AU2010230280B2

AU2010230280B2 - Process for producing a purified synthesis gas stream

Info

Publication number: AU2010230280B2
Application number: AU2010230280A
Authority: AU
Inventors: Cornelis Jacobus Smit; Isaac Cornelis Van Den Born; Gijsbert Jan Van Heeringen; Alex Frederik Woldhuis
Original assignee: SHELL INT RESEARCH; Shell Internationale Research Maatschappij BV
Current assignee: Shell Internationale Research Maatschappij BV
Priority date: 2009-03-30
Filing date: 2010-03-30
Publication date: 2013-08-29
Anticipated expiration: 2030-03-30
Also published as: EP2414280A1; JP2012522089A; AU2010230280A1; CA2756372A1; WO2010112502A1; KR20120013357A; CN102378735A; US20120096770A1

Abstract

A process for producing a purified synthesis gas stream from a feed synthesis gas stream comprising besides the main constituents carbon monoxide and hydrogen also hydrogen sulphide,HCN and/or COS, the process comprising the steps of: (a) removing HCN and/or COS by contacting the feed synthesis gas stream with a water gas shift catalyst in a shift reactor in the presence of steam/waterto react at least part of the carbon monoxide tocarbon dioxide, and to obtain a synthesis gas stream depleted in HCN and/or in COS; (b) removing hydrogen sulphide in the synthesis gas stream depleted in HCN and/or in COS by contacting this gas stream in a H

Description

WO 2010/112502 PCT/EP2010/054188 PROCESS FOR PRODUCING A PURIFIED SYNTHESIS GAS STREAM The present invention relates to a process for producing a purified synthesis gas stream from a feed synthesis gas stream comprising contaminants. Synthesis gas streams are gaseous streams mainly 5 comprising carbon monoxide and hydrogen. Synthesis gas streams are generally produced via partial oxidation or steam reforming of hydrocarbons including natural gas, coal bed methane, distillate oils and residual oil, and by gasification of solid fossil fuels such as biomass or 10 coal or coke. There are many solid or very heavy (viscous) fossil fuels which may be used as feedstock for generating synthesis gas, including biomass, solid fuels such as anthracite, brown coal, bitumous coal, sub-bitumous coal, 15 lignite, petroleum coke, peat and the like, and heavy residues, e.g. hydrocarbons extracted from tar sands, residues from refineries such as residual oil fractions boiling above 360 'C, directly derived from crude oil, or from oil conversion processes such as thermal cracking, 20 catalytic cracking, hydrocracking etc. All such types of fuels have different proportions of carbon and hydrogen, as well as different substances regarded as contaminants. Depending on the feedstock used to generate synthesis gas, the synthesis gas will contain 25 contaminants such as carbon dioxide, hydrogen sulphide, carbonyl sulphide and carbonyl disulphide while also nitrogen, nitrogen-containing components (e.g. HCN and

NH

3 ), metals, metal carbonyls (especially nickel carbonyl and iron carbonyl), and in some cases mercaptans.

WO 2010/112502 PCT/EP2010/054188 -2 Purified synthesis gas can be used in catalytical chemical conversions or to generate power. A substantial portion of the world's energy supply is provided by combustion of fuels, especially natural gas or synthesis 5 gas, in a power plant. Synthesis gas is combusted with air in one or more gas turbines and the resulting gas is used to produce steam. The steam is then used to generate power. An especially suitable system for using synthesis 10 gas in power generation is the Integrated Gasification Combined Cycle (IGCC) system. IGCC systems were devised as a way to use coal as the source of fuel in a gas turbine plant. IGCC is a combination of two systems. The first system is coal gasification, which uses coal to 15 create synthesis gas. The syngas is then purified to remove contaminants. The purified synthesis gas may be used in the combustion turbine to produce electricity. The second system in IGCC is a combined-cycle, or power cycle, which is an efficient method of producing 20 electricity commercially. A combined cycle includes a combustion turbine/generator, a heat recovery steam generator (HRSG), and a steam turbine/generator. The exhaust heat from the combustion turbine may be recovered in the HRSG to produce steam. This steam then passes 25 through a steam turbine to power another generator, which produces more electricity. A combined cycle is generally more efficient than conventional power generating systems because it re-uses waste heat to produce more electricity. IGCC systems are clean and generally more 30 efficient than conventional coal plants. As set out hereinabove, when synthesis gas is used for power production, removal of contaminants is often WO 2010/112502 PCT/EP2010/054188 -3 required to avoid deposition of contaminants onto the gas turbine parts. When synthesis gas is used in catalytical chemical conversions, removal of contaminants to low levels is 5 required to prevent catalyst poisoning. Processes for producing a purified synthesis gas stream generally involve the use of expensive line-ups. For example, cold methanol may be used to remove hydrogen sulphide and carbon dioxide by physical absorption. The 10 concentrations of these contaminants in the purified synthesis gas will still be in the ppmv range. For applications where the synthesis gas is to be catalytically converted, contaminant concentrations in the ppmv range are still too high. Purifying the 15 synthesis gas streams to a higher degree using a methanol-based process would be uneconomical due to the disproportionately large amounts of energy required to regenerate the methanol. In addition, the absorbed H2S needs to be removed, usually by contacting the methanol 20 comprising H 2 S with a stripping gas at elevated temperatures, resulting in a stripping gas comprising

H

2 S. H 2 S in this stripping gas is then converted to elemental sulphur, requiring a considerable capital and operational expenditure. 25 In US 2007/0072949 a process is disclosed wherein sulphur species are removed using low-temperature amine based absorption processes, followed by a solvent regeneration Claus/SCOT process unit. The disadvantage of such a process is that it is limited to the feed gas 30 composition suitable for a Claus process, which is rather high in hydrogen sulphide concentration. It is an object of the present invention to provide an optimised process for purification of a synthesis gas 4 stream derived from a range of carbonaceous fuels, such that the purified synthesis gas is suitable for further use, especially for power production. It has now been found that by removing H 2 S directly 5 from the feed synthesis gas stream, this object can be achieved. Therefore, the invention provides a process for producing a purified synthesis gas stream from a feed synthesis gas stream comprising besides the main 10 constituents carbon monoxide and hydrogen also hydrogen sulphide, HCN and/or COS, the process comprising the steps of: (a) removing HCN and/or COS by contacting the feed synthesis gas stream with a water gas shift catalyst in a shift reactor in the presence of steam/water to 15 react at least part of the carbon monoxide to carbon dioxide, and to obtain a synthesis gas stream depleted in HCN and/or in COS; (b) removing hydrogen sulphide in the synthesis gas stream depleted in HCN and/or in COS by contacting this gas stream in a H 2 S-removal zone with an 20 aqueous alkaline washing liquid to obtain a H 2 S-depleted synthesis gas stream and a sulphide-comprising aqueous stream; (c) contacting the sulphide-comprising aqueous stream with sulphide-oxidizing bacteria in the presence of oxygen in a bioreactor to obtain a sulphur slurry and 25 a regenerated aqueous alkaline washing liquid; (d) removing carbon dioxide from the H 2 S-depleted synthesis gas stream, to obtain the purified synthesis gas stream and a gas stream enriched in CO 2 , wherein the amount of H2S and COS in the feed synthesis gas stream is below 5 30 volume% when the feed synthesis gas stream is obtained by gasification of solid fossil fuels and below 10 volume% when the feed synthesis gas stream is obtained by gasification of an oil residue.

- 4a The process enables removal of hydrogen sulphide, carbonyl sulphide and/or hydrogen cyanide to low levels. The purified synthesis gas, because of its low level of contaminants, is suitable for use as fuel, suitably in 5 gas turbines, or for use in catalytical chemical TS 2337 -5 conversions. The purified synthesis gas is especially suitable for use in an Integrated Gasification Combined Cycle (IGCC). In step (d), a carbon dioxide stream at elevated 5 pressure, suitably in the range of from 4 to 12 bara is obtained. This carbon dioxide stream can be further pressurised and used for example for enhanced oil recovery. The process is economical because H 2 S is removed 10 directly from the synthesis gas stream via conversion into elemental sulphur. The synthesis gas stream depleted in H 2 S has very low concentrations of H 2 S, enabling the use of an inexpensive non-selective acid gas removal unit to remove remaining H 2 S as well as CO 2 15 It will be understood that the amount and type of contaminants in the feed synthesis gas stream can vary and depends on the amount of these contaminants present in the feedstock used to generate the feed synthesis gas stream. 20 Generally, the feed synthesis gas stream is obtained by gasification of feedstock. When using solid fossil fuels such as biomass or coal as feedstock, the amount of H 2 S and COS in the synthesis gas stream leaving the gasifier is below 5 25 volume% based on the synthesis gas stream. When using an oil residue as feedstock, the amount of H 2 S and COS in the synthesis gas stream leaving the gasifier is below 10 volume% based on the synthesis gas stream. 30 The synthesis gas stream generated from a feedstock may comprise particulate matter, for example fly-ash or soot particles. Therefore, in a preferred embodiment WO 2010/112502 PCT/EP2010/054188 -6 synthesis gas exiting a synthesis gas generation unit is contacted with scrubbing liquid in a soot scrubber to remove particulate matter, in particular soot, thereby obtaining the feed synthesis gas stream. The synthesis 5 gas stream exiting the synthesis gas generating unit is generally at elevated temperature and/or elevated pressure. Especially in the event that the synthesis gas is generated in a gasifier, the synthesis gas stream exiting the gasifier will be at elevated temperature and 10 at elevated pressure. To avoid additional cooling and/or depressurising steps, the scrubbing step in the soot scrubber is preferably performed at elevated temperature and/or at elevated pressure. Preferably, the temperature at which the synthesis gas is contacted with scrubbing 15 liquid is in the range of from 40 to 160 *C, more preferably from 110 to 150 *C. Preferably, the pressure at which the synthesis gas stream is contacted with scrubbing liquid is in the range of from 20 to 80 bara, more preferably from 20 to 60 bara. 20 The amount of HCN and/or COS in the feed synthesis gas stream depends on the composition of the feedstock from which the synthesis gas is derived and the technology applied for the production of synthesis gas. Generally, the amount of COS in a feed synthesis gas 25 stream derived from solid fossil fuel feedstocks, especially coal, is from about 100 to 3000 ppmv, based on the feed synthesis gas stream. For biomass, the amount of COS is generally in the range of from 1 to 100 ppmv. 30 In step (a), HCN and/or COS is removed from the feed synthesis gas stream via catalytic conversion. Catalysts for the hydrolysis of HCN and/or COS are known to those skilled in the art and include for example WO 2010/112502 PCT/EP2010/054188 -7 TiO 2 -based catalysts or catalysts based on alumina and/or chromium-oxide. Preferred catalysts are TiO 2 -based catalysts. The amount of water/steam is preferably between 5 5 v/v% and 80 v/v%, more preferably between 10 v/v% and 70 v/v%, still more preferably between 15 v/v% and 50 v/v%, based on steam. In step (a), the feed synthesis gas stream is contacted with a water gas shift catalyst in a shift 10 reactor to remove HCN and/or COS and to additionally react at least part of the carbon monoxide with water to form carbon dioxide and hydrogen. In an especially preferred embodiment of step (a), carbon monoxide in the feed synthesis gas stream is 15 converted with a low amount of steam in the presence of a catalyst as present in one or more fixed bed reactors. A series of shift reactors may be used wherein in each reactor a water gas shift conversion step is performed. The content of carbon monoxide, on a dry basis, in the 20 feed synthesis gas stream as supplied to the first or only water gas shift reactor is preferably at least 50 vol.%, more preferably between 55 and 70 vol.%. The feed synthesis gas stream preferably contains hydrogen sulphide in order to keep the catalyst sulphided and 25 active. The minimum content of hydrogen sulphide will depend on the operating temperature of the shift reactor, on the space velocity (GHSV) and on the sulphur species present in the feed synthesis gas stream. Preferably at least 300 ppm H 2 S is present in the feed synthesis gas 30 stream. There is no limitation on the maximum amount of

H

2 S from a catalyst activity point of view. In the preferred embodiment of step (a), the steam/water to carbon monoxide molar ratio in the feed WO 2010/112502 PCT/EP2010/054188 synthesis gas stream as it enters the first or only water gas shift reactor is preferably between 0.2:1 and 0.9:1. The temperature of the feed synthesis gas stream as it enters the shift reactor is preferably between 190 5 and 230 'C. In addition it is preferred that the inlet temperature is between 10 and 60 0C above the dewpoint of the feed to each water gas shift conversion step. The space velocity in the reactor is preferably between 6000-9000 h-1. The pressure is preferably between 2 and 10 5 MPa and more preferably between 3 and 4.5 MPa. The conversion of carbon monoxide may generally not be 100% because of the sub-stoichiometric amount of steam present in the feed of the reactor. In a preferred embodiment the content of carbon monoxide in the shift 15 reactor effluent, using a fixed bed reactor, will be between 35 and 50 vol.% on a dry basis, when starting from a feed synthesis gas stream comprising between 55 and 70 vol.% carbon monoxide, on a dry basis, and a steam / CO ratio of 0.2 to 0.3 molar. If a further 20 conversion of carbon monoxide is desired it is preferred to subject the shift reactor effluent to a next water gas shift conversion step. The preferred steam/water to carbon monoxide molar ratio, inlet temperature and space velocity for such 25 subsequent water gas shift conversion steps is as described for the first water gas shift conversion step. As described above the feed synthesis gas stream is suitably obtained from a gasification process and is suitably subjected to a water scrubbing step. In such a 30 step water will evaporate and end up in the syngas mixture. The resultant steam to CO molar ratio in such a scrubbed syngas will suitably be within the preferred ranges as described above. This will result in that no WO 2010/112502 PCT/EP2010/054188 -9 steam or water needs to be added to the syngas as it is fed to the first water gas shift conversion step. In order to achieve the desired steam to CO molar ranges for the subsequent steps steam or boiler feed water will 5 have to be added to the effluent of each previous step. The water gas shift step may be repeated to stepwise lower the carbon monoxide content in the shift reactor effluent of each next shift reactor to a CO content, on a dry basis, of below 5 vol.%. It has been found that in 10 4 to 5 steps, or said otherwise, in 4 to 5 reactors such a CO conversion can be achieved. It has been found that it is important to control the temperature rise in each shift reactor. It is preferred to operate each shift reactor such that the 15 maximum temperature in the catalyst bed in a single reactor does not exceed 440 'C and more preferably does not exceed 400 'C. At higher temperatures the exothermal methanation reaction can take place, resulting in an uncontrolled temperature rise. 20 The catalyst used in the shift reactor is preferably a water gas shift catalyst, which is active at the preferred low steam to CO molar ratio and active at the relatively low inlet temperature without favouring side reactions such as methanation. Suitably the catalyst 25 comprises a carrier and the oxides or sulphides of molybdenum (Mo), more preferably a mixture of the oxides or sulphides of molybdenum (Mo) and cobalt (Co) and even more preferably also comprising copper (Cu) tungsten (W) and/or nickel (Ni). The catalyst suitably also comprises 30 one or more promoters/inhibitors such as potassium (K), lanthanum (La), manganese (Mn), cerium (Ce) and/or zirconium (Zr). The carrier may be a refractory material such as for example alumina, MgAl 2

O

4 or MgO-Al2O 3 -TiO 2

-

WO 2010/112502 PCT/EP2010/054188 - 10 An example of a suitable catalyst comprises an active y-A1 2 0 3 carrier and between 1-8 wt% CoO and between 6-10 wt% MoO 3 . The catalyst is preferably present as an extrudate. 5 In a preferred embodiment of step (a), the feed synthesis gas stream comprises at least 50 vol.% of carbon monoxide, and the steam to carbon monoxide molar ratio in the feed synthesis gas stream as it enters the shift reactor or reactors is preferably between 0.2:1 10 and 0.9:1 and the temperature of the feed synthesis gas stream as it enters the shift reactor or reactors is between 190 and 230 C. In the event that step (a) involves the shift reaction as described hereinabove, preferably, a portion 15 of the "shifted" synthesis gas stream, optionally after removal of contaminants, is used for hydrogen manufacture, such as in a Pressure Swing Adsorption (PSA) step. The proportion of the shifted synthesis gas stream used for hydrogen manufacture will generally be 20 less than 15% by volume, preferably approximately 1-10% by volume. The hydrogen manufactured in this way can then be used as the hydrogen source in hydrocracking of the products of the hydrocarbon synthesis reaction. This arrangement reduces or even eliminates the need for a 25 separate source of hydrogen, e.g. from an external supply, which is otherwise commonly used where available. Thus, the carbonaceous fuel feedstock is able to provide a further reactant required in the overall process of biomass or coal to liquid products 30 conversion, increasing the self-sufficiency of the overall process. In step (a), a synthesis gas stream depleted in hydrogen cyanide and/or in COS is obtained.

WO 2010/112502 PCT/EP2010/054188 - 11 In step (b), the synthesis gas stream depleted in hydrogen cyanide and/or in COS is contacted with aqueous alkaline washing liquid to transfer hydrogen sulphide from the synthesis gas stream depleted in hydrogen 5 cyanide and/or in COS to the aqueous alkaline washing liquid. Suitable aqueous alkaline washing liquids include aqueous hydroxide solutions, e.g. sodium hydroxide or potassium hydroxide solutions in water and aqueous 10 (bi)carbonate solutions. Suitably, step (b) is performed at a temperature in the range of from 5 to 70 'C, more preferably from 10 to 50 0C. Preferably, step (c) is performed at a pressure in the range of from 1 to 100 bar(g), more preferably 15 from 1.5 to 80 bar(g). Optionally, the washing liquid is buffered. Preferred buffering compounds are carbonates, bicarbonates phosphates and mixtures thereof, especially sodium carbonate and/or sodium bicarbonate. 20 The concentration of the buffering compounds depends inter alia on the composition of the gas flow and is generally adjusted in such a way, that the washing liquid is kept within the preferred pH range. Preferably, the pH of the washing liquid is in the 25 range of from 4.5 to 10, more preferably from 5.5 to 9.0. In step (c) hydrogen sulphide in the scrubbing medium is converted to elemental sulphur using sulphide oxidising bacteria in the presence of oxygen in a bioreactor. 30 Reference herein to sulphide-oxidising bacteria is to bacteria which can oxidise sulphide to elemental sulphur. Suitable sulphide-oxidising bacteria can be WO 2010/112502 PCT/EP2010/054188 - 12 selected for instance from the known autotropic aerobic cultures of the genera Thiobacillus and Thiomicrospira. The main reactions that can take place in the bioreactor are the microbiological formation of sulphur 5 and sulphate: (la) Sulfur production HS- + 4 02 -+ 1/8 S8 + OH (lb) Sulfur production HS 5 + b< 02 -+ 5/8 S8 + 0H (2) Sulphate production HS- + 202 + OH- -+ SO 4 2 - + H 2 0 The sulphur slurry may comprise one or more products of the main reactions, including elemental sulphur and sulphates. The regenerated aqueous alkaline washing liquid may 10 comprise sulphur particles. Reference herein to sulphide-oxidising bacteria is to bacteria which can oxidise sulphide to elemental sulphur. Suitable sulphide-oxidising bacteria can be selected for instance from the known autotropic aerobic 15 cultures of the genera Thiobacillus and Thiomicrospira. Preferably, the reaction medium in the bioreactor is buffered. The buffering compounds are chosen in such a way that they are tolerated by the bacteria present in the oxidation reactor. Preferred buffering compounds are 20 carbonates, bicarbonates phosphates and mixtures thereof, especially sodium carbonate and/or sodium bicarbonate. The concentration of the buffering compounds depends inter alia on the composition of the gas flow and is generally adjusted in such a way, that the pH of the 25 reaction medium in the oxidation reactor is between 6.0 WO 2010/112502 PCT/EP2010/054188 - 13 and 12.0, preferably between 7.0 and 11.0, more preferably between 8.0 and 10.0. Typical pressures in the bioreactor are between 0.5 and 2 bar(g). 5 Preferably, at least part of the aqueous sulphur slurry obtained in step (c) is separated from the regenerated aqueous alkaline washing liquid. Suitably, the separating step takes place in a solid/liquid separator. Suitable solid/liquid separators are described 10 in Perry's Chemical Engineers' Handbook, 7 th edition, section 22 (1997). The sulphur content of the separated aqueous sulphur slurry is suitably between 5 w/w% and 50 w/w%, based on the slurry. Typically, the water of the sulphur 15 slurry is removed to an extent that a sulphur cake with a dry solids content of between 55 and 70% is obtained. Suitably, the sulphur purity of the sulphur cake is between 90 and 98 w/w%, based on the dry weight of the sulphur cake. Optionally, the sulphur slurry can be re 20 slurried, filtered and dried to obtain a sulphur paste with a purity of at least 95 wt% sulphur, preferably at least 99 wt% sulphur. The sulphur paste thus-obtained can optionally be dried to produce a powder with a dry weight content of at least 85%, preferably at least 90%. This 25 powder can suitably be applied as a fungicide, a fertilizer or as a miticide. In step (d) carbon dioxide is removed from the synthesis gas stream depleted in hydrogen sulphide. In a first embodiment of step (d), carbon dioxide 30 is removed by contacting the synthesis gas stream depleted in H 2 5 with absorbing liquid to remove carbon dioxide and remaining hydrogen sulphide.

WO 2010/112502 PCT/EP2010/054188 - 14 Suitable absorbing liquids may comprise chemical solvents or physical solvents or mixtures thereof. A preferred absorbing liquid comprises a chemical solvent and/or a physical solvent, suitably as an aqueous 5 solution. Suitable chemical solvents are primary, secondary and/or tertiary amines, including sterically hindered amines. A preferred chemical solvent comprises a secondary 10 or tertiary amine, preferably an amine compound derived from ethanolamine, more especially DIPA, DEA, MMEA (monomethyl-ethanolamine), MDEA (methyldiethanolamine) TEA (triethanolamine), or DEMEA (diethyl monoethanolamine), preferably DIPA or MDEA. It is 15 believed that these chemical solvents react with acidic compounds such as H 2 S. In a second embodiment of step (d), carbon dioxide is removed using a membrane. It is advantageous to use membranes with a high 20 selectivity for carbon dioxide. The selectivity is defined as the ratio of the carbon dioxide permeability over the permeability of carbon monoxide and hydrogen as measured in single gas experiments. Preferably, the selectivity of the membrane is between 10 and 200, 25 preferably between 20 and 150. Suitably the membrane material is chosen from the group of polyethylene oxide based materials, preferably polyethylene oxide based material comprising block copolymers, especially PEO 600/5000 T6T6T or a cross 30 linked PEO, polyimide or polyaramide based materials, cellulose acetate based materials, zeolite based materials, preferably silica-alumina phosphate based WO 2010/112502 PCT/EP2010/054188 - 15 materials, more preferably SAPO-34, micro-porous silica materials and carbon molecular sieves materials. In a third embodiment of step (d), carbon dioxide is removed by cooling the gas stream to a temperature at 5 which carbon dioxide will separate from the gas stream. Suitably, the gas stream is cooled to a temperature at which carbon dioxide becomes a liquid or a solid so it can be separated from the gas stream. The purified synthesis gas obtained in step (d) has 10 low levels of contaminants, suitably in the ppmv or even in the ppbv range. Suitably, the gas stream enriched in C02 obtained in step (d) is at a pressure in the range of from 3 to 15 bara, preferably from 5 to 15 bara. This pressurised gas 15 stream enriched in C02 can advantageously be used for enhanced oil recovery, with less compression equipment needed. In applications where the C0 2 -enriched gas stream needs to be at a high pressure, for example when it will 20 be used for injection into a subterranean formation, it is an advantage that the C0 2 -enriched gas stream is already at an elevated pressure. In one embodiment, the C0 2 -enriched gas stream is further pressurised and used for enhanced oil recovery, 25 suitably by injecting it into an oil reservoir where it tends to dissolve into the oil in place, thereby reducing its viscosity and thus making it more mobile for movement towards the producing well. In another embodiment, the C0 2 -enriched gas stream 30 is further pressurised and pumped into an aquifer reservoir for storage.

WO 2010/112502 PCT/EP2010/054188 - 16 In yet another embodiment, the pressurised C02 enriched gas stream is further pressurised and pumped into an empty oil reservoir for storage. For all the above options, a series of compressors 5 is needed to pressurise the C0 2 -enriched gas stream to the desired high pressures. Pressurising the C0 2 -enriched gas stream from atmospheric pressure to a pressure of about 10 bara generally requires a large and expensive compressor. As the process results in a C0 2 -enriched gas 10 stream which is already at elevated pressure, preferably above 10 bara, the most extensive compressor is not needed. In a preferred embodiment, the purified synthesis gas is used for power generation, especially in an IGCC 15 system. In the IGCC system, typically, fuel and an oxygen containing gas are introduced into a combustion section of a gas turbine. In the combustion section of the gas turbine, the fuel is combusted to generate a hot 20 combustion gas. The hot combustion gas is expanded in the gas turbine, usually via a sequence of expander blades arranged in rows, and used to generate power via a generator. Suitable fuels to be combusted in the gas turbine include natural gas and synthesis gas. 25 Hot exhaust gas exiting the gas turbine is introduced into to a heat recovery steam generator unit, where heat contained in the hot exhaust gas is used to produce a first amount of steam. Suitably, the hot exhaust gas has a temperature in 30 the range of from 350 to 700 0C, more preferably from 400 to 650 C. The composition of the hot exhaust gas can vary, depending on the fuel gas combusted in the gas turbine and on the conditions in the gas turbine.

WO 2010/112502 PCT/EP2010/054188 - 17 The heat recovery steam generator unit is any unit providing means for recovering heat from the hot exhaust gas and converting this heat to steam. For example, the heat recovery steam generator unit can comprise a 5 plurality of tubes mounted stackwise. Water is pumped and circulated through the tubes and can be held under high pressure at high temperatures. The hot exhaust gas heats up the tubes and is used to produce steam. The heat recovery steam generator unit can be 10 designed to produce three types of steam: high pressure steam, intermediate pressure steam and low pressure steam. Preferably, the steam generator is designed to produce at least a certain amount of high pressure steam, 15 because high pressure steam can be used to generate power. Suitably, high-pressure steam has a pressure in the range of from 90 to 150 bara, preferably from 90 to 125 bara, more preferably from 100 to 115 bara. Suitably, low-pressure steam is also produced, the low-pressure 20 steam preferably having a pressure in the range of from 2 to 10 bara, more preferably from to 8 bara, still more preferably from 4 to 6 bara. In the heat recovery steam generator unit preferably high pressure steam is produced in a steam 25 turbine, which high pressure steam is converted to power, for example via a generator coupled to the steam turbine. The purified synthesis gas, because of its low level of contaminants, is also suitable for use in catalytic processes, preferably selected from the group 30 of Fischer-Tropsch synthesis, methanol synthesis, di methyl ether synthesis, acetic acid synthesis, ammonia synthesis, methanation to make substitute natural gas WO 2010/112502 PCT/EP2010/054188 - 18 (SNG) and processes involving carbonylation or hydroformylation reactions. Without wishing to be restricted to a particular embodiment, the invention will now be described in 5 further detail with reference to the Figures. In Figure 1, there is shown a process for producing a purified synthesis gas stream. This starts with the gasification of biomass or coal with oxygen in a gasification unit 1 to form a feed synthesis gas stream 10 comprising hydrogen sulphide, HCN and/or COS. Preferably, removal of solids such as slag, soot and the like is done in a solids removal unit (not shown). The resulting feed synthesis gas stream is led to a shift unit 2, where it is contacted with a shift catalysis, converting CO to C02 15 and hydrolysing HCN and COS. The resulting synthesis gas stream depleted in HCN and COS emanating from unit 2 is led to H 2 S-removal zone 3 where H 2 S is removed by contacting the synthesis gas stream with an aqueous alkaline washing liquid. The resulting synthesis gas 20 stream depleted in H 2 S is led from H 2 S-removal zone 3 to acid gas removal unit 4, where it is contacted with absorbing liquid to remove C02 and remaining H 2 S- This results in a purified synthesis gas stream and a gas stream enriched in C02. Aqueous alkaline washing liquid 25 comprising H 2 S is led from the H 2 S removal zone to bioreactor 5, where H 2 S is converted to elemental sulphur. In Figure 2, a preferred embodiment is depicted, wherein the purified synthesis gas is used for power 30 production. In Figure 2, a purified synthesis gas stream as produced in a process according to Figure 1 is led to a power plant comprising a gas turbine (1) and a heat WO 2010/112502 PCT/EP2010/054188 - 19 recovery steam generator unit (2). In the gas turbine, an oxygen-containing gas is supplied via line 4 to compressor 5. Purified synthesis gas as produced in a process described in Figure 1 is supplied via line 6 to 5 combuster 7 and combusted in the presence of the compressed oxygen-containing gas. The resulting combustion gas is expanded in expander 8 and used to generate power in generator 9. Remaining exhaust gas comprising CO 2 and oxygen is led via line 10 to a heat 10 recovery steam generator unit 2. In the heat recovery steam generator unit, water is heated against the hot exhaust gas in in heating section 11 to generate steam. The steam is led via line 12 into a steam turbine 13 to produce additional power in generator 14.

Claims

1. A process for producing a purified synthesis gas stream from a feed synthesis gas stream comprising besides the main constituents carbon monoxide and hydrogen also hydrogen sulphide, HCN and/or COS, the 5 process comprising the steps of: (a) removing HCN and/or COS by contacting the feed synthesis gas stream with a water gas shift catalyst in a shift reactor in the presence of steam/water to react at least part of the carbon monoxide to carbon dioxide, and 10 to obtain a synthesis gas stream depleted in HCN and/or in COS; (b) removing hydrogen sulphide in the synthesis gas stream depleted in HCN and/or in COS by contacting this gas stream in a H 2 S-removal zone with an aqueous alkaline 15 washing liquid to obtain a H 2 S-depleted synthesis gas stream and a sulphide-comprising aqueous stream; (c) contacting the sulphide-comprising aqueous stream with sulphide-oxidizing bacteria in the presence of oxygen in a bioreactor to obtain a sulphur slurry and a 20 regenerated aqueous alkaline washing liquid; (d) removing carbon dioxide from the H 2 S-depleted synthesis gas stream, to obtain the purified synthesis gas stream and a gas stream enriched in CO 2 , wherein the amount of H 2 S and COS in the feed synthesis 25 gas stream is below 5 volume% when the feed synthesis gas stream is obtained by gasification of solid fossil fuels and below 10 volume% when the feed synthesis gas stream is obtained by gasification of an oil residue.

2. A process according to claim 1, wherein the 30 sulphide-oxidising bacteria are selected from the group TS 2337 - 21 of autotropic aerobic cultures of the genera Thiobacillus and Thiomicrospira.

3. A process according to claim 1, wherein the steam/water to carbon monoxide molar ratio in the feed 5 synthesis gas stream as it enters the shift reactor is preferably between 0.2:1 and 0.9:1 and wherein the temperature of feed synthesis gas stream as it enters the shift reactor is in the range of from 190 to 230 0 C and wherein the feed synthesis gas stream comprises at least 10 50 volume% of carbon monoxide, on a dry basis.

4. A process according to any one of the preceding claims, wherein in step (c) carbon dioxide is removed by contacting the synthesis gas stream depleted in hydrogen sulphide with an absorbing liquid at low temperature and 15 at elevated pressure, thereby transferring carbon dioxide from the gas streams to the absorbing liquid to obtain absorbing liquid enriched in carbon dioxide and the purified gas stream.

5. A process according to any one of claims 1 to 3, 20 wherein in step (c) carbon dioxide is removed using a membrane.

6. A process according to any one of claims 1 to 3, wherein in step (c) carbon dioxide is removed by cooling the synthesis gas stream depleted in hydrogen sulphide to 25 a temperature at which carbon dioxide will separate from the gas streams.

7. A process according to any one of the preceding claims, wherein the purified synthesis gas stream is used in a combustion turbine to produce electricity. 30

8. A process according to claim 7, wherein hot exhaust gas is emitted from the combustion turbine and this hot exhaust gas is introduced into a heat recovery steam TS 2337 - 22 generator unit to produce a steam, which steam is used to produce additional electricity.

9. A process according to any one of claims 1 to 6, wherein the further purified synthesis gas is used in 5 catalytic processes, preferably selected from the group of Fischer-Tropsch synthesis, methanol synthesis, di methyl ether synthesis, acetic acid synthesis, ammonia synthesis, methanation to make substitute natural gas (SNG) and processes involving carbonylation or 10 hydroformylation reactions.

10. A process according to any one of claims 1 to 9, wherein the gas stream enriched in CO 2 is at a pressure in the range of from 5 to 50 bara, preferably from 10 to 50 bara, more preferably from 20 to 50 bara. 15

11. A process according to claim 10, wherein the gas stream enriched in CO 2 is further pressurised and injected into a subterranean formation, preferably for use in enhanced oil recovery or for storage into an aquifer reservoir or for storage into an empty oil 20 reservoir

12. A process for producing a purified synthesis gas stream from a feed synthesis gas stream comprising the steps substantially as herein described with reference to Figure 1 or Figure 2. 25

13. Purified synthesis gas produced by the process of any one of claims 1 to 12.