kaisha Toshiba Appareil d'élimination de gaz acides et procédé d'élimination de gaz acides
EP3017857A1 (fr) 2014-11-04 2016-05-11 IFP Energies nouvelles Procede de desacidification d'un effluent gazeux par une solution absorbante avec injection de vapeur dans la solution absorbante regeneree et dispositif pour sa mise en oeuvre
EP3083012A2 (fr) 2013-12-19 2016-10-26 C-Capture Ltd. Système de capture et de libération de gaz acides
US20160375399A1 (en) * 2015-06-24 2016-12-29 Gwangju Institute Of Science And Technology Carbon dioxide absorbent and method for regenerating carbon dioxide absorbent
US20170072361A1 (en) * 2014-03-07 2017-03-16 Korea Institute Of Energy Research Carbon dioxide collecting apparatus and method using independent power generation means
JP2017104775A (ja) * 2015-12-07 2017-06-15 国立研究開発法人産業技術総合研究所 二酸化炭素吸収液および二酸化炭素分離回収方法
US10525404B2 (en) 2016-04-25 2020-01-07 Basf Se Use of morpholine-based hindered amine compounds for selective removal of hydrogen sulfide

Patent Citations (22)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4545965A (en) 1980-07-04 1985-10-08 Snamprogetti, S.P.A. Process of selective separation of hydrogen sulfide from gaseous mixtures containing also carbon dioxide
WO1987001961A1 (fr) 1985-10-04 1987-04-09 Societe Nationale Elf Aquitaine (Production) Procede et dispositif pour l'extraction selective de l'h2s d'un gaz en contenant
US5209914A (en) 1988-05-24 1993-05-11 Elf Aquitaine Production Liquid absorbing acidic gases and use thereof of in deacidification of gases
US20080025893A1 (en) 2004-03-09 2008-01-31 Basf Aktiengesellschaft Method For The Removal Of Carbon Dioxide From Gas Flows With Low Carbon Dioxide Partial Pressures
US20080187485A1 (en) 2006-02-06 2008-08-07 Julia Magne-Drisch Method of extracting the hydrogen sulfide contained in a hydrocarbon gas
EP1996313A1 (fr) 2006-03-10 2008-12-03 Ifp Procede de desacidification d'un gaz par solution absorbante avec regeneration fractionnee par chauffage
EP2193833A1 (fr) 2008-11-20 2010-06-09 Ifp Procédé de désacidification d'un gaz par solution absorbante avec démixtion en cours de régénération
US20100288125A1 (en) 2009-05-12 2010-11-18 Gerald Vorberg Absorption medium for the selective removal of hydrogen sulfide from fluid streams
EP2613867A1 (fr) 2010-09-09 2013-07-17 ExxonMobil Research and Engineering Company PROCÉDÉ D'ÉPURATION DU CO2 PAR UNE AMINE-BASE NON NUCLÉOPHILE EN MÉLANGE POUR UNE ADSORPTION AMÉLIORÉE À DES TEMPÉRATURES PLUS ÉLEVÉES& xA;
WO2013174902A1 (fr) 2012-05-25 2013-11-28 Total S.A. Procede d'elimination selective du sulfure d'hydrogene de melanges gazeux et utilisation d'un thioalcanol pour l'elimination selective du sulfure d'hydrogene
US20140030177A1 (en) * 2012-07-30 2014-01-30 Exxonmobil Research And Engineering Company High cyclic capacity amines for high efficiency co2 scrubbing processes
US20150027056A1 (en) * 2013-07-25 2015-01-29 Exxonmobil Research And Engineering Company Separation of hydrogen sulfide from natural gas
US20150027055A1 (en) 2013-07-29 2015-01-29 Exxonmobil Research And Engineering Company Separation of hydrogen sulfide from natural gas
WO2015017240A1 (fr) * 2013-07-29 2015-02-05 Exxonmobil Research And Engineering Company Séparation de sulfure d'hydrogène de gaz naturel
WO2015066807A1 (fr) 2013-11-07 2015-05-14 Cansolv Technologies Inc. Procédé de capture de dioxyde de soufre dans un courant de gaz
EP3083012A2 (fr) 2013-12-19 2016-10-26 C-Capture Ltd. Système de capture et de libération de gaz acides
EP2889073A1 (fr) 2013-12-25 2015-07-01 Kabushiki Kaisha Toshiba Appareil d'élimination de gaz acides et procédé d'élimination de gaz acides
US20170072361A1 (en) * 2014-03-07 2017-03-16 Korea Institute Of Energy Research Carbon dioxide collecting apparatus and method using independent power generation means
EP3017857A1 (fr) 2014-11-04 2016-05-11 IFP Energies nouvelles Procede de desacidification d'un effluent gazeux par une solution absorbante avec injection de vapeur dans la solution absorbante regeneree et dispositif pour sa mise en oeuvre
US20160375399A1 (en) * 2015-06-24 2016-12-29 Gwangju Institute Of Science And Technology Carbon dioxide absorbent and method for regenerating carbon dioxide absorbent
JP2017104775A (ja) * 2015-12-07 2017-06-15 国立研究開発法人産業技術総合研究所 二酸化炭素吸収液および二酸化炭素分離回収方法
US10525404B2 (en) 2016-04-25 2020-01-07 Basf Se Use of morpholine-based hindered amine compounds for selective removal of hydrogen sulfide

Similar Documents

Publication Publication Date Title
US7485275B2 (en) Method for removing acid gases and ammonia from a fluid stream
US6939393B2 (en) Method for neutralizing a stream of fluid, and washing liquid for use in one such method
US7419646B2 (en) Method of deacidizing a gas with a fractional regeneration absorbent solution
US8845787B2 (en) Absorbent solution based on N, N, N′, N′-tetramethylhexane-1,6-diamine and on a particular amine comprising primary or secondary amine functions and method for removing acid compounds from a gaseous effluent
DK2391435T3 (en) Absorbent CONTAINING cyclic amines FOR REMOVING THE SURE GASES
EP3145621B1 (fr) Procédé amélioré d'élimination de gaz acides au moyen d'une solution absorbante comprenant des composés aminés
US20170320008A1 (en) Process For Selectively Removing Hydrogen Sulphide From Gaseous Mixtures And Use Of A Thioalkanol For Selectively Removing Hydrogen Sulphide
US7374734B2 (en) Absorbing agent and method for eliminating acid gases from fluids
US20130011314A1 (en) Method of removing acid compounds from a gaseous effluent with an absorbent solution based on i, ii/iii diamines
KR20150023481A (ko) 수성 알칸올아민 용액 및 가스 혼합물로부터 황화수소의 제거 방법
MX2015002912A (es) Proceso para la separcion de gases acidos de una corriente de fluido que comprende agua.
US9421493B2 (en) Method for eliminating acid compounds from a gaseous effluent with an absorbent solution made from bis(amino-3-propyl)ethers
RU2745356C1 (ru) Энергоэффективный способ отделения сероводорода от газовых смесей с применением смеси гибридных растворителей
KR20180058723A (ko) 황화수소의 선택적 제거 방법
DK2691163T3 (en) DETENTION OF AMINES FOR REMOVAL OF SURE GAS EMISSIONS BY AMIN-absorbents
RU2736714C1 (ru) Способ отделения сероводорода от газовых смесей с использованием гибридной смеси растворителей
EA037511B1 (ru) Способ селективного удаления кислых газов из потоков текучей среды с использованием смеси гибридного растворителя
WO2022129975A1 (fr) Procédé pour l'élimination sélective du sulfure d'hydrogène à partir d'un courant de gaz
WO2022129977A1 (fr) Procédé de récupération de dioxyde de carbone de haute pureté à partir d'un mélange gazeux
EP2632568A1 (fr) Utilisation du 2-(3-aminopropoxy)éthan-1-ol comme absorbant pour éliminer les gaz acides
Duval Natural gas sweetening
WO2022129974A1 (fr) Milieu d'élimination sélective de sulfure d'hydrogène à partir d'un courant gazeux
WO2023073389A1 (fr) Procédé de purification d'un mélange gazeux comprenant du dioxyde de carbone et éventuellement du sulfure d'hydrogène
RU2729808C1 (ru) Способ для снижения потребления энергии при регенерации гибридных растворителей
US20150314230A1 (en) Absorbent solution based on amines belonging to the n-alkylhydroxypiperidine family and method for removing acid compounds from a gaseous effluent with such a solution

Legal Events

Date Code Title Description
121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 20851414

Country of ref document: EP

Kind code of ref document: A1

NENP Non-entry into the national phase

Ref country code: DE

122 Ep: pct application non-entry in european phase

Ref document number: 20851414

Country of ref document: EP

Kind code of ref document: A1