AU2012261477B2

AU2012261477B2 - Process for removing contaminants from natural gas

Info

Publication number: AU2012261477B2
Application number: AU2012261477A
Authority: AU
Inventors: Robert Amin; Casper Krijno Groothuis
Original assignee: Shell Internationale Research Maatschappij BV
Current assignee: Shell Internationale Research Maatschappij BV
Priority date: 2003-02-07
Filing date: 2012-12-04
Publication date: 2014-01-16
Anticipated expiration: 2024-02-04
Also published as: AU2006236093B2; AU2007216935B2; AU2006236093A1; AU2012261477A1; AU2007216935A1; AU2012261477C1; AU2007216935B8

Abstract

- 14 PROCESS FOR REMOVING CONTAMINANTS FROM NATURAL GAS A process for removing contaminants from a natural gas feed stream including water and sour species, which process comprises the steps of cooling the natural gas feed stream in a first vessel (12) to a first operating temperature at which hydrates may be formed and removing from the first vessel (12) a stream of dehydrated gas (34); and cooling the dehydrated gas in a second vessel (14) to a second operating temperature at which solids of the sour species are formed or at which the sour species dissolve in a liquid and removing from the second vessel (14) a stream of dehydrated sweetened gas (62). (Figure 2) CS/TS9536FF r4r

Description

- 1 PROCESS FOR REMOVING CONTAMINANTS FROM NATURAL GAS The present invention relates to a process for removing contaminants, for example hydrogen sulphide or carbon dioxide when the contaminant is a sour species from a natural gas feed stream including water and sour species. The present invention also relates particularly, though not exclusively, to a 5 process and apparatus for sequentially dehydrating and sweetening the natural gas feed stream. Natural gas from either production reservoirs or storage reservoirs typically contains water, as well as other species, which form solids during the liquefaction to produce liquefied natural gas (LNG). It is common practice for the natural gas to be 10 subjected to a dehydration process prior to the liquefaction. Water is removed to prevent hydrate formation occurring in pipelines and heat exchangers upstream of the liquefaction vessel. If water is not removed, solid hydrates may form in pipe work, heat exchangers and/or the liquefaction vessel. The hydrates are stable solids comprising water and 15 natural gas having the outward appearance of ice, with the natural gas stored within the crystal lattice of the hydrate. Methods of dehydrating natural gas feed streams known in the art include absorption of water in glycol or adsorption of the water using a solid such as hydrated aluminium oxide, silica gels, silica-alumina gels and molecular sieves. 2 0 Natural gas also typically contains sour species, such as hydrogen sulphide

(H

2 S) and carbon dioxide (C0 2 ). Such a natural gas is classified as "sour gas". When the H 2 S and CO 2 have been removed from the natural gas feed stream, the gas is then classified as "sweet". The term "sour gas" is applied to natural gases including H 2 S because of the bad odour that is emitted even at low concentrations from an 25 unsweetened gas. H 2 S is a contaminant of natural gas that must be removed to satisfy legal requirements, as H 2 S and its combustion products of sulphur dioxide and sulphur trioxide are also toxic. Furthermore, H 2 S is corrosive to most metals normally associated with gas pipelines so that processing and handling of a sour gas may lead to premature failure of such systems.

-2 Like dehydration, gas sweetening processes are known in the art, such processes typically include adsorption using solid adsorption processes or absorption using amine processes, molecular sieves, etc. Existing dehydration and gas sweetening processes are extremely complex and expensive. 5 The present invention represents an alternative process for removing contaminants from a natural gas feed stream including water and sour species. In accordance with the present invention, there is provided a process for removing contaminants from a natural gas feed stream including water and sour species, which process comprises the steps of dehydrating the natural gas feed stream 10 in a first vessel; removing from the first vessel a stream of dehydrated gas; cooling by means of exapnsion the dehydrated gas in a second vessel to a second operating temperature at which solids of the sour species are formed; and removing from the second vessel a stream of dehydrated sweetened gas. The term "operating temperature" is used to refer to a temperature below the 15 solid/liquid transition temperature for the contaminant at a given pressure of operation of the first or second vessel. In this specification a "warm" liquid stream can be any compatible stream of liquid having a temperature above the solid/liquid transition temperature of the contaminant for a given pressure of operation of the first or second vessel. The warm 20 liquid stream has thus a temperature that is sufficiently high to cause melting of the solids of the contaminant. The warm liquid may or may not take the contaminant fully into solution. The invention will now be described in more detail with reference to the accompanying non-limiting drawings, wherein 25 Figure I shows schematically a process flow diagram of a non-limiting embodiment of the dehydration step according to the present invention; and Figure 2 shows schematically a process flow diagram of a non-limiting embodiment of the present invention; and Figure 3 shows schematically a process flow diagram of a further non-limiting 30 emobdiment o fthe present invention. Reference is now made to Figure I in which dehydration of the feed stream takes place by means of hydrate formation. In this respect it is noted that the present -3 invention is not limited to the dehydration of the feed stream by hydrate formation. Alternative ways of dehydrating the feed stream include but are not limited to absorption of water in glycol or adsorption of the water using a solid such as hydrated aluminium oxide, silica gels, silica-alumina gels and molecular sieves as is known in 5 the art. Figure I shows an apparatus 10 for carrying out the dehydration step of the present invention. The apparatus 10 comprises a first vessel 12. The contaminant removed in the first vessel 12 is water and thus the gas exiting the first vessel 12 is dry. Also heavy hydrocarbons are removed as a consequence of this process, and thus 10 the gas stream exiting the first vessel 12 is dew pointed for hydrocarbons to an extent determined by the conditions in the first vessel 12. In the embodiment of Figure 1, the water dew point of the gas exiting the first vessel 12, however, is lower than its equilibrium dew point due to the formation of hydrates. In the embodiment as illustrated in Figure 1, wet feed gas from a wellhead is fed 15 through conduit 15 to a first flash tank 16 in which condensate is separated from the feed gas. The pressure and temperature conditions within the first flash tank 16 would typically be in the order of 75 to 130 bar and between 25 and 40 'C (about 5 to 10 'C above the hydrate formation temperature). The condensate liquid stream exiting the first flash vessel 16 through conduit 17 is "a warm liquid" as defined above. The 20 condensate consists of liquid hydrocarbons that are produced together with natural gas. The gas stream separated from the sour wet feed gas in the first flash tank 16 enters the first vessel 12 via wet sour gas feed stream inlet 20. An intermediate heat exchanger 22 may be used to cool the wet sour gas between the first flash tank 16 and the first vessel 12. The intermediate heat exchanger 22 drops the temperature of the 25 wet sour gas to a temperature just above the hydrate formation temperature for the particular pressure of this feed stream. The hydrate formation temperature for the particular pressure of the feed stream is the maximum value of the first operating temperature, which is the operating temperature in the first vessel 12. The wet gas feed stream fed to the first vessel 12 is expanded using a Joule 30 Thompson valve 24 or other suitable expansion means such as a turbo expander to further cool the stream as it enters the first vessel 12. The Joule-Thompson valve 24 may alternatively define the inlet 20 to the first vessel 12. Upon expansion of the wet -4 sour gas feed stream into the first vessel 12, the gas pressure-temperature conditions within the vessel 12 allow hydrates to form. The necessary degree of cooling is achieved by the degree of expansion of the wet sour gas feed stream through the Joule-Thompson valve 24. 5 In the embodiment of Figure 1, the first operating temperature and the pressure in the first vessel 12 are maintained at a level whereby hydrates are formed (again it should be noted that according to the present invention, dehydration of teh feed stream is not limited to hydrate formation). The natural gas feed stream entering downstream of the Joule-Thompson valve 24 into the first vessel 12 is at the first 10 operating temperature. If the natural gas feed stream also contains sour species, the first operating temperature to which the feed gas in the first vessel 12 is cooled is below the temperature at which hydrates are formed but above the temperature at which solids of sour species, such as H 2 S and CO 2 , are formed. This is done to produce hydrates 15 and to prevent the formation of solids of sour species in the first vessel 12. Dry sour gas exits the first vessel 12 via dry sour gas outlet 34. Typically the dry sour gas exiting the first vessel 12 would have a nominal pressure of 10 to 30 bar lower than the pressure upstream of the expansion device 24 and a temperature of 10 to 25'C lower than the temperature just upstream of the expansion device 24. The 20 term "dry gas" is used to refer to water-free gas. A hydrate-containing liquid stream is removed from the first vessel 12 via water condensate outlet 28, and passed through conduit 29 to a separator 30. The water is separated from the condensate in the water condensate separator 30. Such a separator is for example a baffled gravity separation unit. As water is heavier than the 25 condensate, any suitable gravity separation techniques may be used. The separated condensate is removed through conduit 31 and the separated water is removed through conduit 33. The natural gas feed stream entering into the first vessel 12 was cooled to the first operating temperature. Alternatively, the natural gas feed stream can be cooled 30 using one or more sprays of a sub-cooled liquid introduced via sub-cooled liquid inlet 26. In a further alternative embodiment, the natural gas feed stream is cooled by both the Joule-Thompson valve 24 and the sub-cooled liquid supplied through inlet 26. In - 5 case of spray cooling, the natural gas feed stream can enter into the first vessel 12 at a temperature that is at or above the hydrate-formation temperature. The sub-cooled liquid inlet 26 should be located in the first vessel 12 above the inlet 20 of the wet sour gas feed stream. In the illustrated embodiment, the sub-cooled 5 liquid inlet 26 is a plurality of spray nozzles. The particular sub-cooled liquid is condensate recycled from the process and sprayed into the first vessel 12. Sprays are used in order to maximise the contact area of the sub-cooled liquid and the gas and thus the cooling effect of contact of the sub-cooled liquid with the wet sour gas. The dry sour gas at a pressure of 10 to 30 bar lower than the pressure upstream 10 of the expansion device 24 and at the operating temperature of the first vessel 12 is directed via second heat exchanger 36 in conduit 35 to a second flash tank 40. It is cooled in the second heat exchanger 36 to form a two-phase mixture of gas and condensate at a temperature higher than -56 'C. Not shown is that additional cooling may be provided by indirect heat exchange with a refrigerant that is circulated through 15 an external refrigeration cycle, for example a propane refrigeration cycle. In the second flash tank 40, condensate is separated from the dry sour gas stream. The liquid stream exits the second flash tank 40 via liquid outlet 42 and is sufficiently cooled to satisfy the criteria of a sub-cooled liquid that may be fed to the sub-cooled liquid inlet 26 of the first vessel 12. The sub-cooled liquid is supplied through conduit 43, 20 provided with a pump 44 to the sub-cooled liquid inlet 26. The dry sour gas exits the second flash tank 40 via gas outlet 47 and is fed through conduit 45 to the intermediate heat exchanger 22 and from there to an end user (not shown). As observed earlier, the non-limiting embodiment of Figure 1 relates to 25 dehydrating natural gas by forming hydrates (as one optional way of dehydrating the feed stream). To prevent hydrates from blocking outlet 28 and conduit 29, the condensate present in the lower portion of the first vessel 12 is preferably heated. This is suitably done by introducing a warm liquid into the first vessel 12 below the level at which the feed stream is introduced. 30 A portion of the stream of warm condensate separated in the first flash tank 16 is fed through conduit 17 and inlet 18 to the first vessel 12. The warm condensate is sufficiently warm to liquefy hydrate formed in the first region of the first vessel 12. As -6 the hydrates melt, the gas trapped in the hydrate lattice is liberated and the water goes into solution with the condensate. In addition at least a portion of the condensate separated in the water/condensate separator 30 can be recycled for use as the warm liquid used for heating the solids of the freezable species in the first vessel 12 through 5 conduit 37 (after heating, not shown). Any gas present within the water condensate separator may be recycled to the first vessel 12. Alternatively or additionally, a portion of the gas separated in the water/condensate separator 30 may be recycled to the wet sour gas feed stream entering the first vessel 12 via inlet 20. 10 Suitably the liquid that is sprayed into the first vessel through inlets 26 is a natural gas liquid, which natural gas liquid is a mixture of C 2 , liquefied petroleum gas components, C 3 and C 4 and C 5 + hydrocarbon components. Suitably, the warm liquid that is introduced into the first vessel through inlet 18 is also a natural gas liquid. 15 Reference is now made to Figure 2 showing a non-limiting embodiment of a process for removing contaminants, from a natural gas feed stream including water and sour species in accordance with the present invention. In this non-limiting embodiment dehydrated gas is treated to remove sour components from it. The dehydration process is discussed with reference to Figure 1, and will not be repeated 20 here. As indicated above, dehydration of the feed stream is according to the present invention not limited to hydrate formation and can be done in several other ways. Parts having the same function as parts shown in Figure I get the same reference numeral. The dry sour gas exits the second flash tank 40 via gas outlet 47 and is fed to a 25 second vessel 14 via dry sour gas inlet 46. As with the first vessel 12, the dry sour gas being fed to the second vessel 14 may be expanded through a Joule-Thompson valve 48 or other suitable expansion means, such as a turbo expander, in order to further cool the gas. As before with the first vessel 12, the Joule-Thompson valve may define the dry sour gas inlet 46. The temperature of the dry gas entering into the 30 second vessel 14 is at a second operating temperature. The second operating temperature is the maximum temperature at which solids of the sour species are formed or the temperature at which the sour species dissolve in a liquid.

-7 The gas exiting the second vessel 14 via outlet 62 is dehydrated and sweetened. The dry sweetened gas would typically be at a pressure of between 20 and 50 bar and a temperature of not lower than -85 'C. This product stream of sweetened dry gas is typically transported to the end user at ambient temperature. 5 The product stream of dry sweetened gas can be further cooled by allowing the gas to expand in expansion device 63, and the further cooled dry sweetened gas is used in one or more of the heat exchangers 38, 36 or 22 to effect cooling of one or more of the other process streams within the apparatus 10. Please note that the temperature to which the dry gas is cooled in heat exchanger 36 is greater than that at 10 which the solids of the sour species form for the given line pressure. Through outlet 52 a liquid is removed that contains the sour species. The dry sour gas was cooled to the second operating temperature by allowing the gas to expand in Joule-Thompson valve 48. Alternatively, the dry sour gas can be cooled using one or more sprays of a sub-cooled liquid supplied through inlet 49. In a 15 further alternative embodiment, the natural gas feed stream is cooled by both the Joule-Thompson valve 48 and the sub-cooled liquid supplied through inlet 49. In case of spray cooling, the dry gas can enter into the second vessel 14 at a temperature that is at or above the temperature at which solids of the sour species are formed or the temperature at which the sour species dissolve in a liquid. 20 The sub-cooled liquid inlet 49 should be located in the second vessel 14 above the dry sour gas inlet 46. In the illustrated embodiment the sub-cooled liquid inlet 49 is a plurality of spray nozzles. The temperature and pressure conditions in the second vessel 14 are adjusted so as to form solids of the freezable species. For sweetening of a gas, the temperature-pressure conditions need only be adjusted to form solids of 25 hydrogen sulphide (H 2 S) and carbon dioxide (CO 2 ). However, the process conditions within the second vessel are sufficient to cause the formation of solids of the freezable species of other hydrocarbons such as benzene, toluene, ethylbenzene and xylene. Suitably, the sub-cooled liquid is part of the liquid passing through conduit 43. In order to reduce the temperature the liquid is passed through conduit 50 to the heat 30 exchanger 38 where it is cooled by indirect heat exchange with dry sweetened gas. The dry sweetened gas is then passed through conduit 65 to heat exchanger 36 for cooling the dry sour gas from the first vessel 12.

- 8 The dry sweetened gas is then fed to the intermediate heat exchanger 22 and from there to an end user (not shown). Applicant had found that in particular the concentration of C 2

-C

4 hydrocarbon components in the liquid should be in the range of from 0.5 to 1.5 mol per mol of 5 CO 2 in the feed gas. The liquid in the second vessel 14 is the liquid sprayed in the vessel through the inlet 49. Thus the concentration of C 2

-C

4 hydrocarbon components in the sub-cooled liquid should be in the specified range. It will be understood that if the concentration of C 2

-C

4 hydrocarbon components in the liquid stream in conduit 50 is too low, additional C 2

-C

4 hydrocarbon components can be 10 added to this stream. To prevent sour species from blocking outlet 52, the condensate present in the lower portion of the second vessel 14 is preferably heated. This is suitably done by introducing a warm liquid through warm condensate inlet 56 into the second vessel 14 below the level at which the feed stream is introduced. A suitable liquid is liquid 15 passing through conduit 50. Alternatively liquid passing through conduit 31 can be used. Figure 3 shows an alternative non-limiting embodiment of a process for removing contaminants from a natural gas feed stream including water and sour species in accordance with the present invention. Parts having the same function as 20 parts shown in Figures I and 2 are depicted as having the same reference number in Fig. 3. In the embodiment of Fig. 3, the dehydration in the first vessel 12 is performed using molecular sieves (generally referred to with reference number 301). As is common in the art, the first vessel 12 with molecular sieves is operated in cyclic 25 mode, also using a regeneration system (not shown). This regeneration system typically has a separate water knock-out stream (also not shown), and uses a dehydrated gas stream which may be taken from gas stream 34 and after use combined with feed gas stream 15 for reprocessing. As molecular sieves are used, no dehydration by hydrate formation takes place 30 in the first vessel 12. Further, in the embodiment of Fig. 3, the wet feed gas stream 15 is cooled against the dry sweetened gas stream in heat exchanger 322 (rather than in heat exchanger 22 as shown in Fig. 2). Different to Fig. 2, no expansion takes place - 8a between the first flash tank 16 and the inlet 20 of the first vessel 12 in the embodiment of Fig. 3. Also, in Fig. 3, the full bottom stream of the first flash tank 16 is sent to the water/condensate separator 30 Further optimisation of the above discussed flow schemes to improve heat 5 integration is possible. For example part of the hydrocarbon liquid stream leaving the second vessel 14 through outlet 52 can be recycled to inlet 26 of the first vessel 12. In order to do so a separation vessel (not shown) is used to separate a stream of liquid enriched in sour species from the hydrocarbon stream that is recycled. Modifications and variations such as would be apparent to a skilled person are 10 considered to be within the scope of the present invention. It is also to be understood that the scope of the claims should not be limited to the specific non-limiting embodiments described above.

Claims

1. A process for removing contaminants from a natural gas feed stream including water and sour species, which process comprises the steps of dehydrating the natural gas feed stream in a first vessel; removing from the first vessel a stream of dehydrated gas; cooling by means of expansion the dehydrated gas in a second vessel to a second 5 operating temperature at which solids of the sour species are formed; and removing from the second vessel a stream of dehydrated sweetened gas.

2. The process according to claim 1, wherein dehydrating the natural gas feed stream includes cooling the natural gas feed stream to a first operating temperature at which hydrates are formed. 10

3. The process according to claim 1 or claim 2, wherein the means of expansion is a Joule-Thompson valve.

4. The process according to claim 2 or claim 3, wherein the step of cooling the natural gas feed stream in a first vessel to a first operating temperature comprises introducing the natural gas feed stream into the first vessel at a temperature that is 15 below the first operating temperature.

5. The process according to any one of claims 1 to 3, wherein the step of cooling the dehydrated gas in a second vessel to a second operating temperature comprises introducing the dehydrated gas into the second vessel at a temperature that is below the second operating temperature. 20

6. The process according to claim 2 or claim 3, wherein the step of cooling the natural gas feed stream in a first vessel to a first operating temperature comprises introducing the natural gas feed stream into the first vessel at a temperature that is below the first operating temperature, and wherein the step of cooling the dehydrated gas in a second vessel to a second operating temperature comprises introducing the 25 dehydrated gas into the second vessel at a temperature that is below the second operating temperature.

7. The process according to claim 1, comprising: cooling the stream of dehydrated gas removed from the first vessel to form a two-phase mixture of dehydrated gas and - 10 condensate, passing the two-phase mixture of dehydrated gas and condensate into a flash tank, separating the condensate from the dehydrated gas in the flash tank, removing the dehydrated gas from which the condensate has been separated from the flash tank, and introducing the dehydrated gas from which the condensate has been 5 separated into the second vessel.

8. The process according to claim 7, wherein the stream of dehydrated gas removed from the first vessel is cooled in a heat exchanger to form the two-phase mixture of dehydrated gas and condensate.

9. The process according to claim 7 or claim 8, wherein the stream of dehydrated 10 gas removed from the first vessel is cooled to form the two-phase mixture of dehydrated gas and condensate at a temperature higher than -56"C.

10. The process according to any one of claims 7 to 9, further comprising: removing a liquid stream of condensate from the flash tank.

11. The process according to claim 10, further comprising: introducing at least part 15 of the liquid stream of the condensate into the second vessel.

12. The process according to claim 1, comprising: cooling the stream of dehydrated gas removed from the first vessel to form a two-phase mixture of dehydrated gas and condensate, passing the two-phase mixture of dehydrated gas and condensate into a flash tank, separating the condensate from the dehydrated gas in the flash tank, 2 0 removing a liquid stream of condensate from the flash tank. removing the dehydrated gas from which the condensate has been separated from the flash tank, and introducing the dehydrated gas from which the condensate has been separated into the second vessel wherein the step of cooling the dehydrated gas from which the condensate has been separated in the second vessel to the second operating 25 temperature further comprises introducing at least part of the liquid stream of the condensate removed from the flash tank into the second vessel at a temperature that is below the second operating temperature to form a slurry or mixture with the sour species,

13. The process according to claim 11 or 12, wherein the concentration of C2 -C 4 30 hydrocarbon components in the at least part of the stream of condensate removed from the flash tank and introduced into the second vessel is from about 0.5 to 1 .5 per mol of CO 2 in the natural gas feed stream. - 11

14. The process according to any one of claims 11 to 13, wherein the at least part of the stream of condensate removed from the flash tank is introduced into the second vessel through an inlet located above an inlet introducing the dehydrated gas from which the condensate has been separated. 5

15. The process according to claim 14, wherein the inlet introducing the at least part of the stream of condensate removed from the flash tank into the second vessel is a plurality of spray nozzles.

16. The process according to any one of claims 1-6. wherein the step of cooing the dehydrated gas in a second vessel to a second operating temperature further 10 comprises introducing the dehydrated gas into the second vessel and introducing a stream of liquid into the second vessel at a temperature that is below the second operating temperature to form a slurry or mixture with the sour species.

17. The process according to any one of claims 2 to 4, wherein the step of cooling the natural gas feed stream in a first vessel to a first operating temperature comprises 15 introducing the natural gas feed stream into the first vessel and introducing a stream of liquid into the first vessel at a temperature that is below the first operating temperature to form a slurry with the hydrates, and wherein the step of cooling the dehydrated gas in a second vessel to a second operating temperature further comprises introducing the dehydrated gas into the second vessel and introducing a 20 stream of liquid into the second vessel at a temperature that is below the second operating temperature to form a slurry or mixture with the sour species.

18. The process according to claim 16 or claim 17, wherein the stream of liquid is a natural gas liquid.

19. The process according to claim 16 or 17, wherein the concentration of C2 -C4 25 hydrocarbon components in the stream of liquid introduced into the second vessel is from about 0.5 to 1.5 per mol of CO 2 in the natural gas feed stream.

20, The process according to claim 17 or claim 19, wherein the stream of liquid is introduced into the second vessel through an Inlet located above an inlet introducing the dehydrated gas. 30

21. The process according to claim 20, wherein the inlet introducing the stream of liquid into the second vessel is a plurality of spray nozzles. - 12

22. The process according to any one of claims I to 6 or 16 to 21, further comprising the step of heating the sour species in the second vessel to a temperature that is above the second operating temperature to obtain a sour species-containing iquid. 5

23. The process according to claim 22, wherein heating the sour species in the second vessel comprises adding to the sour species a warm liquid.

24. The process according to claim 23, wherein the warn liquid is a natural gas liquid.

25. A process for removing contaminants from a natural gas feed stream including 10 water and sour species comprising the steps, substantially as hereinbefore described with reference to the examples and figures 1 and 2.

26. The process according to any one of claims 2, 17 or 19 to 20, wherein the stream of dehydrated sweetened gas removed from the second vessel is at a temperature of not less than -85"C. 15

27. The process according to any one of claims 2, 17, 19 to 20 or 26, wherein the stream of dehydrated sweetened gas removed from the second vessel is at a pressure of between 20 and 50 bar.

28. The process according to any one of claims I to 6, 16 to 24, 26 or 27, wherein the stream of dehydrated sweetened gas removed from the second vessel is further 20 cooled by means of expansion and passed to one or more heat exchangers to effect cooling of one or more other process streams, but the temperature to which the stream of dehydrated gas removed from the first vessel is cooled in any such heat exchanger is greater than the temperature at which solids of the sour species are formed. 25

29. The process according to claim 28. wherein the stream of dehydrated sweetened gas removed from the second vessel and further cooled by means of expansion is passed to a heat exchanger to effect cooling of the stream of dehydrated gas removed from the first vessel.

30. The process according to any one of claims 16 to 23, 26 or 27, wherein the 30 stream of dehydrated sweetened gas removed from the second vessel is further cooled by means of expansion and passed to a first heat exchanger to effect cooling of the stream of liquid to be introduced into the second vessel, the stream of dehydrated - 13 sweetened gas is then passed to a second heat exchanger to effect cooling of the stream of dehydrated gas removed from the first vessel, but the temperature to which the stream of dehydrated gas removed from the first vessel is cooled in the second heat exchanger is greater than the temperature at which solids of the sour species are 5 formed.

31. The dehydrated sweetened gas of the process of any one of claims I to 30.