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Title:
INTEGRATED PROCESS FOR ELEMENTAL SULPHUR TREATMENT
Document Type and Number:
WIPO Patent Application WO/2018/115919
Kind Code:
A1
Abstract:
The invention relates to a method for removing a sulphur deposit from a well and recovering an elemental sulphur stream, in which a liquid solvent dissolves all or part of the sulphur deposit by physical interaction, and said dissolved sulphur is converted into H2S by chemical extraction with H2, as well as a device for carrying out said method.

Inventors:
WEISS, Claire (33 rue des Fonds Huguenots, VAUCRESSON, 92420, FR)
GHODASARA, Kamlesh (CSTJF EB279 Avenue Larribau, PAU Cedex, 64018, FR)
CADOURS, Renaud (2 Allée du Jardin des Hespérides, FRANCHEVILLE, 69340, FR)
Application Number:
IB2016/001973
Publication Date:
June 28, 2018
Filing Date:
December 23, 2016
Export Citation:
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Assignee:
TOTAL SA (2 place Jean Millier La Défense 6, COURBEVOIE, 92400, FR)
International Classes:
C01B17/033; B01D53/86; C01B17/04; C01B17/16; C10L3/10
Domestic Patent References:
WO2008027381A22008-03-06
Foreign References:
EP2937132A12015-10-28
EP2806015A12014-11-26
EP2412668A12012-02-01
US20110262345A12011-10-27
US5242672A1993-09-07
US7988767B22011-08-02
Attorney, Agent or Firm:
CABINET PLASSERAUD (66 rue de la Chaussée d'Antin, PARIS CEDEX 09, 75440, FR)
Download PDF:
Claims:
CLAIMS

1. A method for removing a sulphur deposit from a well (1) in which a gas is flowing, comprising the steps of:

a) injecting a liquid solvent in said well (1) thereby dissolving all or part of the sulphur deposit in said liquid solvent, and forming a well output (2) comprising the gas from the well (1) and a liquid sulphur rich solvent comprising dissolved sulphur,

b) separating the well output (2) into a gas stream and a liquid sulphur rich solvent stream and recovering separately the gas stream and the liquid sulphur rich solvent stream,

c) producing a feed H2 gas stream by a H2 production unit (9),

d) introducing the liquid sulphur rich solvent into a chemical reaction unit (5) and injecting the feed H2 gas stream into said chemical reaction unit (5) so as to chemically react H2 with the dissolved sulphur of the liquid sulphur rich solvent thereby forming a liquid lean solvent and a H2S gas stream comprising H2S and an unreacted portion of the feed H2 gas stream, e) recovering separately the liquid lean solvent and the H2S gas stream, f) introducing the H2S gas stream comprising H2S and the unreacted portion of the feed H2 gas stream into a H2S treatment unit so as to convert H2S into elemental sulphur.

2. The method according to claim 1, wherein the H2S treatment unit (A) comprises a hydrogenation unit (12), a H2S separation unit (14) and a Claus unit (16) for converting H2S into elemental sulphur, and wherein the H2S gas stream is introduced into the hydrogenation unit (12), into the H2S separation unit (14) or into the Claus unit (16).

3. The method according to claim 2, wherein the H2S treatment unit (A) comprises a tail line (11) connecting the Claus unit (16) to the hydrogenation unit (12), and wherein the feed H2 gas stream is introduced into the tail line (11) and a portion of this H2 gas stream is drawn off from the tail line (11) and introduced into the chemical reaction unit (5).

4. The method according to claim 2, wherein a second feed H2 gas stream produced by the H2 production unit (9) is introduced into the hydrogenation unit (12).

5. The method according to any one of claims 1 to 4, wherein the liquid lean solvent recovered in step e) is reinjected in the well (1). 6. The method according to any one of claims 1 to 5, wherein the step a) of injection of the liquid solvent in the well is performed continuously or sequentially.

7. The method according to any one of claims 1 to 6, wherein the gas flowing in the well (1) contains sulphur contaminants, and wherein the amount of sulphur contaminants is less than 10 g/Sm 3 , in particular less than 5 g/Sm 3 , more particularly less than 2g/Sm3.

8. The method according to any one of claims 1 to 7, wherein the temperature of the chemical reaction of step d) is 170°C to 360°C, preferably 250°C to 325°C, more preferably 275°C to 300°C.

9. The method according to any one of claims 1 to 8, wherein the pressure of the chemical reaction of step d) is 1 bar to 40 bar, preferably 1.2 bar to 15 bar, more preferably 1.3bar to 10 bar.

10. The method according to any one of claim 1 to 9, further comprising the steps of: g) separating the gas stream recovered at step b) in an AGR unit (20) into a sweet hydrocarbon gas stream, which is recovered in a sweet gas recovery line (21), and into an acid gas stream comprising H2S which is recovered in an acid line (17),

h) introducing the acid gas stream recovered in the acid line (17) into the Claus unit (16) so as to produce the elemental sulphur and the tail gas stream comprising sulphur compounds,

i) dehydrating in a dehydration unit (22) and separating in a fractionation unit

(23) the sweet hydrocarbon gas stream recovered in the sweet gas recovery line (21) into a light hydrocarbon gas stream and light hydrocarbon cuts, and j) recovering separately the light hydrocarbon gas stream in a light gas line (24) and the light hydrocarbon cuts in a light cut line (25).

11. A device for carrying out the method according to claim 1, said device comprising:

- a gas/liquid separation unit (3) for separating the well output (2) into a gas stream which is recovered in a gas recovering line (10) and a liquid sulphur rich solvent stream which is recovered in liquid recovering line (4),

- a H2 production unit (9) for producing a feed H2 gas stream,

- a H2 feeding line (7) for recovering the feed H2 gas stream,

- an chemical reaction unit (5) fed by the liquid recovering line (4) and the H2 feeding line (7) for performing chemical reaction of H2 with the dissolved sulphur from the liquid sulphur rich solvent, thereby forming an H2S gas stream and a liquid lean solvent,

- a recycling line (6) for recovering the liquid lean solvent,

- a H2S recovering line (8) for recovering the H2S gas stream from the chemical reaction unit (5), and

- a H2S treatment unit fed by the H2S recovering line (8) for performing conversion of the H2S gas stream into elemental sulphur

12. The device according to claim 11 for carrying out the method according to claim 2, wherein the H2S treatment unit (A) comprises:

- a Claus unit (16) fed with a line (15) comprising an enriched sulphur compounds gas stream for converting H2S into elemental sulphur and a tail gas stream comprising sulphur compounds,

- a tail line (11) for recovering the tail gas stream and an elemental sulphur line (18) for recovering the elemental sulphur ,

- an hydrogenation unit (12) fed with the tail line (11) for hydrogenating the sulphur compounds of the tail gas stream into H2S and gaseous side product(s),

- a gas mixture line (13) for recovering the H2S and the gaseous side product(s),

- a H2S separation unit (14) fed with the gas mixture line (13) for separating H2S from the gaseous side product(s) thereby forming the enriched sulphur compounds gas stream which is recovered in the line (15), wherein the Claus unit (16), the hydrogenation unit (12) or the H2S separation unit (14) is fed with the H2S recovering line (8).

13. The device according to claim 12 for carrying out the method according to claim 3, wherein the H2 feeding line (7) is connected to the tail line (11) and wherein a second H2 feeding line (77) connects the H2 production unit (9) to the tail line (11).

14. The device according to claim 12 for carrying out the method according to claim 3, wherein the hydrogenation unit (12) is fed with a second H2 feeding line (77) connected to the H2 production unit (9).

15. The device for carrying out the method according to claim 10, said device further comprising:

- an AGR unit (20) fed with the gas recovering line (10) comprising the gas stream for separating it into a sweet hydrocarbon gas stream which is recovered in a sweet gas recovery line (21) and an acid gas stream comprising H2S which is recovered in an acid line (17),

- a dehydration unit (22) and a fractionation unit (23) fed with the sweet gas recovery line (20) to dehydrate and separate the sweet hydrocarbon gas stream into a light hydrocarbon gas stream and light hydrocarbon cuts, and

- light gas line (24) and a light cut line (25) to recover separately the light hydrocarbon gas stream and light hydrocarbon cuts.

Description:
INTEGRATED PROCESS FOR ELEMENTAL SULPHUR TREATMENT

Field of the invention

The invention is in the field of natural gas treatment and more particularly the treatment of natural gas comprising sulphur compounds, such as H 2 S. Background

Sour gas often contains significant amount of sulphur contaminants, especially dissolved elemental sulphur. This last one tends to form deposits, for example, on the well tubings/shafts of the gas gathering system, and in the downstream gas treating and processing equipment. Various processes have been proposed for the prevention or removal of such sulphur deposit such as injection into the well of sulphur solvent to dissolve the sulphur deposit. Injection processes offer the possibility to implement a continuous process. Various liquid solvents can be used to dissolve a sulphur deposit and should preferably meet the following criteria: rapid sulphur dissolution, high sulphur solubility in the solvent, easy regeneration, chemical and thermal stability of the solvent under the process conditions. Such liquid solvents include hydrocarbon oils, preferably aromatic (e.g alkyl naphthalene) in which sulphur solubility is higher than paraffinic solvents.

Due to the cost of the liquid solvents, their regeneration is necessary to have an economically viable process. The regeneration of the liquid solvents may be performed mechanically or chemically, for example by crystallization (US 2011/0262345), by the use of an aqueous solution comprising an amine (US 5,242,672), or by catalytic hydrogenation (US 7,988,767).

Crystatech patent (US 2011/0262345) discloses a method for removing a sulphur deposit with a liquid solvent regeneration performed by crystallization. However, the quality of the sulphur recovered from the crystallization technology is low because of trapped organic compounds. US 5,242,672 discloses a typical regenerator unit using an aqueous solution comprising an amine. However, it requires a significant amount of energy. Furthermore, the amine solution may be easily chemically degraded and thus has to be often replaced. Finally, the resulting sulphide compound (polysulphide, sulphur...) may require additional processing to provide a suitable end product.

US 7,988,767 discloses a method for removing a sulphur deposit with a sulphur solvent regeneration by catalytic hydrogenation thereby forming a gas mixture of H 2 and H 2 S. Before the introduction of H 2 S into the Claus unit, H 2 S is separated from H 2 , and this H 2 is reinjected into the catalytic chemical hydrogenation. This H 2 is thus not involved in the treatment steps of H 2 S. This method requires several continuous streams of hydrogen to regenerate the sulphur solvent by catalytic hydrogenation and to treat H 2 S. Therefore, this method is difficult to implement at an industrial level and a lot of capital expenditure (CAPEX) are incurred due to the building of at least two hydrogen plants to provide the several continuous streams of hydrogen and due to the huge amount of sulphur solvent required.

Consequently, there is still a need to provide an improved process and a device for removing a sulphur deposit with a sulphur solvent that is simpler, has a lower CAPEX and results in elemental sulphur of higher quality.

The present invention meets all these needs by providing a method which can be integrated into the gas treatment facility, in particular in a sour gas treatment unit. The method of the invention actually utilizes units which are already known to treat sour gas, which therefore enables a significant reduction of the CAPEX. Furthermore, the method utilizes the hydrogen which is produced in only one unit to be utilized in the chemical reaction with the sulphur from a sulphur rich solvent thereby producing H 2 S and in the treatment of H 2 S.

Summary of the invention

One object of the present invention is a method for removing a sulphur deposit from a well in which a gas is flowing, comprising the steps of:

a) injecting a liquid solvent in said well thereby dissolving all or part of the sulphur deposit in said liquid solvent, and forming a well output comprising the gas from the well and a liquid sulphur rich solvent comprising dissolved sulphur,

b) separating the well output into a gas stream and a liquid sulphur rich solvent stream and recovering separately the gas stream and the liquid sulphur rich solvent stream,

c) producing a feed H 2 gas stream by a H 2 production unit,

d) introducing the liquid sulphur rich solvent into a chemical reaction unit and injecting the feed H 2 gas stream into said chemical reaction unit so as to chemically react H 2 with the dissolved sulphur of the liquid sulphur rich solvent thereby forming a liquid lean solvent and a H 2 S gas stream comprising H 2 S and an unreacted portion of the feed H 2 gas stream, e) recovering separately the liquid lean solvent and the H 2 S gas stream, f) introducing the H 2 S gas stream comprising H 2 S and the unreacted portion of the feed H 2 gas stream into a H 2 S treatment unit so as to convert H 2 S into elemental sulphur.

Advantageously, any H 2 production unit already present in an oil or or gas treatment facility and producing a feed H 2 gas stream containing more than 1 mol. of H 2 can be used in the method of the present invention, such as an H 2 production unit used to provide H 2 in a TGT Unit, hydrocracking process or a hydrodesulphurization process. Advantageously, the method of the present invention significantly reduces the CAPEX since it does not necessitate a dedicated H 2 production unit.

Moreover, the unreacted portion of the feed H 2 gas stream is advantageously introduced into the H 2 S treatment unit and is involved in the steps leading to the conversion of H 2 S into elemental sulphur. Therefore, the H 2 production unit produces H 2 which is not only involved in the formation of the H 2 S gas stream in the chemical reaction unit but also in the treatment of sulphur compounds in the H 2 S treatment unit.

In one embodiment, the H 2 S treatment unit may comprises a hydrogenation unit, a H 2 S separation unit and a Claus unit for converting H 2 S into elemental sulphur, and the H 2 S gas stream may be introduced into the hydrogenation unit, into the H 2 S separation unit or into the Claus unit. In one embodiment, the H 2 S treatment unit may comprises a tail line connecting the Claus unit to the hydrogenation unit, and the feed H 2 gas stream may be introduced into the tail line and a portion of this H 2 gas stream may be drawn off from the tail line and introduced into the chemical reaction unit. In one embodiment, a second feed H 2 gas stream produced by the H 2 production unit may be introduced into the hydrogenation unit.

In one embodiment, the liquid lean solvent recovered in step e) may be reinjected in the well.

In one embodiment, the step a) of injection of the liquid solvent in the well may be performed continuously or sequentially.

In one embodiment, the gas flowing in the well may contain sulphur contaminants, and the amount of sulphur contaminants may be less than 10 g/Sm , in particular less than 5 g/Sm 3 , more particularly less than 2g/Sm 3.

In one embodiment, the temperature of the chemical reaction of step d) may be 170°C to 360°C, preferably 250°C to 325°C, more preferably 275°C to 300°C.

In one embodiment, the pressure of the chemical reaction of step d) may be 1 bar to 40 bar, preferably 1.2 bar to 15 bar, more preferably 1.3bar to 10 bar.

In one embodiment, the method may further comprises the steps of:

g) separating the gas stream recovered at step b) in an AGR unit into a sweet hydrocarbon gas stream, which is recovered in a sweet gas recovery line, and into an acid gas stream comprising H 2 S which is recovered in an acid line, h) introducing the acid gas stream recovered in the acid line into the Claus unit so as to produce the elemental sulphur and the tail gas stream comprising sulphur compounds,

i) dehydrating in a dehydration unit and separating in a fractionation unit the sweet hydrocarbon gas stream recovered in the sweet gas recovery line into a light hydrocarbon gas stream and light hydrocarbon cuts, and

j) recovering separately the light hydrocarbon gas stream in a light gas line and the light hydrocarbon cuts in a light cut line. Another object of the present invention is a device for carrying out the method of the present invention, said device comprising:

- a gas/liquid separation unit for separating the well output into a gas stream which is recovered in a gas recovering line and a liquid sulphur rich solvent stream which is recovered in liquid recovering line,

- a H 2 production unit for producing a feed H 2 gas stream,

- a H 2 feeding line for recovering the feed H 2 gas stream,

- an chemical reaction unit fed by the liquid recovering line and the H 2 feeding line for performing chemical reaction of H 2 with the dissolved sulphur from the liquid sulphur rich solvent, thereby forming an H 2 S gas stream and a liquid lean solvent,

- a recycling line for recovering the liquid lean solvent,

- a H 2 S recovering line for recovering the H 2 S gas stream from the chemical reaction unit, and

- a H 2 S treatment unit fed by the H 2 S recovering line for performing conversion of the H 2 S gas stream into elemental sulphur

In one embodiment, the H 2 S treatment unit may comprise:

- a Claus unit fed with a line comprising an enriched sulphur compounds gas stream for converting H 2 S into elemental sulphur and a tail gas stream comprising sulphur compounds,

- a tail line for recovering the tail gas stream and an elemental sulphur line for recovering the elemental sulphur ,

- an hydrogenation unit fed with the tail line for hydrogenating the sulphur compounds of the tail gas stream into H 2 S and gaseous side product(s), - a gas mixture line for recovering the H 2 S and the gaseous side product(s),

- a H 2 S separation unit fed with the gas mixture line for separating H 2 S from the gaseous side product(s) thereby forming the enriched sulphur compounds gas stream which is recovered in the line,

wherein the Claus unit, the hydrogenation unit or the H 2 S separation unit may be fed with the H 2 S recovering line. In one embodiment, the H 2 feeding line may be connected to the tail line and wherein a second H 2 feeding line connects the H 2 production unit to the tail line.

In one embodiment, the hydrogenation unit may be fed with a second H 2 feeding line connected to the H 2 production unit. In one embodiment, the device may further comprise:

- an AGR unit fed with the gas recovering line comprising the gas stream for separating it into a sweet hydrocarbon gas stream which is recovered in a sweet gas recovery line and an acid gas stream comprising H 2 S which is recovered in an acid line,

- a dehydration unit and a fractionation unit fed with the sweet gas recovery line to dehydrate and separate the sweet hydrocarbon gas stream into a light hydrocarbon gas stream and light hydrocarbon cuts, and

- light gas line and a light cut line to recover separately the light hydrocarbon gas stream and light hydrocarbon cuts. Brief description of the figures

Figure 1 is a schematic representation of the process and device of the invention, wherein the feed H 2 gas stream is introduced into the chemical reaction unit and the H 2 S gas stream is introduced into the hydrogenation unit.

Figure 2 is a schematic representation of the process and device of the invention, wherein the feed H 2 gas stream is introduced into the chemical reaction unit via the tail line and the H 2 S gas stream is introduced into the hydrogenation unit.

Figure 3 is a schematic representation of the process and device of the invention, wherein the feed H 2 gas stream is introduced into the chemical reaction unit and a second feed H 2 gas stream is introduced into the hydrogenation unit. Detailed description of the invention

The method according to the invention applies to the removal of a sulphur deposit from a well 1 in which a gas is flowing by dissolution with a liquid solvent and to the chemical reaction of the dissolved sulphur into H 2 S by a reaction with H 2. The device according to the invention is for carrying out the method according to the invention.

In the following description, the feeding of a unit or any other part of the device with a line and the introduction of a stream or compound into a unit includes direct feeding/introduction as well as indirect feeding/introduction, for instance where the feeding/introduction stream is introduced into a line that feeds the unit, or is subjected to a treatment prior to be fed/introduced to said unit or part, such as a dehydration treatment.

The invention is now described in more details by referring to Figure 1. Natural gas is extracted underground using a well 1. A sulphur deposit is formed because the gas flowing in the well 1 contains sulphur contaminants. The method of the invention is not limited to any particular concentration of sulphur contaminants in the gas.

Typically, the amount of sulphur contaminants, in particular H 2 S, in the gas flowing in the well 1 is less than 10 g/Sm 3 , in particular less than 5 g/Sm 3 , more particularly less than 2g/Sm .

According to a step a) of the method of the invention, a liquid solvent is injected in the well 1, thereby dissolving all or part of the sulphur deposit in said liquid solvent, and forming a well output 2 comprising the gas from the well 1 and a liquid sulphur rich solvent.

Step a) of injection of the liquid solvent in the well 1 may be performed continuously or sequentially.

The liquid solvent is any hydrocarbon able to dissolve a sulphur deposit and which does not chemically react with the sulphur deposit and with H 2 . In other words, the dissolution of the sulphur deposit in the liquid solvent does not produce any sulphurized hydrocarbon. Furthermore, when H 2 is in contact with the liquid solvent, said liquid solvent is not reduced. Typically, the liquid solvent is chosen from naphthenic, a paraffinic, an aromatic hydrocarbon, or mixtures thereof, in particular an aromatic hydrocarbon such as alkyl naphthalene.

By "liquid sulphur rich solvent" it is meant the liquid solvent wherein all or parts of the sulphur deposit have been dissolved. Typically, the liquid sulphur rich solvent may contain from 1 wt to 10 wt weight of dissolved sulphur. This percentage is expressed in number of kg of dissolved sulphur with respect to the total number of kg of the liquid solvent. The dissolved sulphur may be in the form of elemental sulphur.

According to a step b) of the method of the invention, the well output 2 is then separated into a gas stream and a liquid sulphur rich solvent stream. The gas stream and the liquid sulphur rich solvent stream are naturally separated and thus separately recovered.

According to a step c) of the method of the invention, a feed H 2 gas stream is produced by a H 2 production unit 9. According to the present invention, any H 2 production unit 9 already present in an oil or gas treatment facility and producing a feed H 2 gas stream containing more than 1 mol. of H 2 can be used in the method of the present invention, such as an H 2 production unit used to provide H 2 in a hydrocracking process or a hydrodesulphurization process. Advantageously, the method of the present invention significantly reduces the CAPEX since it does not necessitate a dedicated H 2 production unit.

According to one embodiment, the H 2 production unit 9 may be a reducing gas generator in which air, from an AF line 26, steam, from a SF line 27 and fuel gas, from a FGF line 28 are introduced to produce the feed H 2 gas stream. The feed H 2 gas stream comprises gaseous H 2 . They may also comprise other compounds such as C0 2 , CO, H 2 0 and N 2 .

Typically, the feed H 2 gas stream may contain from 1 mol to 10 mol of H 2 , in particular from 2.5 mol to 8 mol of H 2 , more particularly from 5 mol to 7 mol of H 2 This percentage is expressed in mole number of H 2 with respect to the total number of mole of the feed H 2 gas stream.

According to a step d) of the method of the invention, the liquid sulphur rich solvent is introduced into a chemical reaction unit 5 and the feed H 2 gas stream is injected into the chemical reaction unit 5. During this step d), a portion of the feed H 2 gas stream chemically react with the dissolved sulphur of the liquid sulphur rich solvent thereby forming a liquid lean solvent and a H 2 S gas stream comprising H 2 S and an unreacted portion of the feed H 2 gas stream.

Advantageously, the portion of the feed H 2 gas stream required to produce H 2 S from the dissolved sulphur can be easily determined by well-known methods such as dosing the liquid rich solvent and/or by theoretical simulation.

Accordingly, the amount of the feed H 2 gas stream produced by the H 2 production unit can be easily adjusted in accordance with the amount of dissolved sulphur in the liquid sulphur rich solvent. The H 2 S gas stream mainly comprises gaseous H 2 S. It may also comprise other sulphur compounds such as S0 2 , S, COS and CS 2 and other compounds such as H 2 0, C0 2 and CO.

Typically the H 2 S gas stream may contain from 1 mol.% to 50 mol.% of H 2 S, in particular from 2 mol.% to 25 mol.% of H 2 S, more particularly from 3 mol.% to 5 mol.% of H 2 S. This percentage is expressed in mole number of H 2 S with respect to the total number of mole of the H 2 S gas stream.

The H 2 S gas stream also comprises an unreacted portion of the feed H 2 gas stream. Therefore the H 2 S gas stream comprises H 2 .

Typically the H 2 S gas stream may contain more than 0.01 mol.% of H 2 , in particular from 1 mol.% to 5 mol.% of H 2 , more particularly from 2 mol.% to 3 mol.% of H 2 . This percentage is expressed in mole number of H 2 with respect to the total number of mole of the H 2 S gas stream. The rate of conversion is the ratio of mole number of H 2 S formed over the mole number of dissolved elemental sulphur in the liquid sulphur rich solvent during the chemical reaction of step d).

According to one embodiment, the rate of the conversion is from 10% to 100%, in particular from 90 to 99.5% and more particularly from 95% to 99%.

According to one embodiment, the temperature of chemical reaction of step d) is from 170°C to 360°C, preferably from 250°C to 325°C, and more preferably from 275°C to 300°C.

According to one embodiment, the pressure of the chemical reaction of step d) isl bar to 40 bar, preferably 1.2 bar to 15 bar, more preferably 1.3bar to 10 bar.

The chemical reaction of step d) may be performed with or without a catalyst. Typically the catalyst may be any hydrogenation catalyst, such as, but not limited to, CoMo or NiMO.

Advantageously performing the chemical reaction of step d) without a catalyst reduces the CAPEX of the method of the invention and also avoids the classic step of activation of the catalyst. It also avoids the dangerous steps of introduction into and discharge of the catalyst from the chemical reaction unit 5.

However, depending on the amount of dissolved sulphur in the liquid sulphur rich solvent, using a catalyst may facilitate the chemical reaction of step d) by increasing the rate of the conversion. Typically, a catalyst may be used when the liquid sulphur rich solvent contains less than 10 wt% weight of dissolved sulphur.

As mentioned above the chemical reaction of step d) leads to the production of the H 2 S gas stream and the liquid lean solvent, which naturally separates. According to a step e) of the method of the invention, the H 2 S gas stream and the liquid lean solvent are recovered separately.

Typically, the liquid lean solvent is recovered in a recycling line 6 and then reinjected in the well 1. If the well output 2 comprises valuable liquid hydrocarbons, the liquid lean solvent may comprise these valuable liquid hydrocarbons. In this case, the liquid lean solvent may be separated from these valuable liquid hydrocarbons and then reinjected in the well 1. The separated valuable liquid hydrocarbons may then be introduced in a unit of an oil treatment facility to be converted into marketed products.

The H 2 S gas stream recovered during a step e) is introduced into a H 2 S treatment unit A so as to be converted into elemental sulphur during a step f).

According to the method of the present invention, the unreacted portion of the feed H 2 gas stream is advantageously introduced into the H 2 S treatment unit A and is involved in the steps leading to the conversion of H 2 S into elemental sulphur.

Accordingly, the H 2 production unit 9 produces H 2 which is not only involved in the formation of the H 2 S gas stream in the chemical reaction unit 5 but also in the treatment of sulphur compounds in the H 2 S treatment unit A.

Moreover the elemental sulphur obtained from the conversion of the H 2 S gas stream is a recoverable product that may be used for manufacturing sulfuric acid, medicine, cosmetics, fertilizers, rubber products and pesticide.

According to the method of the invention, the H 2 S treatment unit A comprises a hydrogenation unit 12, a H 2 S separation unit 14 and a Claus unit 16 for converting H 2 S into elemental sulphur. According to the method of the present invention, H 2 S is converted into elemental sulphur and a tail gas stream comprising sulphur compounds in the Claus unit 16. The elemental sulphur and the tail gas stream are recovered separately from the Claus unit 16. The recovered tail gas stream is then introduced into the hydrogenation unit 12. According to the method of the present invention, the sulphur compounds are hydrogenated into H 2 S and gasesous side product(s) in the hydrogenation unit 12. H 2 S and the gaseous side product(s) are then recovered from the hydrogenation unit 12 to be introduced into the H 2 S separation unit 14. In the H 2 S separation unit 14, the H 2 S is separated from the gaseous side product(s) thereby forming an enriched sulphur compounds gas stream comprising H 2 S. This enriched sulphur compounds gas stream is recovered to be introduced into the Claus unit 16 so as to convert H 2 S into elemental sulphur and the tail gas stream comprising sulphur compounds.

Typically the tail gas stream comprises sulphur compounds, such as S0 2 , S, COS or CS 2 , and other compounds such as H 2 , N 2 , H 2 S, C0 2 , and mixture thereof.

The enriched sulphur compounds gas stream mainly comprises H 2 S. It may also comprise H 2 S, H 2 0, N 2 , C0 2 . Typically the enriched sulphur compounds gas stream may contain from 10 mol to 80 mol of H 2 S, in particular from 20 mol to 70 mol of H 2 S, more particularly from 30 mol to 50 mol of H 2 S. This percentage is expressed in mole number of H 2 S with respect to the total number of mole of the enriched sulphur compounds gas stream.

Typically the gaseous side product(s) may comprise H 2 S, H 2 0, N 2 , C0 2j S0 2 , COS, CS 2 , and mixture thereof. They may be recovered from the H 2 S separation unit 14 and burnt in an incinerator 19. According to one embodiment, before the introduction of the H 2 S gas stream into the H 2 S treatment unit A during step e), the H 2 S of the H 2 S gas stream is not separated from the unreacted portion of the feed H 2 gas stream.

The gas stream recovered during step b) of the method of the invention may be separated during a step g) in an Acid Gas Removal unit (AGR unit) 20 into a sweet hydrocarbon gas stream which is recovered in a sweet gas recovery line 21, and into an acid gas stream which is recovered in an acid line 17.

Typically, the acid gas stream comprises several compounds such as H 2 S, S0 2 , C0 2 , H 2 0, COS, Mercaptans, hydrocarbons including aromatics such as benzene, toluene, xylene, or mixture thereof. The acid gas stream may be introduced in the Claus unit 16 to produce elemental sulphur and the tail gas stream in a step h).

The sweet hydrocarbon gas stream recovered in the sweet gas recovery line 21 is then dehydrated in a dehydration unit 22 and separated in a fractionation unit 23 into a light hydrocarbon gas stream and light hydrocarbon cuts during a step i). During a step j) the light hydrocarbon gas stream is then recovered in a light gas line 24 while and the light hydrocarbon cuts is recovered separately in a light cut line 25.

According to the method of the invention, represented by Figure 1, the H 2 S gas stream is introduced into the hydrogenation unit 12. The sulphur compounds of the tail gas stream are hydrogenated by the unreacted portion of the feed H 2 gas stream into H 2 S. Moreover H 2 S recovered from the hydrogenation unit 12 comprises H 2 S from the H 2 S gas stream.

Advantageously, the amount of H 2 to perform the hydrogenation can be easily determined since the hydrogenation unit 12 has been studied a lot and thus is well known by the skilled person.

Alternatively, the H 2 S gas stream may be introduced into the H 2 S separation unit 14. In this case the enriched sulphur compounds gas stream comprises H 2 S from the H 2 S gas stream. Alternatively, the H 2 S gas stream may be introduced into the Claus unit 16. In this case the H 2 S from the H 2 S gas stream is converted into elemental sulphur and into the tail gas stream comprising sulphur compounds.

Whatever the unit of the H 2 S treatment unit A into which the H 2 S gas stream is introduced, the method of the present invention advantageously reduces the CAPEX. Indeed, all these units are perfectly integrated into the method of the present invention thereby allowing synergies between all these units.

The choice to introduce the H 2 S gas stream into one of the above mentioned units of the H 2 S treatment unit A depends on the concentration of H 2 S in the H 2 S gas stream.

Typically if the concentration of H 2 S in the H 2 S gas stream is higher or equal to 20 mol.%, in particular 30 mol.%, more particularly 45 mol.%, then the H 2 S gas stream may be introduced into the Claus unit 16. Below these values, the efficiency of the Claus unit 16 might decrease. Typically if the concentration of H 2 S in the H 2 S gas stream is lower or equal to 15 mol.%, in particular 10 mol.%, more particularly 7 mol.%, then the H 2 S gas stream may be introduced into the hydrogenation unit 12.

Typically if the concentration of H 2 S in the H 2 S gas stream is from 5 mol.% to 45 mol.%, in particular 10 mol.% to 30 mol.%, more particularly 15 mol.% to 20 mol.%, then the H 2 S gas stream may be introduced into the H 2 S separation unit 14.

Whatever the unit of the H 2 S treatment unit A into which the H 2 S gas stream is introduced, the H 2 feed gas stream is not necessarily introduced directly into the chemical reaction unit 5. Instead, as illustrated in Figure 2, the H 2 feed gas stream may be first introduced into a tail line 11 of the H 2 S treatment unit A connecting the Claus unit 11 to the hydrogenation unit 12 and a portion of this H 2 gas stream may then be drawn off from the tail line 11 and introduced into the chemical reaction unit 5. The amount of the unreacted portion of the feed H 2 gas stream present in the H 2 S gas stream may be too low to completely hydrogenate the sulphur compounds of the tail gas stream in the hydrogenation unit 12, thereby reducing the efficiency of the H 2 S treatment unit A. Whatever the unit of the H 2 S treatment unit A into which the H 2 S gas stream is introduced, a second feed H 2 gas stream produced by the H 2 production unit 9 may be introduced into the hydrogenation unit 12, as illustrated in Figure 3. Advantageously the introduction of the second feed H 2 gas stream into the hydrogenation unit 12 can easily compensate the low amount of the unreacted portion of the feed H 2 gas stream present in the H 2 S gas stream so that the H 2 S treatment unit A remains efficient. According to one embodiment, the second feed H 2 gas stream is introduced into the tail line 11 so as to be injected into the hydrogenation unit 12.

Accordingly, the second feed H 2 gas stream is mixed with the tail gas stream into the tail line 11. The resulting gas mixture stream is then injected into the hydrogenation unit 12. Another object of the invention is a device for carrying out the methods of the invention. Said device is now described in more details by referring to Figure 1, and comprises:

- a gas/liquid separation unit 3 for separating the well output 2 into a gas stream recovered in a gas recovering line 10 and a liquid sulphur rich solvent stream recovered in liquid recovering line 4,

- a H 2 production unit 9 for producing a feed H 2 gas stream

- a H 2 feeding line 7 for recovering the feed H 2 gas stream,

- a chemical reaction unit 5 fed by the liquid recovering line 4 and the H 2 feeding line 7 for performing chemical reaction of H 2 with the dissolved sulphur from the liquid sulphur rich solvent, thereby forming an H 2 S gas stream and a liquid lean solvent,

- a recycling line 6 for recovering the liquid lean solvent,

- a H 2 S recovering line 8 for recovering the H 2 S gas stream from the chemical reaction unit 5,

- a H 2 S treatment unit A fed by the H 2 S recovering line 8 for performing conversion of the H 2 S gas stream into elemental sulphur.

The gas/liquid separation unit 3 is a common gas/liquid separator. It is able to separate and to recover the liquid sulphur rich stream in the liquid recovering line 4 and the gas stream in the gas recovering line 10.

The chemical reaction unit 5 is a common reactor to perform gas-liquid reaction with production of a gas stream and a liquid flow.

According to one embodiment, the H 2 S treatment unit A comprises:

- a Claus unit 16 fed with a line 15 comprising an enriched sulphur compounds gas stream, comprising mainly H 2 S, for converting H 2 S into elemental sulphur and a tail gas stream comprising sulphur compounds,

- a tail line 11 for recovering the tail gas stream and an elemental sulphur line 18 for recovering the elemental sulphur,

- an hydrogenation unit 12 fed with the tail line 11 for hydrogenating the sulphur compounds of the tail gas stream into H 2 S and gaseous side product(s), - a gas mixture line 13 for recovering the H 2 S and the gaseous side product(s),

- a H 2 S separation unit 14 fed with the gas mixture line 13 for separating H 2 S from the gaseous side product(s) thereby forming the enriched sulphur compounds gas stream which is recovered in the line 15. Typically the Claus unit 16 may be fed with an oxidative agent comprising oxygen in order to enable the oxidation of H 2 S into elemental sulphur. The tail gas stream may also be produced as a side product. The oxidative agent may be air, pure oxygen or a mixture mostly comprising oxygen and nitrogen, wherein the amount of nitrogen does not exceed 80 %. The hydrogenation unit 12 typically comprises a catalyst bed with hydrogenation catalysts, such as CoMo, wherein the sulphur compounds such are hydrogenated converted into H 2 S. Gaseous side product(s) may also be produced as a side product.

The H 2 S separation unit 14 may be an amine-based unit but any other suitable absorbing unit may be used. The device may further comprise a stripper column in order to separate the absorbing solution from the sulphur compounds, thereby producing the enriched sulphur compounds gas stream, comprising mainly H 2 S. The absorbing solution may be recovered at the bottom of the stripper column and recycled to the absorber, while the enriched sulphur compounds gas stream is recovered in a line 15. The device may further comprise an incinerator 19 to burn the gaseous side product(s) recovered from the H 2 S separation unit 14 and producing a flue gas stream.

According to one embodiment, the device may further comprise:

- an Acid Gas Removal unit 20 fed by the gas recovering line 10 comprising the gas stream for separating it into a sweet hydrocarbon gas stream which is recovered in a sweet gas recovery line 20 and an acid gas stream comprising

H 2 S which is recovered in an acid line 17,

- a dehydration unit 22 and a fractionation unit 23 fed with the sweet gas recovery line 20 to dehydrate and separate the sweet hydrocarbon gas stream into a light hydrocarbon gas stream and light hydrocarbon cuts, and - a light gas line 24 and a light cut line 25 to recover separately the light hydrocarbon gas stream and light hydrocarbon cuts.

The Acid Gas Removal unit (AGR unit) 20 may be typically an amine washing unit. According to the desired specification, the amine solutions may include DEA (di- ethanol amine), MDEA (methyl-di-ethanol amine) or activated MDEA or any other amine-based solution known in the art as an absorbing solution.

According to the water dew point desired, the dehydration unit 22 may use a dehydration solvent such as glycol or triethylene glycol (TEG), or molecular sieves.

The fractionation unit 23 generally assures the fractionation; classically it comprises a demethanizer, a deethanizer, a depropanizer and a debutanizer.

Typically, the acid line 17 can feed the Claus unit 16 with the acid gas so as to produce elemental sulphur and the tail gas stream.

According to the device of the invention, represented by Figure 1, the hydrogenation unit 12 is fed with the H 2 S recovering line 8. According to one embodiment, the H 2 S separation unit 14 is fed with the H 2 S recovering line 8.

According to one embodiment, the Claus unit 16 is fed with the H 2 S recovering line 8.

In one embodiment, as illustrated in Figure 2, a second H 2 feeding line 77 connects the H 2 production unit 9 to the tail line 11, and the H 2 feeding line 7 is connected to the tail line 11 downstream to the connection between the second H 2 feeding line 77 and tail line 11.

In one embodiment, as illustrated in Figure 3, the hydrogenation unit 12 may be fed with a second H 2 feeding line 77 connected to the H 2 production unit 9.