WO2009027494A2

WO2009027494A2 - Method for treating a gaseous hydrocarbon stream comprising hydrogen sulphide

Info

Publication number: WO2009027494A2
Application number: PCT/EP2008/061360
Authority: WO
Inventors: Jeroen Van De Rijt
Original assignee: Shell Internationale Research Maatschappij B.V.
Priority date: 2007-08-30
Filing date: 2008-08-29
Publication date: 2009-03-05
Also published as: WO2009027494A3

Abstract

The present invention provides a method of treating a gaseous stream (5, 12) comprising hydrogen sulphide, the method at least comprising the steps of: (a)oxidising hydrogen sulphide in the gaseous stream (5) to provide atreated gaseous stream containing sulphur dioxide and water as a flue gas stream (46); (b)heat exchanging the flue gas stream (22) with one or more water streams (32) to provide one or more steam streams (34) and a cooled flue gas stream (36); and (c)using the one or more steam streams (34) to drive one or more steam turbines (80, 90).

Description

METHOD AND APPARATUS FOR TREATING A GASEOUS HYDROCARBON STREAM COMPRISING HYDROGEN SULPHIDE

The present invention relates to a method of treating a gaseous stream comprising hydrogen sulphide, particularly a hydrogen sulphide containing gaseous stream derived from natural gas or crude oil. The method is particularly useful when combined with a Claus unit, for instance in a natural gas treatment plant, a refinery, synthesis gas manufacturing plant, or other chemical process plant.

The power and heat requirements of a process plant are related to the specific configuration of the plant and ambient conditions.

It is desirable to reduce the amount of hydrogen sulphide in a gaseous stream, such as a gaseous stream derived from natural gas and/or crude oil, for a number of reasons. Sulphur-containing compounds, such as hydrogen sulphide and oxides of sulphur, are controlled by emission standards in many countries. Furthermore, especially hydrogen sulphide can cause erosion of equipment. It is therefore desirable to remove hydrogen sulphide from gaseous streams, such as hydrocarbon streams, for example natural gas streams and/or crude oil .

In addition, hydrogen sulphide provides a valuable source of elemental sulphur. Hydrogen sulphide is often found in natural gas and from by-product gases derived from the refining of crude oil and other industrial processes .

The Claus process is frequently used for the treatment of hydrogen sulphide recovered from various gas streams, such as hydrocarbon streams, for example natural gas. The multi-step process produces sulphur from gaseous hydrogen sulphide.

The Claus process comprises two steps, a first thermal step and a second catalytic step. In the first thermal step, a portion of the hydrogen-sulphide in the gas is oxidised at temperatures above 850 °C to produce sulphur dioxide and water:

2H₂S + 3O₂ → 2SO₂ + 2H₂O (I) In the second catalytic step, the sulphur dioxide produced in the thermal step reacts with hydrogen sulphide to produce sulphur and water:

2SO₂ + 4H₂S → 6S + 4H₂O (II)

The gaseous elemental sulphur produced in step (II) can be recovered in a condenser, initially as liquid sulphur before further cooling to provide solid elemental sulphur. In some cases, the second catalytic step and sulphur condensing step can be repeated more than once, typically up to three times to improve the recovery of elemental sulphur.

The second catalytic step of the Claus process requires sulphur dioxide, one of the products of reaction (I). However, hydrogen sulphide is also required. Typically approximately one third of the hydrogen sulphide gas is oxidised to sulphur dioxide in reaction (I), in order to obtain the desired 1:2 molar ratio of sulphur dioxide to hydrogen sulphide for reaction to produce sulphur in the catalytic step (reaction (II)). The residual off-gases from the Claus process may contain combustible components and sulphur- containing compounds, for instance when there is an excess or deficiency of oxygen (and resultant overproduction or underproduction of sulphur dioxide) . Such combustible components can be further processed, suitably in a Claus off-gas treating unit, for instance in a Shell Claus Off-gas Treating (SCOT) unit.

The overall reaction for the Claus process can therefore be written as:

2H₂S + O₂ → 2S + 2H₂O (III)

It is an object of the invention to improve a method of treating a gaseous stream comprising hydrogen sulphide . It is a further object of the invention to provide a method of treating a gaseous stream comprising hydrogen sulphide which can be used to generate power for use in the treatment process or elsewhere.

To this end, the invention provides a method of treating a gaseous stream (5, 12) comprising hydrogen sulphide, the method at least comprising the steps of: (a) oxidising hydrogen sulphide in the gaseous stream (5) to provide a treated gaseous stream containing sulphur dioxide and water as a flue gas stream (46); (b) heat exchanging the flue gas stream (22) with one or more water streams (32) to provide one or more steam streams (34) and a cooled flue gas stream (36); and (c) using the one or more steam streams (34) to drive one or more steam turbines (80, 90) . It has been found that by using this method sufficient power may be generated to supply the needs of an entire natural gas treatment plant. For instance, heat exchanging the various treated gaseous streams against water streams as described herein can provide 1550 ton/hr steam, which can be used to drive steam turbines to provide approximately 200 MW power. - A -

In addition, the method described herein can be used for the cogeneration of power and heat, wherein the heat can be extracted as steam from the stream turbines.

Furthermore, by providing power from a source other than fuel gas, carbon dioxide emissions are reduced because the quantity of fuel gas burned to generate power in the plant is minimised. In some cases the need for fuel gas can be eliminated entirely.

In a further aspect, the present invention provides an apparatus for treating a gaseous hydrocarbon stream comprising hydrogen sulphide, the apparatus at least comprising : a combustion chamber having a first inlet for a gaseous stream comprising hydrogen sulphide, and an outlet for a treated gaseous stream as a flue gas stream, the outlet for the flue gas stream connected to the first inlet of a first heat exchanger, the first heat exchanger having a second inlet for a first water stream, a first outlet for a cooled flue gas stream and a second outlet for a first steam stream, the second outlet for the first steam stream connected downstream to the inlet of a steam turbine.

Hereinafter the invention will be further illustrated by the following non-limiting drawing. Figure 1 schematically shows a process scheme in accordance with an embodiment of the present invention.

For the purposes of this description, a single reference number will be assigned to a line as well as a stream carried in that line. Same reference numbers refer to similar components.

The method of treating the gaseous stream comprising hydrogen sulphide disclosed herein advantageously provides power to the treatment plant. In this way, the thermal energy released during the treatment of hydrogen sulphide can be harnessed to power a turbine, reducing plant running costs, particularly by minimising the quantity of fuel gas used to generate power in the plant. Hydrogen sulphide-containing gaseous streams are commonly hydrocarbon streams, for instance natural gas streams. Natural gas is comprised substantially of methane, normally greater than 50 mole%, typically greater than 70 mol% methane. Depending on the source, the natural gas may contain varying amounts of hydrocarbons heavier than methane such as ethane, propane, butanes and pentanes as well as some aromatic hydrocarbons. The natural gas may also contain various amounts of hydrogen sulphide. For instance, some natural gas fields contain natural gas having 15-30%, typically 21-26% hydrogen sulphide by volume. The gas may also contain other non-hydrocarbon impurities such as H2O, N2,

CO2 and the like.

The impurity content of extracted natural gas has tended to gradually increase over time in association with the decreasing availability of good quality of natural gas. In addition, environmental legislation is becoming stricter in terms of the impurity content of burned gases. As a result, it is becoming increasingly necessary to treat the natural gas to remove the impurity gases therefrom in order to produce a product gas having a desired specification.

There are known methods for separating a gaseous stream comprising hydrogen sulphide from a gaseous hydrocarbon stream, such as natural gas, to provide a gaseous stream comprising hydrogen sulphide and purified natural gas . Step (a) of the method of treating described herein oxidises hydrogen sulphide in the gaseous stream to provide a treated stream as a flue gas stream. Upon oxidation, a flue gas comprising sulphur dioxide and water is obtained, as shown in reaction (I) above. Step (a) may optionally produce gaseous elemental sulphur in addition to sulphur dioxide and water, for instance when the amount of oxygen supplied is insufficient to oxidise all of the hydrogen sulphide. The oxidising reaction can be carried out in the thermal zone of a Claus unit.

In a further embodiment, the flue gas stream comprising sulphur dioxide and water can be reacted with hydrogen sulphide to provide a gaseous elemental sulphur and water stream as shown in reaction (II) above. This reaction is typically carried out in the presence of a catalyst such as activated alumina or titanium dioxide. This reaction can be carried out in the catalyst zone of a Claus unit.

The hydrogen sulphide for reaction with the sulphur dioxide in the flue gas can be obtained either from the gaseous stream comprising hydrogen sulphide to be treated, or from another source different from the gaseous stream to be treated. In the former case, a part of the gaseous stream to be treated can be drawn off prior to oxidising step (a) and passed to the flue gas stream provided by the oxidation, before reaction (II). Alternatively, insufficient oxygen can be provided to the gaseous stream in oxidising step (a) , such that only a part of the hydrogen sulphide is oxidised. This is known as "straight-through operation". In these ways, hydrogen sulphide can be provided to react with the sulphur dioxide in the flue gas stream to produce elemental sulphur and water. The molar ratio of sulphur dioxide in the flue gas stream to hydrogen sulphide can be approximately 1:2 in order to provide the ratio of reactants required in reaction (II) above.

In another embodiment, the gaseous elemental sulphur and water stream produced from the reaction of the sulphur dioxide in the flue gas with hydrogen sulphide can be condensed to provide a liquid sulphur stream.

Step (b) of the method of treating described herein heat exchanges the flue gas stream with one or more water streams to provide one or more steam streams and a cooled flue gas stream. In one embodiment, the heat exchange can be carried out against the flue gas to provide a first steam stream. This process can be carried out in the waste heat boiler of a Claus unit to produce a saturated steam stream.

The saturated steam stream provided in the heat exchange can be at any pressure. Typically, the upper pressure limit is fixed by (i) the thermal and mechanical limits of the waste heat boiler, which determine the maximum pressure difference between the shell and tube sides of the boiler and (ii) the required exit temperature of the cooled flue gas, which should always be higher than the boiling temperature of the water in the shell-side of the waste heat boiler in order to drive the heat transfer. The saturated steam may have a pressure in the range of 3-55 bar. Generally, the higher the pressure of the steam generation, the higher the amount of power that can be produced from it. Thus there is an incentive to design the waste heat boiler with respect to constraints (i) and (ii) such to allow for a very high pressure.

The amount of heat recovered and steam generated in a Claus waste beat boiler has a direct relationship with the amount of hydrogen sulphide oxidised. Each kilogram of hydrogen sulphide generates approximately 15 200 kJ of heat. A flow rate of 1150 tonnes/hr of saturated steam at 45 bara may be provided by a Claus waste heat boiler, which can generate 150 MW power in steam turbines.

In a further embodiment, a second heat exchange can be carried out against the gaseous elemental sulphur and water stream provided by the reaction of hydrogen sulphide with the sulphur dioxide in the flue gas (reaction (II) above) . The second heat exchange may be carried out in a condenser to provide at a second steam stream, a condensed sulphur stream and an off-gas stream. The second steam stream can be a saturated steam stream. If there is a second heat exchange, it is carried out in combination with the heat exchange of the one or more water streams against the flue gas stream discussed above. Such a second heat exchange may provide 400 tonnes/hr saturated steam at a pressure of 5 bara.

In a further embodiment, the off-gas stream provided by heat exchanging the gaseous elemental sulphur and water stream against a second water stream can be passed to a Claus off-gas treating unit, preferably a Shell Claus Off-gas Treating unit (SCOT) . In the Claus off-gas treating unit, the total sulphur content of the off-gas is reduced by converting any sulphur and sulphur- containing compounds to hydrogen sulphide as shown in reaction (IV) :

SO₂ + 3H₂ → H₂S + 2H₂O (IV)

The hydrogen sulphide can be removed from the stream prior to discharge into the atmosphere. The hydrogen sulphide formed in the Claus off-gas treating unit can be recycled to oxidation step (a) discussed above. The water produced can be treated by known methods . The water may be passed to one or both of the one or more water streams used in heat exchange step (b) and the second water stream which is heat exchanged against the gaseous elemental sulphur and water stream. Alternatively, the water can be used for other purposes.

In another embodiment, the one or more steam streams generated in step (b) can be combined with one or more separate steam streams prior to passing it to the steam turbine in step (c) . The one or more separate steam streams can be obtained from one or both of fired boilers and heat recovery steam generators from gas turbines or recovery of heat from any process. For example, fired boilers may provide a further 150 tonnes/hr steam at a pressure of 45 bara and a temperature of 410 °C, which can be used to generate a further 20 MW power in steam turbines .

In a further embodiment, a portion of the one or more steam streams provided in step (b) can be passed to one or more of the group selected from: a heat exchanger, live steam injectors, thermal compressors and deaerators, allowing the steam to be used within or outside the treatment plant.

In another embodiment, one or more of the steam streams provided by heat exchange may be superheated prior to passing to the steam turbine in step (c) . The superheating provides superheated steam which reduces the quantity of water droplets formed upon expansion in the steam turbine. Reducing water droplet formation reduces erosion of the turbine blades. The superheating may be carried out in any known superheater but preferably in a Claus/SCOT tail gas incinerator.

In yet another embodiment, heat may be recovered from a portion of the steam stream produced in the method described herein such that both heat and power are cogenerated. For example, heat may be recovered from the high pressure steam stream produced from the Claus waste heat boiler or the SCOT unit. Step (c) of the method of treating described herein uses one or more steam streams to drive one or more steam turbines. The steam streams used to drive the steam turbines may be saturated steam streams, or the steam streams may be superheated. The steam turbines may be selected from the group consisting of: backpressure turbines, condensing turbines, backpressure/condensing turbines, condensing/extracting turbines, condensing/admission turbines, and condensing/extraction/admission turbines. In another embodiment, the steam turbines may be used to drive one or more of the group consisting of electrical generators, pumps and compressors.

In another embodiment, heat may be cogenerated with power by extracting steam from the steam turbines. The steam may be extracted at a pressure of 5 bara, and may be fed to any steam consumer (such as reboilers, live steam injection, general heat exchangers). The extraction pressure level is typically dictated by the requirements of the consumers. In one further embodiment of the apparatus described herein, the first outlet of the first heat exchanger is connected downstream to the inlet of a catalyst chamber. The catalyst chamber has an outlet for a gaseous elemental sulphur and water stream which is connected to a first inlet of a second heat exchanger. The second heat exchanger has a second inlet for a second water stream, and a first outlet for a second steam stream. The first outlet of the second heat exchanger is connected downstream to the inlet of a steam turbine.

The term "downstream" used herein means that the stream contents, in this case steam, can travel from a source, in this case the second outlet of the heat exchanger, to a destination, in this case the inlet of the steam turbine, either contiguously or via other intervening lines or streams.

In another embodiment of the apparatus described herein the second heat exchanger further comprises a second outlet for a liquid sulphur stream and a third outlet for an off-gas stream.

Figure 1 schematically shows a process scheme and apparatus (generally indicated with reference numeral 1) for the treatment of a gaseous stream 5 comprising hydrogen sulphide, such as a stream obtained from natural gas or crude oil. This method may operate in those cases where an alternative means for the generation of mechanical or electrical power is desired. The gaseous stream 5 may have been pre-heated by a heater (not shown) to a temperature of 110 °C. The gaseous feed stream 5 is split at junction point 6 into two gaseous streams, 12 and 14 respectively. Gaseous stream 12 is passed to a combustion chamber 10 via first inlet 7 and preferably carries one-third of the mass flow of gaseous stream 5. Combustion chamber 10 is preferably the thermal zone of a Claus unit. Gaseous stream 14 bypasses combustion chamber 10 and is further discussed below. Gaseous stream 14 preferably carries two-thirds of the mass flow of gaseous stream 5.

An oxygen-containing stream 16 is fed to combustion chamber 10 at second inlet 17. In this embodiment, oxygen-containing stream 16 contains sufficient oxygen to oxidise the combustible components of gaseous stream 12. Oxygen-containing stream 16 may be air, oxygen-enriched air, or pure oxygen. Oxygen-containing stream 16 may be pre-heated in one or more stages (not shown) , typically to a temperature of 300 °C.

The combustible compounds in gaseous stream 12 are oxidised in combustion chamber 10. The hydrogen sulphide in gaseous stream 12 reacts with oxygen from oxygen- containing stream 16 to form sulphur dioxide and water as shown in reaction (I) above. The oxidised gas exits combustion chamber 10 via outlet 21 as flue gas stream 22. The flue gas from the combustion chamber 10 thus comprises sulphur dioxide and water vapour. The flue gas may additionally comprise nitrogen and carbon dioxide. In an alternative embodiment termed "straight- through operation", gaseous stream 14 and junction point 6 are not present in the apparatus, such that gaseous stream 12 carries the entire mass flow from gaseous stream 5. In this case, the quantity of oxygen in the oxygen-containing stream 16 fed to combustion chamber 10 is restricted so that only approximately one-third of the hydrogen sulphide is oxidised to sulphur dioxide in accordance with reaction (I) above. In this embodiment the flue gas resulting from the oxidising step comprises (unoxidised) hydrogen sulphide, sulphur dioxide and water vapour. The flue gas may further comprise sulphur vapour, nitrogen, carbon dioxide, carbon monoxide, COS, CS2 and hydrogen. The flue gas can have a molar ratio of sulphur dioxide to unoxidised hydrogen sulphide of approximately 1:2.

In both the afore-mentioned embodiments, the flue gas from the combustion chamber 10 usually has a temperature in the range of 600 to 1650 °C and exits the combustion chamber via outlet 21 as flue gas stream 22. Flue gas stream 22 is passed to heat exchanger 20 via a first inlet 23.

Heat exchanger 20 is preferably a waste heat boiler in a Claus unit, which can be integrated with the combustion chamber 10, which preferably is the thermal zone of a Claus unit. The flue gas stream 22 is heat exchanged against a first water stream 32 obtained from a water supply grid 31. First water stream 32 is normally supplied to the shell side of heat exchanger 20 via second inlet 33. The shell-side pressure of the water is typically in the range 3 to 55 bar. The water is vaporised in heat exchanger 20 by heat exchange with the flue gas to provide a first steam stream 34 exiting heat exchanger 20 at second outlet 35. The first steam stream 34 can be a saturated steam stream, and may be passed to a high pressure saturated steam grid 62. The flue gas exits the heat exchanger 20 as cooled flue gas stream 36 via first outlet 37. Preferably the flue gas has been cooled to a temperature in the range of 170 to 200 °C.

In "straight-through operation", i.e. the arrangement in which gaseous stream 14 is omitted, cooled flue gas stream 36 exiting the heat exchanger 20 may be further cooled in a condenser 30. Cooled flue gas stream 36 is cooled to a temperature of 160 to 170 °C in order to condense and remove any elemental sulphur in the stream. Liquid sulphur is removed from condenser 30 as liquid sulphur stream 38. The flue gas exiting the condenser 30 is then passed directly to catalyst chamber 40 as stream 42. The cooling medium in condenser 30 may be water from grid 31 that evaporates into low-pressure steam (not shown) . In the arrangement in which gaseous stream 14 is present, complete oxidation of gaseous stream 12 occurs in combustion chamber 10 and there is no significant formation of sulphur in combustion chamber 10. Consequently, condenser 30 which condenses and removes elemental sulphur from the cooled flue gas stream 36 can be omitted. In this case, the cooled flue gas 36 exiting the heat exchanger 30 can be directly combined with gaseous stream 14 at junction point 44 to form a combined gaseous stream 46. Combined gaseous stream 46 comprises hydrogen sulphide from gaseous stream 5 and sulphur dioxide and water from the flue gas, which can be in an approximate molar ratio of 2:1. Combined gaseous stream 46 is passed to catalyst chamber 40 via inlet 47. Catalyst chamber 40 is preferably the catalyst zone of a Claus unit. In this zone, hydrogen sulphide and sulphur dioxide react to provide gaseous elemental sulphur and water vapour, in accordance with reaction (II) above. Catalyst chamber 40 typically contains a catalyst which catalyses the reaction between hydrogen sulphide and sulphur dioxide, such as activated alumina or titanium dioxide. The gaseous elemental sulphur and water vapour exits catalyst chamber 40 as stream 48 via outlet 49, and is passed to a second heat exchanger 50 via first inlet 51.

As will be apparent, the "straight-through operation" embodiment and the embodiment with by-pass stream 14 should both provide a gaseous hydrogen sulphide and sulphur dioxide containing stream to catalyst chamber 40 comprising the appropriate 2:1 ratio of hydrogen sulphide and sulphur dioxide for reaction to produce gaseous elemental sulphur and water vapour in accordance with reaction (II) above. Second heat exchanger 50 is preferably a condenser. The gaseous elemental sulphur and water vapour stream 48 entering second heat exchanger 50 is cooled to a temperature of 170 °C by indirect heat exchange against water supplied by a second water stream 52 via second inlet 55. Second water stream 52 is vaporised to provide second steam stream 54 which exits the heat exchanger via first outlet 57. The heat exchange condenses the elemental sulphur, which is removed from heat exchanger 50 via second outlet 53 as liquid sulphur stream 56. The residual gases from the gaseous elemental sulphur and water vapour stream 48 leave heat exchanger 50 as off-gas stream 58 via third outlet 59. The pressure of second steam stream 54 is determined by the temperature of the heat exchange. In order to have heat transfer from the gaseous elemental sulphur and water vapour stream 48 to the second water stream 52, the temperature of off-gas stream 58 must be higher than the boiling temperature of second water stream 52 in heat exchanger 50. Off-gas stream 58 may be passed to a Claus off-gas treating unit 120, preferably a SCOT unit, comprising one or more further catalyst chambers and one or more further heat exchangers in sequence, prior to passing it to incinerator 60, in order to improve elemental sulphur reclamation.

Any of the steam streams generated in the heat exchangers 30 (not shown) , 50 may be passed to a low pressure saturated steam grid 68, the pressure being dictated by the temperature of the streams 42 and 58 at the outlets of the respective heat exchangers.

Alternatively, one or more of the steam streams 34, 54 may be superheated. For example, second steam streams 34, 54 may be passed to superheater 70 as shown in Figure 1. Superheater 70 may be any superheater but is preferably a thermal incinerator for Claus/SCOT off-gas. In this case, the incinerator can use off-gas stream 58 or 88 as a feed.. The treatment of the off-gas stream in the SCOT unit

120 produces sulphur dioxide and water in accordance with reaction (IV) above. After separation by known methods, the sulphur dioxide produced can be returned to the gaseous stream 5 for oxidising in step (a) . The water produced by the SCOT unit can be treated by known methods and passed as water stream 123 exiting SCOT unit 120 at exit 124 to one or both of the one or more water streams 32 of heat exchange step (b) and the second water stream 52 which is heat exchanged against the gaseous and elemental sulphur stream. In this way, the water produced in the SCOT unit can be used to make up any losses in the steam cycle.

One or more of the steam streams 34, 54 is totally or partially fed to superheater 70 via inlet 61 respectively 77 and superheated; a portion or all of one or more of the steam streams 34, 54 may thus bypass superheater 70 as steam streams 39 and 67 respectively. The superheated steam exits superheater 70 via outlet 63 respectively 78 as superheated steam stream 66 respectively 79. In case superheater 70 is the waste heat boiler of a Claus/SCOT off-gas incinerator 60, more heat can be recovered from flue gas stream 64 than is required to superheat all steam from steam streams 34 and 54. In this case additional water may be supplied to waste heat boiler 70 to produce additional superheated or saturated steam (not shown) .

. One or both of the high pressure superheated steam stream 79 and saturated steam stream 39 can be passed to a high pressure steam grid 62 for distribution. Similarly, one or both of the low pressure superheated steam stream 66 and saturated steam stream 67 can be passed to a low pressure steam grid 68. Superheating the steam is advantageous because (i) the condensation of water droplets upon subsequent expansion is minimised, resulting in reduced erosion of expansion machinery, such as steam turbines and (ii) because condensation of water due to heat loss in the distribution system is avoided/reduced, resulting in lower risk of undesirable liquid hammer in the distribution system, as the person skilled in the art will readily understand.

The saturated or superheated steam from high pressure steam grid 62 or the superheated or saturated steam from low pressure steam grid 68 is passed to the inlets 73, 75 of one or more steam turbines 80, 90 as streams 72 and 74 respectively. The steam turbines 80, 90 can be a backpressure turbine, a condensing turbine, a condensing/extracting turbine, a condensing/admission turbine and a condensing/extraction/admission turbine.

Steam turbines 80, 90 can drive one or more of the group selected from electrical generators, pumps and compressors .

Optionally, steam may be supplied to one or more of high pressure steam grid 62 and low pressure steam grid 68 from a source other than first and second heat exchangers 20 and 50. For instance, steam produced in a fired boiler or heat recovery steam generator from a gas turbine 100, 105 could also be fed to one or more of steam grids 62 and 68 by streams 101 and 102. Steam streams 34, 54 from the heat exchanging disclosed herein, or the corresponding superheated steam streams 66 and 79, may also be combined directly with steam from another source .

In addition, steam produced by one or more of the first and second heat exchangers 20 and 50 could be passed to other steam users 110 respectively 115 such as heat exchangers, live steam injector, thermal compressors or deaerators along lines 111 and 112 as well as to steam turbines 80 respectively 90.

As an Example of the method described above, a natural gas composition comprising 21-26 volume% hydrogen sulphide and 10 volume% carbon dioxide can be treated in a natural gas treatment plant at a rate of 1290 million standard cubic feet per day. Treatment as described herein can provide approximately 1150 ton/hr saturated stream at a pressure of 45 bar absolute from a Claus waste heat boiler 20. A further 400 ton/hr saturated steam at a pressure of 5 bara can be produced from sulphur condensers 30 and 50. The 1150 t/h of saturated 45 bara steam can be superheated in Claus/SCOT off-gas incinerator waste heat boiler 70. In addition waste heat boiler 70 can produce 200 t/h of superheated steam at 45 bara and 410 °C. Fired boilers 100 can provide an additional 450 tonne/hr steam at a pressure of 45 bara and a temperature of 410 °C. Thus, in total the method described herein may produce 1800 tonne/hr steam at a temperature of 410 °C and pressure of 45 bara and 400 t/h saturated low pressure steam at a pressure of 5 bara. In order to meet the heat requirement of natural gas treatment plant at 45 bara (steam stream 111 to combined high pressure steam consumers 110), 200 t/h of steam is required, so 1600 t/h of steam is passed to condensing/extraction steam turbines 80. In order to meet the heat demand of the natural gas treatment plant at 5 bara (115) being 1600 t/h, 1200 t/h of steam is extracted from steam turbine 80 at 5 bara and combined with the 400 t/h saturated 5 bara steam of the sulphur condensers 30 and 50. In this example, the power production from condensing/extraction steam turbines 80 is approximately 230 MW.

The person skilled in the art will readily understand that many modifications may be made without departing from the scope of the invention. For example, the invention may be combined with other process units and plants (such as those in a refinery, synthesis generation or chemical plant) and form for example a part of a more complex steam and power system, the latter being generalized in blocks 80, 90, 100, 105, 110 and 115.

Claims

C L A I M S

1. A method of treating a gaseous stream (5, 12) comprising hydrogen sulphide, the method at least comprising the steps of:

(a) oxidising hydrogen sulphide in the gaseous stream (5) to provide a treated gaseous stream containing sulphur dioxide and water as a flue gas stream (46);

(b) heat exchanging the flue gas stream (22) with one or more water streams (32) to provide one or more steam streams (34) and a cooled flue gas stream (36); and (c) using the one or more steam streams (34) to drive one or more steam turbines (80, 90) .

2. The method of claim 1 further comprising:

(a) one or more steps of reacting sulphur dioxide with hydrogen sulphide to provide a gaseous elemental sulphur and water stream (48);

(b) heat exchanging on or more of the gaseous elemental sulphur and water stream (48) against one or more second water streams (52) to provide one or more second steam streams (54), condensed sulphur streams (56) and an off- gas stream (58) and

(c) using the one or more second steam streams (54) to drive one or more steam turbines

3. The method of claim 4 wherein the off-gas stream (58) is passed to a Shell Catalytic Off-gas Treating (SCOT) unit (80) to provide at least hydrogen sulphide and a liquid water stream, wherein the liquid water stream is treated to produce a clean water stream.

4. The method of claim 5 wherein further the clean water stream is passed to either the one or more water streams (32) used in heat exchange step (b) and/or the second water stream (52) which is heat exchanged against the gaseous elemental sulphur and water stream.

5. The method of any one or more of the preceding claims further comprising the step of superheating one or more of the steam streams (34, 54) prior to step (c) .

6. The method of claim 7 wherein the superheating is carried out in a superheater (70), preferably a fired incinerator for one or more of the gas streams 58, 88,.

7. The method of any one or more of the preceding claims wherein one or more of the steam streams (34, 54) provided in step (b) are at a pressure in the range of 3- 55 bar.

8. The method of any one or more of the preceding claims wherein one or more of the steam streams (34, 54) generated in step (b) are combined with one or more separate steam streams prior to step (c) .

9. The method of any one or more of the preceding claims wherein the gaseous stream is obtained from natural gas, a refinery process, a gasification process, or a chemicals process.