Patent Publication Number: US-2010126135-A1

Title: Method and apparatus for operating an integrated gasifier power plant

Description:
BACKGROUND OF THE INVENTION 
     The subject matter disclosed herein relates to integrated gasification combined cycle (IGCC) power generation systems and, more specifically, to IGCC power generation systems with load-following capabilities. 
     In general, IGCC power plants are capable of generating energy from various hydrocarbon feedstock, such as coal, relatively cleanly and efficiently. IGCC technology may convert the hydrocarbon feedstock into a gas mixture of carbon monoxide (CO) and hydrogen (H 2 ) by reaction with steam. These gases may be cleaned, processed, and utilized as fuel in a conventional combined cycle power plant. Coal gasification processes may utilize compressed air or oxygen to react with the coal to form the CO and H 2 . These processes may generally take place at relatively high pressures and temperatures and may generally be more efficient at design point conditions. As such, the coal gasification processes cannot be turned down without loss of efficiency and durability. As a result, an IGCC power plant utilizing coal cannot easily follow grid loads during periods of low demand. Rather, during periods of low demand, shutdowns and reduced power generation from the IGCC power plant, as well as other plants, may be required. 
     BRIEF DESCRIPTION OF THE INVENTION 
     In one embodiment, a method includes converting a hydrocarbon feedstock into a gas mixture. The method also includes burning a first portion of the gas mixture within a combustion chamber. The method further includes converting a second portion of the gas mixture into methanol during periods of low demand for the gas mixture within the combustion chamber. 
     In another embodiment, a combined cycle power generation system is provided. The system includes a gasifier configured to convert coal into a gas mixture. The system also includes a combined cycle gas turbine configured to receive and burn a first portion of the gas mixture as a fuel source. The system further includes a methanol plant configured to receive and convert a second portion of the gas mixture into methanol during periods of low demand for the combined cycle gas turbine. 
     In yet another embodiment, a methanol generation and storage system is provided. The system includes a methanol plant configured to receive a variable portion of a gas mixture from a gasifier and to convert the variable portion of the gas mixture into methanol. The system also includes a storage tank configured to store the methanol and to deliver the methanol for subsequent use as a fuel source. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       These and other features, aspects, and advantages of the present invention will become better understood when the following detailed description is read with reference to the accompanying drawings in which like characters represent like parts throughout the drawings, wherein: 
         FIG. 1  is a schematic flow diagram of an embodiment of a combined cycle power generation system having a gas turbine, a steam turbine, and a heat recovery steam generation system; 
         FIG. 2  is a schematic flow diagram of an embodiment of a coal gasification process of an IGCC power generation system; 
         FIG. 3  is a chart of daily variation of grid loads experienced by an embodiment of the coal gasification process of  FIG. 2 ; 
         FIG. 4  is a schematic flow diagram of an embodiment of a coal gasification process of an IGCC power generation system, including a methanol plant and associated storage tanks; 
         FIG. 5  is a chart of daily variation of grid loads experienced by an embodiment of the coal gasification process of  FIG. 4 ; and 
         FIG. 6  is a flow chart of an embodiment of a method for producing and storing methanol for use in an IGCC power generation system. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     One or more specific embodiments of the present invention will be described below. In an effort to provide a concise description of these embodiments, all features of an actual implementation may not be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers&#39; specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure. 
     When introducing elements of various embodiments of the present invention, the articles “a,” “an,” “the,” and “said” are intended to mean that there are one or more of the elements. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. 
     In certain embodiments, the systems and methods described herein include integrating a methanol plant into an IGCC power generation system. A gas mixture produced by a gasification process of the IGCC power generation system may be converted into methanol. In particular, excess volumes of the gas mixture may be converted into methanol and stored in storage tanks. For instance, during periods of low power demand, excess volumes of the gas mixture not required by the IGCC power generation system may be converted into methanol and stored in the storage tanks. Then, during periods of high power demand, the power output of the IGCC power generation system may be supplemented by a peaking cycle power generation system utilizing at least some of the methanol stored in the storage tanks as a fuel source. By more efficiently utilizing the gas mixture produced by the gasification process, the IGCC power generation system may become both more flexible and more self-sustainable. Moreover, the gasifier units used in the gasification process may be reduced in size, leading to overall cost reductions. In addition, by running the gasifier units at a more constant production rate, operating costs as well as long-term damage to the gasifier may be minimized. 
       FIG. 1  is a schematic flow diagram of an embodiment of a combined cycle power generation system  10  having a gas turbine, a steam turbine, and a heat recovery steam generation (HRSG) system. The system  10  may include a gas turbine  12  for driving a first load  14 . The first load  14  may, for instance, be an electrical generator for producing electrical power. The gas turbine  12  may include a turbine  16 , a combustor or combustion chamber  18 , and a compressor  20 . The system  10  may also include a steam turbine  22  for driving a second load  24 . The second load  24  may also be an electrical generator for generating electrical power. However, both the first and second loads  14 ,  24  may be other types of loads capable of being driven by the gas turbine  12  and steam turbine  22 . In addition, although the gas turbine  12  and steam turbine  22  may drive separate loads  14  and  24 , as shown in the illustrated embodiment, the gas turbine  12  and steam turbine  22  may also be utilized in tandem to drive a single load via a single shaft. In the illustrated embodiment, the steam turbine  22  may include one low-pressure section  26  (LP ST), one intermediate-pressure section  28  (IP ST), and one high-pressure section  30  (HP ST). However, the specific configuration of the steam turbine  22 , as well as the gas turbine  12 , may be implementation-specific and may include any combination of sections. 
     The system  10  may also include a multi-stage HRSG  32 . The components of the HRSG  32  in the illustrated embodiment are a simplified depiction of the HRSG  32  and are not intended to be limiting. Rather, the illustrated HRSG  32  is shown to convey the general operation of such HRSG systems. Heated exhaust gas  34  from the gas turbine  12  may be transported into the HRSG  32  and used to heat steam used to power the steam turbine  22 . Exhaust from the low-pressure section  26  of the steam turbine  22  may be directed into a condenser  36 . Condensate from the condenser  36  may, in turn, be directed into a low-pressure section of the HRSG  32  with the aid of a condensate pump  38 . 
     The condensate may then flow through a low-pressure economizer  40  (LPECON), a device configured to heat feedwater with gases, which may be used to heat the condensate. From the low-pressure economizer  40 , the condensate may either be directed into a low-pressure evaporator  42  (LPEVAP) or toward an intermediate-pressure economizer  44  (IPECON). Steam from the low-pressure evaporator  42  may be returned to the low-pressure section  26  of the steam turbine  22 . Likewise, from the intermediate-pressure economizer  44 , the condensate may either be directed into an intermediate-pressure evaporator  46  (IPEVAP) or toward a high-pressure economizer  48  (HPECON). In addition, steam from the intermediate-pressure economizer  44  may be sent to a fuel gas heater (not shown) where the steam may be used to heat fuel gas for use in the combustion chamber  18  of the gas turbine  12 . Steam from the intermediate-pressure evaporator  46  may be sent to the intermediate-pressure section  28  of the steam turbine  22 . Again, the connections between the economizers, evaporators, and the steam turbine  22  may vary across implementations as the illustrated embodiment is merely illustrative of the general operation of an HRSG system that may employ unique aspects of the present embodiments. 
     Finally, condensate from the high-pressure economizer  48  may be directed into a high-pressure evaporator  50  (HPEVAP). Steam exiting the high-pressure evaporator  50  may be directed into a primary high-pressure superheater  52  and a finishing high-pressure superheater  54 , where the steam is superheated and eventually sent to the high-pressure section  30  of the steam turbine  22 . Exhaust from the high-pressure section  30  of the steam turbine  22  may, in turn, be directed into the intermediate-pressure section  28  of the steam turbine  22 . Exhaust from the intermediate-pressure section  28  of the steam turbine  22  may be directed into the low-pressure section  26  of the steam turbine  22 . 
     An inter-stage attemperator  56  may be located in between the primary high-pressure superheater  52  and the finishing high-pressure superheater  54 . The inter-stage attemperator  56  may allow for more robust control of the exhaust temperature of steam from the finishing high-pressure superheater  54 . Specifically, the inter-stage attemperator  56  may be configured to control the temperature of steam exiting the finishing high-pressure superheater  54  by injecting cooler feedwater spray into the superheated steam upstream of the finishing high-pressure superheater  54  whenever the exhaust temperature of the steam exiting the finishing high-pressure superheater  54  exceeds a predetermined value. 
     In addition, exhaust from the high-pressure section  30  of the steam turbine  22  may be directed into a primary re-heater  58  and a secondary re-heater  60  where it may be re-heated before being directed into the intermediate-pressure section  28  of the steam turbine  22 . The primary re-heater  58  and secondary re-heater  60  may also be associated with an inter-stage attemperator  62  for controlling the exhaust steam temperature from the re-heaters. Specifically, the inter-stage attemperator  62  may be configured to control the temperature of steam exiting the secondary re-heater  60  by injecting cooler feedwater spray into the superheated steam upstream of the secondary re-heater  60  whenever the exhaust temperature of the steam exiting the secondary re-heater  60  exceeds a predetermined value. 
     In combined cycle systems such as system  10 , hot exhaust gas  34  may flow from the gas turbine  12  and pass through the HRSG  32  and may be used to generate high-pressure, high-temperature steam. The steam produced by the HRSG  32  may then be passed through the steam turbine  22  for power generation. In addition, the produced steam may also be supplied to any other processes where superheated steam may be used. The gas turbine  12  cycle is often referred to as the “topping cycle,” whereas the steam turbine  22  generation cycle is often referred to as the “bottoming cycle.” By combining these two cycles as illustrated in  FIG. 1 , the combined cycle power generation system  10  may lead to greater efficiencies in both cycles. In particular, exhaust heat from the topping cycle may be captured and used to generate steam for use in the bottoming cycle. 
     The combined cycle power generation system  10  illustrated in  FIG. 1  may be converted into an IGCC power generation system  10  by introducing a gasifier  64  into the system  10 . In a coal gasification process, performed within the gasifier  64 , rather than burning the coal, the gasifier  64  may break down the coal chemically due to the interaction with steam and the high pressure and temperature within the gasifier  64 . From this process, the gasifier  64  may produce a gas mixture  66  of primarily CO and H 2 . This gas mixture  66  is often referred to as “syngas” and may be burned, much like natural gas, within the combustion chamber  18  of the gas turbine  12 . As will be described in greater detail below, the gas mixture  66  may also be converted into methanol, which may be burned within the combustion chamber  18  as well. In addition, at least some of the produced methanol may be stored within storage tanks for later use within either the combustion chamber  18  or other processes within or external to the combined cycle power generation system  10  of  FIG. 1 . 
       FIG. 2  is a schematic flow diagram of an embodiment of a coal gasification process  68  of an IGCC power generation system  10 . As discussed above, the coal gasification process  68  may include the gasifier  64 . The gasifier  64  may receive coal and water, such as steam, as inputs. Steam received by the gasifier may, for instance, be received from processes either within or external to the IGCC power generation system  10 . For example, in certain embodiments, the steam may be received from the bottoming cycle of the IGCC power generation system  10 , as illustrated in  FIG. 1 . However, the steam may also be received from various other processes within the IGCC power generation system  10  as well as from external sources. 
     The gasifier  64  may also receive high pressure oxygen (O 2 ) from an air separation unit  70 . More specifically, the air separation unit  70  may receive compressed air and generate high pressure O 2  as an oxidant for use in the gasifier  64 . The compressed air received by the air separation unit  70  may, for instance, be received from processes either within or external to the IGCC power generation system  10 . For example, in certain embodiments, the compressed air may be received from the gas turbine compressor  20  of the gas turbine  12  of the IGCC power generation system  10 . However, the compressed air may also be received from various other processes within the IGCC power generation system  10 , as well as from external sources. In addition, in certain embodiments, nitrogen (N 2 ) generated by the air separation unit  70  may also be directed toward other processes, such as the gas turbine  12 . 
     As discussed above, the coal received by the gasifier  64  may be reacted at high pressures and temperatures with the O 2  and steam to form a gas mixture of CO and H 2  as well as other components generated by the chemical reactions within the gasifier  64 . These other components may include sulfur (S) and associated sulfides such as hydrogen sulfide and carbonyl sulfide, mercury (Hg), ammonia, slag, and other particulates. However, the primary components of the gas mixture produced by the gasifier  64  are CO and H 2 . The gas mixture produced by the gasifier  64  may be sent to a gas cleanup tower  72 , where the contaminants present in the gas mixture may be removed. For instance, the sulfur and associated sulfides, mercury, ammonia, slag, and other particulates may be removed, leaving only a substantially pure form of syngas (i.e., CO and H 2 ). The removal of contaminants may, for instance, include the use of scrubbers or dry filtration equipment for removing solid particulates, the use of solvents for removing the sulfides, and so forth. It should also be noted that, in certain embodiments, any carbon dioxide (CO 2 ) captured by the gas cleanup tower  72  may be sequestered. 
     The gas mixture produced by the gasifier  64  may have a very high temperature due to the high pressures and temperatures used in the chemical processes of the gasifier  64 . Therefore, the gas cleanup tower  72  may also include a gas cooling unit, which may cool the hot gas mixture before removing the contaminants. The heat extracted from the hot gas mixture may be captured and used in other processes. In addition, the gas cleanup tower  72  may also include other various sub-systems for conditioning the gas mixture. In general, the gas cleanup tower  72  may ensure that the syngas generated by the gasifier  64  is characterized by appropriate temperatures, pressures, chemical compositions, stoichiometric parameters, and so forth, such that the syngas may be burned efficiently within the combustion chamber  18  of the gas turbine  12  of the IGCC power generation system  10 . 
     Therefore, the gasifier  64 , in association with the air separation unit  70  and the gas cleanup tower  72 , may generate CO and H 2  which may be used as a fuel source to drive the generation of power within the topping cycle of the IGCC power generation system  10 . However, as discussed above, one characteristic of gasifiers in general is that they operate at high pressures and temperatures and work most efficiently at design point conditions. Therefore, the gasifier  64  may not be capable of being operated at conditions other than design point conditions without loss of efficiency and durability. More specifically, the gasifier  64  may not be capable of being turned down (i.e., operating at lower outputs than a design point) during periods of low power demand. 
       FIG. 3  is a chart  74  of daily variation of grid loads experienced by an embodiment of the coal gasification process  68  of  FIG. 2 . More specifically, the chart  74  depicts the daily variation of grid loads that may be demanded of the gas turbine  12  which may be fueled by CO and H 2  from the gasification process  68  of  FIG. 2 . As shown in  FIG. 2 , the grid load requirements  76  of the gas turbine  12  and, therefore, the gasification process  68  may change over the course of a day. Specifically, the grid load requirements  76  may increase from a low demand point  78 , which may generally occur a few hours after midnight, to a peak load demand point  80 , which may generally occur a few hours after noon. 
     The gasification process  68  may be designed to produce enough of the gas mixture such that the gas turbine  12  may meet an average daily load  82 , which is somewhere between the low demand point  78  and the peak load demand point  80 . However, operating the gasification process  68  at the average daily load  82  may, as mentioned above, be problematic in that the gasification process  68  may not easily be turned down during low demand periods. Therefore, during these low demand periods, the coal conversion capabilities of the gasification process  68  and, more specifically, the gasifier  64  may be underutilized, as indicated by regions  84 . In particular, since the gasification process  68  may not be turned down during low demand periods, the power generated by the gas turbine  12  may simply be wasted during these low demand periods. Thus, it is desirable to convert gas fuel into methanol to facilitate storage during lower than average demand periods and burn methanol in the power plant during high demand periods, allowing for the use of an optimally sized gasifier  64 . 
     Another option for sizing the gasification process  68  may be to ensure that the gasification process  68  may produce only enough of the gas mixture such that the gas turbine  12  may meet a base load  86 , which corresponds to the grid load requirements  76  at the low demand point  78 . However, under this design scenario, any excess power requirements would need to be met by other power generation sources, such as peak loading facilities. Moreover, designing the gasification process  68 , as well as the IGCC power generation system  10  in general, at the lower base load may not allow for capturing economies of scale. Therefore, the first scenario discussed above, where the gasification process  68  is operated to produce enough of the gas mixture such that the gas turbine  12  may meet the average daily load  82  may be a better alternative. However, in order to fully utilize the capacity of the gasification process  68  and associated gasifier  64 , the underutilization of coal during low demand periods and the shortage of power during peak loading periods may be addressed using the techniques described herein. 
     In particular,  FIG. 4  is a schematic flow diagram of an embodiment of a coal gasification process  88  of an IGCC power generation system  10 , including a methanol plant  90  and associated storage tanks  92 . In general, the methanol plant  90  may be configured to convert the gas mixture of CO and H 2  into methanol (CH 3 OH). Methanol is a liquid which is suitable for combustion within the combustion chamber  18  of the gas turbine  12 . However, the storage density of methanol is considerably higher than that of the individual components CO and H 2 . In other words, a given mass of methanol may require less volume than a similar mass of the individual components CO and H 2 . For instance, the difference in storage densities between the two may be on the order of 1,000. Therefore, it may be possible to store 1,000 times more methanol than CO and H 2  within a given storage volume. In addition, it may be possible to store the same amount of methanol within a storage volume which is about 1/1,000 th  of that required for a similar amount of CO and H 2 . As such, methanol may be much more easily stored within the storage tanks  92  as compared to CO and H 2 . In other words, storing CO and H 2  within the storage tanks  92  may not be economically feasible in that the storage tanks  92  would require being sized exceedingly large and, therefore, would probably not be practical, from both an operational and economic standpoint. However, converting the CO and H 2  into methanol may make the prospect of storage much more feasible. Additionally, methanol is generally safe to store and transport. As such, methanol may be used as a transportation fuel as well as being transported to various off-site facilities via trucks, pipelines, and so forth. 
     As illustrated in  FIG. 4 , a portion of the CO and H 2  gas mixture, instead of being burned within the combustion chamber  18  of the gas turbine  12 , may be directed into the methanol plant  90 . In particular, a flow control valve  94  may control the distribution of the CO and H 2  gas mixture into the methanol plant  90 . Once in the methanol plant  90 , the CO and H 2  gas mixture may be converted into methanol and may, subsequently, be stored in the storage tanks  92 . At least some of the methanol stored in the storage tanks may then be utilized by a peaking cycle gas turbine  96  to drive a peak load  98  (e.g., an electrical generator). The peaking cycle gas turbine  96  may include a turbine  100 , a combustor or combustion chamber  102 , and a compressor  104 . Therefore, at least some of the methanol stored in the storage tanks  92  may be used as a fuel source, which may be burned within the combustion chamber  102  of the peaking cycle gas turbine  96 . The peaking cycle gas turbine  96  may be capable of generating power during peak load periods. 
     For example, the loads  14  and  98  may include electrical generators, which generate electricity for a facility, an electrical power grid, equipment, or a combination thereof. The gas turbine  12  may drive the load  14  (e.g., electrical generator) during periods of low, medium, and high demand, while the gas turbine  96  may drive the load  98  (e.g., electrical generator) during periods of high demand to provide supplemental power. The methanol plant  90  and storage tanks  92  facilitate dense fuel storage (e.g., methanol) of excess gas fuel produced by the gasifier  64  and the gas cleanup tower  72 , but not used by the gas turbine  12  or other systems. 
     As such, during daily operation, the gasifier  64  may be run at constant conditions. However, using the present embodiments, the gasifier  64  and associated gasification process  88  may also be capable of addressing the underutilization of coal during low demand periods as well as the shortage of power during peak loading periods. Excess CO and H 2  gas mixture generated by the gasifier  64  but not necessary during low demand periods (i.e., during evenings and nights) may be sent to the methanol plant  90  for conversion into methanol and storage in the storage tanks  92 . Conversely, during peak load demand periods (i.e., during mornings and afternoons), at least some of the methanol from the storage tanks  92  may be burned within the combustion chamber  102  of the peaking cycle gas turbine  96 , generating supplementary power, which may be used to meet peak load power requirements. In other words, all of the gas fuel from the gasifier  64  and gas cleanup tower  72  is either used immediately by the gas turbine  12  and/or converted into methanol by the methanol plant  90  and stored in the storage tanks  92  for subsequent use as needed, for instance, by the gas turbine  96 . 
       FIG. 5  is a chart  106  of daily variation of grid loads experienced by an embodiment of the coal gasification process  88  of  FIG. 4 . The chart  106  illustrates how the present embodiments may improve the ability of the gasification process  88  to address the grid load requirements  76 . As in  FIG. 3 , discussed above, the grid load requirements  76  may increase from a low demand point  78 , which may generally occur a few hours after midnight, to a peak load demand point  80 , which may generally occur a few hours after noon. In addition, as in  FIG. 3 , the gasification process  88  may be operated to generate enough of the gas mixture such that the gas turbine  12  may meet the average daily load  82 , which is somewhere between the low demand point  78  and the peak load demand point  80 . 
     However, unlike in  FIG. 3 , the coal conversion capabilities of the gasification process  88  and, more specifically, the gasifier  64  will generally not be underutilized during low demand periods. Rather, during these low demand periods, methanol may be generated from the CO and H 2  gas mixture by the methanol plant  90  and stored in the storage tanks  92 , as indicated by regions  84 . In addition, during peak loading periods, at least some of the methanol stored in the storage tanks  92  may be burned within the combustion chamber  102  of the peaking cycle gas turbine  96  to generate enough supplementary power to meet peak load power requirements, as indicated by region  108 . In certain embodiments, the combined cycle power generation system  10  may include a controller configured to control the combined cycle power generation system  10  such that the methanol plant  90  converts the gas mixture into methanol during periods of low demand for the gas mixture and the storage tank  92  delivers at least some of the methanol during periods of high demand for the gas mixture. 
       FIG. 6  is a flow chart of an embodiment of a method  110  for producing and storing methanol for use in an IGCC power generation system  10 . In step  112 , coal may be converted into a gas mixture via the gasifier  64 . As discussed above, the coal gasification process within the gasifier  64  may break down the coal chemically with steam and high pressures and temperatures. The gas mixture may generally be composed of CO and H 2  and may be suitable as a fuel source within a combustion chamber of a gas turbine, such as the gas turbine  12  of the IGCC power generation system  10 . Although presented herein as a coal gasification process, it should be noted that the process carried out within the gasifier  64  need not be limited to the conversion of coal into a gas mixture. Rather, any suitable hydrocarbon feedstock may be converted into a gas mixture within the gasifier  64 . For instance, biomass and other forms of waste products and by-products may, in certain situations, be suitable for conversion into a gas mixture within the gasifier  64 . 
     In step  114 , the gas mixture may optionally be cooled. The cooling may be performed by a gas cooling unit of the gas cleanup tower  72 . However, the gas cooling unit may, in certain embodiments, be a separate component from the gas cleanup tower  72 . As discussed above, the extracted heat from the gas mixture may be captured and used within other processes, both within and external to the IGCC power generation system  10 . For instance, the extracted heat may be directed into a stage of the HRSG  32  and ultimately transferred into steam for use in the bottoming cycle of the IGCC power generation system  10 . Step  114  may generally be performed before step  116 . 
     In step  116 , contaminants and particulates may optionally be removed from the gas mixture via the gas cleanup tower  72 . As discussed above, these contaminants and particulates may include sulfur and associated sulfides, such as hydrogen sulfide and carbonyl sulfide, mercury, ammonia, slag, and other particulates. Solid particulates may be removed by scrubbers and dry filtration equipment, while sulfides and so forth may be removed using solvents. Once the gas mixture has been cleaned and processed, it may be used as a fuel source by, among other things, gas turbines such as the gas turbine  12  of the IGCC power generation system  10 . 
     Indeed, in step  118 , a first portion of the gas mixture may be burned within the combustion chamber  18  of the gas turbine  12  of the IGCC power generation system  10 . The gas mixture may first be split into a first portion (step  118 ), which may be directed toward the gas turbine  12  of the IGCC power generation system  10 , and a second portion (step  120 ), which may be directed toward the methanol plant  90 . As discussed above, the amount of gas mixture in each of these first and second portions may be controlled, at least in part, by the flow control valve  94 , illustrated in  FIG. 4  above. Furthermore, a control system may be configured to control the operation of the control valve  94  such that the first and second portions of the gas mixture are apportioned according to the particular needs of the IGCC power generation system  10 . 
     For instance, during periods of low demand for the gas turbine  12  of the IGCC power generation system  10 , the second portion directed toward the methanol plant  90  may be increased, such that only the amount of gas mixture required by the gas turbine  12  is directed toward the gas turbine  12 . Conversely, during periods of high demand for the gas turbine  12  of the IGCC power generation system  10 , the second portion directed toward the methanol plant  90  may be reduced, or even shut off, such that the gas turbine  12  receives a desired amount of the gas mixture. 
     In step  120 , the second portion of the gas mixture may be converted into methanol by the methanol plant  90 . For instance, as discussed above, the methanol plant  90  may convert the gas mixture into methanol during periods of low demand for the gas turbine  12  of the IGCC power generation system  10 . In step  122 , at least some of the methanol produced by the methanol plant  90  may optionally be stored within the storage tanks  92 . Storing the methanol in the storage tanks  92  is facilitated by the fact that the storage density of methanol may generally be considerably higher than that of the gas mixture. As such, it may be possible to store more methanol within a given storage volume. In addition, required storage volumes may be reduced due to the higher storage density of methanol. 
     The methanol produced by the methanol plant  90 , whether stored in the storage tanks  92  or not, may have several various uses. For example, in step  124 , at least some of the methanol may optionally be burned within the combustion chamber  102  of the peaking cycle gas turbine  96 . Specifically, as discussed in greater detail above, at least some of the methanol may be stored in the storage tanks  92  during periods of low demand for the gas turbine  12  of the IGCC power generation system  10 . This stored methanol may then be used by the peaking cycle gas turbine  96  during periods of high demand for the gas turbine  12  of the IGCC power generation system  10 . As such, the peaking cycle gas turbine  96  may function as a supplementary power source during peak load hours when the gas turbine  12  of the IGCC power generation system  10  may not be capable of generating sufficient power to meet the peak load power requirements. 
     However, the methanol produced by the methanol plant  90  may have various other uses within the IGCC power generation system  10 . For example, in certain embodiments, at least some of the methanol stored in the storage tanks  92  may be used by the gas turbine  12  of the IGCC power generation system  10 . For instance, during periods where the gas mixture is not being produced by the gasifier  64  (e.g., during periods where coal or other hydrocarbon feedstock are unavailable), the gas turbine  12  may simply use stored methanol in the storage tanks  92  as a fuel source. Furthermore, any processes (e.g., mobile power generation devices) of the IGCC power generation system  10  in which methanol may be used as a fuel source may utilize at least some of the methanol produced by the methanol plant  90 . In addition, at least some of the methanol may be used as a transportation fuel by vehicles used within the IGCC power generation system  10 . 
     However, there are also various other uses for the methanol produced by the methanol plant  90  in addition to using it as a fuel source by the combined cycle gas turbine  12 , the peaking cycle gas turbine  96 , or other processes of the IGCC power generation system  10 . In particular, at least some of the methanol produced by the methanol plant  90  may be used by several different types of off-site facilities. In the present context, “off-site facilities” is intended to mean facilities other than those directly associated with the IGCC power generation system  10 . In step  126 , at least some of the methanol produced by the methanol plant  90  may optionally be transported to various off-site facilities. For example, in certain embodiments, at least some of the methanol may be transported to other simple or combined cycle power plants where the methanol may be consumed to produce additional power. In other embodiments, at least some of the methanol may be distributed to other off-site facilities for use as a transportation fuel. Indeed, the methanol may be used as an added value stream by the IGCC power generation system  10  by transporting at least some of the methanol to any off-site facilities which may utilize methanol as a fuel source. 
     Technical effects of the invention include providing a methanol plant  90  and associated storage tanks  92  for producing and storing methanol for use within the IGCC power generation system  10 . Specifically, the gas mixture produced by the gasifier  64  may be converted into methanol, which may be stored much more cost-efficiently than the gas mixture. As such, the methanol may be produced and stored during periods of low demand for the gas turbine  12  of the IGCC power generation system  10 . Then, at least some of the stored methanol may used by the peaking cycle gas turbine  96  during periods of high demand for the gas turbine  12  of the IGCC power generation system  10 . In doing so, the IGCC power generation system  10  may be characterized by greater flexibility and enhanced self-sustainability. Specifically, the IGCC power generation system  10  may be better prepared to handle not only daily, but also longer-term, variations in power requirements. Moreover, this increased flexibility may also reduce the dependency of the IGCC power generation system  10  upon external sources of power, such as peaking plants. 
     In addition to allowing for greater flexibility and self-sustainability, by more efficiently utilizing the gas mixture produced by the gasifier  64 , it may be possible to reduce the size of the gasifier  64  which may, in turn, reduce the cost of the gasifier  64 . For instance, sizing the gasifier  64  for 50-70%, instead of 100%, of the peak load power requirements may allow for substantial cost reductions. In addition, the ability to run the gasifier  64  at a more constant production rate (i.e., at design operating conditions) throughout the day may eliminate the need to periodically cycle the gasifier  64 , leading to an overall reduction in operating costs, as well as a reduction in long-term damage to the gasifier  64 . 
     This written description uses examples to disclose the invention, including the best mode, and also to enable any person skilled in the art to practice the invention, including making and using any devices or systems and performing any incorporated methods. The patentable scope of the invention is defined by the claims, and may include other examples that occur to those skilled in the art. Such other examples are intended to be within the scope of the claims if they have structural elements that do not differ from the literal language of the claims, or if they include equivalent structural elements with insubstantial differences from the literal languages of the claims.