Technical field

The present invention relates to a method for the purification of a gas mixture comprising at least hydrogen sulfide and carbon dioxide. The invention allows to recover high purity carbon dioxide.

Technical background

The purification of gas mixtures and in particular of hydrocarbon gas mixtures such as natural gas and synthesis gas, in order to remove contaminants and impurities therefrom, is a common operation in industry.

These 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.

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.

The natural gas thus undergoes several treatments in order to meet specifications dictated by commercial constraints, transport constraints or constraints linked to safety. Such treatments include deacidification, dehydration and hydrocarbon liquid recovery treatments. This latter treatment consists in separating ethane, propane, butane and the gasolines forming liquefied petroleum gas (“LPG") from the methane gas, which is sent to the distribution network.

In addition, due to the effect of CO2 on the greenhouse phenomenon, it becomes important to develop technologies which make it possible to capture native CO2 from natural gas to store it or valorize it for other applications such as enhanced oil recovery. When both H2S and CO2 are present in the sour gas, the CO2 recovery becomes a challenge as CO2/H2S separation is required, in order to obtain a high purity CO2 stream (very low H2S content). Thus, the native CO2 recovery will depend on the capacity to separate H2S from CO2.

In addition, CO2 should be separated from H2S for safety reasons. However, CO2 is usually diluted with nitrogen deriving from the sulfur recovery unit, which reduces the purity of the recovered CO2.

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 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 loaded absorbent.

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 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. 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.

Generally, all the acid gases contained in a gas mixture such as natural gas are simultaneously eliminated. In this case, after the elimination of acid gases from natural gas, the mixture of acid gases should be treated in order to separate CO2 from H2S. However, such treatment may significantly increase the operational costs.

Thus, one may also wish to selectively extract the H2S relative to the CO2 contained in a gas mixture such as natural 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 %. Under these conditions, an optimal process would allow the selective elimination of H2S relative to CO2, with minimal or controlled co-absorption of CO2.

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. In addition, 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 (sulfur recovery unit) 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. For example, the gas sent to the Claus installation should generally comprise at least 30 % by volume of H2S.

There is thus a need for a method which makes it possible to purify a gas mixture comprising at least hydrogen sulfide and carbon dioxide in an efficient way, with low operational costs, while efficiently obtaining at the same time a high purity carbon dioxide stream.

Summary of the invention

It is a first object of the invention to provide a method for the purification of a gas mixture comprising at least hydrogen sulfide and carbon dioxide, the method comprising: putting in contact an initial gas mixture with a first absorbent solution so as to obtain a gas mixture depleted in hydrogen sulfide, and a first absorbent solution loaded with hydrogen sulfide, wherein the volume concentration of hydrogen sulfide in the gas mixture depleted in hydrogen sulfide is less than 10% of the volume concentration of hydrogen sulfide in the initial mixture, and the volume concentration of carbon dioxide in the gas mixture depleted in hydrogen sulfide is more than 75% of the volume concentration of carbon dioxide in the initial mixture; regenerating the first absorbent solution loaded with hydrogen sulfide so as to obtain a hydrogen sulfide stream and a regenerated first absorbent solution; putting in contact the gas mixture depleted in hydrogen sulfide with a second absorbent solution so as to obtain a gas stream depleted in carbon dioxide and a second absorbent solution loaded with carbon dioxide; and regenerating the second absorbent solution loaded with carbon dioxide so as to collect a carbon dioxide stream and a regenerated second absorbent solution.

According to some embodiments, the gas mixture depleted in hydrogen sulfide has a content in hydrogen sulfide 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 relative to the volume of the gas mixture depleted in hydrogen sulfide.

According to some embodiments, 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 .

According to some embodiments, the initial gas mixture has a content in carbon dioxide 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.

According to some embodiments, the first absorbent solution comprises at least one absorbent compound in a solvent, the absorbent compound being present in the absorbent solution at a content of at least 50 % by mass relative to the mass of the absorbent solution.

According to some embodiments, 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, and/or wherein the solvent is water.

According to some embodiments, the first absorbent solution comprises at least one polar, aprotic molecule and at least one amine compound in water.

According to some embodiments, 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, dimethylacetamide, caprolactams, 1 ,3-dimethyl-2- imidazolidinone, N,N, dimethylpropyleneurea , hexamethylphosphoramide, dimethyl sulfoxide, dimethyl-thio-formamide, hexamethylphosphorothiotic triamide, and mixtures thereof, and/or wherein 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.

According to some embodiments, the second absorbent solution comprises at least one amine in water, the amine preferably selected from diethanol amine, methyl-di-ethanol amine, activated methyl-di-ethanol amine and mixtures thereof.

According to some embodiments, the step of putting in contact the initial gas mixture with a first absorbent solution is carried out at a temperature from 25 to 100°C and/or at an absolute pressure from 1 to 150 bar.

According to some embodiments, the step of putting in contact the gas mixture depleted in hydrogen sulfide with a second absorbent solution is carried out at a temperature from 25 to 100°C and/or at an absolute pressure from 1 to 150 bar. According to some embodiments, the step of putting in contact the gas mixture with a first absorbent solution and/or the step of putting in contact the gas mixture depleted in hydrogen sulfide with a second absorbent solution is carried out in an absorption column.

According to some embodiments, at least part of the step of regenerating the first absorbent solution loaded with hydrogen sulfide is carried out in a regeneration column.

According to some embodiments, the step of regenerating the second absorbent solution loaded with carbon dioxide is carried out in a regeneration column.

According to some embodiments, at least part of the step of regenerating the first absorbent solution loaded with hydrogen sulfide is 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.

According to some embodiments, the step of regenerating the second absorbent solution loaded with carbon dioxide is 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.

According to some embodiments, the gas stream depleted in carbon dioxide presents a content in carbon dioxide equal to or lower than 10 % by volume and preferably lower than 2 % by volume relative to the volume of the gas depleted in CO2

According to some embodiments, the gas mixture comprises at least one hydrocarbon, and is preferably natural gas.

According to some embodiments, at least part of the regenerated first absorbent solution is recycled in the step of putting the gas mixture in contact with a first absorbent solution.

According to some embodiments, the regenerated second absorbent solution is recycled in the step of putting the gas mixture depleted in hydrogen sulfide in contact with a second absorbent solution.

According to some embodiments, the method comprises a step of treating the hydrogen sulfide stream so as to recover elemental sulfur and a tail gas stream comprising one or more sulfur compounds.

According to some embodiments, said treatment is carried out in a Claus unit.

According to some embodiments, the method further comprises a step of hydrogenating the one or more sulfur compounds in the tail gas stream and obtaining a gas stream comprising hydrogen sulfide. According to some embodiments, said step is carried out in a tail gas treatment unit.

According to some embodiments, the gas stream comprising hydrogen sulfide is recycled to the step of treating the hydrogen sulfide stream so as to recover elemental sulfur and a tail gas stream comprising one or more sulfur compounds.

According to some embodiments, the carbon dioxide stream presents a content in hydrogen sulfide equal to or less than 2000 ppm, and preferably equal to or less than 200 ppm.

The present invention enables to address the need mentioned above. In particular the invention provides a method which makes it possible to purify a gas mixture comprising at least hydrogen sulfide and carbon dioxide in an efficient way, with low operational costs, while efficiently obtaining at the same time a high purity carbon dioxide stream.

More particularly, as the method of the present invention allows to firstly selectively separate the hydrogen sulfide from the gas mixture, and then separate the carbon dioxide from the gas mixture depleted in hydrogen sulfide, it makes it possible to facilitate the gas separation process and reduce the size of the installations and the operational costs related to the capture of CO2. In other words, during the step of putting in contact the gas mixture with a first absorbent solution, it is possible to separate on the one hand an absorbent solution loaded with hydrogen sulfide and on the other hand a gas mixture which is not only depleted in hydrogen sulfide but also contains the majority of the carbon dioxide contained in the initial gas mixture. Thus, the two acid gases are treated separately in order to obtain in the end a purified stream of gas at specification and capture the carbon dioxide at high purity separated from the gas. As the concentration of carbon dioxide is reduced in the hydrogen sulfide stream, it is possible to reduce the size of the installations during gas treatment (for example reduce the size of the Claus unit) and thus the capital expenditure (CAPEX) of the process. In addition, the method of the present invention makes it possible to capture carbon dioxide with reduced operational costs.

Brief description of the drawings

Figure 1 illustrates an installation used for the implementation of one part of the method according to one embodiment of the invention.

Figure 2 illustrates an installation used for the implementation of one part of the method according to another embodiment of the invention. Figure 3 illustrates an installation used for the implementation of one part of the method according to another embodiment of the invention.

Figure 4 illustrates an installation used for the implementation of one part of the method according to another embodiment of the invention.

Figure 5 illustrates a comparative installation.

Figure 6 illustrates an installation used for the implementation of another part of the method according to the invention.

Detailed description

The invention will now be described in more detail without limitation in the following description.

Gas mixture

The present invention makes it possible to treat a gas mixture (also referred to as the initial gas mixture).

According to preferred embodiments, 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.

In addition, 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.

Optionally, 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. According to some embodiments, 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.

According to some embodiments, 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. These 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.

Selective separation of hydrogen sulfide

The method according to the present invention makes it possible to firstly selectively separate H2S relative to CO2 so as to obtain a gas mixture depleted in hydrogen sulfide from the gas mixture and secondly capture the CO2 from the gas mixture depleted in hydrogen sulfide in order to obtain a purified gas stream depleted of CO2 and a CO2 (purified) stream.

The method according to the invention comprises a first step of putting the gas mixture described above in contact with a first absorbent solution.

The first absorbent solution comprises at least one absorbent compound in a solvent. The solvent preferably comprises water, so that the first absorbent solution is an aqueous solution. The absorbent compound is preferably an amine compound.

According to a first variation, the first absorbent solution comprises at least one polar, aprotic molecule and at least one amine compound in water.

The amine compound may be for example aliphatic, cyclic or aromatic. Preferably, 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.

According to other preferred embodiments, 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), 3,9-dimethyl-6- oxa-3,9-diaza-undecane-1 ,11 -diol. According to other preferred embodiments, the amine compound may be a tertiary amine comprising a morpholinone function, such as 4-morpholin-4- ylpentan-1 -ol.

According to other preferred embodiments, 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.

Examples of the amine compound and in particular of tertiary alkanolamines are given in US 2008/0025893, the description of which can be referred to. More particular examples include N-methyldiethanolamine (MDEA), N,N-diethylethanolamine (DEEA), N,N-dimethylethanolamine (DMEA), 2- diisopropylaminoethanol (DIEA), N,N,N',N'-tetramethylpropanediamine (TMPDA), N,N,N',N'-tetraethylpropanediamine (TEPDA), dimethylamino-2- dimethylamino-ethoxyethane (Niax), and N,N-dimethyl-N',N'- diethylethylenediamine (DMDEEDA).

Examples of tertiary alkanolamines that can be used in the process according to the invention are also given in US 2010/0288125, the description of which can be referred to. More particular examples tris(2-hydroxyethyl)amine (triethanolamine, TEA), tris(2-hydroxypropyl)amine (triisopropanol), tributylethanolamine (TEA), bis(2-hydroxyethyl)methylamine

(methyldiethanolamine, MDEA), 2-diethylaminoethanol (diethylethanolamine, DEEA), 2-dimethylaminoethanol (dimethylethanolamine DMEA), 3- dimethylamino-1 -propanol, 3-diethylamino-1 -propanol, 2- diisopropylaminoethanol (DIEA), N,N-bis(2-hydroxypropyl)methylamine or methyldiisopropanolamine (MDIPA).

Other examples of 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 -propanol, 1- dimethylamino-2-methyl-2-propanol, 2-dimethylamino-1 -butanol and 2- dimethylamino-2-methyl-1 -propanol. Other 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.

According to preferred embodiments, 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.

Alternatively, the amine compound may be (or comprise) a demixing amine. By “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. For example, 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.

Preferably, 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. According to preferred embodiments, 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 amine compound(s) may be present in the first 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 first absorbent solution.

Turning now to the polar, aprotic molecule, by “polar"’ 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.

By “aprotic" is meant a molecule which does not contain any acidic hydrogen and thus does not act as a hydrogen bond donor. In particular, 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. Preferably, 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.

According to preferred embodiments, 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. Preferably, 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.

The polar, aprotic molecule(s) may be present in the first 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 first absorbent solution.

The polar, aprotic molecule are involved in strong hydrogen bonding with the water which acts as a solvent of the absorbent solution. 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 first 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 first absorbent solution.

According to some embodiments, the first absorbent aqueous solution may consist of the amine compound, the polar, aprotic molecule and water.

According to other embodiments, the absorbent solution may comprise one or more other additional compounds.

According to a second variation, the first absorbent solution comprises at least one absorbent compound in a solvent, the absorbent compound being present in the absorbent solution at a content of at least 50 % by mass relative to the mass of the absorbent solution.

By “absorbent compound" is meant a compound which may react with H2S. Preferably, the absorbent compound may also react with CO2. Preferably, the reaction of the absorbent compound with CO2 also involves the solvent. Preferably, the reaction of the absorbent compound with H2S does not involve the solvent.

In case the first absorbent solution comprises at least one absorbent compound in a solvent (the absorbent compound being present in the absorbent solution at a content of at least 50 % by mass relative to the mass of the absorbent solution), it is preferable that the first absorbent solution is an aqueous solution. In other words, the solvent is water.

The solvent may be present in the first 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. For example, 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 fact that the first absorbent solution comprises 50 % by mass or more of an absorbent compound makes it possible to selectively separate the hydrogen sulfide from the carbon dioxide. In fact, although the absorbent compound, which is preferably a demixing amine, can typically react with both H2S and CO2, due to the presence of a high concentration of absorbent compound in the absorbent solution, H2S is selectively absorbed by the absorbent solution, relative to CO2. This is because, at a low solvent (preferably water) concentration, the capture of H2S is favored relative to the capture of CO2. The absorbent compound according to the invention is preferably an amine, more preferably a tertiary amine.

The absorbent compound is “demixing", which means (as explained above) that the first 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). In the case of the present invention, the demixing phenomenon is preferably induced by an increase of the temperature.

The absorbent compound is preferably a demixing amine or mixture of amines.

As mentioned above, the absorbent compound is preferably an amine and more preferably a tertiary amine. In the context of the present invention, by “amine" is meant not only monoamines but also polyamines, alkalonamines, amino acids, metallic salts of amino acids and ureas. In addition, 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 et EP 2193833.

According to preferred embodiments, 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.

The absorbent compound according to the invention is present in the first 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. For example, 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. According to some embodiments, the first absorbent solution consists of one or more absorbent compounds and the solvent.

According to other embodiments, the first 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.

In addition, in case the first absorbent solution comprises at least one absorbent compound in a solvent (the absorbent compound being present in the absorbent solution at a content of at least 50 % by mass relative to the mass of the absorbent solution), the first 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. For example, the polar aprotic compound can be chosen from a monoamide such as N-methylpyrrolidone (NMP), dimethylformamide (DMF), caprolactams, 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.

The contacting (absorption) step may be carried out in any apparatus for gas-liquid contact.

Preferably, 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.

Alternatively, this step can be carried out in a static in-line solvent mixer.

Alternatively, this step can be carried out in a rotating packed bed (RPB). Generally, 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.

For the sake of simplicity, the terms “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.

By making reference to figures 1 and 2, the gas mixture entering the absorption column 1 from the bottom part of the column 1 (gas feeding line 2) is put into contact with a stream of the first 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 first absorbent solution may have a flow rate during this step from 800 to 50000 m ³ /day.

According to some embodiments, the step of putting in contact the gas mixture with a first absorbent solution may be carried out at a temperature from 25 to 100°C.

In addition, according to some embodiments, the step of putting in contact the gas mixture with a first absorbent solution may be carried out at an absolute pressure from 1 to 170 bar, and preferably from 1 to 80 bar.

The gas mixture may be put in contact with the absorption solution for a time period from 10 to 500 seconds, and preferably from 10 to 300 seconds

At the end of this step, 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 first absorbent solution loaded with hydrogen sulfide may be recovered at the bottom of the absorption column 1 (loaded solution collecting line 4). In case the (initial) gas mixture comprises one or more hydrocarbons (which is a preferred embodiment of the present invention), at the end of this first step, the stream of gas mixture collected from the top of the absorption column 1 predominantly contains the hydrocarbons while the stream of first absorbent solution recovered from the bottom of the absorption column 1 contains no hydrocarbons or only a residual amount of hydrocarbons.

Besides, 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 . In other words, 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 first 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. For example, 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 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 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 from 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.

In case the initial gas mixture comprises one or more mercaptans, such mercaptans are predominantly recovered in the absorbent aqueous solution loaded with hydrogen sulfide at the bottom of the absorption column 1 .

The method according to the present invention may further comprise an optional step of removing residual hydrocarbon from the first 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 figures 1 and 2). 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.

Thus, the stream of first 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 further comprises a step of regenerating the first absorbent solution loaded with hydrogen sulfide so as to obtain a hydrogen sulfide stream and a regenerated first absorbent solution.

Depending on the nature of the first absorbent solution, the regeneration step may be carried out in a different way.

According to some embodiments, notably when the first absorbent solution comprises at least one polar, aprotic molecule and at least one amine compound in water (first variation), and as illustrated in figure 1 , the step of regenerating the first absorbent solution loaded with hydrogen sulfide 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).

For example, as illustrated in figure 1 , 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 top of the regeneration column 9). During the regeneration step, the reboiler located in the regeneration column 9 may generate water steam by heating the first absorbent 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. Thus, 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 first absorbent solution loaded with hydrogen sulfide. This desorption is promoted by the low pressure and high temperature prevailing in the regenerator. For example, 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 to 3 bar.

On the one hand, the H2S and optionally impurities may be recovered as a gaseous stream at the top of the regeneration column 9 (H2S collecting line 8).

On the other hand, the steam generated in the regeneration column 9 (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. As illustrated in figure 1 , the condensed regenerated absorbent solution may exit the regeneration column 9 via a lean solution collecting line 10 preferably at the bottom of the regeneration column 9.

Optionally, for the purpose of enhancing energetic efficiency, a heat exchanger 7 may be provided in order to preheat the first 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 10 to the loaded solution feeding line 6.

After cooling the regenerated absorbent solution, for example at a temperature from 120 to 50°C, the regenerated absorbent solution may then be recycled in the step of putting in contact the gas mixture with a first absorbent aqueous solution, for example by entering the absorption column 1 via the lean solution collecting line 10.

Although not illustrated in the figures, the present method may also be implemented in other conventional installations.

According to other embodiments especially when the absorbent compound is a demixing amine (and preferably wherein the first absorbent solution comprises at least one absorbent compound in a solvent, the absorbent compound being present in the absorbent solution at a content of at least 50 % by mass relative to the mass of the absorbent solution, second variation), the absorbent solution loaded with hydrogen sulfide may be separated into a first, absorbent compound-rich liquid phase, and a second, solvent-rich liquid phase, and the second liquid phase may be regenerated so as to collect a hydrogen sulfide stream and a regenerated liquid phase.

In this case, according to some embodiments, the absorbent compound may be present in the absorbent solution at a content from 60 to 90 % by mass relative to the mass of the absorbent solution.

In addition, the step of putting in contact the gas mixture with the absorbent solution may be carried out at a temperature from 25 to 100°C and/or at an absolute pressure from 1 to 150 bar. Such step may be carried out in an absorption column or in a rotating packed bed.

According to some embodiments, the separation of the absorbent solution loaded with hydrogen sulfide may comprise heating the absorbent solution loaded with hydrogen sulfide.

Prior to such step, an amount of at least one hydrocarbon may be removed from the absorbent solution loaded with hydrogen sulfide. This may be carried out by passing said solution through a flash tank. In particular, as illustrated in figure 2, the step of regenerating the first absorbent solution loaded with hydrogen sulfide may first comprise heating the first 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.

Thus, in this case, heating the first absorbent solution loaded with hydrogen sulfide makes it possible to separate on the one hand a first liquid 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 from50 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 %.

Herein, the term “absorbent compound" is meant to cover the original absorbent compound as well as the absorbent compound having reacted with an acid gas.

Besides, after H2S has reacted with the absorbent compound, it is predominantly present in the second liquid phase. Typically, when 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.

According to some preferred embodiments, regenerating the first absorbent solution loaded with hydrogen sulfide also includes adding solvent (the same as the one used in the first absorbent solution) into the first absorbent solution loaded with hydrogen sulfide prior to heating.

Then, a separation of the first liquid phase from the second liquid phase may be carried out by decantation, or any other liquid/liquid separation device.

According to some embodiments, the first absorbent solution loaded with hydrogen sulfide is heated directly in the unit wherein its separation into two liquid phases is carried out. Thus, in this case, the absorbent solution exiting the flash tank 5 via the loaded solution feeding line 6 may enter a separation unit 12 where the heating and separation are carried out.

According to other embodiments, the first absorbent solution loaded with hydrogen sulfide may be heated in a heat exchanger 7 prior to entering the separation unit 12 (as illustrated in figure 2). In some embodiments, the absorbent solution loaded with hydrogen sulfide is both preheated prior to entering the separation unit 12 and then further heated in the separation unit 12.

Alternatively to heating, the two-phase separation can be induced by decreasing the temperature of the first absorbent solution loaded with hydrogen sulfide. This specific embodiment will be detailed below.

At the end of this step, the first liquid phase is separated from the second liquid phase.

Accordingly, a first liquid phase collecting line 14 and a second liquid phase collecting line 13 may be connected to respective outlets of the separation unit 12.

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).

According to preferred embodiments, the first liquid phase (thus only a part of the first absorbent solution) may be recycled in the step of putting the gas mixture in contact with a first absorbent solution (for example the first liquid phase collecting line 14 may be connected to an inlet of the absorption column 1 ). This makes it possible to reduce the costs related to the consumption of different materials such as the absorbent compound.

In addition, in case the first absorbent solution comprises at least one absorbent compound in a solvent, the absorbent compound being present in the absorbent solution at a content of at least 50 % by mass relative to the mass of the absorbent solution (second variation), the step of regenerating the first absorbent solution loaded with hydrogen sulfide further comprises regenerating the second liquid phase to collect a hydrogen sulfide stream on the one hand and a regenerated liquid phase on the other hand.

This regeneration 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). 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.

For example, as illustrated in figure 2, the second liquid phase may exit the separation unit 12 via the second liquid phase collecting line 13, and be fed to the regeneration column 9. 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. During this step, the reboiler located in the regeneration column 9 may generate solvent (e.g. water) steam by heating the second liquid phase. The steam ascends in a countercurrent mode in the regeneration column 9, 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. For example, heating of the second liquid phase in the regeneration unit 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 to 3 bars.

On the one hand, the H2S and optionally impurities may be recovered as a gaseous stream at the top of the regeneration column 9 (H2S collecting line 8).

On the other hand, the steam generated in the regeneration column 9 (deriving from the solvent present in the second liquid phase) may be cooled in a condenser present in the regeneration column 9 and recovered in a lean solution collecting line 10. The regenerated liquid phase may then be recycled in the step of adding solvent in the absorbent solution loaded with hydrogen sulfide. In other words, the regenerated liquid phase may be added to the first absorbent solution loaded with hydrogen sulfide prior to the separation of the absorbent solution enriched in hydrogen sulfide and depleted in carbon dioxide (for example the lean solution collecting line 10 may be connected to an inlet of the flash tank 5).

Optionally, for the purpose of enhancing energetic efficiency, a heat exchanger 7 may be provided in order to preheat the first 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 10 to the loaded solution feeding line 6.

Alternatively, as illustrated in figure 3 (where the reference numerals have the same meaning as in figure 2 unless otherwise mentioned), at least part of the regenerated liquid phase may be recycled to the absorption column 1. For example, a lean solution recycling line 10’ may be connected to the lean solution collecting line 10, preferably downstream of the heat exchanger 7. For example, in this case, the absorption column 1 may comprise an upper part and a lower part and the lean solution recycling line 10’ may be connected to the top of the (upper part of the) absorption column 1 . Thus, part of the regenerated liquid phase is sent to the upper part of the absorption column. The first liquid phase collecting line 10 is connected to the top of the bottom part of the absorption column 1 . This configuration makes it possible to reach a more stringent hydrogen sulfide specification. A second loaded solution collecting line 27 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 27 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 .

As mentioned above, in case the two-phase separation can be induced by decreasing (rather than increasing) the temperature of the absorbent solution loaded with hydrogen sulfide, reference may be made to figure 4 (where the reference numerals have the same meaning as in figure 2 unless otherwise mentioned). In this case, loaded absorbent solution is collected from the flash tank 5 via the loaded solution feeding line 6 and passes through a cooling unit 28 which makes it possible to decrease the temperature of the absorbent solution loaded with hydrogen sulfide prior to its entry into the separation unit 12. Furthermore, in this case, when the regenerated liquid phase is recovered in the lean solution collecting line 30, it may be recycled to the step of adding solvent in the absorbent solution loaded with hydrogen sulfide. In other words, 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 30 may be connected to an inlet of the flash tank 5). However, 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 13 via an additional heat exchanger 29.

Of course, the lean solution recycling illustrated with reference to figure 3 may also be implemented when the two-phase separation is induced by a temperature decrease as illustrated with reference to figure 4.

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.

Separation of carbon dioxide and downstream treatment of hydrogen sulfide

As illustrated in figure 5, according to a comparative method for the purification of a gas stream comprising CO2 and H2S is illustrated, a gas to be purified A may enter a first AGR (Acid Gas Removal) Unit 16 wherein purified gas B may be recovered on the one hand, and a stream comprising CO2 and H2S may be recovered on the other hand. Such stream may enter the Claus unit 19 wherein H2S is converted into elemental sulfur to recover a sulfur stream C, and a stream comprising CO2 and remaining H2S enters a TGT (Tail Gas Treatment) unit. After treatment in the TGTII (which comprises a hydrogenation reactor 22 and an absorber unit 23), a stream comprising CO2 may enter a second AGR unit 33 in order to separate CO2 from mainly nitrogen present in the stream and deriving from the Claus unit. After such treatment, CO2 may be pressurized and dehydrated in unit 26 to recover a purified CO2 stream D, while the remaining gas may be incinerated in unit 25 to produce fuel gas E. In addition, treatment in such unit allows to convert the various sulfur species contained in stream into H2S which may then be removed and recycled in the Claus unit 19 via recycle line 24. In this case, CO2 and H2S are both separated from the gas to be separated and are both treated in the Claus unit, which as mentioned above, may have an impact on the size and operating costs of the installation. Thus, until now, one wishing to recover CO2 would use the above technology and set-up.

In contrast, the separation method according to the present invention may be explained by making reference to figure 6. Thus, after carrying out the selective separation detailed above (this treatment being represented by “15” in figure 6) on the gas to be purified A, the stream of gas mixture depleted in hydrogen sulfide recovered from the top of the absorption column 1 (from the gas collecting line 3 for example) and the H2S stream recovered at the top of the regeneration column 9 (from the H2S collecting line 8) can be treated separately and independently from one another.

On the one hand, the stream of gas mixture depleted in hydrogen sulfide is first treated in order to separate gas impurities, notably CO2, from the gas mixture. According to preferred embodiments, this step may be carried out in an AGR (Acid Gas Removal) Unit 16. The AGR unit 16 may comprise an absorption column (similar to the absorption column used above) or any other unit configured for gas-liquid contact. The AGR unit 16 may also comprise a regeneration column (similar to the regeneration column used above). In the absorption column the gas mixture depleted in hydrogen sulfide is put in contact with a second absorbent solution comprising an absorbent compound capable of capturing CO2. The absorbent compound may 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. The second absorbent solution may have a content in the amine compound from 20 to 50 % by weight relative to the total weight of the second absorbent solution.

The second absorbent solution may further comprise a solvent such as water.

During this step, 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.

During this step, the second absorbent solution may have a flow rate from 800 to 50000 m ³ /day.

According to some embodiments, the step of putting the gas mixture depleted in hydrogen sulfide in contact with a second absorbent solution may be carried out at a temperature from 25 to 100°C.

In addition, according to some embodiments, the step of putting the gas mixture depleted in hydrogen sulfide in contact with a second absorbent solution may be carried out at an absolute pressure from 1 to 150 bar, and preferably from 1 to 80 bar.

Alternatively to absorption, this step may be carried out by an adsorption method and unit.

At the end of this step, a gas stream depleted in CO2 F (and other gas impurities) is recovered on the one hand from a purified gas collecting line 17 (for example from the top of the column) and a second 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 depleted in CO2.

According to some embodiments, the gas stream depleted in CO2 may undergo other treatments such as drying (dehydration).

Alternatively, the gas stream depleted in CC^ may directly be available for the gas distribution network.

The second absorbent solution loaded with CO2 then undergoes a treatment in order to regenerate the second absorbent solution and recover the captured CC^from a CO2 collecting line 18. 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 (CO2 stream) at the top of the column). The regenerated second absorbent solution 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 second absorbent solution, thus the regenerated absorbent solution may be fed to the absorption column (not illustrated in the figures).

For example, heating the second 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 CO2 stream may present a content in H2S equal to or less than 2000 ppm, and preferably equal to or less than 200 ppm.

The CO2 stream may then be dehydrated, pressurized and optionally filtered in unit 31 , so as a pure CO2 stream G can be stored of used in enhanced oil recovery (EOR) or in other applications.

On the other hand, the H2S stream recovered from the H2S collecting line 8 (as explained above) after exiting the regeneration column 9 may be converted into elemental sulfur, for example in a Claus unit 19. A Claus unit 19 operates with an oxidizer H, such as air, pure oxygen or mixtures of oxygen and nitrogen, in a combustion chamber. The Claus unit 19 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).

At the end of this step, a first stream comprising elemental sulfur (elemental sulfur stream) is recovered on the one hand from an elemental sulfur collecting line 20. This stream may also comprise polysulfides and some H2S. This stream may be degassed in unit 32 in order to transform polysulfides to H2S and then remove H2S. At the end of this step, a sulfur stream I is obtained. On the other hand, a second, tail gas stream comprising one or more sulfur compounds is recovered from a tail gas collecting line 21 . This stream may comprise for example H2S and/or SO2 that have not reacted in the Claus unit 19. It may also comprise mercaptans, COS compounds, residues of methane and other hydrocarbons and residues of CO2.

According to some embodiments, 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 19 via recycle line 24. 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 22, a quench tower, and an absorber unit 23. 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. This mixture may then enter the hydrogenation reactor 22 wherein the sulfur compounds are converted into H2S. The hydrogenation reactor 22 may comprise a catalyst bed with hydrogenation catalysts such as C0M0 on which the hydrogenation is carried out. Then the tail gas mixture exiting the hydrogenation reactor 22 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. Finally, 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 comprising hydrogen sulfide (hydrogen sulfide gas stream) on the other hand. This step may be carried out in the absorber unit 23. The absorber in the absorber unit 23 may be an amine or any other compound capable of capturing the hydrogen sulfide. In this unit, 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 23 may comprise an absorption column and a regeneration column (in order to regenerate the absorber from the hydrogen sulfide).

On the one hand, the hydrogen sulfide gas stream may be recycled to the Claus unit 19 via a H2S recycling line 24.

On the other hand, the treated tail gas stream may be burned, for example in an incinerator 25 in the presence of a fuel gas J, in order to produce a flue gas K.

Due to the fact that H2S and CO2 are treated separately, it becomes possible not only to reduce the size of the installations but also to considerably reduce the cost of the CO2 and H2S capture as well as the cost of the gas purification. In addition, the present invention makes it possible to capture and recover CO2 in a cost-effective way, which can be valorized in various applications, such as enhanced oil recovery.

Moreover, it is possible to capture more CO2 and at a higher purity. Overall, the cost expressed as cost per ton of CO2 avoided is significantly lower with the set-up of figure 6 compared to the set-up of figure 5.