Abstract:
A process and an installation produces electric power or cogenerates electric and thermal power. A hydrocarbon fuel is enriched through an endothermic reforming reaction on a mixture of the fuel with steam or water. The heat for the reforming reaction is supplied by the combustion of a material, preferably biomass, different from the hydrocarbon fuel. The process integrates this reforming reaction in a gas turbine installation, wherein up to 12% of the exhaust gases of the gas turbine are used as comburant air for the combustion of the material. The process is shown to have little or even no impact on the gas turbine cycle performance when no reforming is applied.

Description:
FIELD OF THE INVENTION 
       [0001]    The present invention is related to a process and system for the operation of a gas turbine, involving methane-steam reforming of natural gas, used in the gas turbine&#39;s combustor. 
       STATE OF THE ART 
       [0002]    Methane-steam reforming in gas turbine cycles is known. Two relevant papers in this respect are ‘A methane-steam reformer for a basic chemically recuperated gas turbine’, Adelman et al, Transactions of the ASME, vol 117, January 1995 (pp. 16-23) and more recently ‘The recuperative auto thermal reforming and recuperative reforming gas turbine power cycles with CO2 removal—Part II: The recuperative reforming cycle’, Fiaschi et al Transactions of the ASME, vol. 126, January 2004 (pp. 62-68). Such ‘Chemically Recuperated Cycles’ use a methane-steam reformer in order to extract heat from the full gas turbine exhaust stream, and transform this heat into chemical energy in the syngas (Adelman). Temperatures in the gas turbine exhausts are however too low to achieve a high amount of reforming, and the obtained energy recovery is therefore too limited for practical application. Fiaschi et al overcome this problem by adding post-combustion of natural gas in the full exhaust of the gas turbine. They use the reforming not for purposes of heat recovery, but to capture CO 2  from the fuel feed prior to the combustion process. 
         [0003]    Another application of reforming is described in documents WO-A-0142636 and US20040206065. In these documents a reforming process is proposed to enrich fuels with low methane concentration with hydrogen. The syngas is dried in order to deliver a syngas suitable for use in gas turbines. The process integration is not further detailed. Document GB-A-2305186 is related to a fuel reforming apparatus and electric power generating system, wherein reforming of fuel gas takes place through a partial combustion of the gas, while mixing the gas with steam. The proposed process cannot be applied directly to biomass because the combustion gases enter the gas turbine expander. 
         [0004]    Document DE19627189 proposes the use of reforming to replace part of the natural gas by coal in a repowered coal steam plant. The reformer is included in the bottom part of the coal furnace, where heat from the coal is used to realize the reforming reaction. The comburant air for the coal combustion is either atmospheric air, or a mixture of air with all of the turbine exhaust gases. Document DE19627189 is applicable only to coal plants repowered with a gas turbine, it is not applicable to highly efficient natural gas combined cycles. There is no further process integration. Power production from biomass can occur through conventional external combustion (steam cycle, organic Rankine Cycle, Stirling engines), or internal combustion after gasification or pyrolysis (gas engine, Integrated Gasiffrcation Combined Cycle). External combustion has the disadvantage of delivering limited conversion efficiencies (max 30-35%), but it is easier to achieve and it needs no severe gas cleaning. Internal combustion has the potential of high efficiencies, but it always needs a severe and mostly problematic gas cleaning. 
       AIMS OF THE INVENTION 
       [0005]    The present invention aims to provide an alternative heat source for the methane-steam reforming process, incorporated into a gas turbine installation. 
       SUMMARY OF THE INVENTION 
       [0006]    The present invention discloses a new process and installation as disclosed in the appended claims. The invention allows to combine natural gas with the combustion of a combustible material other than the gas, in any type of gas turbine plant. According to the preferred embodiment, biomass is used as the combustible material in question. The process avoids any contact between the biomass combustion gases and the internals of the turbine, and is shown to have little or even no impact on the gas turbine cycle performance. In this process, the biomass is used as energy source to provide heat for the endothermic methane-steam reforming reaction, yielding hydrogen, carbon monoxide and carbon dioxide as reaction products. According to the invention, this reforming uses an external heat supply, obtained from the (external) combustion of biomass at 600 to 750° C. The heat contained in the biomass combustion flue gas can thus be transmitted to the natural gas and steam mixture, and transformed into chemical energy through formation of hydrogen. The biomass combustion gases do not mix with the natural gas fuel or with any other flow through the gas turbine, thus avoiding problems such as fouling or corrosion and consequent severe gas cleaning. The obtained syngas can be used in a gas turbine without significant loss of cycle efficiency when using the proposed heat exchanger network in the periphery of the reformer. Biomass can therefore be transformed into electric power at nearly the same efficiency as the considered gas turbine plant, which in the case of combined cycles can exceed 50%. 
     
    
     
       SHORT DESCRIPTION OF THE DRAWINGS 
         [0007]      FIG. 1  represents the basic embodiment of a system according to the invention. 
           [0008]      FIG. 2  represents a first variant of the system, involving a steam-injected gas turbine. 
           [0009]      FIG. 3  represents a second variant of the system, involving a natural gas saturation tower. 
           [0010]      FIG. 4  represents a third variant of the system, involving a means for drying the syngas. 
           [0011]      FIG. 5  illustrates a working example based on the installation of  FIG. 4 . 
       
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
       [0012]    The process of the invention can be described as comprising the following steps, with reference to  FIGS. 1 to 4 :
       providing a supply  9  of natural gas,   providing a supply  22  of water,   possibly, pre-heating ( 10 ) all or a part  9   a  of the natural gas supply,   mixing the (pre-heated) natural gas and the water to obtain a mixture. The mixture can be obtained either by producing steam ( 8 ) and mixing it ( 23 ) with the pre-heated natural gas, or by pre-heating the water supply and mixing it with the (non-pre-heated) natural gas in a saturation tower  13 ,   pre-heating ( 11 ) the mixture,   combusting a supply  30  of combustible material, different from the natural gas supply, and using the heat produced by the combustion to heat up the mixture without direct contact between the mixture and the combustion gases of the combustion ( 12 ), in order to provoke methane-steam reforming reactions to take place in the mixture, thereby obtaining an enriched natural gas. According to the preferred embodiment of the invention, the combustible material used is biomass.   cooling the enriched natural gas ( 11 , 10 ) to a temperature above the dewpoint,   using the enriched natural gas as fuel in the combustion chamber  3  of a gas turbine installation,
 
According to the invention, the process further comprises the steps of:
   using a part of the exhaust gases ( 5 ) of the gas turbine installation, as comburant air for the combustion of combustible material. According to the preferred embodiment, the amount of exhaust gases diverted for this use is maximum 12% of the gas turbine exhaust stream.   using the combustion gases of the combustion for pre-heating said exhaust gases, and for the heating of the water supply, either to produce steam, or to pre-heat the water prior to its entry in the saturation tower.       
 
         [0023]      FIGS. 1 to 4  will now be described in more detail, in order to fully explain the prominent embodiments of the process described above. The following explanation also serves as a full disclosure of the installation of the invention, and its various embodiments. 
         [0024]    The basic installation is shown in  FIG. 1 . A standard gas turbine plant with compressor  1 , expander  2  and combustion chamber  3  is used. The gas turbine may be part of a Combined Cycle, in which case steam ( 21 ) is produced downstream of the gas turbine exhaust in heat exchanger  4  and used for extra power production through expansion in steam turbines (not shown), while the exhaust gases flow towards the stack  20 . Items  1  to  4  are conventional equipment in a conventional process. The invention consists in the addition of the items  5  to  12 . 
         [0025]    According to the process of the invention, a part of the turbine exhaust is diverted through conduit  5  as comburant air to a combustor  6 , being a biomass combustor, fed by a biomass supply  30 , according to the preferred embodiment. According to a preferred embodiment, the amount of diverted turbine exhaust gases is proportional to the amount of biomass burnt, provided the excess oxygen level of the biomass combustor is kept constant (6% excess oxygen has been assumed). According to simulation, the replacement of each 1% of natural gas by biomass thus needs about 1.2% of the turbine exhaust gases as comburant air. The theoretical maximum of heat which can be supplied to the reformer corresponds to 100% reforming of the methane and represents about 10% of the natural gas feed  9 , which puts the maximum of turbine exhaust diversion (proportional to the amount of biomass burnt) to about 12%. In reality, it is difficult to transform all of the methane in a single allothermal reformer and a realistic limit is about 5% replacement, corresponding to about 6% of turbine exhaust diversion. 
         [0026]    The steam production in the bottoming cycle  21  is reduced accordingly with maximum 6% depending on the amount of biomass. The comburant air is preheated through a regenerator  7  prior to the biomass combustion chamber  6 . The heat for this regeneration is supplied by the combustion gases of the biomass combustion. The biomass stack gas is used to heat water supply  22  in order to produce steam in the heat exchanger B. Because of similar temperatures and flow rates, this extra amount of steam is almost equivalent to the reduced amount of steam in the bottom cycle  21 . 
         [0027]    Part of the natural gas feed  9  is preheated through a regenerator  10 , after desulfurization (not shown). In a mixer  23 , this gas is mixed with the steam coming from the boiler  8 . The gas/steam mixture is further preheated through a regenerator  11 , before entering the reformer  12  at about 600° C. The amount of gas is adjusted to achieve a molar steam to carbon ratio of 1.5 to 2 in the reformer  12 . Heat is taken from the biomass combustion gases to feed the reforming reactions, which essentially consist of the following 
         [0000]      CH4+H2O&lt;&gt;CO+3H2 (206 kJ/mol) 
         [0000]      CO+H2O&lt;&gt;CO2+H2 (−41 kJ/mol) 
         [0028]    The temperature during this reaction is preferably in excess of 600° C. up to 750° C. The reforming reaction is endothermic, and the gas stream thus absorbs a part of the energy from the biomass combustor  6 . The produced enriched gas, also called ‘syngas’, thus contains up to 5% energy obtained from biomass through the reforming process, mainly through hydrogen enrichment. The syngas is next cooled in regenerators  11  and  10 , thereby pre-heating the mixture and the natural gas supply respectively. The enriched gas can be cooled to some 100° C. to 200° C. depending on the gas turbine specifications, but its temperature must be kept above the gas dewpoint. If possible, the syngas temperature should be kept at 300° C. or more to achieve the highest marginal efficiency for the biomass. The enriched gas is then mixed with the non-enriched gas stream in mixer  24 , after which this mixture is fed to the gas turbine&#39;s combustion chamber  3 . 
         [0029]    A second embodiment of the process and installation of the invention is shown in  FIG. 2 . The installation comprises an additional conduit  25  for the injection of steam, produced in the heat exchanger  4 , into the gas turbine&#39;s combustion chamber  3 . In the basic cycle of  FIG. 1 , it can be shown that a significant increase in the combustor inlet gas temperature is needed to keep the overall cycle efficiency constant (400° C. or more for replacement of 5% natural gas by biomass). When applying the process directly in steam injected gas turbines, as shown in  FIG. 2 , it can be shown that the cycle efficiency can be kept constant without the necessity of such an increase. 
         [0030]    According to a third embodiment, shown in  FIG. 3 , instead of producing steam in a boiler, the natural gas is mixed with water which has been pre-heated in the liquid phase, the mixing and the evaporation taking place in a saturation tower  13 . In such a saturation tower, the evaporation of the water occurs at a non-constant temperature, and the exiting gas is almost saturated with water. In this case, the feedwater  22  is preheated in the liquid phase by the biomass combustion gases in heat exchanger  14 . Both streams are mixed in countercurrent in the saturation tower  13  where excess water is circulated through a pump  26 , taking up heat in the liquid phase from the biomass combustion gases in heat exchanger  15 . After exit of the tower, the mixture is further preheated by the biomass combustion gases in heat exchanger  16 , and routed to the syngas regenerator  11 . The remainder of the installation is identical to the basic scheme of  FIG. 1 . The installation of  FIG. 3  allows less stringent quality requirements of the consumed water, because of the washing effect of a saturation tower, and because salts are concentrated in the recirculating water rather than being injected in the gas turbine. Desulfurisation can be included in the saturation tower through the washing effect of the water spray. The recirculating water concentrates salts and sulfur residues and needs refreshment. 
         [0031]    A fourth embodiment is shown in  FIG. 4 . This installation is equipped with a means for further cooling and drying the syngas after the regenerator  11 . This is achieved with a condenser  17 , which uses the water and natural gas feeds ( 22 , 9 ) as coldest coolants. After the condenser, the gas stream is split ( 31 ) into streams  9   a  and  9   b , the latter being fed to the saturator  13  and on towards the reformer  12 . The enriched gas is mixed again ( 32 ) with the non-enriched gas stream  9   a , before going to heat exchanger  19 . After the condenser, the feedwater is mixed with condensed water from the condenser itself. This rerouting of the condense water reduces the amount of consumed water by about 65%. The mix of feedwater/condense water is then mixed with the water leaving the saturation tower  13 , and this mixture is further used as major coolant ( 18 ) in the condenser. After  18 , the water flow is circulating back to the tower through pump  26 , the circulating water being itself heated in the liquid phase in heat exchanger  15 . 
         [0032]    The syngas obtained in the saturation tower, is heated in the regenerator  11 , and reformed in the reformer  12 , as in the previous embodiments. After being cooled in the condenser  17 , the cold syngas is reheated by the biomass combustion gases in heat exchanger  19 , before entering the gas turbine&#39;s combustion chamber  3 . 
         [0033]    Compared to the basic system of  FIG. 1  and the embodiment of  FIG. 3 , the drying of the syngas allows to reduce considerably the water consumption and it can be shown that the overall efficiency slightly improves. 
         [0034]      FIG. 5  shows the result of a thermodynamic simulation of the process described in  FIG. 4 . The pressure ratio is assumed to be 20, the turbine inlet temperature is 1273° C., isentropic efficiencies in compressor and turbine are 90%. The gas supply is assumed to be pure methane. The head loss in the main combustor is 5%, and 3% in the other components. 10% of the compressor flow is assumed to bypass the turbine for cooling purposes. The process is calculated for a reference mass flow rate of 1 kg/s in the compressor. The saturator exit temperature is adjusted to yield a Steam to Carbon ration of 2 in the reformer, and the amount of gas in  9   b  is adjusted to yield a power contribution from biomass of 5%, leading to a water consumption of 0.0056 kg/s. The gas reaching the combustor ( 3 ) consists of (by volume) 39.5% hydrogen 49.3% methane, 7.1% carbon dioxide, 3.7% carbon monoxide and 0.3% water. In conclusion, a cycle efficiency is found of 54.9%, which is the same as the cycle efficiency obtained if no addition of biomass is assumed, provided the combustor gas is heated to 440° C. The example is given as illustration and is not limitative. 
         [0000]    Table 1 lists the heat fluxes in the different components, according to the numbering in  FIG. 4 . Table 2 lists the flow properties according to the numbering in  FIG. 5 . The numbering  FIG. 5  is only to be read in combination with the data in table 2, not with the remainder of this description. 
         [0000]    
       
         
               
               
               
             
               
               
               
             
           
               
                   
                 TABLE 1 
               
               
                   
                   
               
               
                   
                 Component 
                 Exchanged heat 
               
               
                   
                 (FIG. 2) 
                 (kJ per kg compressor flow) 
               
               
                   
                   
               
             
             
               
                   
               
             
          
           
               
                   
                 07 regenerator 
                 13 
               
               
                   
                 11 regenerator 
                 31 
               
               
                   
                 12 reformer 
                 41 
               
               
                   
                 13 feedwater saturator 
                 9 
               
               
                   
                 17 gas preheating 
                 1 
               
               
                   
                 17 water preheating 
                 1 
               
               
                   
                 18 main condensation 
                 49 
               
               
                   
                 19 gas reheater 
                 27 
               
               
                   
                   
               
             
          
         
       
     
         [0000]    
       
         
               
               
               
               
             
               
               
               
               
             
           
               
                   
                 TABLE 2 
               
               
                   
                   
               
               
                   
                 Stream (FIG. 5) 
                 flow(kg/s) 
                 Temp(C.) 
               
               
                   
                   
               
             
             
               
                   
               
             
          
           
               
                   
                  1 compressor in 
                 1.000 
                 20 
               
               
                   
                  2 compressor out 
                 1.000 
                 444 
               
               
                   
                  3 combustor out 
                 1.024 
                 1273 
               
               
                   
                  4 turbine out 
                 1.024 
                 531 
               
               
                   
                  5 to bottom HRS 
                 0.959 
                 531 
               
               
                   
                  6 to biomass combustor 
                 0.064 
                 531 
               
               
                   
                  7 after preheating 
                 0.064 
                 650 
               
               
                   
                  8 biomass stack 
                 0.065 
                 100 
               
               
                   
                  9 natural gas in 
                 0.018 
                 20 
               
               
                   
                 10 water in 
                 0.005 
                 20 
               
               
                   
                 11 condensor knock-out 
                 0.014 
                 50 
               
               
                   
                 12 saturator knock-out 
                 0.050 
                 49 
               
               
                   
                 13 water recirculation 
                 0.071 
                 185 
               
               
                   
                 14 water saturator in 
                 0.071 
                 211 
               
               
                   
                 15 gas saturator in 
                 0.007 
                 40 
               
               
                   
                 16 gas saturator out 
                 0.027 
                 196 
               
               
                   
                 17 gas mixture reformer in 
                 0.027 
                 650 
               
               
                   
                 18 syngas reformer out 
                 0.027 
                 700 
               
               
                   
                 19 syngas condensor in 
                 0.027 
                 285 
               
               
                   
                 20 gas mixture reheater in 
                 0.024 
                 50 
               
               
                   
                 21 gas combustor in 
                 0.024 
                 441