Hydrogen and oxygen auxiliary combustion for combined cycle facilities.

Abstract

To provide a combined-cycle power plant.SOLUTION: A combined-cycle power plant comprises a gas turbine engine, an electric generator, a steam generator, and a duct burner system configured to heat exhaust gas. The duct burner system comprises a source of hydrogen fuel, a fuel distribution manifold to distribute the hydrogen fuel inside a duct of the steam generator, and an igniter to initiate combustion of the hydrogen fuel contained in the exhaust gas. A method for heating exhaust gas inside a steam generator for use in a combined-cycle power plant comprises directing exhaust gas of a gas turbine engine into a duct, introducing hydrogen fuel into the duct, combusting the hydrogen fuel and combustion gas inside the duct to generate heated gas, and heating water piping inside the duct with the heated gas to generate steam.SELECTED DRAWING: Figure 1

Description

[Technical Field]

[0001] The present invention relates to combined cycle power plants, such as, but not limited to, combined cycle power plants including gas turbine engines. More particularly, the present invention relates to auxiliary combustion systems for combined cycle power plants, such as, for example, combined cycle power plants utilized with heat recovery steam generators. [Background technology]

[0002] In a gas turbine combined cycle (GTCC) power plant, a gas turbine engine is operable to generate electricity directly by a generator utilizing shaft power. The hot exhaust gases of the gas turbine engine are additionally available to generate steam in a heat recovery steam generator (HRSG), which is available to further generate electricity by rotating the shaft of a steam turbine.

[0003] The power output of an HRSG can be increased by increasing the temperature of the exhaust gases, for example, by utilizing an auxiliary combustion system. In such systems, natural gas fuel is directed into the interior of the HRSG ducts and ignited via duct burners, increasing the energy and temperature of the exhaust gases, thereby increasing the steam-producing capacity of the HRSG.

[0004] Examples of combined cycle power plants utilizing auxiliary combustion systems or duct burners are disclosed in US Pat. Nos. 5,629,299; 5,729,333; and 5,729,333. [Prior art documents] [Patent documents]

[0005] [Patent Document 1] U.S. Patent No. 6,810,675 [Patent Document 2] U.S. Patent No. 6,606,848 [Patent Document 3] US Patent Application Publication No. 2017 / 0350279 Summary of the Invention [Problem to be solved by the invention]

[0006] Challenges to overcome in combined cycle power plant operation include carbon dioxide (CO2) emissions resulting from the combustion of fossil fuels, such as natural gas, which is the most widely used fossil fuel for generating electricity in the United States. The power industry is trending toward reduced-carbon or carbon-free electricity in response to various national policies attempting to reduce carbon-based power as well as ultimately transition to 100% renewable energy. However, the inventors of the present invention recognize that combined cycle power plants utilize fossil fuels, particularly in several different locations within the gas turbine combined cycle power plant. Therefore, simply transitioning the gas turbine engines of a combined cycle power plant to cleaner-burning fuels will not achieve the lowest possible emissions.

[0007] The present subject matter can provide a solution to this and other problems, for example, by providing a method and system for supplying a carbon-free fuel to a combined cycle power plant. In addition to the gas turbine (GT), one part of a combined cycle facility that utilizes fuel to assist in the production of electricity is a duct burner located inside the HRSG. The duct burner inside the HRSG provides supplemental heat input to the thermal cycle to provide the capacity to increase the production of steam that can be converted to electrical energy via a steam turbine generator (STG). Duct burners typically utilize natural gas as a fuel.

[0008] The inventors of the present invention have recognized that duct burners have the ability to burn a variety of fuels. One carbon-free power source is through the use of hydrogen. One such power generation facility capable of converting hydrogen to electricity is a combined cycle power plant having a duct burner with a fuel source that is at least partially hydrogen. Regardless of the percentage of hydrogen burned, lower CO2 emissions are produced than those produced by burning 100% natural gas. Furthermore, the present invention can utilize a pressurized hydrogen fuel source, such as an electrolyzer, at the location of a GTCC power plant. Additionally, a pressurized oxygen source, such as an electrolyzer, may be additionally located at the GTCC power plant to provide oxidant to the combustion process. The amount of oxygen and hydrogen can be controlled or regulated, for example, by utilizing a burner management system to control the auxiliary combustion combustion process independently of the GT operation, thereby producing suitable steam in the HRSG.

[0009] In one example, a duct burner system for a combined cycle power plant, the duct burner system including a gas turbine engine configured to generate exhaust gases and a steam generator configured to receive the exhaust gases from the gas turbine for heating water and generating steam, includes a hydrogen fuel source and a fuel distribution manifold located inside the steam generator for distributing hydrogen fuel along a length of a duct of the steam generator.

[0010] In another example, a method for heating exhaust gases within a heat recovery steam generator for use in a combined cycle power plant includes directing combustion gases of a gas turbine engine into a duct; introducing hydrogen fuel into the duct; combusting the hydrogen fuel and the combustion gases within the duct to produce heated gases; and heating a water pipe in the duct with the heated gases to produce steam.

[0011] This Summary is intended to provide the subject matter of this patent application. This Summary is not intended to provide an exclusive or exhaustive description of the invention. The Detailed Description is intended to provide further information about the invention. [Brief explanation of the drawings]

[0012] [Figure 1] 1 is a schematic diagram of a gas turbine combined cycle power plant including an auxiliary combustion unit including a hydrogen fuel source and an oxygen source. [Figure 2] 2 is a perspective view of a distribution supply system including separate manifolds for introducing hydrogen fuel and oxygen into the ducts of the HRSG of the gas turbine combined cycle power plant shown in FIG. 1. FIG. [Figure 3] FIG. 2 is a schematic cross-sectional view of a hydrogen manifold with nozzles. [Figure 4] FIG. 2 is a schematic block diagram of a burner management system for use in the gas turbine combined cycle power plant shown in FIG. 1. [Figure 5] 1 is a diagram of a method for producing and combusting hydrogen fuel and oxygen in a duct burner of a combined cycle power generation system. DETAILED DESCRIPTION OF THE INVENTION

[0013] In the drawings, which are not necessarily drawn to scale, like reference numbers describe similar components even in different views. Like reference numbers with different letter suffixes may represent different instances of the same component. The drawings, while depicting various embodiments of the present invention, are illustrative and should not be construed as limiting.

[0014] FIG. 1 is a schematic diagram of a combined cycle power plant 10 including a gas turbine 12, a heat recovery steam generator (HRSG) 14, a steam turbine 16, an auxiliary combustion system 18, and a controller 20. The gas turbine 12 is configured to provide an input to a generator 22, and the steam turbine 16 is configured to provide an input to a generator 24. The controller 20 includes a distribution control system (DCS). The HRSG 14 is operatively coupled to the steam turbine 16. The gas turbine 12 includes a compressor 26, a combustor 28, and a turbine 30. The steam turbine 16 includes multiple stages, such as a high-pressure turbine 32 and intermediate-pressure / low-pressure turbines 34A and 34B. The steam turbine 16 is further coupled to a condenser 36. The auxiliary combustion system 18 includes a duct burner system 38, a gas generator 40, storage tanks 42A and 42B, controllers 44A and 44B, valves 46A and 46B, an expansion device 48, and an optional mixer 50.

[0015] The gas turbine 12 is configured to operate by compressing air within a compressor 26, mixing the compressed air with fuel within a combustor 28 to generate high-energy gases through combustion of the fuel, and then expanding the high-energy gases within a turbine 30 to generate rotating shaft power. Rotation of the turbine 30 rotates a shaft to propagate the rotation of the compressor 26 and the compression of air within the compressor 26 to support the combustion process. Thus, combustion of fuel within the combustor 28 is converted to electricity in the generator 22.

[0016] The gas expanded by the turbine 30 is transported into the HRSG 14 to generate steam, for example, to operate the steam turbine 16. The HRSG 14 includes a duct burner system 38, as well as other components not shown in FIG. 1 for simplicity, such as a superheater, evaporator, economizer, or selective catalytic reduction (SCR) system. Exhaust gas E from the turbine 30 passes through various heat transfer elements of the HRSG 14 to generate steam, ultimately rotating the turbines 32, 34A, and 34B, which in turn rotate the shaft of the steam turbine that provides power to the generator 24. A condenser 36 collects steam from the steam turbine 16 and may return condensed water therein to the HRSG 14 to propagate the steam generation process. The steam turbine 16 and condenser 36 may be operated conventionally. Electricity generated by the generators 22 and 24 may be supplied to end users, for example, by coupling to a distributed grid network.

[0017] To increase the power output capacity of the HRSG 14, e.g., its ability to vaporize water into steam, the temperature of the exhaust gas E from the gas turbine 12 is increased by utilizing a duct burner system 38. The duct burner system 38 may introduce fuel into the duct 52 of the HRSG 14 before (e.g., upstream of) the water pipes of the high-pressure steam circuit 54A and the low-pressure steam circuit 54B. The fuel may be mixed with the exhaust gas. The duct burner system 38 includes one or more ignition devices (e.g., ignition devices 68A-68C shown in FIG. 2) to increase the temperature of the exhaust gas E by burning the fuel.

[0018] In the present invention, the duct burner system 38 utilizes hydrogen along with oxygen as an augmenting oxidant for combustion, providing supplemental heat throughout the thermal cycle. Thus, the duct burner system 38 can provide the combined cycle power plant 10 with an expansion operating profile, improved duct burner flame stability, improved overall thermal efficiency, lower emissions, and improved load-following capability. Gas products for supplemental combustion, such as H2 and O2, are generated by the electrolyzer 40 or supplied from an independent source. In one example, the electrolyzer 40 provides H2, and oxygen is utilized from ambient air. In such a configuration, the ambient air contributes nitrogen to the combustion process, resulting in the generation of unwanted emissions. These emissions can be improved by utilizing a selective catalytic reduction (SCR) system. In the illustrated embodiment, the electrolyzer 40 provides both H2 and O2.

[0019] The electrolyzer 40 generates H2 and O2 by utilizing an electric current. For example, water (H2O) is split into oxygen (O2) and hydrogen (H2). As a result of the electrolysis process, for example, O2 and H2 are stored in storage tanks 42A and 42B, respectively. The O2 and H2 are pressurized within the storage tanks 42A and 42B. Electrolysis may occur as a result of the electrolysis process or may be provided by additional means, for example, by one or more compressors or pumps.

[0020] Each storage tank 42A, 42B supplies a gas, such as H2 or O2, to the duct burner system 38. The flow of gas is controlled by controllers 44A, 44B in conjunction with control valves 46A, 46B. Additionally, each storage tank 42A, 42B includes a shutoff valve 56A, 56B. The shutoff valves 56A, 56B each include an on-off valve that allows or prevents the flow of gas from the storage tanks 42A, 42B. Each control valve 46A, 46B includes a control valve that can be moved to multiple positions between an open position and a closed position to allow various amounts of gas to pass through. The control valves 46A, 46B and the shutoff valves 56A, 56B can be connected to the plant controller 20.

[0021] Duct burner system 38 is configured to combust combustion constituents (H2 and O2) added to exhaust gas E supplied to duct 52 from gas generator 40 and / or storage tanks 42A, 42B. Thus, in the configuration shown in Figure 1, pro-oxidant and oxygen (O2) are introduced into duct 52 to support the fuel and hydrogen (H2) introduced into duct 52.

[0022] Fuel and oxidant distribution and flame stability are supported over a wide range of operating conditions, for example, by adjusting control valves 46A, 46B via BMS 44A, 44B. Standard duct burner operation using natural gas is limited by exhaust parameters from the gas turbine, such as exhaust temperature, oxygen level, and flow rate. In the present invention, the independent supply of O2 in the auxiliary combustion system 18 allows combustion of H2 within the duct 52 during operation over a wide range of gas turbine exhaust parameters that are at least somewhat decoupled from the exhaust and operating parameters of the gas turbine 12.

[0023] The flow of H2 from storage tank 42B through control valve 46B to duct burner 38 is controlled by a hydrogen flow controller integrated into BMS 44B and in communication with plant controller 20. BMS 44B regulates the flow of hydrogen as well as the desired total output of GTCC power plant 10, including the energy input from hydrogen-fueled duct burner 38, based on sensor signals from GT load sensor 58A, GT discharge flow sensor 58B, GT discharge temperature sensors 58C and 58D located upstream and downstream of duct burner 38, HRSG steam temperature sensor 58E, and oxygen level sensor 58F. For example, because H2 / O2 combustion is faster and hotter than natural gas combustion, the amount of H2 / O2 to be combusted is based on the discharge flow rate as well as HRSG steam temperature limits.

[0024] The flow of O2 from storage tank 42A to duct burner 38 via control valve 46A is controlled by an oxygen flow controller integrated into BMS 44A and in communication with plant controller 20. BMS 44A controls the oxygen flow rate based on the hydrogen auxiliary combustion load and the flow rate and oxygen content of the incoming GT exhaust gas E to duct burner 38, as well as the exhaust gas temperature both upstream and downstream of duct burner 38. A combined target oxygen content (from the exhaust gas and external supply) of approximately 10% to approximately 20% excess oxygen is predicted to result in complete combustion. An oxygen sensor is disposed within duct 52 to sense the amount of oxygen contained in the exhaust gas E upstream of duct burner system 38.

[0025] The hydrogen and oxygen are supplied from storage tanks 42A, 42B via separate pipes to the inside of duct 52 of HRSG 14, thereby preventing flame flashback inside the supply pipes, as described, for example, with reference to Figure 2. Alternatively, the oxygen and hydrogen are premixed locally and the mixture is injected into the exhaust stream just prior to ignition, for example, inside mixer 50.

[0026] The configuration depicted in FIG. 1 can be expanded with other devices, as well as other hydrogen-fired duct burners, to enhance the availability and efficiency of the combustion process, thereby reducing emissions, among other things. First, fuel preheating enhances flame stability and reduces CO emissions, resulting in improved NOx control through increased flame management. Because hydrogen (above 200 K) has a negative Joule-Thomson coefficient, an expansion device 48 is installed downstream of the hydrogen burner management system (BMS) 44B and hydrogen flow control device (e.g., modulating valve 46B) to preheat the fuel. The expansion device 48 includes any fuel throttling device design that can preheat the fuel, thereby contributing to CO emissions reduction, enhancing flame stability, and improving NOx control. Because the operating temperature of hydrogen is always above 200 K, the Joule-Thomson coefficient remains negative. The post-expansion piping diameter (D2) versus the pre-expansion piping diameter (D1) is determined by cycle design specifications, but D2 is always required to be greater than D1 to accommodate (and maximize) the expansion. As an alternative to or in addition to the expansion device 48, as shown in FIG. 2, a nozzle installed in the duct burner piping can be used to further expand the hydrogen beyond that achieved by the upstream expansion device 48, thereby further preheating the fuel. The use of a nozzle in the duct burner piping allows the post-expansion piping diameter (D2) to be reduced in the upstream expansion device, thereby reducing material costs and complexity. Alternatively, a fuel heating device, such as an electric heater or a heat exchanger in communication with other parts of the GTCC power plant 10, can be used.

[0027] Independently controlled consistent flows of hydrogen and oxygen help ensure optimal combustion conditions to maintain flame stability over a wide range of GT operating conditions and minimize CO and NO emissions. Optional components (fuel control, duct burner nozzles) further enhance system operation.

[0028] 2 is a perspective view of a distribution supply system 60 for the duct burner system 38, including independent manifolds 62A, 62B for the gas turbine combined cycle power plant 10 shown in FIG. 1. The manifolds 62A, 62B are an alternative to the mixer 50. As explained, the mixer 50 is used to premix oxygen and hydrogen prior to ignition and is one means for designing a burner (a "premixed flame"). In such a configuration, a single manifold is used to introduce the oxygen and hydrogen mixture into the duct 52. Alternatively, the manifolds 62A, 62B are used to maintain the oxygen and hydrogen independently until just prior to ignition (a so-called "diffusion flame").

[0029] Gas flow into the manifolds 62A, 62B is controlled by control valves 46A, 46B operated by controllers 44A, 44B, respectively, in coordination with controller 20. Motive pressure acting on the oxygen and hydrogen introduced into manifolds 46A, 46B is provided by compressors, pumps, or electrolyzers 40, or by pressurizing storage tanks 42A, 42B.

[0030] Manifolds 62A, 62B are configured as elongated tubular elements extending partially or completely across duct 52, e.g., within the plane of FIG. 1. Multiple longitudinal levels of manifolds 62A, 62B are provided vertically within duct 52 for distributing oxygen and hydrogen. Orifices 64A, 64B are provided downstream or aft of each manifold 62A, 62B. An ignition system 66 is provided downstream of manifolds 62A, 62B for providing one or more spark or other flame ignition devices by utilizing igniters 68A, 68B, 68C. An exciter 70 is coupled to controller 20 for supplying energy, e.g., heat or electricity, to igniters 68A-68C.

[0031] In the illustrated example, the diameter of manifold 62A is larger than the diameter of manifold 62B. However, the absolute and relative diameters or cross-sectional areas of other shapes for manifolds 62A, 62B, as well as the sizes of orifices 64A, 64B, are determined based on the expected operating ranges for temperature and volume of exhaust gas E, as well as hydrogen and oxygen. Orifices 64A, 64B comprise simple through-bores in manifolds 62A, 62B. However, in other examples, orifices 64A, 64B are configured as or equipped with nozzles, as shown in FIG. 3.

[0032] 3 is a schematic cross-sectional view of manifold 72 including tubular body 74, nozzle 76, and deflector plate 78. Deflector plate 78 is shaped to define a recess 80 in which all or part of tubular body 74 can be disposed. Deflector plate 78 extends across all or part of the width of duct 52 for a length sufficient to cover the width of manifold 72.

[0033] The manifold 72 includes an elongated tubular body 74 having a length spanning at least a portion of the width of the duct 52. The manifold 72 has a partially circular cross-sectional shape, although other cross-sectional shapes are also possible. A nozzle 76 projects radially from the tubular body 74, e.g., from the center of the manifold 72. The manifold 72 is positioned within the duct 52 so that the nozzle 76 projects downstream, e.g., in the flow direction of the exhaust gas E. The nozzle 76 is configured as a narrowing passage, e.g., a converging nozzle, to preheat the H2 gas by adjusting the exit of the H2 gas from the manifold 72. However, the nozzle 76 may have other configurations, such as a converging-diverging nozzle. The nozzle 76 may be used in place of the expansion device 48 or in combination with the expansion device 48 for two-stage heating.

[0034] The baffle 78 is provided to slow or diffuse the flow of the exhaust gas E around the manifold 72. The baffle 78 includes perforations through which the exhaust gas E passes. Thus, the exhaust gas E passing through the baffle 78 and the exhaust gas E flowing around the baffle 78 is slowed to a velocity more suitable for receiving the H gas from the manifold 72 and for supporting the combustion process, e.g., for enhancing flame stability.

[0035] 4 is a schematic block diagram of a control device 44B that includes a burner management system for the duct burner system 38. The control device 44B shown in FIG. 4 is, for example, a computer installed in a control room for the combined cycle power plant 10. The computer has the function of controlling the control valve 46B and the shutoff valve 56B. The control device 44B is similar to the control device shown in FIG. For example, the computer may be installed in a control room for the combined cycle power plant 10. The computer has functionality for controlling the modulating valve 46A and the shutoff valve 56A. The controller 20 (see FIG. 1) is in communication with the controllers 44A and 44B and is configured to control and coordinate the operation of the gas turbine 12, the HRSG 14, and the duct burner system 38. The controller 44B includes a CPU 82, a HDD 84, a RAM 86, a ROM 88 (e.g., an EPROM), and an I / O port 90.

[0036] The input unit 92, recording medium 94, output unit 96, and network 98 may be connected to the I / O port 90 as needed, as may sections of the GTCC power plant 10 that are the target of commands. Examples of sections that are the target of commands include a control valve 46B and a shutoff valve 56B. The operation of the duct burner system 38, including the ignition devices 68A-68C and the exciter 70, is controlled by the control device 20. Other aspects of the GTCC power plant 10 may be additionally controlled, such as the flow of fuel to the gas turbine 12, the inlet guide vanes (not shown), and the operation of the generators 22, 24, the steam turbine 16, and the gas generator 40. Thus, the operation of the GTCC power plant 10, including the auxiliary combustion system 18, is controlled by the controller 20 in combination with the controllers 44A, 44B.

[0037] The input unit 92 includes a keyboard, a mouse, a touch panel, or similar devices that are commonly available. The output unit 96 includes a touch panel and additionally functions as the input unit 92. The recording medium 94 may be any of a variety of recording media, including, for example, magnetic tape, magnetic disks, optical disks, magneto-optical disks, and semiconductor memories. The output unit 96 includes a display device, including, for example, a monitor or printer. A device that outputs sound, such as a speaker, may also be used as the output unit 96. Furthermore, while the control device 44B is integrated with the input unit 92 and the output unit 96, the form of the control device 44B is not limited to this and may be a desktop, notebook, tablet, or other device. The network 98 may include not only the Internet but also a LAN or the like. The control device 44B may be connected to other terminals, such as a database, a server, the control device 20, the control device 44A, etc., via the network 98.

[0038] Various types of programs, including a GTCC power plant program, are stored in the ROM 88. These programs are read from the ROM 88 by the CPU 82, loaded into, for example, the RAM 86, and executed. Operational programs are input from a recording medium 94 or a network 98 via an I / O port 90 and stored in the ROM 88. Operational programs are read from the recording medium 94 or the network 98 via the I / O port 90 and directly loaded into the RAM 86 without being stored in the ROM 88, thereby making them executable. Data obtained by operations is stored in one or more memories among the HDD 84, ROM 88, RAM 86, and recording medium 94, and is output to the output unit 96 by operating the input unit 92. In the present specification, at least one of the RAM 86, ROM 88, HDD 84, recording medium 94, and a storage device connected via the network 98 is simply referred to as a "memory."

[0039] Instructions for operating the auxiliary combustion system 18, the duct burner system 38, and the gas generator 40 are stored in the ROM 88. Such instructions include instructions for opening and closing the shutoff valve 56B when the auxiliary combustion system 18 is connected or disconnected and for commanding the control valve 46B to control the combustion process generated by the duct burner system 38. For example, the instructions are configured to generate a command signal for the control valve 46B based on input signals received by the I / O port 90 from the GT load sensor 58A, the GT discharge flow sensor 58B, the GT discharge temperature sensors 58C and 58D, the HRSG steam temperature sensor 58E, and the oxygen level sensor 58F. Similarly, the instructions are configured to generate a command signal for the control valve 46B based on the output of oxygen introduced into the duct 52 by the controller 44A.

[0040] In a further example, the controller 44B is configured to operate the gas generator 40 to ensure an adequate supply of hydrogen H2 is provided to the duct burner system 38, for example, for expected or projected operation of the GTCC power plant 10. In one example, the controller 44B operates the gas generator 40 simultaneously with operation of the auxiliary combustion system 18 to provide a live supply of hydrogen gas when the auxiliary combustion system 18 is operating. In another example, the controller 44B can operate the gas generator 40 intermittently to charge the storage tank 42B. For example, when the duct burner system 38 withdraws hydrogen gas from the storage tank 42B below a threshold level, the controller 44B initiates operation of the gas generator 40 to charge the storage tank 42B.

[0041] 5 is a schematic diagram illustrating a method for generating and combusting hydrogen fuel and oxygen in a duct burner system of a combined cycle power generation system. In one example, method 100 describes a method for operating the duct burner system 38 and gas generator 40 of the auxiliary combustion system 18 for the heat recovery steam generator 14 of the present invention.

[0042] In step 102, the gas generator 40 is operated to generate O2 and H2 gases. For example, the gas generator 40 receives commands from one or more of the controllers 44A, 44B, and 20 to start, maintain, and stop the generation of O2 and H2 gases.

[0043] In step 104, the gas generated by the gas generator 40 in step 102 is introduced into the duct burner system 38 for heating the exhaust gas E with low or no emissions.

[0044] In step 106, H2 is generated. In one example, the gas generator 40 includes an electrolytic cell that generates H2 gas.

[0045] Immediately or later, the H gas is stored for use in step 107. In one example, the H gas is stored in storage tank 42B, which acts as an accumulator for storing H gas when gas generator 40 is not operating.

[0046] In step 108, O2 is generated. In one example, the gas generator 40 includes an electrolytic cell that generates O2 gas. In another example, oxygen from atmospheric or ambient air is used as the O2 gas source.

[0047] Immediately or later, the O2 gas is stored for use in step 109. In one example, the O2 gas is stored in storage tank 42A, which acts as an accumulator for storing O2 gas when gas generator 40 is not operating.

[0048] In step 110, the H2 gas is pressurized. In one example, the H2 gas is originally pressurized as a result of the generation process in step 106. In the example of a gas generator 40 that includes an electrolyzer, the H2 gas is originally pressurized. In another example, the H2 gas generated in step 106 is subsequently pressurized by other devices, such as a pump or compressor. In yet another example, the pressurized H2 gas is delivered to the site of the combined cycle power plant 10 and transported to the storage tank 42B.

[0049] In step 112, the O2 gas is pressurized. In one example, the O2 gas is originally pressurized as a result of the generation process in step 108. In the example of a gas generator 40 including an electrolyzer, the O2 gas is originally pressurized. In another example, the O2 gas generated in step 108 is subsequently pressurized by other devices, such as a pump or compressor. In yet another example, the pressurized O2 gas is delivered to the site of the combined cycle power plant 10 and transported to the storage tank 42A.

[0050] As noted above, although steps 106, 108, 110, and 112 are illustratively described as separate steps, steps 106, 108, 110, and 112 may occur simultaneously with operation of gas generator 40.

[0051] In step 114, the flow of H2 gas is adjusted based on the load of the gas turbine 12, the flow rate of the exhaust gas E, the temperature of the exhaust gas E, and the steam temperature inside the HRSG 14, detected, for example, via a GT load sensor 58A, a GT discharge flow rate sensor 58B, GT discharge temperature sensors 58C and 58D disposed upstream and downstream of the duct burner system 38, an HRSG steam temperature sensor 58E, and an oxygen level sensor 58F, to control the combustion process inside the duct 52, for example, by utilizing a controller 44B.

[0052] In step 116, the flow of O2 gas is adjusted based on the load of the gas turbine 12, the flow rate of the exhaust gas E, the oxygen level of the exhaust gas E, and the steam temperature inside the HRSG 14, detected, for example, via a GT load sensor 58A, a GT discharge flow rate sensor 58B, GT discharge temperature sensors 58C, 58D disposed upstream and downstream of the duct burner system 38, an HRSG steam temperature sensor 58E, and an oxygen level sensor 58F, to control the combustion process inside the duct 52, for example, by utilizing a controller 44A.

[0053] In step 118, the H2 gas is conditioned through the use of an expansion device, such as a nozzle. Conditioning the H2 gas heats the H2 gas to further increase the efficiency of steam generation within the HRSG 14. For example, the expansion device 48 is used to condition the H2 gas before it is discharged from the duct 52 and after it is discharged from the control valve 46B. In another example, the H2 gas is conditioned by a nozzle, such as the nozzle 76 shown in FIG. 3.

[0054] In step 120, the gas turbine 12 is operated to produce exhaust gases E. As described above, a fuel, such as natural gas, is delivered to the combustor 28 and mixed with ambient air compressed by the compressor 26. The high energy produced as a result of the combustion process is utilized to rotate the turbine 30, and heat from the exhaust gases E discharged from the turbine 30 is utilized in an additional process to generate electricity via the HRSG 14 and the steam turbine 16.

[0055] In step 122 , the exhaust gas E is directed toward the interior of the duct 52 of the HRSG 14 .

[0056] In step 124, H2 gas is introduced into duct 52, for example, by utilizing manifold 62B or manifold 72.

[0057] In step 126, O2 gas is introduced into duct 52, for example, by utilizing manifold 62A or manifold 72.

[0058] In step 128, H2 gas and O2 gas are mixed, for example, by using mixer 50. Step 128 is optional. Step 128 can additionally occur before steps 124 and 126.

[0059] The mixed or independently introduced H and O gases are distributed through manifolds 62A, 62B, and 72 within duct 52 to enable homogeneous and sustainable combustion of H within duct 52. Additionally, baffles 78 are utilized to stabilize the combustion process by slowing down the flow of exhaust gas E in manifolds 62A, 62B, and 72.

[0060] In step 130, the H gas is ignited to combust with the O gas, thereby generating heat. For example, exciter 70 is activated by controller 20 to operate ignition devices 68A-68C, which provide a heat source to propagate combustion and a flame within duct 52.

[0061] In step 132, the heat obtained from the combustion of the H and O gases is utilized to generate steam, for example, by heating water disposed within the HRSG 14. Heating the exhaust gas E from the combustion of the H gas can increase the ability of the HRSG 14 to spin the steam turbine 16 without producing harmful emissions.

[0062] According to the present invention, the HRSG duct burner can efficiently burn hydrogen by using oxygen as an oxidant. By utilizing the above-described apparatus, system, and method, one or more of the following can be achieved: 1.Improved overall thermal cycle efficiency; 2. Reducing emissions; and 3. Improved operating range of duct burners and the operating range and ramping capabilities of composite power plants.

[0063] [Notes] The above detailed description includes references to the accompanying drawings, which form part of the detailed description. The drawings show, by way of illustration, specific embodiments in which the invention may be practiced. These embodiments are also referred to herein as "examples." Such examples may include elements in addition to those shown or described. However, the inventors contemplate examples in which only those elements shown or described are provided. Furthermore, the inventors contemplate examples (or one or more embodiments of such examples) that utilize any combination or variation of the elements shown or described with respect to a particular example (or one or more embodiments of such examples) or any other example (or one or more embodiments of such examples) shown or described herein.

[0064] As used herein, the term "a" includes the meaning of "one or more," independent of any other instances or uses of "at least one" or "one or more," as is common in patent documents. The term "or" is used in a non-exclusive sense, and unless otherwise specified, "A or B" means "A but not B," "B but not A," and "A and B." The term "comprise" is used synonymously with "comprising." Furthermore, in the claims, the terms "including" and "comprising" are used interchangeably, and systems, apparatus, articles, compositions, forms, or processes that include elements in addition to those listed before such terms are deemed not to depart from the technical scope defined by the claims. Furthermore, in the claims, terms such as "first," "second," and "third" are rarely used as labels, but are not intended to impose numerical requirements on their objects.

[0065] Examples of the methods described herein are machine or at least partially computer-implemented. Some examples include computer-readable or machine-readable media encoded with instructions operable to configure an electronic device to perform the methods described in the examples. Implementations of such methods include code, such as microcode, assembly language code, high-level language code, etc. Such code includes computer-readable instructions for performing various methods. The code forms part of a computer program product. Furthermore, in one example, the code is tangibly stored on one or more volatile, persistent, or non-volatile tangible computer-readable media, e.g., during execution or at other times. Examples of these tangible computer-readable media include hard disks, removable magnetic disks, removable optical disks (e.g., compact disks and digital video disks), magnetic cassettes, memory cards or memory sticks, random access memories (RAMs), read-only memories (ROMs), etc.

[0066] The above description is for illustrative purposes only and should not be construed as limiting. For example, the above examples (or one or more implementations of the examples) may be utilized in combination with each other. Other examples are available to those skilled in the art upon review of this specification, for example. The Abstract has been drafted to comply with 37 CFR §1.72(b) to enable the reader to quickly grasp the technical concepts of the invention. It should be noted that the Abstract should not be used to interpret or limit the scope or meaning of the claims. Also, in the above Detailed Description, various features are grouped together throughout the specification. This should not be interpreted as intending that features described in the specification but not in the claims are essential to any claim. Rather, inventive subject matter lies in less than all features of a particular described embodiment. Thus, it should be noted that the following claims are incorporated into the Detailed Description as an example or embodiment, with each claim standing on its own as an independent embodiment, and that such embodiments can be combined with each other in various combinations or variations. The scope of the invention should be determined with reference to the claims, along with the full scope of equivalents to which such claims are entitled. [Explanation of symbols]

[0067] 10. Combined cycle power plants 12 Gas turbine 14 Heat Recovery Steam Generator (HRSG) 16 Steam turbine 18 Auxiliary Combustion System 20 Control device 22 Generator 24 Generator 26 (Gas turbine 12) compressor 28 (gas turbine 12) combustor 30 (Gas Turbine 12) Turbine 32 (Steam turbine 16) high pressure turbine 34A (Steam Turbine 16) Intermediate Pressure Turbine 34B (Steam turbine 16) low pressure turbine 36 (Steam turbine 16) condenser 38 (Auxiliary Combustion System 18) Duct Burner System 40 Gas generator (electrolyzer) (of auxiliary combustion system 18) 42A (Auxiliary Combustion System 18) Storage Tank 42B (Auxiliary Combustion System 18) Storage Tank 44A (Auxiliary Combustion System 18) Control Device 44B (Auxiliary combustion system 18) control device 46A (Auxiliary Combustion System 18) Control Valve 46B (Auxiliary Combustion System 18) Control Valve 48 (Auxiliary combustion system 18) expansion device 50 (auxiliary combustion system 18) mixer 52 (HRSG14) duct 54A High-pressure steam circuit 54B Low pressure steam circuit 56A (Storage Tank 42A) Shut-off Valve 56B (Storage tank 42B) shutoff valve 58A GT Load Sensor 58B GT discharge flow sensor 58C GT exhaust temperature sensor 58D GT exhaust temperature sensor 58E HRSG Steam Temperature Sensor 58F Oxygen Level Sensor 60 Distribution Supply System 62A manifold 62B manifold 64A Orifice 64B Orifice 66 Ignition System 68A ignition system 68B Ignition system 68C ignition system 70 Exciter 72 Manifold 74 Tubular body 76 nozzles 78 Baffle 78 Deflection plate 82 CPU 84 HDD 86 RAM 88 ROM 90 I / O ports 92 Input Units 94 Recording Media 96 output units 98 Network E Exhaust Gas

Claims

1. 1. A combined cycle power plant comprising: an electrolyzer configured to generate hydrogen gas from water; a source of natural gas; a gas turbine engine configured to generate an exhaust gas, the gas turbine engine including a combustor configured to receive natural gas from the natural gas source; and a boiler configured to receive exhaust gases from the gas turbine engine for heating water and generating steam; a duct burner system including a fuel distribution manifold disposed within the boiler for distributing at least a portion of the hydrogen gas within a duct of the boiler; In the combined cycle power plant, the fuel distribution manifold: a tubular body extending along an axis to receive hydrogen gas from the electrolytic cell; a discharge opening in the tubular body for releasing hydrogen gas into the interior of the duct; a burner management system for regulating the flow of hydrogen gas from the electrolyzer to the fuel distribution manifold based on operating parameters of the gas turbine engine; a system controller configured to communicate with the burner management system to coordinate operation of the gas turbine engine and operation of the duct burner system; A combined cycle power plant comprising:

2. 10. The combined cycle power plant of claim 1, further comprising an oxygen source connected to the duct of the boiler.

3. 3. The combined cycle power plant of claim 2, further comprising an oxygen distribution manifold disposed in the boiler to distribute oxygen to the interior of the duct of the boiler.

4. The combined cycle power plant of claim 2, wherein the burner management system regulates the flow of oxygen gas from the electrolyzer based on operating parameters of the gas turbine engine.

5. 5. The combined cycle power plant of claim 4, wherein the burner management system is communicatively coupled to a control valve for controlling the flow of hydrogen gas to the fuel distribution manifold and oxygen gas to the duct.

6. The combined cycle power plant comprises: a flow sensor configured to detect a flow rate of combustion gases within the duct; an oxygen content sensor configured to detect the oxygen content of the combustion gases within the duct; 5. The combined cycle power plant of claim 4, comprising:

7. the combined cycle power plant includes an expansion device configured to expand hydrogen fuel before combustion of hydrogen gas contained in the exhaust gas begins; 2. The combined cycle power plant of claim 1, wherein the expansion device comprises an expansion nozzle disposed between the electrolyzer and the boiler or a nozzle disposed in the fuel distribution manifold.

8. the combined cycle power plant including a deflector positioned upstream of the tubular body to diffuse the flow of exhaust gas around the tubular body; 2. The combined cycle power plant of claim 1, wherein the deflector plate is an elongated plate extending along the tubular body, the deflector plate having openings therethrough for allowing exhaust gas to flow therethrough.

9. the deflector plate includes a recess for receiving the tubular body; The combined cycle power plant of claim 8 , wherein the discharge opening comprises a nozzle.

10. The combined cycle power plant comprises: an ignition device configured to start combustion of hydrogen gas contained in the exhaust gas inside the duct; a first generator configured to be driven by the gas turbine engine to generate electricity; a steam turbine configured to receive steam generated by the boiler; a second generator configured to be driven by the steam turbine to generate electricity; and 2. The combined cycle power plant of claim 1, comprising:

11. 1. A method for operating a combined cycle power plant, comprising: supplying natural gas from a natural gas source to a combustor of a gas turbine engine; mixing air and natural gas in the combustor of the gas turbine engine to generate combustion gases; directing exhaust gases from the gas turbine engine into a duct of a boiler; generating hydrogen fuel from water in an electrolyzer; introducing hydrogen fuel into the duct through a fuel distribution manifold of a duct burner system, the fuel distribution manifold being disposed in the boiler for distributing at least a portion of the hydrogen fuel within the duct of the boiler, the fuel distribution manifold having a tubular body extending along an axis and having a discharge opening; combusting hydrogen fuel and combustion gases within the duct to generate heated gases; heating the boiler water piping inside the duct with the heated gas to generate steam; utilizing a burner management system to regulate the flow of hydrogen gas from the electrolyzer to the fuel distribution manifold based on operating parameters of the gas turbine engine; utilizing a system controller to control the delivery of natural gas from the natural gas source to the combustor; coordinating operation of the gas turbine engine and operation of the duct burner system through communication with the burner management system; A method comprising:

12. The method of any of claims 11 to 15, further comprising directing oxygen into the combustion gases.

13. The method of claim 11, further comprising the step of introducing pure oxygen into the interior of the duct, and wherein the hydrogen fuel is undiluted.

14. 13. The method of claim 12, wherein the method comprises generating pure oxygen with the electrolytic cell.

15. The method comprises: storing the hydrogen fuel and pure oxygen in a storage tank prior to directing the hydrogen fuel and pure oxygen into the interior of the duct; 15. The method of claim 14, comprising:

16. The method of any of claims 14 to 19, further comprising the step of adjusting a flow of hydrogen fuel and a flow of pure oxygen to said duct based on operating conditions of said gas turbine engine.

17. The method comprises: detecting a flow rate of combustion gas inside the duct; detecting the oxygen content of the combustion gases within the duct; 17. The method of claim 16, comprising:

18. The method of claim 11, further comprising the step of expanding the hydrogen fuel prior to introducing the hydrogen fuel into the duct.

19. 12. The method of claim 11, wherein the method comprises generating electricity from the generated steam.

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