Abstract:
A process ( 10 ) for co-producing power and hydrocarbons includes in a wet gasification stage ( 70 ), gasifying coal to produce a combustion gas ( 86 ) at elevated pressure comprising at least H 2  and CO; enriching ( 72 ) a first portion of the combustion gas with H 2  to produce an H 2 -enriched gas ( 88 ); and generating power ( 77 ) from a second portion of the combustion gas. In a dry gasification stage ( 16 ), coal is gasified to produce a synthesis gas precursor ( 36 ) at elevated pressure comprising at least H 2  and CO. At least a portion of the H 2 -enriched gas ( 88 ) is mixed with the synthesis gas precursor ( 36 ) to provide a synthesis gas for hydrocarbon synthesis, with hydrocarbons being synthesized ( 20, 22 ) from the synthesis gas. In certain embodiments, the process ( 10 ) produces a CO 2  exhaust stream ( 134 ) for sequestration or capturing for further use.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application is a national stage application under 35 U.S.C. 371 of PCT Application No. PCT/IB2008/050456 having an international filing date of 8 Feb. 2008, which designated the United States, which PCT application claimed the benefit of U.S. Application No. 60/900,935 filed 12 Feb. 2007 and U.S. Application No. 60/901,251 filed 14 Feb. 2007, the entire disclosures of which are incorporated herein by reference. 
    
    
     FIELD 
     This invention relates to the co-production of power and hydrocarbons. In particular, the invention relates to a process for co-producing power and hydrocarbons. 
     BACKGROUND 
     Coal is used as a feedstock for production of power and for production of hydrocarbons. It is generally accepted that Integrated Gasification Combined Cycle (IGCC) processes have environmental advantages over conventional coal-fired power plants. In IGCC processes coal is first gasified to produce synthesis gas and the synthesis gas then serves as fuel source to a combined cycle power production stage. One route for production of hydrocarbons from coal is to gasify coal to produce synthesis gas and then to convert the synthesis gas to hydrocarbons. 
     It would be an advantage to provide an IGCC process integrated with a hydrocarbon production process which shows economic (i.e. capital and operating cost) benefits and environmental benefits. 
     SUMMARY 
     As used in this specification, the term wet gasification stage means an entrained flow gasification stage in which water is used as a carrier for solid feedstock (e.g. coal). It is thus a slurry that is fed to the gasification stage. 
     As used in this specification, the term dry gasification stage means an entrained flow gasification stage in which a gas is used as a carrier for solid feedstock (e.g. coal). 
     According to the invention, there is provided a process for co-producing power and hydrocarbons, the process including 
     in a wet gasification stage, gasifying coal to produce a combustion gas at elevated pressure comprising at least H 2  and CO; 
     enriching a first portion of the combustion gas with H 2  to produce an H 2 -enriched gas; 
     generating power from a second portion of the combustion gas; 
     in a dry gasification stage, gasifying coal to produce a synthesis gas precursor at elevated pressure comprising at least H 2  and CO; 
     mixing at least a portion of the H 2 -enriched gas with the synthesis gas precursor to provide a synthesis gas for hydrocarbon synthesis; and 
     synthesising hydrocarbons from the synthesis gas. 
     The combustion gas may be produced at a pressure of at least 45 bar, more preferably at least 55 bar, most preferably at least 65 bar, e.g. about 70 bar. Typically, the wet gasification stage uses a water quench to cool the combustion gas. 
     The molar ratio of H 2  and CO in the combustion gas may be higher than the molar ratio of H 2  and CO in the synthesis gas precursor. For avoidance of doubt, the phrase “the molar ratio of H 2  and CO” as used in this specification means the molar concentration of H 2  divided by the molar concentration of CO. The molar ratio of H 2 /CO has an identical meaning. 
     The molar ratio of H 2 /CO in the combustion gas may be at least 0.6. Preferably, the molar ratio is at least 0.8, more preferably at least 0.9, e.g. about 0.96. Typically, the molar ratio of H 2 /CO in the combustion gas is between 0.6 and 1.0. 
     The dry gasification stage should produce synthesis gas at a pressure which is sufficiently high, taking into account pressure losses over process units to allow hydrocarbon synthesis at a suitably high pressure. Typically the synthesis gas precursor is at a pressure of between about 40 bar and about 50 bar, e.g. about 45 bar. Typically, the dry gasification stage includes a gasification stage waste heat boiler. 
     The molar ratio of H 2 /CO in the synthesis gas precursor may be between about 0.3 and about 0.6, typically between about 0.3 and about 0.4, e.g. about 0.4. 
     Enriching a first portion of the combustion gas with H 2  may include subjecting said first portion to water gas shift conversion thereby to produce the H 2 -enriched gas. Typically the water gas shift conversion is a sour shift, i.e. containing a catalyst suitable for reacting carbon monoxide and water to produce additional hydrogen in the presence of sulphur. 
     The process may include purifying a portion of the H 2 -enriched gas, e.g. by using membranes and/or pressure swing adsorption, to produce essentially pure hydrogen. The essentially pure hydrogen may be used for hydroprocessing of hydrocarbons synthesised from the synthesis gas. 
     The H 2 -enriched gas may be at elevated pressure. Mixing at least a portion of the H 2 -enriched gas with the synthesis gas precursor may include passing the H 2 -enriched gas through an expansion turbine to generate power. 
     Generating power from a second portion of the combustion gas may include combusting the combustion gas at elevated pressure in the presence of oxygen to produce hot combusted gas and expanding the hot combusted gas through a gas turbine expander to generate power and to produce hot exhaust gas. Typically, the combustion of the combustion gas occurs in a combustor. The hot exhaust gas may be at or above atmospheric pressure. 
     Generating power from a second portion of the combustion gas may also include recovering heat from the hot exhaust gas in a waste heat recovery stage. Typically, the waste heat recovery stage includes a waste heat recovery stage waste heat boiler. Typically, recovering heat from the hot exhaust gas in the waste heat recovery stage thus includes generating steam in the waste heat recovery stage waste heat boiler. The generated steam may be used to drive a steam turbine to produce power or the steam may be used elsewhere in the process for other purposes. 
     The waste heat recovery stage waste heat boiler may be a co-fired waste heat boiler. The synthesising of hydrocarbons from the synthesis gas may produce a fuel gas. The waste heat recovery stage waste heat boiler may be co-fired with the fuel gas to raise the pressure and/or the temperature of the steam generated by the waste heat recovery stage waste heat boiler. 
     The process may include separating air to produce oxygen. The oxygen may be used to combust the combustion gas to produce the hot combustion gas. Typically, the oxygen must be produced at pressure to exceed the operating pressure of a combustor in which the combustion gas is combusted. Typically liquid oxygen is pumped to the required pressure and the liquid oxygen is then heated to produce oxygen gas which is then used to combust the combustion gas. 
     The oxygen, at lower pressure, may also be used to combust the fuel gas thereby to co-fire the waste heat recovery stage waste heat boiler. 
     The oxygen is typically also used in the wet gasification stage and in the dry gasification stage to gasify coal. This oxygen is the highest pressure oxygen used and the required pressure is typically achieved by pumping liquid oxygen, which is then evaporated at pressure. 
     Synthesising hydrocarbons from the synthesis gas may be effected in any conventional fashion. Typically, the synthesising of hydrocarbons from the synthesis gas includes Fischer-Tropsch synthesis using one or more Fischer-Tropsch hydrocarbon synthesis stages, producing one or more hydrocarbon product streams and a Fischer-Tropsch tail gas which includes CO 2 , CO and H 2 . 
     The one or more Fischer-Tropsch hydrocarbon synthesis stages may be provided with any suitable reactors such as one or more reactors selected from fixed bed reactors, slurry bed reactors, ebullating bed reactors or dry powder fluidised bed reactors. The pressure in the reactors may be between 1 bar and 100 bar, typically below 45 bar, while the temperature may be between 160° C. and 380° C. 
     One or more of the Fischer-Tropsch hydrocarbon synthesis stages may be a low temperature Fischer-Tropsch hydrocarbon synthesis stage operating at a temperature of less than 280° C. Typically, in such a low temperature Fischer-Tropsch hydrocarbon synthesis stage, the hydrocarbon synthesis stage operates at a temperature of between 160° C. and 280° C., preferably between 220° C. and 260° C., e.g. about 250° C. Such a low temperature Fischer-Tropsch hydrocarbon synthesis stage is thus a high chain growth, typically slurry bed, reaction stage, operating at a predetermined operating pressure in the range of 10 to 50 bar, typically below 45 bar. 
     One or more of the Fischer-Tropsch hydrocarbon synthesis stages may be a high temperature Fischer-Tropsch hydrocarbon synthesis stage operating at a temperature of at least 320° C. Typically, such a high temperature Fischer-Tropsch hydrocarbon synthesis stage operates at a temperature of between 320° C. and 380° C., e.g. about 350° C., and at an operating pressure in the range of 10 to 50 bar, typically below 45 bar. Such a high temperature Fischer-Tropsch hydrocarbon synthesis stage is a low chain growth reaction stage, which typically employs a two-phase fluidised bed reactor. In contrast to the low temperature Fischer-Tropsch hydrocarbon synthesis stage, which may be characterised by its ability to maintain a continuous liquid product phase in a slurry bed reactor, the high temperature Fischer-Tropsch hydrocarbon synthesis stage cannot produce a continuous liquid product phase in a fluidised bed reactor. 
     The Fischer-Tropsch tail gas may be treated to remove CO 2 . The CO 2  may be removed in any conventional fashion, e.g. by using a Benfield solution. Typically, the Fischer-Tropsch tail gas is subjected to a water gas shift stage to convert CO to CO 2  and to produce more H 2 . The water gas shift stage would typically be a conventional water gas shift stage, i.e. a sweet shift stage. 
     The process may include separating H 2  from the Fischer-Tropsch tail gas (e.g. using pressure swing adsorption) and recycling the H 2  to the one or more Fischer-Tropsch hydrocarbon synthesis stages. 
     The process may include treating the synthesis gas precursor or the synthesis gas to remove sulphur and/or CO 2 . Treating the synthesis gas precursor or the synthesis gas may be effected in any conventional fashion, e.g. using a Rectisol process which includes a chilled methanol wash. 
     The process may include feeding a portion of the CO 2  obtained from the treatment of synthesis gas precursor or synthesis gas and/or from the treatment of the Fischer-Tropsch tail gas to a combustor used to generate power from the second portion of the combustion gas to act as a temperature moderating agent. Typically, this will include compressing the CO 2  to exceed the operating pressure of the combustor. The compressed CO 2  may be mixed with oxygen already at pressure, before being fed to the combustor. 
     The process may include treating exhaust gas from the waste heat recovery stage waste heat boiler, comprising predominantly CO 2  and water, to remove the water, leaving a CO 2  exhaust stream which may be sequestrated in any conventional fashion, or captured for further use. The CO 2  exhaust stream may be combined with a further portion of CO 2  obtained from the treatment of synthesis gas precursor or synthesis gas and/or from the treatment of the Fischer-Tropsch tail gas. Instead or in addition, the process may include recycling some of the exhaust gas from the waste heat recovery stage waste heat boiler, or some of the CO 2  exhaust stream, to the combustor. 
     The process may include superheating steam from the waste heat recovery stage waste heat boiler using the fuel gas and air. In this event, a stack gas produced by the superheating of the steam should not be mixed with exhaust gas from the waste heat recovery stage waste heat boiler or with the hot exhaust gas from the gas turbine expander. 
     The process may include using, instead of air, essentially pure oxygen or a combination of essentially pure oxygen and CO 2  in at least some fired equipment involved in the production of hydrocarbons. Stack gases from such fired equipment may then be combined to consolidate CO 2 -producing streams. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The invention will now be described, by way of example, with reference to the accompanying diagrammatic drawings in which 
         FIG. 1  shows a process in accordance with the invention for a co-producing power and hydrocarbons; and 
         FIG. 2  shows in more detail a portion of the process of  FIG. 1 . 
     
    
    
     DETAILED DESCRIPTION 
     Referring to  FIG. 1  of the drawings, reference numeral  10  generally indicates a process in accordance with the invention for co-producing power and hydrocarbons. The process  10  includes a coal-to-liquid (CTL) hydrocarbon synthesis facility generally indicated by reference numeral  12  and an Integrated Gasification Combined Cycle (IGCC) facility generally indicated by reference numeral  14 . 
     The CTL facility  12  includes a dry gasification stage  16 , a gas clean-up stage  18 , a first Fischer-Tropsch hydrocarbon synthesis stage  20 , a second Fischer-Tropsch hydrocarbon synthesis stage  22  in series with the first Fischer-Tropsch hydrocarbon synthesis stage  20 , a heavy end recovery stage  24 , a water gas or sweet shift stage  26 , a CO 2  removal stage  28 , a hydrogen separation stage  30 , a reaction water treatment stage  32  and a product work-up stage  34 . 
     A syngas line  36  leads from the dry gasification stage  16  to the gas clean-up stage  18  and from the gas clean-up stage  18  through the first and second Fischer-Tropsch hydrocarbon synthesis stages  20 ,  22 . A Fischer-Tropsch tail gas line  38  leads from the second Fischer-Tropsch hydrocarbon synthesis stage  22  to the heavy end recovery stage  24  and from there to the water gas or sweet shift stage  26 , the CO 2  removal stage  28  and eventually to the hydrogen separation stage  30 . A hydrogen recycle line  40  leads from the hydrogen separation stage  30  back to the first Fischer-Tropsch hydrocarbon synthesis stage  20  and a fuel gas line  42  leads from the hydrogen separation stage  30  to the IGCC facility  14 . 
     A syngas bypass line  44  bypasses the first Fischer-Tropsch hydrocarbon synthesis stage  20 . 
     A sulphur recovery line  46  and a CO 2  line  48  leave the gas clean-up stage  18 . 
     Hydrocarbon product lines  50  and reaction water lines  52  leave the first and second Fischer-Tropsch hydrocarbon synthesis stages  20 ,  22 , with the reaction water lines  52  leading to the reaction water treatment stage  32  and the hydrocarbon product lines  50  leading to the product work-up stage  34 . The product work-up stage  34  is also connected to the heavy end recovery stage  24  by means of a light hydrocarbons line  54  leading from the heavy end recovery stage  24  to the product work-up stage  34 . 
     An oxygenates line  56  and water lines  58  leave the reaction water treatment stage  32 , whereas an LPG line  60 , a naphta line  62  and a diesel line  64  leave the product work-up stage  34 . 
     The CO 2  removal stage  28  is provided with a CO 2  line  66 . 
     The IGCC facility  14  includes a wet gasification stage  70 , a sour shift stage  72 , a hydrogen-enriched gas expansion stage  74 , a gas clean-up stage  76 , a combustion gas expansion stage  77 , a gas combustion and expansion stage  78  and a waste heat recovery stage  80  comprising a co-fired waste heat boiler  82  and steam turbines  84 . 
     A combustion gas line  86  leads from the wet gasification stage  70  to the gas clean-up stage  76  and from the gas clean-up stage  76  to the combustion gas expansion stage  77  and from there to the gas combustion and expansion stage  78 . The combustion gas line  86  between the wet gasification stage  70  and the gas clean up stage  76  also branches off to the sour shift stage  72 . An H 2 -enriched gas line  88  leads from the sour shift stage  72  through the hydrogen-enriched gas expansion stage  74  and joins the syngas line  36  between the dry gasification stage  16  and the gas clean-up stage  18  of the CTL facility  12 . 
     A sulphur removal line  90  leaves the gas clean-up stage  76 . 
     With reference to  FIG. 2  of the drawings, the gas combustion and expansion stage  78  includes a compressor  92  and a gas turbine expander  94  drivingly connected to the compressor  92 . The combustion gas line  86  from the combustion gas expansion stage  77  leads to a combustor  96 . A CO 2  line  98  leads into the compressor  92 . A compressed CO 2  line  102  leads from the compressor  92  to the combustor  96  and is joined by an oxygen line  100 . A hot combusted gas line  104  leads from the combustor  96  to the gas turbine expander  94 . A hot exhaust gas line  106  leads from the gas turbine expander  94  to the co-fired waste heat boiler  82  of the waste heat recovery stage  80 . 
     A steam line  108  leads from the co-fired waste heat boiler  82  to the steam turbines  84  and a condensate recycle line  110  leads back from the steam turbines  84  to the co-fired waste heat boiler  82 . The co-fired waste heat boiler  82  is joined by the fuel gas line  42  from the CTL facility  12  and is also provided with an exhaust gas line  112 . 
     The hydrogen-enriched gas expansion stage  74 , the combustion gas expansion stage  77 , the gas combustion and expansion stage  78  and the steam turbines  84  provide electric power generally indicated by reference numeral  114 . Electricity can be exported and used internally, e.g. in the CTL facility  12 . 
     The CTL facility  12  and the IGCC facility  14  share an air separation unit  120 , a CO 2  and water separation stage  122 , a CO 2  compression and water knock-out stage  124  and a water treatment stage  126 . 
     The oxygen line  100  from the air separation unit  120  leads to the gas combustion and expansion stage  78 , as hereinbefore indicated, but also to other oxygen users in both the CTL facility  12  and the IGCC facility  14 . 
     The CO 2  line  48  from the gas clean-up stage  18  of the CTL facility  12  leads to the CO 2  and water separation stage  122  and the CO 2  line  98  leads from the CO 2  and water separation stage  122  to the compressor  92  of the gas combustion and expansion stage  78 . A water line  128  leads from the CO 2  and water separation stage  122  to the water treatment stage  126 . 
     The CO 2  compression and water knock-out stage  124  is joined by the exhaust gas line  112  from the waste heat recovery stage  80  and the CO 2  line  66  from the CO 2  removal stage  28  of the CTL facility  12 . 
     A water line  130  leads from the CO 2  compression and water knock-out stage  124  to the water treatment stage  126 , which is also joined by the water line  58  from the reaction water treatment stage  32  of the CTL facility  12 . One or more treated water lines  132 , only one of which is shown for simplicity, leads from the water treatment stage  126  to both the CTL facility  12  and the IGCC facility  14 . 
     Referring again to  FIG. 2  of the drawings, the air separation unit  120  is provided with an air feed line  134  and a nitrogen production line  136 . 
     Particulate coal is gasified in the dry gasification stage  16  to produce synthesis gas precursor. The dry gasification stage  16  may employ any conventional dry gasification technology, e.g. the Shell (trade name) entrained flow dry feed gasification technology which produces a synthesis gas precursor with an H 2 /CO molar ratio of about 0.4. Although not shown in the drawings, a waste heat boiler is used to cool the synthesis gas precursor, which is typically produced at a pressure of about 45 bar. The waste heat boiler produces process steam (not shown). The synthesis gas precursor is fed by means of the syngas line  36  to the gas clean-up stage  18 . The synthesis gas precursor is however first enriched in hydrogen by the H 2 -enriched gas flowing along the H 2 -enriched gas line  88 , thereby to increase the H 2 /CO molar ratio so that the H 2 /CO molar ratio is in the range of between about 0.7 and about 2.5. 
     In the gas clean-up stage  18  the synthesis gas is cleaned in conventional fashion to remove sulphur, particulate material and CO 2 . Conventional synthesis gas cleaning technology may be used, e.g. a Rectisol process, amine washes and a CO 2  absorption process employing a Benfield solution. Sulphur is removed from the gas clean-up stage  18  by means of the sulphur recovery line  46  and the CO 2  is removed by means of the CO 2  line  48 . 
     The clean synthesis gas is fed into the first Fischer-Tropsch hydrocarbon synthesis stage  20  and from there into the second Fischer-Tropsch hydrocarbon synthesis stage  22  to convert the synthesis gas to hydrocarbons. Any conventional Fischer-Tropsch hydrocarbon synthesis configuration may be used. In the embodiment shown in  FIG. 1  of the drawings, a two-stage process employing a synthesis gas bypass (using the syngas bypass line  44 ) and a hydrogen recycle (using the hydrogen recycle line  40 ) is illustrated. The Fischer-Tropsch hydrocarbon synthesis stages  20 ,  22  may thus include one or more suitable reactors such as a fluidised bed reactor, a tubular fixed bed reactor, a slurry bed reactor or an ebullating bed reactor. It may even include multiple reactors operating under different conditions. The pressure in the reactors may be between 1 bar and 100 bar but in this embodiment a pressure of about 45 bar is used. The temperature may be between 160° C. and 380° C. Reactors will thus contain a Fischer-Tropsch catalyst, which will be in particulate form. The catalyst may contain, as its active catalyst component, Co, Fe, Ni, Ru, Re and/or Rh, but preferable has Fe as its active catalyst component. The catalyst may be provided with one or more promoters selected from an alkaline metal, V, Cr, Pt, Pd, La, Re, Rh, Ru, Th, Mn, Cu, Mg, K, Na, Ca, Ba, Zn and Zr. The catalyst may be a supported catalyst, in which case the active catalyst component, e.g. Co, is supported on a suitable support such as Al 2 O 3 , TiO 2 , SiO 2 , ZnO or a combination of these. Preferably, the catalyst is an unsupported Fe catalyst. 
     In the first Fischer-Tropsch hydrocarbon synthesis stage  20  and the second Fischer-Tropsch hydrocarbon synthesis stage  22 , reaction water is produced which is removed by means of the reaction water lines  52  and fed to the reaction water treatment stage  32 . In the reaction water treatment stage  32  oxygenates are separated from the reaction water using conventional separation technology and removed by means of the oxygenates line  56 . Water is withdrawn from the reaction water treatment stage  32  and fed to the water treatment stage  126  by means of the water line  58 . 
     Hydrocarbon products produced in the first Fischer-Tropsch hydrocarbon synthesis stage  20  and the second Fischer-Tropsch hydrocarbon synthesis stage  22  are removed by means of the hydrocarbon product lines  50  and fed to the product work-up stage  34 . In the product work-up stage  34 , the hydrocarbon products are worked up to produce LPG gas, naphta and diesel, respectively removed from the product work-up stage  34  by means of the LPG line  60 , the naphta line  62  and the diesel line  64 . 
     A Fischer-Tropsch tail gas is removed from the second Fischer-Tropsch hydrocarbon synthesis stage  22  by means of the Fischer-Tropsch tail gas line  38  and fed to the heavy end recovery stage  24  where light hydrocarbons, e.g. C 3   +  hydrocarbons are removed in conventional fashion and fed by means of the light hydrocarbons line  54  to the product work-up stage  34  to be worked up with the hydrocarbon products entering the product work-up stage  34  by means of the hydrocarbon product lines  50 . The Fischer-Tropsch tail gas is then mixed with steam (not shown) and subjected to the well-known water gas shift reaction to convert CO and water (steam) to CO 2  and H 2 , in the sweet shift stage  26 . From the sweet shift stage  26 , the Fischer-Tropsch tail gas, now with an increased concentration of CO 2  and H 2 , is then fed to the CO 2  removal stage  28 . In the CO 2  removal stage  28 , conventional technology is again used to remove CO 2  and water from the Fischer-Tropsch tail gas. Typically, this includes the use of a Benfield solution to absorb the CO 2 . The CO 2  is then again desorbed and the CO 2  and water are removed from the CO 2  removal stage  28  by means of the CO 2  line  66  and fed to the CO 2  compression and water knock-out stage  124 . 
     The Fischer-Tropsch tail gas from the CO 2  removal stage  28 , now with a reduced concentration of CO 2  and water, is fed to the hydrogen separation stage  30 . In the hydrogen separation stage  30 , conventional pressure swing adsorption is used to separate hydrogen from the Fischer-Tropsch tail gas, producing a fuel gas comprising mostly CO and hydrocarbon gasses. The hydrogen is recycled by means of the hydrogen recycle line  40  to the first Fischer-Tropsch hydrocarbon synthesis stage  20 . The fuel gas is removed by means of the fuel gas line  42  and fed to the waste heat recovery stage  80  of the IGCC facility  14 . Optionally, the fuel gas may be sold as synthetic natural gas and may also be blended with other gas streams to obtain the correct specification for sale. 
     For purposes of generating power, a coal slurry is gasified in the wet gasification stage  70  of the IGCC facility  14  to produce combustion gas. Any conventional wet gasification technology may be used, such as the General Electric (trade name) slurry fed gasification technology. Water is used as a coal carrier so that a coal slurry is gasified resulting in an H 2 /CO molar ratio of about 0.96 in the combustion gas produced in the wet gasification stage  70 . The combustion gas is typically cooled using a water quench. The combustion gas is produced at a pressure of more than 70 bar. 
     The combustion gas from the wet gasification stage  70  is removed by means of the combustion gas line  86  and fed to the gas clean-up stage  76 . Before the gas clean-up stage  76 , a portion of the combustion gas is mixed with steam as required (not shown) and diverted to the sour shift stage  72  where CO and water are converted to CO 2  and H 2 , using the well-known water gas shift reaction. An H 2 -enriched gas is thus produced in the sour shift stage  72  and the H 2 -enriched gas is fed by means of the H 2 -enriched gas line  88  to the hydrogen expansion stage  74 . In the hydrogen expansion stage  74 , the H 2 -enriched gas is expanded through an expansion turbine which drives a generator thereby to produce electrical power. In the expansion turbine, the pressure of the H 2 -enriched gas is dropped from more than 70 bar to about 45 bar, whereafter the H 2 -enriched gas is mixed with the synthesis gas precursor in the syngas line  36  to increase the H 2 /CO molar ratio of the synthesis gas precursor as hereinbefore described. 
     In the gas clean-up stage  76 , the combustion gas is cleaned in conventional fashion to remove sulphur along the sulphur removal line  90 . The clean combustion gas is then fed to the gas combustion and expansion stage  78  by means of the combustion gas line  86  via the combustion gas expansion stage  77 . In the combustion gas expansion stage  77 , the clean combustion gas is expanded through a gas turbine expander, reducing the pressure of the combustion gas to the operating pressure of the gas combustion and expansion stage  78 , and generating electricity (generally indicated by reference numeral  114 ). 
     Air is separated in the air separation unit  120  using conventional cryogenic air separation technology to produce nitrogen and oxygen, as shown in more detail in  FIG. 2 . The nitrogen is removed by means of the nitrogen line  136  and employed in the CTL facility  12  and the IGCC facility  14  where required, or recovered for commercial purposes or purged. The oxygen from the air separation unit  120  is removed by the oxygen line  100  and also distributed to the CTL facility  12  and the IGCC facility  14  for use where required. A portion of the oxygen is fed by means of the oxygen line  100  to the combustor  96  of the gas combustion and expansion stage  78  (see  FIG. 2 ). 
     In the CO 2  and water separation stage  122 , water is knocked from the CO 2 . The water is fed by means of the water line  128  to the water treatment stage  126 . The CO 2  is removed from the CO 2  and water separation stage  122  and fed to the compressor  92  of the gas combustion and expansion stage  78 . 
     CO 2  in the CO 2  line  98  is thus fed to the compressor  92  and compressed. The compressed CO 2  is mixed with high pressure oxygen from the oxygen line  100  and the compressed CO 2  and oxygen mixture is fed by means of the compressed CO 2  and oxygen line  102  to the combustor  96 . Combustion gas fed by means of the combustion gas line  86  is combusted in the combustor  96 , in the presence of the CO 2  and oxygen to produce a hot combusted gas. The hot combusted gas is removed by means of the hot combusted gas line  104  and passed through the gas turbine expander  94  which inter alia drives the compressor  92  by means of a direct mechanical coupling. The gas turbine expander  94  is also used to drive generators (not shown) to generate electric power generally indicated by reference numeral  114 . A hot exhaust gas, comprising mostly CO 2  and water, is removed from the gas turbine expander  94  by means of the hot exhaust gas line  106  and fed to the co-fired waste heat boiler  82  of the waste heat recovery stage  80 . The waste heat boiler  82  is fired with fuel gas fed by means of the fuel gas line  42  and produces high pressure steam which is fed by means of the steam line  108  to the steam turbines  84  which are used to drive generators (not shown) to generate electric power generally indicated by reference numeral  114 . Condensate is recycled from the steam turbines  84  to the co-fired waste heat boiler  82 . 
     The gas turbine expander  94  and/or the steam turbines  84  may be integrated with the air separation unit  120  to drive air compressors of the air separation unit  120  by means of direct mechanical coupling. 
     In the co-fired waste heat boiler  82 , the exhaust gas produced by the combustion of the fuel gas is combined with the exhaust gas from the gas turbine expander  94  and removed by means of the exhaust gas line  112 . As will be appreciated, this exhaust gas comprises mostly CO 2  and water. The exhaust gas is fed to the CO 2  compression and water knock-out stage  124  where it is compressed. Water is knocked out from the compressed CO 2  and fed by means of the water line  130  to the water treatment stage  126 . The compressed CO 2  from the CO 2  compression and water knock-out stage  124  is available for sequestration or capture, as indicated by reference numeral  134 . The compressed CO 2  may thus for example be employed for enhanced oil recovery (EOR) or enhanced coal-bed methane recovery (ECBMR). 
     In the water treatment stage  126 , water fed to the water treatment stage  126  along the water lines  58 ,  128  and  130  are treated to requisite levels. The treated water is removed by means of the treated water lines  132  and distributed to both the CTL facility  12  and the IGCC facility  14 , inter alia to be used as boiler feed water. 
     Selecting a gasification technology best suited to a particular venture involves consideration of various factors, including feedstock characteristics, capital cost, operating cost, reliability, intended application of the produced synthesis gas, etc. The invention, as illustrated, provides an integrated IGCC power plant and CTL plant which benefit from optimal economies of scale of the capital intensive parts and also provides for CO 2  sequestration. A combination of dry gasification and wet gasification is used to provide intermediate streams suited to hydrocarbon synthesis and power production respectively. Advantageously for power production, a wet gasification process can supply combustion gas at pressures higher than 70 bar. A dry gasification process can supply synthesis gas precursor at pressures matching the requirement for Fischer-Tropsch hydrocarbon synthesis, typically around 45 bar. The combustion gas typically has a higher hydrogen content than the synthesis gas precursor, a portion of the combustion gas thus providing a suitable feed material for enrichment with hydrogen to upwardly adjust the molar ratio of H 2  and CO of the synthesis gas precursor. Furthermore, the wet gasification stage typically employs a water quench and the combustion gas is thus saturated with water at relatively high temperature. Advantageously, the steam requirement of the sour shift used to enrich the first portion of the combustion gas with hydrogen is thus reduced. In addition, the dry gasification stage typically employs a waste heat boiler providing process steam. Overall energy efficiency is thus enhanced by the combination of dry- and wet gasification technologies, because the dry gasification approach is more efficient at producing a synthesis gas rich in carbon monoxide and the required process steam, while the wet gasification process is the most efficient approach to produce an enriched hydrogen gas. 
     Advantageously, the IGCC facility may be appropriately sized for internal consumption of energy only or, instead, if there is a suitable market for electricity in the vicinity, the IGCC facility may be sized to maximise economy of scale for the export of power. 
     Air separation units are expensive to construct and energy-intensive to operate due to large compression requirements. Advantageously, when an IGCC facility and a CTL facility share an air separation unit, economy of scale lowers the cost per unit volume of oxygen required by the CTL facility. Power-producing turbines of the IGCC facility may be integrated by direct mechanical coupling to air compressors of the air separation unit, resulting in improved plant energy efficiency, since a loss in efficiency associated with electrical power generation is avoided. 
     Sharing of utilities lowers the cost of expensive ultra-pure water used as boiler feed water make-up to produce steam for use in the steam turbines in the IGCC facility. Savings can also be realised in utility costs for the CTL plant because of better economies of scale. 
     Fuel gas produced by the CTL facility, which in many cases would be purged, can be used as fuel in the IGCC facility, e.g. in heat recovery units of the IGCC facility. This allows the production of steam at a higher pressure and/or a higher temperature. As the fuel gas will come as internal transfer from a large scale facility, costs will be reduced. From the perspective of the CTL facility, this option provides an internal and assured consumer for the fuel gas stream. 
     Power for internal consumption on the CTL facility is generated at optimal cost and efficiency, improving the overall carbon and plant efficiency of the integrated CTL and IGCC facilities compared to that of two stand-alone facilities. 
     Finally, the integration of a CTL facility and an IGCC facility allows capturing of CO 2  from the off-gas of the IGCC facility. This is achieved by directing a portion of the CO 2  produced in the CTL facility, to the compressor of the gas turbine expander of the IGCC facility, together with pure oxygen from an air separation unit, thereby avoiding the introduction of nitrogen into the combustor of the IGCC facility. This allows the gas turbine to be run using a mixture of oxygen and CO 2  instead of a conventional mixture of oxygen and N 2  when air is used. The final off-gas from the IGCC facility will thus be a relatively pure combination of CO 2  and water vapour, which can be combined with the remaining CO 2  produced by the CTL facility for export, allowing the CO 2  processing and compression facilities to benefit from an increased economy of scale.