Patent Publication Number: US-2012023892-A1

Title: Systems and methods for co2 capture

Description:
BACKGROUND OF THE INVENTION 
     The subject matter disclosed herein relates to systems and methods for separating CO 2  and/or other gaseous species from a gas mixture, such as a gas mixture resulting from a combustion process. 
     Power generating processes that are based on combustion of carbon containing fuel produce carbon dioxide (CO 2 ) as a byproduct. Typically the CO 2  is one component of a mixture of gases that result from or pass unchanged through the combustion process. It may be desirable to capture or otherwise remove the CO 2  and/or other components of this gas mixture to prevent the release of these gases into the environment and/or to utilize these gases in the power generation process or in other processes. 
     Unfortunately, CO 2  capture (as well as the capture of other gaseous combustion byproducts) can be energy intensive as well as capital intensive. For example, amine processes used to capture CO 2  may require installation of the capital equipment associated with the amine system (which may result in an 80% increase in the cost of the system) and may be costly and energy intensive to operate. Further, to the extent that the captured CO 2  is compressed, the energy and capital requirements may be increased even further. In addition, such CO 2  capture processes are typically associated with substantial water usage (i.e., a large water footprint). As a result, these capture and removal processes may be expensive and/or infeasible to perform using existing technologies. 
     BRIEF DESCRIPTION OF THE INVENTION 
     With the foregoing background in mind, the present disclosure describes a cryogenic CO 2  separation method that relies on the principle of cooling the gas mixtures to separate CO 2  as liquid or solid and thus making it easier to separate from other gas mixtures. 
     In a first embodiment, a power-generating system is provided. The power-generating system includes a CO 2  separation system comprising an inlet that receives a gas mixture generated by a combustion process. The power-generating system also includes one or more cooling stages that cool the gas mixture such that solid or liquid-phase CO 2  separate out from the gas mixture to produce a substantially CO 2  free gas mixture and one or more separation components that remove the solid or liquid-phase CO 2  once it is separated from the gas mixture. 
     In a second embodiment, a power-generation system is provided. The power-generation system includes a boiler configured to generate heat. The power-generation system also includes one or more cooling stages that cool an exhaust gas exiting the boiler such that one or more constituents of the exhaust gas undergo a phase change and drop out of the exhaust gas. One of the constituents that drop out of the exhaust gas is solid or liquid CO 2 . The power-generation system also includes a separation component configured to separate the solid or liquid CO 2  from the exhaust gas, leaving a substantially CO 2  free gas mixture. 
     In a third embodiment, a combined cycle system is provided. The combined cycle system includes a turbine cycle configured to combust a fuel and air to generate an exhaust gas that passes through one or more turbine components. The combined cycle system also includes a steam cycle configured to utilize heat of the exhaust gas to cause the flow of water or steam through a circuit. The combined cycle system also includes a CO 2  separation system configured to cryogenically separate CO 2  from the exhaust gas to generate a substantially CO 2  free gas mixture. 
    
    
     
       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 flowchart depicting steps in the removal of CO 2  from a gas mixture in accordance with aspects of the present disclosure; 
         FIG. 2  is a block diagram of a turbine system in accordance with aspects of the present disclosure; 
         FIG. 3  is a block diagram of a system for processing a gas mixture to remove CO 2  in accordance with aspects of the present disclosure; 
         FIG. 4  is a block diagram of one embodiment of a power generation system including CO 2  separation in accordance with aspects of the present disclosure; 
         FIG. 5  is a block diagram of a second embodiment of a power generation system including CO 2  separation in accordance with further aspects of the present disclosure; 
         FIG. 6  is a block diagram of a further embodiment of a power generation system including separation of CO 2  as a liquid in accordance with further aspects of the present disclosure; 
         FIG. 7  is a block diagram of one embodiment of a turbine-based system including CO 2  separation in accordance with aspects of the present disclosure; 
         FIG. 8  is a block diagram of a second embodiment of a turbine-based system including CO 2  separation in accordance with further aspects of the present disclosure; 
         FIG. 9  is a block diagram of an air drying system in accordance with further aspects of the present disclosure; 
         FIG. 10  is a block diagram of a third embodiment of a turbine-based system including CO 2  separation in accordance with further aspects of the present disclosure; 
         FIG. 11  is a block diagram of a fourth embodiment of a turbine-based system including CO 2  separation in accordance with further aspects of the present disclosure; and 
         FIG. 12  is a block diagram of a fifth embodiment of a turbine-based system including CO 2  separation in accordance with further aspects of the present disclosure. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     One or more specific embodiments 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 disclosed herein, 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. 
     The present disclosure provides for the cryogenic separation (method  10 ) of CO 2    12  and/or sulfur species  14  from a gas mixture  16 , as depicted in  FIG. 1 . As discussed herein, the gas mixture  16  may be a flue gas or other exhaust gas mixture resulting from a combustion process (such as may be associated with a coal or natural gas fired power plant), a syngas generated by a gasification or reforming plant, natural gas extracted from a well, or any other gas mixture that contains CO 2  or other gas components where separation is warranted. 
     In certain embodiments, the gas mixture  16  is cooled (block  18 ), such as below the typical stack temperatures and, in response to the cooling, drop out water  20 , other impurities or pollutants  14 , and CO 2    12  sequentially. Various impurities or pollutants  14  that may be removed or reduced by the approaches discussed herein include, but are not limited to SO 2 , NO, NO 2 , C 2 H x , H 2 S unburnt hydrocarbons (UHC), mercury particulates, and arsenic, and so forth. The cooling may be achieved by various suitable approaches, such as an external vapor compression cycle or by expansion of the gas mixture. The CO 2    12  can be condensed as a liquid or as a solid, depending on the operating pressure and/or temperature, and may be initially separated out from the gas mixture  16  using a suitable separation device, such as a vapor-solid separator, or a vapor-liquid separator (e.g., a filter, cyclone, column packed with inert substance, and so forth). In embodiments where the CO 2    12  is separated in a solid form, the CO 2    12  may be compressed and/or heated (such as in a posimetric pump or screw compressor) to achieve a phase change to liquid CO 2    12 . The liquid CO 2    12  can then, in certain embodiments, be pumped at high pressure (e.g., approximately 150 bar) such as may be used for carbon sequestration. Further, in certain implementations, the separated CO 2    12  may be used to improve the efficiency of the overall process through one or more recuperative cooling processes. 
     With the foregoing in mind and turning now to the drawings,  FIG. 2  is a block diagram of a turbine system  30 , such as may be used to generate power. As will be appreciated, the turbine system  30  may be suitable for use in a large-scale facility, such as a power plant for generating electricity that is distributed via a power grid to a city or town, or in a smaller-scale setting, such as part of a vehicle engine or small-scale power generation system. That is, the turbine system  30  may be suitable for a variety of applications and/or may be scaled over a range of sizes. 
     In the depicted example, the turbine system  10  includes a fuel injector  32 , a fuel supply  34 , and a combustor  36 . The fuel supply  34  may vary, depending on the embodiment, and may correspond to mechanisms suitable for delivering a fuel or fuel mixture, (e.g., a liquid fuel and/or gas fuel, such as natural gas or syngas) to the turbine system  10  through the fuel injector  32  into the combustor  36 . As discussed below, the fuel injector  32  is configured to inject and mix the fuel with compressed air. Alternatively, the fuel supply  34  may be suitable for delivering coal or other solid and/or particulate fuel materials to the combustor  36  via a suitable fuel injector  32 . 
     The combustor  36  ignites and combusts the fuel-air mixture, and then passes hot pressurized exhaust gas into a turbine  38 . As will be appreciated, the turbine  38  includes one or more stators having fixed vanes or blades, and one or more rotors having blades which rotate relative to the stators. The exhaust gas passes through the turbine rotor blades, thereby driving the turbine rotor to rotate. Coupling between the turbine rotor and a shaft  39  will cause the rotation of the shaft  39 , which is also coupled to several components throughout the turbine system  10 , as illustrated. Eventually, the exhaust of the combustion process may exit the turbine system  10  via an exhaust outlet  40 . 
     A compressor  42  includes blades rigidly mounted to a rotor which is driven to rotate by the shaft  39 . As air passes through the rotating blades, air pressure increases, thereby providing the combustor  36  with sufficient air for proper combustion. The compressor  42  may intake air to the turbine system  10  via an air intake  44 . Further, the shaft  39  may be coupled to a load  46 , which may be powered via rotation of the shaft  39 . As will be appreciated, the load  46  may be any suitable device that may use the power of the rotational output of the turbine system  10 , such as a power generation plant or an external mechanical load. For example, the load  46  may include an electrical generator, a propeller of an airplane, and so forth. The air intake  44  draws air  50  into the gas turbine system  10  via a suitable mechanism, such as a cold air intake. The air  50  then flows through blades of the compressor  42 , which provides compressed air  52  to the combustor  36 . In particular, the fuel injector  32  may inject the compressed air  52  and fuel  34 , as a fuel-air mixture  54 , into the combustor  36 . Alternatively, the compressed air  52  and fuel  34  may be injected directly into the combustor for mixing and combustion. 
     With the foregoing in mind, an example of a system  80  for treating the gas mixture  16  exiting the turbine system  30  is depicted in  FIG. 3 . In accordance with this example, the gas mixture  16  may be a flue gas from a power generation plant. In such an embodiment, the flue gas may have 10%-15% moisture content and a temperature of approximately 200° F. (i.e., approximately 93° C.) upon entering the system  80 . The gas mixture  16  may be initially cooled (block  84 ), such as by a heat exchanger, such that some or all (e.g., 50% to 100%) of the water  20  is removed from the gas mixture  16 . The removed water  20  may undergo subsequent treatment (block  86 ) and/or may be utilized in the overall process, such as being introduced as part of a steam cycle or coolant loop associated with the power generation process. 
     In one embodiment, the gas stream leaving the cooling block  84  is at about −10 C to −30 C such that additional water  20  and/or impurities  14  are removed from the gas mixture. This gas stream may, in the depicted example, undergo compression, such as in compressor  88 , after which the temperature may increase, such as to about 200° F. to about 500° F. (i.e., about 93° C. to about 260° C.). This gas stream may subsequently be cooled again (block  90 ), by a heat exchanger or other suitable cooling mechanism. In one embodiment, the cooled gas mixture is at about −30 C to −80 C. The gas mixture may undergo expansion, such as in a turbine  94  where work is extracted, and may exit the expansion process at a reduced temperature, e.g., about −80 c to −135 C. At these temperatures and at partial pressures of CO 2  below 5.2 bar the CO 2  may be in a solid phase, while at partial pressures of CO 2  above 5.2 bar the CO 2  may be in a liquid phase. The liquid or solid-phase CO 2    12  may be separated out (block  96 ) such as by a sweeping solid particles in a settling tank or by using a suitable separation device, such as a cyclone or vapor liquid separator. In embodiments where the CO 2    12  is separated in a solid form, the CO 2    12  may be compressed (block  100 ) (such as in a posimetric pump or screw compressor) to achieve a phase change to liquid CO 2 . 
     In certain embodiments, the CO 2    12  may be recycled (i.e., recirculated), as depicted by line  108  and used to improve the freeze process efficiency and thereby increase CO 2  concentration. In other embodiments, liquid CO 2  recovered by the processes discussed herein may be used as a working fluid in a bottoming cycle. In one such embodiment where the liquid CO 2  is used as a working fluid, the exhaust from a heat recovery steam generator (HRSG) may be used as a heat source with respect to the CO 2  and the cooled exhaust air from a condenser as may be used as a heat sink with respect to the CO 2 . That is, in such an embodiment different respective aspects of the process that undergo complementary heating and cooling may be thermally integrated. For example, as depicted in  FIG. 3  and other embodiments, heat generated as a by-product of one or more of the cooling and/or CO 2  separation stages may be removed by and used to heat the separated CO 2  to turn a portion of this CO 2  from a solid to a liquid, thereby facilitating cooling at the cooling stage (by removing unwanted heat) and liquefaction of the solid CO 2 . In such an embodiment, energy consumption of the process may be reduced. Further, the separated CO 2  may be used to enhance aspects of the power generation process (such as providing cooling), and/or used for other processes, such a carbonation or to enhance oil recovery in from existing wells. 
     In certain embodiments, the remaining gas mixture  106  is a CO 2  lean, dry exhaust gas (i.e., an exhaust gas that is substantially free or reduced in water and CO 2 , as well as SO 2  in certain embodiments) which may consist primarily of N 2 . In addition, the remaining gas mixture  106  will also typically be reduced in O 2  content. As discussed herein, the remaining gas mixture  106  may be utilized for a variety of purposes within the power generation system. For example, the remaining gas mixture  106  may be used as a desiccant to dry air going into a gas turbine engine or coal fired burner involved in the power generation process. Likewise, the remaining gas mixture  106  may be used directly as an input to the combustion process (i.e., fed to the turbine or burner in conjunction with ambient air) to reduce the O 2  content in the air, thereby reducing NOx emissions. 
     Further, to the extent that the remaining gas mixture  106  is a suitable temperature, it may be used to cool one or more parts of the power generation system. For example, in certain embodiments CO 2  lean, cold gas may be used to cool the inlet air provided to the combustion process, to dump heat from cooling water, to treat high pressure steam before sending the steam to an expander for electricity generation, and so forth. 
     Further, the remaining gas mixture  106 , if under pressure, may be expanded (block  104 ) to extract additional work. For example, in implementations where the remaining gas mixture  106  is at 1.5 to 5 bar of pressure or greater, an expansion may be performed to extract additional work. In one such embodiment, the remaining gas mixture  106  may be provided to an expander at about −30 to −80 C and at a pressure above ambient. After expansion (and work extraction), the remaining gas mixture may be at about −70 to −130 C and ambient air pressure. Conversely, in embodiments where the remaining gas mixture  106  is less than 1.5 bar of pressure, the expansion step may be omitted. 
     With the foregoing in mind, specific examples and embodiments are provided to further discussion. It should be appreciated that the provided examples are intended to illustrate certain of the possible implementations and are not intended to limit the scope of the present disclosure. As will be appreciated, the present approaches may be applicable to the separation of CO 2  (or other gaseous components) from a gas mixture in a variety of different contexts, including contexts other than those discussed herein. 
     Turning now to  FIG. 4 , an example is depicted of a CO 2  separation system used in conjunction with a boiler, such as a high-pressure boiler, that may be used in a power plant. For example, the boiler may be a coal-fired or other combustion boiler for use in a power generation plant or system. In one such embodiment, flue-gas desulfurization (FGD) components typically present in the system may be replaced by heat exchangers used in the present cryogenic approach. In such an approach, SO 2  as well as CO 2  will be removed by cryogenic processes as opposed to those processes typically used in flue-gas desulfurization. In this example, air  120  and fuel  122  (e.g., coal) are introduced into a boiler  124 , where the air  120  and fuel  122  are combusted. As a byproduct of this combustion process, a gas mixture  106  (e.g., flue gas) exits the boiler  124 . In other embodiments, the boiler  124  may be a heat recovery steam generator (HRSG) used in a process in which CO 2  containing hot gases (such as exhaust gases) are used to generate steam or provide process heat. In such embodiments the CO 2  containing hot gases that provide heat to the HRSG may be processed in accordance with the approaches discussed herein. 
     The gas mixture  106  is cooled (block  84 ), such as using a heat exchanger, and some or all of the water  20  drops out. In certain embodiments, other impurities, such as SO 2    14 , may also be completely or partially removed at this stage. As discussed above, the water  20  may be treated and/or used in the power generation process, such as in the water circuit discussed below. The gas mixture  106  may pass through a compressor  88  before being cooled (block  90 ), such as via a heat exchanger. In this cooling step additional water  20  and/or impurities (e.g., SO 2    14 ), if present, may be removed. However, as will be appreciated, both the water  20  and SO 2    14  components of the gas mixture may be removed prior to the gas mixture  106  undergoing compression at compressor  88 . 
     In the depicted example the gas mixture may pass through a heat exchanger  128 , such as an air-to-air heat exchanger, before undergoing expansion (block  94 ), such as in a turbine where work is extracted. In one embodiment, the heat exchanger  128  may reduce the temperature of the gas mixture  16  to less than 32° F. (i.e., less than 0° C.) before undergoing expansion at block  94 . After exiting the expansion step, the CO 2    12  may be in a liquid or solid phase, and thus may, in one implementation, be mechanically separated out (block  96 ). For example, in one embodiment the solid phase CO 2    12  may be separated out from the gas mixture  16  by a cyclone-type device. The solid-phase CO 2  may then be compressed (block  100 ) such as by a posimetric pump or a solid compressor, so that the CO 2  enters a liquid phase which may be pumped. 
     In the depicted embodiment, the remaining gas mixture  106  (such as an N 2  gas mixture) is cold and dry, such as at about −100° F. (i.e., about −74° C.). This remaining gas mixture  106  may be used to remove heat from a cooling water circuit (depicted by dotted lines  132 ) that removes heat from the boiler  124  and drives a steam turbine  134 . For example, the remaining gas mixture  106  may be used in a condenser  136  or other heat removal mechanism to cool the water or other coolant in the cooling circuit  132 . Upon removing heat from the cooling circuit, the remaining gas mixture  106  may be at a temperature of about 100° F. (i.e., about 37° C.). 
     In one embodiment, the remaining gas mixture  106  may be further used to cool the boiler  124 . In such an embodiment, the remaining gas mixture absorbs rejected or radiated heat from the boiler  124 , heating the remaining gas mixture  106  to about 300° F. to about 500° F. (i.e., about 148° C. to about 260° C.). The heated remaining gas mixture  106  may then be expanded (block  104 ), such as via a turbine, to extract additional work. 
     Turning to  FIG. 5 , in certain embodiments it may useful to condense the CO 2  directly from the gas mixture as a liquid, as opposed to a solid, thereby avoiding mechanical separation of the solid CO 2  and pressurization or compression of the solid CO 2  to a liquid form. Such embodiments may be implemented by maintaining the gas stream at a suitably high pressure. 
     For example, in one such embodiment air  120  is introduced to the boiler  124 , such as a high pressure boiler, at increased pressure, such as by operation of a compressor  140 . By performing the combustion at higher pressure, flue gas compression may be avoided or reduced. For example, flue gas may be kept above or near the triple-point of CO 2  such that the CO 2  can be subsequently condensed as a solid instead of a liquid. In one such example, the air  120  may be introduced to the boiler  124  at increased pressure, so that the compression step between the first and second cooling steps may be omitted and, likewise, the heat exchanger operation prior to the expansion step  94  of  FIG. 4  may be omitted. Further, as depicted in  FIG. 6 , the system of  FIG. 5  may be further modified to omit the expansion step  94 . In one such embodiment, CO 2    12  may be collected in a liquid phase at a CO 2  separation stage  97 . 
     In  FIG. 7  an alternative embodiment is depicted in the context of an air cycle machine for CO 2  capture in the context of a natural gas combined cycle. As will be appreciated, such an implementation may also be used in the context of other fuel types. In the depicted example, discussion of certain aspects may be omitted to focus on those aspects related to CO 2  separation and/or capture. 
     For example, turning to  FIG. 7 , a gas turbine engine  160  is depicted to which air  120  is provided at ambient temperature and pressure for combustion. In the depicted embodiment, the air  120  initially enters a low pressure compressor  162  which compresses the air  120 , thereby increasing the temperature of the air, such as to about 300° F. (i.e., about 148° C.). In the depicted example, the air  120  may then pass through an intercooler  164  which reduces the temperature of the air  120 , such as to about 120° F. (i.e., about 48° C.). The cooled air  120  may then be passed though a high pressure compressor  166 , after which the air temperature may be about 750° F. (i.e., about 398° C.). The compressed air  120 , along with a fuel stream  122 , may then enter a combustor  168  where the air  120  and fuel  122  are combusted. The exhaust gas mixture  16  produced by the combustion process may pass through one or more turbines, such as high pressure turbine  170  and/or low pressure turbine  172  which act to generate power. Upon exiting the gas turbine engine  160 , the gas mixture  16  may be about 800° F. to about 1,100° F. (i.e., about 426° C. to about 593° C.). The gas mixture  16  may pass through a heat exchanger, such as the depicted heat recovery steam generator (HRSG)  174  that includes a water/steam cycle  176  that acts to cool the gas mixture  16  and recover heat energy that may be used to perform additional work. For example, the steam cycle interfaced by the HRSG  174  may include a steam turbine power plant drive by the heat generated by the gas turbine engine  160 . 
     Upon exiting the HRSG  174  (or other heat exchanger), the temperature of the gas mixture  16  is reduced, such as to about −10 C and a portion of the water  20  may drop out as a liquid. The gas mixture  16  may be further cooled upon passage through a heat exchanger  178 , which may lower the temperature of the gas mixture  16  to about −30 C, thereby forcing some or all of the remaining water  20  out of the gas mixture  16 . In the depicted example, the gas mixture  16  may pass through a second low pressure compressor  180  where the gas mixture  16  is pressurized, thereby increasing the temperature, such as to about 300° F. to about 400° F. (i.e., about 148° C. to about 204° C.). The compressed gas mixture  16  may then pass through a second intercooler  182  where the temperature of the gas mixture is lowered, such as to about −30 to −80 C. In one embodiment, external refrigeration may be employed to achieve this additional cooling. The gas mixture  16  may then undergo an expansion (block  184 ) where work may be extracted after which the remaining gas mixture  106  may be at a temperature of −70 to −130 C and the CO 2    12  may be in a liquid or solid phase suitable for separation (block  188 ) from the gas mixture, such as by a suitable separation mechanism (i.e., settling tanks with sweeps, cyclones, and so forth). In the depicted implementation, the separated CO 2  is in a solid phase and is compressed (block  190 ), such as by a posimetric pump and/or solid compressor, to yield a liquid phase CO 2  product. 
     The remaining gas mixture  106 , which may be primarily dry N 2 , may be used to cool the air inlet of the gas turbine engine  160  or as an input to the gas turbine engine  160  to improve the efficiency of the system and to reduce the formation of NOx (e.g., NO, NO 2 , and so forth) in the combustion process. In addition, the remaining gas mixture  106  may be used to cool one or more of the heat exchanger components of the system, such as the heat exchanger  178  used to cool the gas mixture  16  upon exiting the HRSG  174 . 
     Turning to  FIGS. 8 and 9 , a further embodiment of an approach to CO 2  capture which utilizes an air drying system is depicted in  FIG. 8 . An example of a suitable air drying system is depicted in  FIG. 9  for reference. In the depicted system of  FIG. 8 , the ambient air  120  is initially dried, such as by a desiccant air drying system  200 , and cooled, such as by heat exchanger  204 , before being provided to the gas turbine engine  160 . In one such embodiment, the air  120  leaving the heat exchanger  204  and entering the gas turbine engine  160  is at about −10° F. to about −20° F. (i.e., about −23° C. to about −29° C.). Such cooled air should be relatively dense relative to air at ambient temperature and thus may provide an increase in power generated by the gas turbine engine  160 . As discussed with respect to  FIG. 7 , the air  120  is combusted with fuel  122  in the gas turbine engine  160 . In one embodiment, the exhaust gas mixture  16  leaving the gas turbine engine is at about 800° F. (i.e., about 426° C.) before entering the HRSG  174 , where the gas mixture is further cooled such that some or all of the water  20  drops out in liquid form. 
     In the depicted embodiment, the gas mixture  16  is compressed in a low pressure compressor  180  and subsequently cooled by an intercooler  182 . In the depicted implementation, the gas mixture  16  is also passed through a second air drying system  210  before undergoing expansion (block  184 ) where work may be extracted. As discussed with respect to  FIG. 7 , upon being expanded, the gas mixture may be at a temperature and pressure where the CO 2  is in a solid or liquid form and amenable to separation (block  188 ) from the gas mixture, such as by mechanical or other suitable approaches. In the depicted embodiment, the remaining gas mixture  106 , which may be at about −70 C to −130 C may be used to cool the heat exchanger  204  (which may form part of the air inlet of the gas turbine engine  160 ) through which air  120  passes to enter the gas turbine engine  160  and/or to cool one or more of the disclosed intercoolers. In certain embodiments, as discussed above, to the extent the separated CO 2    12  is in a solid phase, the CO 2  may be compressed (block  190 ), such as using a posimetric pump or solid compressor, to a liquid phase. 
     With respect to  FIG. 9 , an example of a desiccant air drying system, such as depicted at blocks  200  and  210  of  FIG. 8 , is depicted in greater detail. In this example, air  120  passes through an air contactor  220  where the air  120  comes in contact with a suitable desiccant material  222  that circulates through the air contactor  220 . In one embodiment, the desiccant material  222  is a liquid desiccant, such as a salt solution (e.g., lithium bromide, calcium chloride, lithium chloride, and so forth) or other suitable desiccant. In one such implementation, the desiccant  222  enters the air contactor  220  at about 60° F. (i.e., about 15° C.) but is heated while in contact with the air  120 . In the air contactor  220 , moisture from the air  120  is absorbed by the desiccant material  222 , thereby drying the air  120  and increasing the water content of the desiccant  222 . In the depicted embodiment, the dried air  120  proceeds to a subsequent process stage (such as the heat exchanger  204  or expander  184  of  FIG. 8 ). 
     The desiccant  222 , after contacting the air  120 , is increased in temperature (such as to about 75° F. (i.e., about 23° C.) and water content. The desiccant  222  is processed to remove the absorbed water content, allowing the desiccant  222  to be reused in the air drying process. In the depicted example, the desiccant  222 , such as a liquid desiccant, is pumped (such as via pump  226 ) through a first heat exchanger  228 . The heat exchanger  228  acts to heat the moist desiccant  222  traveling through one portion of the heat exchanger  228  while cooling the dried desiccant  222  traveling through a different portion of the heat exchanger  228 . As a result, the moist desiccant leaving the heat exchanger  228  is heated to a temperature of about 150° F. (i.e., about 65° C.). 
     In the depicted example, the partially heated desiccant  222  may be further heated in a second heat exchanger  230  which utilizes hot gas turbine exhaust  232  (such as prior to the exhaust gas  232  passing through the HRSG) to further heat the desiccant  222 . For example, in one embodiment, the heated desiccant is at a temperature of about 200° F. to about 300° F. (i.e., about 93° C. to about 148° C.). The heated desiccant  222  may then be routed through a contactor boiler  236  through which ambient air  240  is passed so as to contact the heated desiccant  222 . The ambient air  240  absorbs moisture from the heated desiccant  222  such that the desiccant  222  leaving the contactor boiler  236  is dry, i.e., has little or no moisture content. In one example, the desiccant  222  leaving the contactor boiler  236  is at about 200° F. to about 300° F. (i.e., about 93° C. to about 148° C.). 
     The desiccant  222  may then, in one implementation, be pumped (such as via pump  240 ) through the heat exchanger  228  discussed above such that the heat of the dried desiccant is used to heat the moist desiccant leaving the air contactor  220 . As a result of this heat exchange, the dried desiccant is in turn cooled and exits the heat exchanger  228  at a lower temperature, such as about 100° F. (i.e., about 37° C.). In one embodiment, the desiccant  222  may be further cooled, such as via a third heat exchanger  242  which uses a coolant  244 , such as cooling water from cooling towers, to extract heat from the desiccant  222 . In such an embodiment, the desiccant  222  may be at a temperature of about 60° F. (i.e., about 15° C.) after exiting the heat exchanger  242 . The dried and cooled desiccant  222  may then be reused to dry air  120  passing through the air contactor  220 . 
     In another embodiment the implementation discussed above with respect to  FIG. 7  may be modified such that the system is operated at higher pressure downstream of the gas turbine engine  160 . For example, in the depicted embodiment of  FIG. 10 , air  120  is provided to the gas turbine engine  160  at ambient temperature and pressure for combustion. In this embodiment, the exhaust gas mixture  16  leaving the gas turbine engine  160  is not fully expanded and, as a result, does not need to be compressed downstream. For example, in one such embodiment the gas mixture  16  leaving the gas turbine engine  160  is at a temperature of about 1,100° F. (i.e., about 593° C.) and at a pressure between 1.1 bar and 10 bar (e.g., 2 bar to 6 bar or 5 bar). At such a temperature and pressure, the steam turbine of the steam cycle  176  (interfaced via the HRSG  174 ) may operate at a higher efficiency. Further, in one such implementation, the flue gas is kept near or above the triple point of CO 2  so that there is no subsequent flue gas compression step. In one such example, the CO 2  may be subsequently condensed as a liquid instead of a solid due to the flue gas being maintained at a higher pressure. 
     Upon exiting the HRSG  174 , the temperature of the gas mixture  16  is reduced and a portion of the water  20  may drop out as a liquid. The gas mixture  16  may be further cooled upon passage through a heat exchanger  178 , which may lower the temperature of the gas mixture  16 , thereby forcing some or all of the remaining water  20  out of the gas mixture  16 . In the depicted example, the gas mixture  16  is still at pressure (e.g., about 5 bar) and may pass through a second intercooler  182  where the temperature of the gas mixture is lowered. The gas mixture  16  may then undergo an expansion (block  184 ) where work may be extracted. Upon expansion the gas mixture  16  is sufficiently cool that the CO 2    12  may be in a liquid or solid phase (depending on the pressure) suitable for separation (block  188 ) from the gas mixture  16 , such as by a suitable separation mechanism (i.e., settling tanks with sweeps, cyclones, and so forth). In one implementation, the separated CO 2  is in a solid phase and is compressed (block  190 ), such as by a posimetric pump and/or solid compressor, to yield a liquid phase CO 2  product. In other implementations, the gas mixture  16  is at sufficient pressure that the CO 2    12  is condensed out as a liquid. 
     Further, as previously discussed, the remaining gas mixture  106 , which may be primarily dry N 2 , may be used to cool the air inlet of the gas turbine engine  160  or as an input to the gas turbine engine  160  to improve the efficiency of the system and to reduce the formation of NO in the combustion process. In addition, the remaining gas mixture  106  may be used to cool one or more of the heat exchanger components of the system, such as the heat exchanger  178  used to cool the gas mixture  16  upon exiting the HRSG  174 . 
     Turning to  FIG. 11 , in an embodiment where liquefied natural gas (LNG) is available, a regas and air cycle machine may be employed in the system for CO 2  capture. In the depicted embodiment of  FIG. 11 , the natural gas combined cycle implementation depicted with respect to  FIG. 8  is modified to include an exhaust drier  260  (as discussed with respect to  FIG. 9 ) downstream from the HRSG  174  but upstream of the second low pressure compressor  180 . In one such implementation, the remaining gas mixture  106  (primarily dry N 2 ) is at a temperature of about −100° F. (i.e., about −74° C.) and may be used to cool the second intercooler  182  and/or the exhaust drier  260 . 
     In addition, a liquefied natural gas (LNG) circuit  264  is depicted with respect to the second intercooler  182  which assists in cooling the gas mixture  16  as it passes through the second intercooler  182  and, in the process heating or gasifying the LNG in the circuit  264 . For example, in one embodiment, the natural gas (NG) approaches second intercooler  182  in a liquid state, such as at a temperature of about −160° F. (i.e., about −106° C.). In this example, the liquefied natural gas absorbs heat from the exhaust gas  16  via the interface with the second intercooler  182  and leaves the interface with the second intercooler  184  at a higher temperature and in a gasified state. 
     In an additional embodiment, the present approaches to CO 2  capture may be integrated in a combined cycle power generation scheme, as depicted in  FIG. 12 . In the depicted embodiment, the air  120  is initially cooled prior to entering the gas turbine engine  160 , such as via heat exchanger  204 , which may be provided as an inlet air cooler in certain implementations. In one such example, the largest volume compressor stages are present in the gas turbine engine  160  portion of the combined cycle. 
     In the depicted embodiment, the exhaust gas mixture  16  exiting the gas turbine engine  160  is not fully expanded and may, therefore, be at a pressure of about 1.5 bar to about 5 bar when entering the HRSG  174 . In one such embodiment, the increased gas turbine exhaust pressure may reduce the volume flow and length of a low swirl burner present in gas turbine engine  160 . The gas mixture  16 , after exiting the HRSG  174 , may pass through a heat exchanger  178 , such as an air-to-air heat exchanger, prior to undergoing an expansion step, such as at expander  184 . In one embodiment, the temperature of the gas mixture  16  leaving the heat exchanger  178  and entering the expander  184  is less than about 32° F. (i.e., about 0° C.). As discussed in other embodiments, upon being expanded, the gas mixture  16  may be at a temperature and pressure where the CO 2  is in a solid or liquid form and amenable to separation (block  188 ) from the gas mixture, such as by mechanical or other suitable approaches. In the depicted embodiment, the remaining gas mixture  106 , which may be at about −100° F. (i.e., about −73° C.) may be used to cool the heat exchanger  178  and/or the heat exchanger  204  (which may form part of the air inlet of the gas turbine engine  160 ) through which air  120  passes to enter the gas turbine engine  160  and/or to cool one or more of the disclosed intercoolers. 
     As will be appreciated, the approaches discussed herein may be used in a variety of contexts to capture CO 2 , and are not limited to those examples discussed herein. For example, cryogenic processes as discussed herein may be utilized to replace CO 2  (and potentially H 2 S) removal in certain types of power production plants, such as a plant based on an integrated gasification combined cycle as may be used to produce power from syngas derived from coal. In such an example, CO 2  may be frozen or condensed on gasification such that the cooled syngas drops out water, CO 2 , and H 2 S. Likewise, the present approaches may be applied in other contexts to remove CO 2  from exhaust gases or other gas mixtures, regardless of the manner in which the gas mixture is derived or produced. 
     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.