NL1002135C2 - Method for removing sulfur-containing impurities, aromatics and hydrocarbons from gas. - Google Patents

Description

Title: Method for removing sulfur-containing impurities, aromatics and hydrocarbons from gas

The invention relates to a process for purifying hydrocarbon gas, more in particular natural gas, which is contaminated with sulfur compounds in the form of H2S and mercaptans, as well as with CO2. More particularly, the invention includes a process for converting mercaptans to H 2 S in and removing CO2 and adsorbed hydrocarbons and aromatics from H 2 S containing gas to form elemental sulfur from H 2 S.

Purification of natural gas, purification of refinery gases and purification of synthesis gas release sulfur-containing gases, in particular H2S, which must be removed in order to limit the emissions into the atmosphere, in particular of SO2, which is generated when such sulfur compounds are burned . The extent to which the sulfur compounds must be removed from, for example, natural gas, depends on the intended application of the gas and the quality requirements. If the gas must comply with the so-called "pipe line specificaton", the H2S content must be reduced to a value lower than 20 5 mg / Nm3. Requirements are also imposed on the maximum content of other sulfur compounds. A large number of methods are known from the prior art with which the amount of sulfur compounds in a gas, such as natural gas, can be reduced.

Usually, the following process route is used to remove sulfur-containing components from gases. In a first step, the gas to be treated is purified, removing sulfur-containing components from the gas, followed by recovery of sulfur from 10 02 135.

2 these sulfur-containing components, after which a sulfur cleaning step of the residual gas follows. In this sulfur cleaning step, an attempt is made to recover the last percent sulfur before the residual gas is emitted into the atmosphere via the chimney.

In the purification step, processes are often used in which aqueous solvents (absorbents, also called solvents) are used. These processes are divided into five main groups, namely chemical solvent processes, physical solvent processes, physical / chemical solvent processes, redox processes, where H2S is directly oxidized to sulfur in an aqueous solution and finally a group of fixed bed processes where H2S is chemical or physical is absorbed or adsorbed or selectively oxidized catalytically to elemental sulfur.

The first three groups are generally used in industry for the removal of large amounts of sulfur-containing components, usually present in mostly large amounts of gas. The last two groups are limited in terms of the amount of sulfur to be removed and the concentration of the sulfur-containing components. These processes are therefore less suitable for removing high concentrations of sulfur in large industrial gas treatment plants.

25 The chemical solvent processes include the so-called.

amine processes using aqueous solutions of alkanolamines or potassium carbonate solutions.

In the physical solvent processes, 30 different chemicals are used. For example, polyethylene glycol (DMPEG) known under the name Selexol, N-Methyl-Pyrrolidone (NMP) known under the name Purisol or methanol known under the name Rectisol.

The Sulfinol process is well known in the group of physical / chemical processes. This process uses a mixture of an alkanolamine with sulfolane dissolved in a small amount of water.

10 02 13 6 3

In the above three methods, an absorber and a regenerator are used. In the absorber, the sulfur-containing components are chemically or physically bound to the solvent. The sulfur-containing components are desorbed from the solvent by means of a pressure drop and / or temperature increase in the regenerator, after which the solvent can be reused. A detailed description of this method can be found in R.N. Medox "Gas and Liquid Sweetening" Cambell Petroleum 10 Series (1977). In this process, in addition to the sulfur-containing components, CO2 is also completely or partially removed, depending on the chosen solvent.

The sulfur compounds removed are carried along with the CO2 from the regenerator to a sulfur recovery plant in order to recover the sulfur from H2S and other sulfur compounds. It is a frequently used process for the recovery of sulfur from the sulfur compounds, in particular H2S, thus obtained

Claus process. This process is described in detail from H.G.

20 Paskall, "Capability of the modified Claus process" Western Research Development, Calgary, Alberta, Canada, 1979.

The Claus process consists of a thermal step followed by usually 2 or 3 reactor steps. In the thermal step, a third of the H2S is burned to SO2 according to the reaction H2s + 1.502 - »SO2 + H2O, after which the rest, so 2/3 of the H2S, reacts with the SO2 formed according to the Claus reaction under sulfur and water formation.

2 H2S + S02 - »3 S + 2 H20.

The efficiency of the Claus process depends on a number of factors. For example, the equilibrium of the Claus reaction shifts with increasing water content in the gas in the 10 02 1 35.

4 direction of H2S. The efficiency of the sulfur recovery plant can be increased by using a tail gas sulfur recovery plant; known processes are the SUPERCLAUS ™ process and the SCOT process. The SUPERCLAUS ™ 5 process uses a catalyst as described in European Patent Applications No. 242,920 and 409,353, as well as in International Patent Application No.

WO-A 95/07856, wherein this catalyst is used in a third or fourth reactor stage as described inter alia in "Hydrocarbon Processing" April 1989, pages 40-42.

Using this method, the last residues of H 2 S present in the process gas stream are selectively oxidized to elemental sulfur according to the reaction H 2 S + 0.5 O 2 -> S + H 2 O.

In this way, the efficiency of the sulfur recovery plant can easily be increased to 99.5%. The gas supplied to the Claus plant can sometimes contain large amounts of CO2 / for instance up to 98.5%, which has a very detrimental effect on the flame temperature in the thermal step. With a large amount of CO2 instability of the flame can occur and the efficiency in the thermal stage will also decrease, as a result of which the total efficiency of the Claus installation decreases.

The gas can also contain large amounts of hydrocarbons. When processing sulfur-containing gas in an oil refinery gas, the hydrocarbon content will generally be low, usually <2% by volume.

In the purification of natural gas using physical or physical / chemical processes, larger quantities of hydrocarbons, resp. aromatics, in the gas that is fed to the sulfur recovery plant (Clausgas). In the thermal stage of a Claus installation, these hydrocarbons are completely burned because the reaction speed of the hydrocarbons with oxygen is higher than the tO 02 1 i - 5 reaction speed of H2S and oxygen. When large amounts of CO2 are present, the flame temperature will consequently be lower and so will the reaction speed of the components during combustion. Therefore, it is possible for soot to form in the flame of the burner of the thermal stage.

Carbon black formation gives rise to blockage problems in the catalytic reactors of a Claus plant, in particular the first reactor. The ratio between the oxygen requirement for the conversion of H 2 S to sulfur and the oxygen requirement for the combustion of the hydrocarbons and aromatics can also assume such values that the Claus process can no longer be properly controlled. These problems are known in the industry.

In addition, besides H2S and the above-mentioned large amounts of CO2, mercaptans are also often present in the gas. Chemical processes are used in industry, whereby these mercaptans are not removed from the gas to be purified, eg natural gas, so that post-cleaning is required with a fixed bed process. Molecular sieves are often used to remove these mercaptans.

However, when such a fixed bed is saturated with mercaptans, the molecular sieves must be regenerated, often using the purified natural gas. This regeneration gas must then be purified again. When the molecular sieves are regenerated, the mercaptans are largely released at the start of regeneration. There are also processes in which the mercaptans are returned from a post-purification stage to the Claus plant. These mercaptans then give a peak load in the thermal stage of the Claus plant, as a result of which the air regulation is seriously disrupted. Such a process route is described in Oil and Gas Journal 57, August 19, 1991, pp. 57-59. In addition, this leads to loss of natural gas, which can easily rise to about 10%.

10 02 1 55.

6

A method of processing sulfur-containing gases containing carbonyl sulfide and / or other organic components such as mercaptans and / or di-alkyl disulfides is known. This method is described in UK patent 5 number 1563251 and in UK patent number 1470950.

The object of the present invention is inter alia to provide a method for removing sulfur-containing impurities in the form of mercaptans and H2S from hydrocarbon gas, which may also contain CO2 and higher aliphatic and aromatic hydrocarbons, and to recover elemental sulfur , where the disadvantages outlined above do not arise. More particularly, it is an object of the invention to provide a method in which the residual gases contain no or only very few harmful substances, so that they can be discharged into the atmosphere without any objection. It is also an object of the invention to provide a method in which the sulfur-containing impurities are largely recovered as elemental sulfur, for example to an amount of more than 90, more particularly more than 95%.

Surprisingly, it has been found that with the method according to the invention large gas flows can be purified in a very efficient manner, while at the same time meeting strict requirements with regard to emission of harmful substances and recovery efficiency of sulfur.

The present invention provides a simple method for purifying contaminated hydrocarbon gas with sulfur recovery, according to which method, in a first absorption step, the sulfur-containing impurities are removed from the gas, to form a purified gas stream on the one hand and an acid on the other gas, which sour gas is supplied to a second absorption step in which the sour gas is separated into an H2S-enriched and mercaptan-depleted first gas stream, which is fed to a Claus 35 plant, followed by a selective oxidation step of H2S to elemental sulfur in the residual gas , and a H2S-depleted and mercaptan-enriched second 1 0 02 1 35.

7 gas stream, which second gas stream, if desired after further treatment, is subjected to a selective oxidation of sulfur compounds to elemental sulfur.

According to a preferred embodiment of the invention, the first absorption step is performed using a chemical, physical or chemical / physical absorbent that removes all contaminants from the natural gas. Preferably, this is a sulfolane-based absorbent in combination with a secondary and / or tertiary amine. As already indicated, such systems are known and are already widely used for the purification of natural gas, especially when natural gas is liquefied after purification. The absorption is, as usual, based on a system in which the impurities in a first column are absorbed in the solvent, after which, if the solvent is loaded with impurities, this solvent is regenerated in a second column, for example by heating and / or by reducing pressure. The temperature at which the absorption takes place depends largely on the solvent and the pressure applied. At the pressures of 2 to 100 bar common for natural gas, the absorption temperature is generally 15 to 50 ° C, although good results can also be obtained outside these ranges. The natural gas is preferably purified to meet the pipeline specification, which means that generally no more than 10, more particularly no more than 5 ppm of H 2 S may be present.

According to the method of the invention, the acid gas in a second absorption stage is first separated into two other gases, namely an H2S-rich gas and a CC2-rich gas, which contains, in addition to CO2, hydrocarbons, aromatics and the unabsorbed mercaptans. With this method, the H2S concentration can be increased two to six times.

This second absorption is preferably effected using a solvent based on a secondary or tertiary amine, more in particular with an aqueous solution of methyl diethanol amine, optionally in combination with an activator therefor. , or with a hindered tertiary amine. Such processes are known and described in the literature (MDEA process, ÜCARSOL, FLEXSORB-SE, and the like). The mode of operation of such processes is comparable to the first absorption stage. The degree of enrichment is preferably at least 2 to 6 times or more, which partly depends on the starting concentration of H 2 S. The degree of enrichment can be adjusted by suitable choice of the construction of the absorber.

10 The H2S-rich first gas stream can be processed very well in the Claus plant, whereby the absence of a large part of CO2, hydrocarbons and aromatics during combustion does not cause additional gas throughput in the installation. As a result, the Claus plant can be built much smaller, while also achieving much higher sulfur recovery yields.

Such a Claus installation is known and the manner in which it is operated with regard to temperature, pressure and the like is described in detail in the publications cited in the introduction.

The residual gas from the Claus plant, which still contains residual sulfur compounds, is supplied, if desired after additional hydrogenation, to a residual gas processing plant, in which elemental sulfur is formed by selective oxidation of the sulfur compounds, which is separated in a suitable plant, for example such as described in European patent application No. 655,414.

After separation of the sulfur, the residual gas can be burned in an afterburner. The heat released can be used to generate steam.

The selective oxidation is preferably carried out in the presence of a catalyst that selectively converts sulfur compounds to elemental sulfur, for example, the catalysts described in the aforementioned European and international patent applications. These publications, the contents of which are incorporated herein by 1002131 9 reference, also indicate the most suitable process conditions, such as temperature and pressure. In general, however, the pressure is not critical, while temperatures may range from the sulfur dew point to about 300 ° C, more particularly less than 250 ° C.

The CO2-rich second gas stream with the hydrocarbons, aromatics and mercaptans present, is mixed with the residual gas from the Claus sulfur recovery plant and fed to the residual gas recovery plant on the basis of selective oxidation of the sulfur compounds to elemental sulfur. The residual gas recovery plant in this case is preferably the SUPERCLAUS reactor stage, in which the mercaptans are oxidized to elemental sulfur with the oxygen present.

Alternatively, the CO2-rich gas can also be traded separately in a SUPERCLAUS reactor stage. When the mercaptans content in the gas is high, it may be required to cool the SUPERCLAUS reactor to prevent the temperature in the catalyst bed from rising too high with the selectivity decreasing and an excess amount of SC> 2 becoming formed.

According to another embodiment of the process according to the invention, the CO2-rich gas, the second gas stream, coming from the enrichment unit, is passed with hydrogen 25 over a hydrogenation reactor containing a sulfided group 6 and / or group 8 metal catalyst which is provided on a support.

Alumina is preferably used as the carrier in this type of catalysts, since this material, in addition to the desired thermal stability, also permits good dispersion of the active component. The catalytically active material is preferably a combination of cobalt and molybdenum.

The gas stream must be heated for the hydrogenation from the absorption / desorption temperature of about 40 ° C, to the temperature required for the hydrogenation from 200 to 300 ° C. This heating preferably takes place indirectly 10 02 1 3S.

10 and not with a burner arranged in the gas stream, as is customary. Namely, the drawback of direct heating is that direct heating in this case gives rise to strong soot formation, which can lead to fouling and clogging in the hydrogenation and the subsequent selective oxidation.

In the hydrogenation step, the mercaptans in the gas are converted into H2S using the hydrogen supplied.

The CC> 2 "rich gas from the hydrogenation step containing CO2, 10 H2 S, hydrocarbons and aromatics is mixed with the residual gas from the Claus plant and then fed and sent to the residual gas sulfur recovery unit, preferably a SUPERCLAUS reactor stage.

The gas from the hydrogenation reactor can also be treated in a separate SUPERCLAUS reactor.

It may be necessary to cool the SUPERCLAUS reactor to prevent the catalyst temperature from rising too high.

As indicated, the gas from the selective oxidation is finally burned, the remaining organic impurities being converted into water and CO2.

The invention will now be elucidated with reference to a few figures, wherein in figure 1 in the form of a block diagram the variant is shown with an additional hydrogenation step of the second, H2S lean gas stream. In figure 2 the variant is shown without hydrogenation.

As shown in figure 1, the sour gas, originating from a first absorption unit, not shown, in which polluted natural gas is split into a gas stream of the desired specification on the one hand and the sour gas on the other hand, via line 1 to an absorber of a selective absorption / regeneration installation 3 led. The non-absorbed components of the gas, consisting mainly of carbon dioxide, hydrocarbons (including 35 aromatics), mercaptans and a low content of H 2 S, are led via line 2 to the hydrogenation reactor 6. In line 2, the gas is brought to the desired hydrogenation temperature with addition of hydrogen and / or carbon monoxide before being introduced into hydrogenation reactor 6.

In the hydrogenation reactor 6, the mercaptans and other organic sulfur compounds 5 present in the gas are converted to H2S. The gas from the hydrogenation reactor 6, after cooling, is led via line 5 to the residual gas sulfur removal stage 11 of the Claus plant 8 to convert the H2S present to elemental sulfur.

The H2S-rich gas mixture from the regeneration section of the absorption / regeneration installation 3 is supplied via line 7 to the Claus installation 8, in which the majority of the sulfur compounds are converted into elemental sulfur which is removed via line 9.

In order to increase the efficiency of the Claus plant 8, the residual gas is fed via line 10 to a residual gas sulfur removal stage 11. This sulfur removal step can be a known sulfur removal process such as e.g. a dry bed oxidation step, an absorption step or a liquid oxidation step. The air 20 required for the oxidation is supplied via line 12. The sulfur formed is discharged via line 13.

The gas is then led via line 14 to the afterburner 15 before the gas is removed via chimney 16.

As shown in figure 2, the sour gas, originating from a first absorption unit, not shown, in which polluted natural gas is split into on the one hand a gas flow of the desired specification and on the other hand the sour gas, via line 1 to an absorber of a absorption / regeneration installation 3 led.

The H2S rich gas mixture from the regeneration section of the absorption / regeneration installation 3 is supplied via line 4 to the Claus installation 5, in which the majority of the sulfur compounds are converted into elemental sulfur which is removed via line 6.

In order to increase the efficiency of the Claus plant 5, the residual gas is fed via line 7 to a residual gas 10 02 1 3 0 12 sulfur removal stage 8. The sulfur removal stage 8 operates on the dry bed oxidation principle.

The non-absorbed components of the gas from the absorption section of the absorption / regeneration installation consisting mainly of carbon dioxide, hydrocarbons (including aromatics), mercaptans and a low content of H2S are fed via line 2 to the oxidation reactor of the residual gas sulfur removal stage 8. The required air for oxidation of H 2 S and mercaptans is supplied via line 9. To limit the temperature rise in the oxidation reactor, cooled process gas is recycled from line 12 using a densifier 14 to line 7. The sulfur formed is discharged through line 11. The gas is then passed via line 12 to the afterburner 16 before the gas is discharged through chimney 17.

The invention is illustrated by the following examples, which are not intended to be limiting.

EXAMPLE 1

An amount of acid gas of 15545 Nm ^ / h from the regenerator of a gas treatment plant had the following composition at 40 ° C and a pressure of 1.70 bar abs. 25

9.0 vol.% H2S

0.01 vol.% COS

0.22% by volume CH3SH

0.38% by volume of C 2 H 5 SH

0.03% by volume of C3H7SH

0.01 vol% C4H9SH

81.53 vol.% CO2 4.23 vol.% H 2 O 3.51 vol.% Hydrocarbons (C 1 to C 17) 35 1.08 vol.% Aromatics (Benzene, Toluene, Xylene) 10 02 1. - 13

This sour gas was contacted with a methyl diethanolamine solution in an absorber from a scrubber to absorb the H 2 S and part of the CO2.

5 The amount of product gas (CO2 rich gas) from the absorber was 13000 Nm3 / h with the following composition: 88.47 vol.% CO2

500 ppm vol. H2S

10 70 ppm vol. COS

0.26% by volume CH3SH

0.46 vol.% C 2 H 5 SH

0.04% by volume of C3H7SH

0.01 vol% C4H9SH

15 5.21 vol.% H20 4.2 vol.% Hydrocarbons (C1 to C17) 1.29 vol.% Aromatics (Benzene, Toluene, Xylene)

To this product gas was fed 2700 Nm3 / h reducing gas 20 containing hydrogen and carbon monoxide and then heated to 205 ° C to hydrogenate all mercaptans present to H2S in the hydrogenation reactor which is a sulfided group 6 and / or group 8 metal catalyst, which is applied to an alumina support, in this case contained a Co-Mo catalyst.

The temperature of the gas from the reactor was 232 ° C. The sour gas was then cooled to 226 ° C and fed to the residual sulfur removal stage of the sulfur recovery plant. The amount of the gas coming out of the hydrogenation reactor was 15700 Nm3 / h and had the following composition: 10 02 1 35.

14

0.68 vol. % H2S

60 ppm vol. COS

74.22 vol.% C02 8.14 vol.% H 2 O 5 3.48 vol.% Hydrocarbons (C1 to C17) 1.07 vol.% Aromatics (Benzene, Toluene, Xylene) 0.86 vol.% H2 11.56 vol,% N2 10 After desorption in a regenerator, the acidic H2S / CO2 gas mixture (H2S rich gas) was fed to a sulfur extraction plant. This H2S / CO2 gas mixture was 2690 Nm3 / h and had the following composition at 40 ° C and 1.7 bar. abs.

15

51.7 vol.% H2S

44.0 vol.% CO2 4.3 vol.% H 2 O 20 2780 Nm3 / h air was supplied to the burner of the thermal stage of the sulfur recovery plant, so that after the second Claus reactor stage 1.14 vol.% H2S and 0.07 vol.% SO2 was present in the process gas. The process gas was then fed to the tail gas 25 sulfur removal stage.

875 Nm3 / h air was supplied to this gas. The inlet temperature of the selective oxidation reactor was 220 ° C and the outlet temperature was 267 ° C. The selective oxidation reactor was filled with catalyst as described in European patents 242,920 and 409,353 and in International patent application WO-A 95/07856.

The sulfur formed in the sulfur recovery plant was condensed and discharged after each stage. The escaping inert gas was led to the chimney via afterburning. The amount of sulfur was 2068 kg / h. The total desulfurization efficiency based on the 10 02 1 35.

Original sour gas containing 9.0% by volume H 2 S was 96.5%.

EXAMPLE 3 5

An amount of acid gas of 15545 Nm3 / h from the regenerator of a gas treatment plant had the following composition at 40 ° C and a pressure of 1.70 bar abs.

10 9.0 vol.% H2S

0.01 vol.% COS

0.22% by volume CH3SH

0.38% by volume of C 2 H 5 SH

0.03% by volume of C3H7SH

0.01 vol% C4H9SH

81.53 vol.% CO2 4.23 vol.% H 2 O 3.51 vol.% Hydrocarbons (C ^ to 0 ^ 7) 1.08 vol.% Aromatics (Benzene, Toluene, Xylene) 20

This acid gas was contacted with a methyl diethanolamine solution in an absorber from a scrubber to absorb the H 2 S and part of the CO2.

The amount of product gas (CO2 rich gas) from the absorber was 13000 Nm3 / h with the following composition: 88.47 vol.% CO2

500 ppm vol. H2S

30 70 ppm vol. COS

0.26% by volume CH3SH

0.46 vol.% C 2 H 5 SH

0.04% by volume of C3H7SH

0.01 vol% C4H9SH

35 5.21 vol.% H20 4.2 vol.% Hydrocarbons (C1 to C17) 1.29 vol.% Aromatics (Benzene, Toluene, Xylene) 10 b2 I i-, 16

The product gas was then warmed to 230 ° C and fed to the residual gas sulfur removal stage from the sulfur recovery plant.

After desorption in a regenerator, the acidic H2S / CO2 gas mixture (H2S rich gas) was fed to a sulfur recovery plant. This H2S / CO2 gas mixture was 2690 Nm3 / h and had the following composition at 40 ° C and 1.7 bar abs.

51.7 vol.% H2S

44.0 vol.% CO2 4.3 vol.% H 2 O

2780 Nm3 / h air was fed to the burner of the thermal stage of the sulfur recovery plant, so that after the second Claus reactor stage 1.14 vol.% H2S and 0.07 vol.% SO2 was present in the process gas. The process gas was then fed to the residual gas sulfur removal stage.

875 20 Nm3 / h air was supplied to this gas and the supplied product gas. The inlet temperature of the selective oxidation reactor was 230 ° C and the outlet temperature was 290 ° C. To limit the temperature rise in the oxidation reactor to 60 ° C, 13000 Nm3 / h of the gas cooled after the reactor was recycled over the reactor. The selective oxidation reactor was charged with catalyst as described in European patents 242,920 and 409,353, as well as in international patent application No. WO-A 95/07856.

The sulfur formed in the sulfur recovery plant was condensed and discharged after each stage. The emerging inert gas was led to the chimney via afterburning. The amount of sulfur was 2050 kg / h. The total desulfurization efficiency based on the original acid gas, which contained 9.0% by volume H 2 S, was 95.7%.

10 02 1 35.

Claims (14)

1. A method for removing sulfur-containing impurities in the form of mercaptans and H2S from hydrocarbon gas, which may also contain CO2 and higher aliphatic and aromatic hydrocarbons, and recovering elemental sulfur, in a first absorption step removing the sulfur-containing impurities from the gas is removed to form a purified gas stream on the one hand and an acid gas on the other hand, the sour gas being fed to a second absorption step in which the sour gas is separated into a first gas stream enriched in H 2 S and mercaptan-depleted to a Claus installation is followed, followed by a selective oxidation step of H 2 S to elemental sulfur in the tail gas, and a H 2 S-depleted and mercaptan-enriched second gas stream, which second gas stream, if desired after further treatment, is subjected to a selective oxidation of sulfur compounds to elemental sulfur. The method of claim 1, wherein said second gas stream is hydrogenated prior to the selective oxidation. A method according to claim 1 or 2, wherein said selective oxidation of the residual gas of the first gas stream and of the second gas stream takes place in the same reactor. 4. A method according to claim 1 or 2, wherein said selective oxidation of the residual gas of the first gas stream and of the second gas stream takes place in two separate reactors. 5. Process according to claims 1-4, wherein the first absorption step is carried out using a chemical, physical or chemical / physical absorbent which removes substantially all sulfur compounds and CO2 from the gas in 10 02 1 35. 6. A method according to claim 5, wherein as absorbent sulfolane is used in combination with a secondary or 5 tertiary amine. The method of claims 1-6, wherein the second absorption step is performed using an absorbent based on a secondary and / or tertiary amine. A method according to claims 1-7, wherein the first absorption step is carried out in such a way that the purified gas contains no more than 10, more particularly no more than 5 ppm, of sulfur-containing impurities. 9. A method according to claim 9, wherein natural gas is used as the gas to be purified, which optionally is liquefied after the purification. 10. A method according to claims 1-9, wherein the second absorption step is carried out such that the content of H2S in the first gas stream is at least 2.5 times, more in particular at least 4 times, higher than the content of H2S in the sour gas. A method according to claims 1-10, wherein the content of mercaptans in the first gas stream is less than 1 ppm. A process according to claims 2-11, wherein the hydrogenation takes place in the presence of a supported catalyst, with a catalytically active component based on at least one Group VIB metal and at least one Group VIII metal of the Periodic Table of the Elements, more particularly on a combination of cobalt and molybdenum. A method according to claims 2-12, wherein the hydrogenation takes place in the presence of an amount of water. 14. The method of claims 2-13, wherein the second gas stream is indirectly heated prior to hydrogenation. 10021J,