CA3235954A1

CA3235954A1 - Method for the purification of a gas mixture comprising carbon dioxide and optionally hydrogen sulfide

Info

Publication number: CA3235954A1
Application number: CA3235954A
Authority: CA
Inventors: Frederick De Meyer; Karen GONZALEZ-TOVAR; Benedicte Poulain
Original assignee: TotalEnergies Onetech SAS
Current assignee: TotalEnergies Onetech SAS
Priority date: 2021-10-26
Filing date: 2021-10-26
Publication date: 2023-05-04
Also published as: WO2023073389A1

Abstract

The present invention relates to a method for the purification of a gas mixture comprising carbon dioxide and optionally hydrogen sulfide, the method comprising: putting in contact an initial gas mixture comprising hydrogen sulfide at an amount equal to or less than 20 volume % and carbon dioxide at an amount equal to or less than 20 volume %, with an absorbent solution so as to obtain a gas mixture depleted in carbon dioxide and/or hydrogen sulfide, and an absorbent solution loaded with carbon dioxide and/or hydrogen sulfide, wherein the absorbent solution comprises at least one tertiary amine, at least one glycol compound and water; and regenerating the absorbent solution loaded with carbon dioxide and/or hydrogen sulfide so as to collect a stream comprising carbon dioxide and/or hydrogen sulfide and a regenerated absorbent solution.

Description

Method for the purification of a gas mixture comprising carbon dioxide and optionally hydrogen sulfide Technical field The present invention relates to a method for the purification of a gas mixture comprising hydrogen sulfide at an amount equal to or less than 20 volume % and carbon dioxide at an amount equal to or less than 20 volume %.
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 Ito 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 `)/0 by volume.

A well known technology used for acid gas separation and thus for gas purification is absorption by an absorbent solution, typically an aqueous amine. A
major disadvantage regarding the implementation of this technology on industrial sites is its high cost due to the large amount of energy required for the regeneration of the absorbent solution loaded with acid gases. In other words, energy is required to heat and vaporize part of the loaded absorbent solution for its regeneration and for the desorption of the acid gases.
The article "Carbon dioxide solubility in mixtures of methyldiethanolamine with monoethylene glycol, monoethylene glycol¨water, water and triethylene glycol" of E. Skylogianni etal. (J. Chem. Thermodynamics, 151 (2020), 106176) describes a study related to the carbon dioxide solubility in non-aqueous and aqueous mixtures of methyldiethanolamine (MDEA) with monoethylene glycol (MEG), as such solvents are relevant for the combined acid gas removal and hydrate control in natural gas treatment.
The article "Signs of alkylcarbonate formation in water-lean solvents: VLE-based understanding of pKa and pKs effects" of R. R. Wanderley et al.
(International Journal of Greenhouse Gas Control, 109 (2021), 103398) relates to a study evaluating alkylcarbonate-forming water-lean solvents based on the properties of its single constituents, namely the basicity of the amine and the autoprotolysis constant of the organic diluent.
Document EP 3083012 relates to a method for the capture of at least one acid gas in a composition, the release of said gas from said composition, and the subsequent regeneration of said composition for re-use, said method comprising performing, in order, the steps of: (a) capturing the at least one acid gas by contacting said at least one gas with a capture composition comprising at least one salt of a carboxylic acid and at least one water-miscible non-aqueous solvent;
(b) releasing said at least one acid gas by adding at least one protic solvent or agent to said composition; and (c) regenerating the capture composition by partial or complete removal of said added protic solvent or agent from said composition.
Document US 2016/0193563 relates to a solvent for recovery of carbon dioxide from gaseous mixture, having alkanolamine, reactive amines acting as promoter or activators, glycol, and a carbonate buffer.
Document WO 2012/034921 relates to a process for CO2 capture from gas mixtures and for CO2 removal from gaseous wastes of industrial processes or combustion gases, which is carried out by bringing into contact the gas mixtures with an absorbent solution of amines in anhydrous alcohols; this process comprising CO2 absorption at room temperature and atmospheric pressure and

3 CO2 absorption and amine regeneration at temperatures lower than the boiling temperature of the solution and at atmospheric pressure.
The article "CO2 solubility and mass transfer in water-lean solvents" of R.
R. Wanderley et al. (Chemical Engineering Science (2019), doi:
https://doi.org/10.1016/j.ces.2019.03.052) describes the effects of adding organic diluents to chemical solvents, both in terms of shifts to CO2 solubilities and mass transfer rates. Such study allows for some insights regarding the interplay of chemical properties in water-lean solvents.
There is thus a need for a method which makes it possible to efficiently separate acid gases such as carbon dioxide and hydrogen sulfide from a gas mixture and to efficiently regenerate the solution used for the separation method, with low energetic consumption and without deteriorating the other process parameters (such as absorption capacity, thermal degradation).
Summary of the invention It is a first object of the invention to provide a method for the purification of a gas mixture comprising carbon dioxide and optionally hydrogen sulfide, the method comprising:
putting in contact an initial gas mixture comprising hydrogen sulfide at an amount equal to or less than 20 volume % and carbon dioxide at an amount equal to or less than 20 volume %, with an absorbent solution so as to obtain a gas mixture depleted in carbon dioxide and/or hydrogen sulfide, and an absorbent solution loaded with carbon dioxide and/or hydrogen sulfide, wherein the absorbent solution comprises at least one tertiary amine, at least one glycol compound and water; and ¨ regenerating the absorbent solution loaded with carbon dioxide and/or hydrogen sulfide so as to collect a stream comprising carbon dioxide and/or hydrogen sulfide and a regenerated absorbent solution.
According to some embodiments, the glycol is present in the absorbent solution at a content from 20 to 45 mol A) and preferably from 20 to 40 mol %
relative to the absorbent solution.
According to some embodiments, the absorbent solution has a boiling temperature from 105 to 140 C, and preferably 130 to 135 C.
According to some embodiments, the tertiary amine is chosen from N-nnethyldiethanolann ine, 2-(2-diethylanninoethoxy)ethanol, (2,2'-(((methylazaned iy1)bis(ethane-2,1-diy1))bis(oxy))diethanol), 3,9-d innethy1-6-oxa-

4 3,9-diaza-undecane-1,11-diol and 4-morpholin-4-ylpentan-1-ol, and mixtures thereof.
According to some embodiments, the glycol compound is ethylene glycol.
According to some embodiments, the step of putting in contact the gas mixture with an absorbent solution is carried out at a temperature from 25 to and/or at an absolute pressure from 1 to 170 bar.
According to some embodiments, the step of putting in contact the gas mixture with an absorbent solution is carried out in an absorption column or in a rotating packed bed.
According to some embodiments, the gas mixture comprises at least one hydrocarbon, and is preferably natural gas.
According to some embodiments, the step of regenerating the absorbent solution loaded with carbon dioxide and/or hydrogen sulfide is carried out in a regeneration column (9).
According to some embodiments, regenerating the absorbent solution loaded with carbon dioxide and/or hydrogen sulfide is carried out by heating the absorbent solution loaded with carbon dioxide and/or hydrogen sulfide preferably at a temperature from 100 to 200 C, and more preferably from 110 to 140 C.
According to some embodiments, regenerating the absorbent solution loaded with carbon dioxide and/or hydrogen sulfide is carried out at an absolute pressure from 1 to 3 bar.
According to some embodiments, during the regeneration of the absorbent solution loaded with carbon dioxide and/or hydrogen sulfide, the energy consumption is from 80 to 200 MJ/m3 of absorbent solution.
According to some embodiments, the regenerated absorbent solution is recycled in the step of putting in contact the gas mixture with an absorbent aqueous solution.
The present invention enables to meet the abovementioned need. In particular the invention provides a method which makes it possible to separate acid gases such as carbon dioxide and hydrogen sulfide from a gas mixture and to efficiently regenerate the solution used for the separation method, with low energetic consumption and without deteriorating the other process parameters (such as absorption capacity, thermal degradation).
This is achieved by the method according to the present invention. More particularly, when the gas mixture to be purified comprises hydrogen sulfide at an amount equal to or less than 20 volume % and carbon dioxide at an amount equal to or less than 20 volume %, and when the absorbent solution used for the separation of acid gases comprises a tertiary amine, a glycol compound and water, it is possible to significantly reduce the energy consumption during the separation method, and more specifically during the regeneration of the absorbent solvent.
Putting in contact a gas stream comprising carbon dioxide (CO2) and

5 optionally hydrogen sulfide (H2S) with an absorbent solution comprising a tertiary amine, a glycol compound and water makes it possible to separate the carbon dioxide and optionally the hydrogen sulfide from the rest of the gas mixture.
Furthermore, the absorbent solution loaded with the acid gases will be regenerated by heating and vaporizing the solvent so as to desorb the acid gases.
On the one hand, the specific combination of components in the absorbent solution makes it possible to reduce the energy required for the desorption of the acid gases from the absorbent solution and also the energy used to heat up the solvent in order to attain a temperature at which the water present in the solvent can be vaporized during the regeneration step (relative to an absorbent solution devoid of glycol for example). In addition, even though the presence of a glycol compound should decrease the absorption capacity and the absorption rate of the solution, due to the hydroxy groups of such molecule, it seems that the glycol is involved in the chemical absorption of the acid gases, therefore affecting less the absorption capacity of the absorbent solution than other co-solvents (such as co-solvents devoid of hydroxy groups).
On the other hand, the above advantageous effects are observed for initial gas mixtures comprising specific amounts of acid gases and more particularly comprising an amount of hydrogen sulfide equal to or less than 20 volume % and an amount of carbon dioxide equal to or less than 20 volume %. In fact, when the initial gas comprises more than 20 volume A of hydrogen sulfide, the energy gain is less significant than the energetic gain during the purification of a gas mixture comprising an amount of hydrogen sulfide equal to or less than 20 volume %.
Brief description of the drawings Figure 1 illustrates an installation used for the implementation of the method according to one embodiment of the invention.
Figure 2 illustrates H2S concentration profiles in the vapor phase of the absorption column in tests 1 and 3 (see below). The number of column segments can be read on the Y-axis and the CO2 concentration (in mol%) can be read on the X-axis.
Figure 3 illustrates CO2 concentration profiles in the vapor phase of the absorption column in tests 1 and 3 (see below). The number of column segments

6 can be read on the Y-axis and the CO2 concentration (in mol%) can be read on the X-axis.
Figure 4 illustrates H2S concentration profiles in the vapor phase of the absorption column in tests 2 and 4 (see below). The number of column segments can be read on the Y-axis and the H2S concentration (in mol%) can be read on the X-axis.
Figure 5 illustrates CO2 concentration profiles in the vapor phase of the absorption column in tests 2 and 4 (see below). The number of column segments can be read on the Y-axis and the CO2 concentration (in mol%) can be read on the X-axis.
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.
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 carbon dioxide.
The gas mixture according to the present invention comprises carbon dioxide in a content equal to or less than 20 % by volume, preferably equal to or less than 10 % by volume, preferably from 0.1 to 10 % by volume, and more preferably from 0.5 to 10 % by volume relative to the volume of the gas mixture.
This content may be for example from 0.1 to 0.2 cY0; or from 0.2 to 0.5 %; or from 0.5 to 1 %; or from 1 to 2 %; or from 2 to 3 %; or from 3 to 4 %; or from 4 to 5 %;
or from 5 to 6 %; or from 6 to 7 %; or from 7 to 8%; or from 8 to 9 %; or from 9 to 10 %; or from 10 to 11 %; or from 11 to 12 %; or from 12 to 13 %; or from 13 to 14 %; or from 14 to 15 %; or from 15 to 16 %; or from 16 to 17 %; or from 17 to 18 %; or from 18 to 19 %; or from 19 to 20 % by volume relative to the volume of the gas mixture. This content can be measured by gas phase chromatography and spectroscopy.

7 In addition, the gas mixture of the present invention comprises hydrogen sulfide in a content equal to or lower than 20 % by volume, preferably equal to or lower than 10 % by volume, more preferably equal to or lower than 5 % by volume, and more preferably equal to or lower than 3 A by volume relative to the volume of the gas mixture. This content may be for example from 0.001 to 0.01 (Yo; or from 0.01 to 0.5%; or from 0.5 to 1 %; or from 1 to 2%; or from 2 to 4%; or from 6 to 6%; or from 6 to 8%; or from 8 to 10%; or from 10 to 12%; or from 12 to 14%;
or from 14 to 16%; or from 16 to 18%; or from 18t0 20% 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 nnercaptan, ethyl nnercaptan, 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 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 Cl 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.
Absorbent solution The absorbent solution according to the present invention makes it possible to separate CO2 and optionally H2S from the gas mixture described above.
The absorbent solution according to the invention is an aqueous solution that comprises at least one tertiary amine and at least one glycol compound.
In other words, the absorbent solution is a mixture of a tertiary amine, a glycol compound and water.
The tertiary amine may be for example aliphatic, cyclic or aromatic.
Preferably, the tertiary amine is selected from tertiary alkanolamines. It may be reminded that the alkanolannines or amino alcohols are amines comprising at least

8 one hydroxyalkyl group (comprising for example from 1 to 10 carbon atoms) bound to the nitrogen atom.
The tertiary amine may further comprise at least one oxygen and/or at least one sulfur atom.
According to other preferred embodiments, the tertiary amine may be an ethoxyethanolamine, such as 2-(2-diethylaminoethoxy)ethanol (DEAE-EO), (2,2'-(((methylazanediy1)bis(ethane-2,1-diy1))bis(oxy))diethanol).
According to other preferred embodiments, the tertiary amine may be a tertiary amine comprising a morpholinone function, such as 4-morpholin-4-ylpentan-1-ol .
According to other preferred embodiments, the tertiary amine may be a tertiary polyamine such as 3,9-dimethy1-6-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 tertiary amine and in particular of tertiary alkanolamines are given in US 2008/0025893, the description of which can be referred to.
More particular examples include N-methyldiethanolamine (MDEA), N,N-d iethylethanolannine (DEEA), N,N-d imethylethanolamine (DM EA), 2-diisopropylaminoethanol (DIEA), N,N,N',N'Aetramethylpropanediannine (TM P DA), N,N,N',N'-tetraethylpropanediamine (TEPDA), d innethylamino-2-dimethylarn ino-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)annine (Methanol am me, TEA), tris(2-hydroxypropyl)amine (triisopropanol), tributylethanolamine (TEA), bis(2-hydroxyethyl)methylamine (methyldiethanolamine, MDEA), 2-diethylaminoethanol (diethylethanolamine, DEEA), 2-d imethylam inoethanol (dimethylethanolamine DMEA), 3-d imethylam ino-1-propanol, 3-d iethylam ino-1 -propanol, diisopropylanninoethanol (DIEA), N,N-bis(2-hydroxypropyl)methylamine or nnethyldiisopropanolamine (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-methyld iethanolamine,

9 triethanolannine, N-ethyldiethanolamine, 2-d imethylaminoethanol, 2-d imethylam ino-1-propanol, 3-d imethylamino-1-propanol, 1-d innethylamino-2-propanol, N-methyl-N-ethylethanolamine, 2-d iethylaminoethanol, 3-d imethylam ino-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-methy1-1-propanol, 1-d imethylarn ino-2-methy1-2-propanol, 2-d innethylarn ino-1-butanol and 2-d imethylarn ino-2-methy1-1-propanol.
Other tertiary amines that can be mentioned include the bis(tertiary diamines) such as N,N,N',N'-tetramethylethylenediamine, N,N-diethyl-N',N'-dimethylethylenediamine, N,N,N',NI-tetraethylethylenediamine, N,N,N',N'-tetrannethy1-1,3-propanediamine (TM P DA), N,N,N',Ni-tetraethy1-1,3-propanediam me (TEPDA), N,N-dimethyl-N',N'-diethylethylenediamine (DMDEEDA), 1-d imethylam ino-2-d imethylam inoethoxy-ethane (bis[2-dimethylam ino)ethyl]ether) mentioned in U.S. Patent Publication No.
2010/0288125.
According to preferred embodiments, the tertiary amine may be chosen from N-methyldiethanolamine (MDEA), 2-(2-diethylaminoethoxy)ethanol (DEAE-E0), (2,2'-(((methylazanediy1)bis(ethane-2,1-diy1))bis(oxy))d iethanol), 3,9-dimethy1-6-oxa-3,9-d iaza-undecane-1,11-d iol and 4-morphol in-4-ylpentan-1-ol and their mixtures.
The tertiary amine may be present in the absorbent solution at a total content from 5 to 20 mol %, and preferably from 5 to 15 mol % relative to the absorbent solution. For example, such content may be from 5 to 10 mol %; or from

10 to 15 mol %; or from 15 to 20 mol % relative to the absorbent solution.
As mentioned above, the absorbent solution further comprises at least one glycol. By "glycol' is meant a molecule that comprises two hydroxy (-OH) groups.
The glycol compound is preferably miscible with the tertiary amine and with water.
By "miscible" is meant that the glycol compound forms a homogeneous mixture when mixed with water.
In addition, the glycol compound has a boiling temperature higher than 100 C, and more preferably from 120 to 250 C.
The glycol compound may be chosen from ethylene glycol, propylene glycol, diethylene glycol, ethylene glycol monobutyl ether (EGE3E), and ethylene glycol monomethyl ether (EGME).
According to preferred embodiments, the glycol compound is ethylene glycol.

The glycol compound may be present in the absorbent solution at a total content from 20 to 45mo1 `)/0, and preferably from 20 to 40 mol % relative to the absorbent solution. For example, such content may be from 20 to 25 mol /0; or from 25 to 30 mol %; or from 30 to 35 mol %; or from 35 to 40 mol %; or from 5 to 45 mol % relative to the absorbent solution.
The water may be present in the absorbent solution in an amount from 10 to 75 mol %, and preferably from 40 to 70 mol % relative to the absorbent solution.
According to some embodiments, the absorbent solution may consist of the tertiary amine, the glycol compound and water.
10 According to other embodiments, the absorbent solution may comprise one or more other additional compounds.
According to some preferred embodiments, the absorbent solution has a boiling temperature from 105 to 140 C, and preferably from 130 to 135 C. For example, this temperature may be from 105 to 110 C; or from 110 to 115 C; or from 115 to 120 C; or from 120 to 125 C; or from 125 to 130 C; or from 130 to 135 C; or from 135 to 140 C.
It is advantageous to perform the regeneration at a relatively higher temperature from a regeneration efficacy standpoint, as a higher temperature favors the desorption of the acid gases. On the other hand, the regeneration should be performed at a temperature lower than the temperature at which the amine may start degrading. For this reason, it is advantageous if the boiling temperature of the absorbent solution is not more than 135 C or 130 C.
In comparison with a binary water-amine solution having a boiling point of approximately 120 C, more energy is needed to bring the above absorbent solution to its boiling point. On the other hand, considerably less energy is needed to vaporize the water, which is present in a lesser amount. In addition, less energy is required to heat up the absorbent solution (because heat capacity of ethylene glycol is lower than the heat capacity of water). Less energy is also required for the desorption reaction because the CO2 and/or H2S are less strongly absorbed in the presence of ethylene glycol. Moreover, in industrial applications, as only a fraction of the water should be vaporized, in the presence of a glycol, such vaporization starts at higher temperature (compared to a case wherein glycol is not present). At such higher temperature, less water is present but the thermodynamic desorption is improved.
Separation method

11 The method according to the present invention makes it possible to separate CO2 and optionally H2S from the gas mixture described above by using the absorbent solution described above.
The method according to the invention comprises a first step of putting the gas mixture in contact with the absorbent solution.
This contacting (absorption) step may be carried out in any apparatus for gas-liquid contact.
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/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 gas mixture entering the absorption column 1 from the bottom part of the absorption column 1 (gas feeding line 2) is put into contact with a stream of the absorbent solution according to the invention entering the absorption column 1 from the top of the absorption column 1. This contact is preferably made in a counter-current mode.
The gas mixture may have a flow rate during this step from 300 to 56 x 106 kg/h.
In addition, the gas mixture entering the absorption column 1 may have a temperature from 25 to 100 C.
The absorbent solution may have a flow rate during this step from 800 to 1000000 kg/h.
According to some embodiments, the absorbent solution entering the absorption column 1 may have a temperature from 25 to 100 C.

12 the step of putting in contact the gas mixture with an absorbent solution may be carried out at a temperature from 25 to 100 C.
In addition, according to some embodiments, the step of putting in contact the gas mixture with an absorbent solution may be carried out at an absolute pressure from 1 to 170 bar, and preferably from 1 to 80 bar.
The gas mixture may be put in contact with the absorbent solution for a time period from 10 to 500 seconds, and preferably from 10 to 300 seconds.
At the end of this step, a stream of gas mixture depleted in carbon dioxide and optionally hydrogen sulfide may be collected from the top (gas collecting line 3) of the absorption column 1 while a stream of absorbent solution loaded with carbon dioxide and optionally hydrogen sulfide may be recovered at the bottom of the absorption column 1 (loaded solution collecting line 4). 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 absorbent solution recovered from the bottom of the absorption column 1 contains no hydrocarbons or only a residual amount of hydrocarbons.
In other words, this step makes it possible to separate on the one hand the gas comprising hydrocarbons and on the other hand the absorbent solution and (most of the) CO2 and optionally (most of the) H2S.
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 15 ppm by volume. This content can be measured by gas phase chromatography. For example, this content may be from 0 to 1 ppm; or from 1 to 2 ppm, or from 2 to 5 ppm; or from 5 to 20 ppm, or from 20 to 50 ppm; or from to 100 ppm by volume relative to the volume of the gas mixture depleted in hydrogen sulfide.
The stream of gas mixture collected from the top of the absorption column 1 may have a content in CO2 lower than 5 %, and preferably from 0.5 to 4 `)/0 by volume relative to the volume of the stream of gas mixture depleted in hydrogen sulfide.
In case the initial gas mixture comprises one or more mercaptans, such nnercaptans are predominantly recovered in the absorbent solution loaded with carbon dioxide and optionally hydrogen sulfide. The method according to the present invention may further comprise an optional step of removing residual

13 hydrocarbon from the absorbent solution loaded with carbon dioxide and optionally hydrogen sulfide.
This step may be carried out for example by passing said solution from the absorption column 1, via the loaded solution collecting line 4 and into a flash tank 5 (as illustrated in figure 1). This step may be carried out at a temperature from 50 C to 90 C and at an absolute pressure from 4 to 15 bar.
Thus, the stream of absorbent solution loaded with carbon dioxide and optionally hydrogen sulfide may exit the absorption column 1 from the bottom of the absorption column 1 and enter the flash tank 5 via the loaded solution collecting line 4. The hydrocarbons removed at this step may be used for example as fuel gas or may be recycled in the method according to the present invention for example by mixing these hydrocarbons with the (initial) gas mixture (not illustrated in the figures) for example after a compression step. The loaded absorbent solution is collected from the flash tank 5 in a loaded solution feeding line 6.
The absorbent solution loaded with carbon dioxide and optionally hydrogen sulfide can be regenerated in order to collect a stream comprising carbon dioxide and optionally hydrogen sulfide on the one hand and a regenerated absorbent solution on the other hand.
This step may be carried out in a regeneration column 9, preferably comprising a reboiler (for example at the lower (bottom) part of the regeneration column 9) (not illustrated in the figures). 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 1, the loaded solution feeding line 6 may be connected to an inlet of the regeneration column 9, so as to feed the absorbent solution loaded with carbon dioxide and optionally hydrogen sulfide to the regeneration column 9 (for example from the bottom of the regeneration column 9). During the regeneration step, the reboiler located in the regeneration column 9 may generate water steam by heating the absorbent solution loaded with carbon dioxide and optionally hydrogen sulfide and promote desorption of the carbon dioxide and optionally the hydrogen sulfide and recovery of a gas enriched in carbon dioxide and optionally hydrogen sulfide at the top of the regeneration column 9. Thus, the steam ascends in a counter-current mode in the regeneration column 9, entraining the CO2 and optionally the H2S and optionally other impurities (such as nnercaptans) remaining in the absorbent solution loaded with carbon dioxide and optionally hydrogen sulfide. This desorption is promoted by

14 the low pressure and high temperature prevailing in the regenerator. For example, heating of the absorbent aqueous solution loaded with carbon dioxide and optionally hydrogen sulfide in the regeneration column 9 may be carried out at a temperature from 100 to 200 C, and more preferably from 110 to 140 C and at an absolute pressure from 1 bar to 3 bar.
The absorbent solution loaded with carbon dioxide and optionally hydrogen sulfide may have a content in carbon dioxide from 5 kg/m3 to 45 kg/m3, and preferably from 10 kg/m3 to 30 kg/m3.
The absorbent solution loaded with carbon dioxide and optionally hydrogen sulfide may have a content in hydrogen sulfide from 10 kg/m3 to 45 kg/nn3, and preferably from 10 kg/m3 to 30 kg/m3.
According to preferred embodiments, during the regeneration of the absorbent solution loaded with carbon dioxide and optionally hydrogen sulfide, the energy consumption (duty) is from 80 to 200 MJ/m3 of absorbent solution (notably: from 80 to 100 MJ/m3, or from 100 to 120 MJ/nn3, or from 1200 to 160 MJ/m3, or from 160 to 180 MJ/m3, or from 180 to 200 MJ/m3). With this energy consumption it is possible to obtain a regenerated absorbent solution comprising an amount of 0.0015 wt% CO2 or lower and of 0.03 wt% H2S or lower. In addition, with this energy consumption it is possible to recover CO2 and H2S with a minimum recovery rate of 75 % for CO2 and 99.95 % for H2S. Such energy consumption is preferably the energy consumption in the reboiler of the regeneration column 9.
The energy consumption (duty) is calculated from the measured vapor flow rate and the latent heat of vaporization of water at the steam supply pressure according to the following equation (and is then converted into MJ/h):
exp _______________________________________ Fm n Vreb = 1000 x All ,11,2 Qreexr, = duty given to the reboiler in MJ/h;
Fm= mass flow rate (vapor) in kg/h;
i1HIla2p = latent heat of vaporization of water at the pressure of the steam stream (4 bar) = 2107 kJ/kg.
On the one hand, the CO2 and optionally the H2S and optionally impurities may be recovered as a gaseous stream at the top of the regeneration column 9 (CO2 and optionally H2S collecting line 10).

On the other hand, the steam generated in the column (deriving from the absorbent solution therefore comprising the tertiary amine, the glycol compound and water) may be cooled in a condenser present in the regeneration column 9.
As illustrated in figure 1, the condensed regenerated absorbent solution may exit 5 the regeneration column 9 via a lean solution collecting line 11 preferably at the bottom of the regeneration column 9.
The condensed regenerated absorbent solution stream may comprise an amount equal to or less than 0.03 % by weight, and preferably equal to or less than 0.01 % by weight of H2S relative to the weight of the condensed regenerated 10 absorbent solution.
The condensed regenerated absorbent solution stream exiting the regeneration column 9 may also comprise an amount equal to or less than 0,0015 % by weight, and preferably equal to or less than 0,001 (:)/0 by weight of CO2 relative to the weight of the condensed regenerated absorbent solution.

15 Optionally, for the purpose of enhancing energetic efficiency, a heat exchanger 7 may be provided in order to preheat the absorbent solution loaded with carbon dioxide and/or hydrogen sulfide before feeding it to the regeneration column 9. The heat exchanger 7 may transfer heat from the lean solution collecting line 11 to the loaded solution feeding line 6.
After cooling the regenerated absorbent solution, for example at a temperature from 120 C to 30 C, the regenerated absorbent solution may then be recycled in the step of putting in contact the gas mixture with an absorbent solution, for example by entering the absorption column 1 via the lean solution collecting line 11.
Examples The following examples illustrate the invention without limiting it.
In these examples, the potential of the absorbent solution according to the invention to reduce duty consumption in the reboiler of the regeneration column was evaluated. Pilot tests were then carried out in order to acquire experimental data to compare the performance of the absorbent solution according to the invention with a comparative absorbent solution (water-amine binary composition) (example 1) or to illustrate the efficiency of the absorbent solution according to the present invention (example 2).
Example 1:

16 Two absorbent solutions were used in this example, as detailed in the table below:
Absorbent MDEA (mol%) Ethylene glycol Water (mol()/0) solution (molc/o) B 13 ¨ 87 Four tests were carried out. Tests 1 and 2 are according to the invention (using absorbent solution A), while tests 3 and 4 are comparative tests (using absorbent solution B).
The gas composition (in vol.(:)/0) for each test is detailed in the table below:
Test CO2 H 2S N2 1 (iv) 2.4 2.3 95.3 2 (iv) 2.4 2.4 95.2 3 (comp) 2.4 2.3 95.3 4 (comp) 2.5 2.5 95.0 The absorption operating conditions are summarized in the following table:
o 2' ru c ¨
o0 0) c-_.. ,_ ._ O¨ z..._ CU
D --- (7) a) cn L- - a) a)0 r) El ¨ = 2 Co co a) Ilii 92 q= 0_ -E2 FO) E
<
1 (iv) 1006.6 39.6 30.1 409.0 2 (iv) 1005.5 49.6 38.4 409.0 3 (comp) 1003.2 41.3 31.0 409.1 4 (comp) 1002.6 50.1 39.1 409.1 After the absorption step the following performances were evaluated:

17 (I) Cl) -E. -E' õ..., co co a) 0 a) 0) 0) - U)-Cl)() -...- 0,-, ,.._.õ !-E" .c.,, !- , a) _c) c _0 c "
H CO 0 CO 0 a -'' =
, . .=, .-, .- D = - =
ON :/) CO (7) 0 c/2 1 (N V) 0 = 0 =
1 (iv) 0.0009 0.0085 0.0113 6.1 2 (iv) 0.0009 0.0136 0.006 7.7 3 (comp) 0.002 0.033 0.0097 6.5 4 (comp) 0.003 0.032 0.0062 7.3 The regeneration operating conditions (in the regeneration column) are summarized in the following table:
U) a) c a) CT) -' -c - -c E
C - c ,....., 0 0 _c, - .
5.1) 0) c c.7- a) cr) ,P. .-= . CIF) C p 0 -LJ.c 0 E _,2C,.., 2- _0 ID
0 ,- --- -a , 0 2 E.) .......
2 zr, u) .3) ET2 u) cp c 0 2 m (,), a) ----c a) i- 2 t - fa t) 't.r9 7E, U) 2 u) = - , c) a) c _ a) u) it - L _ ...._.
._ 0 y), 2 -- 0 a) b 0- 2 ON t " 8 (2, .-S= (7) u) E a_ 0 TD IOU) 0) 72 _92 a) 0 m U) u) i- 0 1 (iv) 8.2 10.9 1 1 0.1 0.63 22.8 144.43 2 (iv) 10.4 11.5 110.7 0.84 24.1 128.58 3 (comp) 9.7 10.6 109.2 1.28 28.4 259.3 4 (comp) 10.9 11.4 109.3 1.28 28.1 259.5 Concerning the regeneration performances, the duty used to regenerate the absorbent solution A according to the invention (tests 1 and 2) is considerably lower than that used in the comparative absorbent solution B (tests 3 and 4).

18 In order to compare the process performance with both absorbent solutions, the settings were such that the same H2S composition in the treated gas was obtained. The following table illustrates the column configuration used.
Parameter Absorption column Regeneration column Diameter (m) 0.194 0.3 Packed Height (m) 3.53 2.6 Packing type MELLAPAK 250X

The following process performances were obtained after the regeneration step:
Test kg of vapor /m3 solvent kg vapor/kg CO2 captured 1 (iv) 72.2 6.9 2 (iv) 64.3 5.3 Average 68.3 6.1 3 (comp) 123.4 13.0 4 (comp) 123.5 10.0 Average 123.5 11.0 From the above table, a reduction of about 70 % was observed of the ratio kg of vapor /m3 solvent when comparing the absorbent solution according to the invention A (test 1 and 2) with the comparative absorbent solution B (tests 3 and 4). Thus, the energy consumption is decreased when using the absorbent solution A.
In addition, the ratio kg vapor/ kg CO2 captured was reduced of about 85 % when comparing the absorbent solution according to the invention A (test 1 and 2) with the comparative absorbent solution B (tests 3 and 4). This also indicates a decrease in energy consumption when using the absorbent solution A.
In figures 2 (tests 1 and 3) and 4 (tests 2 and 4), the H2S composition profiles in the gas throughout the absorption column were compared. From this figure it can be concluded that for the comparative absorbent solution B
(tests 2 and 4), most part of the H2S is absorbed in the bottom half of the column and in the upper half the absorption rate is very low. The upper half of the column is used

19 to reach H2S specification. For the absorbent solution A (test 1 and 2) the absorption rate in the bottom half of the column is lower but it is higher at the upper half. The H2S absorption rate is more linear for absorbent solution A.
The H2S profiles are different for the two absorbent solutions, but very similar contents in the treated gas (top of the column) are obtained in all tests ( around 7 PPrnw)-In figures 3 (tests 1 and 3) and 5 (tests 2 and 4), the CO2 composition profiles in the gas throughout the absorption column were compared. From this figure it can be concluded that for the comparative absorbent solution B
(tests 2 and 4), the CO2 absorption rate is higher at the bottom half of the column than that in the absorbent solution A (tests 1 and 2). In the upper half, the CO2 absorption rate is higher for the absorbent solution A. When comparing absorbent solutions A and absorbent solutions B performances, similar compositions of are obtained in the treated gas (top of the column).
Example 2:
One absorbent solution (according to the invention) was used in this example, as detailed in the table below:
Absorbent MDEA (mol%) Ethylene glycol Water (mol%) solution (mol /0) Three tests (5, 6 and 7) were carried out, all tests being according to the invention.
The gas composition (in vol. /0) for each test is detailed in the table below:
Test CO2 H2S N2 5 (iv) 2.6 2.6 94.8 6 (iv) 2.4 2.4 95.2 7 (iv) 2.4 2.6 95.0 The absorption operating conditions are summarized in the following table:

o 4= c ---- 0 3) ..
0 1 C -_, ._ 0 m 2._... Ct TD, a) _o 1 õ......, D '---- CO 1- a) V) .7) 5' 9 2 I!
a) u) ¨ "L" -= = .........
i¨ o a) [13 =
2 co a) ro -2 a) (1) u) o a) o) a3 2 E 2 u=
0_ _ a) a_ u) E
o 0 u) < 0 a) _ca 1¨

<
5 (inv) 1002.4 60.4 38.2 409.0 6 (iv) 821.4 39.6 38.4 409.0 7 (inv) 1502.1 49.7 38.4 408.9 After the absorption step the following performances were evaluated:
U) u) , ¨ a)as a) . a) o) 0) ...:.

o - ' 0, ...._, o U) .._.- a) :(1) -;--tii ,- E
a) _a , _o C
U) 1¨ as cp CO 0 a -g 0_ o_ 0_ =¨ = .¨ = c c --,, 61 cf) (7) 04 u2 Pi) 0 = 0 m 5 (iv) 0.0008 0.0146 0.0063 12.8 6 (iv) 0.0009 0.0063 0.0076 4.1 7(iv) 0.0012 0.0281 0.0045 6.5 5 The regeneration operating conditions (in the regeneration column) are summarized in the following table:

a) a) C
"E" --5 -E' _-F, E C --, o 0 =
a) 01 C ,-) a) 0-) -_.. " C) o -12 coE -E)CTD Co CO
_CD C o _CD
c,1¨ 79 02 2 ¨
co a) C c _o ' (I)--..- .D -L' 0 L_ ¨ D
ilL) = co CD ----a) I¨ co a) _C co a) =-,.., C (7) 2 m u) , (I) C = a) C C C _CD CD CO
a) -0 C .¨..-.¨ o c)" =¨ o a) ¨ " 0-ON =-g 2 ID) uc?. =-E' cs s) E o_ E o , 0 c7) = TD o) _0 a) a) C) D
(/) Cl) P < 1¨
to 5(iv) 11.6 12.3 110.7 0.93 23.0 134.89 147.42 6 (iv) 10.7 13.8 108.9 0.79 25.0 147.43 7(iv) 7.3 8.0 115.4 1.02 24.1 The following table illustrates the column configuration used.
Parameter Absorption column Regeneration column Diameter (m) 0.194 0.3 Packed Height (m) 3.53 2.6 Packing type MELLAPAK 250X MELLAPAK 250X
The following process performances were obtained after the regeneration step:
Test kg of vapor /m3 solvent kg vapor/kg CO2 captured 5 (iv) 67.7 5.1 6 (iv) 90.3 6.6 7 (iv) 49.4 5.5 Average 69.1 5.7 From the above table, a low ratio of kg of vapor 1m3 solvent and a low ratio of kg vapor/ kg CO2 captured are observed. Each low ratios means a low energy consumption.

Claims

1. A method for the purification of a gas mixture comprising carbon dioxide and optionally hydrogen sulfide, the method comprising:
¨ putting in contact an initial gas mixture comprising hydrogen sulfide at an amount equal to or less than 20 volume % and carbon dioxide at an amount equal to or less than 20 volume %, with an absorbent solution so as to obtain a gas mixture depleted in carbon dioxide and/or hydrogen sulfide, and an absorbent solution loaded with carbon dioxide and/or hydrogen sulfide, wherein the absorbent solution comprises at least one tertiary amine, at least one glycol compound and water; and ¨
regenerating the absorbent solution loaded with carbon dioxide and/or hydrogen sulfide so as to collect a stream comprising carbon dioxide and/or hydrogen sulfide and a regenerated absorbent solution.

2. The method according to claim 1, wherein the glycol is present in 20 the absorbent solution at a content from 20 to 45 mol % and preferably from 20 to 40 mol % relative to the absorbent solution.

3. The method according to claim 1 or 2, wherein the absorbent solution has a boiling temperature from 105 to 140 C, and preferably 25 130 to 135 C.

4. The method according to any one of claims 1 to 3, wherein the tertiary amine is chosen from N-methyldiethanolamine, 2-(2-diethylaminoethoxy)ethanol, (2,2'-(((methylazanediy1)bis(ethane-30 2,1-diy1))bis(oxy))diethanol), 3,9-d imethy1-6-oxa-3,9-d iaza-undecane-1,11-diol and 4-morpholin-4-ylpentan-1-ol, and mixtures thereof.

5. The method according to any one of claims 1 to 4, wherein the glycol 35 compound is ethylene glycol.

6. The method according to any one of claims 1 to 5, wherein the step of putting in contact the gas mixture with an absorbent solution is carried out at a temperature from 25 to 100 C and/or at an absolute pressure from 1 to 170 bar.

7. The method according to any one of claims 1 to 6, wherein the step of putting in contact the gas mixture with an absorbent solution is carried out in an absorption column or in a rotating packed bed.

8. The method according to any one of claims 1 to 7, wherein the gas mixture comprises at least one hydrocarbon, and is preferably natural gas.

9. The method according to any one of claims 1 to 8, wherein the step of regenerating the absorbent solution loaded with carbon dioxide and/or hydrogen sulfide is carried out in a regeneration column (9).

10. The rnethod according to any one of claims 1 to 9, wherein regenerating the absorbent solution loaded with carbon dioxide and/or hydrogen sulfide is carried out by heating the absorbent solution loaded with carbon dioxide and/or hydrogen sulfide preferably at a temperature from 100 to 200 C, and more preferably from 110 to 140 C.

11. The method according to any one of claims 1 to 10, wherein regenerating the absorbent solution loaded with carbon dioxide and/or hydrogen sulfide is carried out at an absolute pressure from 1 to 3 bar.

12. The method according to any one of claims 1 to 11, wherein during the regeneration of the absorbent solution loaded with carbon dioxide and/or hydrogen sulfide, the energy consumption is from 80 to 200 MJ/m3 of absorbent solution.

13. The method according to any one of claims 1 to 12, wherein the regenerated absorbent solution is recycled in the step of putting in contact the gas mixture with an absorbent aqueous solution.