System and method for operating a power plant in combustion and non-combustion control modes with gas processing - Patents.com

Abstract

The system includes a controller configured to vary operation of the combustion-driven power plant between a first control mode and a second control mode, the first control mode including an ignition mode of the combustion-driven power plant and an exhaust gas treatment mode of the gas treatment system for treating exhaust gases through at least one gas capture system, and the second control mode including a non-ignition mode of the combustion-driven power plant and an air treatment mode for treating an air flow through the at least one gas capture system, the air flow being directed by one or more air movers.

Description

[Technical Field]

[0001] FIELD OF THE INVENTION This application relates generally to systems and methods for operating gas treatment systems to treat exhaust gases or air, for example, in connection with power plants that use combustion systems as an energy source to generate electricity.

[0002] Industrial plants, such as power plants, may produce various gases, such as exhaust gases from combustion systems. The combustion systems may include gas turbine engines or systems, reciprocating piston-cylinder engines, furnaces, boilers, or other industrial equipment. These exhaust gases may include one or more undesirable gases, such as acid gases and / or greenhouse gases. For example, undesirable gases may include carbon oxides, such as carbon dioxide (CO) and carbon monoxide (CO), nitrogen oxides, such as nitrogen dioxide (NO), and / or sulfur oxides, such as sulfur dioxide (SO). CO is both an acid gas and a greenhouse gas. Unfortunately, the CO content in the atmosphere has generally increased over millennia and currently exceeds approximately 420 parts per million by volume (ppmv) or 643 parts per million by weight (ppmw) in the atmosphere. Due to various regulations and environmental concerns regarding global warming, it would be desirable to reduce the emission of undesirable gases (e.g., CO) into the atmosphere, especially for equipment that consumes hydrocarbon fuels, such as combustion systems. [Prior art documents] [Patent documents]

[0003] [Patent Document 1] U.S. Patent Application Publication No. 2018 / 0216532 Summary of the Invention

[0004] Certain embodiments commensurate in scope with the originally claimed subject matter are summarized below. These embodiments are not intended to limit the scope of the claimed embodiments; rather, these embodiments are intended only to provide a brief summary of possible forms of the present subject matter. Indeed, the embodiments claimed herein may include a variety of forms that may be similar to or different from the embodiments set forth below.

[0005] In a specific embodiment, a system includes a power plant having a first powertrain with a first combustion system, a first turbine, and a first motor-generator. The power plant includes a gas treatment system having at least one gas capture system configured to at least partially capture undesirable gases. The power plant includes an exhaust flow path through the at least one gas capture system, an air flow path through the at least one gas capture system, and at least one flow control device configured to control flow through the exhaust flow path and the air flow path. The power plant includes a controller configured to change operation of the power plant between a first control mode and a second control mode. The first control mode includes an ignition mode of the first combustion system to drive the first motor-generator in a generator mode to produce electrical power and an exhaust gas treatment mode of the gas treatment system to treat the exhaust gases through the at least one gas capture system. The second control mode includes a non-ignition mode of the first combustion system and an air treatment mode to treat an air flow through at least one of the first or second gas capture systems, the air flow being induced by one or more air movers.

[0006] In certain embodiments, the system includes a controller configured to vary operation of the combustion-driven power plant between a first control mode and a second control mode. The first control mode includes an ignition mode of the combustion-driven power plant and an exhaust gas treatment mode of the gas treatment system for treating exhaust gases through at least one gas capture system. The second control mode includes a non-ignition mode of the combustion-driven power plant and an air treatment mode for treating an air flow through the at least one gas capture system, the air flow being directed by one or more air movers.

[0007] In certain embodiments, a method includes varying operation of a combustion-driven power plant between a first control mode and a second control mode. The method includes controlling operation of the combustion-driven power plant in a first control mode, the first control mode including an ignition mode of the combustion-driven power plant and an exhaust gas treatment mode of the gas treatment system for treating exhaust gases through at least one gas capture system. The method includes controlling operation of the combustion-driven power plant in a second control mode, the second control mode including a non-ignition mode of the combustion-driven power plant and an air treatment mode for treating an air flow through the at least one gas capture system, the air flow being directed by one or more air movers.

[0008] These and other features, aspects, and advantages of the presently disclosed technology will become better understood from the following detailed description when taken in conjunction with the accompanying drawings, in which like reference numerals represent like parts throughout. [Brief explanation of the drawings]

[0009] [Figure 1] 1 is a schematic diagram of an embodiment of a combined cycle power plant having a gas turbine system, a heat recovery steam generator (HRSG), a steam turbine system, and a multi-stage gas processing system having multiple gas capture systems configured to capture undesirable gases (e.g., CO). [Figure 2]FIG. 2 is a schematic diagram of one embodiment of a gas capture system for the multi-stage gas processing system of FIG. 1, illustrating a sorbent-based gas capture system. [Figure 3] 2 is a schematic diagram of an embodiment of a gas capture system of the multi-stage gas processing system of FIG. 1, illustrating a solvent-based gas capture system. [Figure 4] 2 is a schematic diagram of an embodiment of the combined cycle power plant of FIG. 1 further illustrating details of a multi-mode configuration for selectively operating in power producing and power consuming modes. [Figure 5] 1 is a schematic diagram of an embodiment of a power plant having a multi-mode configuration for selectively operating in a power producing mode and a power consuming mode. [Figure 6] FIG. 5 is a schematic diagram of an embodiment of the combined cycle power plant of FIGS. 1 and 4, further illustrating multiple powertrains having a gas turbine system, a steam turbine system, an HRSG, and a motor-generator. [Figure 7] 6 is a schematic diagram of an embodiment of the power plant of FIG. 5, further showing a plurality of powertrains having a combustion system, a steam generator, an air mover, a steam turbine, and a motor-generator. [Figure 8] 8 is a flow chart of one embodiment of a process for controlling operation of a power plant in power producing and power consuming modes, as described above with reference to FIGS. 1-7. DETAILED DESCRIPTION OF THE INVENTION

[0010] Described below are one or more specific embodiments of the system of the present disclosure. In an effort to provide a concise description of these embodiments, all features of an actual implementation may not be described herein. It should be understood that in developing such an actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developer's particular objectives, including, for example, adherence to system-related and business-related constraints, which may vary from implementation to implementation. Moreover, it should be understood that such a development effort may be complex and time-consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill in the art having the benefit of this disclosure.

[0011] When introducing elements of various embodiments of the presently disclosed embodiments, the words "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.

[0012] The disclosed embodiments include systems and methods for reducing the carbon footprint of combustion systems, such as combustion-driven power plants. For example, the disclosed embodiments can reduce the carbon footprint of a power plant to at least carbon neutral or carbon negative. However, the disclosed embodiments are not limited to carbon neutral or carbon negative footprints, and thus any reduction in the carbon footprint of a power plant is within the scope of the disclosed embodiments. In the context of this application, any reference to a carbon neutral or carbon negative target or goal is intended as a non-limiting example.

[0013] As described below, the disclosed embodiments selectively operate a power plant in a power production mode (e.g., a firing mode or a fuel combustion mode) to generate electricity and a power consumption mode (e.g., a non-firing mode or a non-combustion mode) to consume electricity, with the gas processing system configured to treat exhaust gases during the power production mode and the gas processing system configured to treat an air stream during the power consumption mode. During the power production mode, the power plant combusts fuel to generate combustion gases to drive one or more motor-generators (e.g., operating in a generator mode) as an energy source to generate electricity, while the gas processing system removes undesirable gases (e.g., CO) from the exhaust gases. For example, the combustion gases may be used to drive a gas turbine of a gas turbine system coupled to the motor-generators, and / or the combustion gases may be used to generate steam to drive a steam turbine of a steam turbine system coupled to the motor-generators. During the power consumption mode, the power plant consumes electricity to drive one or more air streams through the gas processing system, thereby treating the air to reduce the power plant's carbon footprint. For example, a power plant may consume electricity to operate a motor-generator (e.g., operating in electric motor mode) to drive a compressor of a gas turbine system, an air mover of a combustion system, and / or one or more additional air movers that provide one or more air flows through the gas processing system. In some embodiments, the power plant may consume electricity to drive one or more separate motor-driven air movers to provide one or more air flows through the gas processing system. Thus, in certain embodiments, the power consumption mode does not involve combustion of fuel to generate electricity, but rather an air flow is provided to the gas processing system for processing the air. In certain embodiments, the gas processing system may include a single gas capture system or multiple gas capture systems, and the gas processing system may be configured to use the same or different gas capture systems to process exhaust gases in a power production mode and to process air in a power consumption mode.Thus, the present application contemplates any use of the same or different gas capture systems for exhaust gas and air treatment.

[0014] As described in more detail below, a power plant can operate in a power production mode when power demand and / or energy pricing are above a threshold level and can operate in a power consumption mode when power demand and / or energy pricing are below a threshold level (e.g., low or negative energy pricing). The threshold level can vary depending on various factors, including threshold levels based on operator preferences, emissions standards, or any other factor. In this application, any description of power demand and / or energy pricing as the basis for switching a power plant between a power production mode and a power consumption mode is intended as a non-limiting example. In the context of power demand and energy pricing, when power demand and / or energy pricing are low or negative, the power plant can use electricity, thereby providing advantageous environmental benefits by treating the air to reduce undesirable gases (e.g., CO) in the ambient air. Overall, by treating the exhaust gas during the power production mode and treating the air stream during the power consumption mode, the power plant may have lower overall emission levels of undesirable gases (e.g., CO) than if it only treated the exhaust gas during the power production mode. In this way, power plants can more easily achieve their target carbon footprint, such as carbon neutral or carbon negative emissions (e.g., CO2 emissions), or another suitable target.

[0015] In the context of exhaust gas treatment, carbon neutral is a state of net-zero CO2 emissions, where the amount of CO2 in the exhaust gas is equal to the amount of CO2 in the inlet air entering the process. Similarly, in the context of exhaust gas treatment, carbon negative is a state of net-negative CO2 emissions, where the amount of CO2 in the exhaust gas is less than the amount of CO2 in the inlet air entering the process. In the context of air treatment, carbon negative is a state of net-negative CO2 emissions, where the amount of CO2 in the treated air is less than the amount of CO2 in the ambient air before treatment. In certain embodiments, a power plant enables carbon-neutral or carbon-negative emissions (e.g., CO2 emissions) during power production mode, and the power plant also enables carbon-negative emissions (e.g., CO2 emissions) during power consumption mode. Overall, a power plant may enable carbon-neutral or carbon-negative emissions (e.g., CO2 emissions) when considering exhaust gas treatment during power production mode and air treatment during power consumption mode.

[0016] Again, in some embodiments, the power plant may not achieve carbon-neutral or carbon-negative emissions, but may substantially reduce its carbon footprint by treating exhaust gases (e.g., CO2 capture) in the power production mode and treating air (e.g., CO2 capture) in the power consumption mode. In certain embodiments, the power plant enables a first reduction in emissions (e.g., CO2 capture) during the power production mode, and the power plant also enables a second reduction in emissions (e.g., CO2 capture) during the power consumption mode. The first reduction in emissions can be, for example, at least 50%, 60%, 70%, 80%, 90%, 95%, 97.5%, 99%, or 100% carbon capture (e.g., CO2 capture) from the exhaust gases. The second reduction in emissions can be, for example, at least 50%, 60%, 70%, 80%, 90%, 95%, 97.5%, 99%, or 100% carbon capture (e.g., CO2 capture) from the treated ambient air. Overall, a power plant allows for a reduction in its carbon footprint (e.g., CO2 emissions) when considering exhaust gas treatment during power production mode and air treatment during power consumption mode. Therefore, the following discussion should be understood to be directed to the reduction of undesirable gases (e.g., CO2) that would benefit from air treatment at the power plant, where air treatment may not otherwise occur, as the typical goal is to treat exhaust gases while the power plant is operating to generate electricity. Furthermore, because the power plant's gas treatment system is used for both exhaust gas treatment and air treatment, the power plant can use the same gas treatment system to provide air treatment, rather than investing in a dedicated air treatment system (e.g., a direct air capture (DAC) plant) unrelated to the power plant.

[0017] Although the disclosed embodiments are illustrated and described in the context of CO removal, the disclosed embodiments can be used to remove any “undesirable gas” or “undesirable gases,” including, but not limited to, carbon oxides (e.g., CO, CO), nitrogen oxides (e.g., NO), sulfur oxides (e.g., SO), and various other acid gases and / or greenhouse gases. As described below, the combustion system may be associated with a power plant (e.g., a coal- or other fuel-burning power plant or a combined-cycle power plant), a simple-cycle gas turbine system, a reciprocating piston-cylinder engine, a furnace, a boiler, or other industrial equipment that produces exhaust gases. The combined-cycle power plant can include a gas turbine system that drives an electric generator, a heat recovery steam generator (HRSG) that uses heat from the exhaust gas of the gas turbine system to generate steam, and a steam turbine of a steam turbine system that is driven by the steam to drive the electric generator. The coal- or other fuel-burning power plant can use combustion gases from the combustion fuel (e.g., coal) to generate steam in a steam generator (e.g., a boiler), and the steam turbine of the steam turbine system is driven by the steam to drive the electric generator.

[0018] With the above in mind, the disclosed embodiments include multiple gas processing stages configured to remove undesirable gases (e.g., CO) from the air and / or from the exhaust gas of a combustion system to help achieve desired emissions targets, such as, but not limited to, net-neutral or net-negative emissions. The disclosed embodiments may use the same or different gas processing stages (e.g., gas capture stages) for air processing and exhaust gas processing. Furthermore, while multiple stages can be used for exhaust gas processing and air processing in various configurations, certain embodiments of the gas processing system may use a single stage of gas processing (e.g., gas capture). The multiple gas processing stages may include one or more gas processing systems located upstream of the compressor and / or combustor, or one or more gas processing systems located downstream of the gas turbine and / or HRSG, or a combination thereof. The gas processing system may include an adsorbent-based gas processing system, a solvent-based gas processing system, a cryogenic-based gas processing system, one or more other types of gas processing systems, or a combination thereof. The gas processing system is not limited to the examples described herein; therefore, any suitable gas processing system may be used for gas capture. For example, a sorbent-based gas processing system is configured to adsorb undesirable gases onto a sorbent material and then desorb the undesirable gases from the sorbent material using a heat source. The adsorption process is exothermic, and the desorption process is endothermic. As a further example, a solvent-based gas processing system may include an absorber configured to absorb undesirable gases into a solvent and a regenerator configured to remove the undesirable gases from the solvent using a heat source. Thus, in both types of gas processing systems, a heat source can be used to facilitate the removal and capture of undesirable gases (e.g., CO). During a power production mode (e.g., a firing mode), the heat source may include steam generated by a steam generator (e.g., a HRSG), waste heat from one or more waste heat recovery systems, or a combination thereof.During the power consumption mode (e.g., non-firing mode), the heat source may include one or more heaters (e.g., electric heaters), heat exchangers, or combinations thereof. In some embodiments, the heat source may include one or more separate gas turbine systems that generate heat in the form of exhaust gases, compressed air, and / or waste heat. Further, in some embodiments, the heat source may include one or more separate steam generators (e.g., HRSGs) configured to provide steam as a heat source, for example, associated with the separate gas turbine systems. Various aspects and embodiments of the gas processing system are described in further detail below.

[0019] FIG. 1 is a schematic diagram of an embodiment of a combined cycle power plant 10 having a gas turbine system 12 (e.g., a gas turbine engine), a heat recovery steam generator (HRSG) 14, a steam turbine system 16 (e.g., a steam turbine engine), and a multi-stage gas processing system (GTS) 18. As described in further detail below, the multi-stage gas processing system 18 is configured to process one or more air streams and / or exhaust gases within the combined cycle power plant 10. For example, in a power production mode (e.g., a firing mode or a combustion mode), the combined cycle power plant 10 is configured to generate electricity for local use or distribution on the power grid while processing exhaust gases resulting from combustion of fuel through the multi-stage gas processing system 18. In a power consumption mode (e.g., a non-firing mode or a non-combustion mode), the combined cycle power plant 10 is configured to consume power to drive one or more air streams for processing in the multi-stage gas processing system 18. The power consumption mode is particularly advantageous when power demand and / or power prices are below a threshold, such as low or negative energy pricing. Collectively, the air treatment during the power consumption mode and the exhaust gas treatment during the power production mode help to provide a desired reduction in carbon emissions (e.g., carbon-neutral or carbon-negative emissions (e.g., CO2 emissions)) by the combined cycle power plant 10. The various features and stages of the gas processing system 18 are described in further detail below, and the various features and stages may be used in any suitable combination with each other. However, before moving on to the gas processing system 18 and its different modes (e.g., power production mode and power consumption mode), the combined cycle power plant 10 will be described as one possible context for using the gas processing system 18.

[0020] The cycle of the gas turbine system 12 is often referred to as the “topping cycle,” and the cycle of the steam turbine system 16 is often referred to as the “bottoming cycle.” By combining these two cycles as shown in FIG. 1 , the combined cycle power plant 10 can achieve even greater efficiency in both cycles. In particular, waste heat from the topping cycle can be captured and used to generate steam in the HRSG 14 for use in the bottoming cycle. However, the HRSG 14 can be configured to generate and supply steam for other uses in the combined cycle power plant 10, including the gas processing system 18 (e.g., in power production mode). For example, the gas processing system 18 can be configured to use the steam generated in the HRSG 14 to facilitate separation and capture of undesirable gases, such as carbon capture (e.g., CO capture) in an adsorbent-based gas processing system and / or a solvent-based gas processing system. However, in power consumption mode, the gas processing system 18 can use other heat sources, such as, for example, electric heaters, heat exchangers, waste heat systems, or any combination thereof. During the power consumption mode, use of the heat exchanger and / or waste heat system may depend on the availability of other heating fluids and / or waste heat.

[0021] As shown, the gas turbine system 12 includes an intake section 20, a compressor section 22, a combustor section 24, a turbine section 26, and a motor-generator 28 (e.g., selectively functioning as an electric motor or a generator). As described in detail below, the motor-generator 28 can operate as a generator during a power production mode, while the motor-generator 28 can operate as an electric motor during a power consumption mode. The intake section 20 can include one or more air filters, an anti-icing system, a fluid injection system (e.g., temperature control fluid), a silencer baffle, or any combination thereof, which can be disposed in a filter house and / or an intake duct. In some embodiments, the intake section 20 can include one or more air movers configured to help direct airflow through the intake section 20 and the gas turbine system 12 during a power consumption mode. For example, the air mover can include an electric motor-driven fan or blower that can be activated during a power consumption mode. The compressor section 22 includes multiple compressor stages 30, each having a plurality of rotating compressor blades 32 coupled to a compressor shaft 38 and a plurality of stationary compressor vanes 34 coupled to a compressor casing 36. The combustor section 24 includes one or more combustors 40. A shaft 42 extends between the compressor section 22 and the turbine section 26. Each combustor 40 includes one or more fuel nozzles 44 coupled to one or more fuel supplies 46, which may supply fuel via primary and secondary fuel circuits. The fuel supplies 46 may supply natural gas, syngas, biofuel, fuel oil, or any combination of liquid and gaseous fuels. The turbine section 26 includes multiple turbine stages 56, each having a plurality of rotating turbine blades 48 coupled to a turbine shaft 54 ​​and a plurality of stationary turbine vanes 50 coupled to a turbine casing 52. The turbine shaft 54 ​​also connects to the motor-generator 28 via a shaft 58.

[0022] In a power production mode, the gas turbine system 12 transfers an intake air flow 60 from the intake section 20 to the compressor section 22. The compressor section 22 progressively compresses the intake air flow 60 in stages 30 and delivers a compressed air flow 62 to one or more combustors 40. The one or more combustors 40 receive fuel from a fuel supply 46, transfer the fuel through fuel nozzles 44, and combust the fuel with the compressed air flow 62 to generate hot combustion gases in a combustion chamber 64 within the combustor 40. The one or more combustors 40 then transfer a hot combustion gas flow 66 to the turbine section 26. The turbine section 26 progressively expands the hot combustion gas flow 66, driving the rotation of turbine blades 48 in stages 56 before expelling an exhaust gas flow 68. As the hot combustion gas flow 66 drives the rotation of the turbine blades 48, the turbine blades 48 drive the rotation of the turbine shaft 54, shafts 42 and 58, and compressor shaft 38. Thus, in a power production mode, the turbine section 26 drives the rotation of the compressor section 22 and the motor-generator 28 (e.g., functioning as an electrical generator). An exhaust gas stream 68 may be partially or wholly directed to flow through the HRSG 14 to enable heat recovery and steam generation. In certain embodiments, one or more additional gas turbine systems 12 may be included as part of the combined cycle power plant 10, and the additional gas turbine systems 12 may discharge an exhaust gas stream 68 to the HRSG 14. Thus, the aggregate exhaust gas stream 68 from the gas turbine systems 14 (e.g., one, two, three, four, or more) may be passed through the HRSG 14 to generate steam for the steam turbine system 16, with the exhaust gas stream 68 then being processed by the gas processing system 18.

[0023] The HRSG 14 may include multiple heat exchangers and / or heat exchanging components 70 arranged in different sections, such as a high-pressure (HP) section 72, an intermediate-pressure (IP) section 74, and a low-pressure (LP) section 76. The components 70 may include an economizer, an evaporator, a superheater, or any combination thereof, in each of the HP, IP, and LP sections 72, 74, and 76. The components 70 may be coupled to each other via various conduits and headers. In a power production mode, the HRSG 14 may transfer one or more flows of steam (e.g., low-pressure steam, intermediate-pressure steam, high-pressure steam) to the steam turbine system 16. In the illustrated embodiment, the components 70 of the HRSG 14 include a finishing high-pressure superheater 78, a secondary reheater 80, a primary reheater 82, a primary high-pressure superheater 84, an interstage desuperheater 86, an interstage desuperheater 88, a high-pressure evaporator 90 (HP EVAP), a high-pressure economizer 92 (HP ECON), an intermediate-pressure evaporator 94 (IP EVAP), an intermediate-pressure economizer 96 (IP ECON), a low-pressure evaporator 98 (LP EVAP), and a low-pressure economizer 100 (LP ECON). The HRSG 14 also includes a housing or duct 102 that houses the various components 70. The functions of the components 70 are described in further detail below.

[0024] The steam turbine system 16 includes a steam turbine 104 having a high-pressure steam turbine (HP ST) 106, an intermediate-pressure steam turbine (IP ST) 108, and a low-pressure steam turbine (LP ST) 110, which are coupled to each other via shafts 112 and 114. In certain embodiments, the steam turbine system 16 may include any number of steam turbines, such as one, two, three, four, five, or more steam turbines. As shown, the steam turbine 104 may be coupled to a load 116 (e.g., a generator) via a shaft 118. In some embodiments, the gas turbine system 12 and the steam turbine system 16 are arranged in series along a common shaft, and thus may both drive the same load (e.g., a motor-generator 28). In a power production mode, the HRSG 14 may be configured to generate high-pressure steam for the high-pressure steam turbine 106, intermediate-pressure steam for the intermediate-pressure steam turbine 108, and low-pressure steam for the low-pressure steam turbine 110. In certain embodiments, exhaust from the high-pressure steam turbine 106 may be routed through a primary reheater 82, an interstage superheater 88, and a secondary reheater 80 within the HRSG 14 to an intermediate-pressure steam turbine 108, and exhaust from the intermediate-pressure steam turbine 108 may be routed to a low-pressure steam turbine 110. The steam turbine 104 may discharge condensate 120 (or condense steam in a condenser 122 downstream of the steam turbine 104), which may then be pumped back to the HRSG 14 via one or more pumps 124.

[0025] In the power production mode, the exhaust gas stream 68 passes through the HRSG 14, transferring heat to the components 70 to generate steam for driving the steam turbine 104. The exhaust steam from the low-pressure steam turbine 110 may be directed to a condenser 122 to form condensate 120. The condensate 120 from the condenser 122 may then be directed to the low-pressure section 76 of the HRSG 14 using a pump 124. The condensate 120 may then flow through a low-pressure economizer 100, which is configured to heat feedwater 126 (including the condensate 120) with the exhaust gas stream 68. From the low-pressure economizer 100, the feedwater 126 may flow to the low-pressure evaporator 98. The feedwater 126 from the low-pressure economizer 100 may be directed by a pump 125 toward the intermediate-pressure economizer 96 and the high-pressure economizer 92. Steam from the low-pressure evaporator 98 may be directed to a low-pressure steam turbine 110. Similarly, from the intermediate-pressure economizer 96, feedwater 126 may be diverted into the intermediate-pressure evaporator 94 and / or towards the high-pressure economizer 92. Additionally, steam from the intermediate-pressure economizer 96 may be diverted to a fuel gas heater 95, where the steam may be used to heat fuel gas for use in the combustion chamber 64 of the gas turbine system 12. Steam from the intermediate-pressure evaporator 94 may be diverted to an intermediate steam turbine 108.

[0026] Feedwater 126 from the high-pressure economizer 92 may be routed to the high-pressure evaporator 90. Steam from the high-pressure evaporator 90 may be routed to the primary high-pressure superheater 84 and the finishing high-pressure superheater 78, where the steam is superheated and ultimately routed to the high-pressure steam turbine 106. An interstage desuperheater 86 may be disposed between the primary high-pressure superheater 84 and the finishing high-pressure superheater 78. The interstage desuperheater 86 enables more robust control of the exhaust temperature of the steam from the finishing high-pressure superheater 78. Specifically, the interstage desuperheater 86 may be configured to control the temperature of the steam exiting the finishing high-pressure superheater 78 by injecting a cooled feedwater spray into the superheated steam upstream of the finishing high-pressure superheater 78 whenever the exhaust temperature of the steam exiting the finishing high-pressure superheater 78 exceeds a predetermined value.

[0027] Additionally, exhaust from the high-pressure steam turbine 106 may be directed to the primary reheater 82 and the secondary reheater 80, where it may be reheated before being directed to the intermediate-pressure steam turbine 108. The primary reheater 82 and the secondary reheater 80 may also be associated with an interstage desuperheater 88 configured to control the exhaust steam temperature from the reheaters. Specifically, the interstage desuperheater 88 may be configured to control the temperature of the steam exiting the secondary reheater 80 by injecting a cooling feedwater spray into the superheated steam upstream of the secondary reheater 80 whenever the exhaust temperature of the steam exiting the secondary reheater 80 exceeds a predetermined value. The arrangement of the components 70 of the HRSG 14 is merely one possible example for use in the combined cycle power plant 10 and gas processing system 18, and the components 70 may be arranged differently within the scope of the present disclosure.

[0028] The combined cycle power plant 10 further includes a fluid connection system 130 between a stage of the HRSG 14 and a stage of the steam turbine system 16. For example, the fluid connection system 130 includes a high-pressure steam supply conduit or line 132 coupled to an inlet to the finishing high-pressure superheater 78 and the high-pressure steam turbine 106, and a discharge or return line 134 coupled to an outlet of the high-pressure steam turbine 106 and the primary reheater 82. The fluid connection system 130 also includes an intermediate-pressure steam supply conduit or line 136 and a discharge or return line 138. The intermediate-pressure steam supply line 136 is fluidly coupled to an outlet of the intermediate-pressure evaporator 94 and the secondary reheater 80 and to an inlet to the intermediate-pressure steam turbine 108. The discharge or return line 138 is fluidly coupled to an outlet of the intermediate-pressure steam turbine 108 and an inlet to the low-pressure steam turbine 110. The fluid connection system 130 also includes a low-pressure steam supply conduit or line 140 and a discharge or return line 142. A low-pressure steam supply line 140 is fluidly coupled to an outlet of the low-pressure evaporator 98 and a discharge or return line 138 from the intermediate-pressure steam turbine 108, as well as an inlet to the low-pressure steam turbine 110. A discharge or return line 142 is fluidly coupled to an outlet of the low-pressure steam turbine 110 and an inlet to the low-pressure economizer 100. As mentioned above, the return line 142 includes the condenser 122 and the pump 124.

[0029] The combined cycle power plant 10 may include a control system 144 communicatively coupled to a monitoring system 146, with the control system 144 and monitoring system 146 communicatively coupled to various components of the gas turbine system 12, the HRSG 14, the steam turbine system 16, and the gas processing system 18. The monitoring system 146 is configured to monitor a plurality of sensors 148, designated by "S," distributed throughout the combined cycle power plant 10. The control system 144 includes a controller 150, which includes one or more processors 152, a memory 154, and instructions 156 stored in the memory 154 and executable by the processor 152, to perform various control functions for operating the gas turbine system 12, the HRSG 14, the steam turbine system 16, and the gas processing system 18. In certain embodiments, the control system 144 may communicate information (e.g., sensor feedback, alerts, alarms, etc.) to a user interface, cloud storage, a remote computer system, or any combination thereof.

[0030] The sensors 148 may be communicatively coupled to the control system 144 via communication wires or wireless communication circuitry. The sensors 148 may be located at one or more locations in the intake section 20, the compressor section 22, the combustor section 24, the turbine section 26, the HRSG 14, the steam turbine system 16, the gas processing system 18, and the surrounding environment (e.g., air quality monitoring). For example, the sensors 148 may be located at one or more locations in each of the high-pressure steam turbine 106, the intermediate-pressure steam turbine 108, and the low-pressure steam turbine 110, thereby enabling monitoring of steam properties (e.g., temperature, pressure, etc.) at various locations. The sensors 148 may also be located along each of the lines 132, 134, 136, 138, 140, 142 of the fluid connection system 130, thereby serving to monitor various fluid parameters between the HRSG 14, the steam turbines 106, 108, and 110 and the gas processing system 18. Additionally, sensors 148 may be coupled to and / or distributed throughout gas processing system 18 to enable monitoring and control of gas processing (e.g., gas capture) from various air and / or exhaust gas streams. In certain embodiments, sensors 148 may include flow sensors, pressure sensors, temperature sensors, fluid composition sensors, flame sensors, vibration sensors, clearance sensors, trip sensors, or any combination thereof. Fluid composition sensors may monitor composition levels of various undesirable gases, such as, for example, carbon oxides (e.g., CO, CO), nitrogen oxides (e.g., NO), sulfur oxides (e.g., SO), and various other acid gases and / or greenhouse gases, as well as composition levels of oxygen, hydrogen, and unreacted fuel gas content.Thus, sensor feedback from sensors 148 can be used to adjust various aspects of gas processing system 18 in power producing and power consuming modes to reduce the carbon footprint of combined cycle power plant 10, such as by substantially removing undesirable gases (e.g., CO) from the exhaust gases and air (e.g., ambient air), so that the carbon footprint is at least below a desired carbon emissions threshold (e.g., at least low carbon, carbon neutral, or carbon negative emissions). Further details of monitoring and control of gas processing system 18 are discussed further below.

[0031] As described in further detail below, gas processing system 18 is configured to remove and / or capture one or more undesirable gases (e.g., exhaust gases, acid gases, greenhouse gases, etc.) from one or more air streams and / or exhaust gas stream 68 during power production and power consumption modes of combined cycle power plant 10. For example, during power production mode, gas processing system 18 is configured to remove and / or capture one or more undesirable gases from inlet air stream 60 to gas turbine system 12 (e.g., upstream of compressor section 22 and / or combustor section 24) and / or exhaust gas stream 68 (e.g., downstream of turbine section 26 and / or HRSG 14). In a further example, during the power consumption mode, one or more air streams may be configured to remove and / or capture one or more undesirable gases from the one or more air streams, which may flow internally through the gas turbine system 12 (e.g., the compressor section 22, the combustor section 24, and the turbine section 26), entirely external to the gas turbine system 12, or partially internal and partially external to the gas turbine system 12 (e.g., through the compressor section 22 but not through the combustor section 24 and / or the turbine section 26) using compressor bleed lines extending to the gas processing system 18. Various air circuits are described in further detail below with reference to FIG. 7. During the power consumption mode, the gas processing system 18 may not process the exhaust gas stream 68; however, some embodiments may route the exhaust gas stream from another source to the gas processing system 18 for processing in conjunction with the air stream.

[0032] Undesirable gases are intended to encompass any gases that may be undesirable in the ambient air, the intake air stream 60, and / or the exhaust gas stream 68. For example, undesirable gases may include acid gases and / or greenhouse gases. As a further example, undesirable gases may include carbon oxides (CO), such as carbon dioxide (CO) and carbon monoxide (CO). X ), nitrogen oxides (NO X), sulfur dioxide (SO2) and other sulfur oxides (SO X The adsorption or absorption of CO from ambient air, intake air stream 60, and / or exhaust gas stream 68 may include any gas that is typically subject to regulation, including, but not limited to, CO, methane (CH), or any combination thereof. The disclosed embodiments are particularly well suited for gas adsorption or absorption of CO from ambient air, intake air stream 60, and / or exhaust gas stream 68. However, the following description is intended to cover each of these examples when referring to undesirable gases.

[0033] The gas processing system 18 may include multiple gas capture systems 160 (e.g., gas capture systems 162, 164, 166) located throughout the combined cycle power plant 10 to process gas streams (e.g., air streams, exhaust streams, etc.). Each of the gas capture systems 160 (e.g., 162, 164, and 166) may be configured to use one or more heat sources to facilitate gas capture, and the gas capture systems 160 may include an adsorbent-based gas capture system, a solvent-based gas capture system, or a combination thereof. As described below, the heat sources may include a heating fluid 168 (e.g., steam and / or heated water) extracted from the HRSG 14 and / or the steam turbine system 16 and supplied to the gas capture system 160 via a steam supply system 170 (e.g., a steam supply circuit), waste heat recovered by a waste heat recovery (WHR) system 172 of the combined cycle power plant 10, one or more electric heaters, or a combination thereof. The HRSG 14 and the waste heat recovery system 172 may typically be available during the power production mode of the combined cycle power plant 10; however, portions of the HRSG 14 and the waste heat recovery system 172 may not be available during the power consumption mode of the combined cycle power plant 10. For example, during the power consumption mode, the heat source may include an electric heater, which may be used to generate the heating fluid 168 and / or to provide heat in a different manner. For example, the electric heater may be configured to apply heat directly to the gas capture systems 162, 164, and 166, for example, by directly heating the sorbent material and / or solvent. In this application, any description of the heating fluid 168 for use as a heat source for the gas capture systems 162, 164, and 166 is intended to include embodiments that rely on an electric heater or other heat source being available during the power consumption mode. For example, the power consumption mode may also use a heat exchanger and / or the waste heat recovery system 172, depending on the availability of the heating fluid and / or waste heat.

[0034] In the power production mode, gas processing system 18 may use steam and / or waste heat as a heat source, as described below. Steam supply system 170 may include steam supply conduits or lines 174 and 176 coupled at one or more locations to HRSG 14 and / or steam turbine system 16. In the illustrated embodiment, steam supply lines 174 and 176 may be coupled to HRSG 14 and / or steam turbine system 16 at or between the low-pressure and intermediate-pressure sections, such as, for example, between low-pressure steam turbine 110 and intermediate-pressure steam turbine 108 and / or between LP section 76 and IP section 74 of HRSG 14. However, in certain embodiments, steam supply system 170 may be selectively coupled to any, multiple, or all of the components of HRSG 14 (e.g., one or more components or locations in each of HP, IP, and LP sections 72, 74, and 76) and / or to any, multiple, or all of the stages of steam turbine system 16 (e.g., HP, IP, and LP steam turbines 106, 108, 110) so that heating fluid 168 (e.g., steam and / or heated water) may be extracted at one or more pressures, temperatures, or conditions for use in gas capture system 160. For example, control system 144 may be configured to control various valves coupled to steam lines to control steam flow from the various components of HRSG 14 and the stages of steam turbine system 16. Additionally, in certain embodiments, heating fluid 168 (e.g., steam and / or heated water) may be extracted from other sources, such as a waste heat steam generator that generates steam using waste heat from waste heat recovery system 172. The gas processing system 18 is also configured, via control by the control system 144, to combine steam 18 from various steam sources (e.g., HRSG 14, steam turbine system 16, waste heat recovery system 172, waste heat steam generator, etc.) to provide a mixed steam having desired steam characteristics, such as steam temperature and associated pressure between upper and lower temperature thresholds. Additionally, the quality of the steam (saturated or superheated) may be monitored to meet the specific heating requirements of the gas processing system 18.

[0035] A control system 144 and a monitoring system 146 are communicatively coupled to the gas processing system 18, including the various gas capture systems 160, to provide control of the gas processing and capture process, including control of the heat source (e.g., heating fluid 168, waste heat, electric heaters, etc.) used by the gas capture systems 160. The heat source may depend on the mode of the combined cycle power plant 10. For example, in a power consumption mode of the combined cycle power plant 10, the heating fluid 168 may be unavailable, and thus the gas processing system 18 may rely on one or more electric heaters as a heat source. However, when the heating fluid 168 is available, such as during a power production mode of the combined cycle power plant 10, steam may be applied to the gas processing system 18 for indirect heating via a heat exchanger process or direct heating of a CO2-bearing adsorbent or solvent. If the monitoring system 146 (e.g., sensor 148) indicates that the temperature of the extracted heating fluid 168 (e.g., steam and / or heated water) is above an upper temperature threshold, the control system 144 may be configured to control the gas treatment system 18 to temper or cool the heating fluid 168 (e.g., via a desuperheater, chiller, or heat exchanger) to reduce the steam temperature to within the upper and lower temperature thresholds. If the monitoring system 146 (e.g., sensor 148) indicates that the temperature of the extracted heating fluid 168 (e.g., steam and / or heated water) is below a lower temperature threshold, the control system 144 may be configured to control the gas treatment system 18 to heat the heating fluid 168 (e.g., via a heater or heat exchanger) to increase the steam temperature to within the upper and lower temperature thresholds. In certain embodiments, the upper and lower temperature thresholds for a gas capture system 160 that uses a sorbent material (e.g., a sorbent-based gas capture system) may be between approximately 80°C and 120°C.

[0036] For temperature regulation, steam supply lines 174 and 176 can include respective heat exchangers 178 and 180 configured to condition the heating fluid 168 (e.g., steam and / or heated water) supplied to gas capture system 160. Heat exchangers 178 and 180 can use another fluid to heat or cool the steam. For example, waste heat recovery system 172 can be configured to exchange heat (e.g., via a heat exchange fluid) with heat exchangers 178 and 180 to heat or cool the heating fluid 168 (e.g., steam and / or heated water) to within upper and lower temperature thresholds. Control system 144 can be coupled to various valves, pressure regulators, and sensors 148 to help control the respective flows through heat exchangers 178 and 180, thereby controlling the heat exchange and the resulting temperature of heating fluid 168 (e.g., steam and / or heated water). Additionally or alternatively, as described above, the waste heat recovery system 172 may be configured to transfer heat between the waste heat and the heating fluid 168 (e.g., steam and / or heated water), for example, in a waste heat steam generator, to adjust the temperature of the heating fluid 168. The waste heat recovery system 172 may also be used to improve the efficiency of the combined cycle power plant 10 in other ways, such as to provide heat to other equipment throughout the combined cycle power plant 10.

[0037] The waste heat recovery system 172 may include multiple distributed waste heat recovery systems 182, 184, 186. The waste heat recovery system 182 is coupled to the motor-generator 28 (e.g., a generator) of the gas turbine system 12, the waste heat recovery system 184 is coupled to the load 116 (e.g., a generator) of the steam turbine system 16, and the waste heat recovery system 186 is coupled to a compression system 188 of the gas processing system 18. The waste heat recovery systems 182, 184, 186 may include one or more heat exchangers configured to transfer heat between a respective heat-generating component (e.g., 28, 116, 188) and one or more fluids. For example, each waste heat recovery system 182, 184, 186 may transfer heat between a first fluid (e.g., a coolant and / or lubricant within the heat-generating component 28, 116, 188) and a second fluid via a first heat exchanger. The second fluid may be water used directly to generate steam in a waste heat steam generator, or may be a working fluid used indirectly to transfer heat to water (e.g., via a second heat exchanger) to generate steam. In some embodiments, the waste heat recovery system 172 may include one or more distributed waste heat recovery systems coupled to other machinery and equipment in the combined cycle power plant 10, including, but not limited to, electric motors, pumps, compressors, chemical reactors, air separation units (ASUs), or any combination thereof. In some embodiments, the waste heat recovery system 172 may be configured to deliver a heating fluid (e.g., water, coolant, lubricant, etc.) to supply heat to the gas capture system 160, which may be used alone or in combination with the heating fluid 168 (e.g., steam and / or heated water) as a heat source for the gas capture system 160. Again, when the aforementioned heat sources are unavailable, such as during a power consumption mode of the combined cycle power plant 10, one or more electric heaters may be used as a heat source to support the gas processing system 18.

[0038] In certain embodiments, the gas capture systems 160 (e.g., 162, 164, 166) can be arranged in series (e.g., multiple stages), in parallel, or a combination thereof, relative to the direction of flow through the combined cycle power plant 10. However, the illustrated embodiment includes at least two of the gas capture systems 160 arranged in series, whereby the multiple stages of gas capture serve to sequentially reduce the content of undesirable gases to a desired gas capture threshold (e.g., a low-carbon, net-neutral, or net-negative capture state). For example, gas processing system 18 may include or selectively operate multiple gas capture systems 162 only, multiple gas capture systems 164 only, multiple gas capture systems 166 only, a combination of gas capture systems 162 and 164, a combination of gas capture systems 162 and 166, a combination of gas capture systems 164 and 166, all of gas capture systems 162, 164, and 166, or any suitable multi-stage configuration of two, three, four, five, six, seven, eight, nine, ten, or more gas capture systems 160. Additionally, multi-stage gas treatment system 18 can include the same or different gas capture systems 160 at various locations, such as different sizes or flow capacity, different internal surface areas along the flow paths, different flow rates along the flow paths, different numbers of flow paths, different geometric or serpentine configurations of the flow paths, different residence times along the flow paths, different gas capture technologies (e.g., adsorbent-based gas capture and / or solvent-based gas capture), specifications for treating high or low concentrations of undesired gases, or any combination thereof. For example, gas capture systems 162 and 166 may be designed to treat low concentrations of undesired gases, while gas capture system 164 may be designed to treat high concentrations of undesired gases. In some embodiments, the concentration of undesired gases in gas capture systems 162 and 166 may be 100 times or more lower than in gas capture system 164.

[0039] Gas capture systems 162, 164, and 166 may vary in design and gas processing capabilities, depending at least in part on their placement in combined cycle power plant 10. In the illustrated embodiment, gas capture system 162 is coupled to combined cycle power plant 10 along inlet air stream 60 (e.g., at inlet section 20), and gas capture systems 164 and 166 are coupled to combined cycle power plant 10 along exhaust gas stream 68 (e.g., downstream of turbine section 26). However, gas capture systems 164 and 166 may be selectively operated for gas processing of exhaust gas stream 68 during a power production mode or for gas processing of an air stream during a power consumption mode. In certain embodiments, any one or more of gas capture systems 162, 164, and / or 166 may be used to process the air stream and capture undesirable gases (e.g., CO) during a power consumption mode.

[0040] In the illustrated embodiment, the gas capture system 162 is configured to capture undesirable gases (e.g., CO) from a flow of air (airflow) 190 before entering the gas turbine system 12 and / or before combustion. In a power production mode, the gas capture system 162 uses a heating fluid 168 (e.g., steam and / or heated water) as a heat source; however, in a power consumption mode, the gas capture system 162 may use one or more electric heaters as a heat source. As described in further detail below, the gas capture system 162 may include a sorbent-based gas capture system, a solvent-based gas capture system, or a combination thereof. An example is provided below with reference to FIGS. 2 and 3. A steam supply line 174 is coupled to the gas capture system 162 and provides the heating fluid 168 (e.g., steam and / or heated water) as a steam stream and / or a water stream, as indicated by arrow 192. As described above, the steam supply system 170 may include one or more steam supply lines (e.g., lines 174) coupled to the HRSG 14 and / or the steam turbine system 16 so as to be able to supply the heating fluid 168 (e.g., steam and / or heated water) to the gas capture system 162 under various conditions (e.g., pressure, temperature, steam content, water content, etc.).

[0041] While shown in the intake section 20, the gas capture system 162 may be configured to treat the airflow 190 at any location throughout the combined cycle power plant 10, including upstream of the compressor section 22, between the compressor stages 30 of the compressor section 22, downstream of the compressor section 22 and upstream of the combustor section 24, other locations containing the airflow, or combinations thereof. In certain embodiments, the gas capture system 162 may be configured to treat recirculated exhaust gas (EGR), such as the exhaust gas 68 recirculated to the compressor section 22, and thus the gas capture system 162 may be sized to handle high concentrations of undesirable gases recirculated as part of the EGR process. The gas capture system 162 generally treats the airflow 190 (or EGR stream) directed into the gas turbine system 12 to reduce concentrations of undesirable gases, while simultaneously sending the captured gas 194 to the compression system 188 via an exhaust conduit or line 196. The exhaust line 196 may also include post-treatment equipment, such as a dryer 198 configured to remove moisture content from the trapped gas 194 .

[0042] 1 , gas capture systems 164 and 166 are coupled to the combined cycle power plant 10 along the exhaust gas stream 68 downstream of the gas turbine section 26 and the HRSG 14. In a power production mode of the combined cycle power plant 10, the gas capture systems 164 and 166 are configured to remove undesirable gases from the exhaust gas stream 68 discharged from the gas turbine system 12 and the HRSG 14. In certain embodiments, the gas capture systems 164 and 166 may be configured to treat the exhaust gas stream at any location throughout the combined cycle power plant 10, including upstream of the HRSG 14, between sections of the HRSG 14 (e.g., HP, IP, and LP sections 72, 74, and 76), downstream of the HRSG 14, in a separate exhaust gas stream relative to the exhaust gas stream 68, or any combination thereof. For example, the separate exhaust gas stream may originate from another combustion system, such as, for example, a furnace, a boiler, a reciprocating piston-cylinder engine, or any combination thereof. In the illustrated embodiment, gas capture system 164 is positioned upstream of gas capture system 166, such that gas capture systems 164 and 166 may represent first and second gas capture stages along exhaust gas flow 68. In a power consumption mode of combined cycle power plant 10, one or both of gas capture systems 164 and 166 may be used to process an airflow while no combustion is occurring in gas turbine system 12. For example, as described below with reference to FIGS. 4-7 , the airflow may be diverted internally through gas turbine system 12, externally from gas turbine system 12, and / or partially internal and external to gas turbine system 12, where the airflow is channeled through one or both of gas capture systems 164 and 166 to remove undesirable gases (e.g., CO) from the air.

[0043] As further shown in FIG. 1 , gas processing system 18 may include one or more dryers 200, one or more fans 202, and one or more valves 204 along a flow path (e.g., duct) 206 upstream of gas capture systems 164 and 166. In a power production mode, flow path 206 corresponds to an exhaust flow path for exhaust gas stream 68. In a power consumption mode, flow path 206 may correspond to an air flow path for an air stream, such as an air stream passing through the interior of gas turbine system 12. One or more dryers 200 are configured to remove moisture (e.g., water content or steam) and dry exhaust gas stream 68 and / or the air flow along flow path 206. One or more fans 202 (e.g., electric motor fans) are configured to increase the pressure and / or flow rate of exhaust gas stream 68 and / or the air flow along flow path 206. One or more valves 204 are configured to adjust the pressure, flow rate, and / or distribution of exhaust gas stream 68 and / or the air flow along flow path 206 to gas capture systems 164 and 166. In certain embodiments, the illustrated dryer 200, fan 202, and valve 204 are partially or entirely shared by the gas capture systems 164 and 166. However, in some embodiments, one or more dryers 200, fans 202, and valves 204 may be independently located upstream of each of the gas capture systems 164 and 166. Depending on the mode of the combined cycle power plant (e.g., power production mode or power consumption mode), the exhaust gas stream 68 and / or the air flow along the flow path 206 may flow through each of the gas capture systems 164 and 166 in series to progressively remove undesirable gases and achieve a desired capture amount. For example, in the power production mode, the exhaust gas stream 68 flows through both the gas capture systems 164 and 166. In the power consumption mode, the air flow may flow through only the gas capture system 164, only the gas capture system 166, or both the gas capture systems 164 and 166.In some embodiments, the gas capture system 166 may be designed for low concentrations of undesirable gases (e.g., CO), and therefore the gas capture system 166 may be better suited to process the airflow in a power consumption mode.

[0044] In the power production mode of the combined cycle power plant 10, the gas capture system 164 removes a portion of the undesired gases from the exhaust gas stream 68 and discharges a treated exhaust gas stream (e.g., an upstream or first stage treated exhaust gas) to the gas capture system 166, discharging a trapped gas portion of the trapped gas 194 as indicated by discharge conduit or line 208. As described in further detail below, the gas capture system 164 may include an adsorbent-based gas capture system, a solvent-based gas capture system, or a combination thereof. Examples are provided below with reference to Figures 2 and 3. A steam supply line 176 is coupled to the gas capture system 164 and supplies a heating fluid 168 (e.g., steam and / or heated water) to the gas capture system 164 as a steam stream and / or a heated water stream. As described above, the steam supply system 170 may include one or more steam supply lines (e.g., line 176) coupled to the HRSG 14 and / or the steam turbine system 16 to supply the heating fluid 168 (e.g., steam and / or heated water) to the gas capture system 164 at various conditions (e.g., pressure, temperature, steam content, water content, etc.). The discharge line 208 may include various aftertreatment devices, such as a dryer 210 configured to remove moisture (e.g., water content or steam) and dry the captured gas 194 to produce a dried captured gas, as indicated by a discharge conduit or line 212. The captured gas 194 then flows to the compression system 188, as described below. In a power consumption mode, the gas capture system 164 may selectively remove a portion of the undesired gases from the air stream and discharge a treated air stream (e.g., an upstream or first-stage treated air stream) to the gas capture system 166, where the trapped gas portion of the captured gas 194 may be discharged, as indicated by a discharge conduit or line 208. The heat source used during the power consumption mode may include one or more different heat sources, such as an electric heater and / or a heat exchanger.

[0045] Similarly, in the power production mode of the combined cycle power plant 10, the gas capture system 166 removes a portion of the undesired gases from the exhaust gas stream 68 and discharges the treated exhaust gas stream (e.g., downstream or second-stage treated exhaust gas) to a subsequent gas capture system or exhaust stack 214, which discharges the trapped gas portion of the captured gas 194 as indicated by discharge conduit or line 216. As described in further detail below, the gas capture system 166 can include an adsorbent-based gas capture system, a solvent-based gas capture system, or a combination thereof. Examples are provided below with reference to Figures 2 and 3. A steam supply line 176 is coupled to the gas capture system 166 and supplies a heating fluid 168 (e.g., steam and / or heated water) to the gas capture system 166 as a steam stream and / or a heated water stream. As described above, the steam supply system 170 may include one or more steam supply lines (e.g., line 176) coupled to the HRSG 14 and / or the steam turbine system 16 so as to supply the heating fluid 168 (e.g., steam and / or heated water) to the gas capture system 166 at various conditions (e.g., pressure, temperature, steam content, water content, etc.). The discharge line 216, as indicated by discharge conduit or line 220, may include various after-treatment equipment, such as a dryer 218 configured to remove moisture (e.g., water content or steam) and dry the captured gas 194 to produce a dry captured gas. The captured gas 194 then flows to the compression system 188, as described below. In the power consumption mode, the gas capture system 166 may selectively remove a portion of the undesired gas from the airflow and exhaust the treated airflow (e.g., a downstream or second stage treated airflow) to a subsequent gas capture system or exhaust stack 214, exhausting the trapped gas portion of the trapped gas 194 as indicated by exhaust conduit or line 216. The heat source used during the power consumption mode may include one or more different heat sources, such as an electric heater and / or a heat exchanger.

[0046] Compression system 188 can include a single-stage or multi-stage compression system. In the illustrated embodiment, compression system 188 includes one or more first or upstream compressors 222 configured to compress capture gas 194 in one or more upstream stages, one or more second or downstream compressors 224 configured to compress capture gas 194 after compression by compressors 222, and one or more intercoolers 226 configured to cool capture gas 194 between compressors 222 and 224. Intercooler 226 can include heat exchangers, gas dryers, and / or other equipment to facilitate gas compression. Compression system 188 outputs compressed capture gas 194 at a specified pressure and gas purity to a storage unit and / or pipeline 228, as indicated by discharge conduit or line 230. As mentioned above, waste heat recovery system 186 may be coupled to compression system 188 to extract waste heat that may be used as a heat source for gas processing system 18 (e.g., gas capture system 160), for improved plant efficiency, or for other uses. Waste heat recovery system 186 may be coupled to one or more of compressor 222, compressor 224, and / or intercooler 226.

[0047] As mentioned above, gas capture systems 162, 164, and 166 may vary depending on their placement in combined cycle power plant 10. For example, gas capture system 162 may be designed to process low concentrations of undesirable gases, such as CO concentrations at or near typical atmospheric concentration levels, thereby ensuring that gas capture system 162 is configured to reduce the CO concentration to a level below typical atmospheric concentration levels (e.g., less than about 420 ppmv CO). For example, gas capture system 162 may be configured to reduce the concentration of CO by at least 50%, 60%, 70%, 80%, or 90% of typical atmospheric concentration levels. In certain embodiments, to achieve such concentration levels, gas capture system 162 may be sized substantially larger than gas capture systems 164 and 166 to allow sufficient residence time for the gas (e.g., air being processed within gas capture system 162). In certain embodiments, gas capture system 162 may be excluded from gas processing system 18.

[0048] In contrast, gas capture system 164 may be designed to handle higher concentrations of undesired gas compared to gas capture systems 162 and / or 166, and gas capture system 166 may be designed to handle lower or moderate concentrations of undesired gas compared to gas capture systems 162 and / or 164. For example, gas capture system 164 may be designed to handle at least 10 times, 20 times, 30 times, 40 times, 50 times, 60 times, 70 times, 80 times, 90 times, 100 times, 110 times, 120 times, 130 times, 140 times, 150 times, or more CO2 concentrations than gas capture system 162, while gas capture system 166 may be designed to handle at least 2 times, 3 times, 4 times, 5 times, 6 times, 7 times, 8 times, 9 times, 10 times, or more CO2 concentrations than gas capture system 162. By way of further example, gas capture system 164 may be designed to process at least 10 times, 11 times, 12 times, 13 times, 14 times, 15 times, 16 times, 17 times, 18 times, 19 times, 20 times, 21 times, 22 times, 23 times, 24 times, 25 times, or more CO concentrations than gas capture system 166. By way of further example, gas capture system 166 may be designed to process at least 1%, 2%, 3%, 4%, 5%, 6%, 7%, 8%, 9%, 10% or more CO concentrations relative to the concentration of CO processed by gas capture system 162. In one embodiment, in the power production mode of combined cycle power plant 10, gas capture systems 164 and 166 may capture approximately 95% and 4.5%, respectively, of the total CO concentration in exhaust gas stream 68, and vent the remaining 0.5% to exhaust stack 214. In another embodiment, gas capture systems 164 and 166 may capture approximately 90% and 9.5%, respectively, of the total concentration of CO in exhaust gas stream 68, leaving the remaining 0.5% for emission to exhaust stack 214. Thus, in a power consumption mode, embodiments of gas capture systems 162 and / or 166 may be suitable for low concentrations of undesirable gases (e.g., CO) present in air, rather than high concentrations of undesirable gases present in exhaust gas stream 68.

[0049] In certain embodiments, gas capture system 164 may be designed to handle an inlet CO concentration of about 60,000 ppmw (parts per million by weight) (e.g., capture at least 70%, 75%, 80%, 85%, 90%, 95% or more of the CO), gas capture system 162 may be designed to handle an inlet CO concentration of about 643 ppmw (e.g., capture at least 50%, 60%, 70%, 80% or more of the CO), and gas capture system 166 may be designed to handle an inlet CO concentration of about 3,000 ppmw (e.g., capture at least 50%, 60%, 70%, 80%, 90% or more of the CO). In certain embodiments, gas capture system 164 may be designed to capture approximately 25,000-100,000 ppmw of CO, gas capture system 162 may be designed to capture approximately 100-300 ppmw of CO, and gas capture system 166 may be designed to capture approximately 1,000-10,000 ppmw of CO. In some embodiments, gas capture system 164 may be designed to capture at least 70%, 75%, 80%, 85%, 90%, 95%, or more of the total CO concentration in exhaust gas stream 68, while gas capture systems 162 and / or 166 may be designed to capture substantially all or a portion of the remaining CO (e.g., at least 70%, 80%, 85%, 90%, or 95% of the remaining CO) present in exhaust gas stream 68 that is not captured. Carbon capture by gas capture system 162 removes undesirable gases (e.g., CO) from intake air stream 60, indirectly reducing the presence of undesirable gases in exhaust gas stream 68. Again, in power consumption mode, embodiments of gas capture systems 162 and / or 166 may be suited to low concentrations of undesirable gases (e.g., CO) present in air, rather than high concentrations of undesirable gases present in exhaust gas stream 68.

[0050] In one particular embodiment, gas capture system 164 may be designed to capture approximately 95% of the total CO concentration in exhaust gas stream 68 (e.g., 95% of 60,000 ppmw, resulting in gas capture of 57,000 ppmw of CO), and gas capture systems 162 and / or 166 may be designed to capture substantially all or part of the remaining 5% of the total CO concentration in exhaust gas stream 68 (e.g., 2.5%, 3%, 3.5%, 4%, 4.5%, or 5% of 60,000 ppmw, resulting in partial or complete capture of an additional 3,000 ppmw of CO). For example, gas capture systems 162 and / or 166 may capture 90% (e.g., 90% of the 3,000 ppmw CO) of the remaining 5% (or substantially 4.5%) of the total CO concentration, resulting in only 300 ppmw CO in the treated exhaust gas stream 68 delivered to exhaust stack 214. This particular embodiment results in a net-negative carbon footprint for combined cycle power plant 10. However, various configurations of gas capture systems 160 (e.g., 162, 164, and 166) are contemplated by the present disclosure to achieve a desired carbon footprint (e.g., a low-carbon, net-neutral, or net-negative carbon footprint) for combined cycle power plant 10.

[0051] In some embodiments, each of gas capture systems 162, 164, and 166 can include several modular gas capture units, each of which has a common capacity, with the number of modular gas capture units selected based on the concentration level (e.g., CO2 level) in the gas being processed in the particular gas capture system 162, 164, or 166. The modular gas capture units can also include modular sorbent-based gas capture units, modular solvent-based gas capture units, or a combination thereof. In this manner, gas capture systems 162, 164, and 166 can be assembled and scaled to meet the needs of a particular location and application using the same or different types of gas capture technology.

[0052] As described above, control system 144 and monitoring system 146 are communicatively coupled to gas capture system 160 and various sensors 148 to provide monitoring and control of gas capture of undesirable gases (e.g., CO). For example, sensors 148 may include gas composition sensors configured to provide concentration levels of undesirable gases (e.g., CO) and other gases (e.g., oxygen, hydrogen) upstream, within, and / or downstream of each of gas capture systems 160. Sensors 148 may also include temperature, pressure, and flow rate sensors configured to provide relevant feedback regarding the flow of gases (e.g., air, exhaust gases) processed by gas capture system 160 and the flow of steam or other fluids used to support gas capture system 160. Using sensor feedback, the control system 144 can adjust the operation of the gas capture system 160 depending on the concentration level of the undesired gases and the operating mode (e.g., power production mode or power consumption mode), such as by adjusting the properties (e.g., temperature, pressure, flow rate, and / or flow path) of the steam or other fluid within the gas capture system 160, adjusting the residence time within the gas capture system 160, activating or deactivating one or more of the gas capture systems 160, adjusting the dryers (e.g., 200, 210, and 218), adjusting the fan 202, adjusting the valve 204, adjusting the HRSG 14 and / or the extraction of the heating fluid 168 (e.g., steam and / or water content and condition, extraction point, etc.), adjusting the electric heater that provides heat to the gas capture system, adjusting the gas turbine system 12 (e.g., adjusting the fuel / air ratio, combustion characteristics, fuel type, fuel additives, etc.), or any combination thereof. By coordinating various aspects of the gas processing system 18 (e.g., multiple stages of the gas capture system 160) in conjunction with the gas turbine system 12 and the HRSG 14, the combined cycle power plant 10 can be configured to provide a desired carbon footprint (e.g., a low-carbon, net-neutral, or net-negative carbon footprint).

[0053] The gas capture systems 160 (e.g., 162, 164, and 166) may be configured in various ways depending on the particular demand and CO2 concentration levels and operating mode (e.g., power production mode or power consumption mode) of the combined cycle power plant 10. Table 1 illustrates various scenarios for the gas capture systems 162, 164, 166 in the combined cycle power plant 10. In the scenarios below, each of the gas capture systems 162, 164, and 166 is depicted as either n / a (e.g., not present or not activated), an adsorbent-based system as described below with reference to FIG. 2, or a solvent-based system as described below with reference to FIG. 3. The adsorbent-based and solvent-based gas capture systems can each use a heating fluid 168 (e.g., steam and / or heated water) from the HRSG 14 and / or waste heat (e.g., 182, 184, and / or 186) from the waste heat recovery system 172 as a heat source for the gas capture process. Additionally, for each of the following scenarios, the adsorbent-based systems may be the same or different in type, configuration, capacity, residence time, and / or any other characteristic. Similarly, for each of the following scenarios, the solvent-based systems may be the same or different in type, configuration, capacity, residence time, and / or any other characteristic. Finally, for each of the following scenarios, gas capture systems 162, 164, and 166 may each include one or more stages and / or parallel flows of gas capture.

[0054] [Table 1] JPEG2026502429000003.jpg177162

[0055] As noted above, the disclosed embodiments include at least 58 scenarios for gas capture systems 162, 164, and 166. Additional scenarios are contemplated using other gas capture technologies and / or variations of sorbent-based, solvent-based, and cryogenic gas capture systems. With the above in mind, Figures 2 and 3 present embodiments of sorbent-based and solvent-based gas capture systems.

[0056] In certain embodiments, the control system 144 and the monitoring system 146 may be used to monitor and control the operation of the combined cycle power plant 10 in multiple operating modes (e.g., a power production mode and a power consumption mode), which may depend on energy demand, energy pricing, energy credits, gas capture credits, or any combination thereof. For example, at certain times, energy demand and / or energy pricing may fall to a level where it is undesirable to operate the combined cycle power plant 10 to generate electricity. For example, energy pricing may fall below a pricing threshold, such as low pricing, zero pricing, or negative pricing for power generation. Negative pricing may result in energy credits (e.g., monetary compensation) for stopping the supply of power to the power grid. Gas capture credits may correspond to tax credits for capturing undesirable gases, such as carbon capture credits (e.g., CO2 capture credits). When the gas turbine system 10 is non-firing or non-combusting (e.g., no fuel is being burned to produce combustion gases), the gas capture credit (e.g., tax credit) may be higher, resulting in gas capture (e.g., direct air capture) occurring only on the air stream without the exhaust gas stream 68. In contrast, when the gas turbine system 10 is firing or combusting (e.g., fuel is being burned to produce combustion gases), the gas capture credit may be lower, resulting in gas capture occurring on the exhaust gas stream 68 (e.g., alone or in combination with gas capture on the air stream). Accordingly, the monitoring system 146 may be configured to monitor current energy demand, current energy pricing, energy credits, gas capture credits, or other factors that may cause a change in the operation of the combined cycle power plant 10.

[0057] Thus, depending on energy demand, energy pricing, energy credits, and gas capture credits, the control system 144 can modify the operation of the combined cycle power plant 10 to selectively operate in a power production mode or a power consumption mode. For example, the power production mode can include an ignition mode or a combustion mode of the gas turbine system 12, in which the fuel supply 46 supplies fuel to the combustor 40, igniting a fuel-air mixture to generate hot combustion gases that then drive the turbine section 26 to generate electricity via the motor-generator 28 operating in a generator mode. In other words, the power production mode (e.g., the ignition mode) of the gas turbine system 12 actively combusts fuel with air to operate the gas turbine system 12 and generate electricity. In the power production mode, the exhaust gas stream 68 also passes through the HRSG 14, which generates steam to operate the steam turbine system 16 and generate electricity via a load 116 (e.g., a generator). Exhaust gas stream 68 then flows through gas capture systems 164 and 166 which process exhaust gas stream 68 to obtain captured gas 194 as described above.

[0058] However, if the monitoring system 146 determines that energy demand and / or energy pricing falls below a lower threshold and / or that energy credits and gas capture credits exceed a threshold, the control system 144 may control the combined cycle power plant 10 to switch from the power production mode to a power consumption mode. In the power consumption mode, which may also be described as a no-fire mode or no-combustion mode, the control system 144 controls the gas turbine system 12 to stop igniting or burning the fuel-air mixture in the combustor 40, thereby stopping the flow of hot combustion gases through the turbine section 26. In other words, in the power consumption mode, the gas turbine system 12 may stop supplying fuel from the fuel supply 46 to the combustor 40, stop igniting the fuel-air mixture, and therefore stop generating hot combustion gases that drive the turbine section 26. As a result, the power consumption mode no longer powers the gas turbine system 12 by the expansion of hot combustion gases through the turbine section 26. Instead, in the power consumption mode, the control system 144 is configured to operate the motor-generator 28 in a motor mode (e.g., an electric motor), thereby enabling the motor-generator 28 (e.g., an electric motor) to drive the rotation of the gas turbine system 12. When the motor-generator 28 (e.g., an electric motor) rotates the gas turbine system 12, the compressor section 22 rotates and compresses the intake air flow 60 from the intake section 20, causing the compressed air 62 to flow internally through the combustor section 24 and the turbine section 26. Thus, the power consumption mode of the gas turbine system 12 consumes electricity to drive the rotation of the gas turbine system 12 using the motor-generator 28 (e.g., an electric motor) to drive the rotation of the gas turbine system 12 and cause the air to flow internally through the compressor section 22, the combustor section 24, and the turbine section 26.

[0059] The airflow from the gas turbine system 12 may then be routed directly or indirectly to one or both of the gas capture systems 164 and 166. For example, the control system 144 may be configured to control various valves and flow controls to extract the airflow exiting the turbine section 26 so that the airflow can bypass the HRSG 14 and / or the gas capture system 164. For example, the control system 144 may be configured to control one or more air circuits (e.g., bypass flow paths or circuits) to direct the airflow from the turbine section 26 to the gas capture system 166 (or one or both of the gas capture systems 164 and 166). In certain embodiments, as described in further detail below, the control system 144 may also be configured to control one or more air circuits (e.g., bleed lines or circuits) from the compressor section 22 to the gas capture system 166 (or one or both of the gas capture systems 164 and 166). Additionally, the control system 144 may be configured to operate one or more air movers, such as air compressors, fans, and / or blowers, to direct or drive airflow within the gas turbine system 12 and / or at least partially or entirely external to the gas turbine system 12 through the gas capture system 166 (or one or both of the gas capture systems 164 and 166).

[0060] Gas capture system 166 (or one or both of gas capture systems 164 and 166) is then configured to treat the air stream to help treat the air in the environment. For example, gas capture system 166 can reduce undesirable gases (e.g., CO) in the environment and output captured gas 194, and output a treated air product via exhaust stack 214. In certain embodiments, gas capture system 166 can be used to treat the air stream without gas capture systems 162 and 164. In some embodiments, gas capture system 166 is used in combination with gas capture system 162 and / or gas capture system 164 to treat the air stream for air treatment and capture of undesirable gases (e.g., CO) and to obtain captured gas 194.

[0061] In the power consumption mode, the gas capture systems 162, 164, and / or 166 can use heat from one or more heat sources to aid in the gas capture process. However, in the power consumption mode, the gas turbine system 12 does not ignite to produce combustion gases, and therefore the HRSG 14 does not transfer heat from the exhaust gas stream 68 to water to generate steam, and therefore the HRSG 14 cannot produce steam to operate the steam turbine system 16. Therefore, the control system 144 can stop operation of the HRSG 14 and the steam turbine system 16 during the power consumption mode. In some embodiments, with low, zero, or negative energy prices, the control system 144 can be configured to operate the HRSG 14 using heat provided by an electric heater, and the steam can be used as a heat source for the gas capture systems 162, 164, and / or 166. However, in other embodiments, HRSG 14 and steam turbine system 16 may not operate during the power consumption mode, and one or more different heat sources (e.g., electric heaters) may be used to provide heat to gas capture systems 162, 164, and / or 166. For example, electric heaters may be used to directly or indirectly heat the solvent in a solvent-based gas capture system, the adsorbent material in an adsorbent-based gas capture system, or a combination thereof.

[0062] Additionally, in certain embodiments, one or more additional combustion systems, such as additional gas turbine systems, reciprocating engine systems, furnaces, or other combustion systems, may be configured to supply hot combustion gases to HRSG 14 for steam generation to operate steam turbine system 16 and / or supply exhaust gases to gas capture systems 164 and 166. For example, if another combustion system continues to operate in a power production mode while gas turbine system 12 operates in a power consumption mode, exhaust gases from the other combustion system may still be used to operate HRSG 14 and steam turbine system 16 of combined cycle power plant 10 and / or continue exhaust gas processing through capture systems 164 and 166, along with providing airflow to one or more of gas capture systems 162, 164, and / or 166.

[0063] In certain embodiments, the control system 144 and the monitoring system 146 may be used to monitor and control the operation of the combined cycle power plant 10 in multiple load-based operating modes (e.g., full load mode and part-load mode) related to the power production mode, where the part-load mode may be less than or equal to approximately 30%, 40%, 50%, 60%, 70%, 80%, or 90% of the full-load operating condition of the combined cycle power plant 10. In the part-load mode, the control system 144 may be configured to redirect one or more airflows through the gas capture systems 162, 164, and / or 166 in addition to the exhaust gas flowing through the gas capture systems 164 and 166. For example, during the part-load mode, the gas turbine system 12 may produce a substantially reduced flow rate or amount of exhaust gas for processing by the gas capture systems 164 and 166, resulting in some unused capacity for gas processing in the gas capture systems 164 and 166. As an example, the part-load mode results in only 30%, 40%, 50%, 70%, 80%, or 90% of the capacity of the gas capture systems 164 and 166 being used. The unused capacity may be based on the exhaust gas flow rate, the percentage of undesirable gases in the exhaust gas, the rated capacity of the gas capture systems 164 and 166, or various other factors. The control system 144 selectively enables airflow to one or both of the gas capture systems 164 and 166 during the part-load mode, thereby removing or capturing undesirable gases (e.g., CO) from both the exhaust gas and the ambient air. Additionally, the gas capture systems 164 and 166 can use available excess heat from the exhaust gas and / or steam from the HRSG 14 to aid in the desorption of undesirable gases from the sorbent material, the removal of undesirable gases from the solvent, or any combination thereof, depending on the configuration of the gas capture systems 164 and 166. The part-load mode may be used in the power production mode in any of the embodiments described in detail below.

[0064] While gas capture systems 162, 164, and 166 can include a variety of configurations and gas capture processes, Figures 2 and 3 illustrate possible implementations that may be used for one or more of gas capture systems 162, 164, and 166. Additionally, Figures 4-7 illustrate possible implementations of gas treatment system 18 for treating exhaust gases and air in different modes, such as a power production mode and a power consumption mode. Figure 8 illustrates a process for operating gas treatment system 18 according to the embodiment shown in Figures 1-7.

[0065] 2 is a schematic diagram of one embodiment of the gas capture system 160 of the multi-stage gas processing system 18 of FIG. 1 , illustrating a sorbent-based gas capture system 250. In the illustrated embodiment, the sorbent-based gas capture system 250 includes a sorbent-based gas capture assembly or unit 252 (e.g., an adsorber or adsorption unit) having a plurality of sorbent-containing conduits 254, such as sorbent-containing conduits 256 and 258. The sorbent-containing conduits 254 (e.g., 256 and 258) may be lined with sorbent along their interior surfaces, may be filled within their interior volumes with sorbent, or may generally be filled with sorbent material to a volume percentage of at least 10%, 20%, 30%, 40%, 50%, 60%, 70%, 80%, 90%, or more. However, the sorbent-based gas capture unit 252 can include any number of sorbent-containing conduits 254, such as 2, 3, 4, 5, 6, 7, 8, 9, 10, or more, configured in parallel and / or series. Each of the sorbent-containing conduits 254 (e.g., 256 and 258) includes an outer conduit wall 260 disposed circumferentially about a flow path 262 along a central axis 264 from an inlet 266 to an outlet 268, with a sorbent material 270 disposed along and / or within a central bore or inner surface 272 of the outer conduit wall 260.

[0066] The sorbent material 270 (e.g., solid sorbent) can cover, coat, or substantially fill at least 50%, 60%, 70%, 80%, 90%, 95%, or 100% of the inner surface 272 of the outer conduit wall 260. Additionally or alternatively, the sorbent material 270 can at least partially fill or pack the central hole or the interior volume of the inner surface 272 such that voids remain to facilitate fluid flow (e.g., void fraction of 10%, 20%, 30%, 40%, or 50% or less). For example, the sorbent material 270 can include a plurality of particles, beads, strips, strands, mesh, or other dispersed structures that leave voids for fluid flow. In certain embodiments, the sorbent material 270 can be bonded to one or more internal structures within the sorbent-containing conduit 254, such as, for example, one or more of a wire grid or mesh, radial protrusions, baffles, fins, honeycomb structures, or any combination thereof. Additionally, in some embodiments, the central axis 264 extending from the inlet 266 to the outlet 268 can define the flow path 262 as a straight flow path, a curved flow path, a bent or serpentine flow path, a spiral or helical flow path, a serpentine flow path, an expansion and contraction flow path, a flow path with divisions and / or joins, or any combination thereof. For example, the flow path 262 can be defined as a serpentine flow path and include any number or configuration of the aforementioned flow paths. The sorbent material 270 can include one or more sorbent materials configured to adsorb undesired gases, e.g., carbon oxides (CO), such as carbon dioxide (CO) and carbon monoxide (CO). X ), nitrogen oxides (NO X ), sulfur dioxide (SO2) and other sulfur oxides (SO XThe adsorbent material 270 may be a sorbent material designed or suitable for adsorbing CO2, methane (CH4), or any other undesirable gas described herein, subject to regulation, and / or considered a greenhouse gas. For example, the adsorbent material 270 may include mesoporous silica, zeolites (e.g., aluminosilicates), and porous solid phase materials including metal-organic frameworks (MOFs) and covalent organic frameworks (COFs). The aforementioned adsorbent materials 270 may be particularly well suited for CO2 adsorption in the adsorbent-based gas capture unit 252. However, any suitable adsorbent material 270 may be used depending on the desired goal for gas capture of the undesirable gas. In certain embodiments, multiple adsorbent-based gas capture systems 250 may be used in series, each using the same or different adsorbent materials 270 to sequentially remove and capture the same or different undesirable gases.

[0067] The sorbent-based gas capture system 250 may be configured to alternate the various sorbent-based gas capture units 252 between an adsorption mode (e.g., adsorbing undesired gases onto the sorbent material 270) and a desorption mode (e.g., desorbing undesired gases from the sorbent material 270) using the controller 150 of the control system 144 and the sensors 148 of the monitoring system 146. For example, using the controller 150, the sorbent-based gas capture system 250 may operate the sorbent-based gas capture unit 256 in an adsorption mode while operating the sorbent-based gas capture unit 258 in a desorption mode, or vice versa. The adsorbent-based gas capture system 250 may also be configured to operate multiple units (e.g., two, three, four, or more) of the adsorbent-based gas capture units 252 in adsorption mode and multiple units (e.g., two, three, four, or more) of the adsorbent-based gas capture units 252 in desorption mode, and the multiple units may be arranged in series, parallel, or a combination thereof. The controller 150 is configured to alternate the adsorbent-based gas capture units 252 between adsorption and desorption modes via multiple upstream and downstream systems, such as an upstream flow distribution system 274 and a downstream flow distribution system 276. The upstream flow distribution system 274 includes a heating fluid supply system 278 (e.g., a steam and / or heated water supply system) and a gas supply system 280, and the downstream flow distribution system 276 includes a post-desorption treatment system 282 (e.g., a gas, steam, and / or heated water treatment system) and a treated gas treatment system 284. While the heating fluid supply system 278 may rely on steam 168 generated using waste heat and / or heat from combustion in the gas turbine system 12 during the power production mode of the combined cycle power plant 10, the heating fluid supply system 278 may rely on steam 168 generated using electric heaters, waste heat, and / or other available heat sources during the power consumption mode of the combined cycle power plant 10. In some embodiments, the steam 168 may be replaced or supplemented with other heating fluids, direct or indirect heating via electric heaters, or other heating configurations, particularly as needed for the power consumption mode.

[0068] In the desorption mode, the sorbent-based gas capture unit 252 may be configured to transfer the heating fluid 168 through the sorbent-containing conduit 254 in direct contact with the sorbent material 270 (e.g., direct heat transfer), through one or more heat exchange conduits through or around the sorbent-containing conduit 254 without contacting the sorbent material 270 (e.g., indirect heat transfer), or a combination thereof. Again, one or more additional heat sources (e.g., electric heaters) may be used to provide heat to the sorbent material 270. In certain embodiments of the desorption mode described below, the adsorbent-based gas capture unit 252 can directly transfer the heating fluid 168 through the adsorbent material 270 in the adsorbent-containing conduit 254 to desorb the undesired gas (e.g., CO) into the heating fluid 168 to produce a gas / heated fluid stream for further processing, or the adsorbent-based gas capture unit 252 can use the heating fluid 168 for indirect heat transfer to the adsorbent material 270 for desorption of the undesired gas, while using a separate flow directing system (e.g., a vacuum system) to direct the undesired gas downstream for further processing. For example, the vacuum system can include one or more fans, blowers, or pumps to draw and / or generate a vacuum to direct the flow from the adsorbent-containing conduit 254 to downstream processing components. Additionally, in some embodiments, the heating fluid 168 can use steam, waste heat, and / or an electric heater to heat water to produce heated water, which is then routed through the gas capture unit 252 of the sorbent system for direct contact with the sorbent material 270 and for desorbing undesired gases from the sorbent material 270. Thus, the disclosed embodiments can use a variety of heating fluids 168 (e.g., steam, heated water, steam-heated fluid, or combinations thereof) as heat sources that can directly or indirectly apply heat to the sorbent material 270 to facilitate the desorption process.

[0069] In certain embodiments, a sequential process of adsorption, desorption, and cooling, in which a wheel of sorbent material 270 is rotated, can be performed to provide a continuous flow of captured undesired gases. For example, a wheel of sorbent material 270 can extend into each of a plurality of conduits 254 and rotate continuously through the conduits 254. During wheel rotation, one or more of the conduits 254 flows a gas 286 being treated to remove undesired gases, while simultaneously, one or more of the conduits 254 flows a heating fluid 168 (e.g., steam and / or heated water) to remove and capture undesired gases (e.g., CO) to produce a captured gas 194. For desorption, the heating fluid 168 (e.g., steam and / or heated water) can be routed or generally configured to provide direct and / or indirect heat transfer to the sorbent material 270, thereby assisting in separating and capturing the undesired gases.

[0070] In the illustrated embodiment, the upstream flow distribution system 274 is configured to distribute the flow and alternating flow (e.g., when alternating between adsorption and desorption modes) of the heating fluid 168 (e.g., steam and / or heated water) and gas 286 (e.g., inlet air stream 60 and / or exhaust gas stream 68) to the multiple adsorbent-containing conduits 254 (e.g., 256 and 258) of the adsorbent-based gas capture unit 252. The heating fluid supply system 278 includes one or more steam supplies, heated water supplies, waste heat supplies, and / or electric heaters. For example, the heating fluid supply system 278 can include the HRSG 14 and the waste heat recovery system 172 (e.g., 182, 184, and / or 186), which can be configured to generate the heating fluid 168 (e.g., steam and / or heated water). The heating fluid supply system 278 also includes a heating fluid control 288 (e.g., steam and / or heating fluid control) having one or more heating fluid control components 290, 292, and 294, which may be configured to treat, regulate, and / or control the properties of the heating fluid 168 upstream of the sorbent-containing conduits 254 (e.g., 256 and 258) of the sorbent-based gas capture unit 252. For example, the heating fluid control component 290 may include a thermal control component (e.g., a steam / hot water temperature control component), such as a heat exchanger, an electric heater, a chiller, or any combination thereof, configured to regulate (e.g., increase or decrease) the temperature of the heating fluid 168. The heat exchanger may exchange heat with water, a lubricant, a coolant, a refrigerant, or some other thermal fluid. In some embodiments, the waste heat recovery system 172 may be used for heat transfer in the heater exchanger. The heating fluid control components 292 may include pressure control components such as a pressure regulator, an expander or expansion chamber, a contracter or contraction chamber, a fan or pump for adding energy, a turbine for extracting energy, or another suitable pressure controller. The heating fluid control components 294 may include pre-treatment components such as, for example, a particulate filter, a chilled water drain, and / or other pre-treatment components configured to modify the properties of or remove contaminants from the heating fluid 168 (e.g., steam and / or heated water).Heating fluid supply system 278 may also include one or more valves 296 configured to control the distribution of heating fluid 168 (e.g., steam and / or heated water) to multiple sorbent-containing conduits 254 (e.g., 256 and 258) of sorbent-based gas capture unit 252, as indicated by distribution conduits or lines 298 and 300. For example, valve 296 may include one or more two-way valves, three-way valves, or distribution manifolds for distributing heating fluid 168 (e.g., steam and / or heated water) in response to control signals from controller 150.

[0071] To distribute the gas 286, the gas supply system 280 of the upstream flow distribution system 274 includes a gas pretreatment 302 having one or more gas pretreatment components 304, 306, 308 that may be configured to treat, condition, and / or control the properties of the gas 286 (e.g., the inlet gas stream 60 or the exhaust gas stream 68) upstream of the sorbent-containing conduits 254 (e.g., 256 and 258) of the sorbent-based gas capture unit 252. For example, the gas pretreatment component 304 may include a thermal control component (e.g., a gas temperature regulation component), such as a heat exchanger, an electric heater, a cooler, or any combination thereof, configured to adjust (e.g., increase or decrease) the temperature of the gas 286. The heat exchanger may exchange heat with water, exhaust gas, a compressor bleed stream, waste heat, or some other thermal fluid. In some embodiments, the waste heat recovery system 172 may be used for heat transfer in the heater exchanger. Gas pre-treatment components 306 may include pressure control components, such as a pressure regulator, an expander or expansion chamber, a contractor or contraction chamber, a fan or pump for adding energy, a turbine for extracting energy, or another suitable pressure controller. Gas pre-treatment components 308 may include one or more contaminant removal units, such as a particulate filter, a moisture removal unit or dryer, a chemical removal unit, and / or other removal units configured to purify gas 286. Gas supply system 280 may also include one or more valves 310 configured to control the distribution of gas 286 to multiple sorbent-containing conduits 254 (e.g., 256 and 258) of sorbent-based gas capture unit 252, as indicated by distribution conduits or lines 312 and 314. For example, valve 310 may include one or more two-way valves, three-way valves, or distribution manifolds, perforated plates, and / or flow distribution packings to distribute gas 286 in response to control signals from controller 150.

[0072] The downstream flow distribution system 276 is configured to distribute the flow from the plurality of adsorbent-containing conduits 254 (e.g., 256 and 258) of the adsorbent-based gas capture unit 252 and alternate flows (e.g., when changing between adsorption and desorption modes) to the post-desorption treatment system 282 and the treated gas processing system 284. The post-desorption treatment system 282 may include one or more valves 316 configured to control the distribution of the trapped gas / heating fluid stream (e.g., gas, steam, and / or heated water) from the plurality of adsorbent-containing conduits 254 (e.g., 256 and 258) of the adsorbent-based gas capture unit 252, as indicated by distribution conduits or lines 318 and 320. For example, the valves 316 may include one or more two-way valves, three-way valves, or manifolds for collecting the trapped gas / heating fluid stream in response to a control signal from the controller 150. In certain embodiments, the trapped gas / heated fluid flow is the result of a desorption mode in which a heating fluid 168 (e.g., steam and / or heated water) is directed through the sorbent-containing conduits 254 to desorb undesired gases (e.g., CO) from the sorbent material 270 in each sorbent-containing conduit 254. Accordingly, the post-desorption treatment system 282 can also include a post-desorption processor 322 having one or more post-desorption treatment components 324, 326, and 328 (e.g., gas, steam, and / or heated water treatment components), which can be configured to process, adjust, and / or control the properties of the trapped gas / heated fluid flow (e.g., gas, steam, and / or heated water flow) from the sorbent-containing conduits 254 (e.g., 256 and 258) of the gas capture unit 252 of the sorbent system. For example, the post-desorption treatment component 324 can include a trapped gas / heating fluid separator configured to separate the heating fluid 168 (e.g., steam and / or heated water) from the trapped gas, thereby outputting water 330 (e.g., condensate) and the trapped gas 194. Examples of trapped gas / heating fluid separators include a thermal control component, a pressure control component, a chemical separation component, or a combination thereof. For example, the trapped gas / heating fluid separator may be configured to condense or cool the heating fluid 168 using a condenser.The post-desorption treatment component 326 can include one or more removal units configured to remove contaminants from the water 330 and / or the trapped gas 194. In the case of the water 330, the removal unit can include a particulate filter and / or a water treatment unit. In the case of the trapped gas 194, the removal unit can include a particulate filter, a water removal unit or dryer, or an additional gas treatment unit. The post-desorption treatment component 328 can include one or more pressure and / or flow control components, such as one or more pumps for the water 330 and one or more compressors for the trapped gas 194. The post-desorption treatment component 328 can also include one or more vacuum pumps configured to draw the trapped gas / heated fluid stream from the gas capture unit 252 of the adsorbent system.

[0073] For distribution of gas 286, treated gas processing system 284 of downstream flow distribution system 276 may include one or more valves 332 configured to control distribution of the treated gas stream from multiple sorbent-containing conduits 254 (e.g., 256 and 258) of sorbent-based gas capture unit 252, as indicated by distribution conduits or lines 334 and 336. For example, valve 332 may include one or more two-way valves, three-way valves, or manifolds to collect the treated gas stream in response to control signals from controller 150, thereby outputting treated gas 338. The treated gas is the result of an adsorption mode in which gas 286 (e.g., inlet stream 60 or exhaust gas stream 68) is directed through sorbent-containing conduits 254 to adsorb undesired gases (e.g., CO) onto the sorbent material 270 in each sorbent-containing conduit 254, thereby reducing the content or concentration level of the undesired gas in the remaining treated gas stream.

[0074] The control system 144 (e.g., the controller 150) is configured to receive feedback from the sensors 148 to facilitate adjustment of various operating parameters of the adsorbent-based gas capture unit 252. For example, the control system 144 may be configured to selectively operate one or more heat sources to provide heat for desorption depending on the operating mode of the combined cycle power plant 10, such as a power production mode and a power consumption mode. In certain embodiments, the control system 144 may selectively supply steam and / or heated water from the HRSG 14 during the power production mode, while the control system 144 may selectively supply heat using one or more electric heaters during the power consumption mode.

[0075] As a further example, the control system 144 may be configured to alternate flows (e.g., thermal fluid 168 and gas 286) through multiple sorbent-containing conduits 254 (e.g., 256 and 258) such that the sorbent-containing conduits 254 can alternate between an adsorption mode and a desorption mode. In the adsorption mode, the sorbent-containing conduit 254 (e.g., 256 or 258) receives a flow of gas 286, adsorbs undesirable gases (e.g., CO) from the gas 286 onto the sorbent material 270, and outputs the gas 286 with reduced content or concentration levels of the undesirable gas as treated gas 338. The adsorption mode is an exothermic process, generating heat that is carried away with the treated gas 338. In the desorption mode, the sorbent-containing conduit 254 (e.g., 256 or 258) receives a flow of a heating fluid 168 (e.g., steam and / or heated water), desorbs undesired gases (e.g., CO) from the sorbent material 270 into the heating fluid 168, and outputs the heating fluid 168 with the desorbed undesired gases (e.g., enriched in undesired gases such as CO) as a trapped gas / heated fluid stream. The desorption mode is an endothermic process, and the heating fluid 168 provides sufficient heat (e.g., directly or indirectly) to drive the desorption of the undesired gases (e.g., CO) from the sorbent material 270.

[0076] The control system 144 is configured to monitor sensors 148, such as sensors 148 at or upstream of the inlet 266 and sensors 148 at or downstream of the outlet 268, to assess the adsorption and desorption rates, concentration levels of undesirable gases, and other characteristics affecting the adsorption and desorption modes in each of the adsorbent-containing conduits 254 (e.g., 256 and 258). If the sensors 148 indicate that the adsorbent-containing conduits 254 (e.g., 256 and 258) need to alternate between modes (e.g., adsorption and desorption modes), the control system 144 may be configured to control the valves 296, 310, 316, 332 to change from the flow of heating fluid 168 to the flow of gas 286 in one of the adsorbent-containing conduits 254 and from the flow of gas 286 to the flow of heating fluid 168 in another of the adsorbent-containing conduits 254. With respect to the heating fluid 168 (e.g., steam and / or heated water) used in one of the sorbent-containing conduits 254, the control system 144 may be configured to control the HRSG 14, the waste heat recovery system 172, the heating fluid control 288, one or more electric heaters, or any combination thereof, to control the properties of the heating fluid 168 (e.g., temperature, pressure, flow rate, steam content, water content, etc.). With respect to the gas 286 used in one of the sorbent-containing conduits 254, the control system 144 may be configured to control the gas pre-treatment 302 to control the properties (e.g., temperature, pressure, flow rate, etc.) of the gas 286. Similarly, the control system 144 is configured to control the post-desorption processor 322 to control the treatment of the captured gas / heating fluid exiting one or more of the sorbent-containing conduits 254.

[0077] In the case of a multi-stage gas processing system 18, the control system 144 also coordinates control among the multiple gas capture systems 160 based on the operating mode of the combined cycle power plant 10, thereby providing the desired reduction in concentration levels of undesirable gases (e.g., CO2) to achieve a desired carbon footprint (e.g., a low-carbon, net-neutral, or net-negative carbon footprint). Additionally, after desorption is complete and before adsorption, a flow of chilled water or other coolant can be applied through the adsorbent-system gas capture unit 252 to cool the adsorbent-containing conduit 254 to a desired temperature before the next adsorption step.

[0078] FIG. 3 is a schematic diagram of one embodiment of the gas capture system 160 of the multi-stage gas processing system 18 of FIG. 1 , illustrating a solvent-based gas capture system 350. The solvent-based gas capture system 350 includes an absorber 352, a solvent supply system 354, and a solvent exhaust system 356. The solvent-based gas capture system 350 can use one or more solvents to capture undesired gases. Example solvents include monoethanolamine (MEA), diglycolamine (DGA), advanced amine solvents, amino acid salts, carbonate solvents, aqueous ammonia, immiscible liquids, and ionic liquids. As described below, the solvent-based gas capture system 350 uses a heated fluid 168 (e.g., from the HRSG 14), waste heat (e.g., from the waste heat recovery system 172), and / or other heat sources (e.g., electric heaters) to facilitate gas capture of undesired gases.

[0079] As described in further detail below, the solvent supply system 354 is configured to supply a gas-lean solvent 358 into the absorber 352 via a conduit 360 coupled to a solvent distributor 362 having a plurality of nozzles 364. The nozzles 364 are configured to output a solvent dispersion 366 into an interior volume 368 of the absorber 352. The solvent dispersion 366 helps to more evenly distribute the gas-lean solvent 358 throughout the interior volume 368 so that the solvent has a more uniform temperature distribution as it flows downward through the absorber 352 toward the solvent discharge system 356. The conduit 360 is coupled to a solvent inlet 370 of the absorber 352, and the solvent discharge system 356 is coupled to a solvent outlet 372 of the absorber 352.

[0080] The solvent exhaust system 356 is configured to receive the gas-rich solvent 374 from the solvent outlet 372 and transfer the gas-rich solvent 374 to the solvent regeneration system 376. The solvent exhaust system 356 also includes a gas compressor 378 downstream of the solvent regeneration system 376, a gas dryer 380 downstream of the gas compressor 378, and an outlet for the captured gas 194 downstream of the gas dryer 380. The solvent exhaust system 356 also provides a return conduit 382 from the solvent regeneration system 376 back to the solvent supply system 354 so that the regenerated solvent can be returned to the solvent supply system 354 as gas-lean solvent 358.

[0081] The absorber 352 also includes a gas inlet 384 configured to receive the gas 286 (e.g., the inlet air stream 60 or the exhaust gas stream 68) into the absorber 352 and a gas outlet 386 configured to discharge the treated gas 338 from the absorber 352. In the illustrated embodiment, the absorber 352 includes a vessel or housing 388 having a top 390, a bottom 392, and a middle portion 394 axially disposed between the top 390 and the bottom 392 relative to a central axis 396 of the housing 388. The following description may refer to an axial direction or axis 398 disposed along the central axis 396, a radial direction or axis 400 that intersects or is perpendicular to the central axis 396, and a circumferential direction or axis 402 that extends circumferentially around the central axis 396. The top 390 includes a top plate or cover 404 having a gas outlet 386 coaxial with the central axis 396. However, the gas outlet 386 may be positioned offset from the central axis 396 or at other locations along the top 390 .

[0082] The intermediate portion 394 includes a sidewall 406 that extends in a circumferential direction 402 about a central axis 396. For example, the sidewall 406 may be an annular sidewall, a square sidewall, a rectangular sidewall, or any other suitable shape extending about the central axis 396. In certain embodiments, the gas outlet 386 may be disposed in the sidewall 406 along the top portion 390. Additionally, the solvent inlet 370 may be disposed in a top plate or cover 404 of the top portion 390 or along the sidewall 406.

[0083] The bottom 392 may include a base plate 408 below the gas inlet 384 and the solvent outlet 372. In the illustrated embodiment, the gas inlet 384 and the solvent outlet 372 are disposed on the sidewall 406 along the bottom 392. However, in certain embodiments, the gas inlet 384 and / or the solvent outlet 372 may be disposed on the base plate 408 of the bottom 392. In some embodiments, the gas inlet 384 may include multiple gas inlets and / or the solvent outlet 372 may include multiple solvent outlets.

[0084] Within the interior volume 368 of the absorber 352, the absorber 352 may further include one or more sets of packing 410, a support tray or screen 412, and a solvent distributor 414 having a plurality of nozzles 416. For example, in the illustrated embodiment, the absorber 352 includes four sets of components (e.g., packing 410, support tray or screen 412, and solvent distributor 414) disposed between the solvent distributor 362 and a bottom 392 having a gas inlet 384 and a solvent outlet 372. The packing 410 may include a plurality of beads, balls, or mixture-directing structures configured to facilitate mixing between the gas 286 and the gas-lean solvent 358 supplied to the interior volume 368 of the absorber 352. The support tray or screen 412 may include a wire mesh, a plate with a plurality of openings, or another suitable structure that holds the packing 410 in place while allowing fluid flow of gas and solvent through the absorber 352 in opposite directions and through the support tray or screen 412. The solvent distributor 414 may be similar to the solvent distributor 362, such that the nozzles 416 output a solvent dispersion 418 that is evenly distributed throughout the interior volume 368 to better distribute the solvent through the packing 410 and support tray or screen 412. The set of packing 410, support tray or screen 412, and solvent distributor 414 are spaced apart from one another along the central axis 396. However, this spacing may be increased, decreased, or even eliminated in certain embodiments of the absorber 352.

[0085] During operation, the absorber 352 is configured to create a cross-flow or counter-flow of the gas-lean solvent 358 and the gas 286 within the interior volume 368, thereby facilitating gas absorption of certain undesirable gases (e.g., CO) from the gas 286 into the gas-lean solvent 358. As shown, at the bottom 392, the gas 286 enters the absorber 352 through the gas inlet 384, and the gas 286 flows upwardly through the interior volume 368 of the absorber 352, as indicated by arrows 420. The gas 286 entering the absorber 352, as indicated by arrows 420, can form bubbles of gas 286 that rise upwardly through the gas-lean solvent 358 within the interior volume 368. The gas 286 then passes through each subsequent stage or set of packing 410, support trays or screens 412, and solvent distributor 414.

[0086] In the upper portion 390, a solvent supply system 354 supplies gas-lean solvent 358 to the interior volume 368 via a solvent inlet 370, a conduit 360, a solvent distributor 362, and a plurality of nozzles 364. Again, the nozzles 364 may be distributed at various locations throughout the interior volume 368 to help more evenly distribute the gas-lean solvent 358 throughout the interior volume 368, as shown by the solvent dispersion 366. The gas-lean solvent 358 then flows downward through the interior volume 368 through each subsequent set or stage of packing 410, support tray or screen 412, and solvent distributor 414 having nozzles 416. As the gas-lean solvent 358 passes through each packing 410, various beads, balls, or mixing structures within the packing 410 are configured to aid in mixing the gas-lean solvent 358 with the gas 286, thereby aiding in absorbing various undesirable gases from the gas 286 into the gas-lean solvent 358. For example, the gas-lean solvent 358 may be configured to absorb carbon dioxide (CO) or other undesirable gases, as described in detail above. As the absorption process occurs, heat is generated within the absorber 352, thereby increasing the temperature of the solvent within the absorber 352. In certain embodiments, a thermal control system (e.g., a heat exchanger, chiller, etc.) can be coupled to the absorber 352 to control the temperature and improve the efficiency of the absorption process. The absorption process continues within each set or stage of packing 410, support trays or screens 412, and solvent distributor 414. Between each stage or set, the solvent distributor 414 helps to better distribute the solvent, as illustrated by the solvent dispersion 418. The solvent dispersion 418 can help to mix the solvent evenly with the gas 286 and provide a more uniform temperature distribution. The absorption process is then repeated with the next set or stage of packing 410, support trays or screens 412, and solvent distributor 414.

[0087] Finally, absorber 352 discharges gas-rich solvent 374 at bottom 392 through solvent outlet 372, and absorber 352 discharges treated gas 338 at top 390 through gas outlet 386. Treated gas 338 may be substantially free of or have been stripped of one or more undesirable gases (e.g., CO). In contrast, gas-rich solvent 374 may have absorbed one or more undesirable gases (e.g., CO). Thus, gas-rich solvent 374 may be described as a CO2-rich solvent (or other gas-rich solvent depending on the undesirable gas), while gas-lean solvent 358 may be described as a CO2-lean solvent (or other gas-lean solvent depending on the undesirable gas), with specific gas absorption occurring in absorber 352. Similarly, gas 352 can be described as CO2-containing or rich gas (or other containing or rich gas depending on the undesired gas), treated gas 338 can be CO2-reduced gas, CO2-lean gas, or CO2-free gas (or other reduced, lean, or free gas depending on the undesired gas), and specific gas absorption can be described as occurring in absorber 352. Gas absorption as described herein is intended to cover any one or more of the undesired gases described herein, or any other regulated gas or greenhouse gas.

[0088] The gas-rich solvent 374 output from the absorber 352 flows into a solvent regeneration system 376, which may be configured to capture undesirable gases (e.g., CO) in the gas-rich solvent 374 and regenerate the solvent (e.g., remove the undesirable gases (e.g., CO) for reuse as the gas-lean solvent 358). In the illustrated embodiment, the solvent-based gas capture system 350 includes a steam supply system 422 coupled to the solvent regeneration system 376 to facilitate solvent regeneration and capture of the captured gas 194. In particular, the steam supply system 422 includes one or more sources of heating fluid 168 (e.g., steam and / or heated water), such as, for example, the HRSG 14, the waste heat recovery systems 172 (e.g., 182, 184, and 186), and / or other heat sources (e.g., electric heaters). The steam supply system 422 can inject the heating fluid 168 (e.g., steam and / or heated water) directly into the solvent regeneration system 376 for solvent regeneration and capture of the captured gas 194. In some embodiments, the steam supply system 422 can further treat and / or control the properties of the heating fluid 168 (e.g., steam and / or heated water) before injecting it into the solvent regeneration system 376, such as, for example, temperature control and / or pressure control. In some embodiments, the steam supply system 422 can use the heating fluid 168 (e.g., steam and / or heated water) and / or waste heat from the waste heat recovery system 172 as an indirect heat source for the absorber 352 and / or to generate steam in a boiler. In each of these embodiments, the heating fluid 168 (e.g., steam and / or heated water) and waste heat from the waste heat recovery system 172 may be obtained and / or processed as described in detail above with reference to FIGS. 1 and 2 .

[0089] Thus, undesirable gases (e.g., CO) may be output from the solvent regeneration system 376 to a gas compressor 378, as indicated by arrow 424, which is configured to compress the undesirable gases before being dried by a gas dryer 380. The gas dryer 380 then removes the moisture content in the compressed undesirable gases from the gas compressor 378 and then outputs the compressed, dried undesirable gases as captured gas 194. The solvent regeneration system 376 also outputs regenerated solvent as gas-lean solvent 358, which is returned to the solvent supply system 354 via a return conduit 382. The regenerated solvent is essentially gas-rich solvent 374, and the undesirable gases are removed in the solvent regeneration system 376.

[0090] In the solvent supply system 354, the gas-lean solvent 358, whether it be the original supply of gas-lean solvent 358 or regenerated solvent from a solvent regeneration system 376, is supplied to the absorber 352 along with one or more components 426, 428, 430, 432. The components 426, 428, 430, and 432 may include one or more solvent pumps, a solvent filter or treatment system, one or more heat exchangers configured to cool the gas-lean solvent 358, one or more solvent tanks, one or more solvent pressure regulators, one or more solvent flow meters, or any combination thereof.

[0091] 4 is a schematic diagram of one embodiment of the combined cycle power plant 10 of FIG. 1 , further illustrating details of a multi-mode configuration 450 for selectively operating in a power-producing mode and a power-consuming mode. The illustrated multi-mode configuration 450 has a power-generating fluid circuit 452 and a power-consuming fluid circuit 454. The power-generating fluid circuit 452 includes an air circuit 456, a fuel circuit 458, an exhaust gas circuit 460, and multiple steam circuits 462. The power-consuming fluid circuit 454 includes multiple air circuits 464. As described in further detail below, the control system 144 is configured to selectively use the power-generating fluid circuit 452 and the power-consuming fluid circuit 454 of the multi-mode configuration 450 to change the combined cycle power plant 10 between a power-producing mode (e.g., a firing or combustion mode to generate electricity) and a power-consuming mode (e.g., a non-firing or non-combustion mode to consume electricity).

[0092] The combined cycle power plant 10 has substantially the same configuration as the combined cycle power plant 10 of FIG. 1 . However, the gas turbine system 12 is mechanically coupled to the steam turbine system 16 via a common shaft 466, and the gas turbine system 12 and the steam turbine system 16 are both mechanically coupled to the motor-generator 28. However, in certain embodiments, the combined cycle power plant 10 of FIG. 4 can have the gas turbine system 12 and the steam turbine system 16 separately coupled to the motor-generator 28 and the load 116 (e.g., a generator) without the common shaft 466, as shown in FIG. 1 . In either configuration, the combined cycle power plant 10 has various components and functions as already described in detail with reference to FIG. 1 . Therefore, unless otherwise noted, the components and functions of the combined cycle power plant 10 of FIG. 4 are the same as those described in detail above with reference to FIGS. 1-3 . In the illustrated embodiment, the gas turbine system 12 includes an intake section 20, a compressor section 22, a combustor section 24 having a combustor 40, a turbine section 26, and a motor-generator 28. Additionally, combined cycle power plant 10 includes HRSG 14, gas processing system 18, and exhaust stack 214. As shown, gas processing system 18 includes gas capture systems 164 and 166. In some embodiments, gas processing system 18 also includes gas capture system 162 upstream of intake section 20, as shown in FIG. 1 . The illustrated steam turbine system 16 includes multiple steam turbines 104, such as steam turbines 468 and 470. Although the illustrated steam turbine system 16 includes only two steam turbines 104, steam turbine system 16 may include the same steam turbine sections 106, 108, 110 as described above with reference to FIG. 1 .

[0093] In certain embodiments, the control system 144 may be configured to switch between a power production mode (e.g., a firing mode) and a power consumption mode (e.g., a non-firing mode) of the combined cycle power plant 10 using the power generation fluid circuit 452 and the power consumption fluid circuit 454. In the power production mode, the gas turbine system 12 is configured to receive an intake air flow 60 from the intake section 20 to the compressor section 22 via the air circuit 456. The intake section 20 may include a plurality of air filters 472, which may be part of an air filter enclosure or filter housing. Thus, the air filters 472 are configured to filter the intake air flow 60 upstream of the compressor section 22. The intake air flow 60 passes through the compressor section 22, and the compressed air flow flows to the combustor 40. The fuel circuit 458 is configured to transfer fuel from the fuel supply 46 into the combustor 40, for example, into one or more fuel nozzles 44, as described above with reference to FIG. 1 . The fuel mixes with air from compressor section 22 and is combusted to generate hot combustion gases, which then flow through turbine section 26 to drive the rotation of turbine section 26. The rotation of turbine section 26 also drives the rotation of compressor section 22, common shaft 466, and motor-generator 28 (e.g., operating in generator mode to generate electricity). Turbine section 26 then discharges exhaust gas stream 68, which flows through HRSG 14 before entering gas capture systems 164 and 166 of gas processing system 18.

[0094] As shown, HRSG 14 generates steam, which is distributed through steam circuit 462. In the illustrated embodiment, steam circuit 462 includes steam circuits 474, 476, and 478. Steam circuit 474 extends from HRSG 14 to steam turbine 468, steam circuit 476 extends from HRSG 14 to steam turbine 470, and steam circuit 478 extends from HRSG 14 to gas capture systems 164 and 166 of gas processing system 18. As shown, the steam distributed along steam circuit 478 serves as a heat source 480 to enable operation of gas capture systems 164 and 166. In some embodiments, heat source 480 may include steam, heated water, or a combination thereof. Further, in some embodiments, heat source 480 may include one or more electric heaters that add heat to generate steam and / or heated water, for example, when combined cycle power plant 10 is operating in a power consumption mode. If available, steam may be used as a heat source 480 to desorb undesired gases from the sorbent material in a sorbent-based gas capture system, or to remove undesired gases from the solvent in a solvent-based gas capture system, or for any other suitable use of heat to facilitate the operation of gas capture systems 164 and 166. Flow supplied to steam turbines 468 and 470 through steam circuits 474 and 476 is used to drive the rotation of steam turbines 468 and 470, which in turn serves to drive the rotation of motor-generator 28 (e.g., operating in generator mode to generate electricity). Thus, in response to the rotation imparted by gas turbine system 12 and steam turbine system 16, motor-generator 28 operates as a generator to generate electricity for the electric grid.

[0095] As further shown, exhaust gas stream 68 flows from turbine section 26 to exhaust stack 214 through exhaust gas circuit 460, passing through duct 482, HRSG 14, duct 484, gas capture system 164, duct 486, gas capture system 166, duct 488, and exhaust stack 214. Ducts 482, 484, 486, and 488 may be duct sections of a common duct or separate duct sections between the illustrated components. Downstream of gas capture systems 164 and 166, exhaust gas stream 68 is discharged as treated gas 490 (e.g., having a reduced content of undesirable gases). Gas capture systems 164 and 166 operate as described in detail above with reference to FIG. 1 . As shown, in power production mode, exhaust gas stream 68 is treated by both gas capture systems 164 and 166, thereby increasing the amount of gas capture performed on exhaust gas stream 68 before being discharged through exhaust stack 214. Gas capture systems 164 and 166 are configured to produce or output captured gas 194 (e.g., captured CO), which is then forwarded to compression system 188 for gas compression before distribution through storage / pipeline 228. In power production mode, air circuit 464 may or may not be used to forward air flow to gas capture systems 164 and / or 166 to facilitate air treatment of the ambient air. Additionally, in certain embodiments, exhaust gases may be forwarded to one or both of gas capture systems 164 and 166 for gas treatment, as described in further detail below.

[0096] In a power consumption mode of the combined cycle power plant 10, the control system 144 is configured to use the power consumption fluid circuit 454 to transfer one or more air flows through the air circuit 464 to one or both of the gas capture systems 164 and 166 for air processing. For example, the power consumption fluid circuit 454 may include multiple air movers 492, such as air mover 494, air mover 496, and air mover 498. The air mover 492 may also include the compressor section 22 of the gas turbine system 12, which is configured to transfer the air flows to the interior of the gas turbine system 12 without combusting fuel with the air.

[0097] In the illustrated embodiment, the air mover 494 is mechanically coupled to and driven by the motor-generator 28 (e.g., operating in a motor mode). For example, the motor-generator 28 may be coupled to the air mover 494 via a clutch 500, which in turn is coupled to the steam turbine system 16 and the gas turbine system 12 via a clutch 502. The clutches 500 and 502 may each include clutch portions 504 and 506, such as clutch plates or other engageable clutch members, configured to selectively engage and disengage rotation between the motor-generator 28 and the respective components, e.g., the air mover 494 and the steam turbine system 16 and the gas turbine system 12. In some embodiments, one or more additional clutches may be used to independently engage and disengage the steam turbine system 16 and the gas turbine system 12. For example, the steam turbine system 16 may be relocated to another position to allow for placement of additional clutches. The clutch 500 is disposed between a shaft 508 of the motor-generator and a shaft of the air mover 494. Clutch 502 is disposed between a shaft 512 of motor-generator 28 and a shaft 514 of steam turbine system 16 .

[0098] In the power consumption mode, motor-generator 28 can operate as an electric motor to drive the rotation of air mover 494, steam turbine system 16, and gas turbine system 12 (e.g., driving compressor section 22), to drive only air mover 494, or to drive only steam turbine system 16 and gas turbine system 12 (e.g., driving compressor section 22). For example, control system 144 can selectively operate clutch 502 to decouple motor-generator 28 from steam turbine system 16 and gas turbine system 12 while operating clutch 500 to connect motor-generator 28 to air mover 494, thereby allowing motor-generator 28 (e.g., operating in motor mode) to drive air mover 494 to provide air flow through air circuit 464. Further, control system 144 may be configured to operate clutch 500 to disconnect motor-generator 28 from air mover 494 and to operate clutch 502 to connect motor-generator 28 to steam turbine system 16 and gas turbine system 12, thereby allowing motor-generator 28 (e.g., operating in motor mode) to drive the rotation of steam turbine system 16 and gas turbine system 12 (e.g., driving compressor section 22).

[0099] As will be appreciated, when the motor-generator 28 (e.g., operating in motor mode) drives the rotation of the steam turbine system 16 and the gas turbine system 12, the compressor section 22 may compress the intake air flow 60 in one or more compressor stages to provide the air flow to the gas capture systems 164 and / or 166 downstream of the gas turbine system 12. For example, the air flow may pass internally through the compressor section 22, the combustor section 24, and the turbine section 26 and then flow to the gas capture systems 164 and / or 166. However, in some embodiments, some or all of the air flow may be bled or extracted from the compressor section 22, the combustor section 24, the turbine section 26, and / or downstream of the turbine section 26 and then forwarded to the gas capture systems 164 and / or 166.

[0100] While compressor section 24 may be used solely as air mover 492 to direct air flow to gas capture systems 164 and / or 166, any one or more of air movers 494, 496, and 498 may also be used to direct air flow to gas capture systems 164 and / or 166. For example, air mover 492 may include air movers 496 and 498 driven by respective electric motors 516 and 518. Thus, electric motors 516 and 518 may be controlled by control system 144 to rotate air movers 496 and 498 to supply air flow through air circuit 464 to gas capture systems 164 and / or 166, either alone or in combination with the air flow supplied by compressor section 22. In some embodiments, any one or more air movers 492 (e.g., compressor section 22 and air movers 494, 496, 498) can be used to provide airflow to gas capture systems 164 and / or 166, as well as gas capture system 162, as described above with reference to FIG. 1.

[0101] In the illustrated embodiment, an air mover 496 driven by an electric motor 516 may be disposed in or coupled to the intake section 20, such that the air mover 496 pushes or pulls the air flow through an air filter 472 before distributing the air flow to the gas capture systems 164 and / or 166. The air mover 498 driven by the electric motor 518 may be independent from other components of the combined cycle power plant 10, such as, for example, a stand-alone air mover 498. The air movers 494, 496, 498 may include one or more of an air compressor, a fan, a blower, or any combination thereof. In certain embodiments, the power consuming fluid circuit 454 also includes one or more air filters 520 separate from the intake section 20, such as, for example, a stand-alone air filter unit for a power consuming mode.

[0102] The plurality of air circuits 464 may include air circuit 522, air circuit 524, air circuit 526, and air circuit 528. Air circuit 522 may extend internally through gas turbine system 12 from intake section 20 to duct 482. For example, air circuit 522 may include intake circuit 456 from intake section 20 to compressor section 22, an air path through compressor section 22, an air path through combustor 40, and an air path through turbine section 26 to duct 482. Thus, air circuit 522 may be described as an internal airflow circuit through gas turbine system 12.

[0103] Air circuits 524, 526, and 528 may be described as external air circuits, independent air circuits, or secondary air circuits external to gas turbine system 12. In the illustrated embodiment, air circuit 524 extends from a first location (e.g., an air extraction connection) to a second location (e.g., an air injection location), with the first location fluidly coupled to duct 482 between turbine section 26 and HRSG 14 and the second location fluidly coupled to duct 486 between gas capture system 164 and gas capture system 166. Air circuit 524 may therefore be described as a bypass circuit that bypasses HRSG 14 and gas capture system 164. Air circuit 524 selectively supplies bypass air 530 from air circuit 522 to gas capture system 166 via duct 486.

[0104] The air circuit 526 extends from a first location (e.g., an air extraction connection or a compressor bleed connection) to a second location (e.g., an air injection location), with the first location fluidly coupled to the compressor section 22 and the second location fluidly coupled to the duct 486. The air circuit 526 is configured to supply bleed air 532 from the air flowpath of the compressor section 22 to the gas capture system 166 without the airflow passing through the combustor 40 and the turbine section 26. The air circuit 524 may also be described as a bleed air circuit, which may be controlled by the control system 144 to adjust the pressure or pressure ratio throughout the gas turbine system 12 as appropriate to facilitate operation of the gas turbine system 12 when driven by the motor-generator 28 in a power consumption mode (e.g., operating in a motor mode). The air circuit 526 may also include one or more coolers 534 configured to cool the temperature of the bleed air 532 before sending the airflow to the gas capture system 166. The cooler may include a heat exchanger that exchanges heat with a liquid coolant (e.g., water) or a gas coolant (e.g., air) to reduce the temperature of the bleed air 532 .

[0105] Air circuit 528 may extend from one or more of air movers 494, 496, 498 to duct 486 upstream of gas capture system 166. Air circuit 528 therefore supplies additional air 536 that is generally separated from the air flow supplied through air circuit 522 internal to gas turbine system 12. Additional air 532 may be filtered by one or more of air filters 520 along air circuit 528. Additional air 536 may selectively receive air flow from one or more of air movers 494, 496, 498. For example, air mover 494 driven by motor-generator 28 (e.g., operating in motor mode) may be configured to supply air flow to air filter 520 via air circuit 538, and / or air mover 494 may be configured to supply air flow through air circuit 540 coupled to intake section 20. When air is supplied into intake section 20 from air mover 494, the air flow may be distributed along intake circuit 456 into compressor section 22 (e.g., via air circuit 522) and / or along air circuit 542 into air filter 520. Similarly, within intake section 20, air mover 496 driven by electric motor 516 may be configured to provide an air flow for distribution along intake circuit 456 into compressor section 22 (e.g., via air circuit 522) and / or along air circuit 542 into air filter 520. Additionally, air mover 498 driven by electric motor 518 may be configured to supply an air flow to air filter 520 via air circuit 544. At air filter 520, any of the one or more air flows received from air movers 494, 496, and / or 498 are filtered to remove undesirable particulates or moisture content before being delivered to gas capture system 166 through air circuit 528.

[0106] The control system 144 is configured to control various air flows through the air circuits 464 via a plurality of valves 546, such as, for example, valves 548 and 550 along air circuits 538 and 540, valves 552, 554, and 556 along air circuits 524, 526, and 528, and valves 558 and 560 along air circuits 456 and 542. Each of the illustrated valves 546 may include a valve assembly driven by an actuator, which is controlled by the control system 144. The valves 546 may include gate valves, ball valves, or other valve types. The actuators may include electric and / or fluid actuators, such as, for example, pneumatic or hydraulic actuators. During operation, the control system 144 may selectively open or close each of the valves 546, alone or in combination with other valves, to selectively provide air flow through the various air circuits 464 to the gas capture system 166 for air processing during a power consumption mode. Further, in combination with controlling valve 546, control system 144 may be configured to control motor-generator 28 (e.g., operating in motor mode), clutches 500 and 502, and electric motors 516 and 518 to operate various air movers 492 and redirect air flow through various air circuits 464 to gas capture system 166. In some embodiments, air circuits 524, 526, and 528 may be selectively coupled to both gas capture systems 164 and 166, and valve 546 may be selectively opened and closed to direct air flow through both gas capture systems 164 and 166, gas capture system 164 only, or gas capture system 166 only.

[0107] The control system 144 may control the airflow for air processing in the gas processing system 18 in various manners during the power consumption mode. As one example, the control system 144 may selectively operate the clutch 502 to connect the motor-generator 28 (e.g., operating in a motor mode) to the compressor section 22 of the gas turbine system 12 to rotate the compressor section 22 and generate a compressed airflow that passes internally through the gas turbine system 12 via the air circuit 522, thereby directing the airflow from the intake section 20 to the compressor section 22, through the combustor section 24, and through the turbine section 26 through the air circuit 456. Additionally, the airflow may be diverted from the duct 482 through the air circuit 524 to the duct 486 upstream of the gas capture system 166 and / or from the compressor section 22 to the duct 486 upstream of the gas capture system 166 through the air circuit 526. For example, when clutch 502 mechanically couples motor-generator 28 to compressor section 22, while motor-generator 28 is operating in motor mode to drive compressor section 22, control system 144 can selectively open valve 552 to enable bypass air 530 and / or can selectively open valve 554 to enable bleed air 532. When valve 552 is open, bypass air 530 flows through air circuit 524 to gas capture system 166, bypassing HRSG 14 and gas capture system 164. When valve 554 is open, bleed air 532 flows through air circuit 526 to gas capture system 166, bypassing combustor section 24, turbine section 26, HRSG 14, and gas capture system 164. The illustrated embodiment may also include a valve or flow regulator within duct 482, allowing control system 144 to open or close the flow of air through HRSG 14 to gas capture systems 164 and 166.

[0108] In some embodiments, control system 144 can decouple motor-generator 28 from steam turbine system 16 and gas turbine system 12 such that motor-generator 28 does not drive compressor section 22 (e.g., operating in motor mode) to provide airflow through air circuit 522. However, whether motor-generator 28 drives compressor section 22 or not, motor-generator 28 may also be controlled in conjunction with clutch 500 to drive air mover 494, which then provides airflow through either air circuit 538 or air circuit 540, as described in detail above. For example, control system 144 can selectively control motor-generator 28 and clutch 500 to drive air mover 494, selectively open valve 548 to allow airflow through air circuit 538 to air filter 520, and / or selectively open valve 550 to allow airflow through air circuit 540 through intake section 20 to one or both of air circuits 456 and 542. Within intake section 20, air mover 496 may also be driven by respective electric motors 516 to provide air flow along one or both of air circuits 456 and 542. During operation, control system 144 may selectively open valve 558 to allow air flow through air circuit 456 and air circuit 522 within gas turbine system 12 as described above, and / or open valve 560 to allow air flow through air circuit 542 to air filter 520. Air flow through air circuits 538 and 542 may then flow from air filter 520 through air circuit 528 to gas capture system 166 as additional air 536. Additionally, control system 144 may selectively operate electric motors 518 to drive air mover 498 to supply air flow through air circuit 544 to air filter 520, which supplies filtered air through air circuit 528 to gas capture system 166 as additional air 536.

[0109] The control system 144 is configured to allow any one or more of these air flows to flow through the air circuits 464 to the gas trapping system 166. In the illustrated embodiment, the various air flows can bypass the gas trapping system 164 and flow only to the gas trapping system 166. However, in certain embodiments, the various air circuits 464 may be configured to redirect one or more of the air flows to the gas trapping system 164 without the gas trapping system 166 or through both the gas trapping systems 164 and 166. Additionally, in some embodiments, the various air circuits 464 may be configured to redirect one or more of the air flows to the gas trapping system 162 upstream of the intake section 20, as shown in FIG. 1 .

[0110] In the power consumption mode, the various air movers 492 provide airflow to the gas capture system 166 (or, in some cases, any combination of the gas capture systems 162, 164, 166), which uses one or more heat sources 562 to support the gas capture process (e.g., heat for desorption of undesired gases from a sorbent material and / or heat for stripping undesired gases from a solvent). For example, the power consumption fluid circuit 454 can include one or more heat sources 562, such as one or more heat exchangers 564 and one or more heaters 566. The heat exchangers 564 can be configured to exchange heat between a heating fluid and a working fluid, and the heating fluid can include compressed air or a fluid heated by waste heat. Although the gas turbine system 12 does not produce combustion gases and exhaust gases during the power consumption mode, other sources of combustion gases and exhaust gases can be used for heat transfer in the heat exchangers, depending on their availability during the power consumption mode. The working fluid may include water, air, or another suitable liquid or gas, which may be transferred through the gas capture system 166 to facilitate separation of gases within the gas capture system 166. The one or more heaters 566 may include electric heaters that typically consume electricity to provide heat to the gas capture system 166. As shown, a heat source 562 is configured to provide heat to the gas capture system 166, as indicated by arrow 568. The heat 568 may be configured to facilitate desorption of undesired gases from an air stream within a sorbent material in a sorbent-based gas capture system, separation of gases from a solvent in a solvent-based gas capture system, or any other suitable configuration. Thus, the heat source 562 may be used as a substitute for steam used in the steam circuit 578, which is typically available during the power production mode but may be unavailable during the power consumption mode. As a result, during the power consumption mode, steam may be unavailable, and therefore the steam circuit 478 may not be used to provide heat to the gas capture systems 164 and 166.In certain embodiments, a heat source 562 (e.g., a heater 566) may be used to generate steam for heat 568, and the heat source 562 may be independent or integrated with the HRSG 14 or other steam generator.

[0111] The gas capture system 166 is configured to capture one or more undesirable gases from the air stream as captured gas 194 and output treated gas 490 through the exhaust stack 214. The treated gas 490 may be described as treated air (e.g., carbon-reduced air), which has a lower content of undesirable gases than ambient or ambient air. The captured gas 194 includes one or more of the undesirable gases captured from the air stream. The captured gas 194 may include carbon dioxide (CO) or other undesirable gases as described above. The captured gas 194 is then sent to the compression system 188 and storage pipeline 228.

[0112] During operation, the combined cycle power plant 10 may be selectively controlled by the control system 144 to operate in either a power production mode (e.g., a firing mode) of the gas turbine system 12 or a power consumption mode (e.g., a non-firing mode) of the gas turbine system 12 depending on various operating parameters and external factors. As described above, the external factors may include energy pricing of electricity on the power grid, energy demand for electricity on the power grid, various energy credits (e.g., currency credits resulting from negative energy pricing), various gas capture credits (e.g., tax credits for carbon capture), or any combination thereof. For example, the control system 144 may switch between a power production mode and a power consumption mode depending on whether energy demand and / or energy pricing is above or below one or more thresholds. For example, if energy pricing falls to low, zero, or negative energy pricing, the control system 144 may transition from the power production mode to the power consumption mode. If energy pricing rises above a threshold or positive energy pricing, the control system 144 may transition from the power consumption mode to the power production mode. Additionally, if credits are available to reduce undesirable gases from the air, such as reducing carbon dioxide in the air, the control system 144 may be configured to transition from a power production mode to a power consumption mode if energy demand and / or energy pricing are also sufficiently low. Regardless of the reason, the control system 144 is configured to allow operation in either mode of operation.

[0113] The power production mode, as described above, generally involves combusting fuel from the fuel supply 46 with air from the intake section 20 to produce hot combustion gases that drive the turbine section 26 and provide heat for steam generation in the HRSG 14. The steam is then used to drive the steam turbine 104 in the steam turbine system 16. Thus, the gas turbine system 12 and the steam turbine system 16 may be used to drive the same or different generators (e.g., the motor-generator 28 in generator mode and the load 116 as a generator). For example, the combined cycle power plant 10 may include a configuration of the gas turbine system 12 and the steam turbine system 16 as shown in FIG. 1 or a series configuration of the gas turbine system 12 and the steam turbine system 16 as shown in FIG. 4. In the power production mode, the control system 144 may not operate the various air movers 492 that circulate or supply airflow through the air circuit 464 to the gas capture system 166.

[0114] However, when operating in the power consumption mode, the control system 144 may enable airflow through one or more of the air circuits 464 from the air mover 492 to the gas capture system 166 for air treatment to produce treated gas 490 and captured gas 194. In the power consumption mode, the gas turbine system 12 does not ignite or combust fuel from the fuel supply 46 to generate hot combustion gases to drive the turbine section 26 and generate steam via the HRSG 14. Thus, the motor-generator 28 operates in a motor mode to drive the compressor section 22 and / or the air mover 494 of the gas turbine system 12. Additionally, the air movers 496 and 498 may be driven by respective electric motors 516 and 518 to provide airflow through the air circuits 464 to the gas capture system 166. Any one or more of the air circuits 464 may be used by the power consumption fluid circuit 454 during the power consumption mode. In certain embodiments, the combined cycle power plant 10 may have a different configuration, a different combustion system than the gas turbine system 12, and / or additional combustion systems (e.g., additional gas turbine system 12, reciprocating piston-cylinder engines, furnaces, boilers, etc.). Various configurations are described in further detail below.

[0115] Figure 5 is a schematic diagram of one embodiment of a power plant 600 having a multi-mode configuration 450 for selectively operating in a power producing mode and a power consuming mode, as described above. In contrast to the combined cycle power plant 10 of Figure 4, the power plant 600 has a combustion system 600 and a steam generator 602 rather than the gas turbine system 12 and HRSG 14 of Figure 4. Otherwise, the power plant 600 is substantially the same as the combined cycle power plant 10 described in detail above with reference to Figures 1-4. Thus, unless otherwise specified, each of the components and functions of the power plant 600 are the same as those described in detail above with reference to Figures 1-4.

[0116] Combustion system 600 may include gas turbine system 12 or a non-gas turbine system configuration. In certain embodiments, combustion system 600 may include a furnace, a reciprocating piston-cylinder engine, or another fuel-driven combustion system. For example, combustion system 600 may include a coal-fired furnace or a fuel-fired furnace operating on various liquid, gaseous, or solid fuels. The fuel may include coal, petroleum products, natural gas, syngas, gasoline, biofuel, or other suitable fuel. Combustion system 600 may receive an airflow from intake section 20, as described in detail above. However, compressor section 22 of gas turbine system 12 may be replaced with an air mover 604, which may be driven by steam turbine system 16 or a separate electric motor. As shown, air mover 604 is driven by steam turbine system 16 via shaft 606. Air mover 604 may include an air compressor, a fan, a blower, or another suitable air moving system. An air mover 604 provides an airflow into combustion system 600, which also receives one or more fuels from fuel supply 46. Combustion system 600 is configured to combust one or more fuels with the airflow from air mover 604, thereby generating hot combustion gases, as indicated by arrows 608. Hot combustion gases 608 then flow through steam generator 602, which heats water to generate steam for supply through steam circuit 462, as described in detail above. Otherwise, power plant 600 operates substantially as described above with reference to FIG. 4.

[0117] Combustion system 600 may include a reciprocating piston-cylinder engine, and thus power plant 600 may be a combined cycle power plant that uses power extracted from the reciprocating piston-cylinder engine to drive motor-generator 28 as a generator, in the same configuration as described above with reference to FIG. 4 . Alternatively, combustion system 600 may include a fuel-fired furnace that supplies hot combustion gases 608 to steam generator 602 to produce steam for operating steam turbine system 16. However, when configured as a furnace, combustion system 600 may not produce mechanical power to drive motor-generator 28 as a generator. Thus, when configured as a furnace, combustion system 600 may be used only to provide heat to generate steam in steam generator 602 for steam turbine system 16. Nevertheless, power plant 600 is configured to operate in power production and power consumption modes in the same manner as described in detail above with reference to FIGS. 1 and 4 . Thus, in the power consumption mode, the control system 144 is configured to route one or more air flows through the air circuit 464 to the gas capture system 166 for treatment of the air and capture of undesirable gases as captured gas 194. In contrast, in the power production mode, the control system 144 is configured to operate the combustion system 600 to provide hot combustion gases 608 for steam generation via the steam generator 602, which is then used by the steam turbine system 16 to generate electricity.

[0118] FIG. 6 is a schematic diagram of one embodiment of the combined cycle power plant 10 of FIGS. 1 and 4 , further illustrating a plurality of powertrains 650 having the gas turbine system 12, the steam turbine system 16, the HRSG 14, and the motor-generator 28. In the illustrated embodiment, the powertrain 650 includes first and second powertrains 652 and 654. However, any number of additional powertrains 650 may be included in the combined cycle power plant 10. The first powertrain 652 includes the gas turbine system 12A, the HRSG 14A, the steam turbine system 16A, and the motor-generator 28A. Similarly, the second powertrain 654 includes the gas turbine system 12B, the HRSG 14B, the steam turbine system 16B, and the motor-generator 28B. In general, the components of the first and second powertrains 652 and 654 are substantially identical to one another and are as described in detail above with reference to FIGS. 1 and 4 . Furthermore, the components and functions of the combined cycle power plant 10 are the same as those described above with reference to FIGS.

[0119] The combined cycle power plant 10 may include various control modes, such as a power production mode and a power consumption mode, operated by the control system 144 as described above. Additionally, the control system 144 may be configured to control the operation of the multiple powertrains 650 to operate all of the powertrains 650 in the same operating mode, different operating modes, or any other suitable configuration. For example, the control system 144 may be configured to operate all of the powertrains 650 in a power production mode, to operate all of the powertrains 650 in a power consumption mode, or to operate in a combination of power production and power consumption modes.

[0120] For example, in certain embodiments, control system 144 may be configured to operate first powertrain 652 in a power consumption mode, as described in detail above with reference to FIG. 4, while operating second powertrain 654 in a power production mode. In such a configuration, second powertrain 654 operating in a power production mode may be configured to supply exhaust gases 656 and steam 658 to gas processing system 18 having gas capture systems 164 and 166. For example, second powertrain 654 may output exhaust gases 656 along circuit 660 coupled to duct 484 upstream of gas capture system 164 and may supply steam 658 to gas capture systems 164 and 166 via circuit 662. Thus, in the illustrated embodiment, first powertrain 652 operates in a power consumption mode as described above, while second powertrain 654 operates in a power production mode, providing steam 658 as a heat source 480 to facilitate operation of gas capture systems 164 and 166 while also passing exhaust gas 656 through both gas capture systems 164 and 166 for treatment of the exhaust gas. The illustrated embodiment can simultaneously treat exhaust gas 656 from second powertrain 654 using both gas capture systems 164 and 166 while also treating one or more air streams provided to gas capture system 166 through air circuit 464. In certain embodiments, control system 144 can control the percentage of exhaust gas that is mixed with the air stream prior to treatment in gas capture system 166, thereby helping to control the temperature, humidity, or other parameters of the gas mixture (e.g., exhaust gas and air) treated by gas capture system 166. For example, the exhaust gas can be used to increase the inlet temperature and humidity of the gas mixture (e.g., exhaust gas and air) that is transferred to the gas capture system 166 for processing. In other words, ambient air can be mixed with the exhaust gas being fed to the gas capture system 166, thereby helping to control the gas capture process.Control system 144 may be configured to control the amount of air flow provided to gas capture system 166 to use the available capacity of gas capture system 166. In some embodiments, the air flow provided by air circuit 464 may be diverted to duct 484 along with exhaust gases 656 such that both the exhaust gases 656 and the air flow are processed by both gas capture systems 164 and 166.

[0121] In some embodiments, first and second powertrains 652 and 654 can operate simultaneously in a power consumption mode, thereby providing airflow to gas processing system 18 to increase the airflow for air treatment and trapping of undesirable gases as trapped gas 194. In these embodiments, the airflow may be provided to gas processing system 18 for gas treatment in one or both of gas trapping systems 164 and 166. For example, if gas trapping system 166 has sufficient capacity to process the airflows of both powertrains 652 and 654, the airflow may be directed only to gas trapping system 166 for air purification. However, if gas trapping system 166 alone is insufficient to process the airflows from both powertrains 652 and 654, the airflow may be directed through both gas trapping systems 164 and 166.

[0122] Again, as described in detail above, when control system 144 operates each powertrain 650 in a power consumption mode, motor-generators 28A and 28B may operate as motors that drive the rotation of at least the compressor sections 22 of gas turbine systems 12A and 12B, and optionally the rotation of steam turbine systems 16A and 16B, such that compressor sections 22 provide airflow through respective gas turbine systems 12A and 12B to supply gas processing system 18. Additionally, one or more of air movers 492 may be used to supply airflow to gas processing system 18, such as gas capture system 164 and / or gas capture system 166. In the illustrated embodiment, when both first and second powertrains 652 and 654 are operating in a power consumption mode, heat source 562 may be used to provide heat to support the operation of gas capture systems 164 and / or 166. However, when powertrain 652 operates in a power consuming mode while powertrain 654 operates in a power producing mode, steam 658 may be used as heat source 580 with or without one or more heat sources 562. All other aspects of combined cycle power plant 10 remain the same as described in detail above.

[0123] FIG. 7 is a schematic diagram of one embodiment of the power plant 600 of FIG. 5 , further illustrating a plurality of powertrains 700 having a combustion system 600, a steam generator 602, an air mover 604, a steam turbine system 16, and a motor-generator 28. For example, the powertrain 700 may include any number of powertrains having similar components and functionality as those described in detail above. For example, the powertrain 700 may include a first powertrain 702 including an air mover 604A, a combustion system 600A, a steam generator 602A, a steam turbine system 16A, and a motor-generator 28A. Similarly, the second powertrain 704 may include an air mover 604B, a combustion system 600B, a steam generator 602B, a steam turbine system 16B, and a motor-generator 28B. The powertrain 700, including the first and second powertrains 702, 704, may be arranged substantially similarly to the plurality of powertrains 650 of FIG. 6 . Thus, the operation, function, and control are substantially the same as those described in detail above, with the difference being that the gas turbine system 12 and HRSG 14 are replaced with a combustion system 600 and a steam generator 602.

[0124] In the illustrated embodiment, the powertrains 700 can operate in the same or different operating modes, such as a power production mode, a power consumption mode, or a combination thereof. For example, the control system 144 may be configured to operate all of the powertrains 700 in a power production mode, all of the powertrains 700 in a power consumption mode, or one or more of the powertrains 700 in a power production mode and a power consumption mode. In a control configuration in which all of the powertrains 700 operate in a power production mode, the gas processing system 18 is configured to process exhaust gases from each powertrain using the gas capture systems 164 and 166. Thus, the first powertrain 702 can combust fuel from a fuel supply to generate hot combustion gases to produce steam.

[0125] In a control configuration in which first and second powertrains 702 and 704 operate in an electrical power producing mode, each of combustion systems 600A and 600B receives fuel from a respective fuel supply 46 and air from a respective air mover 604A and 604B to generate hot combustion gases 608. The combustion gases 608 then pass through a respective steam generator 602A and 602B to generate steam for a respective steam turbine system 16A and 16B, with the exhaust gases being discharged for treatment in gas processing system 18. Thus, gas processing system 18 can receive exhaust gases 656 from steam generator 602B via circuit 660 and exhaust gases from steam generator 602A downstream of each combustion system 600, such that gas capture system 164 treats the exhaust gases for subsequent treatment in gas capture system 166. Additionally, steam generators 602A and 602B provide steam as a heat source 480 to support the operation of gas processing systems 164 and 166 .

[0126] When control system 144 operates both first and second powertrains 702 and 704 in the power consumption mode, combustion systems 600A and 600B do not receive and combust fuel from their respective fuel supplies 46. Instead, control system 144 can control the flow through intake sections 20A and 20B and respective air movers 604A and 604B to provide airflow (i.e., no fuel combustion) through combustion systems 600A and 600B for subsequent air processing in gas processing system 18. Thus, each of combustion systems 600A and 600B cannot produce hot combustion gases 608; rather, combustion systems 600A and 600B only pass airflow for downstream air processing in gas processing system 18. The air flow can pass through all of the ducts 482, 484, 486, 488 and each of the gas processing systems 164, 166, or one or more of the air circuits 524, 526, 528 can be used to redirect the air flow to the gas capture system 166 (or any combination of the gas capture systems 162, 164, 166), as described above.

[0127] The control system 144 can also operate the first and second powertrains 702 and 704 in different operating modes. For example, the control system 144 can operate the first powertrain 702 in a power consumption mode, as described above, while operating the second powertrain 704 in a power production mode. While the second powertrain 704 is operating in the power production mode, the combustion system 600B combusts fuel to generate hot combustion gases 608, which pass through the steam generator 602B to generate steam for the steam turbine system 16B and steam 658 for the heat source 480, as described above. Additionally, the second powertrain 704 discharges exhaust gases 656 via a circuit 660 to a duct 484 upstream of the gas capture systems 164 and 166. Thus, while exhaust gas 656 can be processed by gas capture systems 164 and 166 in substantially the same manner as described above with reference to FIG. 6 , one or more air streams can also be supplied by air circuit 464 for processing in one or both of gas capture systems 164 and 166. In certain embodiments, control system 144 can control the proportion of exhaust gas mixed with the pre-processing air stream in one or both of gas capture systems 164 and 166, thereby helping to control the temperature, humidity, or other parameters of the gas mixture (e.g., exhaust gas and air) being processed by gas capture systems 164 and / or 166. For example, exhaust gas can be used to increase the inlet temperature and humidity of the gas mixture (e.g., exhaust gas and air) being transferred to gas capture systems 164 and / or 166 for processing. In other words, ambient air can mix with the exhaust gas being supplied to gas capture systems 164 and / or 166, thereby helping to control the gas capture process. In the illustrated embodiment, if steam is available, steam 658 may be used as heat source 480 to support gas capture systems 164 and 166, with or without heat source 562 as described above. All other aspects of power plant 600 are substantially the same as described in detail above with reference to Figures 1-6.

[0128] FIG. 8 is a flowchart of one embodiment of a process 750 for controlling operation of a power plant in a power producing mode and a power consuming mode, as described in detail above with reference to FIGS. 1-7. Process 750 may be performed by one or more controllers, such as controller 150 of control system 144. Process 750 may be used in any combustion-driven power plant, such as combined cycle power plant 10 of FIGS. 1, 4, and 6 and / or power plant 600 of FIGS. 5 and 7. In the illustrated embodiment, process 750 may include monitoring power demand and power prices for electricity supplied by the power plant on the power grid (block 752). For example, process 750 may monitor increases or decreases in power demand and power prices (e.g., electricity prices). Process 750 may also include a query or evaluation regarding whether power demand and / or power prices are below a threshold (block 754). For example, the threshold may include a power demand threshold and / or a power price threshold that are minimum levels for operating the power plant in a power producing mode. Thus, process 750 may proceed to control the power plant depending on whether the power demand and / or power price is below a threshold, as indicated by arrow 756, or above a threshold, as indicated by arrow 758.

[0129] As indicated by arrow 758, if the power demand and / or power price are above a threshold, the process 750 may proceed to controlling the power plant to operate in a power production mode (e.g., a firing mode or a combustion mode) and an exhaust gas treatment mode of one or more gas capture systems (block 760). The process 750 may then continue to control the combustion of fuel to generate hot combustion gases in a combustion system, such as a furnace, a gas turbine system, a reciprocating piston-cylinder engine, or any combination thereof (block 762). The process 750 may then proceed to controlling the generation of steam by extracting heat from the hot combustion gases (block 764). For example, the extraction of heat to generate steam may be performed via one or more HRSGs 14 and / or one or more steam generators 602. The process 750 may then proceed to controlling the generation of power by extracting power from the hot combustion gases and / or steam (block 766). For example, the hot combustion gases may be used to drive a turbine section of the gas turbine system 12, a piston of a reciprocating piston-cylinder engine, or another engine. The steam may be used to drive one or more turbines of the steam turbine system 16. The process 750 may then proceed to controlling treatment of the exhaust gas in a first stage of a gas capture system using the steam as a heat source (block 768). For example, the treatment may be performed using the gas capture system 164 of the gas processing system 18, as described in detail above. The steam may be used as a heat source to assist in desorption of the undesired gas from the adsorbent material, separation of the undesired gas from the solvent, or any combination thereof. The process 750 may then proceed to controlling treatment of the exhaust gas in a second stage of the gas capture system using steam as a heat source (block 770). For example, the gas processing may be performed using the gas capture system 166, as described above. Again, the steam may be used as a heat source to assist in desorption of the undesired gas from the adsorbent material, separation of the undesired gas from the solvent, or any combination thereof.The process 750 ultimately produces the captured gas 194 and the treated gas 490, as described in detail above.

[0130] If the power demand and / or power price is below a threshold, as indicated by arrow 756 (block 754), process 750 proceeds to controlling the power plant in a power consumption mode (e.g., a non-fired mode or a non-combustion mode) and an air treatment mode of the gas capture system (block 772). Process 750 may then proceed to controlling one or more compressors and / or air movers to provide airflow along one or more of air circuits 464, as described in detail above (block 774). For example, the airflow may be provided via compressor section 22 of gas turbine system 12, air mover 604 of combustion system 600, or one of air movers 494, 496, and / or 498. Process 750 may then proceed to controlling heat generation using one or more heaters and / or heat exchangers (block 776). For example, a heat source 562 including a heat exchanger 564 and / or a heater 566 may be used to provide heat to support operation of the gas capture system 166 and / or 164. The process 750 may then proceed to controlling airflow through an existing flow path of the combustion system and / or other flow paths (block 778). For example, the existing flow path of the combustion system may include the air circuit 522 internal to the gas turbine system 12, the air circuit internal to the combustion system 600, or a combination thereof. The other flow path may include one or more of the air circuits 464 described in detail above. The process 750 may then proceed to controlling a bypass of the airflow around the steam generator and / or the first stage of gas capture (block 780). For example, the steam generator may include the HRSG 14, the steam generator 602, or a combination thereof. The first stage of gas capture may include the gas capture system 164. The bypass may include the air circuit 524 that enables bypass air 530 as described above. The process 750 may then proceed to control the treatment of the airflow in a second stage of gas capture using heat (block 782).The second stage of gas capture can include a gas capture system 166, and the heat can include heat 568 from one or more heat sources 562, as described in detail above. Thus, the air stream is treated to remove one or more undesirable gases, such as carbon dioxide, thereby processing the air for discharge to the environment as treated gas 490. Additionally, process 750 obtains captured gas 194 (e.g., carbon capture, such as CO). Process 750 can also include a combination of a power production mode and a power consumption mode, as described in detail above with reference to FIGS. 6 and 7. During operation, process 750 enables various power plants 10 to operate in both power generation and power consumption modes, depending on various external factors, such as power demand, power prices, energy credits, gas capture credits (e.g., tax credits for capturing undesirable gases), or any combination thereof. Thus, when power demand and / or power prices are low, e.g., low, zero, or negative power pricing, process 750 can operate the power plant in a power consumption mode to generate energy credits and / or gas capture credits while treating the air in the environment.

[0131] Technical effects of the disclosed embodiments include a multi-stage gas processing system having multiple gas capture systems 160 (e.g., 162, 164, and 166), which may include a sorbent-based gas capture system (e.g., 250 in FIG. 2 ) and / or a solvent-based gas capture system (e.g., 350 in FIG. 3 ) with a heating fluid 168 (e.g., steam and / or heated water), waste heat from a waste heat recovery system 172 (e.g., 182, 184, and 186), and / or a heat source 562 (e.g., heat exchanger 564 and / or heater 566) as the heat source for the gas capture process. The disclosed embodiments substantially reduce concentration levels of undesirable gases (e.g., CO) to levels below input levels, thereby helping to achieve a desired carbon footprint (e.g., a low-carbon, net-neutral, or net-negative carbon footprint) of the combined cycle power plant 10 and / or the power plant 600. The disclosed embodiments advantageously control a power plant (e.g., 10, 600) in either a power production mode or a power consumption mode, thereby enabling gas capture from exhaust gases while generating electricity in the power production mode and gas capture from the air (e.g., ambient air) while not generating electricity in the power consumption mode. In particular, when power demand and / or electricity prices are low, zero, or negative, the power consumption mode enables additional gas capture from ambient air that would not otherwise be possible at the power plant (e.g., 10, 600).

[0132] The subject matter detailed above may be governed by one or more of the provisions set forth below.

[0133] The system includes a power plant having a first powertrain with a first combustion system, a first turbine, and a first motor-generator. The power plant includes a gas treatment system with at least one gas capture system configured to at least partially capture undesirable gases. The power plant includes an exhaust flow path through the at least one gas capture system, an air flow path through the at least one gas capture system, and at least one flow control device configured to control flow through the exhaust flow path and the air flow path. The power plant includes a controller configured to change operation of the power plant between a first control mode and a second control mode. The first control mode includes an ignition mode of the first combustion system to drive the first motor-generator in a generator mode to produce electrical power and an exhaust gas treatment mode of the gas treatment system to treat the exhaust gases through the at least one gas capture system. The second control mode includes a non-ignition mode of the first combustion system and an air treatment mode to treat airflow through the at least one gas capture system, the airflow being induced by one or more air movers.

[0134] 10. The system of any preceding clause, wherein the second control mode includes a motor mode of the first motor-generator to consume electrical power to drive a first air mover of the one or more air movers, and the air flow path includes a first air circuit extending inwardly through the first combustion system.

[0135] The system of any preceding clause, wherein the air flow path includes a second air circuit that bleeds air from the first air mover and bypasses at least the first combustion system, or a third air circuit that bleeds air from at least the first combustion system and bypasses at least a first steam generator or first gas capture system upstream of a second gas capture system of at least one gas capture system, or a combination thereof.

[0136] The system of any preceding clause, wherein the first air mover is selectively driven or not driven by the first motor-generator in the motor mode via control of a first clutch, and the one or more air movers include a second air mover selectively driven or not driven by the first motor-generator in the motor mode via control of a second clutch.

[0137] 10. The system of any preceding clause, wherein the one or more air movers include an air mover driven by an electric motor.

[0138] 10. The system of any preceding clause, wherein the air mover is disposed within a filter house of the first powertrain.

[0139] 10. The system of any preceding clause, wherein the air flow path does not extend internally through the first powertrain.

[0140] 10. The system of claim 1, wherein the exhaust flow path extends through first and second gas trapping systems of the at least one gas trapping system, the air flow path extends through the second gas trapping system, and the air flow path does not extend through the first gas trapping system.

[0141] The system of any preceding clause, wherein the second gas capture system comprises an adsorbent-based gas capture system.

[0142] 10. The system of any preceding clause, wherein the undesirable gas comprises carbon dioxide (CO2).

[0143] 10. The system of any preceding clause, wherein the first turbine includes a first gas turbine driven by combustion gases produced by the combustion system in the first control mode.

[0144] 10. The system of any preceding clause, wherein the first air mover includes a first air compressor of the first powertrain.

[0145] 10. The system of any preceding clause, wherein the first powertrain includes a first heat recovery steam generator (HRSG) configured to generate steam using heat from the combustion gas, and a first steam turbine driven by the steam in the first control mode.

[0146] 10. The system of any preceding clause, wherein the first powertrain includes a first steam generator configured to generate steam using heat from combustion gases generated by the combustion system in the first control mode, and the first turbine includes a first steam turbine driven by the steam in the first control mode.

[0147] The system of any preceding clause, wherein the power plant includes a second powertrain having a second combustion system, a second turbine, and a second motor-generator, and the controller is configured to selectively operate the power plant in one of a third control mode and a fourth control mode. The third control mode includes a non-firing mode of the first combustion system, a firing mode of the second combustion system, and a gas treatment mode of the gas treatment system for treating at least a portion of the exhaust gas from the second combustion system and the airflow through at least one gas capture system. The fourth control mode includes a non-firing mode of the first and second combustion systems and an air treatment mode for treating the airflow through the at least one gas capture system, wherein the airflow is at least partially induced by a first air mover of the first combustion system, a second air mover of the second combustion system, one or more air movers driven by individual shafts of each of the first or second powertrains, one or more air movers driven by respective electric motors separate from the first and second powertrains, or any combination thereof.

[0148] 10. The system of any preceding clause, wherein the controller is configured to control steam supply from a steam generator of the second powertrain to the at least one gas capture system in the third control mode.

[0149] 10. The system of any preceding clause, wherein the first control mode includes a full load control mode and a part load control mode of the first powertrain, the part load control mode being configured to enable the air flow through the at least one gas capture system via the one or more air movers.

[0150] 10. The system of any preceding clause, wherein the one or more air movers include a first air mover driven by the first powertrain, a second air mover driven by an electric motor, or a combination thereof.

[0151] The system includes a controller configured to vary operation of the combustion-driven power plant between a first control mode and a second control mode, the first control mode including an ignition mode of the combustion-driven power plant and an exhaust gas treatment mode of the gas treatment system for treating exhaust gases through at least one gas capture system, and the second control mode including a non-ignition mode of the combustion-driven power plant and an air treatment mode for treating an air flow through the at least one gas capture system, the air flow being directed by one or more air movers.

[0152] The method includes changing operation of a combustion-driven power plant between a first control mode and a second control mode. The method includes controlling operation of the combustion-driven power plant in a first control mode, the first control mode including an ignition mode of the combustion-driven power plant and an exhaust gas treatment mode of a gas treatment system for treating exhaust gases through at least one gas capture system. The method includes controlling operation of the combustion-driven power plant in a second control mode, the second control mode including a non-ignition mode of the combustion-driven power plant and an air treatment mode for treating an air flow through the at least one gas capture system, the air flow being directed by one or more air movers.

[0153] This specification uses examples to describe the present embodiments, including the best mode, and to enable any person skilled in the art to practice the embodiments disclosed herein, including making and using any devices or systems, and performing any incorporated methods. The patentable scope of the presently disclosed embodiments 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 that do not differ in material way from the literal language of the claims. [Explanation of symbols]

[0154] 10. Combined Cycle Power Plants 12, 12A, 12B Gas Turbine Systems 14 Heat Recovery Steam Generator (HRSG), HRSG 16, 16A, 16B Steam Turbine Systems 18 Gas Treatment System 20, 20A, 20B intake section 22 Compressor Section 24 Combustor Section 26 Turbine Section 28 Motor generator, heat generating component 28A, 28B Motor Generator 30 compressor stages 32 Rotary compressor blade 34 Fixed compressor vane 36 Compressor casing 38 Compressor shaft 40 Combustor 42 Shaft 44 Fuel Nozzle 46 Fuel supply 48 Turbine Blades 50 Fixed turbine vanes 52 Turbine casing 54 Turbine shaft 56 Turbine Stages 58 Shaft 60 Intake flow 62 Compressed Air Flow 64 Combustion chamber 66 High-temperature combustion gas flow 68 Exhaust gas flow 70 Components 72 High Pressure (HP) Section 74 Medium Pressure (IP) Section 76 Low Pressure (LP) Section 78 Finishing high pressure superheater 80 Secondary reheater 82 Primary reheater 84 Primary high pressure superheater 86, 88 Interstage desuperheater 90 High-pressure evaporator 92 High-pressure economizer 94 Medium pressure evaporator 95 Fuel gas heater 96 Medium Pressure Economizer 98 Low-pressure evaporator 100 Low-pressure economizer 102 Enclosure or duct 104 Steam Turbine 106 High Pressure Steam Turbine (HP ST) 108 Intermediate Pressure Steam Turbine (IP ST) 110 Low Pressure Steam Turbine (LP ST) 112 Shaft 114 Shaft 116 Load 118 Shaft 120 condensate 122 Condenser 124, 125 Pumps 126 Water Supply 130 Fluid Connection System 132 High pressure steam supply conduit or line 134 Discharge or return line 136 Medium pressure steam supply conduit or line 138 Discharge or return line 140 Low pressure steam supply conduit or line 142 Discharge or return line 144 Control Systems 146 Surveillance System 148 sensors 150 Controller 152 processors 154 memory 156 Command 160, 162, 164, 166 Gas capture system 168 Heating fluids, steam 170 Steam Supply System 172 Waste Heat Recovery (WHR) System 174, 176 Steam supply conduit or line 178, 180 heat exchanger 182, 184, 186 Waste heat recovery system 188 Compression System 190 airflow 192 Arrow 194 Trapped Gas 196 Discharge conduit or line 198 Dryer 200 Dryer 202 Fans 204 Valve 206 Channel 208 Discharge ducts or lines 210 Dryer 212 Discharge conduits or lines 214 Exhaust stack 216 Discharge conduits or lines 218 Dryer 220 Discharge ducts or lines 222, 224 compressors 226 Intercooler 228 Storage / Pipeline 230 Discharge ducts or lines 250 Adsorbent-based gas capture systems 252 Adsorbent-based gas capture unit 254, 256 Adsorbent-containing conduit 258 Gas capture unit, adsorbent-containing conduit 260 Outer conduit wall 262 Channel 264 Central axis 266 Entrance 268 Exit 270 Adsorbent Materials 272 Inside 274 Upstream Flow Distribution System 276 Downstream Flow Distribution System 278 Heated Fluid Supply System 280 Gas Supply System 282 Desorption Aftertreatment System 284 Treated Gas Treatment System 286 Gas 288 Heated Fluid Control 290, 292, 294 Heated fluid control components 296 Valve 298, 300 Distribution conduits or lines 302 Gas Pretreatment 304, 306, 308 Gas Pretreatment Components 310 Valve 312, 314 Distribution conduits or lines 316 Valve 318, 320 Distribution conduits or lines 322 Post-detachment processor 324, 326, 328 Desorption post-processing components 330 water 332 Valve 334, 336 Distribution conduit or line 338 Treated Gas 350 Solvent-Based Gas Capture System 352 Absorber 354 Solvent Supply System 356 Solvent Discharge System 358 Gas Lean Solvent 360 Conduit 362 Solvent Distributor 364 nozzles 366 Solvent Dispersion 368 internal volume 370 Solvent inlet 372 Solvent outlet 374 Gas-rich Solvents 376 Solvent Regeneration System 378 Gas Compressor 380 Gas Dryer 382 Return conduit 384 Gas inlet 386 Gas Outlet 388 Case 390 Upper 392 Bottom 394 Middle part 396 Central axis 398, 400 axis 402 Axis, circumferential direction 404 Cover 406 Side wall 408 base plate 410 Gasket 412 Support tray or screen 414 Solvent Distributor 416 Nozzle 418 Solvent dispersion 420 Arrow 422 Steam Supply System 424 Arrow 426, 428, 430, 432 Components 450 Multimode Configuration 452 Power Generation Fluid Circuit 454 Power consumption fluid circuit 456 Air circuit, intake circuit 458 Fuel circuit 460 exhaust gas circuit 462 Steam Circuit 464 Air Circuit 466 Common Shaft 468, 470 Steam turbine 472 Air Filter 474, 476, 478 Steam circuits 480 Heat source 482, 484, 486, 488 Ducts 490 Treated Gas 492, 494, 496, 498 Air Mover 500, 502 clutch 504, 506 clutch part 508 Motor generator shaft 512 shaft 514 Shaft 516, 518 Electric motors 520 Air Filter 522, 524, 526, 528 Air circuits 530 Bypass Air 532 Bleed Air 534 Cooler 536 Additional Air 538, 540, 542, 544 Air circuits 546, 548, 550, 552, 554, 556, 558, 560 valves 562 Heat source 564 Heat exchanger 566 Heater 568 fever 578 Steam Circuit 580 Heat source 600 Power plants, combustion systems 600A, 600B Combustion System 602, 602A, 602B Steam Generators 604, 604A, 604B Air Movers 606 Shaft 608 High-temperature combustion gas 650 Powertrain 652 First Powertrain 654 Second Powertrain 656 Exhaust Gas 658 Steam 660, 662 circuits 700 Powertrain 702 First Powertrain 704 Second Powertrain 750 processes 756, 758 Arrows

Claims

1. 1. A system comprising: A power plant (600) comprising: a first powertrain (652) comprising a first combustion system (600), a first turbine, and a first motor-generator (28); a gas treatment system (18) comprising at least one gas capture system (160, 162, 164, 166) configured to at least partially capture undesired gases; an exhaust flow path through the at least one gas capture system (160, 162, 164, 166); an air flow path through the at least one gas capture system (160, 162, 164, 166); at least one flow control configured to control flow through the exhaust flow path and the air flow path; a controller (150) configured to change operation of the power plant (600) between a first control mode and a second control mode; Equipped with the first control mode includes an ignition mode of the first combustion system (600) for driving the first motor-generator (28) in a generator mode to produce electrical power, and an exhaust gas treatment mode of the gas treatment system (18) for treating exhaust gases via the at least one gas capture system (160, 162, 164, 166); the second control mode includes a non-ignition mode of the first combustion system (600) and an air treatment mode for treating an airflow through the at least one gas entrapment system (160, 162, 164, 166), the airflow being directed by one or more air movers (492, 494, 496, 498); system.

2. 2. The system of claim 1, wherein the second control mode comprises a motor mode of the first motor-generator (28) consuming electrical power to drive a first air mover of the one or more air movers (492, 494, 496, 498), and the air flow path comprises a first air circuit extending inwardly through the first combustion system (600).

3. 3. The system of claim 2, wherein the air flow path comprises: a second air circuit that extracts air from the first air mover and bypasses at least the first combustion system (600); and a third air circuit that extracts air from downstream of the at least first combustion system (600) and bypasses at least a first steam generator or a first gas capture system, or a combination thereof, upstream of a second gas capture system of the at least one gas capture system (160, 162, 164, 166).

4. 3. The system of claim 2, wherein the first air mover is selectively driven or not driven by the first motor-generator in the motor mode via control of a first clutch, and the one or more air movers include a second air mover that is selectively driven or not driven by the first motor-generator in the motor mode via control of a second clutch.

5. The system of claim 1 , wherein the one or more air movers (492, 494, 496, 498) comprise air movers driven by electric motors (516, 518).

6. The system of claim 5 , wherein the air mover is disposed within a filter house of the first powertrain (652).

7. The system of claim 1 , wherein the air flow path does not extend internally through the first powertrain (652).

8. 2. The system of claim 1, wherein the exhaust flow path extends through first and second gas capture systems of the at least one gas capture system, the air flow path extends through the second gas capture system, and the air flow path does not extend through the first gas capture system.

9. The system of claim 8 , wherein the second gas capture system comprises an adsorbent-based gas capture system (250).

10. The undesired gas is carbon dioxide (CO ２ 10. The system of claim 8, comprising:

11. The system of claim 1 , wherein the first turbine comprises a first gas turbine driven by combustion gases produced by the combustion system (600) in the first control mode.

12. The system of claim 11 , wherein the first air mover comprises a first air compressor of the first powertrain (652).

13. 13. The system of claim 12, wherein the first powertrain comprises a first heat recovery steam generator (HRSG) configured to generate steam using heat from the combustion gases, and a first steam turbine driven by the steam in the first control mode.

14. 2. The system of claim 1, wherein the first powertrain (652) comprises a first steam generator configured to generate steam using heat from combustion gases generated by the combustion system (600) in the first control mode, and the first turbine comprises a first steam turbine (16) driven by the steam in the first control mode.

15. The power plant (600) comprises a second powertrain (654) including a second combustion system (600), a second turbine, and a second motor-generator (28), and the controller (150) is configured to: a third control mode including the non-ignition mode of the first combustion system (600), the ignition mode of the second combustion system (600), and a gas treatment mode of the gas treatment system (18) for treating at least a portion of the exhaust gas from the second combustion system (600) and the airflow through the at least one gas capture system (160, 162, 164, 166); a fourth control mode including the non-ignition mode of the first and second combustion systems (600) and the air treatment mode for treating the airflow through the at least one gas entrapment system (160, 162, 164, 166), wherein the airflow is at least partially induced by a first air mover of the first combustion system (600), a second air mover of the second combustion system (600), one or more air movers (492, 494, 496, 498) driven by respective shafts of the first or second powertrains (652, 654), one or more air movers (492, 494, 496, 498) driven by respective electric motors (516, 518) separate from the first and second powertrains (652, 654), or any combination thereof; The system of claim 1 , configured to selectively operate the power plant (600) at one of:

16. 16. The system of claim 15, wherein the controller (150) is configured to control steam supply from a steam generator (602) of the second powertrain (654) to the at least one gas capture system (160, 162, 164, 166) in the third control mode.

17. 2. The system of claim 1, wherein the first control mode includes a full load control mode and a part load control mode of the first powertrain, the part load control mode being configured to allow the air flow through the at least one gas capture system via the one or more air movers.

18. 18. The system of claim 17, wherein the one or more air movers (492, 494, 496, 498) include a first air mover driven by the first powertrain (652), a second air mover driven by an electric motor (516, 518), or a combination thereof.

19. 1. A system comprising: a controller (150) configured to vary operation of the combustion-driven power plant between a first control mode and a second control mode; Equipped with the first control mode includes an ignition mode of the combustion-driven power plant and an exhaust gas treatment mode of a gas treatment system (18) for treating exhaust gases via at least one gas capture system (160, 162, 164, 166); the second control mode includes a non-ignition mode of the combustion-driven power plant and an air treatment mode for treating an air flow through the at least one gas capture system (160, 162, 164, 166), the air flow being directed by one or more air movers (492, 494, 496, 498); system.

20. 1. A method comprising: varying operation of the combustion-driven power plant between a first control mode and a second control mode; controlling operation of the combustion-driven power plant in a first control mode, the first control mode including an ignition mode of the combustion-driven power plant and an exhaust gas treatment mode of a gas treatment system (18) for treating exhaust gases via at least one gas capture system (160, 162, 164, 166); controlling operation of the combustion-driven power plant in the second control mode, the second control mode including a no-fire mode of the combustion-driven power plant and an air treatment mode for treating an air flow through the at least one gas capture system (160, 162, 164, 166), the air flow being directed by one or more air movers (492, 494, 496, 498); A method comprising:

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