Patent Publication Number: US-8529679-B2

Title: System and method for improving performance of an IGCC power plant

Description:
BACKGROUND OF THE INVENTION 
     The subject matter disclosed herein relates to integrated gasification combined cycle (IGCC) power plants. More specifically, the disclosed embodiments relate to systems and methods for improving the performance of IGCC power plants. 
     IGCC power plants are capable of generating energy from various carbonaceous feedstock, such as coal or natural gas, relatively cleanly and efficiently. IGCC technology may convert the carbonaceous feedstock into a gas mixture of carbon monoxide (CO) and hydrogen (H2), i.e., syngas, by reaction with oxygen and steam in a gasifier. These gases may be cleaned, processed, and utilized as fuel in the IGCC power plant. For example, the syngas may be fed into a combustor of a gas turbine of the IGCC power plant and ignited to power the gas turbine for use in the generation of electricity. Such IGCC power plants include several components that generate low-grade heat, which is subsequently dissipated. 
     BRIEF DESCRIPTION OF THE INVENTION 
     Certain embodiments commensurate in scope with the originally claimed invention are summarized below. These embodiments are not intended to limit the scope of the claimed invention, but rather these embodiments are intended only to provide a brief summary of possible forms of the invention. Indeed, the invention may encompass a variety of forms that may be similar to or different from the embodiments set forth below. 
     In a first embodiment, a system includes a gas cleaner. The gas cleaner includes a solvent to clean a syngas. The system also includes a heat exchanger configured to heat a liquid to generate a vapor. The system further includes a vapor absorption refrigeration (VAR) cycle coupled to the gas cleaner and the heat exchanger. The VAR cycle is configured to cool the solvent. In addition, the vapor drives the VAR cycle. 
     In a second embodiment, a system includes a multi-cooler controller. The multi-cooler controller includes a first cooler controller and a second cooler controller. The first cooler controller is configured to control a vapor compression refrigeration (VCR) cycle. The second cooler controller is configured to control a VAR cycle. The multi-cooler controller is configured to selectively adjust loads of the VCR cycle and the VAR cycle to cool a solvent of a gas cleaner. 
     In a third embodiment, a system includes an IGCC heat exchanger configured to heat water to produce steam. The IGCC heat exchanger includes a syngas cooler downstream from a gasifier or an air cooler coupled to an air separation unit (ASU). The system also includes a steam conduit coupled to the IGCC heat exchanger. The system further includes an IGCC component coupled to the steam conduit. The IGCC component includes a VAR cycle, a deaerator, or a steam turbine. 
    
    
     
       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  a schematic block diagram of an exemplary embodiment of an IGCC power plant; 
         FIG. 2  is a process flow diagram of an exemplary embodiment of a low-temperature gas cooling (LTGC) unit of  FIG. 1 , which may generate low, low pressure (LLP) steam; 
         FIG. 3  is a process flow diagram of an exemplary embodiment of an ASU air compressor of  FIG. 1 , which may generate LLP steam; 
         FIG. 4  is a process flow diagram of an exemplary embodiment of a syngas cleaning system of  FIG. 1 , which has been configured to utilize the LLP steam; 
         FIG. 5  is a process flow diagram of an exemplary embodiment of the gas turbine engine of  FIG. 1 , which has been configured to utilize the LLP steam; 
         FIG. 6  is a process flow diagram of an exemplary embodiment of a deaerator, which has been configured to utilize the LLP steam; and 
         FIG. 7  is a process flow diagram of an exemplary embodiment of the steam turbine of  FIG. 1 , which has been configured to utilize the LLP steam. 
     
    
    
     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. 
     IGCC plants with carbon capture consume more auxiliary loads compared to non-carbon capture plants. However, these same plants generate low-grade heat energy, which may otherwise be dissipated, for example, in cooling water systems. The disclosed embodiments reduce utility power consumption and cooling tower loads of an IGCC plant by utilizing low, low pressure (LLP) steam (e.g., steam at a pressure range between 20-40 psia) generated from this low-grade heat energy by various IGCC heat exchangers, such as air separation unit (ASU) compressor inter-coolers and after-coolers, low-temperature gas cooling (LTGC) section, trim coolers, and so forth. However, other IGCC heat exchangers may be used to generate the LLP steam. 
     In certain embodiments, the LLP steam may be used to reduce utility power consumption for an acid gas removal (AGR) solvent refrigeration system of the IGCC plant by using the LLP steam to drive a vapor absorption refrigeration cycle. In other embodiments, the LLP steam may be used to cool inlet air into a gas turbine engine of the IGCC plant by using the LLP steam to drive another vapor absorption refrigeration cycle. The efficiency of the gas turbine engine may generally depend upon the ambient air temperature. During hot days, the output of the gas turbine engine may be reduced due to the low density of the ambient air. Therefore, cooling the inlet air into the gas turbine engine improves the output and efficiency of the IGCC plant. In yet other embodiments, the LLP steam may be used to reduce the amount of low-pressure steam extracted from a steam turbine of the IGCC plant by supplementing the flow of extracted low-pressure steam in a deaeration system. In still other embodiments, the LLP steam may be admitted into a low-pressure section of a steam turbine of the IGCC plant to increase the output and efficiency of the steam turbine. However, the LLP steam may be used in various other applications throughout the IGCC plant. 
       FIG. 1  illustrates an IGCC system  10  that may be powered by synthetic gas, e.g., syngas. Elements of the IGCC system  10  may include a fuel source  12 , such as a solid feed, which may be utilized as a source of energy for the IGCC. The fuel source  12  may include coal, petroleum coke, biomass, wood-based materials, agricultural wastes, tars, coke oven gas and asphalt, or other carbon containing items. 
     The solid fuel of the fuel source  12  may be passed to a feedstock preparation unit  14 . The feedstock preparation unit  14  may, for example, resize or reshaped the fuel source  12  by chopping, milling, shredding, pulverizing, briquetting, or palletizing the fuel source  12  to generate feedstock. Additionally, water, or other suitable liquids, may be added to the fuel source  12  in the feedstock preparation unit  14  to create slurry feedstock. In other embodiments, no liquid is added to the fuel source  12 , thus yielding dry feedstock. 
     The feedstock may be passed to a gasifier  16  from the feedstock preparation unit  14 . The gasifier  16  may convert the feedstock into a combination of carbon monoxide and hydrogen, e.g., syngas. This conversion may be accomplished by subjecting the feedstock to a controlled amount of steam and oxygen at elevated pressures (e.g. from approximately 290 psia to 1230 psia) and temperatures (e.g., approximately 1300° F.-2900° F.), depending on the type of gasifier  16  utilized. The gasification process may include the feedstock undergoing a pyrolysis process, whereby the feedstock is heated. Temperatures inside the gasifier  16  may range from approximately 300° F. to 1300° F. during the pyrolysis process, depending on the fuel source  12  utilized to generate the feedstock. The heating of the feedstock during the pyrolysis process may generate a solid, e.g., char, and residue gases, e.g., carbon monoxide, and hydrogen. 
     A combustion process may then occur in the gasifier  16 . The combustion may include introducing oxygen to the char and residue gases. The char and residue gases may react with the oxygen to form carbon dioxide and carbon monoxide, which provides heat for the subsequent gasification reactions. The temperatures during the combustion process may range from approximately 1300° F. to 2900° F. Next, steam may be introduced into the gasifier  16  during a gasification step. The char may react with the carbon dioxide and steam to produce carbon monoxide and hydrogen at temperatures ranging from approximately 1500° F. to 2000° F. In essence, the gasifier utilizes steam and oxygen to allow some of the feedstock to be “burned” to produce carbon monoxide and energy, which drives a second reaction that converts further feedstock to hydrogen and additional carbon dioxide. In this way, a resultant gas is manufactured by the gasifier  16 . This resultant gas may include approximately 85% of carbon monoxide and hydrogen, as well as CH 4 , CO2, H2O, HCl, HF, COS, NH 3 , HCN, and H 2 S (based on the sulfur content of the feedstock). This resultant gas may be termed dirty syngas. The gasifier  16  may also generate waste, such as slag  18 , which may be a wet ash material. This slag  18  may be removed from the gasifier  16  and disposed of, for example, as road base or as another building material. 
     The dirty syngas may then be directed into a low-temperature gas cooling (LTGC) unit  20 , which may be configured to cool the dirty syngas. As described below, the LTGC unit  20  may include one or more heat exchangers configured to transfer heat from the heated dirty syngas into other media, such as steam condensate, cooling water from a cooling tower, and boiler feedwater from a boiler feedwater system. 
     The cooled dirty syngas from the LTGC unit  20  may then be cleaned in a syngas cleaning system  22 . The syngas cleaning system  22  may scrub the cooled dirty syngas to remove the HCl, HF, COS, HCN, and H 2 S from the cooled dirty syngas, which may include separation of sulfur  24  by, for example, an acid gas removal (AGR) process. Furthermore, the syngas cleaning system  22  may separate salts  26  from the cooled dirty syngas via a water treatment process that may utilize water purification techniques to generate usable salts  26  from the cooled dirty syngas. Subsequently, the gas from the syngas cleaning system  22  may include clean syngas. 
     A gas processor  28  may be utilized to remove residual gas components  30  from the clean syngas such as, ammonia, methanol, or any residual chemicals. However, removal of residual gas components  30  from the clean syngas is optional, since the clean syngas may be utilized as a fuel even when containing the residual gas components  30 , e.g., tail gas. This clean syngas may be transmitted to a combustor  32  (e.g., a combustion chamber) of a gas turbine engine  34  as combustible fuel. 
     The IGCC system  10  may further include an air separation unit (ASU)  36 . The ASU  36  may operate to separate air into component gases by, for example, distillation techniques. The ASU  36  may separate oxygen from the air supplied to it from an ASU compressor  38 , and the ASU  36  may transfer the separated oxygen to the gasifier  16 . Additionally, the ASU  36  may transmit separated nitrogen to a diluent gaseous nitrogen (DGAN) compressor  40 . As described below, the ASU compressor  38  may include one or more compression sections, one or more inter-coolers between the compression sections, and/or one or more after-coolers after the compression sections. The inter-coolers and after-coolers may cool the compressed air before delivering the compressed air to the ASU  36 . 
     The DGAN compressor  40  may compress the nitrogen received from the ASU  36  at least to pressure levels equal to those in the combustor  32  of the gas turbine engine  34 , for proper injection to happen into the combustor chamber. Thus, once the DGAN compressor  40  has adequately compressed the nitrogen to a proper level, the DGAN compressor  40  may transmit the compressed nitrogen to the combustor  32  of the gas turbine engine  34 . The nitrogen may be used as a diluent to facilitate control of emissions, for example. 
     The gas turbine engine  34  may include a turbine  42 , a drive shaft  44  and a compressor  46 , as well as the combustor  32 . The combustor  32  may receive fuel, such as syngas, which may be injected under pressure from fuel nozzles. This fuel may be mixed with compressed air as well as compressed nitrogen from the DGAN compressor  40 , and combusted within combustor  32 . This combustion may create hot pressurized combustion gases. 
     The combustor  32  may direct the combustion gases towards an inlet of the turbine  42 . As the combustion gases from the combustor  32  pass through the turbine  42 , the combustion gases may force turbine blades in the turbine  42  to rotate the drive shaft  44  along an axis of the gas turbine engine  34 . As illustrated, drive shaft  44  is connected to various components of the gas turbine engine  34 , including the compressor  46 . 
     The drive shaft  44  may connect the turbine  42  to the compressor  46  to form a rotor. The compressor  46  may include blades coupled to the drive shaft  44 . Thus, rotation of turbine blades in the turbine  42  causes the drive shaft  44  connecting the turbine  42  to the compressor  46  to rotate blades within the compressor  46 . This rotation of blades in the compressor  46  may cause the compressor  46  to compress air received via an air intake in the compressor  46 . The compressed air may then be fed to the combustor  32  and mixed with fuel and compressed nitrogen to allow for higher efficiency combustion. The drive shaft  44  may also be connected to a load  48 , which may be a stationary load, such as an electrical generator for producing electrical power, for example, in a power plant. Indeed, the load  48  may be any suitable device that is powered by the rotational output of the gas turbine engine  34 . 
     The IGCC system  10  also may include a steam turbine engine  50  and a heat recovery steam generation (HRSG) system  52 . The steam turbine engine  50  may drive a second load  54 . The second load  54  may also be an electrical generator for generating electrical power. However, both the first and second loads  48 ,  54  may be other types of loads capable of being driven by the gas turbine engine  34  and steam turbine engine  50 , respectively. In addition, although the gas turbine engine  34  and steam turbine engine  50  may drive separate loads  48  and  54 , as shown in the illustrated embodiment, the gas turbine engine  34  and steam turbine engine  50  may also be utilized in tandem to drive a single load via a single shaft. The specific configuration of the steam turbine engine  50 , as well as the gas turbine engine  34 , may be implementation-specific and may include any combination of sections. 
     The system  10  may also include the HRSG  52 . Heated exhaust gas from the gas turbine engine  34  may be transported into the HRSG  52  and used to heat water and produce steam used to power the steam turbine engine  50 . Exhaust from, for example, a low-pressure section of the steam turbine engine  50  may be directed into a condenser  56 . The condenser  56  may utilize a cooling tower  58  to exchange heated water for cooled water. The cooling tower  58  acts to provide cool water to the condenser  56  to aid in condensing the steam transmitted to the condenser  56  from the steam turbine engine  50 . Condensate from the condenser  56  may, in turn, be directed into the HRSG  52 . Again, exhaust from the gas turbine engine  34  may also be directed into the HRSG  52  to heat the water from the condenser  56  and produce steam. 
     In combined cycle systems such as the IGCC system  10 , hot exhaust may flow from the gas turbine engine  34  and pass to the HRSG  52 , where it may be used to generate high-pressure, high-temperature steam. The steam produced by the HRSG  52  may then be passed through the steam turbine engine  50  for power generation. In addition, the produced steam may also be supplied to any other processes where steam may be used, such as to the gasifier  16 . The gas turbine engine  34  generation cycle is often referred to as the “topping cycle,” whereas the steam turbine engine  50  generation cycle is often referred to as the “bottoming cycle.” By combining these two cycles as illustrated in  FIG. 1 , the IGCC 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. 
     As described above, the IGCC system  10  includes several components that generate low-grade heat energy, which may otherwise be dissipated. The disclosed embodiments utilize this low-grade heat energy to generate low, low pressure (LLP) steam for use in various methods to improve the overall performance of the IGCC system  10 . The LLP steam may be in the range of approximately 20-40 psia, as opposed to low pressure (LP) applications, which are generally in the range of approximately 60-100 psia. Two particular components of the IGCC system  10  that generate this type of low-grade heat energy, which may be converted into LLP steam, are the LTGC unit  20  and the ASU compressor  38  of  FIG. 1 . However, the disclosed embodiments for utilizing LLP steam may be applied to the generation of low-grade heat energy by any other components of the IGCC system  10 . 
       FIGS. 2 and 3  illustrate two exemplary components of the IGCC system  10  that may be used to generate LLP steam for use in various applications throughout the IGCC system  10 . For example,  FIG. 2  is a process flow diagram of an exemplary embodiment of the LTGC unit  20  of  FIG. 1 . As illustrated, in certain embodiments, the LTGC unit  20  may include three heat exchangers  60 ,  62 ,  64 . The three heat exchangers  60 ,  62 ,  64  may be any type of heat exchangers capable of transferring heat from syngas to a coolant, such as water or steam condensate. In particular, the LTGC unit  20  may include a first heat exchanger  60  (e.g., an LLP steam generator) configured to receive heated dirty syngas from the gasifier  16  of  FIG. 1  and to cool the heated dirty syngas with boiler feedwater. More specifically, heat from the heated dirty syngas may be transferred into the boiler feedwater to generate LLP steam. 
     For example, in certain embodiments, the heated dirty syngas may enter the first heat exchanger  60  at a temperature of approximately 315° F. and the boiler feedwater may enter the first heat exchanger  60  at a temperature of approximately 95° F. However, in other embodiments, the heated dirty syngas may enter the first heat exchanger  60  at a temperature in the range of 250-400° F. More specifically, the heated dirty syngas may enter the first heat exchanger  60  at a temperature of approximately 290° F., 295° F., 300° F., 305° F., 310° F., 315° F., 320° F., 325° F., 330° F., 335° F., 340° F., and so forth. In addition, the boiler feedwater may enter the first heat exchanger  60  at a temperature in the range of 70-290° F. More specifically, the boiler feedwater may enter the first heat exchanger  60  at a temperature of approximately 80° F., 85° F., 90° F., 95° F., 100° F., 105° F., 110° F., and so forth. 
     In certain embodiments, the generated LLP steam may exit the first heat exchanger  60  at a temperature of approximately 250° F. and the dirty syngas may exit the first heat exchanger  60  at a temperature of approximately 255° F. However, in other embodiments, the generated LLP steam may exit the first heat exchanger  60  at a temperature in the range of 200-300° F. More specifically, the generated LLP steam may exit the first heat exchanger  60  at a temperature of approximately 225° F., 230° F., 235° F., 240° F., 245° F., 250° F., 255° F., 260° F., 265° F., 270° F., 275° F., and so forth. In addition, the dirty syngas may exit the first heat exchanger  60  at a temperature in the range of 200-300° F. More specifically, the dirty syngas may exit the first heat exchanger  60  at a temperature of approximately 230° F., 235° F., 240° F., 245° F., 250° F., 255° F., 260° F., 265° F., 270° F., 275° F., 280° F., and so forth. In addition, in certain embodiments, the generated LLP steam may exit the first heat exchanger  60  at approximately 30 psia or, in other embodiments, may exit the first heat exchanger  60  within the range of 20 psia to 40 psia. As described below, the generated LLP steam may be used in various applications throughout the IGCC system  10 . 
     As illustrated in  FIG. 2 , the LTGC unit  20  may also include a second heat exchanger  62  configured to receive dirty syngas from the first heat exchanger  60  and to cool the dirty syngas with steam condensate. More specifically, heat from the dirty syngas may be transferred into the steam condensate to generate heated steam condensate. 
     For example, in certain embodiments, the dirty syngas may enter the second heat exchanger  62  at a temperature of approximately 255° F. and the steam condensate may enter the second heat exchanger  62  at a temperature of approximately 100° F. However, in other embodiments, the dirty syngas may enter the second heat exchanger  62  at a temperature in the range of 200-300° F. More specifically, the dirty syngas may enter the second heat exchanger  62  at a temperature of approximately 230° F., 235° F., 240° F., 245° F., 250° F., 255° F., 260° F., 265° F., 270° F., 275° F., 280° F., and so forth. In addition, the steam condensate may enter the second heat exchanger  62  at a temperature in the range of 50-150° F. More specifically, the steam condensate may enter the second heat exchanger  62  at a temperature of approximately 85° F., 90° F., 95° F., 100° F., 105° F., 110° F., 115° F., and so forth. 
     In certain embodiments, the heated steam condensate may exit the second heat exchanger  62  at a temperature of approximately 200° F. and the dirty syngas may exit the second heat exchanger  62  at a temperature of approximately 120° F. However, in other embodiments, the heated steam condensate may exit the second heat exchanger  62  at a temperature in the range of 150-250° F. More specifically, the heated steam condensate may exit the second heat exchanger  62  at a temperature of approximately 175° F., 180° F., 185° F., 190° F., 195° F., 200° F., 205° F., 210° F., 215° F., 220° F., 225° F., and so forth. In addition, the dirty syngas may exit the second heat exchanger  62  at a temperature in the range of 50-150° F. More specifically, the dirty syngas may exit the second heat exchanger  62  at a temperature of approximately 105° F., 110° F., 115° F., 120° F., 125° F., 130° F., 135° F., and so forth. 
     As illustrated in  FIG. 2 , the LTGC unit  20  may also include a third heat exchanger  64  configured to receive dirty syngas from the second heat exchanger  62  and to cool the dirty syngas with cooling water from the cooling tower  58  of  FIG. 1 . More specifically, heat from the dirty syngas may be transferred into the cooling water to generate heated cooling water, which may be sent back to the cooling tower  58  of  FIG. 1 . As described above, the cooled dirty syngas from the third heat exchanger  64  may be directed to the syngas cleaning system  22  of  FIG. 1 . 
     For example, in certain embodiments, the dirty syngas may enter the third heat exchanger  64  at a temperature of approximately 120° F. and may exit the third heat exchanger  64  at a temperature of approximately 115° F. However, in other embodiments, the dirty syngas may enter the third heat exchanger  64  at a temperature in the range of 50-150° F. More specifically, the dirty syngas may enter the third heat exchanger  64  at a temperature of approximately 105° F., 110° F., 115° F., 120° F., 125° F., 130° F., 135° F., and so forth. In addition, the dirty syngas may exit the third heat exchanger  64  at a temperature in the range of 50-150° F. More specifically, the dirty syngas may exit the third heat exchanger  64  at a temperature of approximately 100° F., 105° F., 110° F., 115° F., 120° F., 125° F., 130° F., and so forth. In other words, only a very small amount of heat may be dissipated into the cooling water from the dirty syngas since a substantial amount of the heat energy in the heated dirty syngas entering the LTGC unit  20  may be transferred into the LLP steam and the heated steam condensate in the first and second heat exchangers  60 ,  62 , respectively. 
       FIG. 3  is a process flow diagram of an exemplary embodiment of an ASU compressor  38  of  FIG. 1 , which may generate LLP steam. As illustrated, in certain embodiments, the ASU compressor  38  may include multiple compression sections. In particular, the illustrated ASU compressor  38  includes a first compression section  66  and a second compression section  68  connected by a common shaft  70 . For instance, the first compression section  66  may be a low-pressure compression section while the second compression section  68  may be an intermediate-pressure or high-pressure section. Air may be received by the first compression section  66  and compressed within the first compression section  66 , such that the pressure and the temperature of the air is increased. 
     In certain embodiments, the heated compressed air  72  may be directed into an inter-cooler  74 , where the heated compressed air  72  may be cooled. In particular, in certain embodiments, boiler feedwater may be used as a cooling medium by the inter-cooler  74 . As such, heat from the heated compressed air  72  may be transferred to the boiler feedwater to generate LLP steam, which may be used in various applications throughout the IGCC system  10 . The cooled compressed air  76  from the inter-cooler  74  may be directed into the second compression stage  68  and compressed within the second compression section  68 , such that the pressure and the temperature of the cooled compressed air  76  is increased. 
     In certain embodiments, the heated compressed air  78  from the second compression section  68  may be directed into an after-cooler  80 , where the heated compressed air  78  may be cooled. In particular, in certain embodiments, boiler feedwater may again be used as a cooling medium by the after-cooler  80 . As such, heat from the heated compressed air  78  may be transferred to the boiler feedwater to raise the temperature of water or to generate LLP steam, which may also be used in various applications throughout the IGCC system  10 . The cooled compressed air from the after-cooler  80  may be directed into the ASU  36  of  FIG. 1 . 
     Although illustrated in  FIG. 3  as having two compression sections  66 ,  68 , one inter-cooler  74 , and one after-cooler  80 , in certain embodiments, more than two compression sections, more than one inter-cooler, and/or more than one after-cooler may be used in the ASU compressor  38 . In addition, although illustrated as integrating heat exchangers which directly heat boiler feedwater or convert boiler feedwater into LLP steam, in certain embodiments, multi-step processes (e.g., an inter-cooler  74  or after-cooler  80  plus an additional heat exchanger) for converting the low-grade heat energy from the inter-cooler  74  and the after-cooler  80  may be utilized. In addition, in other embodiments, the boiler feedwater may be heated to the saturation temperature within the inter-coolers  74  and the after-coolers  80  and the heated boiler feedwater may then be used in the first heat exchanger  60  of the LTGC unit  20  to generate the LLP steam. 
     As described above, the LLP steam generated by one of the IGCC heat exchangers (e.g., within the LTGC unit  20  of  FIG. 1 , the ASU compressor  38  inter-coolers or after-coolers of  FIG. 3 , and so forth) may be used in various applications throughout the IGCC system  10 .  FIGS. 4 through 7  illustrate four exemplary methods for utilizing the LLP steam. For example,  FIG. 4  is a process flow diagram of an exemplary embodiment of the syngas cleaning system  22  of  FIG. 1 , which has been configured to utilize the LLP steam as a source of heat energy. In particular,  FIG. 4  illustrates an acid gas recovery (AGR) process, which may be part of the syngas cleaning system  22  processes. As illustrated, dirty syngas from the LTGC unit  20  of  FIG. 1  may enter an absorber  82  and clean syngas may exit the absorber  82  and be directed to the combustor  32  of the gas turbine engine  34  of  FIG. 1  after syngas conditioning and heating as per the gas turbine engine  34  requirements. 
     More specifically, the absorber  82  may use a solvent to purify (e.g., remove acid gas from) the dirty gas stream. In certain embodiments, the solvent may be introduced through the top of the absorber  82 , as illustrated by line  84 . As the solvent moves downward through the absorber, the solvent may selectively absorb acid gas vapor from the dirty syngas, such that clean syngas exits near the upper portion of the absorber  82 . As such, a mixture of the solvent and acid gas may exit through the bottom of the absorber  82 , as illustrated by line  86 . The solvent/acid gas mixture may be directed through a control valve  88 , a knockout drum (K/O drum)  89 , and a heat exchanger  90  before entering a solvent regenerator  92 , as illustrated by line  94 . The control valve  88  and the K/O drum  89  may be used to control the flow of the solvent/acid gas mixture and to reduce the pressure of the solvent/acid gas mixture to release undissolved gases. In addition, as described below, the heat exchanger  90  may be configured to transfer heat from a separate stream of solvent from the solvent regenerator  92 . 
     Since the acid gas is lighter than the solvent, the acid gas generally exits through the top of the solvent regenerator  92  whereas the solvent exits through the bottom of the solvent regenerator  92 , as illustrated by line  96 . As illustrated, a first portion of the solvent from the solvent regenerator  92  may be pumped by a pump  98  into the heat exchanger  90 , as illustrated by line  100 . However, a second portion of the solvent from the solvent regenerator  92  may be circulated through a re-boiler  102  and directed back into the solvent regenerator  92 , as illustrated by line  104 . As such, the solvent exiting through the bottom of the solvent regenerator  92  may be at a higher temperature than the solvent/acid gas mixture that enters the solvent regenerator  92 . However, the solvent may generally absorb the acid gas vapor within the absorber  82  more effectively when the solvent is at lower temperatures. This is part of the rationale behind using the heat exchanger  90  to transfer heat from the solvent in line  100  to the solvent/acid gas mixture from the absorber  82 . 
     However, the amount of heat transferred from the solvent in line  100  to the solvent/acid gas mixture from the absorber  82  in the heat exchanger may be relatively low. As such, the syngas cleaning system  22  may include a vapor absorption refrigeration (VAR) cycle  106  and a vapor compression refrigeration (VCR) cycle  108  to further cool the solvent before the solvent enters through the top of the absorber  82 . Cooling the solvent enhances its ability to remove acid gas in the absorber  82 . Although illustrated as being in series with each other, the VAR cycle  106  and the VCR cycle  108  may, in certain embodiments, be used in parallel lines. 
     In certain embodiments, the VAR cycle  106  may include an absorber containing an absorbent within which a refrigerant may dissolve, a pump for increasing the pressure and temperature of the absorbent/refrigerant mixture, a condenser for cooling the refrigerant while maintaining the higher pressure of the refrigerant, an expansion valve for reducing the pressure and temperature of the refrigerant to create a gaseous/liquid state of the refrigerant, and an evaporator for cooling the solvent. The LLP steam may, in certain embodiments, drive the pump of the VAR cycle  106 . Conversely, in certain embodiments, the VCR cycle  108  may include a compressor for compressing a refrigerant to create a superheated refrigerant at higher pressures and temperatures, a condenser for cooling the superheated refrigerant while maintaining the higher pressure of the refrigerant, an expansion valve for reducing the pressure and temperature of the refrigerant to create a gaseous/liquid state of the refrigerant, and an evaporator for cooling the solvent. 
     In certain embodiments, the LLP steam generated by one of the IGCC heat exchangers may be used to drive the VAR cycle  106 , which is specifically designed to be driven by heat sources such as the LLP steam. In particular, in certain embodiments, the VAR cycle  106  may be added to an existing AGR process of the syngas cleaning system  22  to supplement an existing VCR cycle  108 . As such, the size and power requirements for the VCR cycle  108  may be drastically reduced by adding the VAR cycle  106  and utilizing the LLP steam to drive the VAR cycle  106 . In other words, the utility power required to drive the VCR cycle  108  may be offset by instead utilizing the heat energy from the LLP steam to drive the VAR cycle  106  to meet the overall cooling requirements from the combination of the VAR cycle  106  and the VCR cycle  108 . 
     For example, in certain embodiments, approximately 30% of the refrigeration compressor load of the VCR cycle  108  may be decreased using this technique. However, in other embodiments, the refrigeration compressor load of the VCR cycle  108  may be reduced by approximately 10-100%, 10-50%, 20-40%, and so forth. In addition, the VAR cycle  106  generally requires less operating and maintenance costs compared to the VCR cycle  108 . As described in greater detail below, in operation, the VCR cycle  108  may enable stable operation during start-up and part-load operations of the IGCC system  10 , whereas the VAR cycle  106  may increase the net output and efficiency of the IGCC system  10  during normal operating conditions of the IGCC system  10 . 
     In addition, as described in greater detail below, in certain embodiments, a multi-cooler controller  110  may be used to control the VAR cycle  106  and the VCR cycle  108 . In particular, in certain embodiments, the multi-cooler controller  110  may include a VCR controller  112  and a VAR controller  114 , wherein the VCR controller  112  may generally be configured to control the VCR cycle  108  and the VAR controller  114  may generally be configured to control the VAR cycle  106 . However, the multi-cooler controller  110  may be configured to coordinate the operation of the VCR controller  112  and the VAR controller  114  during start-up, part-load operations, and normal operations. 
     The concept of using the LLP steam generated by one of the IGCC heat exchangers (e.g., within the LTGC unit  20  of  FIG. 2 , the ASU compressor  38  inter-coolers or after-coolers of  FIG. 3 , and so forth) to drive a VAR cycle may be extended to several other applications throughout the IGCC system  10 . For example,  FIG. 5  is a process flow diagram of an exemplary embodiment of the gas turbine engine  34  of  FIG. 1 , which has been configured to utilize the LLP steam as a source of heat energy to drive a VAR cycle. As illustrated, the compressor  46  of the gas turbine engine  34  may intake ambient air, which may be compressed within the compressor  46 . However, the gas turbine engine  34  generally operates more efficiently when the air taken into the compressor  46  is cooler and at higher densities. 
     As such, in certain embodiments, the gas turbine engine  34  may include an inlet air chiller  116 , which may be configured to cool the ambient air before directing the cooled air into the compressor  46 . Similar to the embodiment illustrated in  FIG. 4 , the LLP steam generated by one of the components of the IGCC system  10  may be used to drive a VAR cycle  118 , which may generate a cooling fluid which may be circulated through the inlet air chiller  116 , as illustrated by lines  120  and  122 . The cooling fluid from the VAR cycle  118  may be used by the inlet air chiller  116  to cool the ambient air, which is ultimately directed into the compressor  46  for compression. 
     As will be appreciated, using the inlet air chiller  116  may prove particularly beneficial during hot days, when the efficiency of the gas turbine engine  34  is substantially lower due to the higher ambient air temperatures and lower ambient air densities. As such, using the LLP steam to drive the VAR cycle  118 , which enables the inlet air chiller  116  to cool the ambient air, may lead to overall higher efficiencies of the gas turbine engine  34 . In certain embodiments, a controller  124  may be used to control the VAR cycle  118 , similar to the controllers  110 ,  112 ,  114  of  FIG. 4 . 
     However, driving VAR cycles is not the only application for the LLP steam generated by one of the IGCC heat exchangers (e.g., within the LTGC unit  20  of  FIG. 2 , the ASU compressor  38  inter-coolers or after-coolers of  FIG. 3 , and so forth). For example,  FIG. 6  is a process flow diagram of an exemplary embodiment of a deaerator  126 , which has been configured to utilize the LLP steam. As illustrated, the deaerator  126  may receive one or more condensate flow streams and one or more steam flow streams. In particular, the deaerator  126  illustrated in  FIG. 6  may be configured to receive condensate from a low-pressure (LP) section of the steam turbine  50  of  FIG. 1 , as well as condensate from other processes throughout the IGCC system  10 . In addition, the deaerator  126  illustrated in  FIG. 6  may be configured to receive LP steam extracted from the LP section of the steam turbine  50  of  FIG. 1 , as well as the LLP steam generated by one of the IGCC heat exchangers. 
     The deaerator  126  illustrated in  FIG. 6  is a tray-type deaerator, which consists of a tray section  128  above a boiler feedwater vessel  130 . However, other types of deaerators may be used. The condensate streams enter toward the top of the tray section  128  and flow downward through perforated trays toward the boiler feedwater vessel  130 . The LP and LLP steam enters toward the bottom of the tray section  128  and flows upward through the perforated trays. The LP and LLP steam strips the condensate of gases dissolved within the condensate and exits through a vent through the top of the tray section  128 . Conversely, the deaerated condensate flows into the boiler feedwater vessel  130  as boiler feedwater, where it may be pumped by a pump  132  to the HRSG  52  of  FIG. 1  or any other processes throughout the IGCC system  10  that can use boiler feedwater. 
     The embodiment illustrated in  FIG. 6  is similar to the embodiment illustrated in  FIG. 4  in that the LLP steam from one of the IGCC heat exchangers is used to supplement existing equipment and/or heat sources. In particular, the LLP steam that is injected into the tray section  128  of the deaerator  126  may offset the amount of LP steam extracted from the LP section of the steam turbine  50  of  FIG. 1 . As such, the efficiency of the steam turbine  50  and, in turn, the overall efficiency of the IGCC system  10  may be enhanced by utilizing the LLP steam in this manner. In certain embodiments, a controller  134  may be used to control the flow of LLP steam into the tray section  128 . 
       FIG. 7  illustrates another application for the LLP steam generated by one of the IGCC heat exchangers (e.g., within the LTGC unit  20  of  FIG. 2 , the ASU compressor  38  inter-coolers or after-coolers of  FIG. 3 , and so forth). In particular,  FIG. 7  is a process flow diagram of an exemplary embodiment of the steam turbine  50  of  FIG. 1 , which has been configured to utilize the LLP steam. In the illustrated embodiment, the steam turbine  50  may include one low-pressure section  136  (LP ST), one intermediate-pressure section  138  (IP ST), and one high-pressure section  140  (HP ST). However, the specific configuration of the steam turbine  50  may be implementation-specific and may include any combination of sections. In certain embodiments, the sections  136 ,  138 ,  140  of the steam turbine  50  may drive a common shaft  142 , which may drive the load  54  of  FIG. 1 . 
     In certain embodiments, high-pressure (HP) steam may be received from the HRSG  52  of  FIG. 1  by the high-pressure section  140  of the steam turbine  50 . Exhaust from the high-pressure section  140  of the steam turbine  50  may, in turn, be directed into the intermediate-pressure section  138  of the steam turbine  50  after re-heating or without re-heating, as illustrated by lines  144  and  145 . In addition, exhaust from the intermediate-pressure section  138  of the steam turbine engine  50  may be directed into the low-pressure section  136  of the steam turbine engine  50 , as illustrated by line  146 . Furthermore, exhaust from the low-pressure section  136  of the steam turbine  50  may be directed into the condenser  56  of  FIG. 1 . As illustrated, the LLP steam from one of the IGCC heat exchangers may be admitted into the low-pressure section  136  of the steam turbine engine  50  based on the LLP steam pressure level. For this purpose, the LLP steam may be superheated either in a process section or the HRSG system  52 . As such, the output of the low-pressure section  136  and, in turn, the overall efficiency of the steam turbine  50  may be increased. In certain embodiments, a controller  148  may be used to control the flow of LLP steam into the low-pressure section  136  of the steam turbine  50 . 
     Technical effects of the disclosed embodiments include generating LLP steam using various IGCC heat exchangers of the IGCC system  10  (e.g., within the LTGC unit  20  of  FIG. 2 , the ASU compressor  38  inter-coolers or after-coolers of  FIG. 3 , and so forth) and utilizing the LLP steam in various application throughout the IGCC system  10  (e.g., driving the VAR cycle  106  of  FIG. 4  to supplement the VCR cycle  108  of  FIG. 4 , driving the VAR cycle  118  of  FIG. 5  to cool the ambient inlet air into the gas turbine engine  34  of  FIG. 5 , supplementing the flow of LP steam extracted from the steam turbine  50  in the deaerator  126  of  FIG. 6 , improving the output and efficiency of the steam turbine  50  of  FIG. 7 , and so forth). 
     The disclosed embodiments lead to several tangible benefits. For example, the disclosed embodiments may lead to a reduction in AGR refrigeration load, leading to improved efficiency and net power output of the IGCC system  10 . In addition, the disclosed embodiments may lead to improved performance of the gas turbine engine  34  on hot days by cooling the ambient air before the air is taken into the compressor  46  of the gas turbine engine  34  of the IGCC system  10 . The disclosed embodiments may also lead to a reduction in the amount of LP steam extracted from the steam turbine  50  for use in the deaerator  126 . The disclosed embodiments may further lead to increased output and performance of the steam turbine  50 . In addition to these benefits, the disclosed embodiments may also lead to a reduction in the size of the cooling tower  58 , the cooling tower load of the ASU  36  and the AGR section of the syngas cleaning system  22 , and so forth. Furthermore, the disclosed embodiments may be implemented in existing IGCC plants as well as new IGCC plants. 
     In addition, the disclosed embodiments may be at least partially controlled by at least one controller or uniquely programmed device (e.g., a computer), such as the multi-cooler controller  110 , VAR controller  112 , and VCR controller  114  of  FIG. 4 , and the controllers  124 ,  134 , and  148  of  FIGS. 5 ,  6 , and  7 , respectively. In particular, the controllers may be configured to control the operation of the IGCC heat exchangers generating the LLP steam and/or the applications utilizing the LLP steam. The controllers may, in certain embodiments, be physical computing devices uniquely programmed to control valves, pumps, and so forth. More specifically, the controllers may include input/output (I/O) devices for determining how to control the control valves, pumps, and so forth. In addition, in certain embodiments, the controllers may also include storage media for storing historical data, theoretical performance curves, and so forth. 
     One example of how the controllers may control the operation of the IGCC system  10  to utilize the LLP steam relates to the multi-cooler controller  110  illustrated in  FIG. 4 . Temperature control logic in the controllers  110 ,  112 ,  114 , which controls the temperature of the solvent in the syngas cleaning system  22 , may be enabled once the gasifier  16  of  FIG. 1  is turned on and syngas production has reached at least 50% of the normal operating flow rate. Immediately after start-up of the gasifier  16 , the IGCC system  10  may be operating in a part-load condition and, therefore, the control logic may enable one of a plurality of individual units in the VCR cycle  108 . Initially, only one compressor in the VCR cycle  108  may be turned on and may be gradually ramped up to its maximum operating point. This may be referred to as a start-up mode. 
     Once the IGCC system  10  is ramped up to normal operating conditions, the controller may enable the VAR cycle  106 . Upon successful start-up of the VAR cycle  106 , one of the compressors of the VCR cycle  108  may be shut down. Once the temperature of the solvent decreases for a certain time period, the other compressors of the VCR cycle  108  may be shut down, allowing the refrigeration load to be shared by the VAR cycle  106  and the VCR cycle  108 . This may be referred to as the ramp-up mode. 
     In certain embodiments, the VAR controller  114  may control operation of the VAR cycle  106  and the VCR controller  112  may be configured to control operation of the VCR cycle  108 . The VCR cycle  108  may always be operational, irrespective of the load on the IGCC system  10 , and the VAR cycle  106  may be shut down through a manual override during turndown. As such, in general, the controllers may comprise a VCR mode, wherein the VCR controller  112  enables the VCR cycle  108  and the VAR controller  114  disables the VAR cycle  106 , and a joint mode, wherein the VCR controller  112  enables the VCR cycle  108  and the VAR controller  114  enables the VAR cycle  106 . 
     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.