WO2024180358A1

WO2024180358A1 - Method for selective separation of hydrogen sulfide from a gas mixture

Info

Publication number: WO2024180358A1
Application number: PCT/IB2023/000082
Authority: WO
Inventors: Frédérick DE MEYER; Karen GONZALEZ TOVAR; Bénédicte POULAIN; Eric CLOAREC; Christophe MAGNON
Original assignee: TotalEnergies Onetech SAS
Current assignee: TotalEnergies Onetech SAS
Priority date: 2023-02-27
Filing date: 2023-02-27
Publication date: 2024-09-06
Anticipated expiration: 2025-08-27

Abstract

The present invention relates to a method for the purification of a gas mixture, the method comprising: - putting in contact an initial gas mixture comprising at least hydrogen sulfide and carbon dioxide 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; and - regenerating the first absorbent solution loaded with hydrogen sulfide so as to obtain a hydrogen sulfide stream and a regenerated first absorbent solution; wherein the first absorbent solution comprises at least 95 wt% of a first absorbent compound and water, and the first absorbent compound is a tertiary alkanolamine having the following formula (I): R₁-N(-R₃)-R₂ wherein : - R₁ and R₂ are the same or different, and are independently a secondary or tertiary C₃ to C₅ alkanol group, and - R₃ is a C₁ to C₅ branched or straight alkyl group.

Description

Method for selective separation of hydrogen sulfide from a gas mixture

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 makes it possible to selectively separate hydrogen sulfide from the gas mixture.

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.

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. Conventionally, an absorbent solution comprising an amine compound has been proposed. Amine compounds, especially tertiary amines and sterically hindered amines, react faster with H2S than with CO2 (i.e., show kinetic selectivity for H2S over CO2), and the absorption of H2S by such amines is thermodynamically slightly more favorable than the absorption of CO2. The overall selectivity obtained depends essentially on the operating parameters (temperature, pressure, solvent composition and flow rate, gas composition) as well as on the design of the separation unit (column dimensions, number of trays, etc.).

Document EP3185989 relates to a method for removing hydrogen sulfide and carbon dioxide from a stream of fluid, the method comprising: a) an absorption step, in which the stream of fluid is brought into contact with an absorption agent comprising an aqueous solution (i) of an amine of general formula (I); and optionally (ii) at least one tertiary amine; b) a regeneration step, in which at least one sub-stream of the CO2- and H2S-loaded absorption agent is regenerated and a regenerated absorption agent is thus obtained; and c) a recirculation step, in which at least one sub-stream of the regenerated absorption agent is recirculated to the absorption step a).

Document US4749555 relates to a process for the selective removal of H2S and COS from a gas stream having a relatively large concentration of CO2 and being predominantly formed of light hydrocarbons, such as methane. In this process, the solvent comprises a bridgehead amine, a tertiary amine, water, and optionally a physical solvent acceptable to COS absorption, such as sulfolane.

Document EP3356013 relates to an absorbent for the selective removal of hydrogen sulfide from a fluid stream, containing an aqueous solution comprising a) a tertiary amine; b) an amine pH promoter, selected from the compounds mentioned in the description; wherein the molar ratio between b) and a) is in the range of 0.05 to 1 .0; and c) an acid having a pK_a value of less than 6 in an amount such that the pH value of the aqueous solution is 7.9 to less than 8.8 when measured at 120°C.

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. 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.

For example, document US2015/0027055 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.

Document US4545965 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 WO2013/174902 relates to a process for 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 WO2022/129975 relates to a method for selective separation of hydrogen sulfide relative to carbon dioxide from a gas mixture comprising at least hydrogen sulfide and carbon dioxide. The method comprises putting in contact the gas mixture with an absorbent aqueous solution comprising at least one polar, aprotic molecule and at least one amine compound.

Document WO2022/129974 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 method comprising: putting in contact the gas mixture with an absorbent solution comprising 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, so as to obtain a gas mixture depleted in hydrogen sulfide, and an absorbent solution loaded with hydrogen sulfide; separating the absorbent solution loaded with hydrogen sulfide into a first, absorbent compoundrich liquid phase, and a second, solvent-rich liquid phase; and regenerating the second liquid phase so as to collect a hydrogen sulfide stream and a regenerated liquid phase.

Document WO2022/129977A1 relates to a method for the purification of a gas mixture comprising at least hydrogen sulfide and carbon dioxide. The method comprises 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; 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.

However, there exists a continuous 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, the method comprising:

- putting in contact an initial gas mixture comprising at least hydrogen sulfide and carbon dioxide 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; and

- regenerating the first absorbent solution loaded with hydrogen sulfide so as to obtain a hydrogen sulfide stream and a regenerated first absorbent solution; wherein the first absorbent solution comprises at least 95 wt% of a first absorbent compound and water, and the first absorbent compound is a tertiary alkanolamine having the following formula (I): RI-N(-R₃)-R₂ wherein :

- Ri and R₂ are the same or different, and are independently a secondary or tertiary C₃ to Cs alkanol group, and

- R₃ is a Ci to Cs branched or straight alkyl group.

According to some embodiments, R1 and R₂ are the same.

According to some embodiments, R₃ is a Ci to C₃ alkyl group, preferably selected from methyl and isopropyl.

According to some embodiments, the first absorbent compound is chosen from methyldiisopropanolamine (MDIPA), 1 ,1 '-(isopropylamino)di(2-propanol), 1- [(2-hydroxybutyl)(methyl) amino]butan-2-ol, and 1 ,1 '-(methylamino)bis(2-methyl- 2-propanol).

According to some embodiments, the total concentration of the first absorbent compound and the water in the first absorbent solution is at least 98 wt%.

According to some embodiments, the concentration of the first absorbent compound is more than 40 wt%, and the concentration of water is less than 60 wt%, relative to the total of the first absorbent solution.

According to some embodiments, the step of putting in contact the initial gas mixture with the first absorbent solution is carried out at a temperature of from 10 to 80°C, preferably from 15 to 60°C, more preferably 20 to 50°C, and still more preferably from 20 to 40°C.

According to some embodiments, the first absorbent solution further comprises an acid having a concentration of less than 1 mol%.

According to some embodiments, 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 gas 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 gas mixture.

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 step of putting in contact the initial gas mixture with the first absorbent solution to the carbon dioxide volume content in the initial gas mixture before said step is 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 step of putting in contact the initial gas mixture with the first absorbent solution to the hydrogen sulfide volume content in the initial gas mixture before said step is 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 initial gas mixture.

According to some embodiments, the step of putting in contact the initial gas mixture with the first absorbent solution is carried out at an absolute pressure from 1 to 150 bar.

According to some embodiments, 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 initial gas mixture further 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 initial gas mixture in contact with the first absorbent solution.

According to some embodiments, the method further comprises:

- 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 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 gas mixture depleted in hydrogen sulfide with the 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 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 carbon dioxide stream has a content in hydrogen sulfide equal to or less than 2000 ppm, and preferably equal to or less than 200 ppm.

According to some embodiments, the method further 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, the above treatment is carried out in a Claus unit.

According to some embodiments, the method further comprising 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, the above step of hydrogenating the one or more sulfur compounds in the tail gas stream and obtaining a gas stream comprising hydrogen sulfide 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.

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, by selectively separating H2S from the gas mixture.

This is achieved by using an absorbent solution comprising a tertiary alkanolamine having the formula (I) as defined above. One main approach for increasing the selectivity of H2S absorption is to slow down the absorption of CO2, which is limited by a liquid phase transfer. By doing a digital and experimental screening, the present inventors have observed that, in most of the conventional amine compounds, a decreased rate of CO2 absorption (relative to MDEA (methyldiethanolamine)) is accompanied by a decreased rate of H2S absorption, which is not desirable. However, the present inventors have surprisingly found that it is not the case with the tertiary alkanolamine having the formula (I) as defined above: the CO2 absorption rate is decreased without impacting the H2S absorption rate. Furthermore, the present inventors have confirmed in pilot absorption-regeneration tests that the selectivity of H2S over CO2 is higher with the tertiary alkanolamine having the formula (I) than with conventional amine compounds such as MDEA.

One advantage of the invention is that, due to the high selectivity, the specification of H2S (e.g., up to 4 ppm by volume) in the treated gas (after H2S is separated) can be more easily achieved.

Another advantage is good regeneration of the solvent since the solvent is mostly aqueous. Moreover, the present method can be easily implemented with conventional units/installations without any major modification because the physical properties of the aqueous solution of the tertiary alkanolamine having the formula (I) as defined above are close to conventional aqueous solutions of, for example, MDEA.

Thus, the method of the present invention is regenerative, continuous and selective over a wide range of natural gas composition, making it possible to efficiently 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. As the concentration of carbon dioxide is reduced in the hydrogen sulfide stream, it is also possible to reduce the size of the downstream gas treatment installations (for example reduce the size of the Claus unit) and thus the capital expenditure (CAPEX) of the process.

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 another part of the method according to the invention.

Figure 3 shows CO2 slippage (CO2 in treated gas/CO2 in feed gas) and H2S content in the treated gas over a temperature ranging from 20 to 40°C in an absorption column, using a first absorbent solution of the invention (black cercles for CO2 slippage, and black diamonds for H2S content) and a conventional absorbent solution (blank cercles for CO2 slippage, and blank squares for H2S content). The CO2 slippage (%) can be read on the Y-axis on the left side, the H2S content can be read on the Y-axis on the right side, and the temperature (°C) can be read on the X-axis.

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

Initial gas mixture

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

The initial gas mixture of the present invention comprises at least hydrogen sulfide and carbon dioxide.

The initial 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 initial gas mixture. This content can be measured by gas phase chromatography.

In addition, the initial 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 initial gas mixture. This content can be measured by gas phase chromatography.

Optionally, the initial 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 initial 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 initial gas mixture.

According to some embodiments, the initial 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 initial gas mixture.

The initial gas mixture may further comprise at least one hydrocarbon. These hydrocarbons are for example saturated hydrocarbons for example Ci 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 initial gas mixture is preferably 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. In other embodiments, the initial gas mixture may be a refinery gas, a biomass fermentation gas, a tail gas obtained at the outlet of sulfur chains (CLAUS installation).

First absorbent solution

The first absorbent solution according to the present invention makes it possible to selectively separate H2S relative to CO2 from the initial gas mixture described above.

The first absorbent solution comprises at least 95 wt% of a first absorbent compound and water, i.e. the total concentration of the first absorbent and water make up at least 95 wt% of the first absorbent solution.

The first absorbent compound is a tertiary alkanolamine having the following formula (I):

RI-N(-R₃)-R₂ wherein

- R1 and R2 are the same or different, and are independently a secondary or tertiary C3 to C5 alkanol group, and

- R3 is a Ci to C5 branched or straight alkyl group.

In some embodiments, R1 and R2 of the formula (I) may be the same.

In some embodiments, R3 may be a Ci to C3 alkyl group, preferably selected from methyl and isopropyl.

In preferred embodiments, the first absorbent compound may be chosen from methyldiisopropanolamine (MDIPA), 1 ,1 '-(isopropylamino)di(2-propanol), 1- [(2-hydroxybutyl)(methyl) amino]butan-2-ol, and 1 ,1 '-(methylamino)bis(2-methyl- 2-propanol).

In preferred embodiments, a single compound of formula (I) is present. However, it is also possible to use a combination of two or more compounds of formula (II). In such a case, by “the first absorbent compound" is meant “the combination of first absorbent compounds" .

The first absorbent compound of the present invention shows higher selectivity than the conventional amine compound, such as MDEA. Without wishing to be bound by theory, it is believed that this higher selectivity may be due to the additional alkyl groups which make the entire compound an amphiphilic (hydrophobic-hydrophilic) molecule. For example, one example of the first absorbent compound of the present invention, MDIPA, is similar to MDEA (having a similar pKa), and has two additional -CH3 groups in the two “alkanol” branches, thus making them iso-alkanol branches. Due to the presence of the three additional -CH3 groups in total, the compound becomes an amphiphilic molecule, which may have a strong impact on the partial charges of the oxygen and nitrogen atoms and on the solvation effects.

The total concentration of the first absorbent compound and the water in the first absorbent solution may be at least 96 wt%, preferably at least 97 wt%, more preferably at least 98 wt%, and further preferably at least 99 wt%.

The concentration of the first absorbent compound in the first absorbent solution may be more than 40 wt%, and preferably more than 50 wt%, and more preferably more than 55 wt% relative to the total weight of the first absorbent solution. For example, the first absorbent compound may be present in an amount of from 40.1 to 50%, 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 weight relative to the total weight of the first absorbent solution.

The concentration of the water in the first absorbent solution may be less than 60 wt%, preferably less than 50 wt%, and more preferably less than 45 wt%. For example, the water may be present in an amount of 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 50%, 55 to 59.9% by weight relative to the total weight of the first absorbent solution.

The fact that the first absorbent solution comprises more than 50% by mass of the first absorbent compound makes it possible to optimize the selective separation of hydrogen sulfide from carbon dioxide. In fact, although the first absorbent compound can typically react with both H2S and CO2, due to the presence of a high concentration of the absorbent compound in the absorbent solution, H2S is selectively absorbed by the absorbent solution, relative to CO2. This is because, at a low water concentration by mass, the capture of H2S is favored relative to the capture of CO2.

According to preferred embodiments, the tertiary alkanolamine 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 tertiary alkanolamine is more basic, and in particular more basic than MDEA.

In some embodiments, water is the only solvent in the first absorbent solution (in particular, no organic solvent is present).

According to some embodiments, the first absorbent solution may consist essentially of water and the first absorbent compound.

According to some embodiments, the first absorbent solution may consist of the first absorbent compound and water. According to other embodiments, the absorbent solution may further comprise an acid.

The acid may have a pKa value of less than 6, in particular less than 5.

The amount of acid in the first absorbent solution may be 0.1 to 5.0 wt%, preferably 0.2 to 4.0 wt%, 0.3 to 3.0 wt% and more preferably 0.4 to 2.0 wt%, relative to the total weight of the first absorbent solution.

In mole percent, the acid may be present in the first absorbent solution in an amount of less than 1 mol%. For example, the acid may be present in the first absorbent solution in an amount of from 0.1 to 0.5 mol%, or from 0.5 to 0.99 mol%.

The acid may be selected from organic and inorganic acids. Suitable acids include for example phosphonic acids, sulfonic acids, carboxylic acids and amino acids.

The addition of the above acid makes it possible to more easily achieve the H2S specification of e.g. up to 4 ppm by volume in the treated initial gas.

The first absorbent solution may further comprise one or more other additional compounds.

Such additional compounds may be chosen for example from 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.

Selective separation of hydrogen sulfide

The method according to the invention comprises a step of putting the initial gas mixture as described above in contact with the first absorbent solution as defined above, so as to obtain a gas mixture depleted in hydrogen sulfide and a first absorbent solution loaded with hydrogen sulfide.

In some embodiments, the step of putting in contact the initial gas mixture with the first absorbent solution may be carried out at a temperature of from 10 to 80°C, preferably from 15 to 50°C, more preferably from 20 to 40°C.

This step may be carried out at an absolute pressure from 1 to 150 bar, and preferably from 1 to 80 bar.

This 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 packing 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/s² 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 figure 1, the initial gas mixture entering the absorption column 1 from the bottom part of the column 1 (via a 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 initial gas mixture may have a flow rate during this step from 0.23 x 10⁶ to 56 x 10⁶ Nm³/day.

The first absorbent solution may have a flow rate during this step from 100 to 50000 m³/day, preferably 500 to 50000 m³/day, and more preferably 800 to 50000 m³/day.

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

At the end of this step, as illustrated in figure 1 , a stream of gas mixture depleted in hydrogen sulfide may be collected from the top (via a 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 (via a loaded solution collecting line 4).

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 comprising (most of the) H2S.

In case the initial gas mixture comprises one or more hydrocarbons, at the end of this step, the stream of gas mixture depleted in hydrogen sulfide predominantly contains the hydrocarbons while the stream of first absorbent solution loaded with hydrogen sulfide contains no hydrocarbons or only a residual amount of hydrocarbons.

In case the initial gas mixture comprises one or more mercaptans, such mercaptans are predominantly recovered in the first absorbent solution loaded with hydrogen sulfide.

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 gas mixture.

The stream of gas mixture depleted in hydrogen sulfide may have 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, or equal to or lower than 4 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 4 ppm; or from 4 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 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 gas mixture.

On the other hand, the volume concentration of carbon dioxide in the stream of first absorbent solution loaded with hydrogen sulfide may be from 0.1 to 10%, and preferably from 0.5 to 5% by volume relative to the volume of the first absorbent solution loaded with hydrogen sulfide.

The ratio Rs of the H2S volume content in the gas mixture after this step to the H2S volume content in the initial gas mixture before this 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 this step to the CO2 volume content in the initial gas mixture before this 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 initial 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 first absorbent solution loaded with hydrogen sulfide. This step may be carried out for example by passing the first absorbent solution loaded with hydrogen sulfide from the absorption column 1 , via the loaded solution collecting line 4 and into a flash tank 5 (as illustrated in figure 1). This step may be carried out at a temperature from 50°C to 90°C and at an absolute pressure from 4 to 15 bar.

The 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 for example after a compression step.

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.

In some embodiments, 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, not illustrated in the figures).

This desorption of H2S may be promoted by the low pressure and high temperature prevailing in the regeneration column. For example, this step 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.

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 first absorbent 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.

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 first absorbent solution therefore comprising the first absorbent compound and water) may be cooled in a condenser present in the regeneration column 9, for example at a temperature from 120 to 50°C before being recycled. At least part of the regenerated first absorbent solution may be recycled in the above step of putting the initial gas mixture in contact with the first absorbent solution. As illustrated in figure 1 , for example, the 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 and enter the absorption column 1 via the lean solution collecting line 10.

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.

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

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

The method according to the present invention may further comprise a step of 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 a step of regenerating the second absorbent solution loaded with carbon dioxide so as to collect a carbon dioxide stream and a regenerated second absorbent solution.

The method may further comprise 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.

The separation of carbon dioxide and the downstream treatment of hydrogen sulfide are illustrated in figure 2. After carrying out the selective separation of H2S as detailed above (this treatment being represented by “15” in figure 2) on the initial gas mixture to be purified, represented by “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 hydrogen sulfide 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 may be put in contact with the second absorbent solution comprising an absorbent compound capable of capturing CO2.

The second absorbent solution may comprise at least one amine in water. The amine is preferably selected from di-ethanol amine (DEA), methyl-di-ethanol amine (MDEA), activated MDEA, any other amine known in the art for absorbing CO2 and mixtures thereof.

The second absorbent solution may have an amine content of from 20 to 50 wt% relative to the total weight of the second absorbent solution.

During this step, the gas mixture depleted in hydrogen sulfide may have a flow rate from 0.23 x 10⁶ to 56 x 10⁶ Nm³/day.

During this step, the second absorbent solution may have a flow rate from 800 to 50000 m³/day.

According to some embodiments, this step may be carried out at a temperature from 25 to 100°C.

In addition, according to some embodiments, this step 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, represented by F in Figure 2 (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 carbon dioxide stream may be collected from, for example, a CO2 collecting line 18. This may be carried out for example in a regeneration column (wherein the second 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, for example, in the step of putting the gas mixture depleted in hydrogen sulfide in contact with the second absorbent solution, and thus the regenerated second absorbent solution may be fed to the absorption column (not illustrated in the figures).

The step of regenerating the second absorbent solution loaded with carbon dioxide 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 has a content in hydrogen sulfide 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 . The resulting pure CO2 stream, as represented by G in Figure 2, can be stored in subterranean formations, or used in enhanced oil recovery (EOR) or in other applications.

On the other hand, the hydrogen sulfide 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 convert 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 may be 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.

The method of the invention may further comprise 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, the tail gas stream may be fed into a TGT (Tail Gas Treatment) unit (represented by a hydrogenation reactor 22 and an absorber unit 23). Treatment in such a 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 a 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 (RGG), a hydrogenation reactor 22, a quench tower, and an absorber unit 23. More particularly, in the 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. In the conventional method, a purified gas comprising CO2 and H2S may be recovered after an AGR (Acid Gas Removal) Unit, and this purified gas may then treated by a Claus unit. Thus, CO2 and H2S are both separated from the initial gas mixture and are both treated in the Claus unit, which may have an impact on the size and operating costs of the installation.

In the present method, due to the selective separation of H2S over CO2, it is possible to recover high-purity CO2 and use it in other applications. Consequently, after carrying out the selective separation method detailed above, the stream of gas mixture depleted in hydrogen sulfide recovered from the top of the absorption column 1 and the H2S stream recovered at the top of the regeneration column 9 can be treated separately and independently from one another.

This makes it 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. Moreover, it is also possible to capture more CO2 at a higher purity. Overall, the cost expressed as cost per ton of CO2 avoided is significantly lower with the set-up of figure 2 compared to the conventional installation in which CO2 and H2S are both recovered in the AGR unit and then both treated in the Claus unit.

Examples

The following examples illustrate the invention without limiting it.

Example 1

The pilot scale testing was performed using the following solutions as an absorbent solution:

- A: 13 mol% (55 wt%) of MDIPA in 87 mol% (45 wt%) of water; and

- B: 13 mol% MDEA (50 wt%) in 87 mol% (50 wt%) water.

An initial gas mixture was put in contact with each of the above absorbent solutions at a temperature ranging from 20 to 60°C in an absorption column.

The fraction of CO2 which was not absorbed by the absorbent solution (the fraction of CO2 that passed the absorption column, the phenomenon also called “CO2 slippage”, determined by the formula: CO2 in treated gas / CO2 in feed gas) was measured using a gas chromatograph (PERICHROM model PR2100, France).

The results are shown in Figure 3. The results are normalized to the H2S specification: the plot was obtained at the same H2S specification of 4 to 15 ppm of the treated gas. As shown in Figure 3, in the tests performed at the temperature of 20°C and 30°C, the absorbent solution A comprising MDIPA (the first absorbent solution of the present invention) shows increased rate of CO2 slippage compared to the absorbent solution B comprising MDEA (Comparative Example), for achieving the H2S specification of 4 or 5 ppm in the treated gas. In the tests performed at the temperature of 40°C, the H2S content in the treated gas using the absorbent solution A is a little bit higher (but still comparable to) than using the absorbent solution B. In these tests, the absorbent solution A comprising MDIPA shows increased rate of CO2 slippage compared to the absorbent solution B comprising MDEA, for achieving a similar H2S specification in the treated gas. The results of these tests indicate that the solution A has better chemical selectivity of H2S over CO2 than the solution B.

In addition, better selectivity was observed at a lower temperature in both solutions. However, the chemical selectivity did not depend on other operating conditions, such as the total pressure.

Since the solution was an aqueous solution, good regeneration of the solvent was also demonstrated.

Claims

1. A method for the purification of a gas mixture, the method comprising: putting in contact an initial gas mixture comprising at least hydrogen sulfide and carbon dioxide 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; and regenerating the first absorbent solution loaded with hydrogen sulfide so as to obtain a hydrogen sulfide stream and a regenerated first absorbent solution; wherein the first absorbent solution comprises at least 95 wt% of a first absorbent compound and water, and the first absorbent compound is a tertiary alkanolamine having the following formula (I):

RI-N(-R₃)-R₂ wherein :

Ri and R₂ are the same or different, and are independently a secondary or tertiary C₃ to Cs alkanol group, and

R₃ is a Ci to Cs branched or straight alkyl group.

2. The method according to claim 1 , wherein R1 and R₂ are the same.

3. The method according to claim 1 or 2, wherein R₃ is a Ci to C₃ alkyl group, preferably selected from methyl and isopropyl.

4. The method according to any one of claims 1 to 3, wherein the first absorbent compound is chosen from methyldiisopropanolamine (MDIPA), 1 ,1 '-(isopropylamino)di(2-propanol), 1 -[(2- hydroxybutyl)(methyl) amino]butan-2-ol, and 1 ,1 '- (methylamino)bis(2-methyl-2-propanol).

5. The method according to any one of claims 1 to 4, wherein the total concentration of the first absorbent compound and the water in the first absorbent solution is at least 98 wt%.

6. The method according to any one of claims 1 to 5, wherein the concentration of the first absorbent compound is more than 40 wt%, and the concentration of water is less than 60 wt%, relative to the total of the first absorbent solution.

7. The method according to any one of claims 1 to 6, wherein the step of putting in contact the initial gas mixture with the first absorbent solution is carried out at a temperature of from 10 to 80°C, preferably from 15 to 50°C, more preferably from 20 to 40°C.

8. The method according to any one of claims 1 to 7, wherein the first absorbent solution further comprises an acid having a concentration of less than 1 mol%.

9. The method according to any one of claims 1 to 8, 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 gas 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 gas mixture.

10. The method according to any one of claims 1 to 9, wherein 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.

11. The method according to any one of claims 1 to 10, wherein the ratio of the carbon dioxide volume content in the gas mixture after the step of putting in contact the initial gas mixture with the first absorbent solution to the carbon dioxide volume content in the initial gas mixture before said step is 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 step of putting in contact the initial gas mixture with the first absorbent solution to the hydrogen sulfide volume content in the initial gas mixture before said step is lower than 0.001 , and preferably lower than 0.0001 .

12. The method according to any one of claims 1 to 11 , wherein 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 initial gas mixture.

13. The method according to any one of claims 1 to 12, wherein the step of putting in contact the initial gas mixture with the first absorbent solution is carried out at an absolute pressure from 1 to 150 bar.

14. The method according to any one of claims 1 to 13, wherein 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.

15. The method according to any one of claims 1 to 14, wherein the initial gas mixture further comprises at least one hydrocarbon, and is preferably natural gas.

16. The method according to any one of claims 1 to 15, wherein at least part of the regenerated first absorbent solution is recycled in the step of putting the initial gas mixture in contact with the first absorbent solution.

17. The method according to any one of claims 1 to 16, comprising: 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.

18. The method according to claim 17, wherein the second absorbent solution comprises at least one amine in water, the amine preferably selected from di-ethanol amine, methyl-di-ethanol amine, activated methyl-di-ethanol amine and mixtures thereof.

19. The method according to claim 17 or 18, wherein the step of putting in contact the gas mixture depleted in hydrogen sulfide with the 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.

20. The method according to any one of claims 17 to 19, wherein 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.

21. The method according to any one of claims 17 to 20, wherein the carbon dioxide stream has a content in hydrogen sulfide equal to or less than 2000 ppm, and preferably equal to or less than 200 ppm.

22. The method according to any one of claims 1 to 21 , comprising 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.

23. The method according to claim 22, wherein said treatment is carried out in a Claus unit.

24. The method according to claim 22 or 23, further comprising a step of hydrogenating the one or more sulfur compounds in the tail gas stream and obtaining a gas stream comprising hydrogen sulfide.

25. The method according to claim 24, wherein said step is carried out in a tail gas treatment unit.

26. The method according to claim 24 or 25, wherein 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.