WO2006106289A1

WO2006106289A1 - Treatment of fuel gas

Info

Publication number: WO2006106289A1
Application number: PCT/GB2006/000999
Authority: WO
Inventors: Andrew Miller Cameron; Steven Rhys Graville
Original assignee: The Boc Group Plc
Priority date: 2005-04-06
Filing date: 2006-03-17
Publication date: 2006-10-12
Also published as: ZA200708547B; KR20070118690A; GB0507017D0; EP1899042A1; CN101193690A

Abstract

Fuel gas, for example coke oven gas, is treated to remove hydrogen sulfide and ammonia impurities in absorption columns (12) and (18). The absorbent is regenerated in a stripping column (32). A gas stream comprising hydrogen sulfide and ammonia passes from the stripping column to the same combustion stage or furnace (48) of a Claus plant (44). The combustion is conducted under conditions that eliminate essentially all the ammonia. The combustion is supported by a gas stream containing at least 40% by volume of oxygen. Residual amounts of sulfur dioxide and sulfur in the tail gas from the Claus plant (44) are reduced catalytically in a reactor (73) and the resulting gas recycled to the absorption column (12).

Description

TREATMENT OF FUEL GAS

This invention relates to a method of treating a fuel gas containing hydrogen sulfide impurity. One example of such a fuel gas is coke oven gas.

Industrial gases such as coke oven gas, natural gas and various artificially produced fuel gases are used in industrial plants to make useful products or are burned in suitable combustion apparatus to produce heat. These gases are mixtures of a number of different components. First, there are one or more principal combustible components, usually carbon monoxide, or hydrogen, or an aliphatic hydrocarbon such as methane; secondly one or more non-combustible components such as carbon dioxide, nitrogen and argon, and thirdly a range of impurities including hydrogen sulfide. Other impurities that may be present include ammonia, oxides of nitrogen, oxides of sulfur, hydrogen cyanide and carbonyl sulfide. In addition, there may be aromatic hydrocarbons and higher aliphatic hydrocarbons present.

The method according to the present invention relates to the treatment of a fuel gas containing both hydrogen sulfide and ammonia impurities.

US-A-4 085 199 discloses a method for desulfurising a hydrogen and hydrogen sulfide containing fuel gas without exhausting any sulfur-containing tail gas. Hydrogen sulfide is separated from the fuel gas by an absorption- desorption process using a liquid phase absorbent of hydrogen sulfide such as monoethanolamine (MEA). The hydrogen sulfide is passed to a Claus reaction zone with an approximately stoichiometric amount of sulfur dioxide. A tail gas containing sulfur compounds passes out of the Claus reaction zone. A portion of the feed gas by-passes the separation and the Claus reaction zone and is reacted with the tail gas in a catalytic hydrogenation zone. As a result, species such a sulfur dioxide, carbonyl sulfide, carbon disulfide and elemental sulfur vapours which may be present in the tail gas are reduced to hydrogen sulfide. The resulting hydrogenated tail gas is recycled to the absorption process for removal of hydrogen sulfide therefrom.

The particular example of this process which is given in US-A-4 085 199 is the desulfurisation of coke oven gas. Coke oven gas normally contains a significant amount of ammonia. But US-A-4 085 199 is silent as to the treatment of the ammonia impurity. The reason for this omission is straightforward. Ammonia is conventionally removed entirely separately from the hydrogen sulfide.

The method according to the invention enables both hydrogen sulfide and ammonia impurities to be removed from a fuel gas with the hydrogen sulfide.

According to the present invention there is provided a method of treating a feed stream of a fuel gas containing both hydrogen sulfide and ammonia as impurities, comprising extracting at least 70% of the hydrogen sulfide impurity content of the feed stream in absorbent, stripping hydrogen sulfide from so- formed hydrogen sulfide charged absorbent to form a combustible gas stream containing hydrogen sulfide, forming sulfur from the combustible gas stream and recovering the so-formed sulfur and a tail gas stream, containing residual amounts of hydrogen sulfide, sulfur vapour and sulfur dioxide, reducing the residual amounts of sulfur dioxide and sulfur vapour in the tail gas stream to hydrogen sulfide, and combining the reduced tail gas stream with the said feed stream upstream of the extraction of the hydrogen sulfide impurity, wherein the formation of the sulfur includes at least one combustion stage in which part of the hydrogen sulfide content of the combustible gas stream is burned to form sulfur dioxide which reacts with unbumt hydrogen sulfide to form sulfur vapour, characterised in that ammonia impurity is also extracted from the feed gas by absorbent, a flow of ammonia is created by stripping ammonia from so-formed ammonia-charged absorbent, the flow of ammonia is passed to the said combustion stage, and combustion of the hydrogen sulfide is carried out under conditions that eliminate essentially all the ammonia, the combustion being supported by a gas stream containing at least 40% (and preferably at least 80%) by volume of oxygen molecules.

The method according to the invention therefore eliminates the need for an entirely separate extraction and treatment of ammonia impurity from the feed stream, being able to reduce the ammonia level to less than 100 parts per million by volume, a level considered to be below that which causes a downstream formation of ammonia salts that blocks the passage of gas ultimately leading to failure of the plant in which the method is performed.

The method according to the invention is particularly suited to the treatment of coke oven gas, but may be used to treat any other fuel gas containing both hydrogen sulfide and ammonia as impurities.

In order to eliminate all the ammonia in the said combustion stage it is desirable to maintain a high flame temperature therein. If the effluent gas that leaves the said combustion stage has a temperature of at least 1300⁰C, and the configuration of the burner is such that all the ammonia is subjected to the high flame temperature, then conditions in the flame will generally favour thermal cracking of the ammonia to nitrogen and hydrogen. One particular advantage of feeding ammonia stripped from the ammonia-charged absorbent to a combustion stage of a plant for recovering sulfur from hydrogen sulfide is that the ammonia can be eliminated therein with minimal formation of oxides of nitrogen, unlike known processes in which an ammonia stream is removed and separated under oxidising conditions which lead to the formation of oxides of nitrogen.

The supply of the combustion supporting gas containing at least 40% by volume of oxygen to the combustion stage facilitates the creation of high flame temperature conditions and thermal cracking of ammonia therein. The combustion supporting gas is preferably commercially pure oxygen (i.e. oxygen containing less than 5% by volume of impurities, preferably less than 1.5% by volume of impurities, and most preferably less than one per cent of impurities) or oxygen-enriched air is preferably supplied to this combustion stage. A further advantage of using pure oxygen or oxygen-enriched air containing at least 40% by volume to support combustion in the said combustion stage is that it enables the size of the tail gas stream to be kept down. So keeping down the size of the tail gas stream is important because dilution of the fuel gas with the tail gas has the effect of reducing its calorific value. The smaller the tail gas stream, the less marked is this reduction in calorific value.

The combination of the tail gas stream with the feed stream results in the removal of residual hydrogen sulfide impurity from the tail gas thereby eliminating the need for a separate tail gas treatment plant. A further advantage of keeping down the size of the tail gas stream, the size of the hydrogen sulfide and ammonia absorption unit(s) can be kept down. Further, the size can be kept down of any equipment used for further treatment of the treated fuel gas. For example, such equipment may be desired for the washing of aromatic hydrocarbon impurities such as benzene, toluene and xylene out of the treated fuel gas. If, for example, a subsisting coke oven gas treatment plant is converted to operation by the method according to the invention it may, however, not be advantageous to replace the aromatic hydrocarbon impurity washer with a smaller one. Nonetheless, there will be opportunities to prevent the washer from acting as a restriction on the maximum attainable output of treated fuel gas.

The order in which the ammonia and hydrogen sulfide impurities are extracted from the feed stream is not critical to the method according to the invention. A single or different adsorbents may be used. Preferably most of the hydrogen sulfide is absorbed in aqueous liquid having a pH greater than 7. Preferably, most of the ammonia is absorbed in aqueous liquid having a pH of less than 7. If separate absorbents of the hydrogen sulfide and ammonia impurities are chosen, the hydrogen sulfide charged absorbent is preferably stripped separately from the ammonia charged absorbent and the resulting combustible gas stream containing hydrogen sulfide may be fed to the said combustion stage separately from the ammonia stripped from the ammonia charged absorbent or may be combined with the stripped ammonia upstream of the said combustion stage.

Preferably the recovery of the sulfur includes a plurality of stages of combustion in which part of the hydrogen sulfide content of the combustible gas stream is burned. Preferably pure oxygen or oxygen-enriched air containing at least 80% by volume of oxygen is supplied to all of the said stages of combustion.

Preferably, the reduction of the tail gas is performed over a catalyst, employing a gas mixture containing hydrogen or pure hydrogen as a reductant. The source of the reductant may be cleaned coke oven gas. The catalyst is typically of cobalt and manganese on a support and the reduction reactions are preferably carried out at a temperature in the range of 32O⁰C to 400⁰C.

Preferably, the reduced tail gas has water vapour condensed out of it, upstream of being combined with the feed gas, by indirect heat exchange with a coolant and/or by direct contact with water.

The method according to the invention will now be described by way of example with reference to the accompanying drawing which is a flow diagram schematically illustrating a plant for the treatment of coke oven gas.

The drawing is not to scale. Referring to Figure 1 , coke oven gas is withdrawn from one or more coke ovens 2 at an elevated temperature typically in the order of 1100⁰C or higher, is cooled by direct contact in a primary cooler 4 with an aqueous solution of ammonia so as to condense tars and other heavy hydrocarbons out of the gas. Some of the ammonia content of the coke oven gas may be extracted in the primary cooler 4. The uncondensed gas flows from the primary cooler 4 to an electrostatic precipitator 6 which is operated so as to remove particulate contaminants from the coke oven gas. The flow of coke oven gas is created by operation of a blower 8 located downstream of the electrostatic precipitator 6. The configuration, construction and operation of the primary cooler 4 and the electrostatic precipitator 6 are well known in the art of treating coke oven gas and need not be described further herein.

The treated coke oven gas exiting the blower 8 typically comprises hydrogen, methane, and carbon monoxide. In addition, it may contain carbon dioxide, nitrogen, gaseous hydrocarbons containing two or more carbon atoms, and a range of undesirable gaseous impurities including ammonia, hydrogen sulfide, carbonyl sulfide and typically hydrogen cyanide. In accordance with the invention, the coke oven gas is treated by scrubbing so as to remove the ammonia, hydrogen sulfide, carbonyl sulfide and hydrogen cyanide impurities. Typically, upstream of its being scrubbed, the coke oven gas passes from the blower 8 through a secondary cooler 10 in order to reduce its temperature to well below 100⁰C. The resulting cooled coke oven gas is introduced into a first absorption column 12, typically at a pressure in the range of 1.2 to 2 bar (absolute). The first absorption column 12 contains suitable members or devices (not shown) for bringing ascending gas into intimate contact with descending liquid. Typically, the first absorption column 12 contains a packing, for example a structured packing, for this purpose. A flow of absorbent is passed to one or more spray nozzles 14 situated at the top of the column 12 and issues from the nozzles 14, descending the column 12. the absorbent is typically alkaline, for example, a caustic soda solution or an aqueous solution of ammonia. Such an ammonia solution may be generated in another part of the plant, for example, the primary cooler 4. As the alkaline absorbent solution descends the column 12 so it contacts ascending coke oven gas. The alkaline absorbent solution absorbs hydrogen sulfide, hydrogen cyanide and carbon dioxide from the coke oven gas. The relative mole fractions of carbon dioxide, hydrogen cyanide and hydrogen sulfide in the coke oven gas are normally such that the water becomes progressively more acid as it descends the first absorption column 12.

Coke oven gas essentially freed of hydrogen sulfide, carbon dioxide and hydrogen cyanide impurities leaves the top of the first absorption column 12 through an outlet 16 and flows to a bottom region of a second absorption column 18. Ammonia and any traces of carbonyl sulfide present are absorbed from the coke oven gas in the second absorption column 18 by means of a neutral or acidic aqueous absorbent. Liquor from the bottom of the first absorption column 12 may be used as the absorbent in the second absorption column 18. A pump 20 is operated to withdraw liquid from the bottom of the column 12 through an outlet 22 and to pass it to one or more spray nozzles 24 at the top of the second absorption column 18. Similarly to the first absorption column 12, the second absorption column 18 contains a packing, for example a structured packing, or like means, to bring ascending gas into intimate contact with descending alkaline liquid which issues from the spray nozzles 24. As a result of the intimate contact, ammonia is progressively absorbed from the coke oven gas as it ascends the second absorption column 18. Treated coke oven gas, now essentially free of environmentally unacceptable gaseous impurities, in particular, hydrogen sulfide, ammonia and hydrogen cyanide, flows out of the second absorption column 18 through an outlet 26 at its top and may be used as a fuel for power generation or heating purposes.

The liquid at the bottom of the second absorption column 18 contains absorbed ammonia and such traces of other impurities as flow out of the first absorption column 12. This liquid is continuously withdrawn through an outlet 28 at the bottom of the second absorption column 18 by operation of a pump 30. The liquid withdrawn from the second absorption column 18 by operation of the pump 30 flows to the top of a stripping column 32. Typically, the liquid is heated to a temperature close to the boiling point of water in a further heat exchanger 34 upstream of the column 32. The stripping column 32, similarly to the. absorption ^p^mns 12 and 18, contains a packing, for example a,, structured packing, or other liquid-gas contact means to bring the liquid absorbent as it descends the column 32 into intimate contact with ascending gas or vapour so as to strip hydrogen sulfide, ammonia, carbon dioxide and hydrogen cyanide therefrom. The liquid absorbent is typically introduced into the top of the column 32 through one or more spray nozzles 36. The bottom of the stripping column 32 is provided with an internal or external boiler 38 so as to boil a part of the liquid at the bottom of the stripping column 32. The boiler 38 is typically heated by an external source of superheated steam. The vapour that is created by operation of the boiler 38 ascends the column and strips hydrogen sulfide, ammonia, carbon dioxide and hydrogen cyanide from the descending liquid. A gas stream comprising water vapour, carbon dioxide, hydrogen cyanide, ammonia and hydrogen sulfide flows out of the stripping column 32, through an outlet 40 at its top. Although the hydrogen sulfide content of the raw coke oven gas may be less than 2% by volume,- the gas that leaves the top of the stripping column 32 will contain substantially more hydrogen sulfide. Typically it contains more than 20% by volume of hydrogen sulfide. It also typically contains a similar volume of ammonia. Because this gas mixture contains hydrogen sulfide and ammonia in such proportions it is combustible.

That part of the liquid absorbent which is not boiled in the boiler 38 is typically continuously discharged from the plant shown in Figure 1 through an outlet 42. It may typically be fed to an effluent treatment plant so as to render it fit for discharge to the environment. The gas stream containing hydrogen sulfide and ammonia which is produced from the stripping column 32 is used as a feed to a Claus plant 44. If desired, it may be the sole hydrogen sulfide containing gas stream that is sent to the Claus plant 44. Alternatively, however, there may be a secondary feed of a hydrogen sulfide-containing gas stream from a separate source. The Claus plant 44 is arranged and configured so as to ensure the essentially complete elimination of all ammonia and hydrogen cyanide in the feed gas to it, the ammonia concentration being reduced to below 100 parts per million by volume. A feature of the Claus plant 44 is that it employs commercially pure oxygen (typically containing more than 99% by volume of oxygen) or oxygen- enriched air containing at least 80% by volume of oxygen to support combustion of a part of the hydrogen sulfide and ammonia and hydrogen cyanide. Unusually, no air taken directly from the atmosphere need typically be used to support combustion. By such means, it is firstly possible to create combustion conditions which prevent any ammonia passing to the catalytic stages of the Claus plant while at the same time keeping down the quantities of diluent gases in the gas stream which leaves the Claus plant to be recycled in accordance with the invention to the absorption columns 12 and 18.

Both the flow of hydrogen sulfide containing gas from the stripping column 32 and a flow of commercially pure oxygen are supplied, the latter via a pipe 45, to a burner 46 which fires either axially or tangentially into a furnace 48 forming part of the Claus plant 44. The burner is preferably formed of a corrosion-resistant ferrous alloy such as stainless steel. The burner 46 is preferably of a tip-mixed configuration, that is mixing of the combustible gas containing hydrogen sulfide, ammonia and hydrogen cyanide with the oxygen takes place downstream of the distal end of the burner 46. The burner 46 may have a configuration of passages which ensures intimate mixing of the combustible gas with the oxygen. For example, it may be of a shell-and-tube configuration (not shown) with, typically, the combustible gas being provided to the tubes and the oxygen to the shell. In another arrangement, there are two sets of tubes. One set of tubes is supplied with the combustible gas and the other set of tubes with some of the oxygen. The remainder of the oxygen is supplied to the shell. Such an arrangement may be used to ensure that an adequate temperature is created for the destruction of ammonia without causing damage to the refractory lining of the furnace 48. Typically, when pure oxygen is used to support combustion, a flame with a local region of at least 2000⁰C can be created. Such high flame temperatures promote the thermal cracking of ammonia and thus facilitate its destruction with the creation of minimum attendant oxides of nitrogen. The relative flow rates of combustible gas and oxygen to the burner 46 are such that about two thirds of the hydrogen sulfide remain unbumed. Various reactions take place within the furnace 48. Some of the hydrogen sulfide is oxidised to sulfur dioxide and water vapour. Some hydrogen sulfide cracks thermally to hydrogen and sulfur vapour. Hydrogen cyanide is fully oxidised. As stated above, some ammonia cracks thermally to nitrogen and hydrogen. There is also combustion of ammonia to form nitrogen and water vapour. Some of the sulfur dioxide that is formed by the combustion of hydrogen sulfide reacts with the residual hydrogen sulfide to form sulfur vapour and water vapour. (That is the Claus reaction.) Various other reactions may also take place in the furnace 48 such as the formation of carbon monoxide, carbon oxysulfide and carbon disulfide. An effluent gas stream flows out of the furnace 48 directly into a waste heat boiler 50 or other form of heat exchanger in which it is cooled to a temperature typically in the range of 25O⁰C to 400⁰C. During the passage of the gas stream through the waste heat boiler 50, there is a tendency for some hydrogen to reassociate with sulfur to form hydrogen sulfide.

The cooled effluent gas stream passes from the waste heat boiler 50 to a sulfur condenser 52 in which it is further cooled to a temperature in the range of 12O⁰C to 16O⁰C and in which the sulfur vapour is condensed and is extracted via an outlet 54. The resulting liquid sulfur is typically passed to a sulfur seal pit (not shown). The resulting sulfur vapour-depleted gas stream (now typically containing only traces of sulfur vapour) is heated downstream of the sulfur condenser 52 to a temperature in the range of 25O⁰C to 35O⁰C, typically about 300⁰C, for example, by indirect heat exchange with superheated steam, or a hot gas, in a reheater 56.

The thus reheated sulfur vapour depleted gas stream flows into a first catalytic Claus reactor 60. The first catalytic Claus reactor 60 comprises at least one conventional catalyst of the Claus reaction, that is the reaction between hydrogen sulfide and sulfur dioxide to form sulfur vapour and water vapour. Typically, the catalyst is activated alumina, titanium dioxide or bauxite. Most of the sulfur dioxide content of the sulfur vapour-depleted gas stream reacts over this catalyst to form sulfur vapour and water vapour. The reaction does not go to completion, however, and therefore at least one further catalytic stage of Claus reaction is performed. First, however, the gas flowing from the first catalytic Claus reactor 60 flows to another sulfur condenser 62 in which the gas stream is cooled to a temperature in the range of 12O⁰C to 16O⁰C and in which the sulfur vapour is condensed. The condensate is extracted from the condenser 62 through an outlet 64 leading to a sulfur seal pit (not shown). The resulting sulfur vapour-depleted gas stream (now typically containing only traces of sulfur vapour) is reheated downstream of the condenser 62 to a temperature in the range of 25O⁰C to 35O⁰C, typically about 300⁰C, by indirect heat exchange with, for example, superheated steam or a hot gas in a >■-^■■•* reheater 66. The thus reheated sulfur vapour-depleted gas stream flows into a second catalytic Claus reactor 68. The second catalytic Claus reactor 68 is similar in all essential respects to the first catalytic Claus reactor 60. Most of the remaining sulfur dioxide reacts with hydrogen sulfide over the catalyst to form sulfur vapour and water vapour. The resulting gas mixture leaves the second catalytic Claus reactor 68 and passes into a yet further sulfur condenser 70 in which it is cooled to a temperature in the range of 12O⁰C to 16O⁰C so as to condense its sulfur vapour content. The sulfur vapour content is extracted via an outlet 72 and flows to a sulfur seal pit (not shown). The resulting gas stream still contains a small amount of sulfur dioxide and may also contain traces of carbon disulfide, carbon oxysulfide and sulfur vapour. In order to convert these compounds to hydrogen sulfide, the resulting gas stream is reheated in a reheater 71 and is reduced at a temperature of approximately 35O⁰C over a suitable catalyst in reactor 73, typically a supported cobalt-molybdenum catalyst, employing hydrogen as the reducing agent. Normally the resulting gas mixture contains sufficient hydrogen for this purpose. If desired, however, an external source of hydrogen may be employed, for example, a hydrogen generator. The reduced gas stream then has most (typically at least 85% by volume) of its water content removed by passage through a condenser 74, in which it is cooled typically to a temperature in the range of 5O⁰C to 95⁰C. The condenser 74 is preferably direct contact column in which the reduced gas stream is contacted with a flow of water. An indirect heat exchanger can alternatively be used. The composition of the gas stream exiting the condenser on a dry basis is typically in the range of 4-8% H₂ ; 40-70% N₂; 22-45% CO₂; and 4-7% H₂S (all percentages by volume). The precise amount of water vapour present depends on the exit temperature of the reduced gas stream from the condenser 74. Downstream of the condenser 74, the gas stream is combined with the cooled coke oven gas stream. This combination takes place at a location downstream of the secondary cooler 10 but upstream of the inlet for the coke oven gas to the absorption column 12. The size of the gas stream recycled from the Claus plant 44 is limited by the fact that oxygen-enriched air containing at least 40% by volume of oxygen or essentially pure oxygen is used to support combustion therein. Accordingly, the treated coke oven gas has an acceptable calorific value.

Various modifications may be made to the plant shown in Figure 1 according to the composition of the gas evolved from the stripping column 32. If the proportion of combustible species in this gas is too high, then combustion of one third of its hydrogen sulfide content in the furnace 48 may lead to the creation therein of temperatures high enough to damage its refractory lining. In this case, the combustion may take place in two thermal stages, significantly less than one third of the hydrogen sulfide content of the gas taking place in the furnace 48. Thus, a second furnace may be utilised downstream of the sulfur condenser 52. The operation of the second furnace is analogous to that of the furnace 48 and a total of about one third of the hydrogen sulfide content of the gas evolved from the stripping column 32 may be fully oxidised to sulfur dioxide in the two furnaces. It is still important, however, to ensure that an adequate temperature is maintained in the furnace 48 to ensure destruction of ammonia and preferably all the ammonia is destroyed in the furnace 48 with none entering the second furnace. In an alternative modification, rather than providing a discrete second furnace (with attendant waste heat boiler and sulfur condenser), the waste heat boiler 50 may be made with two passes communicating with one another via a chamber into which further oxygen is supplied. The temperature intermediate the two passes is sufficient for autogenous combustion of some of the residual hydrogen sulfide to take place in the chamber and for resulting sulfur dioxide to react with residual hydrogen sulfide to form further sulfur vapour. In this way, the advantage of having two discrete hydrogen sulfide combustion regions can be obtained with minimal additional equipment, an additional burner and sulfur condenser, in particular, being avoided. The or each furnace may be operated with an effluent gas outlet temperature in the range of 1300⁰C to 1600⁰C. If the gas which supports combustion in the furnace is a combination of commercially pure oxygen and air, the temperature may be controlled by adjusting the relative proportions of air and commercially pure oxygen.

In a further modification the acid gas stripped from the liquid absorbent may be heated to above its dew point, typically to at least 1O⁰C thereabove, and maintained at such temperature, e.g. by one of a thermally insulated and/or heated pipeline upstream of the Claus plant, so as to prevent condensation.

It is desirable that the Claus plant 44 be able to convert at least 95% of the incoming hydrogen sulfide to sulfur. The degree of conversion achieved in each catalytic Claus stage depends in part on the concentration of the hydrogen sulfide over the catalyst. Various changes, improvements and modifications may be made to the absorption of impurities from the coke oven gas and their subsequent stripping from absorbent. For example, if the pH is appropriately controlled therein, a single absorption column can perform the functions of the columns 12 and 18. In another modification the gas-charged liquid from the absorption column 12 is stripped separately from the gas-charged liquid from the absorption column 18. An advantage of such separate stripping is that the amount of residual hydrogen sulfide and ammonia retained in the absorbents can be minimised, thereby facilitating downstream waste water treatment. Stripping of the hydrogen sulfide is facilitated by acidifying the gas-loaded absorbents (e.g. by means of dilute sulfuric acid) and stripping of the ammonia is facilitated by rendering the gas-loaded absorbent more alkaline (e.g. by means of caustic soda). In a further alternative modification a selective absorbent of hydrogen sulfide may be employed. Preferred selective absorbents include alkanolamines, particularly ethanolamines. Monoethanolamine is particularly preferred. If such a selective absorbent is employed, it is preferable to remove upstream ammonia from the gas stream.

In summary, the plant shown in the drawing is able to remove ammonia, hydrogen sulfide and hydrogen cyanide impurities from coke oven gas. It therefore makes possible a considerable simplification in the conventional purification plant in which the ammonia is dealt with entirely separately from the hydrogen sulfide.

Claims

1. A method of treating a feed stream of a fuel gas containing both hydrogen sulfide and ammonia as impurities, comprising extracting at least 70% of the hydrogen sulfide impurity content of the feed stream in absorbent, stripping hydrogen sulfide from so-formed hydrogen sulfide charged absorbent to form a combustible gas stream containing hydrogen sulfide, forming sulfur from the combustible gas stream and recovering the so-formed sulfur and a tail gas stream containing residual amounts of hydrogen sulfide, sulfur vapour and sulfur dioxide, reducing the residual amounts of sulfur dioxide and sulfur vapour in the tail gas stream to hydrogen sulfide, and combining the reduced tail gas stream with the said feed stream upstream of the extraction of the hydrogen sulfide impurity, wherein the formation of the sulfur includes at least one combustion stage in which part of the hydrogen sulfide content of the combustible gas stream is burned, characterised in that ammonia impurity is also extracted from the feed gas by absorbent, a flow of ammonia is created by stripping ammonia from so-formed ammonia-charged absorbent, the flow of ammonia is passed to the said combustion stage, and the combustion of the hydrogen sulfide is carried out under conditions that eliminate essentially all the ammonia, the combustion being supported by a gas stream containing at least 40% by volume of oxygen.

2. A method as claimed in claim 1 , in which effluent gas leaves the said combustion stage at a temperature of at least 1300⁰C.

3. A method as claimed in claim 1 or claim 2, in which oxygen-enriched air containing at least 50% by volume of oxygen or pure oxygen is supplied to the said combustion stage and a hot flame zone is created therein, ammonia cracking thermally in the hot flame zone, the effluent gas from the combustion stage being essentially free of oxides of nitrogen.

4. A method as claimed in any one of the preceding claims, in which the extraction of the ammonia is performed downstream of the extraction of the hydrogen sulfide.

5. A method as claimed in any one of the preceding claims, in which the ammonia is absorbed separately from the hydrogen sulfide

6. A method as claimed in claim 5, in which the hydrogen sulfide charged absorbent is stripped separately from the ammonia charged absorbent.

7. A method as claimed in any one of the preceding claims, in which the recovery of the sulfur includes a plurality of stages of combustion in each of which part of the hydrogen sulfide content of the combustible gas stream is burned.

8. A method as claimed in claim 7, in which pure oxygen or oxygen- enriched air containing at least 80% by volume of oxygen is supplied to all of the said stages of combustion.

9. A method as claimed in any one of the preceding claims, in which the feed gas is coke oven gas.

10. A method as claimed in any one of the preceding claims, wherein the reduction of the tail gas is performed over a catalyst, employing hydrogen as a reductant.

11. A method as claimed in any one of the preceding claims, wherein the reduced tail gas, upstream of being combined with the feed gas, has water condensed out of it.

12. A method as claimed in claim 11 , wherein the condensation is performed by direct contact with water.