WO2022129974A1 - Milieu d'élimination sélective de sulfure d'hydrogène à partir d'un courant gazeux - Google Patents

Milieu d'élimination sélective de sulfure d'hydrogène à partir d'un courant gazeux Download PDF

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Publication number
WO2022129974A1
WO2022129974A1 PCT/IB2020/001109 IB2020001109W WO2022129974A1 WO 2022129974 A1 WO2022129974 A1 WO 2022129974A1 IB 2020001109 W IB2020001109 W IB 2020001109W WO 2022129974 A1 WO2022129974 A1 WO 2022129974A1
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hydrogen sulfide
absorbent solution
absorbent
gas mixture
liquid phase
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PCT/IB2020/001109
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English (en)
Inventor
Frédérick DE MEYER
Renaud Cadours
Bénédicte POULAIN
Claire Weiss
Eric CLOAREC
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Totalenergies Onetech
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Priority to PCT/IB2020/001109 priority Critical patent/WO2022129974A1/fr
Publication of WO2022129974A1 publication Critical patent/WO2022129974A1/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
    • B01D53/1418—Recovery of products
    • 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
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2256/00—Main component in the product gas stream after treatment
    • B01D2256/22—Carbon dioxide
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • 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

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.
  • the present invention further relates to the use of a solution comprising a demixing amine to selectively absorb 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
  • 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.
  • 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 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 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 2889073 relates to an acid gas removal apparatus including an absorption tower in which gas containing acid gas is put into contact with an acid gas absorbent which is a solution containing a thermosensitive nitrogencontaining compound and having a LCST (lower critical solution temperature) at a predetermined temperature to absorb the acid gas into the absorbent and remove the acid gas from the gas; a first heater heating the absorbent to LCST of the solution or more; a tank phase-separating the absorbent into a rich absorbent phase and a lean absorbent phase whose content of the thermosensitive compound is higher; a second heater heating the rich phase; a regeneration tower releasing the acid gas in the rich phase; a third heater provided at the regeneration tower heating the rich phase.
  • an absorption tower in which gas containing acid gas is put into contact with an acid gas absorbent which is a solution containing a thermosensitive nitrogencontaining compound and having a LCST (lower critical solution temperature) at a predetermined temperature to absorb the acid gas into the absorbent and remove the acid gas from the gas;
  • Document EP 1996313 relates to a process for deacidifying a gaseous effluent comprising acidic compounds.
  • This process comprises putting the gaseous effluent in contact with an absorbent solution so as to obtain a gaseous effluent depleted in acid compounds and an absorbent solution loaded with acid compounds, the absorbent solution being chosen for its property of forming two separable phases when it is has absorbed an amount of acidic compounds and is heated, heating the absorbent solution loaded with acid compounds so as to separate a first fraction of absorbent solution depleted in acid compounds and a second fraction of absorbent solution enriched in acid compounds, regenerating the second fraction so as to release a part of the acidic compounds, and recycling the first fraction and the regenerated absorbent solution.
  • Document EP 3017857 relates to a process for deacidifying a gaseous effluent comprising acidic compounds, such as CO2 and/or H2S, and a device for its implementation, by putting the gaseous effluent in contact with an absorbent demixing solution, in which the regeneration is carried out by injecting steam into a liquid guard formed by the regenerated absorbent solution at the bottom of a regeneration column.
  • acidic compounds such as CO2 and/or H2S
  • Document EP 2193833 relates to a method for deacidifying a gas by using an absorbing solution.
  • the method involves introducing a part of an absorbent solution charged with acidic compounds in a regeneration zone to produce a partially regenerated absorbent solution.
  • a part of the partially regenerated absorbent solution is taken from the zone and is separated into a fraction enriched with acidic compounds and a fraction depleted in acidic compounds.
  • the fraction enriched with acidic compounds is introduced into another regeneration zone to produce a regenerated absorbent solution.
  • the fraction depleted in acidic compounds and the regenerated absorbent solution are recycled.
  • Document US 4545965 relates to a process for selectively separating hydrogen 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 solvent is water.
  • the absorbent compound is present in the absorbent solution at a content from 60 to 90 % by mass relative to the mass of the absorbent solution.
  • the absorbent compound is 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 diethylamin
  • 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 or in a rotating packed bed.
  • the gas mixture comprises at least one hydrocarbon, and is preferably natural gas.
  • the method further comprises a step of removing an amount of the at least one hydrocarbon from the absorbent solution loaded with hydrogen sulfide prior to the step of separating the absorbent solution loaded with hydrogen sulfide.
  • the step of removing an amount of the at least one hydrocarbon from the absorbent solution loaded with hydrogen sulfide is carried out by passing said solution through a flash tank.
  • separating the absorbent solution loaded with hydrogen sulfide comprises heating the absorbent solution loaded with hydrogen sulfide.
  • heating the absorbent solution loaded with hydrogen sulfide is carried out at a temperature from 80 to 120°C.
  • separating the absorbent solution loaded with hydrogen sulfide further comprises adding solvent into the absorbent solution loaded with hydrogen sulfide prior to heating.
  • separating the first liquid phase from the second liquid phase is carried out by decantation.
  • regenerating the second liquid phase is carried out by heating the second liquid phase preferably at a temperature from 100 to 200°C, and more preferably from 110 to 150°C.
  • regenerating the second liquid phase is carried out at an absolute pressure from 1 to 3 bar.
  • the first liquid phase is recycled in the step of putting the gas mixture in contact with an absorbent solution.
  • the regenerated liquid phase is recycled in the step of separating the absorbent solution loaded with hydrogen sulfide.
  • the 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 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, carbon dioxide with a high selectivity for hydrogen sulfide and reduced costs.
  • H2S hydrogen sulfide
  • CO2 carbon dioxide
  • the absorbent solution loaded with hydrogen sulfide can be separated so as to obtain a first, absorbent compound-rich, liquid phase, and a second, solvent-rich, liquid phase.
  • These phases can be separated from one another, which allows to avoid regenerating the entirety of the absorbent solution.
  • the first liquid phase (which predominantly comprises the regenerated absorbent compound) can be directly recycled in the method according to the invention, and more particularly in the step of putting the gas mixture in contact with the absorbent solution.
  • the second liquid phase (which predominantly comprises the solvent) can be regenerated in order to collect the hydrogen sulfide and recycle the regenerated liquid phase in the method according to the invention.
  • the energetic and material costs can be reduced with the present method.
  • Figure 1 illustrates an installation used for the implementation of the method according to one embodiment of the invention.
  • Figure 2 illustrates an installation used for the implementation of the method according to one embodiment of the invention.
  • Figure 3 illustrates an installation used for the implementation of the method according to one embodiment of the invention.
  • 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 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 comprises at least one absorbent compound in a solvent.
  • absorbent compound is meant a compound which may react with H2S.
  • the absorbent compound may also react with CO2.
  • the reaction of the absorbent compound with CO2 also involves the solvent.
  • the reaction of the absorbent compound with H2S does not involve the solvent.
  • the absorbent solution is an aqueous solution.
  • the solvent is water.
  • the solvent may be present in the absorbent solution at a content lower than 50 % by mass relative to the mass of the absorbent solution, and preferably at a content from 10 to 40 % by mass relative to the mass of the absorbent solution.
  • the solvent may be present in the absorbent solution at a content from 0.1 to 1 %; or from 1 to 5 %; or from 5 to 10 %; or from 10 to 15%; or from 15 to 20 %; or from 20 to 25 %; or from 25 to 30 %; or from 30 to 35 %; or from 35 to 40 %; or from 40 to 45 %; or from 45 to 49.9 % by mass relative to the mass of the absorbent solution.
  • the absorbent compound according to the invention is preferably an amine, more preferably a tertiary amine.
  • the amine compound may further comprise at least one oxygen and/or at least one sulfur atom.
  • the absorbent compound is “demixing”, which means that the absorbent solution may form two immiscible liquid phases under specific conditions (for example in a certain temperature range or depending on the concentration of absorbed compound).
  • the absorbent compound is preferably a demixing amine or mixture of amines.
  • 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 phenomenon is preferably induced by an increase of the temperature.
  • the absorbent compound is preferably an amine and more preferably a tertiary amine.
  • amine is meant not only monoamines but also polyamines, alkalonamines, amino acids, metallic salts of amino acids and ureas.
  • this definition includes aliphatic amines (cyclic or acyclic), saturated and unsaturated amines and aromatic and non-aromatic amines.
  • the demixing amine may be chosen from an amine described in documents EP 2889073, EP 1996313, EP 3017857 and EP 2193833.
  • the absorbent compound may 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 diethyla
  • the absorbent compound according to the invention is present in the absorbent solution at a content of more than or equal to 50 % by mass relative to the mass of the absorbent solution, and preferably at a content from 60 to 90 % by mass relative to the mass of the absorbent solution.
  • the absorbent compound according to the invention may be present at a content from 50 to 55 %; or from 55 to 60 %; or from 60 to 65 %; or from 65 to 70 %; or from 70 to 75 %; or from 75 to 80 %; or from 80 to 85 %; or from 85 to 90 %; or from 90 to 95 %; or from 95 to 99.9 % by mass relative to the mass of the absorbent solution.
  • the absorbent solution consists of one or more absorbent compounds and the solvent.
  • the absorbent solution may comprise, apart from the one or more absorbent compounds and solvent, one or more other additional compounds.
  • Such compounds may be chosen for example from sulfolane, diethylene glycoldiethyl ether (DEGDEE), thiodiglycol (TDG), toluene, sulfolane (tetramethylene sulfone), acetonitrile, tetrahydrofuran (THF), propylene carbonate, dimethyl ethers of ethylene and propylene glycols, ketones such as methyl ethyl ketone (MEK), esters such as ethyl acetate and amyl acetate, and halocarbons such as 1 ,2-dichlororobenzene (ODCB) and their mixtures.
  • DEGDEE diethylene glycoldiethyl ether
  • TDG thiodiglycol
  • TDG thiodiglycol
  • toluene sulfolane (tetram
  • the absorbent solution may comprise one or more polar aprotic compounds 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.
  • polar aprotic compounds 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 diamide
  • Such compounds may form hydrogen bonds with the solvent, notably water, by forming hydrogen bonds, and make it possible to increase the selectivity of H2S absorption relative to CO2 absorption.
  • 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 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 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 0.23 x 10 6 to 56 x 10 6 Nm 3 /day.
  • the absorbent 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 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 150 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 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 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 by volume; 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 column 1 may have a content in CO2 from 0.1 to 10 % by volume 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 10000 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 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 to 90°C and at an absolute pressure from 4 to 15 bar.
  • the stream of absorbent 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 method according to the present invention then comprises a step of separating the absorbent solution loaded with hydrogen sulfide into two liquid immiscible phases.
  • the separation step comprises heating the absorbent solution loaded with hydrogen sulfide. This heating may be carried out at a temperature from 80 to 120°C and at an absolute pressure from 4 to 15 bar.
  • the heating makes it possible (due to the demixing properties of the absorbent component) to form two immiscible liquid phases: a first, absorbent compound-rich, liquid phase, and a second, solvent-rich, liquid phase.
  • heating the absorbent solution loaded with hydrogen sulfide makes it possible to separate on the one hand the liquid first phase and on the other hand a second liquid phase.
  • the majority of the absorbent compound is thus recovered in the first liquid phase, while the majority of the solvent is recovered in the second liquid phase.
  • the concentration of absorbent compound in the first liquid phase may be from 50 to 100 wt %, and preferably from 60 to 98 wt %.
  • the concentration of absorbent compound in the second liquid phase may be from 0 to 50 wt %, and preferably from 0 to 30 wt %.
  • absorbent compound is meant to cover the original absorbent compound as well as the absorbent compound having reacted with an acid gas.
  • H2S after H2S has reacted with the absorbent compound, it is predominantly present in the second liquid phase.
  • the solvent is water and the absorbent compound is an amine, H2S is present in the solution in the form of SH“ ions, and therefore in the aqueous solvent.
  • separating the absorbent solution loaded with hydrogen sulfide includes adding solvent (the same as the one used in the absorbent solution) into the absorbent solution loaded with hydrogen sulfide prior to heating.
  • the separation of the first liquid phase from the second liquid phase may be carried out by decantation, or any other liquid/liquid separation device.
  • the absorbent solution loaded with hydrogen sulfide is heated directly in the unit wherein its separation into two liquid phases is carried out.
  • the absorbent solution exiting the flash tank 5 via the loaded solution feeding line 6 may enter a separation unit 9 where the heating and separation are carried out.
  • the absorbent solution loaded with hydrogen sulfide may be heated in a heat exchanger 7 prior to be entering the separation unit 9 (as illustrated in figure 1).
  • the absorbent solution loaded with hydrogen sulfide is both preheated prior to entering the separation unit 9 and then further heated in the separation unit 9.
  • the two-phase separation can be induced by decreasing the temperature of the absorbent solution loaded with hydrogen sulfide. This specific embodiment will be detailed below.
  • the present invention allows to recover the majority of the absorbent compound (first liquid phase) without implementing costly regeneration processes. This makes it possible to reduce energy consumption.
  • a first liquid phase collecting line 10 and a second liquid phase collecting line 11 may be connected to respective outlets of the separation unit 9.
  • a gas phase may also be present in addition to the two liquid phases, which can be evacuated from the separation unit 9 via a gas line (not illustrated in the figures).
  • the first liquid phase may be recycled in the step of putting the gas mixture in contact with an absorbent solution (for example the first liquid phase collecting line 10 may be connected to an inlet of the absorption column 1 ).
  • the method according to the present invention further comprises regenerating the second liquid phase to collect hydrogen sulfide on the one hand and a regenerated liquid phase on the other hand.
  • This step may be carried out in a regeneration column 12, preferably comprising a reboiler (for example at the lower (bottom) part of the regeneration column 12) (not illustrated in the figures).
  • a reboiler for example at the lower (bottom) part of the regeneration column 12
  • 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 second liquid phase may exit the separation unit 9 via the second liquid phase collecting line 11 and be fed to the regeneration column 12.
  • the regeneration column 12 may include a stripping section and a reflux section above the stripping section.
  • the second liquid phase collecting line 11 may be connected to the top of the stripping section.
  • the reboiler located in the regeneration column 12 may generate solvent (e.g. water) steam by heating the second liquid phase.
  • the steam ascends in a counter-current mode in the regeneration column 12, entraining the H2S and optionally other impurities (such as residual CO2) remaining in the second liquid phase. This is promoted by the low pressure and high temperature prevailing in the regenerator.
  • heating of the second liquid phase in the regeneration unit 12 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 H2S and optionally impurities may be recovered as a gaseous stream at the top of the regeneration column 12 (H2S collecting line 13).
  • the gaseous stream exiting the regeneration column 12 may comprise from 40 to 97 % by volume, and preferably from 70 to 97 % by volume of H2S relative to the volume of gaseous stream exiting the regeneration column 12.
  • the gaseous stream exiting the regeneration column 12 may comprise from 0 to 60 % by volume and preferably from 0 to 30 % by volume of CO2 relative to the volume of gaseous stream exiting the regeneration column 12.
  • the ratio of H2S volume concentration to CO2 volume concentration in the gaseous stream exiting the regeneration column 12 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 may be cooled in a condenser present in the regeneration column 12 (not represented in the figures).
  • This solution regenerated in the regeneration column 12 is recovered in a lean solution collecting line 14.
  • the regenerated liquid phase may then be recycled in the step of adding solvent in the absorbent solution loaded with hydrogen sulfide.
  • the regenerated liquid phase may be added to the absorbent solution loaded with hydrogen sulfide prior to the step of separating the absorbent solution enriched in hydrogen sulfide and depleted in carbon dioxide (for example the lean solution collecting line 14 may be connected to an inlet of the flash tank 5).
  • a heat exchanger 7 may be provided in order to preheat the absorbent solution loaded with hydrogen sulfide before feeding it to the separation unit 9.
  • the heat exchanger 7 may transfer heat from the lean solution collecting line 14 to the loaded solution feeding line 6.
  • a lean solution recycling line 14’ may be connected to the lean solution collecting line 14, preferably downstream of the heat exchanger 7.
  • the absorption column 1 may comprise an upper part and a lower part and the lean solution recycling line 14’ may be connected to the top of the (upper part of the) absorption column 1 .
  • the first liquid phase collecting line 10 is connected to the top of the bottom part of the absorption column 1 .
  • a second loaded solution collecting line 15 may be connected at the bottom of the upper part of the absorption column 1 so as to collect loaded solution and feed it to the flash tank 5, together with the loaded solution collected from the loaded solution collecting line 4 described above. Alternatively, this loaded collecting line 15 may be dispensed with. Then, the entirety of the loaded solution is collected via the loaded solution collecting line 4 connected at the bottom of the (lower part of the) absorption column 1 .
  • the regenerated liquid phase may be added to the absorbent solution loaded with hydrogen sulfide prior to the step of separating the absorbent solution enriched in hydrogen sulfide and depleted in carbon dioxide (for example the lean solution collecting line 14 may be connected to an inlet of the flash tank 5).
  • the regenerated liquid phase may optionally be cooled prior to entering the flash tank 5. For instance, it may exchange heat with the second liquid phase flowing in the second liquid phase collecting line 11 via an additional heat exchanger 17.
  • the lean solution recycling illustrated with reference to figure 2 may also be implemented when the two-phase separation is induced by a temperature decrease as illustrated with reference to figure 3.
  • 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 captured 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 column 1 and the H2S recovered at the top of the regeneration column 12 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.
  • 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.
  • 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 CC ⁇ 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 total 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.
  • EOR enhanced oil recovery
  • the H2S recovered (as explained above) after exiting the regeneration column 12 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.Cn the other hand, 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 hydrogen sulfide 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 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.

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  • Chemical & Material Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Analytical Chemistry (AREA)
  • General Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • Gas Separation By Absorption (AREA)

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. Ledit procédé comprend : la mise en contact du mélange gazeux avec une solution absorbante comprenant au moins un composé absorbant dans un solvant, le composé absorbant étant présent dans la solution absorbante à une teneur d'au moins 50 % en masse par rapport à la masse de la solution absorbante, de manière à obtenir un mélange gazeux appauvri en sulfure d'hydrogène, et une solution absorbante chargée avec du sulfure d'hydrogène ; la séparation de la solution absorbante chargée en sulfure d'hydrogène en une première phase liquide riche en composé absorbant, et une seconde phase liquide riche en solvant ; et la régénération de la seconde phase liquide de façon à collecter un courant de sulfure d'hydrogène et une phase liquide régénérée.
PCT/IB2020/001109 2020-12-17 2020-12-17 Milieu d'élimination sélective de sulfure d'hydrogène à partir d'un courant gazeux WO2022129974A1 (fr)

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Citations (11)

* 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
WO2006103812A1 (fr) * 2005-03-28 2006-10-05 Mitsubishi Materials Corporation Procede de purification du gaz, appareil correspondant et liquide absorbant les gaz acides utilise lors de la purification
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
US20100132551A1 (en) * 2008-11-20 2010-06-03 Pierre-Antoine Bouillon Gas deacidizing method using an absorbent solution with demixing during regeneration
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
US20150027055A1 (en) 2013-07-29 2015-01-29 Exxonmobil Research And Engineering Company Separation of hydrogen sulfide from natural gas
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
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 (12)

* 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
WO2006103812A1 (fr) * 2005-03-28 2006-10-05 Mitsubishi Materials Corporation Procede de purification du gaz, appareil correspondant et liquide absorbant les gaz acides utilise lors de la purification
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
US20100132551A1 (en) * 2008-11-20 2010-06-03 Pierre-Antoine Bouillon Gas deacidizing method using an absorbent solution with demixing during regeneration
EP2193833A1 (fr) 2008-11-20 2010-06-09 Ifp Procédé de désacidification d'un gaz par solution absorbante avec démixtion en cours de régénération
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
US20150027055A1 (en) 2013-07-29 2015-01-29 Exxonmobil Research And Engineering Company Separation of hydrogen sulfide from natural gas
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
US10525404B2 (en) 2016-04-25 2020-01-07 Basf Se Use of morpholine-based hindered amine compounds for selective removal of hydrogen sulfide

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