Patent Publication Number: US-11661866-B2

Title: Hydrogen and oxygen supplemental firing for combined cycle facility

Description:
TECHNICAL FIELD 
     This document pertains generally, but not by way of limitation, to combined-cycle power plants, such as those including gas turbine engines. More specifically, but not by way of limitation, the present application relates to supplemental firing systems for combined-cycle power plants, such as those that can be used in heat recovery steam generators. 
     BACKGROUND 
     In a gas turbine combined-cycle (GTCC) power plant, a gas turbine engine can be operated to directly generate electricity with a generator using shaft power. Hot exhaust gas of the gas turbine engine can additionally be used to generate steam within a heat recovery steam generator (HRSG) that can be used to rotate a steam turbine shaft to further produce electricity. 
     Output of the HRSG can be increased by increasing the temperature of the exhaust gas, such as by use of a supplemental firing system. In such systems, a natural gas fuel can be directed into the duct of the HRSG and ignited via a duct burner to increase the energy and temperature of the exhaust gas, thereby increasing the capability of producing steam in the HRSG. 
     Examples of combined-cycle power plants using supplemental firing systems or duct burners are described in Pat. No. U.S. Pat. No. 6,810,675 to Liebig; Pat. No. U.S. Pat. No. 6,606,848 to Rollins III; and Pub. No. US 2017/0350279 to Kobayashi et al. 
     OVERVIEW 
     Problems to be solved in operating combined-cycle power plants include the emission of carbon dioxide (CO 2 ) due to burning of fossil fuels such as natural gas, which is the most widely used fossil fuel for power generation in the United States. The power industry is attempting to move towards reduced-carbon or carbon-free electricity in response to various state policies prompting the drawing down of carbon-based power along with the additional eventual transition to 100% renewable energy. However, the present inventors have recognized, among other things, that combined-cycle power plants utilize fossil fuels in multiple, disparate places within a gas turbine combined-cycle power plant. As such, simply transitioning a gas turbine engine of a combined-cycle power plant over to burning cleaner fuel will not achieve the lowest emissions possible. 
     The present subject matter can provide solutions to this problem and other problems, such as by providing methods and systems for providing carbon-free fuel to a combined-cycle power plant. One portion of the combined-cycle facility that uses fuel, in addition to the gas turbine (GT), to support the production of electricity is the duct burner that is located within the HRSG. The duct burner inside of the HRSG provides supplemental heat input to the thermal cycle to provide the capability to increase steam production that can be converted to electrical energy via a steam turbine generator (STG). The duct burner typically uses natural gas as the fuel. 
     The present inventors have recognized that duct burners have the ability to burn a wide range of fuels. One source of carbon-free electricity is via the use of hydrogen. One such power generation facility that can convert 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, it will produce lower CO 2  emissions than that of combusting 100% natural gas. Furthermore, the present disclosure can use a source of pressurized hydrogen fuel, such as an electrolyser, at the location of the GTCC power plant. Furthermore, a source of pressurized oxygen, such as the electrolyser, can additionally be located at the GTCC power plant to provide an oxidant to the combustion process. The amount of hydrogen and oxygen can be controlled or modulated, such as by using a burner management system, to control the supplemental firing combustion process independent of the operation of the GT, thereby allowing tailored steam production in the HRSG. 
     In an example, a duct burner system for a combined-cycle power plant comprising a gas turbine engine configured to generate exhaust gas and a steam generator configured to receive the exhaust gas from the gas turbine to heat water and generate steam, the duct burner system can comprise a source of hydrogen fuel and a fuel distribution manifold located in the steam generator to distribute the hydrogen fuel across a length of a duct of the steam generator. 
     In another example, a method for heating exhaust gas in a heat recovery steam generator for use in a combined-cycle power plant can comprise directing combustion gas of a gas turbine engine into a duct, introducing hydrogen fuel into the duct, combusting the hydrogen fuel and the combustion gas in the duct to generate heated gas, and heating water pipes in the duct with the heated gas to generate steam. 
     This overview is intended to provide an overview of subject matter of the present patent application. It is not intended to provide an exclusive or exhaustive explanation of the invention. The detailed description is included to provide further information about the present patent application. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG.  1    is a schematic view of a gas turbine combined-cycle power plant including a supplemental firing unit including sources of hydrogen fuel and oxygen. 
         FIG.  2    is a perspective view of a distribution system including separate manifolds for introducing hydrogen fuel and oxygen into a duct of a HRSG of the gas turbine combined-cycle power plant of  FIG.  1   . 
         FIG.  3    is a schematic cross-sectional view of a hydrogen manifold incorporating a nozzle. 
         FIG.  4    is a schematic block diagram of a burner management system for use in the gas turbine combined-cycle power plant of  FIG.  1   . 
         FIG.  5    is a schematic line diagram illustrating methods of generating and combusting hydrogen fuel and oxygen in a duct burner of a combined-cycle power generation system. 
     
    
    
     In the drawings, which are not necessarily drawn to scale, like numerals may describe similar components in different views. Like numerals having different letter suffixes may represent different instances of similar components. The drawings illustrate generally, by way of example, but not by way of limitation, various embodiments discussed in the present document. 
     DETAILED DESCRIPTION 
       FIG.  1    is a schematic diagram of combined-cycle power plant  10  comprising gas turbine  12 , heat recovery steam generator (HRSG)  14 , steam turbine  16 , supplemental firing system  18 , and plant controller  20 . Gas turbine  12  can be configured to provide input to electrical generator  22  and steam turbine can be configured to provide input to electrical generator  24 . Controller  20  can comprise a Distributed Control Systems (DCS) device. HRSG  14  can be operatively coupled to steam turbine  16 . Gas turbine  12  can include compressor  26 , combustor  28  and turbine  30 . Steam turbine  16  can include multiple stages, such as high pressure turbine  32  and intermediate/low pressure turbines  34 A and  34 B. Steam turbine  16  can additionally be coupled to condenser  36 . Supplemental firing system  18  can comprise duct burner system  38 , gas generator  40 , storage tanks  42 A and  42 B, control devices  44 A and  44 B, valves  46 A and  46 B, expansion device  48  and an optional mixer  50 . 
     Gas turbine  12  can be configured to operate by compressing air in compressor  26 , mixing the compressed air with fuel in combustor  28  to generate high energy gases via burning of the fuel, and then expanding the high energy gases in turbine  30  to produce rotational shaft power. Rotation of turbine  30  can rotate a shaft to propagate rotation of compressor  26  and compression of air therein to maintain the combustion process. That same rotational shaft power can be used to turn a generator shaft to provide input to electric generator  22 . Thus, combustion of fuel in combustor  28  is converted to electricity at electric generator  22 . 
     Gas expanded by turbine  30  can be passed into HRSG  14  to, for example, generate steam for operation of steam turbine  16 . HRSG  14  can include duct burner system  38 , as well as other components such as a superheater, an evaporator, an economizer and a selective catalytic reduction (SCR) system, which are not shown in  FIG.  1    for simplicity. Exhaust gas E from turbine  30  can pass by various heat transfer components, of HRSG  14  to produce steam and ultimately cause rotation of turbines  32 ,  34 A and  34 B to rotate a steam turbine shaft that provides input to electrical generator  24 . Condenser  36  can collect steam from steam turbine  16  and return water condensed therein to HRSG  14  to propagate the steam generation process. Steam turbine  16  and condenser  36  can operate in a conventional manner. Thus, generation of heat from exhaust gas of gas turbine  12  can be converted to electricity at electric generator  24 . Electricity generated by electrical generators  22  and  24  can be delivered to end users such as by coupling to a distributed grid network. 
     In order to increase the output capacity of HRSG  14 , e.g., the ability to turn water into steam, the temperature of exhaust gas E of gas turbine  12  can be increased using duct burner system  38 . Duct burner system  38  can introduce a fuel into duct  52  of HRSG  14  before (e.g., upstream of) water piping of high pressure and low pressure steam circuits  54 A and  54 B. The fuel can mix with the exhaust gas. Duct burner system  38  can include one or more ignitors (e.g., ignitors  68 A- 68 C of  FIG.  2   ) to cause the fuel to burn to increase the temperature of exhaust gas E. 
     In the present disclosure, duct burner system  38  can utilize hydrogen with oxygen as an augmenting oxidant to combust and provide supplemental heat to the overall thermal cycle. The oxygen and hydrogen ratio can be independent from the operating profile of gas turbine  12 . As such, duct burner system  38  can provide an expanded operating profile, improved duct burner flame stability, improved overall thermal efficiency, lower emissions, and enhanced load following capabilities to combined-cycle power plant  10 . The gas products for the supplemental firing. e.g., H 2  and O 2 , can be produced by electrolyser  40  or can be provided from independent sources. In an example, electrolyser  40  can provide H 2  and oxygen can be utilized from ambient air. In such configurations, ambient air provides nitrogen to the combustion process, which can result in the production of unwanted emissions. Such emissions can be remedied with the use of selective catalytic reduction (SCR) systems. In the illustrated embodiment, electrolyser  40  can provide both H 2  and O 2 . 
     Electrolyser  40  generates H 2  and O 2  gas using an electric current. For example, water (H 2 O) can be decomposed into oxygen (O 2 ) and hydrogen (H 2 ). The resulting constituents of the electrolysis process, e.g., O 2  and H 2 , can be stored in tanks  42 A and  42 B, respectively. The O 2  and H 2 , can be pressurized within tanks  42 A and  42 B. The pressurization can occur as a result of the electrolysis process or can be provided by additional means, such as one or more compressors or pumps. 
     Each of tanks  42 A and  42 B can provide a gas such as H 2  or O 2  to duct burner system  38 . Flow of the gas can be controlled by control devices  44 A and  44 B in conjunction with modulating valves  46 A and  46 B. Furthermore, tanks  42 A and  42 B can be provided with shut-off valves  56 A and  56 B. Shut-off valves  56 A and  56 B can comprise on/off valves that permit or obstruct flow of gas from tanks  42 A and  42 B, respectively. Valves  46 A and  46 B can comprise modulating valves that can be moved into a plurality of positions between on and off to allow different amounts of gas to flow therethrough, respectively. Modulating valves  46 A and  46 B and shut-off valves  56 A and  56 B can be connected to plant controller  20 . 
     Duct burner system  38  can be configured to combust the combustion constituents (H 2  and O 2 ) added to exhaust gas E provided to duct  52  from gas generator  40  and/or tanks  42 A and  42 B. As such, in the configuration of  FIG.  1   , an augmenting oxidant, oxygen (O 2 ), can be introduced into duct  52  to support the burning of a fuel, hydrogen (H 2 ), also introduced into duct  52 . 
     Fuel and oxidant distribution and flame stability can be supported over a wide range of operating conditions, such as by modulation of valves  46 A and  46 B through BMS  44 A and  44 B, respectively. Operation of a standard duct burner using natural gas is limited by parameters of the gas turbine exhaust, such as exhaust gas temperature, oxygen level, and flow rate. With supplemental firing system  18  of the present disclosure, a separate supply of O 2  can enable combustion of H 2  in duct  52  with operation over a wider range of gas turbine exhaust parameters, at least somewhat decoupled from the exhaust and operation parameters of gas turbine  12 . 
     The flow of H 2  from tank  42 B via valve  46 B to duct burner  38  can be controlled by a hydrogen flow controller incorporated into BMS  44 B and in communication with plant controller  20 . BMS  44 B can modulate the hydrogen flow rate based on sensor signals from GT load sensor  58 A, and GT exhaust flow rate sensor  58 B, GT exhaust temperature sensors  58 C and  58 D upstream and downstream of duct burner  38 . HRSG steam temperature sensor  58 E, oxygen level sensor  58 F, as well as the desired total power output of GTCC power plant  10  including the energy input from hydrogen-fueled duct burner  38 . For example, because combustion of H 2 /O 2  is faster and hotter than natural gas, the amount of H 2 /O 2  to be combusted can be based upon the exhaust flow rate as well as HRSG steam temperature limitations. 
     The flow of O 2  from tank  42 A via valve  46 A to duct burner  38  can be controlled by an oxygen flow controller incorporated into BMS  44 A and in communication with plant controller  20 . BMS  44 A can control the oxygen flow rate based on the supplemental firing load of the hydrogen and also the flow rate and oxygen content of the incoming GT exhaust E to duct burner  38  as well as the exhaust gas temperature both upstream and downstream of duct burner  38 . A target combined oxygen content (from the exhaust gas and external supply) of about 10% to about 20% excess oxygen is expected to provide complete combustion. Oxygen sensors can be provided in duct  52  to sense the amount of oxygen in exhaust gas E upstream of duct burner system  38 . 
     The hydrogen and oxygen can be supplied from tanks  42 A and  42 B via separate pipes all the way to the inside of duct  52  of HRSG  14 , to prevent flame flashback in the supply pipes, as described with reference to  FIG.  2    for example. Alternatively, the oxygen and hydrogen can be pre-mixed locally, such as within mixer  50 , and the mixture can be injected into the exhaust stream immediately prior to ignition. 
     The configuration of  FIG.  1   , as well as other hydrogen-combusting duct burners, can be enhanced with other optional devices and configurations that can add value and efficiency to the combustion process to, among other things reduce emissions. First, fuel pre-heat can increase flame stability, reduce CO, and allow increased flame management to improve NOx control. Because Hydrogen (above 200° K) has a negative Joule-Thomson coefficient, expansion device  48  can be installed after both hydrogen Burner Management System (BMS)  44 B and hydrogen flow controller (e.g. valve  46 B) to provide fuel pre-heat. Expansion device  48  can comprise any throttling device design that can provide fuel pre-heat to help reduce CO, and enhance flame stability and NOx control. Because the operating temperature of the hydrogen will always be above 200° K, the joule-Thompson coefficient will always remain negative. The pipe diameter of post-expansion (D2) versus pre-expansion (D1) can also be dictated by cycle design specifics but it is always expected that D2 will be greater than D1, to accommodate (and potentially maximize) the expansion. Alternatively, or in addition to, expansion device  48 , nozzles can be installed on the duct burner lines, and utilized to further expand the hydrogen beyond what the upstream expansion device  48  achieves, to obtain further fuel pre-heat, as is illustrated in  FIG.  2   . Use of nozzles on the duct burner lines can allow for a reduction of the post-expansion pipe diameter (D2) at the upstream expansion device, which may reduce material cost and complexity. In other examples, fuel heating devices, such as electric heaters or heat exchangers in communication with other portions of GTCC power plant  10  can be used. 
     The separately controlled and consistent flows of hydrogen and oxygen can help ensure optimal combustion conditions to maintain flame stability and minimize CO and NO emissions over a wide range of GT operating conditions. The optional components (throttling device, duct burner nozzles) further enhance the operation of the system. 
       FIG.  2    is a perspective view of distribution system  60  for duct burner system  38  including separate manifolds  62 A and  62 B for introducing oxygen and hydrogen fuel into duct  52  of HRSG  14  of gas turbine combined-cycle power plant  10  of  FIG.  1   . Manifolds  62 A and  62 B can provide an alternative to mixer  50 . As mentioned, mixer  50  can be used for premixing oxygen and hydrogen before ignition, which is one way to design a burner (“premixed flame”). In such a configuration, a single manifold can be used to introduce the mixture of oxygen and hydrogen into duct  52 . Alternatively, manifolds  62 A and  62 B can be used to keep oxygen and hydrogen separate until just before ignition (so called “diffusion flame”). Duct burner system  38  can be configured either way. 
     Flow of gas into manifolds  62 A and  62 B can be controlled by modulating valves  46 A and  46 B, which are operated by control devices  44 A and  44 B, respectively, in coordination with controller  20 . Motive pressure to the oxygen and hydrogen introduced into manifolds  46 A and  46 B can be provided by compressors or pumps, electrolyser  40 , or by pressurization of tanks  42 A and  42 B. 
     Manifolds  62 A and  62 B can be configured as elongate tubular elements that can extend partially or fully across duct  52 , e.g., into the plane of  FIG.  1   . Multiple longitudinal levels of manifolds  62 A and  62 B can be vertically provided within duct  52  to distribute the oxygen and hydrogen across the height of duct  52 . Manifolds  62 A and  62 B can be provided with orifices  64 A and  64 B, respectively, to permit gas to flow out of the elongate tubular elements. Orifices  64 A and  64 B can be provided on downstream or trailing sides of manifolds  62 A and  62 B, respectively. Ignition system  66  can be provided downstream of manifolds  62 A and  62 B to provide one or more sparks or other flame-instigators using ignitors  68 A.  68 B and  68 C. Excitor  70  can be coupled to controller  20  to provide energy to ignitors  68 A- 68 C, such as heat or electricity. 
     In the illustrated example, the diameter of manifold  62 A is shown to be greater than the diameter of manifold  62 B. However, the absolute and relative diameters, or cross-sectional areas for other shapes, for manifolds  62 A and  62 B, as well as the sizes of orifices  64 A and  64 B, can be determined based on the expected operating range of temperature and volume of exhaust gas E as well as Hydrogen and Oxygen. Orifices  64 A and  64 B can comprise simple through-bores in manifolds  62 A and  62 B. However, in other examples, orifices  64 A and  64 B can be configured as or equipped with nozzles, as is shown in  FIG.  3   . 
       FIG.  3    is a schematic cross-sectional view of manifold  72  comprising tubular body  74 , nozzle  76  and deflector  78 . Deflector  78  can be contoured to form pocket  80  in which tubular body  74  can be fully or partially disposed. Deflector  78  can extend fully or partially across the width of duct  52  a length sufficient to shield the width of manifold  72 . 
     Manifold  72  can comprise elongate tubular body  74  having a length configured to span, or at least partially span, the width of duct  52 . Manifold  72  can have a partially circular cross-sectional profile, but can have other shapes. Nozzle  76  can project from tubular body  74 , such as in a radial direction from the center of manifold  72 . Manifold  72  can be positioned within duct  52  such that nozzle  76  projects in a downstream direction, e.g., in a flow direction of exhaust gas E. Nozzle  76  can be configured as a narrowing passage, e.g., a converging nozzle, to throttle the exit of the H 2  gas from manifold  72  and thereby provide pre-heating to the H 2  gas. However, nozzle  76  can have other configurations, such as converging-diverging. Nozzle  76  can be an alternative to expansion device  48  or can be provided in combination with expansion device  48  to provide two-stage heating. 
     Baffle  78  can be provided to slow down or diffuse the flow of exhaust gas E around manifold  72 . Baffle  78  can be provided with perforations to allow exhaust gas E to pass through baffle  78 . As such, exhaust gas E passing through and around baffle  78  can be slowed to a velocity more suited for receiving the H 2  gas from manifold  72  and sustaining the combustion process, e.g., promoting flame stability. 
       FIG.  4    is a schematic block diagram of control device  44 B comprising a burner management system for duct burner system  38 . Control device  44 B of  FIG.  4    can be, for example, a computer that is installed in a control room for combined-cycle power plant  10 , and has a function to control valves  46 B and  56 B. Control device  44 B of  FIG.  1    can be, for example, a computer that is installed in a control room for combined-cycle power plant  10 , and has a function to control valves  46 A and  56 A.  FIG.  4    is described with reference to control device  44 B, though control device  44 A can be configured similarly. Controller  20  ( FIG.  1   ) can be in communication with control devices  44 A and  44 B and can be configured to control and coordinate operation of gas turbine  12 . HRSG  14 , and duct burner system  38 . Control device  44 B can comprise CPU  82 , HDD  84 , RAM  86 . ROM (for example, EPROM)  88 , and I/O port  90 . 
     Input unit  92 , recording medium  94 , output unit  96 , network  98 , can be connected to I/O port  90  as appropriate, as well as a section of GTCC power plant  10  to be commanded. The sections to be commanded can include modulation valve  46 B and shut-off valve  56 B. Operation of duct burner system  38 , including ignitors  68 A- 68 C and excitor  70 , can be controlled by controller  20 , which can additionally control other aspects of GTCC power plant  10  such as fuel flow to gas turbine  12 , inlet guide vanes (not depicted), operation of generators  22  and  24 , steam turbine  16 , gas generator  40  and others. As such, operation of GTCC power plant  10  including supplemental firing system  18  can be controlled by controller  20  in combination with control devices  44 A and  44 B. 
     Input unit  92  can comprise a keyboard, a mouse, a touch panel, and the like can be typically used. Output unit  92  can comprise a touch panel, and can additionally function as input unit  92 . Recording medium  94  can comprise any of various kinds of recording mediums such as a magnetic tape, a magnetic disk, an optical disk, a magneto-optical disk, and a semiconductor memory is applicable. Output unit  96  can comprise a display device such as a monitor or a printer is applicable. A device such as a loudspeaker that outputs sound is applicable as output unit  96 . In addition, control device  44 B can be configured integrally with input unit  92  and output unit  96 , and a form of control device  44 B is not limited but can be a desktop type, a notebook type, a tablet type, or the like. Network  98  includes not only the Internet but also a LAN and the like, and control device  44 B can be connectable to another terminal, a database, a server, controller  20 , control device  44 A or the like via network  98 . 
     Various kinds of programs including a GTCC operation program and the like are stored in ROM  88 , and these programs are read by CPU  82  from ROM  88 , loaded to, for example, RAM  86 , and executed. The operation program can be input from recording medium  94  or network  98  via I/O port  90  and stored in ROM  88 . The operation program can be executed by being read by CPU  82  from recording medium  94  or network  98  via the I/O port  90  and directly loaded to RAM  86  without being stored in ROM  88 . Data and the like obtained by operations are stored in one or more memories out of HDD  84 , ROM  88 , RAM  86 , and recording medium  94 , and output to output unit  96  by operating input unit  92 . In the present specification, at least one of RAM  86 , ROM  88 . HDD  84 , recording medium  94 , a storage device connected via the network  98 , and the like will be denoted simply as “memory,” hereinafter. 
     Instructions for operating supplemental firing system  18 , duct burner system  38  and gas generator  40  can be stored in ROM  88 . Such instructions can include commands for opening and closing shut-off valve  56 B when supplemental firing system  18  comes on-line or goes off-line and commands for modulating valve  46 B to control the combustion process generated by duct burner system  38 . For example, the instructions can be configured to generate command signals for modulating valve  46 B based on input signals received from GT load sensor  58 A, GT exhaust flow rate sensor  58 B, GT exhaust temperature sensors  58 C and  58 D, HRSG steam temperature sensor  58 E and oxygen level sensor  58 F received by I/O port  90 . Likewise, the instructions can be configured to generate command signals for modulating valve  46 B based on output of oxygen being introduced into duct  52  by control device  44 A. 
     In additional examples, control device  44 B can be configured to operate gas generator  40 , such as to ensure that an adequate supply of hydrogen has H 2  can be supplied to duct burner system  38  for expected or forecast operation of GTCC power plant  10 . In an example, control device  44 B can operate gas generator  40  in real-time with operation of supplemental firing system  18  to provide a live supply of hydrogen gas while supplemental firing system  18  is operating. In other examples, control device  44 B can operate gas generator  40  intermittently to fill tank  42 B and as duct burner system  38  draws hydrogen gas from tank  42 B, such as below a threshold level, control device  44 B can initiate operation of gas generator  40  to fill tank  42 B. 
       FIG.  5    is a schematic line diagram illustrating methods of generating and combusting hydrogen fuel and oxygen in a duct burner of a combined-cycle power generation system. In an example, method  100  describes a method for operating duct burner system  38  and gas generator  40  of supplemental firing system  18  for heat recovery steam generator  14  according the present disclosure. 
     At step  102 , gas generator  40  can be operated to generate O 2  and H 2  gas. For example, gas generator  40  can receive instructions from one or more of control device  44 A, control device  44 B and controller  20  to initiate, sustain and cease generation of O 2  and H 2  gas. 
     At step  104 , gas generated by gas generator  40  at step  102  can be introduced into duct burner system  38  to provide low-emission or no-emission heat to exhaust gas E. 
     At step  106 . H 2  can be generated. In an example, gas generator  40  can comprise an electrolyser that generates H 2  gas. 
     At step  107 , the H 2  gas can be stored for use, either immediately or subsequently. In an example the H 2  gas can be stored in tank  42 B. Tank  42 B can act as an accumulator for storing of the H 2  gas when gas generator  40  is not operating. 
     At step  108 . O 2  can be generated. In an example, gas generator  40  can comprise an electrolyser that generates O 2  gas. In another example, oxygen from atmospheric or ambient air can be used as a source of O 2  gas. 
     At step  109 , the O 2  gas can be stored for use, either immediately or subsequently. In an example the O 2  gas can be stored in tank  42 A. Tank  42 A can act as an accumulator for storing of the O 2  gas when gas generator  40  is not operating. 
     At step  110 , the H 2  gas can be pressurized. In an example, the H 2  gas can be inherently pressurized as a result of the generation process at step  106 . In examples of gas generator  40  comprising an electrolyser, the H 2  gas can be inherently pressurized. In other examples, the H 2  gas produced at step  106  can be subsequently pressurized with another device, such as a pump or compressor. In yet other examples, pressurized H 2  gas can be delivered in tank  42 B to the site of combined-cycle power plant  10 . 
     At step  112 , the O 2  gas can be pressurized. In an example, the O 2  gas can be inherently pressurized as a result of the generation process at step  108 . In examples of gas generator  40  comprising an electrolyser, the O 2  gas can be inherently pressurized. In other examples, the O 2  gas produced at step  108  can be subsequently pressurized with another device, such as a pump or compressor. In yet other examples, pressurized O 2  gas can be delivered in tank  42 A to the site of combined-cycle power plant  10 . 
     As indicated, although steps  106 ,  108 ,  110  and  112  are indicated as separate steps, in examples, steps  106 ,  108 ,  110  and  112  can occur simultaneously with the operation of gas generator  40 . 
     At step  114 , flow of the H 2  gas can be modulated, such as by use of control device  44 B, to control the combustion process in duct  52  based on, for example, load of gas turbine  12 , flow rate of exhaust gas E, temperature of exhaust gas E and steam temperatures within HRSG  14 , as can be sensed via GT load sensor  58 A, and GT exhaust flow rate sensor  58 B. GT exhaust temperature sensors  58 C and  58 D upstream and downstream of duct burner  38 , HRSG steam temperature sensor  58 E and oxygen level sensor  58 F. 
     At step  116 , flow of the  02  gas can be modulated, such as by use of control device  44 A, to control the combustion process in duct  52  based on, for example, load of gas turbine  12 , flow rate of exhaust gas E, temperature of exhaust gas E, oxygen level of exhaust gas E, and steam temperatures within HRSG  14 , as can be sensed via GT load sensor  58 A, and GT exhaust flow rate sensor  58 B, GT exhaust temperature sensors  58 C and  58 D upstream and downstream of duct burner  38 , HRSG steam temperature sensor  58 E and oxygen level sensor  58 F. 
     At step  118 , the H 2  gas can be throttled via use of an expansion device such as a nozzle. Throttling of the H 2  gas can add heat to the H 2  gas to further increase the efficiency of steam production in HRSG  14 . For example, expansion device  48  can be utilized to throttle the H 2  gas before entering duct  52 , after exiting valve  46 B. In other examples, throttling of the H 2  gas can occur with nozzles, such as nozzle  76  of  FIG.  3   . 
     At step  120 , gas turbine  12  can be operated to produce exhaust gas E. As described, a fuel such as natural gas can be delivered to combustor  28  and mixed with ambient air compressed by compressor  26 . The high energy gas resulting from the combustion process can be used to turn turbine  30  and heat from exhaust gas E exiting therefrom can be used in an additional process to generate electricity with HRSG  14  and steam turbine  16 . 
     At step  122 , exhaust gas E can be directed into duct  52  of HRSG  14 . 
     At step  124 , the H 2  gas can be introduced into duct  52 , such as by use of manifold  62 B or manifold  72 . 
     At step  126 , the O 2  gas can be introduced into duct  52 , such as by use of manifold  62 A or manifold  72 . 
     At step  128 , the H 2  gas and the O 2  gas can be mixed, such as by using mixer  50 . Step  128  can be optional. Step  128  can additionally occur before steps  124  and  126 . 
     Mixed or independently introduced H 2  gas and O 2  gas can be distributed within duct  52  via manifolds  62 A,  62 B or  72  to allow for an even and sustainable combustion of H 2  within duct  52 . Baffle  78  can further be utilized to stabilize the combustion process by slowing the flow of exhaust gas E at manifolds  62 A.  62 B or  72 . 
     At step  130 , the H 2  gas can be ignited to burn with the O 2  gas, thereby producing heat. For example, excitor  70  can be activated by controller  20  to operate ignitors  68 A- 68 C, thereby causing a heat source to propagate combustion and flame within duct  52 . 
     At step  132 , heat from the combustion of the H 2  gas with the O 2  gas at step  130  can be used to generate steam, such as by heating water located in HRSG  14 . Heating of exhaust gas E with the combustion of the H 2  gas can increase the ability of HRSG  14  to turn steam turbine  16  without producing harmful emissions. 
     The invention disclosed here enables the HRSG duct burner to efficiently combust hydrogen by implementing a hydrogen-fueled duct burner that utilizes oxygen as an augmenting oxidant. The implementation of the aforementioned devices, systems and methods can allow for either one or a combination of the following: 
     1. Improved overall thermal cycle efficiency; 
     2. Lower emissions; and 
     3. Improved duct burner operating range and the operating range and ramping capabilities of the combined-cycle power plant. 
     VARIOUS NOTES 
     The above detailed description includes references to the accompanying drawings, which form a part of the detailed description. The drawings show, by way of illustration, specific embodiments in which the invention can be practiced. These embodiments are also referred to herein as “examples.” Such examples can include elements in addition to those shown or described. However, the present inventor also contemplates examples in which only those elements shown or described are provided. Moreover, the present inventor also contemplates examples using any combination or permutation of those elements shown or described (or one or more aspects thereof), either with respect to a particular example (or one or more aspects thereof), or with respect to other examples (or one or more aspects thereof) shown or described herein. 
     In this document, the terms “a” or “an” are used, as is common in patent documents, to include one or more than one, independent of any other instances or usages of “at least one” or “one or more.” In this document, the term “or” is used to refer to a nonexclusive or, such that “A or B” includes “A but not B,” “B but not A,” and “A and B,” unless otherwise indicated. In this document, the terms “including” and “in which” are used as the plain-English equivalents of the respective terms “comprising” and “wherein.” Also, in the following claims, the terms “including” and “comprising” are open-ended, that is, a system, device, article, composition, formulation, or process that includes elements in addition to those listed after such a term in a claim are still deemed to fall within the scope of that claim. Moreover, in the following claims, the terms “first,” “second,” and “third,” etc. are used merely as labels, and are not intended to impose numerical requirements on their objects. 
     Method examples described herein can be machine or computer-implemented at least in part. Some examples can include a computer-readable medium or machine-readable medium encoded with instructions operable to configure an electronic device to perform methods as described in the above examples. An implementation of such methods can include code, such as microcode, assembly language code, a higher-level language code, or the like. Such code can include computer readable instructions for performing various methods. The code may form portions of computer program products. Further, in an example, the code can be tangibly stored on one or more volatile, non-transitory, or non-volatile tangible computer-readable media, such as during execution or at other times. Examples of these tangible computer-readable media can include, but are not limited to, hard disks, removable magnetic disks, removable optical disks (e.g., compact disks and digital video disks), magnetic cassettes, memory cards or sticks, random access memories (RAMs), read only memories (ROMs), and the like. 
     The above description is intended to be illustrative, and not restrictive. For example, the above-described examples (or one or more aspects thereof) may be used in combination with each other. Other embodiments can be used, such as by one of ordinary skill in the art upon reviewing the above description. The Abstract is provided to comply with 37 C.F.R. § 1.72(b), to allow the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims. Also, in the above Detailed Description, various features may be grouped together to streamline the disclosure. This should not be interpreted as intending that an unclaimed disclosed feature is essential to any claim. Rather, inventive subject matter may lie in less than all features of a particular disclosed embodiment. Thus, the following claims are hereby incorporated into the Detailed Description as examples or embodiments, with each claim standing on its own as a separate embodiment, and it is contemplated that such embodiments can be combined with each other in various combinations or permutations. The scope of the invention should be determined with reference to the appended claims, along with the full scope of equivalents to which such claims are entitled.