Gas turbine exhaust gas treatment system and method

Abstract

A turbine exhaust gas treatment system and method for improved operational flexibility includes a turbine exhaust gas discharge structure, a catalytic turbine exhaust gas treatment system at least partially located within the turbine exhaust gas discharge structure, a pump, and at least two heat exchangers. A first heat exchanger, at least partially located within the turbine exhaust gas discharge structure, removes heat from the turbine exhaust gas by transferring heat to a working fluid. A second heat exchanger removes the heat acquired in the first heat exchanger from the working fluid. A pump drives the working fluid between the first and second heat exchangers. In a further embodiment, the catalytic turbine exhaust gas treatment system is replaced by a heat recovery steam generator.

Description

Technical Field

[0001] [Cross - Reference to Related Applications] This application is a continuation - in - part of U.S. Patent Application Serial No. 17 / 487,887, filed on September 28, 2021, which claims the priority of U.S. Provisional Patent Application Serial No. 63 / 084,290, filed on September 28, 2020, and both of these applications are hereby incorporated by reference in their entirety.

[0002] [Statement Regarding Federally Sponsored Research or Development] Not applicable

Background Art

[0003] Exhaust gases resulting from various processes and / or the combustion of various fuels generally contain one or more harmful substances such as carbon monoxide and / or nitrogen oxides. For example, the combustion of natural gas or other fossil fuels in a power plant produces a hot exhaust gas stream containing carbon monoxide, nitrogen oxides, and / or other exhaust gases. Similarly, in the manufacture of chemical products, hydrocarbon cracking, steelmaking, and other processes, hot exhaust gas streams containing harmful substances are produced. Typically, an exhaust gas stream is treated with one or more catalysts (e.g., a catalyst bed) to reduce carbon monoxide, nitrogen dioxide, and / or other substances. For example, a catalyst can convert nitrogen dioxide and / or carbon monoxide into one or more of water, diatomic nitrogen, carbon dioxide, and / or other less harmful compounds. To treat nitrogen oxides using a catalyst, generally, a reactant such as anhydrous ammonia or an aqueous solution of ammonia is introduced upstream of a selective catalytic reduction (SCR) catalyst.

[0004] Each catalyst and / or reactant has an operating temperature range that optimizes the desired reaction for reducing exhaust gas components. Furthermore, if the exhaust gas temperature exceeds the mechanical / chemical design limits of the catalyst or housing, the catalyst or reactant itself and / or the housing containing the catalyst and / or reactant (e.g., SCR) or material may be damaged. Therefore, it may be advantageous to control the temperature of the exhaust gas before it passes through the catalyst material in order to keep it within a temperature range that can optimally treat specific components in the exhaust gas.

[0005] Many conventional exhaust gas cooling and exhaust gas treatment systems suffer from problems such as reduced performance, limited operational flexibility, lifespan, and efficiency, due to the limitations of the cooling system and the requirements of the exhaust gas treatment system mentioned above.

[0006] Power plants have highly complex structures that incorporate multiple systems to ensure efficient and productive performance. Boilers and / or heat recovery steam generators (HRSGs) form the core of the power plant and are designed to operate within a specific range of intended conditions. This range is very broad, but once defined, operating outside of these conditions can lead to operational and safety problems.

[0007] Many fossil fuel power plants are being forced to rethink their operating profiles as they cope with the increasing impact of renewable energy. In addition to the impact of renewable energy generation, there are significant natural fluctuations in electricity demand between day and night, with demand dropping sharply, especially in the evening / nighttime hours. Power plants want to reduce output during these low-demand periods to achieve substantial reductions in operating costs.

[0008] However, in the case of a typical combined cycle power plant (i.e., a power generation cycle using a gas turbine (GT) that emits emissions from a heat recovery steam generator (HRSG)), a decrease in electricity demand leads to a decrease in the output of the GT. A decrease in gas turbine output generally results in both a decrease in the exhaust gas flow rate into the HRSG and an increase in the exhaust gas temperature entering the HRSG. This effect (reduced exhaust gas flow rate and high gas temperature) causes the boiler to operate off-design conditions, resulting in lower efficiency than intended. As the power load decreases further, there is a limit to how much further reduction is possible without operating the equipment / facilities in an unsafe manner. Further complicating the operation of the system is the need to ensure that the GT operates under conditions that can satisfy environmental regulations, either by treating the emissions from the gas turbine directly from the gas turbine or in the HRSG.

[0009] New power plants can also be designed to reflect the further reduced operating load in their equipment design, but this comes with a significant increase in cost due to more materials and equipment. While such design adjustments allow for an expanded operating range, they still present the challenge of lower operating efficiency.

[0010] In conventional combined cycles, a desuperheater may be used to increase the flow rate of desuperheating water introduced into the steam network as an attempt to ensure that the design temperature is not exceeded. Furthermore, under lower gas turbine conditions, there is a limit to the amount of additional desuperheating water that can be added, as the desuperheater exhaust approaches the steam saturation temperature (i.e., the additional water does not evaporate within the system). The use of superheaters and reheaters in HRSGs is described in U.S. Patents 8,820,078 and 9,435,228, both of which are incorporated herein by reference as being fully described. In HRSG operation, there is a need to increase operational flexibility and reduce inefficient and wasteful characteristics during off-design operation.

[0011] There is a need for methods / systems that enable power plants (new and existing) to achieve a wider operating range while still meeting emission requirements without significantly sacrificing efficiency. [Overview of the Initiative]

[0012] The cooling system described herein offers several advantages over typical gas turbine flue gas treatment systems and / or heat recovery steam generators (HRSGs). By cooling the turbine flue gas using the disclosed system, the temperature of the turbine flue gas can be controlled to be within a range suitable for treatment by one or more catalysts (e.g., catalytic treatment of carbon monoxide, selective catalytic reduction (SCR), treatment of nitrogen oxides, etc.). By using a working fluid, as described herein, to cool the turbine flue gas before catalytic treatment, it is possible to control the temperature of the turbine flue gas at one or more locations more precisely. For example, the working fluid can be used to control the temperature of the turbine flue gas within a first temperature range before carbon monoxide treatment at a first location, and within a second different temperature range before nitrogen oxide treatment at a second location. Such controllability enables optimal temperatures for different catalytic reactions.

[0013] Furthermore, during the startup of a typical combined cycle power plant, a considerable amount of time is required to heat the large mass of the HRSG steel, and this must be done in a way that does not damage the HRSG. This means controlling / limiting the heat output from the gas turbine during startup. The startup time of a combined cycle is a high-cost period because steam / electricity production is low or zero until the power plant is operational. Also, many gas turbines increase emissions at the low operating load required during startup, so there is a risk that the power plant will exceed the required emission standards during such an operating period. The disclosed invention enables controlled removal of heat from the exhaust gas at the HRSG inlet, allowing the gas turbine to start up without or with minimal limitations, while ensuring the safe operation of the HRSG and enabling startup in a manner required to limit potential damaging stress that could shorten the HRSG's operating life. The energy removed from the HRSG inlet is stored and can be recovered during subsequent operation as a means of reducing energy input from the gas turbine when higher power is required or for a certain period, thereby improving the efficiency of the power plant.

[0014] Therefore, the controllability provided by using a working fluid to cool the turbine exhaust gas allows for reduced energy consumption compared to the use of other techniques (e.g., forced induction fans in simple cyclic operation), and the controllable cooling use by the working fluid allows for optimization of the catalytic reaction used to treat the turbine exhaust gas. The advantages of the turbine exhaust gas treatment systems currently described herein are these advantages and / or other advantages. The use of a working fluid to cool the turbine exhaust gas offers the advantage that the heat of the turbine exhaust gas can be removed and captured by the working fluid or redistributed in areas within the HRSG to facilitate the HRSG startup or catalysis. In an example that is not limited, the heat captured at the inlet of the HRSG is directed to be discharged in a separate coil located at the inlet of the SCR catalyst. In such a scheme, the exhaust gas traveling through the coil recovers heat from the SCR inlet coil and carries this heat directly to the SCR catalyst. This arrangement allows a significant portion of the HRSG inlet exhaust gas energy to effectively bypass the heating surface upstream of the catalyst, which, as mentioned earlier, poses a problem for power plant operation. By heating the catalyst more rapidly, it enables an early reduction in gas emissions during the initial startup phase of the power plant.

[0015] Similar to rapid catalytic start-up, recovered inlet heat can be distributed upstream of a specific heating surface (e.g., evaporator coil) (either directly from the upstream coil or from recovered energy stored in a thermal energy storage system), enabling more controlled heating of the associated thick-walled steel components (i.e., not affected by the unlimited heat input from an unrestricted gas turbine start-up), thereby limiting the thermal stress applied to the coil and reducing the likelihood of premature failure. Similar to this operation, the bypass of heat around the superheater and reheater coils located upstream of the heated HRSG coil in question reduces any amount of water injected into the HRSG steam flow. Energy removed from turbine exhaust gases can be recovered directly by mechanical connections to devices such as pumps (e.g., pumps driven by a working fluid), indirectly by expansion through appropriate devices connected to a generator (e.g., a working fluid driving an energy recovery turbine coupled to a generator), or the heat recovered by the working fluid may be used to heat a separate process fluid (e.g., using a heat exchanger to transfer heat from the working fluid to another process fluid).

[0016] Additional embodiments of the cooling system for a heat recovery steam generator (HRSG) described herein may increase the operating range of the power plant while promoting even higher power plant efficiency. In this power plant, the gas turbine output decreases as the electricity demand decreases. The decrease in gas turbine output leads to a decrease in the flow rate of hot exhaust gas from the turbine and an increase in the exhaust gas temperature in the HRSG. This consequently leads to the HRSG operating at even lower efficiency under out-of-design conditions. The cooling system of this disclosure provides a control coil at the inlet of the HRSG, independent of the HRSG coil. The control coil can be operated at any load (any regulated speed of fluid flow through the coil) to remove the required heat from the gas turbine exhaust gas entering the HRSG and reduce the exhaust gas temperature. This allows the HRSG to operate safely and efficiently even downstream of a reduced-output gas turbine. The heat recovered by the control coil is led to a thermal energy storage system (TESS), where the heat is stored until the HRSG operation can use the stored thermal energy to satisfy peak load conditions or other process requirements. The inlet control coil plays a role in controlling and limiting the high heat content of the gas turbine exhaust gas flowing into the HRSG. Subsequently, the control coil can be operated to enable heating of the HRSG by controllingly reducing the flow rate of the cooling fluid within the coil. This disclosure relates to the use of individually designed, dedicated heating surface coils (control coils) or sets of such coils so that the flow through the coil is independent of the steam production from the boiler's evaporator section. In contrast, with conventional coils, the steam flow through the superheater / reheater heating coil is determined by the steam production in the dedicated evaporator section of the HRSG / boiler.

[0017] The use of control coils through which a heating fluid, gas, or supercritical fluid passes reduces, and in some cases eliminates, the need for desuperheating at low loads, without being subject to operating limitations imposed by physical constraints. For example, the heat recovered by the supercritical / heating fluid passing through the control coil may not even affect the saturation temperature (i.e., the working fluid may be single-phase). Furthermore, since the heat recovered by the control coil is directed to a thermal energy storage system, adjustment of the fluid temperature at the HRSG-controlled coil outlet becomes unnecessary.

[0018] Therefore, this disclosure addresses the increasingly important issue of the limited ability of combined cycles to operate at low power loads, a need that arises as renewable energy is increasingly integrated into national power grids.

[0019] This disclosure reduces the time required to bring the emissions system to a regulatory-compliant state during power plant startup.

[0020] This disclosure also contributes to minimizing the amount of desuperheater water required under out-of-design conditions (e.g., partial load or different ambient conditions), thereby reducing the risk of erosion of HRSG and steam turbine components. The reduction in desuperheater spray water also contributes to improved boiler efficiency by further reducing the amount of cooling water used for desuperheater spraying, thereby reducing steam production in the maximum pressure system. Since such a reduction in steam production is particularly noticeable when spraying into the reheater coil upstream of the evaporator, this disclosure can offer significant advantages in systems with reheater coils.

[0021] Other advantages and features of the system described herein will become apparent from the disclosures described below. [Brief explanation of the drawing]

[0022] [Figure 1]A schematic diagram of a gas turbine exhaust gas treatment system including a catalyst treatment device and a carbon dioxide cooling system for cooling turbine exhaust gas, in which an enlarged view of a mass inventory management system is shown at the lower left side. [Figure 2] A schematic diagram of an alternative embodiment of the turbine exhaust gas treatment system of FIG. 1, in which thermal oil is used as the working fluid. [Figure 3] A schematic diagram of an alternative embodiment of the turbine exhaust gas treatment system of FIG. 1, in which water is used as the working fluid. [Figure 4] A schematic diagram of an alternative embodiment of the turbine exhaust gas treatment system of FIG. 1, including a heat exchanger provided between a pump and an expansion nozzle. [Figure 5] A schematic diagram of an alternative embodiment of the turbine exhaust gas treatment system of FIG. 4, in which thermal oil is used as the working fluid. [Figure 6] A schematic diagram of an alternative embodiment of the turbine exhaust gas treatment system of FIG. 4, in which water is used as the working fluid. [Figure 7] A schematic diagram of an alternative embodiment of the turbine exhaust gas treatment system of FIG. 1, in which split cooling is used to cool the turbine exhaust gas before the first catalyst treatment device and further cool the turbine exhaust gas after the first catalyst treatment device and before the second catalyst treatment device. [Figure 8] A schematic diagram of an alternative embodiment of the turbine exhaust gas treatment system of FIG. 7, including a heat exchanger provided between a pump and an expansion nozzle. [Figure 9A] A schematic diagram of an alternative embodiment of a turbine exhaust gas treatment system having an independent cooling loop. [Figure 9B] A schematic diagram of an alternative embodiment of a turbine exhaust gas treatment system having an independent cooling loop and a common mass inventory system. [Figure 9C] A schematic diagram of an alternative embodiment of a turbine exhaust gas treatment system having three or more independent cooling loops. [Figure 10]This is a schematic diagram of an exhaust gas treatment system similar to Figure 1, located upstream of the catalytic exhaust gas treatment device and containing a control coil connected to a thermal energy storage system and a cooling loop. [Figure 11] This is a schematic diagram of an alternative embodiment of the cooling system shown in Figure 10, which is located upstream of the heat recovery steam generator (HRSG) and has a control coil connected to a thermal energy storage system (TESS) and a cooling loop. [Figure 12] This is a schematic diagram of an additional embodiment of the cooling system shown in Figure 11, which is located upstream of the heat recovery steam generator (HRSG) and has a control coil connected to a thermal energy storage system (TESS) and a cooling loop. [Figure 13] This is a schematic diagram of an additional embodiment of the cooling system shown in Figure 11, which is located upstream of the heat recovery steam generator (HRSG) and has a control coil connected to a thermal energy storage system (TESS) and a cooling loop. [Figure 14] This is a schematic diagram of an additional embodiment of the cooling system shown in Figure 11, which is located upstream of the heat recovery steam generator (HRSG) and has a control coil connected to a thermal energy storage system (TESS) and a cooling loop. [Figure 15] This is a schematic diagram of an additional embodiment of the cooling system shown in Figure 11, which is located upstream of the heat recovery steam generator (HRSG) and has a control coil connected to a thermal energy storage system (TESS) and a cooling loop.

[0023] Corresponding reference letters and symbols indicate the corresponding parts throughout multiple drawings of the drawing. [Modes for carrying out the invention]

[0024] The following detailed description, which is illustrative and not limiting, describes the claimed gas turbine exhaust gas treatment system and related methods. This description will enable a person skilled in the art to manufacture and use the turbine exhaust gas treatment system. This detailed description includes what is considered to be the best mode for realizing the currently claimed turbine exhaust gas treatment system and related methods, and describes various embodiments, adaptations, modifications, alternatives, and applications of the turbine exhaust gas treatment system. Furthermore, it should be understood that the disclosed turbine exhaust gas treatment system is not limited to the structural details and arrangement of components shown in the following description or drawings. This disclosure has other embodiments and can be implemented or carried out in various ways. It should also be understood that the expressions and terms used herein are for illustrative purposes only and should not be construed as limiting.

[0025] Referring to Figures 1-8, a turbine exhaust gas treatment system uses a working fluid to treat turbine exhaust gas. The term “turbine exhaust gas” as used herein should be understood as gas from or involved in any process that uses or produces turbine exhaust gas as a byproduct, such as combustion (e.g., related to power production), chemical manufacturing, oil cracking, steelmaking, or other processes. Referring again to a simple-cycle turbine installation, such an installation uses only a single thermodynamic cycle (e.g., a Brayton cycle) so that the high-temperature exhaust gas is discharged directly from the gas turbine into the atmosphere. When emission reduction is required in a simple-cycle power plant, large forced-draft fans are often used to mix a large amount of ambient air with the gas turbine exhaust gas to achieve the required catalytic operating temperature. Such fans are expensive to procure and generally have high operating costs (e.g., high power consumption).

[0026] The exhaust gas treatment system cools the high-temperature exhaust gas to an optimal temperature range to facilitate the desired chemical reactions that occur to treat the exhaust gas components, while simultaneously protecting the catalytic system from mechanical damage due to overheating. This is achieved without the use of large forced-draft or induction fans. There is no need to add additional air or other gases to the exhaust gas for the purpose of cooling it before treating it in one or more catalytic processes. In some embodiments, additional air or other gases are indirectly added to the exhaust gas, but this is not for cooling the exhaust gas, but to facilitate the treatment of the turbine exhaust gas. For example, ammonia may be used when treating nitrogen oxides in the turbine exhaust gas stream. In this case, the ammonia may be in aqueous solution, so that the ammonia is mixed with air in a mixing tank, and the water-soluble ammonia is flushed in the mixing tank and diluted with air before being injected into the turbine exhaust gas.

[0027] Upstream of the catalyst system, heat transfer coils are used to treat the exhaust gas to reduce the high-temperature gas temperature to a target range for safer and more efficient operation of the catalyst. The heat recovered from the host turbine exhaust gas is dissipated into the surroundings through air-cooled and / or water-cooled heat exchangers. Alternatively, the removed heat can be used to heat an external process stream (e.g., through the use of a heat exchanger), recovered by mechanical application (e.g., using the removed heat to drive a pump), or recovered by the direct expansion of a thermal working fluid using equipment connected to an electric generator (e.g., the thermal fluid expands to drive a turbine, which in turn drives an electric generator). Furthermore, the recovered heat can be stored and recovered for use at another time when energy demand is high. By placing additional heat exchange coils within the gas stream, it is possible to achieve different turbine exhaust gas temperatures at different points within the turbine exhaust gas stream.

[0028] Such temperature control enables improved treatment of turbine exhaust gases. For example, generally, the target optimal temperature range for a catalyst to treat carbon monoxide does not overlap with the optimal temperature range for nitrogen oxide treatment reactions. The temperature for treating carbon monoxide is higher than the temperature for treating nitrogen oxides. As a result, carbon monoxide treatment catalysts can operate in a higher temperature range below the upper limit temperature than SCR catalysts. By using multiple cooling coils (e.g., heat exchangers), the temperature of the turbine exhaust gas stream can be controlled, improving the efficiency of catalytic treatment.

[0029] In some embodiments of turbine exhaust gas treatment systems, the system uses supercritical carbon dioxide as the working fluid. This offers particular advantages in that supercritical carbon dioxide has a high fluid density, is easily pumped by a closed cooling loop, and has a high heat capacity, allowing for a smaller amount of fluid to pass through the heat exchanger coils for the same degree of temperature reduction as the high-temperature turbine exhaust gas. In other embodiments of turbine exhaust gas treatment systems, other suitable heat transfer working fluids, including but not limited to hot oil and / or water, may be used. The system uses a cooling loop to cool the turbine exhaust gas stream to be treated. As used herein, “cooling loop” should be understood to refer to equipment used in a standard cooling cycle that provides a cooled working fluid to a heat exchanger to cool the turbine exhaust gas or any other gas to be treated. For example, a cooling loop may include piping, conduits, etc. that have and transmit the working fluid; a condenser; a pump; an expansion nozzle; an evaporator; and / or other components (e.g., shared or dedicated mass inventory systems) for providing a cooling cycle for the turbine exhaust gas to be treated. Piping, conduits, etc., provide fluid communication of the working fluid between other components of the cooling loop.

[0030] Referring to Figure 1, one embodiment of a turbine exhaust gas treatment system 100 using a carbon dioxide working fluid is shown. The exhaust gas to be treated (e.g., exhaust gas from a gas turbine or other process) is received by a turbine exhaust gas discharge structure 102. The turbine exhaust gas discharge structure 102 is configured to receive turbine exhaust gas from a source (e.g., a turbine) and to pass the turbine exhaust gas through the turbine exhaust gas discharge structure 102. For example, the turbine exhaust gas discharge structure 102 is connected to the turbine exhaust gas source by hard piped and may be or include pipes, ducts, or other structures.

[0031] The turbine exhaust gas passing through the turbine exhaust gas discharge structure 102 passes through the catalytic turbine exhaust gas treatment device 104. The catalytic turbine exhaust gas treatment device 104 is positioned at least partially within the turbine exhaust gas discharge structure 102 so that the turbine exhaust gas comes into contact with the catalytic turbine exhaust gas treatment device 104. The catalytic turbine exhaust gas treatment device 104 is configured to treat at least one component of the turbine exhaust gas through a catalytic reaction between the catalyst housed within the catalytic turbine exhaust gas treatment device 104 and at least one component of the turbine exhaust gas. For example, the catalytic turbine exhaust gas treatment device 104 may contain any suitable activator for reacting with carbon monoxide to form carbon dioxide. For example, carbon monoxide may be treated with platinum, rhodium, palladium, a common oxidizer, or any other suitable catalyst.

[0032] System 100 may further include a second catalytic turbine exhaust gas treatment device 106 located within the turbine exhaust gas discharge structure 102 and downstream of the first catalytic turbine exhaust gas treatment device 104. The second catalytic turbine exhaust gas treatment device 106 is configured to treat at least one component of the turbine exhaust gas through a catalytic reaction between a catalyst housed within the second catalytic turbine exhaust gas treatment device 106 and at least one component of the turbine exhaust gas. For example, the second catalytic turbine exhaust gas treatment device 106 includes any suitable activator for reacting with nitrogen oxides to form one or more of water, diatomic nitrogen, or other compounds. The activator may be anhydrous ammonia, an aqueous solution of ammonia, or a similar reactant, or may include the same.

[0033] In some embodiments, the first catalytic turbine exhaust gas treatment system 104 is configured to treat both carbon monoxide and nitrogen oxides in the turbine exhaust gas. The first catalytic turbine exhaust gas treatment system 104 can treat both carbon monoxide and nitrogen oxides using multiple catalysts or a single catalyst. For example, in the case of a single catalyst, the first catalytic turbine exhaust gas treatment system 104 may include iron and cobalt impregnated on activated semi-coke. The catalyst is supplied with carbon monoxide (e.g., carbon monoxide from the turbine exhaust gas) and absorbs or otherwise removes nitrogen oxides from the turbine exhaust gas. To treat both carbon monoxide and nitrogen oxides, other single catalysts such as a barium-accelerated copper chromate catalyst or any other suitable catalyst may also be used.

[0034] To reduce the temperature of the turbine exhaust gas to a range suitable for treatment by the catalytic turbine exhaust gas treatment device 104, the system includes a first heat exchanger 108. The first heat exchanger 108 is located at least partially within the turbine exhaust gas discharge section 102 and upstream of the catalytic turbine exhaust gas treatment device 104. The first heat exchanger 108 is configured to remove heat from the turbine exhaust gas passing through the turbine exhaust gas discharge structure 102 by transferring heat through the first heat exchanger 108 to a working fluid (e.g., carbon dioxide) within the first heat exchanger 108. The working fluid passes through a cooling loop, providing continuous (e.g., on demand) cooling to the turbine exhaust gas during operation of the turbine exhaust gas treatment system 100. It should be understood that the turbine exhaust gas may also be cooled for purposes other than improving turbine exhaust gas treatment (e.g., reduction of carbon monoxide and / or nitrogen oxides). For example, the turbine exhaust gas may be cooled to be maintained within a specific temperature range, independently of the temperature range for turbine exhaust gas treatment. This allows turbine exhaust gases to be processed into other products or used for other applications such as controlling heat input to combined cycles.

[0035] The cooled working fluid passes through the first heat exchanger 108 and exits from the first heat exchanger 108 with additional heat. The working fluid exiting the first heat exchanger enters a second heat exchanger 110 located downstream of the first heat exchanger 108. The second heat exchanger 110 is configured to remove the heat acquired in the first heat exchanger 108 from the working fluid. The second heat exchanger 110 may also be a condenser that facilitates the phase change of the gaseous or partially gaseous working fluid discharged from the first heat exchanger 108 to at least partially liquid discharged from the second heat exchanger 110. This facilitates the pumping of the working fluid. Alternatively, the second heat exchanger 110 simply removes heat from the working fluid.

[0036] In some embodiments, the second heat exchanger 110 is an air-cooled heat exchanger, and in other embodiments, the second heat exchanger 110 is a water-cooled heat exchanger. The second heat exchanger 110 includes a fan that passes air over the second heat exchanger 110. The second heat exchanger 110 transfers heat to the atmosphere. In some embodiments, the second heat exchanger 110 is a cooling tower or an evaporative cooler, or may include both.

[0037] The working fluid (e.g., carbon dioxide) that has left the second heat exchanger 110 is received by a pump 112 located downstream of the second heat exchanger 110. The pump 112 is configured to be adapted to drive the working fluid by the cooling loop. The pump 112 may be driven by an electric motor, such as a variable frequency drive motor. The pump 112 is configured to be adapted to pump supercritical carbon dioxide (or any other applicable fluid). In other embodiments (described later in this specification with reference to other drawings), the working fluid may undergo a phase change within the cooling loop, and the pump 112 is configured to be adapted to pump a mixed-phase working fluid. The pump 112 may compress the working fluid or simply pump the working fluid.

[0038] Pump 112 delivers the carbon dioxide working fluid flowing through the cooling loop to the expansion nozzle 114. The expansion nozzle 114 is located downstream of pump 112 and upstream of the first heat exchanger 108. The expansion nozzle 114 is configured to expand the supercritical carbon dioxide working fluid before it enters the first heat exchanger 108, thereby lowering the working fluid temperature. The expansion nozzle 114 can be configured to adapt to change at least some of the phases of the working fluid. Alternatively, the expansion nozzle 114 expands the working fluid without a phase change. The use of the expansion nozzle 114 (compared to a system without the expansion nozzle 114) lowers the working fluid temperature, thus reducing the amount of working fluid required to achieve the target gas temperature at the inlet of the catalytic exhaust gas treatment device 104. The reduced temperature allows for the use of even less working fluid.

[0039] System 100 includes a bypass loop, which includes a bypass nozzle 116. The bypass loop (including the bypass nozzle 116) is configured to be adjustable and optionally allow the working fluid to bypass the expansion nozzle 114. The expansion nozzle 114 can be bypassed using the bypass 116 if sufficient cooling is provided by the second heat exchanger 110 removing heat from the working fluid. For example, the ambient temperature may be low enough that the second heat exchanger 110 can provide sufficient cooling to the turbine exhaust gas. By bypassing the expansion nozzle 114, system 100 can avoid or reduce the pressure loss associated with the use of the expansion nozzle 114. By bypassing the expansion nozzle 114 and avoiding the aforementioned pressure loss, efficiency is improved because the energy required to pump with a pressure-held working fluid is reduced.

[0040] In embodiments including a bypass nozzle 116, the bypass is configured to bypass the expansion nozzle 114 so that the working fluid is instead expanded by the bypass expansion nozzle 116. The bypass nozzle 116 is configured to expand the working fluid to a smaller extent than the expansion nozzle 114. Alternatively, the bypass nozzle 116 may expand the working fluid to a larger extent than the expansion nozzle 114 so that the expansion nozzle 114 is bypassed when additional cooling is required to maintain the exhaust gas temperature within a range suitable for processing, as described herein. In other embodiments, the bypass nozzle 116 can be designed to minimize or reduce the expansion of the fluid passing through the bypass. The bypass valve and expansion nozzle may be functionally a throttle valve or a fixed device and can be operated manually or automatically.

[0041] System 100 further includes a mass inventory management system 118. The mass inventory management system 118 is configured to be adapted to manage the amount of working fluid in a cooling loop including a first heat exchanger 108. The mass inventory management system 118 is configured to be adapted to controllably receive working fluid from downstream of the first heat exchanger 108 in order to manage the amount of working fluid in the cooling loop. The mass inventory management system 100 is also configured to be adapted to add or remove working fluid from the cooling loop.

[0042] The mass inventory management system 118 controls the removal of working fluid from downstream of the first heat exchanger 108 at the takeoff point 120 (e.g., using a controllable valve). The working fluid removed from the cooling loop at the takeoff point 120 passes through a valve toward the pump 122. The pump 122 delivers the working fluid from the takeoff point 120 to the mass inventory management system 118. The working fluid pumped by the pump 122 passes through additional valves on its way to the mass inventory management system 118.

[0043] In the enlarged schematic diagram of the inventory management system shown in Figure 1, the working fluid is received into the first tank 124 of the mass inventory management system 118. The first tank 124 can function as a storage and / or temporary storage tank for the working fluid. The first tank is discharged by the mass inventory pump 126. The working fluid leaving the first tank 124 passes through a check valve located between the first tank 124 and the mass inventory pump 126. The mass inventory pump 126 can be controlled to supply the working fluid to the second tank 128 of the mass inventory management system 118. The second tank 128 can function as a storage tank for the working fluid. The working fluid driven by the pump 126 passes through the check valve and / or additional valves on its way to the second tank 128.

[0044] A controllable valve 130 (which may be, for example, an open / close discrete valve with a generally fixed flow limit, or an active flow control valve with flow control characteristics that allow for a variable flow rate) is located downstream of the second tank 128 to control the addition of working fluid to the cooling loop. The controllable valve 130 is positioned to discharge working fluid from the mass inventory management system 118 into the cooling loop downstream of the second heat exchanger 110 and upstream of the pump 112. The mass inventory management system 118 is also configured to controllably receive working fluid from the cooling loop at a second take-off point 132 located downstream of the pump 112 and upstream of the expansion nozzle 114.

[0045] Next, referring to Figure 1, System 100 includes various sensors used to control the pumping of working fluid to the first heat exchanger 108, pump 112, mass inventory management system 118, etc. In Figure 1, the sensor indicated by the abbreviation "PT" includes a pressure transducer configured to measure the pressure of the working fluid at the relevant point in System 100. The sensor indicated by the abbreviation "TE" includes a temperature element (e.g., thermocouple, thermistor, or similar) configured to measure the temperature of the working fluid or the turbine exhaust gas in System 100. The sensor indicated by the abbreviation "FT" includes a flow transmitter / flow meter (e.g., an anemometer, magnetic flow meter, turbine flow meter, rotometer, spring piston flow meter, etc.). System 100 may also employ additional and / or different types of process measurements to control and / or provide process conditions for data acquisition and system optimization.

[0046] The system 100 is controlled in operation using such sensors and controllable devices (e.g., valves). The system 100 is controlled primarily based on the temperature of the turbine exhaust gas entering the catalytic turbine exhaust gas treatment device 104, which is located within the high-temperature turbine exhaust gas stream and the turbine exhaust gas discharge structure 102. Alternatively, the system may also be controlled based on the temperature of the turbine exhaust gas entering the second catalytic turbine exhaust gas treatment device 106. A setpoint temperature relative to the high-temperature turbine exhaust gas temperature at the catalyst surface (e.g., the inlet of the first catalytic turbine exhaust gas treatment device and / or the second catalytic turbine exhaust gas treatment device) is used to modulate a variable-frequency drive motor that drives the pump 112. This controls the flow rate of the working fluid in the cooling loop, increasing the flow rate when the turbine exhaust gas temperature at the catalyst surface is higher than the setpoint. In an alternative embodiment, the pump 112 is not driven by a variable-frequency drive motor; instead, a flow control valve is located downstream of the pump 112. Such a flow control valve is used to control the flow rate of the working fluid through the cooling loop, and consequently control the temperature of the turbine exhaust gas.

[0047] In some embodiments, the system 100 is controlled by setting the flow rate of the working fluid passing through the bypass valve 116 by controlling the turbine exhaust gas temperature at the surface of the catalytic turbine exhaust gas treatment device 104. When the pump flow rate reaches a predetermined level, the flow rate is modulated through the bypass valve 116, allowing the turbine exhaust gas temperature at the surface of the catalytic turbine exhaust gas treatment device 104 to be controlled.

[0048] In embodiments of system 100 that include a heat exchanger using fans (e.g., a second heat exchanger 110), ON / OFF sequence control of the fans within the heat exchanger may be used to optimize or reduce power consumption and / or for additional temperature control of the working fluid. For example, on days with low ambient temperatures, the fans can be stopped if the working fluid temperature is low enough to achieve the desired turbine exhaust gas temperature at the catalyst surface. Furthermore, in some embodiments, one or more heat exchangers can be bypassed in whole or in part, and the corresponding fans can be switched to low-speed operation. By optionally bypassing one or more ambient air heat exchangers, additional temperature control of the working fluid can be achieved before it enters the heat exchanger 108 located in the high-temperature turbine exhaust gas stream. Bypassing one or more ambient air heat exchangers also reduces power consumption by the pump 112 because it reduces the low total pressure loss for closed working fluid loop flow.

[0049] In applications using CO2 (e.g., system 100 shown in Figure 1), the mass inventory management system 118 can be operated to maintain the CO2 working fluid in a supercritical state (T>32°C, 77ar) or a liquid state throughout the entire working loop. However, it should also be understood that the use of the expansion valve / nozzle 114 allows for the introduction of a two-phase fluid containing steam into the first heat exchanger 108 (e.g., a heat transfer coil in a high-temperature gas stream). For the CO2 working fluid, to ensure that the fluid state at the inlet of the pump 112 is either supercritical (high-temperature environmental conditions, typically T>28°C) or liquid phase (low-temperature environmental conditions, typically T<28°C), the mass inventory management system 118 is controlled based on the temperature at the inlet of the pump 112 and is controlled to manage the pressure at this location by adding or removing mass from the closed cooling loop system.

[0050] Referring to Figures 2 to 8, different embodiments of the system 100 are illustrated and will be described later. Components shown in the same way as those shown in Figure 1 are identical or substantially similar unless otherwise described below. For example, in Figure 2, the first heat exchanger 208 is identical to the first heat exchanger 108 described with reference to Figure 1.

[0051] Referring specifically to Figure 2, a turbine exhaust gas treatment system 200 is shown, which is a variation of the turbine exhaust gas treatment system 100 shown in Figure 1. Instead of using carbon dioxide as the working fluid (as in system 100, for example), system 200 uses thermal oil as the working fluid. System 200 does not include expansion nozzles or bypass nozzles. The thermal oil working fluid does not expand before entering the first heat exchanger 208. System 200 also differs from system 100 in that the second heat exchanger 210 can be optionally bypassed through the control of system 200.

[0052] The systems 200 also differ from each other in that the mass inventory management system 218 includes only a single tank 224. Tank 224 is monitored by a level transmitter (LT), and the amount of hot oil in the cooling loop is controlled to control the entire system 200 as described with reference to Figure 1.

[0053] Referring to Figure 3, a turbine exhaust gas treatment system 300 is shown, which is a variation of the turbine exhaust gas treatment systems 100 and 200 shown in Figures 1 and 2. The turbine exhaust gas treatment system 300 differs from the turbine exhaust gas treatment system 200 shown in Figure 2 in that it uses water as the working fluid. The turbine exhaust gas treatment system 300 also differs in that it does not include a bypass for the second heat exchanger 310.

[0054] Referring to Figure 4, a turbine exhaust gas treatment system 400 is shown, which is a variation of the turbine exhaust gas treatment system 100 shown in Figure 1. The turbine exhaust gas treatment system 400 uses carbon dioxide as the working fluid. The turbine exhaust gas treatment system 400 differs from the turbine exhaust gas treatment system 100 in that it includes a third heat exchanger 434 and additional sensors associated with the third heat exchanger 434 (e.g., a temperature sensor located downstream of the third heat exchanger 434 and upstream of the expansion nozzle 414).

[0055] The third heat exchanger 434 is located downstream of the pump 412 and is configured to remove heat from the working fluid. The third heat exchanger 434 is either air-cooled or water-cooled. The third heat exchanger 434 includes a fan that passes ambient air over or through the third heat exchanger 434, thereby transferring heat from the working fluid to the ambient air. As described in relation to Figure 1, the fan can be controlled to minimize power consumption while maintaining the turbine exhaust gas temperature within a range suitable for processing by a catalytic-based turbine exhaust gas treatment system (e.g., one or more SCR systems). For example, the fan can be controlled based on the temperature of the working fluid upstream of the third heat exchanger 434, the temperature of the working fluid downstream of the third heat exchanger 434, and / or the temperature of the turbine exhaust gas before it enters the first catalytic exhaust gas treatment system and / or the second catalytic exhaust gas treatment system.

[0056] The system 400 also includes a manually operated or actuated bypass valve 436, which is configured to be controllable or selectively allow the working fluid to bypass the third heat exchanger 434. The bypass 436 is controlled based on one or more inputs described immediately prior to the control of the fan of the third heat exchanger 434 and / or other elements described in the prior embodiments. The third heat exchanger 434 may be bypassed or partially bypassed to improve the efficiency of the system 434 by reducing the power consumption of the associated fan and / or reducing the total pressure loss in the cooling loop. The third heat exchanger 434 is bypassed only if an appropriate turbine exhaust gas temperature can be maintained without using the third heat exchanger 434.

[0057] Referring to Figure 5, a turbine exhaust gas treatment system 500 is illustrated, which is a modified version of the turbine exhaust gas treatment system 200 shown in Figure 2. This includes a third heat exchanger 534 and a bypass 536 of the type described in relation to Figure 4. The turbine exhaust gas treatment system 500 differs from system 200 in that it includes a third heat exchanger 534. The turbine exhaust gas treatment system 500 differs from system 400 primarily in that its working fluid is hot oil. System 500 has the advantages of systems 200 and 400 (like system 400), but uses hot oil instead of carbon dioxide.

[0058] Referring to Figure 6, a turbine exhaust gas treatment system 600 is shown, which is a modified version of the turbine exhaust gas treatment system 300 shown in Figure 3, and which includes a third heat exchanger 634 and a bypass 636 of the type described in relation to Figure 4. The turbine exhaust gas treatment system 600 differs from system 300 in that it includes a third heat exchanger 634. The turbine exhaust gas treatment system 600 differs from system 400 mainly in that the working fluid is water. System 600 has the advantages of systems 300 and 400 (like system 400), but uses water instead of carbon dioxide.

[0059] Referring to Figure 7, a turbine exhaust gas treatment system 700 is shown, which is a modified version of the turbine exhaust gas treatment system 100 shown in Figure 1. The turbine exhaust gas treatment system 700 differs from system 100 primarily in that it includes a fourth heat exchanger 738. The fourth heat exchanger 738 is at least partially located within the turbine exhaust gas discharge section 702, downstream of the catalytic exhaust gas treatment device 704. The fourth heat exchanger 738 is also located upstream of the second catalytic turbine exhaust gas treatment device 706. The fourth heat exchanger 738 is configured to remove heat from the turbine exhaust gas passing through the turbine exhaust gas discharge structure 102 and transfer heat to the working fluid (e.g., carbon dioxide) passing through the fourth heat exchanger 738. The fourth heat exchanger is located downstream of the pump 712 and upstream of the second heat exchanger 710 within the cooling loop. The fourth heat exchanger 738 is also located downstream of the expansion nozzle 714.

[0060] The first heat exchanger 708 and the fourth heat exchanger 738 are arranged in a parallel loop so that the working fluid is branched, with separate portions of the working fluid passing through the first heat exchanger 708 and the fourth heat exchanger 738, respectively. After leaving the first heat exchanger 708 and the fourth heat exchanger 738, the separate portions of the working fluid are merged to form a single flow. The combined output is received by the second heat exchanger 710. The fourth heat exchanger 738 can be preferentially supplied to maintain the turbine exhaust gas temperature range within the operating parameters of the second catalytic exhaust gas treatment device 706 and can be adapted to be removed from the working fluid before it reaches the first heat exchanger 708. In other words, the working fluid flow is branched upstream of the first heat exchanger 708 and the fourth heat exchanger 738 so that a portion of the working fluid is supplied to the first heat exchanger 708 and the separated portion is supplied to the fourth heat exchanger 738. This configuration (for example, in a parallel configuration rather than a series configuration where a single stream of working fluid is heated sequentially) supplies separate streams of cooled working fluid to two heat exchangers, respectively. The length and configuration of the branch piping are adapted and configured to preferentially supply the fourth heat exchanger 738. Alternatively, the heat exchangers (i.e., 708 and 738) may be in a series configuration where the flow of the same coolant (e.g., CO2) passes through each heat exchanger, and the direction of the fluid flow may be parallel to or counter-flowing to the hot turbine exhaust gas stream. In other words, either of the two heat exchangers may be preferentially supplied, the heat exchangers may be supplied in series, or the heat exchangers may be supplied in parallel.

[0061] Advantageously, the use of two heat exchangers to independently cool the turbine exhaust gas before different catalytic treatment devices allows for independent control of the turbine exhaust gas temperature before each independent treatment device. This makes it possible to maintain the turbine exhaust gas temperature within a first range for treatment by the first catalytic treatment device 704 (e.g., carbon monoxide treatment). The turbine exhaust gas temperature is then independently maintained within a lower second temperature range for treatment by the second catalytic treatment device 706 (e.g., SCR for nitrogen oxide treatment).

[0062] The fourth heat exchanger 738 and the first heat exchanger 708 can be controlled independently based on the working fluid temperature monitored at the outlets of both the first heat exchanger 708 and the fourth heat exchanger 738. The flow of working fluid to the first heat exchanger 708 and the fourth heat exchanger 738 can be controlled through a temperature control valve (e.g., control valve 740) located in piping converted into a controlled coil. Two temperature control valves (one for each heat exchanger) or a single control valve 740 may be used to control the flow rate of working fluid to the fourth heat exchanger 738, with the remainder of the working fluid being supplied to the first heat exchanger 708 located downstream of the fourth heat exchanger 738.

[0063] The system 700 includes a mass inventory management system 718 configured to controllly receive the working fluid downstream of the fourth heat exchanger 738 at the extraction point 742 (for example, using a controllable valve). Otherwise, the mass inventory system 718 operates as described above.

[0064] Referring to Figure 8, a turbine exhaust gas treatment system 800 is shown, which is a variation of the turbine exhaust gas treatment system 700 shown in Figure 7. The turbine exhaust gas treatment system 800 differs from system 700 mainly in that it further includes a third heat exchanger 834 and a bypass 836 of the type illustrated and described in relation to Figure 4. This system 800 combines the advantages of the fourth heat exchanger 838 and the third heat exchanger 834 described above.

[0065] In general, the use of the fourth heat exchanger is illustrated only in Figures 7 and 8, but it should be understood that the fourth heat exchanger may also be used in any system described herein.

[0066] Referring to Figures 9A to 9C, multiple independent cooling loops can cool the turbine exhaust gas within the turbine exhaust gas discharge structure 902. Each independent cooling loop 950, 950', 950” (shown as a dotted line) cools the turbine exhaust gas using an independent heat exchanger within the turbine exhaust gas discharge structure 902. Independent cooling loop 950 cools the turbine exhaust gas by supplying cooled working fluid to the first heat exchanger 908, receiving heated working fluid from the first heat exchanger 908, and cooling the heated working fluid before supplying it to the first heat exchanger 908. Independent cooling loop 950 uses solid piping to provide fluid communication and control of the working fluid between the other components of the cooling loop 950. The independent cooling loop 950' further includes conduits, valves, or similar components. The independent cooling loop 950' cools the turbine exhaust gas discharge structure 902. The independent cooling loop 950' cools the turbine exhaust gas by supplying cooled working fluid to the fourth heat exchanger 938, receiving heated working fluid from the fourth heat exchanger 938, and cooling the heated working fluid before supplying it to the fourth heat exchanger 938. The independent cooling loop 950' further includes piping, conduits, valves, etc., shown by solid lines, to provide fluid communication and control of the working fluid between the other components of the cooling loop 950'.

[0067] Each independent cooling loop 950 includes at least a second heat exchanger 910 and a pump 912. Similarly, each independent cooling loop 950' includes at least a second heat exchanger 910' and a pump 912'. Each independent cooling loop 950, 950' similarly includes heat exchangers (first heat exchanger 908 and fourth heat exchanger 938) located within the turbine exhaust gas discharge structure 902. Each independent cooling loop 950, 950' may include other equipment of the type described in relation to any embodiment disclosed herein. For example, each independent cooling loop 950, 950' may include expansion nozzles 914, 914', bypass nozzles 916, 916', mass inventory systems 918, 918', pumps 922, 922' for extracting and supplying the mass inventory systems, etc. Each independent cooling loop 950, 950' may also include a third heat exchanger of the type described in relation to Figures 4-6 and 8. The mass inventory systems 918, 918' may be of the type described in relation to the different embodiments disclosed herein.

[0068] It should also be understood that the system 900, including the independent cooling loops 950, 950', can use any working fluid described herein (e.g., carbon dioxide, water, thermal fluid / oil, etc.). Since the independent cooling loops 950, 950' are independent structures, each having its own independent mass inventory system 918, 918', the independent cooling loops 950, 950' can use different working fluids. For example, the independent cooling loop 950 may use water as its working fluid, and the independent cooling loop 950' may use carbon dioxide as its working fluid. Any combination of working fluids can be used.

[0069] Referring to Figure 9B, system 900 includes independent cooling loops 950, 950' but has a shared mass inventory system 918. This embodiment is substantially similar to that described with respect to Figure 9A, but differs substantially in that the independent cooling loops 950, 950' share a single mass inventory system 918 and the independent cooling loops share a working fluid. The mass inventory system 918 is any configuration described herein in relation to other embodiments and drawings, and appropriate modifications can be made to double the inputs and outputs to accommodate the two separate cooling loops 950, 950'. The mass inventory system 918 is adapted and configured to transmit the working fluid between the separate cooling loops 950, 950'.

[0070] Referring to Figure 9C, the type of system 900 described herein includes any number of catalytic turbine exhaust gas treatment devices and any number of separate cooling loops 950, 950', 950''. For example, and as shown in Figure 9C, the system 900 includes three catalytic turbine exhaust gas treatment devices. A first heat exchanger 908 is configured to work in conjunction with a separate cooling loop 950 to cool turbine exhaust gas within a turbine exhaust gas discharge structure upstream of the first catalytic turbine exhaust gas treatment device 904. A fourth heat exchanger 938 works in conjunction with a separate cooling loop 950 to cool turbine exhaust gas upstream of the second catalytic turbine exhaust gas treatment device 906. A sixth heat exchanger 952 works in conjunction with a separate cooling loop 950'' to cool turbine exhaust gas upstream of the third catalytic turbine exhaust gas treatment device 954. In this embodiment, each isolated cooling loop 950, 950', 950'' includes a separate mass inventory system, and each loop can use a different working fluid. It should be understood that three or more isolated cooling loops can be used with the type of single mass inventory system described in relation to Figure 9B. It should also be understood that three or more catalytic turbine exhaust gas treatment systems can be used in a system with a single cooling loop having parallel branches supplying each isolated heat exchanger (for example, as shown in at least Figure 7).

[0071] Referring to Figures 1 to 9C, the system described herein includes several heat exchangers as generally described. It should be understood that the heat exchangers described herein may be any suitable configuration. For example, any or all of the heat exchangers may be a parallel-flow heat exchanger, a cross-flow heat exchanger, a counter-flow heat exchanger, or any other suitable heat exchanger.

[0072] It should be understood that the systems described herein include multiple catalytic turbine exhaust gas treatment systems. However, in alternative embodiments, one or more catalytic turbine exhaust gas treatment systems may be replaced with different turbine exhaust gas treatment systems, but are not limited to non-catalytic treatment systems. The non-catalytic treatment system may include a membrane, a urea injection system, or other system configured to remove one or more compounds from the turbine exhaust gas. For example, the membrane may be a synthetic membrane made of a polymer, cellulose acetate, or ceramic material. Any suitable material may be used for the membrane, and the membrane may be configured to remove carbon monoxide, nitrogen oxides, sulfur dioxide, hexane, carbon dioxide, butane, methane, benzene, or other compounds.

[0073] Next, referring to Figures 1 to 9C, the system described herein provides the advantages described herein for improving turbine exhaust gas treatment. The system provides increased control over the temperature of the turbine exhaust gas, ensuring that the turbine exhaust gas is treated. The system described herein also provides increased efficiency through control of various components of the cooling subsystem used for cooling the turbine exhaust gas treatment. Furthermore, the system described herein does not use or does not include a forced draft fan for mixing the turbine exhaust gas with air, using a working fluid cooling system and corresponding technology (e.g., refrigeration or other common cooling methods), and does not require the injection of water into the high-temperature turbine exhaust gas stream. This not only improves efficiency by eliminating the power consumption associated with forced draft fans, but also reduces the negative effects (e.g., corrosion) that may result from water injection. Similarly, the system described herein does not use or include an induced draft fan. Such a fan is unnecessary because the use of the cooling system described herein does not require additional upstream air to cool the turbine exhaust gas. The system described herein exhausts the treated turbine exhaust gas directly into the atmosphere.

[0074] Figure 10 shows a further embodiment of the turbine exhaust gas treatment system 1000 of the present disclosure. The embodiment of Figure 10 also includes the exhaust gas discharge structure 102 shown in Figure 1. Similar to the embodiment of Figure 1, the exhaust gas discharge structure 102 is configured to receive exhaust gas from a source such as a gas turbine and to allow the exhaust gas to pass through the exhaust gas discharge structure 102.

[0075] As in the embodiment shown in Figure 1, the exhaust gas passing through the exhaust gas discharge structure 102 of Figure 10 passes through the catalytic exhaust gas treatment device 104. The system 1000 shown in Figure 10 includes a second catalytic exhaust gas treatment device 106. The system 1000 shown in Figure 10 further includes a first heat exchanger 108A located at least partially within the exhaust gas discharge structure 102 and upstream of the catalytic exhaust gas treatment device 104. Similar to the embodiment shown in Figure 1, the first heat exchanger 108A is configured to remove heat from the exhaust gas passing through the exhaust gas discharge structure 102 by transferring heat within the first heat exchanger 108A from a working fluid passing through the first heat exchanger 108A. The working fluid may be carbon dioxide or any other fluid used in the heat exchanger. The working fluid passes through a cooling loop to continuously cool the exhaust gas while the system 1000 is in operation. Similar to the embodiments described above, the exhaust gas may also be cooled for purposes other than improving exhaust gas treatment. For example, the exhaust gas may be cooled to keep it within a specific temperature range, regardless of the temperature range for exhaust gas treatment.

[0076] The cooled working fluid passing through the first heat exchanger 108A leaves the first heat exchanger 108A with additional heat. The working fluid leaving the first heat exchanger enters a second heat exchanger 1002 located downstream of the first heat exchanger 108A. The second heat exchanger 1002 is configured to remove the heat acquired in the first heat exchanger 108A from the working fluid. In the embodiment shown in Figure 10, the second heat exchanger 1002 is a heat exchanger within a thermal energy storage system (TESS) or mechanism 1004. The thermal energy storage system 1004 may be a sand-bed heat storage media type system or other type system. The thermal energy storage system 1004 is configured to remove the heat acquired in the first heat exchanger 108A from the working fluid and store the removed heat in the heat storage media. The stored heat is recovered and used for additional steam generation or water heating within the cycle or for other process needs that use heat / energy when increased power or power plant flexibility is required. The second heat exchanger 1002 of the thermal energy storage system 1004 is part of a cooling loop located outside the exhaust gas discharge structure 102 and outside the exhaust gas passing through the exhaust gas discharge structure.

[0077] As shown in Figure 10, the cooling loop consists of conduits 1006, 1008 or other types of fluid transport means extending from the first heat exchanger 108A to the second heat exchanger 1002 of the thermal energy storage system 1004, and then returning from the second heat exchanger 1002 to the first heat exchanger 108A. Pump 1010 is located downstream of the thermal energy storage system 1004. Pump 1010 is in fluid communication with the thermal energy storage system 1004 and is configured to circulate the working fluid through the cooling loop defined by the first heat exchanger 108A, conduits 1006, 1008, and the thermal energy storage system 1004. Pump 1010 is part of the cooling loop.

[0078] The first heat exchanger 108A is positioned at the inlet of the exhaust gas discharge structure 102 and supplies a flow of high-temperature exhaust gas to the exhaust gas discharge structure 102, supporting a rapid and unrestricted startup of the gas turbine. Since the first heat exchanger 108A can be controlled to reduce or limit the heat of the exhaust gas from the gas turbine entering the exhaust gas discharge structure 102, the exhaust gas discharge structure 102 does not need to be configured with limits based on the amount of heat of the turbine exhaust gas entering the exhaust gas discharge structure 102. Furthermore, because the first heat exchanger 108A is controlled to reduce or limit the heat of the exhaust gas from the gas turbine entering the exhaust gas discharge structure 102, the gas turbine can quickly reach its maximum power load while the high-temperature exhaust gas from the turbine enters the exhaust gas discharge structure 102 while being controlledly cooled by the first heat exchanger 108A. The operation of the pump 1010 can be adjusted to regulate the flow rate of the cooling fluid passing through the first heat exchanger 108A, thereby regulating the heat of the exhaust gas that passes through the first heat exchanger 108A and enters the exhaust gas discharge structure 102.

[0079] Figure 11 shows a further embodiment of the turbine exhaust gas treatment system 1014. Figure 11 shows a system 1014 similar to system 1000 in Figure 10, except that the exhaust gas discharge structure 102 shown in Figure 10 is replaced by a heat recovery steam generator (HRSG) 1016. The heat recovery steam generator 1016 may be of the type described, for example, in U.S. Patent No. 6,508,206 ("206 Patent") or U.S. Patent No. 10,108,086 ("086 Patent"), both of which are incorporated herein by reference in their entirety. The heat recovery steam generator 1016 is configured to receive high-temperature exhaust gas G from a source such as a gas turbine and to pass the exhaust gas G through the heat recovery steam generator 1016. The heat recovery steam generator 1016 shown in Figure 11, like the heat recovery steam generators shown in Figures 12 to 15, includes common components typically used in heat recovery steam generators as described in the aforementioned referenced patents. Typical components of the heat recovery steam generator 1016 shown in Figure 11 include a housing 1018 with internal ducts, an upstream end 1020, and a downstream end 1022 on the opposite side. The upstream end 1020 is connected to a gas turbine, and exhaust gas G discharged by the gas turbine flows from left to right as shown in Figure 11 into the upstream end 1020 of the heat recovery steam generator housing 1018 and flows through the ducts of the heat recovery steam generator 1016. The downstream end 1022 or discharge end of the heat recovery steam generator 1016 is connected to a chimney 1024 that leads the exhaust gas into the atmosphere, in fluid communication. In the exemplary system shown in Figure 11, the heat recovery steam generator 1016 includes a superheater 1026, an evaporator 1028, an economizer 1030, and a feedwater heater illustrated in 20 of the 206 patent, which are arranged basically from left to right in order from the upstream end 1020 to the downstream end 1022 of the housing 1018. The feedwater flows from the feedwater heater to the economizer 1030, and from there to the evaporator 1028, which converts the feedwater into saturated steam. The superheater 1026, shown as a high-pressure superheater (HP SH2), converts the saturated steam into superheated steam, which flows into the steam turbine to drive the steam turbine.The heat recovery steam generator 1016 generates steam from the heat of the exhaust gas, supplies the steam to a steam turbine, and drives the steam turbine in a conventional manner. The heat recovery steam generator 1016 shown in Figure 11 schematically illustrates other components of HRSGs known in the art, such as a further high-pressure superheater HP SH1, reheaters (RH1 and RH2), a low-pressure economizer (LP ECO), and a low-pressure evaporator (LP EVAP), and it should be understood that 1028 represents the high-pressure evaporator (HP EVAP). Figure 11 is merely an example of a heat recovery steam generator that can employ the heat storage concept of this disclosure, and the heat storage concept of this disclosure is not limited to the heat recovery steam generator shown in Figure 11. For example, the heat storage concept of this disclosure can also be used in the heat recovery steam generators shown in Figures 12 to 15. The system shown in Figure 11 also includes a second heat exchanger 1034 of the thermal energy storage system 1036 and a first heat exchanger 1032 connected to the cooling loop. The first heat exchanger 1032 is at least partially located within the inlet of the heat recovery steam generator 1016. Similar to the embodiments described above, the first heat exchanger 1032 is configured to remove heat from the exhaust gas G passing through the heat recovery steam generator 1016 by transferring heat to a working fluid passing through the first heat exchanger 1032. The working fluid may be carbon dioxide or any other fluid. The working fluid passes through a cooling loop to continuously cool the exhaust gas while the system 1014 is operating. Similar to the embodiments described above, the exhaust gas may be cooled for various purposes. In particular, it may be cooled to keep the exhaust gas within a predetermined temperature range below a temperature that could damage any of the components of the heat recovery steam generator 1016. Similar to the embodiment shown in Figure 10, the cooled working fluid passes through the first heat exchanger 1032 and then leaves the first heat exchanger with additional heat. The working fluid leaves the first heat exchanger 1032 and is led through the first conduit 1038 to a second heat exchanger 1034 located downstream of the first heat exchanger 1032. The second heat exchanger 1034 is configured to remove the heat acquired in the first heat exchanger 1032 from the working fluid. Similar to the embodiment shown in Figure 10, the second heat exchanger 1034 is a heat exchanger located within a thermal energy storage system 1036.The thermal energy storage system 1036 may be a sand-bed thermal storage medium type system or another type system. The thermal energy storage system 1036 is configured to remove heat acquired in the first heat exchanger 1032 from the working fluid and store the removed heat in the thermal storage medium. The stored heat can be recovered and used for additional steam generation or water heating in the cycle or other process requests where the stored energy / heat is available, when increased power or flexibility of the power plant is required. The working fluid leaves the second heat exchanger 1034 and returns to the first heat exchanger 1032 through the second conduit 1040 to complete the cooling loop. As shown in Figure 11, an air-cooled or water-cooled heat exchanger 1042 is located downstream of the second heat exchanger 1034 and upstream of the first heat exchanger 1032 in the cooling loop. The air-cooled or water-cooled heat exchanger 1042 can be operated to further cool the working fluid before it is transferred to the first heat exchanger 1032. The cooling loop shown in Figure 11 also includes a pump 1044. The pump 1044 circulates the cooling fluid through the cooling loop between the first heat exchanger 1032 and the second heat exchanger 1034 of the thermal energy storage system 1036.

[0080] A further feature of this system, shown in Figure 11, is that as the thermal energy medium of the thermal energy storage system 1036 is heated, the working fluid at the outlet of the second heat exchanger 1034 of the thermal energy storage system 1036 is guided to the heat exchanger of the heat recovery steam generator 1016, for example, a low-pressure evaporator or a high-pressure evaporator, as shown in Figure 11, thereby preheating these components of the heat recovery steam generator 1016.

[0081] A further feature of the stem shown in Figure 11 is that the second heat exchanger 1034 of the thermal energy storage system 1036 functions as a charging heat exchanger 1034. The charging heat exchanger 1034 charges or adds heat to the thermal energy storage medium of the thermal energy storage system 1036. Additionally, a discharge heat exchanger 1046 is present in the heat storage medium of the thermal energy storage system 1036. The heat stored in the thermal energy storage medium of the thermal energy storage system 1036 is discharged to the discharge heat exchanger 1046. The working fluid from the heat recovery steam generator 1016 flows, for example, from the economizer, flows from the heat recovery steam generator 1016 to the thermal energy storage system 1036, and passes through the discharge heat exchanger 1046. As the working fluid passes through the discharge heat exchanger 1046, the working fluid acquires the heat discharged from the heat storage medium of the thermal energy storage system 1036. The heated working fluid flows from the exhaust heat exchanger 1046 of the thermal energy storage system 1036 and is led to the heat recovery steam generator 1016, and is then led to the components of the heat recovery steam generator 1016, for example, to preheat the low-pressure evaporator or high-pressure evaporator of the heat recovery steam generator, as shown in Figure 11.

[0082] Figure 12 shows a further embodiment of the turbine exhaust gas treatment system 1048. The system shown in Figure 12 is substantially identical to the system shown in Figure 11, and Figure 12 shows that the first heat exchanger 1050, shown by a solid line, is located at a first position at the inlet of the heat recovery steam generator 1052, and the first heat exchanger 1050, shown by a dotted line, is located at a second position at the inlet inside the heat recovery steam generator 1052. Providing the option of locating the first heat exchanger 1050 at either the first or second position inside the heat recovery steam generator 1052 provides a further means of regulating the heat of the gas turbine exhaust gas entering the heat recovery steam generator 1052. As shown in Figure 12, the first position of the first heat exchanger 1050, shown by a solid line, has greater vertical space, which makes it possible to provide a first heat exchanger 1050 that is vertically larger at the first position than the first heat exchanger 1050 shown by a dotted line at the second position. Regardless of whether the first heat exchanger 1050 is located in a first or second position within the heat recovery steam generator 1052, it is connected to the second heat exchanger 1054 of the thermal energy storage system 1048 and to the cooling loop.

[0083] Figure 13 shows a further embodiment of the exhaust gas treatment system 1058, which uses a pair of cooling coils positioned at different locations along the flow path within the heat recovery steam generator 1060. In Figure 13, the first heat exchanger 1062 is located at the inlet of the heat recovery steam generator 1060, and the second heat exchanger 1064 is located further downstream within the heat recovery steam generator 1060 between the reheater (RH1) and the high-pressure superheater (HP SH1). Both the first heat exchanger 1062 and the second heat exchanger 1064 are connected to a cooling loop with a third heat exchanger 1066 of the thermal energy storage system 1068.

[0084] Figure 14 shows a turbine exhaust gas treatment system 1070 similar to that in Figure 13. The system in Figure 14 also includes a heat recovery steam generator 1072, which has a first heat exchanger 1074 and a second heat exchanger 1076 spaced apart along the exhaust gas flow path passing through the heat recovery steam generator 1072. Figure 14 also shows the catalyst of a selective catalytic reduction (SCR). The second heat exchanger 1076 is located directly upstream of the SCR and directly downstream of the high-pressure evaporator (HP EVAP). The first heat exchanger 1074 and the second heat exchanger 1076 are also connected to a third heat exchanger 1078 of a thermal energy storage system 1080 and a cooling loop. The system shown in Figure 14 also differs from the system shown in Figure 13 in that a series of valves 1082a, 1082b, and 1082c are provided in the cooling loop. A series of valves 1082a, 1082b, and 1082c can be selectively operated to either include the second heat exchanger 1076 in the cooling loop or exclude it from the cooling loop. For example, by closing valve 1082a and opening valves 1082b and 1082c, the second heat exchanger 1076 can be connected in series with the first heat exchanger 1074 and the third heat exchanger 1078 within the cooling loop.

[0085] In this cooling loop configuration, the fluid passing through the first heat exchanger 1074 enters the heat recovery steam generator 1072 and receives heat from the flow of turbine exhaust gas G passing through the first heat exchanger 1074. The heated fluid then passes through the second heat exchanger 1076 and flows through the components of the heat recovery steam generator 1072 located upstream of the second heat exchanger 1076, releasing heat into the cooled exhaust gas flow. The exhaust gas flow, reheated by the second heat exchanger 1076, then passes through the catalytic converter (SCR). The reheating of the exhaust gas flow in the second heat exchanger 1076 before the exhaust gas passes through the catalytic converter (SCR) allows for faster heating of the catalytic converter (SCR). Thus, in the cooling loop shown in Figure 14, high-temperature turbine exhaust gas is received at the inlet of the heat recovery steam generator 1072, which enables rapid starting of the gas turbine. The received high-temperature exhaust gas heats the working fluid in the first heat exchanger 1074. The heated working fluid is transferred from the first heat exchanger 1074 to the second heat exchanger 1076, which is either adjacent to or upstream of the catalytic converter (SCR). The heated working fluid passing through the second heat exchanger 1076 reheats the exhaust gas flow that passes through the second heat exchanger 1076 and then through the catalytic converter (SCR). The reheated exhaust gas passing through the catalytic converter (SCR) raises the temperature of the catalytic converter (SCR), allowing the exhaust control to activate more quickly than in the absence of a cooling loop.

[0086] Alternatively, valve 1082a is opened and valves 1082b and 1082c are closed to directly connect the first heat exchanger 1074 to the third heat exchanger 1078 and exclude the second heat exchanger 1076 from the cooling loop. Since the exchanger coil 1074 can be fluidly connected to the SCR, the high-temperature fluid from the heat exchanger 1074 can flow rapidly into the SCR, rapidly heating the catalyst and reducing exhaust gas emissions. The second heat exchanger coil 1076 is located directly upstream of the selective catalytic reduction (SCR) in the heat recovery steam generator 1072. At this position, the second heat exchanger 1076 can be operated to cool the exhaust gas passing through the heat recovery steam generator 1072 before it passes through the SCR. This allows the second heat exchanger 1076 to control and reduce the exhaust gas temperature within the SCR's processing range, optimizing the catalytic reaction in the exhaust gas treatment. Figure 15 shows a further embodiment of system 1084 for turbine exhaust gas treatment, similar to the system described above. The system shown in Figure 15 demonstrates that a cooling loop, including a thermal energy storage system 1086, can be selectively connected to various components of the heat recovery steam generator 1088. The cooling loop includes a series of valve assemblies 1090, which can be selectively operated to connect the thermal energy storage system 1086 to various components of the heat recovery steam generator 1088, or to disconnect it from various components of the heat recovery steam generator 1088, as shown in Figure 15.

[0087] Each embodiment of the system for treating turbine exhaust gas G and controlling the temperature of turbine exhaust gas flowing into the heat recovery steam generator, as described above with reference to Figures 11 to 15, supports the rapid and unrestricted starting of the gas turbine communicating with the heat recovery steam generator and at least relaxes, without imposing, any limitations on the operating speed of the gas turbine from no-load to pre-load conditions. These configurations enable an extended operating range for the gas turbine and the combined cycle by allowing for sustained lower operating ranges. The turbine exhaust gas G treatment systems shown in the embodiments of Figures 11 to 15 each provide at least one inlet or first heat exchanger control coil at the inlet of the heat recovery steam generator. The first heat exchanger is part of a cooling loop and can regulate the heat of the turbine exhaust gas G by cooling the turbine exhaust gas G entering the heat recovery steam generator, thereby controlling the heating process of the heat recovery steam generator by controlling the flow rate of the cooling fluid passing through the inlet or first heat exchanger control coil. The embodiments of Figures 11 to 15 enable cooling of the gas flowing into the HRSG without the use of a superheat reducer, thereby reducing energy consumption.

[0088] The additional advantages of the system described herein are as follows: The system described herein can eliminate or reduce the complexity of flow regulators, which are often required in turbine exhaust streams to ensure good flow distribution of high-temperature turbine exhaust gas in terms of catalytic systems. Such flow regulators have the problem of being excessively costly to supply / install due to their operating requirements, as they are under the influence of high turbine exhaust gas temperatures and highly turbulent turbine exhaust gas flow. The system described herein can eliminate or reduce such flow regulators as a result of the turbine exhaust gas being controlledly cooled and / or the use of dilution air being eliminated. That is, since the system described herein does not use dilution air, a flow regulator for adequately mixing dilution air with the turbine exhaust gas is unnecessary. Additionally or alternatively, heat exchangers placed within the turbine exhaust gas discharge structure can adequately disperse the flow of the turbine exhaust gas.

[0089] Furthermore, it should be understood that the systems described herein transfer heat from turbine exhaust gases to multiple locations / applications, making the energy available for other heating applications and / or power generation. The heated working fluid can heat other process fluids through a heat exchanger. The heated working fluid can drive mechanical devices (e.g., pumps). In addition, the heated working fluid can be expanded to drive a turbine, which in turn can drive an electric generator.

[0090] Since various modifications can be made to the above structure and method without departing from the broad scope of this disclosure, all matters included in the above description or shown in the accompanying drawings should be interpreted as illustrative rather than restrictive.

Claims

1. A turbine exhaust gas treatment system, wherein the system is The exhaust gas discharge structure is configured to receive exhaust gas from a turbine and allow the exhaust gas to pass through an exhaust gas discharge structure, As a catalytic exhaust gas treatment device at least partially disposed within the exhaust gas discharge structure, the catalytic exhaust gas treatment device is configured to process the at least one component of the turbine exhaust gas through a catalytic reaction between a catalyst held within the catalytic exhaust gas treatment device and at least one component of the exhaust gas, A first heat exchanger, at least partially located within the exhaust gas treatment structure and upstream of the catalytic exhaust gas treatment device, is configured to remove heat from exhaust gas passing through the exhaust gas discharge structure by transferring heat to a working fluid passing through the first heat exchanger, the working fluid passing through a cooling loop to provide continuous cooling to the exhaust gas during operation of the exhaust gas treatment system, and the first heat exchanger is part of the cooling loop, In the cooling loop, the second heat exchanger is located downstream of the first heat exchanger and is in fluid communication with the first heat exchanger. The second heat exchanger is a heat exchanger in a thermal energy storage system configured to remove heat acquired by the first heat exchanger from the working fluid and store the removed heat in a heat storage medium. The second heat exchanger is part of the cooling loop and is located outside the exhaust gas discharge structure and outside the exhaust gas passing through the exhaust gas discharge structure. In the cooling loop, the pump is positioned downstream of the thermal energy storage system and is in fluid communication with the thermal energy storage mechanism. The pump is configured to circulate the working fluid through the cooling loop, and the pump is part of the cooling loop. A system that includes this.

2. The system according to claim 1, wherein the thermal energy storage mechanism further comprises an energy storage container having a heat storage medium.

3. The system according to claim 2, further comprising the heat storage medium being sand.

4. The energy storage container has a filling heat exchanger and a discharge heat exchanger, The system according to claim 3, further comprising the fact that the packed heat exchanger is the second heat exchanger.

5. The system according to claim 4, further comprising the fact that the filled heat exchanger and the exhaust heat exchanger are in heat transfer communication with the heat storage medium contained in the energy storage container.

6. A turbine exhaust gas treatment system, wherein the system is The exhaust gas discharge structure is configured to receive exhaust gas from a turbine and allow the exhaust gas to pass through an exhaust gas discharge structure, As an exhaust gas heat recovery device arranged within the exhaust gas discharge structure, the exhaust gas heat recovery device is configured to recover heat from the exhaust gas passing through the exhaust gas discharge structure through heat transfer between the exhaust gas and a first working fluid circulating through the exhaust gas heat recovery device, As a first heat exchanger located at least partially within the exhaust gas discharge structure and upstream of the exhaust gas heat recovery device, the first heat exchanger is configured to remove heat from the exhaust gas before it passes through the exhaust gas discharge structure by transferring heat to a second working fluid passing through the first heat exchanger, the second working fluid passing through a cooling loop to continuously provide cooling to the exhaust gas during the operation of the system for processing turbine exhaust gas and to control the heat of the exhaust gas, and the first heat exchanger is part of the cooling loop, In the cooling loop, the second heat exchanger is located downstream of the first heat exchanger and is in fluid communication with the first heat exchanger. The second heat exchanger is a heat exchanger of a thermal energy storage mechanism configured to remove heat acquired by the first heat exchanger from the second working fluid and store the removed heat in a heat storage medium. The second heat exchanger is part of the cooling loop and is located outside the exhaust gas discharge structure and outside the exhaust gas passing through the exhaust gas discharge structure. Displaced downstream of the second heat exchanger of the thermal energy storage mechanism, and configured as a pump that is in fluid communication with the second heat exchanger of the thermal energy storage mechanism, the pump is configured to circulate the second working fluid through the cooling loop, and the pump is part of the cooling loop, A system that includes this.

7. The system according to claim 6, further comprising an energy storage container having a heat storage medium as the thermal energy storage mechanism.

8. The system according to claim 7, further comprising the heat storage medium being sand.

9. The energy storage container has a filling heat exchanger and a discharge heat exchanger, The system according to claim 8, further comprising the fact that the packed heat exchanger is the second heat exchanger located in the cooling loop together with the first heat exchanger.

10. The system according to claim 9, further comprising the fact that the packed heat exchanger and the discharge heat exchanger are in heat transfer communication with a sand thermal energy storage medium.

11. The system according to claim 10, further comprising the exhaust heat exchanger being in fluid communication with the exhaust gas heat recovery device located downstream of the first heat exchanger.

12. The third heat exchanger is located at least partially within the exhaust gas discharge structure and downstream of the exhaust gas heat recovery device, and the exhaust gas heat recovery device is located between the first and third heat exchangers, the third heat exchanger is configured to remove heat from the exhaust gas passing through the exhaust gas discharge structure by transferring heat to the second working fluid passing through the third heat exchanger, the second working fluid passing through a cooling loop to provide continuous cooling to the exhaust gas during operation of the system for processing turbine exhaust gas, and the third heat exchanger is part of the cooling loop, It further includes, The system according to claim 6, wherein the second heat exchanger of the thermal energy storage mechanism is located downstream of the first and third heat exchangers in the cooling loop, is in fluid communication with the first and third heat exchangers, and is configured to remove heat acquired by the first and third heat exchangers from the second working fluid and store the removed heat in the heat storage medium.

13. The system according to claim 6, further comprising the exhaust gas discharge structure being a heat recovery steam generator.

14. A turbine exhaust gas treatment system, wherein the system is The heat recovery steam generator is configured to receive exhaust gas from a turbine and pass the exhaust gas through the heat recovery steam generator, As an exhaust gas heat recovery device arranged within the heat recovery steam generator, the exhaust gas heat recovery device is configured to recover heat from the exhaust gas passing through the heat recovery steam generator through heat transfer between the exhaust gas and a first working fluid circulating through the exhaust gas heat recovery device, As a first heat exchanger located at least partially within the heat recovery steam generator and upstream of the exhaust gas heat recovery device, the first heat exchanger is configured to remove heat from the exhaust gas before it passes through the heat recovery steam generator by transferring heat to a second working fluid passing through the first heat exchanger, the second working fluid passing through a cooling loop to provide continuous cooling to the exhaust gas during operation of the system for processing turbine exhaust gas and to control the heat of the exhaust gas, the first heat exchanger being part of the cooling loop, The second heat exchanger is located downstream of the first heat exchanger in the cooling loop and is in fluid communication with the first heat exchanger. The second heat exchanger is a heat exchanger of a thermal energy storage mechanism configured to remove heat acquired by the first heat exchanger from the second working fluid and store the removed heat in a heat storage medium. The second heat exchanger is part of the cooling loop and is located outside the heat recovery steam generator and outside the exhaust gas passing through the heat recovery steam generator. Displaced downstream of the second heat exchanger of the thermal energy storage mechanism, and configured as a pump that is in fluid communication with the second heat exchanger of the thermal energy storage mechanism, the pump is configured to circulate the second working fluid through the cooling loop, and the pump is part of the cooling loop, A system that includes this.

15. The system according to claim 14, further comprising an energy storage container having a heat storage medium as the thermal energy storage mechanism.

16. The system according to claim 15, further comprising the heat storage medium being sand.

17. The energy storage container has a filling heat exchanger and a discharge heat exchanger. The system according to claim 16, further comprising the fact that the packed heat exchanger is the second heat exchanger located in the cooling loop together with the first heat exchanger.

18. The system according to claim 17, further comprising the fact that the filled heat exchanger and the discharge heat exchanger in the energy storage container are in heat transfer communication with a sand heat storage medium.

19. The system according to claim 18, further comprising the exhaust heat exchanger in the energy storage container being in fluid communication with the exhaust gas heat recovery device in the heat recovery steam generator located downstream of the first heat exchanger.

20. As a third heat exchanger located within the heat recovery steam generator and downstream of the exhaust gas heat recovery device, the exhaust gas heat recovery device is provided between the first heat exchanger and the third heat exchanger, and the third heat exchanger is configured to remove heat from the exhaust gas passing through the heat recovery steam generator by transferring heat to the second working fluid passing through the third heat exchanger, the second working fluid passing through the cooling loop to provide continuous cooling to the exhaust gas during operation of the system for processing turbine exhaust gas, and the third heat exchanger is part of the cooling loop, It further includes, The system according to claim 14, wherein the second heat exchanger of the thermal energy storage mechanism is located downstream of the first heat exchanger and the third heat exchanger in the cooling loop, is in fluid communication with the first heat exchanger and the third heat exchanger, and the second heat exchanger of the thermal energy storage mechanism is configured to remove heat acquired by the first heat exchanger and the third heat exchanger from the second working fluid and store the removed heat in the heat storage medium.

21. The system according to claim 14, further comprising a superheater, an evaporator, and a feedwater heater, for the heat recovery steam generator.

22. A method for treating gas turbine exhaust gas flowing through an exhaust gas discharge structure, wherein the method is The steps include: directing the flow of exhaust gas from a gas turbine to a first heat exchanger located at least partially within the exhaust gas discharge structure, and transferring heat from the flow of exhaust gas directed to the first heat exchanger to a working fluid passing through the first heat exchanger; The first heat exchanger is part of a cooling loop, and the step of guiding the exhaust gas that is led to the first heat exchanger to the working fluid through the cooling loop in order to provide continuous cooling to the exhaust gas, The steps include: guiding the working fluid downstream of the first heat exchanger through the cooling loop to a second heat exchanger located in the cooling loop (the second heat exchanger is a heat exchanger in a thermal energy storage system); The steps include removing the heat acquired by the first heat exchanger from the working fluid and storing the removed heat in the heat storage medium of the thermal energy storage system, Methods that include...

23. The method according to claim 22, further comprising the second heat exchanger of the thermal energy storage system being part of the cooling loop located outside the exhaust gas discharge structure.

24. The method according to claim 22, further comprising the step of circulating the working fluid through the cooling loop by operating a pump in the cooling loop (the pump is located downstream of the thermal energy storage system in the cooling loop).

25. The exhaust gas discharge structure is a heat recovery steam generator, The method according to claim 22, further comprising the step of guiding the flow of exhaust gas from the gas turbine through a first heat exchanger at least partially located within the heat recovery steam generator.

26. The thermal energy storage system includes the step of removing heat from the working fluid using a heat exchanger in the thermal energy storage system (filling the heat storage medium with the heat removed from the working fluid), The steps include: discharging heat from the heat storage medium to the exhaust heat exchanger of the thermal energy storage system that is in heat transfer communication with the heat storage medium; The method according to claim 22, further comprising:

27. The method according to claim 26, further comprising the step of connecting the exhaust heat exchanger to an exhaust gas heat recovery device located in the exhaust gas discharge structure downstream of the first heat exchanger so as to be in fluid communication with it.

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