WO2014198783A1

WO2014198783A1 - Process for the oxidation of hydrogen sulphide

Info

Publication number: WO2014198783A1
Application number: PCT/EP2014/062148
Authority: WO
Inventors: Eri Ito; Diego Patricio VALENZUELA; Sipke Hidde Wadman
Original assignee: Shell Internationale Research Maatschappij BV; Shell Oil Co
Current assignee: Shell Internationale Research Maatschappij BV; Shell USA Inc
Priority date: 2013-06-14
Filing date: 2014-06-11
Publication date: 2014-12-18
Anticipated expiration: 2015-12-14

Abstract

The present invention provides a process for the oxidation of hydrogen sulphide (H₂S) in an H₂S-containing hydrocarbon feed gas to elemental sulphur. In the process a H₂S-containing hydrocarbon feed gas (10) and a sulphur dioxide containing gas (20) are contacted in a catalytic zone (3) at a temperature of 120 to 200°C, and a pressure of 4 to 200 bara, thereby forming elemental sulphur which is essentially in liquid form. A stream (30) containing the elemental sulphur and a first H₂S-depleted gaseous stream (50) are removed from the catalytic zone (3). The first H₂S-depleted gaseous stream (50) is separated, thereby obtaining a concentrated H₂S-containing gaseous stream (60) and a second H₂S-depleted gaseous stream (70). The concentrated H₂S-containing gaseous stream (60) is incinerated, thereby obtaining a SO₂-containing stream (80). At least a part of the SO₂-containing stream (80) is used as the SO₂-containing gas (20) supplied in step (b).

Description

PROCESS FOR THE OXIDATION OF HYDROGEN SULPHIDE

Field of the invention

The present invention relates to a process for the oxidation of hydrogen sulphide in a hydrogen sulphide- containing hydrocarbon feed gas to elemental sulphur. Background of the invention

A known industrial process for the conversion of hydrogen sulphide (¾S) is the so-called Claus process. In a Claus process ¾S is reacted with sulphur dioxide (SO₂) to elemental sulphur and water according to the Claus reaction.

2 H₂S + S0₂ <=> 2 H₂0 + 3/n S (1)

Conventionally, this reaction is performed in several stages at temperatures in the range of from 200 to 350°C and at near atmospheric pressures. The elemental sulphur obtained polymerizes at these conditions.

¾S is typically obtained as part of a larger volume of hydrocarbon feed gas, such as natural gas. In many conventional Claus processes, ¾S is first separated from a hydrocarbon gas stream, e.g. by a solvent extraction process. After solvent regeneration, a ¾S-rich gas is obtained at low pressure (typically about 1 to 2 bara) which is dealt with in the Claus process. About one third of the ¾S in this gas is oxidized with air to SO₂ in a burner, according to:

2 H₂S + 3 0₂ => 2 H₂0 + 2 S0₂ (2) The S O2 subsequently reacts with the remaining ¾S to elemental sulphur according to reaction (1) .

Reaction (2) is typically performed at temperatures in the range of from 950 to 1450°C, preferably 1000 to 1200°C, and at pressures in the range of from 1 to 2 bar.

Reaction (2) is an exothermic reaction.

A known, more recent process for the oxidation of ¾S in an H2 S-containing feed gas to elemental sulphur is disclosed in W02010 /060970 , the teaching of which is hereby incorporated by reference. In a process as

disclosed in W02010 /060970 , there is - unlike many conventional Claus processes - no need to first separate ¾S from an H2 S-containing hydrocarbon feed gas. In a catalytic zone, under specific conditions, hydrogen sulphide and sulphur dioxide can be reacted in the presence of hydrocarbons to form elemental sulphur according to reaction (1).

A disadvantage of this known process is that a part of the formed elemental sulphur is incinerated to

generate S O2 . This S O2 is recycled to the catalytic zone in which elemental sulphur is formed according to

reaction (1) . This generation of S O2 requires a large incinerator, and thus significant CAPEX.

Another disadvantage of the process according to W02010 /060970 is related to the natural gas sales

specifications. The potential buyers of natural gas often desire a level of less than 4 ppm ¾S. To achieve such low ¾S levels, further ¾S separation technology needs to be used after the process according to WO2010/060970.

It is an object of the present invention to provide a process for the oxidation of ¾S in an H2 S-containing hydrocarbon feed gas to elemental sulphur with no or minimized incineration of elemental sulphur to generate S O2 to be used in the Claus reaction.

It is a further object of the present invention to provide an alternative process for the oxidation of ¾S in an H2 S-containing hydrocarbon feed gas to elemental sulphur .

Summary of the invention

It has now been found that one or more of the above or other objects can be achieved by providing a process for the oxidation of hydrogen sulphide (¾S) in an ¾S- containing hydrocarbon feed gas to elemental sulphur, the process at least comprising the steps of:

(a) providing a H2 S-containing hydrocarbon feed gas, the hydrocarbon feed gas comprising in the range of from 10 to 99.9 vol% of hydrocarbons;

(b) supplying the H2 S-containing hydrocarbon feed gas as provided in step (a) and a sulphur dioxide ( S O2 ) - containing gas to a reaction zone comprising at least one catalytic zone comprising a catalyst;

(c) contacting the H2 S-containing hydrocarbon feed gas comprising in the range of from 10 to 99.9 vol% of hydrocarbons and the S 02-containing gas as supplied in step (b) with a catalyst in the at least one catalytic zone,

the temperature in the catalytic zone being in the range of from 120 to 200°C, and the pressure in the catalytic zone being in the range of from 4 to 200 bara,

thereby forming elemental sulphur which is essentially in liquid form;

(d) removing a stream containing the elemental sulphur and a first ¾S-depleted gaseous stream from the

catalytic zone; (e) separating the first H2 S-depleted gaseous stream as obtained in step (d) thereby obtaining a concentrated H2 S-containing gaseous stream and a second ¾S-depleted gaseous stream;

(f) incinerating the concentrated H2 S-containing gaseous stream obtained in step (e) thereby obtaining a S O2 - containing stream; and

(g) using at least a part of the S 02-containing stream obtained in step (f) as the S 02-containing gas supplied in step (b) .

The process of the present invention maintained the advantages found for a process according to

W02010 /060970. The process according to the invention is suitable for the deep desulphurisation of gaseous

hydrocarbon streams with a relatively high hydrogen sulphide content, i.e. above 0.5 vol% and up to 25- 50 vol%. The process according to the invention does not require the separation of hydrogen sulphide or mercaptans from the hydrocarbon-comprising feed, such as in

conventional Claus processes. And in the process the oxidation of the liquid sulphur by the oxidant is

prevented. Furthermore, by ensuring that the sulphur formed is in a liquid form the catalyst remains

accessible to the reactants and clogging of the catalyst or catalyst pores is prevented. And the process according to the invention can be performed as a continuous

process. Further, hydrogen sulphide containing gas can be processed at the pressure at which it is produced or at which it becomes available. Natural gas can for example be processed at the pressure at which it is produced at the well and effluents from a hydroprocessing or

gasification unit can be processed without depressurizing them. Additionally, the process of the present invention has the following advantages.

It has surprisingly been found that the process according to the present invention results in decreased CAPEX as compared to a process according to

W02010 /060970. No additional production and separate incineration of sulphur for producing S O2 is needed for reaction (1) in the catalytic zone. The process can be performed without a large sulphur incinerator as needed in a process according to W02010 /060970. Although the generation of S O2 by incineration of elemental sulphur is still possible according to the present invention, it is preferred that only a small amount of elemental sulphur, or no elemental sulphur, is incinerated for the

generation of S O2 for the Claus process.

A further advantage of the process according to the present invention is that the risk of S O2 slip-through (into the first ¾S-depleted gaseous stream) as compared to a process according to W02010 /060970 is avoided or at least minimized.

An even further advantage of the process according to the present invention is that the catalyst in the at least one catalytic zone has an expected longer service life as compared to a process according to W02010 /060970 , due to suppressed sulfation as a result of H2 S-rich operation in the catalytic zone. Sulfation is a known cause for deactivation of catalysts.

Another advantage is related to the natural gas sales specifications. With the process of the present invention it is possible to achieve very low levels of ¾S, e.g. less than 4 ppm ¾S, in natural gas with less extra ¾S separation technology as compared to a process according to WO2010/060970. A further advantage of the process according to the invention is that it is suited for the treatment of hydrocarbon feeds which comprise a relatively large amount of gasses that do not participate in the sulphur recovery reactions, such as carbon dioxide, as compared to the amount of hydrogen sulphide. There is no need to reduce the amount of such ^xinert' gasses before the reaction to elemental sulphur takes place.

Furthermore, in the process according to the

invention ¾S is oxidized to sulphur according to

exothermic reaction (1) . Compounds other than ¾S, such as hydrocarbons or hydrogen, are not or hardly oxidized. This has the advantages that:

(i) there is no need to separate ¾S from the other gas components, such as in conventional Claus processes; and

(ii) the reaction can occur at higher pressures (e.g. 4 - 200 bara, preferably 10 - 150 bara) as compared to conventional Claus processes, thereby allowing higher capacity for a given reactor volume and ensuring that the first ¾S-depleted gaseous stream maintains a high pressure .

The process according to the invention can be

operated continuously without the need to regularly regenerate the catalyst, contrary to prior art processes that require periodical regeneration of the catalyst

(e.g. by removing sulphur from the catalyst pores) .

The present invention can be used to oxidize ¾S from various gaseous streams, for example light hydrocarbons, such as methane, ethane, propane, and gases derived from such light hydrocarbons; natural gas; gases derived from tar sand and shale oils; and gases associated with crude oil production. Brief Description of the Drawings

Fig. 1 schematically a process scheme for performing the method according to the present invention;

Fig. 2 schematically a further process scheme for performing the method according to the present invention wherein the elemental sulphur and first ¾S-depleted gaseous stream are removed from the catalytic zone as separate streams; and

Fig. 3 schematically an even further embodiment of a process scheme for performing the method according to the present invention, wherein two catalytic zones 3A and 3B are used.

Detailed description of the invention

The present invention provides a process for the oxidation of hydrogen sulphide (¾S) in an H2 S-containing hydrocarbon feed gas to elemental sulphur, the process at least comprising the steps of:

the temperature in the catalytic zone being in the range of from 120 to 200°C, and the pressure in the catalytic zone being in the range of from 4 to 200 bara, thereby forming elemental sulphur which is essentially in liquid form;

catalytic zone;

(e) separating the first ¾S-depleted gaseous stream as obtained in step (d) thereby obtaining a concentrated H2 S-containing gaseous stream and a second ¾S-depleted gaseous stream;

Step (a)

In step (a) , an H2 S-containing hydrocarbon feed gas is provided. The H2 S-containing hydrocarbon feed gas typically comprises - in addition to ¾S and hydrocarbons - one or more of molecular hydrogen (¾) , carbon monoxide

(CO) , nitrogen, carbon dioxide, argon, helium or other inert gases.

The H2 S-containing hydrocarbon feed gas comprises in the range of from 10 to 99.9 vol% of hydrocarbons.

Preferably, the H2 S-containing hydrocarbon feed gas comprises at least 25 vol%, even more preferably at least 40 vol% of hydrocarbons, based on the total volume of the H2 S-containing feed gas. More preferably, the ¾S- containing feed gas comprises in the range of from 40 to 99.5 vol%, even more preferably below 99 vol% of

hydrocarbons .

The H2 S-comprising feed gas may comprise other sulphur compounds such as mercaptans, typically in the range of from 1 ppmv to 5 vol% (based on the total volume of the feed gas), COS, typically in the range of from 0.1 to 5000 ppmv (based on the total volume of the feed gas) , more typically from 0.1 to 2500 ppmv, and/or C S 2 .

Preferably, the H2 S-containing feed gas provided in step (a) comprises from 0.1 to 50 vol% ¾S based on the total volume of the H2 S-containing feed gas, preferably at least 0.5 vol% and preferably at most 30 vol~6 , more preferably at most 25 vol%.

Further, the H2 S-containing feed gas provided in step

(a) may comprise from 0.1 to 89 vol% CO2 based on the total volume of the H2 S-containing feed gas, preferably in the range of from 1.0 to 50 vol%, more preferably in the range of from 1.0 to 30 vol%.

Step (b)

In step (b) , the H2 S-containing hydrocarbon feed gas as provided in step (a) and a S 02-containing gas are supplied to a reaction zone comprising at least one catalytic zone comprising a catalyst.

Preferably, the combined H2 S-containing hydrocarbon feed gas and the S 02-containing gas supplied to the reaction zone comprise no more than 20 mol% water, preferably no more than 10 mol%, more preferably no more than 7.0 mol%. Water is one of the reaction products of the reaction between ¾S and S O2 and any water present in the gases supplied to the reaction zone negatively influences the equilibrium of reaction (1), by drawing the equilibrium toward the reactants side.

Preferably, the molar ratio of H₂S to S 0₂ (H₂S/ S 0₂ ) supplied to the reaction zone in step (b) is in the range of from 2.0 to 20, preferably at least 2.3, more

preferably at least 2.4 and preferably at most 10.0, more preferably at most 5.0, even more preferably at most 4.0. The catalyst as used according to the present

invention is not particularly limited and may be selected from a broad range of catalysts or combination thereof. Preferably, the catalyst is a Ti0₂-comprising catalyst. A Ti0₂-comprising catalyst typically has a high temperature stability, which is particular beneficial in case of unintended temperature rises in the reaction zone. By using a Ti0₂-comprising catalyst any COS or CS₂ present in the feed gas, the S0₂-containing gas supplied to the reaction zone or formed in the reaction zone is partly, substantially or fully converted to CO₂, water and elemental sulphur. Both COS and CS₂ are catalytically hydrolysed in the presence of the T1O₂ catalyst to CO₂ and ¾S. The ¾S is subsequently reacted with SO₂. There is no need for a separate process to remove and/or convert COS or CS₂ prior to the process according to the invention .

Step (c)

In step (c) , the H₂S-containing hydrocarbon feed gas comprising in the range of from 10 to 99.9 vol% of hydrocarbons and the S0₂~containing gas as supplied in step (b) are contacted with a catalyst in the at least one catalytic zone, thereby forming elemental sulphur. The conditions are such that the elemental sulphur formed is essentially in liquid form. The temperature in the catalytic zone is in the range of from 120 to 200°C. The pressure in the catalytic zone is in the range of from 4 to 200 bara.

The ¾S reacts with the SO₂ as shown in formula (1) . This reaction is exothermic. Most of the heat released during the reaction is transported out of the catalytic zone together with the reaction products and the ¾S depleted gas. However, in case of very high ¾S- concentrations it may be preferably to provide additional means of cooling. As one example, and as explained in WO 2010/060970, this can be achieved by using an inert liquid. Alternatively, and preferably, a gas recycle stream is used for cooling. As another alternative, the reaction zone can be cooled using a multi-tubular reactor arrangement with catalyst and process gas inside each tubular reactor and a cooling medium such as water on the outside of the tubular reactors.

The reactor configuration in which the process of the present invention is performed can comprise one or more isothermal reactors, e.g. cooled reactors, and/or one or more adiabatic reactors. It is possible to combine an isothermal reactor and an adiabatic reactor in series, or as a staged reactor.

In the process according to the present invention, elemental sulphur is formed in step (c) essentially in liquid form. According to the present invention elemental sulphur essentially in liquid form means that most of the elemental sulphur is liquid, and only a small amount is in the vapour phase at the temperature and pressure in the catalytic zone. Further, the elemental sulphur is liquid and not a gel at the temperature and pressure in the catalytic zone.

Preferably at least 70% of the elemental sulphur formed in step (c) has a dynamic viscosity below 1000 mPa-s (1000 milliPascal times second; i.e. 1000 cP

(centipoise) ; i.e. 1 N-s/m²), preferably below 500 mPa-s, even more preferably below 200 mPa-s, still more

preferably below 100 mPa-s, still more preferably below

50 mPa-s, still even more preferably below 20 mPa-s at the temperature and pressure in the catalytic zone; and the dynamic viscosity preferably is at least 0.01 mPa-s, more preferably at least 0.5 mPa-s, even more preferably at least 1 mPa-s, at the temperature and pressure in the catalytic zone.

More preferably at least 80% of the elemental sulphur formed in step (c) has a dynamic viscosity below 1000 mPa-s, preferably below 500 mPa-s, even more preferably below 200 mPa-s, still more preferably below 100 mPa-s, still more preferably below 50 mPa-s, still even more preferably below 20 mPa-s at the temperature and pressure in the catalytic zone; and the dynamic viscosity

preferably is at least 0.01 mPa-s, more preferably at least 0.5 mPa-s, even more preferably at least 1 mPa-s, at the temperature and pressure in the catalytic zone.

Most preferably at least 90% of the elemental sulphur formed in step (c) has a dynamic viscosity below 1000 mPa-s, preferably below 500 mPa-s, even more preferably below 200 mPa-s, still more preferably below 100 mPa-s, still more preferably below 50 mPa-s, still even more preferably below 20 mPa-s at the temperature and pressure in the catalytic zone; and the dynamic viscosity

In step (c) , preferably at least 70%, more preferably at least 80%, even more preferably at least 90% of the elemental sulphur in the reaction zone(s) has a dynamic viscosity below 1000 mPa-s, preferably below 500 mPa-s, even more preferably below 200 mPa-s, still more

preferably below 100 mPa-s, still more preferably below 50 mPa-s, still even more preferably below 20 mPa-s at the temperature and pressure in the catalytic zone; and the dynamic viscosity preferably is at least 0.01 mPa-s, more preferably at least 0.5 mPa-s, even more preferably at least 1 mPa · s .

By ensuring that the sulphur formed is essentially in a liquid form the catalyst remains accessible to the reactants and clogging of the catalyst or catalyst pores is prevented. Therefore, the process according to the invention may be a continuous process, contrary to many prior art processes for sulphur removal from gas stream, which require a batch wise process in order to allow for periodical regeneration of the catalyst due to sulphur deposits on the catalyst.

In the process according to the invention any mercaptans present in the feed gas to the reaction zone may be partly converted to polysulphides and ¾S. The ¾S is subsequently reacted with SO₂. There is no need to separate mercaptans from the feed gas prior to the present process.

Preferably, the H₂S-containing feed gas is contacted with the catalyst in step (c) at a normal gas hourly space velocity in the range of from 100 to 300,000

Nl/kg/h, preferably of from 200 to 20,000 Nl/kg/h.

Preferably, the H₂S-containing feed gas has a residence time in the catalytic zone in step (c) of from 1 to 3000 seconds, preferably at least 5 seconds and preferably at most 60 seconds.

The temperature in the catalytic zone is in the range of from 120 to 200°C. In this way a significant

polymerization of sulphur and the associated rise in viscosity at higher temperatures is prevented.

Preferably the temperature in the catalytic zone is at least 120°C, more preferably at least 125°C.

Preferably the temperature in the catalytic zone is at most 200°C, more preferably at most 190°C, even more preferably at most 180 °C, still more preferably at most 160 °C.

In one preferred embodiment the temperature in the catalytic zone is in the range of from 120 to 135 °C, more preferably of from 125 to 135°C. In another

preferred embodiment, where there is a relatively high H2S partial pressure, the temperature in the catalytic zone is at least 120 °C and may be up to 190 °C,

preferably up to 160 °C.

The pressure in the catalytic zone is in the range of from 4 to 200 bara, preferably from 10 to 150 bara.

Step (d)

In step (d) , a stream containing the elemental sulphur and a first ¾S-depleted gaseous stream are removed from the catalytic zone. The stream containing the elemental sulphur and the first ¾S-depleted gaseous stream are typically removed as one stream and

subsequently separated, but may also be removed as separate streams from the catalytic zone.

Preferably, the first ¾S-depleted gaseous stream obtained in step (d) contains from 15 to 45 mol% ¾S based on the amount of ¾S present in the H₂S-containing feed gas as provided in step (a) , preferably at least 20 mol%, more preferably at least 25 mol% and preferably at most 40 mol%. Typically the first ¾S-depleted gaseous stream obtained in step (d) contains from 0.1 to 15 mol%, preferably at least 0.2 mol% and preferably at most 10 mol% H₂S.

Further it is preferred that a part of the first ¾S- depleted gaseous stream obtained in step (d) is recycled and supplied to the reaction zone in step (b) . This allows for regulation of the ¾S concentration at the inlet of the reaction zone, thereby optimizing the performance of the reaction zone.

Step (e)

In step (e) , the first H₂S-depleted gaseous stream as obtained in step (d) is separated thereby obtaining a concentrated H₂S-containing gaseous stream and a second ¾S-depleted gaseous stream. The person skilled in the art will readily understand that this separation can be performed in several ways, such as using solvent

extraction. Typically, the concentrated H₂S-containing gaseous stream comprises from 5.0 to 100 mol% ¾S, preferably at least 7.0 mol%, more preferably at least 10 mol%, even more preferably at least 20 mol% and yet even more preferably at least 25 mol% ¾S. The second ¾S- depleted gaseous stream typically comprises 1-10,000 ppm

¾S, more typically at least 2 ppm, even more typically at least 3 ppm and preferably at most 200 ppm, more preferably at most 20 ppm ¾S.

The second ¾S-depleted gas stream may be further treated and is usually dried (e.g. using cooling with liquid water knock-out, molsieves or glycol dehydration) . The second ¾S-depleted gaseous stream may be further separated to provide specific hydrocarbon products, e.g. LPG, C5+, or natural gas having sales specifications, or may be further processed to produce LNG (Liquefied

Natural Gas) . Any separated LPG or C5+ may be treated with e.g. amine or caustic to remove COS and mercaptans, if any.

In one embodiment, the first ¾S-depleted gaseous stream as obtained in step (d) is treated before it is separated in step (e) .

In case at least a part or a fraction of the first ¾S-depleted gaseous stream as obtained in step (d) is treated with amine in step (e) , it is preferred to place a T1O2 bed downstream from step (d) to scavenge the remaining SO2 from the gas before the gas enters the amine reactor in which step (e) takes place. Preferably this T1O2 bed is placed before cooling equipments. The first ¾S-depleted gaseous stream as obtained in step (d) , or a part or a fraction thereof, can be sent

directly to the T1O2 bed, without any heating or cooling.

In the 1O2 bed SO2 is removed by direct reaction with H2S while the catalyst is maintained at least partially liquid free to keep a high catalytic activity until the pore volume is filled. Thereafter the gas is sent to the amine reactor in which step (e) takes place.

Step (f)

In step (f) , the concentrated H₂S-containing gaseous stream obtained in step (e) is incinerated thereby obtaining a S0₂-containing stream. If needed, additional fuel may be added. Typically, in step (f) also water is obtained; this water may be removed, if desired, but this is not required.

Preferably, the S0₂-containing stream obtained in step (f) is separated thereby obtaining a concentrated SO₂ stream (and a C0₂/ ₂-enriched stream) . Preferably, the concentrated SO₂ stream comprises at least 60 mol% SO₂, preferably at least 70 mol% SO₂, more preferably at least

80 mol% SO₂, even more preferably at least 90 mol% SO₂. Further it is preferred that the concentrated SO₂ stream is pressurized before being used as the S0₂-containing gas supplied in step (b) . Typically, the concentrated SO₂ stream is compressed to sour gas feed pressure, which is typically from 10 to 150 bara.

Step (g) In step (g) , at least a part of the S0₂-containing stream obtained in step (f) is used as the S0₂-containing gas supplied in step (b) .

Drawings

Hereinafter the invention will be further illustrated by the following non-limiting drawings. Herein shows:

For the purpose of this description, same reference numbers refer to same or similar components.

Detailed description of the drawings

Figure 1

Fig. 1 schematically shows a process scheme for the oxidation of ¾S in an H₂S-containing hydrocarbon feed gas to elemental sulphur. The process scheme is generally referred to with reference number 1.

The process scheme 1 comprises a reaction zone 2, a catalytic zone 3 (containing a fixed bed of T1O₂

oxidation catalyst), a gas/liquid-separator 4, a

separator 5, a combustor 6, a separator 7 and a

compressor 8.

In the embodiment of Figure 1 a process scheme is shown, wherein the reaction zone 2 has a single catalytic zone 3; the person skilled in the art will readily understand that two or more catalytic zones (in series or parallel) optionally with different types of reactors (such as actively cooled reactors and/or adiabatically cooled reactors) may be used (see e.g. WO 2010/060970, the teaching of which is hereby incorporated by reference and Fig. 3 hereinafter) .

During use, a H2 S-containing feed gas 10 (such as natural gas containing ¾S) is supplied to the catalytic zone 3 in reaction zone 2, together with a S 02-containing gas 20. The person skilled in the art will readily understand that the H2 S-containing feed gas 10 and S O2 - containing gas 20 may be combined before supplying to the catalytic zone 3 in reaction zone 2.

In the catalytic zone 3 the H2 S-containing feed gas 10 and the S 02-containing gas 20 are contacted with a catalyst and converted, thereby forming elemental sulphur, under such conditions that the elemental sulphur formed is essentially in liquid form. A stream 30 containing elemental sulphur and ¾S is removed from the catalytic zone 3.

In the embodiment of Fig. 1 stream 30 is separated in gas/liquid-separator 4, thereby obtaining a stream 40 enriched in elemental sulphur and a first ¾S-depleted gaseous stream 50. The stream 40 enriched in elemental sulphur is typically further treated and may subsequently be sold on the market. If desired (not shown), part of stream 40 may be recycled to the reaction zone 2.

The first ¾S-depleted gaseous stream 50 is separated in separator 5 thereby obtaining a concentrated ¾S- containing gaseous stream 60 and a second ¾S-depleted gaseous stream 70. The second ¾S-depleted gaseous stream 70 may be further treated to e.g. remove residual ¾S, mercaptans, water and other contaminants, if needed, and sent to the grid or further separated to provide specific hydrocarbon products or further processed to produce LNG (Liquefied Natural Gas) .

The concentrated H₂S-containing gaseous stream 60 is incinerated in combustor 6 (whilst adding air or oxygen stream 110, and if desired, additional fuel) thereby obtaining a S0₂-containing stream 80. The S0₂-containing stream 80 is separated in separator 7 (typically to remove SO₂ from the other component such as CO₂, ₂ and O₂) thereby obtaining a concentrated SO₂ stream 90 and a

C0₂~enriched stream 100. The concentrated SO₂ stream 90 is subsequently compressed before being used as the SO₂- containing gas 20 supplied to the catalytic zone 3.

In the embodiment of Figure 1, a part 120 of the first ¾S-depleted gaseous stream 50 is recycled and supplied to the reaction zone 2 to assist in cooling of the reaction zone. Typically, the stream 120 is

pressurized (e.g. using a compressor) before being fed to the reaction zone 2.

Figure 2

In the embodiment of Figure 2, the stream 30

containing elemental sulphur and the first ¾S-depleted gaseous stream 50 are removed as separate streams from the reaction zone 2. Stream 30 is sent to the gas/liquid- separator 4 thereby obtaining a stream 40 enriched in elemental sulphur and a H₂S-containing stream 45. If desired, part or all of stream 45 may be combined with the concentrated H₂S-containing gaseous stream 60.

Figure 3

Figure 3 shows an alternative embodiment of a process scheme for performing the method according to the present invention, wherein two catalytic zones 3A and 3B are used. As can be seen, two gas/liquid separators 4A and 4B are used (instead of one in Figure 1) . After removing stream 30A (containing elemental sulphur, gaseous ¾S and non-reacted gaseous components such as methane) from the first catalytic zone 3A, it is separated in first

gas/liquid separator 4A thereby obtaining a stream 40A enriched in elemental sulphur and a stream 35 which is passed to the second catalytic zone 3B. Stream 30 and the first ¾S-depleted gaseous stream 50 are removed as separated streams from the second catalytic zone 3B (but may, as shown in Figure 1, be removed as a single stream and subsequently be separated to generate stream 50). Stream 30 is separated in the second gas/liquid separator 4B thereby obtaining a stream 40B enriched in elemental sulphur. Streams 40A and 40B are combined to form stream 40 and may be further purified/degassed to obtain a pure sulphur product. Stream 50 is processed as discussed for Fig. 1.

The concentrated SO₂ stream 90 is pressurized before being used as the S0₂-containing gas streams 20A and 20B supplied to the catalytic zones 3A, 3B.

The person skilled in the art will readily understand that many modifications may be made without departing from the scope of the invention. As mere examples:

- The reaction zone 2 and the separator 4 may be placed inside one and the same pressure vessel;

- The temperature of the process streams 10, 20, 30, 40, 45, 50, 60, 70, 80, 90, 120 may be regulated by heating or cooling;

- The temperature and pressure of the concentrated SO₂ stream 90 may be regulated such that this stream is in liquid form to allow pumping thereof; - Coolers may be provided to cool the reaction zone 2 or parts thereof to reduce temperature increase in the reaction zone 2 ;

- Equipment (such as O2 enrichment membranes, cryogenic air separation units or the like) may be included to increase the O2 mol percentage in stream 110;

- S O2 may be injected into reaction zone 2 at multiple locations ;

- The catalytic zone 3 may be embodied in various

segments with different properties for the catalytic bed for each segment;

- Etc.

Examples

Tables 1 and 2 below show actual non-limiting examples, providing information on conditions and composition of the various streams, whilst using the process scheme and stream numbers of Figure 2, for the oxidation of ¾S in an H2 S-containing feed gas.

Table 1 shows a first embodiment wherein the feed stream contains a relatively high amount of ¾S (26.3 mol%) , whilst Table 2 shows a second embodiment wherein the feed stream contains a relatively low amount of ¾S (0.8 mol%) .

The molar H2 S / S O2 ratio supplied to the reaction zone 2 was 3.0 for the high ¾S embodiment of Table 1 and 3.0 for the low ¾S embodiment of Table 2. The normal gas hourly space velocity for feed gas stream 10 was 8000 Nl/kg/h. Further the pressure in catalytic zone was 75 bara and the temperature 130 °C. Table 1

Table 2

Stream number 10 20 50 60 70 in Figure 2

Temperature 40.7 45.0 45.0 45.0 45.0 [°C]

Pressure 72.9 1.3 72.2 1.7 72.2 [bara]

H₂S [mol%] 0.8 - 0.25 8.5 -

S0₂ [mol%] - 94.0 - - -

H₂0 [mol%] 0.1 6.0 0.65 5.4 0.1

C0₂ [mol%] 2.3 - 2.3 79.3 -

N₂ [mol%] 4.1 - 4.1 - 4.2

Hydrocarbons 92.7 92.7 6.8 95.7 [mol%]

Claims

C L A I M S

1. A process for the oxidation of hydrogen sulphide in an H₂S-containing hydrocarbon feed gas to elemental sulphur, the process at least comprising the steps of:

(a) providing a H₂S-containing hydrocarbon feed gas (10), the hydrocarbon feed gas (10) comprising in the range of from 10 to 99.9 vol% of hydrocarbons;

(b) supplying the H₂S-containing hydrocarbon feed gas (10) as provided in step (a) and a sulphur dioxide (SO₂)- containing gas (20) to a reaction zone (2) comprising at least one catalytic zone (3) comprising a catalyst;

(c) contacting the H₂S-containing hydrocarbon feed gas (10) comprising in the range of from 10 to 99.9 vol% of hydrocarbons and the S0₂-containing gas (20) as supplied in step (b) with a catalyst in the at least one catalytic zone (3) ,

the temperature in the catalytic zone (3) being in the range of from 120 to 200°C, and the pressure in the catalytic zone being in the range of from 4 to 200 bara, thereby forming elemental sulphur which is essentially in liquid form;

(d) removing a stream (30) containing the elemental sulphur and a first ¾S-depleted gaseous stream (50) from the catalytic zone (3) ;

(e) separating the first H₂S-depleted gaseous stream (50) as obtained in step (d) thereby obtaining a concentrated

H₂S-containing gaseous stream (60) and a second ¾S- depleted gaseous stream (70);

(f) incinerating the concentrated H₂S-containing gaseous stream (60) obtained in step (e) thereby obtaining a SO₂- containing stream (80); and (g) using at least a part of the S0₂-containing stream (80) obtained in step (f) as the S0₂-containing gas (20) supplied in step (b) .

2. The process according to claim 1, wherein the ¾S- containing feed gas (10) provided in step (a) comprises from 0.1 to 50 vol% ¾S based on the total volume of the H₂S-containing feed gas (10), preferably at least

0.5 vol% and preferably at most 30 vol%.

3. The process according to claim 1 or 2, wherein the H₂S-containing feed gas (10) provided in step (a)

comprises of from 25 to 99.9 vol% hydrocarbons based on the total volume of the H₂S-containing feed gas (10), preferably of from 40 to 99.5 vol%.

4. The process according to any one of the preceding claims, wherein the molar ratio of ¾S to SO2 (H2S/SO2) supplied to the reaction zone (2) in step (b) is in the range of from 2.0 to 20, preferably at least 2.3, more preferably at least 2.4 and preferably at most 10.0, more preferably at most 5.0, even more preferably at most 4.0.

5. The process according to any one of the preceding claims, wherein the catalyst is a Ti0₂-comprising

catalyst .

6. The process according to any one of the preceding claims, wherein the H₂S-containing feed gas (10) is contacted with the catalyst in step (c) at a normal gas hourly space velocity in the range of from 100 to 300,000 Nl/kg/h, preferably of from 200 to 20,000 Nl/kg/h.

7. The process according to any one of the preceding claims, wherein the H₂S-containing feed gas (10) has a residence time in the catalytic zone in step (c) of from

1 to 3000 seconds, preferably at least 5 seconds and preferably at most 60 seconds.

8. The process according to any one of the preceding claims, wherein the temperature in the catalytic zone (3) is in the range of from 120 to 190°C, preferably of from 120°C to 180°C, more preferably of from 120°C to 160°C.

9. The process according to any one of the preceding claims, wherein the pressure in the catalytic zone (3) is in the range of from 10 to 150 bara.

10. The process according to any one of the preceding claims, wherein the first ¾S-depleted gaseous stream (50) obtained in step (d) contains from 15 to 45 mol% ¾S based on the amount of ¾S present in the H2 S-containing feed gas (10) as provided in step (a), preferably at least 20 mol%, more preferably at least 25 mol% and preferably at most 40 mol%.

11. The process according to any one of the preceding claims, wherein a part (120) of the first ¾S-depleted gaseous stream (50) obtained in step (d) is recycled and supplied to the reaction zone (2) in step (b) .

12. The process according to any one of the preceding claims, wherein a part of the second ¾S-depleted gas stream (70) obtained in step (e) is dried and further separated to provide specific hydrocarbon products such as LPG, C5+, or natural gas having sales specifications, or further processed to produce LNG.

13. The process according to any one of the preceding claims, wherein the S 02-containing stream (80) obtained in step (f) is separated thereby obtaining a concentrated S0₂ stream (90) .

14. The process according to claim 13, wherein the concentrated S O2 stream (90) comprises at least 60 mol%

S O2 , preferably at least 70 mol% S O2 , more preferably at least 80 mol% S O2 , even more preferably at least 90 mol% S0₂.

15. The process according to claim 13 or 14, wherein the concentrated SO₂ stream (90) is pressurized before being used as the S0₂-containing gas (20) supplied in step (b) .