System and method for model-based control of a gas turbine system considering fluid injection

Abstract

The system includes a gas turbine system having a compressor, a combustor, and a turbine. The system further includes a power management system configured to provide an injection fluid to a host fluid of the gas turbine system to manage power generation of the gas turbine system, the injection fluid including a gas mixture including oxygen. The system further includes a model-based controller configured to control operation of the gas turbine system, the model-based controller having one or more models that account for the injection fluid provided to the host fluid by the power management system.

Description

[Technical Field]

[0001] The subject matter disclosed herein relates to control of gas turbine systems, and more particularly, to control of gas turbine systems having fluid injection for power management. [Background technology]

[0002] Industrial machines, such as gas turbine systems, may be provided for generating power. For example, the gas turbine system may include a compressor that compresses a working fluid (e.g., air), a combustor that burns fuel with the compressed working fluid to generate hot combustion gases, and a turbine driven by the hot combustion gases to drive a load. The load may include a generator configured to generate power for a power grid. Thus, the gas turbine system may be part of a power plant. The power generated by the gas turbine system affects the efficiency of the power plant. Therefore, it would be beneficial to manage the power of the gas turbine system using fluid injection. However, the fluid mixture significantly affects combustion dynamics. In particular, introducing an oxygen-containing gas mixture into the main working fluid of the gas turbine can change the combustion dynamics. The oxygen-containing gas may be, for example, air, the gas turbine's combustion gas, or a mixture of air and combustion gas. Changes in the temperature and composition of the gas mixture reacted with fuel in the combustion chamber can cause vibrations, etc. There is a need for control of the gas turbine system that takes into account the injection of oxygen-containing gas, which can help control the operating parameters of the gas turbine system. [Prior art documents] [Patent documents]

[0003] [Patent Document 1] US Patent Application Publication No. 2019 / 0234303 Summary of the Invention

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

[0005] In some embodiments, a system includes a gas turbine system having a compressor, a combustor, and a turbine. The system further includes a power management system configured to provide an injection fluid to a host fluid of the gas turbine system to manage power generation of the gas turbine system, the injection fluid comprising a gas mixture including oxygen. The system further includes a model-based controller configured to control operation of the gas turbine system, the model-based controller having one or more models that account for the injection fluid provided to the host fluid by the power management system.

[0006] In some embodiments, a system includes a model-based controller configured to control operation of a gas turbine system coupled to a power management system. The gas turbine system has a compressor, a combustor, and a turbine. The power management system is configured to provide an injection fluid to a host fluid of the gas turbine system to manage power generation of the gas turbine system, the injection fluid including a gas mixture including oxygen. The model-based controller has a processor, a memory, and one or more models that account for the injection fluid provided to the host fluid by the power management system.

[0007] In some embodiments, a method includes controlling operation of a gas turbine system coupled to a power management system via a model-based controller. The gas turbine system has a compressor, a combustor, and a turbine. The power management system is configured to provide an injection fluid to a host fluid of the gas turbine system to manage power generation of the gas turbine system, the injection fluid including a gas mixture including oxygen. The model-based controller has one or more models that account for the injection fluid provided to the host fluid by the power management system.

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

[0009] [Figure 1] FIG. 1 is a block diagram of an embodiment of a gas turbine system coupled to a fluid injection power management system configured to supply an injection fluid to a host fluid of the gas turbine system, where a model-based controller takes into account injection fluid properties. [Figure 2] 2 is a block diagram of an embodiment of the model-based controller of FIG. 1, further illustrating refinements to the physics-based model controller and the regression-based model controller to take into account fluid injection characteristics. [Figure 3] 3 is a flowchart of an embodiment of a process suitable for upgrading the model-based controller of FIGS. 1 and 2. [Figure 4] 4 is a flowchart of an embodiment of a model-based control process for the gas turbine system of FIGS. 1-3 that takes into account fluid injection characteristics of the injection fluid. DETAILED DESCRIPTION OF THE INVENTION

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

[0011] When introducing elements of various embodiments of the invention, the articles "a," "an," "the," and "said" are intended to mean that there are one or more elements. The terms "comprising," "including," and "having" are intended to be inclusive and mean that there may be additional elements other than the listed elements. Furthermore, the term "or" is intended to be inclusive, indicating that A or B includes only A, only B, or both A and B.

[0012] The present disclosure generally relates to gas turbine systems that include fluid injection power management systems. During operation, the fluid injection power management system can inject fluid (e.g., an oxygen-containing gas mixture such as air, nitrogen, steam, water, or any combination thereof) through a compressor section to manage or control mass fluid flow within the gas turbine system. The added fluid can therefore provide additional rotational power for the gas turbine system. In some embodiments, the fluid injection power management system can use an electric compressor to inject fluid into the gas turbine system, thereby reducing the carbon footprint. In some embodiments, the fluid injection power management system can be retrofitted in-situ to an existing gas turbine system. That is, the fluid injection power management system can be provided as a retrofit kit that is installed and used to manage or control the power of an existing gas turbine system.

[0013] The technology described herein further includes embodiments of a model-based controller suitable for controlling a gas turbine system when a fluid injection power management system is in place. The model-based controller may include, for example, a computer simulation or model of the gas turbine system, the fluid injection power management system, and various subcomponents. The computer model may comprise one or more mathematical representations of operating parameters. Each of these representations may rely on input values ​​to generate estimates of the modeled operating parameters. The mathematical representations can generate surrogate operating parameter values ​​that can be used in situations where measured parameter values ​​are not available. The modeled operating parameters may include, but are not limited to, compressor airflow, combustor fuel / air ratio, light-off temperature, combustor flame temperature, fuel system pressure ratio, acoustic characteristics and combustion dynamics, hot gas flow through the turbine (e.g., combustion and / or exhaust gas flow), or any combination thereof. The computer model may be a physics-based aerothermodynamic computer model, a regression fitting model, a neural net model, or other suitable computer model, or combination thereof, of the gas turbine system, the fluid injection power management system, and various subcomponents. The computer model can receive several inputs that facilitate simulation and control, but when unexpected changes occur that are not accounted for by the computer model, the model-based controller may not be able to effectively and / or accurately control various operating parameters.

[0014] In embodiments disclosed herein, a model-based controller is modified to incorporate information regarding any fluid injections, such as compressed air injections from one or more external compressors, for power management of a gas turbine system. The fluid injections (e.g., compressed air injections) are separate from or in addition to compressed air from a main compressor of the gas turbine system. For example, one or more external compressors may provide fluid injection at one or more fluid injection points, such as one or more fluid injection points between the compressor discharge from the main compressor and the combustor, one or more fluid injection points along a compressor bleed line from the main compressor to the turbine, or any combination thereof. The fluid injections may include various characteristics, such as fluid composition, temperature, pressure, flow rate, injection location, or any combination thereof. Without the disclosed embodiments, the model-based controller may not know the specific details regarding any fluid injections (e.g., compressed air injections) for power management and may therefore aimlessly attempt to control the gas turbine system based on changes observed during operation of the gas turbine system. However, in the disclosed embodiments, the model-based controller is configured to receive and process information regarding the fluid injection (e.g., characteristics of the fluid injection) within the model-based controller, thereby adjusting the operation of the gas turbine system to account for the fluid injection. The information regarding the fluid injection may include information regarding ignition targets (e.g., ignition temperature, combustion gas temperature inside the combustor, turbine inlet temperature), combustion characteristics, combustion dynamics, exhaust gas emissions (e.g., nitrogen oxides, (NO X ), carbon oxides (CO X ), sulfur oxides (SO X), unburned hydrocarbons), component life and reliability, power output, efficiency, fuel flow to the fuel nozzles in the combustor, fuel split between the fuel nozzles, compressor bleed flow, inlet guide vane position, or any combination thereof. As described below, the model-based controller can process fluid injection information in combination with other flows (e.g., fluid injection flow combined with the main compressor flow entering the combustor), separately from other flows (e.g., fluid injection flow considered separate from the main compressor flow entering the combustor, fluid injection flow considered separate from the compressor bleed flow entering the turbine), or any combination thereof.

[0015] The model-based controller improved using information about the fluid injections may include one or more types of computer simulations or models, such as one or more physics-based models of the gas turbine system, one or more regression-based models, or a combination thereof. In some embodiments, the controller may use a physics-based model controller, which includes one or more physics-based models of the gas turbine system characteristics (e.g., thermodynamic properties), and the physics-based model controller is improved by inputting information about the fluid injections into the physics-based model. An example of a physics-based model is the Adaptive Real-Time Engine Simulator (ARES) model offered by General Electric Company of Schenectady, New York. In some embodiments, the controller may use a regression-based model controller, which includes one or more regression-based models of the gas turbine system characteristics, and the regression-based model controller is improved by inputting information about the fluid injections into the regression-based model. An example of a regression-based model includes a turbine inlet temperature (TIT) function, which may be modified to incorporate several fluid injection variables and used to improve control of the gas turbine system. The TIT may correspond to the combustion gas temperature at or upstream of the first stage nozzle of the turbine. However, a temperature function, such as a light-off temperature function, may be used for the combustion gas temperature immediately downstream of the turbine's first-stage nozzle. By incorporating fluid injection information as an input into a model-based controller, the techniques described herein may enable more efficient and improved power management or control of a gas turbine system. Disclosed embodiments of the model-based controller can model flow dynamics and predict changes in the ratio of the host stream to the oxygen-containing gas, as well as their temperature and pressure, over time as a function of operating parameters such as changes in control valve stroke, enabling much more accurate control of fast transient events. Model-predicted characteristics may be used to improve control of fast transient events.

[0016] 1 illustrates an embodiment of a power generation system 100 having a gas turbine system 102 including a controller 130 and a fluid injection power management system 150, where the controller 130 comprises a model-based controller having one or more computer models (e.g., physics-based models and / or regression-based models) that receive information about fluid injection by the fluid injection power management system 150 to improve control of the power generation system 100. In particular, the controller 130 (e.g., model-based controller) may receive monitored information about the fluid injection, such as injection location, fluid properties (e.g., temperature, pressure, flow rate, fluid composition), or any combination thereof. The computer models (e.g., physics-based models and / or regression-based models) use fluid information, independent and / or in combination with other fluid information, such as the main compressed air flow from the compressor 108, the compressor bleed air flow from the compressor 108 to the turbine 114, and / or the hot gas flow (e.g., combustion gas flow and / or exhaust gas flow) through the turbine 114, at the fluid injection point of the fluid injection power management system 150. Various details of the improved model-based control by controller 130 are described in further detail below.

[0017] 1 , the power generation system 100 may include a gas turbine system 102, a monitoring and control system 104, and a fuel supply system 106. The gas turbine system 102 may include a compressor section or compressor 108, a combustor section or combustor 110, one or more fuel nozzles 112, a gas turbine section or turbine 114, and an exhaust section 118. The compressor 108 may include one or more compressors or compressor stages, such as 1 to 30 compressor stages. In the illustrated embodiment, the compressor 108 is the main compressor of the gas turbine system 102. The combustor 110 may include one or more combustors, such as an annular combustor or multiple combustion cans arranged circumferentially around a central axis. The turbine 114 may include one or more turbines or turbine stages, such as 1 to 10 turbine stages.

[0018] During operation, the gas turbine system 102 may draw an oxidant (e.g., air 120) into the compressor 108, which may then compress the air 120 and move the air 120 to the combustor 110. The compressor 108 may further include inlet guide vanes (IGVs) 121, which are adjustable to regulate the intake of the oxidant into the compressor 108. In the combustor 110, a fuel nozzle 112 (or multiple fuel nozzles 112) may inject fuel that mixes with the compressed air 120 to create, for example, an air-fuel mixture. The air-fuel mixture may then be combusted in the combustor 110 to generate hot combustion gases, which flow downstream into and through the turbine 114 and drive one or more turbine stages. During operation, the combustion gases flow through the turbine 114 and may drive one or more stages of turbine blades, which in turn may drive the rotation of the shaft 122. The shaft 122 may be connected to a load 124, such as a generator, that uses the torque of the shaft 122 to generate electricity. After passing through the turbine 114, the hot combustion gases may be discharged to the environment via an exhaust section 118 as exhaust gases 126. In this description, the terms combustion gas stream and exhaust gas stream may be used interchangeably to refer to the hot combustion products produced in the combustor 110, which then flow downstream through the turbine 114 and various downstream equipment. The exhaust gases 126 may contain undesirable exhaust gas emissions, including carbon oxides (CO), such as carbon dioxide (CO) and carbon monoxide (CO). X ), nitrogen oxides such as nitrogen dioxide (NO2) X ), sulfur dioxide (SO2) and other sulfur oxides (SO X ), unburned hydrocarbons, etc. Improved control by the controller 130 incorporating information about fluid injection into the computer model is configured to help control exhaust gas emissions.

[0019] The exhaust gas 126 may contain thermal energy, which in some embodiments can be recovered by a heat recovery steam generation (HRSG) system 128 before being released to the environment through an exhaust stack 129. The HRSG system 128 includes multiple heat exchangers configured to transfer heat from the exhaust gas 126 to generate steam. In some embodiments, the HRSG system 128 may not be present. In embodiments with the HRSG system 128, the hot exhaust gas 126 from the gas turbine 114 flows through the HRSG system 128 to recover heat from the exhaust gas 126 and generate steam. For example, the heat from the exhaust 126 may be used to generate low-pressure steam, intermediate-pressure steam, and / or high-pressure steam. The steam generated by the HRSG system 128 can then flow through a steam turbine engine for further power generation. Additionally, the generated steam may be supplied to any other system of the power generation system 100, such as a gasifier used to gasify a feedstock to generate raw syngas, a gas processing system used to remove undesirable gases from the exhaust 126, or any combination thereof. In a "combined cycle" system, the gas turbine engine's generation cycle is often called the "topping cycle," and the steam turbine engine's generation cycle is often called the "bottoming cycle." In particular, waste heat from the topping cycle can be captured and used to generate steam for use in the bottoming cycle, thereby improving the efficiency of both cycles.

[0020] As described above, the power generation system 100 includes a controller 130, such as an electronic controller (e.g., a processor-based controller), configured to control the operation of the gas turbine system 102, the fluid injection power management system 150, and other components. The controller 130 may be communicatively connected to a number of sensors 132, a human-machine interface (HMI) operator interface 134, and one or more actuators 136 suitable for controlling the components of the power generation system 100. The actuators 136 may include valves, switches, positioners, pumps, etc. suitable for controlling various components of the power generation system 100. The controller 130 may receive sensor feedback from the sensors 132 and use the sensor feedback to control various components of the gas turbine system 102, including the compressor 108, the combustor 110, the turbine 114, the exhaust section 118, the load 124, the HRSG 128, the fluid injection power management system 150, etc. The sensors 132 may include temperature sensors, pressure sensors, flow sensors, fluid composition sensors, exhaust gas emissions sensors, vibration sensors, combustion dynamics sensors, or any combination thereof. The sensor feedback may include characteristics or properties of the fluid injection by the fluid injection power management system 150, such as the temperature, pressure, flow rate, fluid composition (e.g., gas composition, water content), injection location, or any combination thereof. As described in more detail below, the controller 130 (e.g., a model-based controller) is configured to input the fluid injection sensor feedback into a computer model (e.g., a physics-based model and / or a regression-based model) that is configured to adjust operating parameters of the gas turbine system 102 and the fluid injection power management system 150 to achieve various control objectives (e.g., ignition objectives, exhaust gas emissions, component life and reliability, combustion dynamics).

[0021] In certain embodiments, HMI operator interface 134 may be executable by one or more computer systems of power generation system 100. A plant operator may interface with power generation system 100 via HMI operator interface 134. Accordingly, HMI operator interface 134 may include various input / output devices (e.g., a mouse, keyboard, monitor, touch screen, or other suitable input / output devices) to enable the plant operator to provide commands (e.g., control commands and / or operational commands) to controller 130.

[0022] The controller 130 may include one or more processors 140 capable of executing software programs that perform the disclosed techniques, including the operation of computer models (e.g., physics-based models and / or regression-based models) to input sensor feedback related to fluid injection. For example, the one or more processors 140 may include one or more microprocessors, one or more “general-purpose” microprocessors, one or more special-purpose microprocessors, and / or one or more application-specific integrated circuits (ASICS), or a combination thereof. As a further example, the one or more processors 140 may include one or more reduced instruction set (RISC) processors. The controller 130 may include a memory device 142 that may store information such as control software, databases, lookup tables, configuration data, etc. The memory device 142 may include a tangible, non-transitory, machine-readable medium, such as volatile memory (e.g., random access memory (RAM)) and / or non-volatile memory (e.g., read-only memory (ROM), flash memory, a hard drive, or any other suitable optical, magnetic, or solid-state storage medium, or a combination thereof).

[0023] In the illustrated embodiment, the power generation system 100 includes a fluid injection power management system 150 (e.g., a gas injection power management system) configured to supply or inject an injection fluid (e.g., a power management fluid) into the gas turbine system 102 at one or more injection locations 151 via one or more conduits or piping 152. The injection location 151 may include one or more locations at or downstream of the compressor discharge of the compressor 108, such as a compressor discharge casing 154 between the compressor discharge and the combustor 110. The injection location 151 may include a location at or downstream of the combustor 110, such as in the flow of combustion gases generated by the combustor 110 and delivered to the turbine 114. The injection location 151 may include a location at the turbine 114, such as a turbine inlet for the combustion gases from the combustor 110, at or between turbine stages of the turbine 114, and / or at a compressor bleed flow entering the turbine 114 from the compressor 108. Thus, conduits or piping 152 may include a supply conduit fluidly coupling each injection location 151, where one or more valves 153 may be coupled to controller 130 to enable selective control of the injection fluid to each injection location 151. In some embodiments, conduits or piping 152 may include a compressor bleed conduit 155 from compressor 108 to turbine 114. Controller 130 is configured to control valves 153 to control the injection flow to injection locations 151, where controller 130 is further configured to receive sensor feedback regarding the properties of the injection fluid from sensors 132, as described above.

[0024] The injection fluid (e.g., power management fluid) injected by the fluid injection power management system 150 may include a compressed fluid, which is typically added to other fluids (e.g., host fluids) already flowing through the gas turbine system 102. For example, the injection fluid may include one or more compressed gases, such as an oxygen-containing gas mixture (e.g., air, oxygen-enriched air, oxygen-depleted air), an inert gas (e.g., nitrogen), exhaust gas recirculation (EGR), carbon dioxide, steam, or any combination thereof. An oxygen-containing gas mixture may include any one or more gases that contain oxygen. Thus, any description of an injection fluid (e.g., injection gas) is intended to include one or more of the non-limiting examples discussed above. As discussed above, sensor feedback from the sensors 132 may include fluid composition, temperature, pressure, flow rate, injection location, and other injection fluid properties. The sensor feedback from the sensors 132 may further include fluid composition, temperature, pressure, flow rate, and other characteristics of the host fluid of the gas turbine system 102 at the injection location 151 (e.g., compressed air from the compressor 108 to the combustor 110, compressor bleed air from the compressor 108 to the turbine 114, combustion gases in the turbine 114), so that the controller 130 can compare the host fluid to the injection fluid. During operation of the gas turbine system 102, the injection fluid may selectively flow (e.g., via control of a valve 153) through a conduit or piping 152 to the injection location 151 to mix with the host fluid, thereby providing power management for the gas turbine system 102. For example, the injection fluid may enter a compressor discharge casing 154, where the injection fluid may mix with a host compressed flow (e.g., host compressor air) from the compressor 108 prior to the combustor 110. Thus, the mass flow rate of the fluid (e.g., injected fluid added to the host compressed flow) increases within the various combustors 110, increasing the amount of hot discharge gas entering the turbine 114 and therefore increasing the power of the power generation system 100. The injected fluid may further enter one or more conduits or piping 152 (e.g., compressor bleed conduits 155) from the compressor 108 to the turbine 114, where the injected fluid may mix with the host compressor bleed flow (e.g., host compressor air) from the compressor 108 prior to the turbine 114.The injected fluid may further flow into one or more conduits or piping 152 fluidly coupled to the turbine 114, where the injected fluid may mix with the host hot gas flow (e.g., the combustion gas flow and / or the exhaust gas flow) through the turbine 114. Thus, the turbine 114 receives a greater mass flow rate with the addition of the injected fluid, increasing the power output of the turbine 114 by the power generation system 100.

[0025] In some embodiments, the fluid injection power management system 150 may include one or more compressors 156 configured to compress a fluid (e.g., gas) from one or more gas sources 157 (e.g., an air source, an inert gas source, a combustion and / or exhaust gas source). The one or more compressors 156 may include a rotary compressor and / or a reciprocating piston-cylinder compressor, which may be driven by an electric motor and / or a combustion engine (e.g., a reciprocating piston-cylinder engine). The compressor 156 is typically separate, independent, and / or auxiliary to the compressor 108 of the gas turbine system 102. For example, the compressor 156 may be described as a secondary and / or stand-alone compressor 156 to the gas turbine system 102. To operate with a low carbon footprint, the compressor may be driven by an electric motor and / or a combustion engine using one or more clean fuels, such as hydrogen. Power for the electric motor may include the use of renewable energy sources, such as a solar power system, a wind power system (e.g., a wind turbine), a hydrogen turbine power system, etc. Additionally, fluid injection power management system 150 may include a fluid storage vessel or tank 158, which may be used to store compressed fluid for injection (e.g., air, an inert gas such as nitrogen, or an oxygen-containing compressed gas mixture such as combustion and / or exhaust gases) as the injection fluid into gas turbine system 102 at various injection points 151. As described above, fluid injection power management system 150 may be provided as a retrofit kit and installed in an existing power generation system 100. Thus, controller 130 may include some control updates, or the control updates may be provided already built into the control package when power generation system 100 is provided from the manufacturer with fluid injection power management system 150 installed. The control updates may include model-based control updates, such as physics-based model updates, regression-based model updates, or any combination thereof.For example, the model-based control updates may include fluid injection updates that enable the model-based control to process sensor feedback regarding properties of the injected fluid provided by the fluid injection power management system 150. For example, at each possible injection location 151, the fluid injection updates may enable a computer model to incorporate properties regarding the injected fluid (e.g., fluid composition, temperature, pressure, flow rate, water content) alone or in combination with a host fluid (e.g., compressed air in the compressor discharge casing 154, compressor bleed air, combustion and / or exhaust gas flow) at the injection location 151. As an example of a regression-based model, an equation for determining turbine inlet temperature (TIT) may be shown below in equation (1):

[0026] (1) TIT = aTAT + bp c +c

[0027] where a, b, and c are constants, TAT is the turbine outlet temperature, and p c is the pressure at the compressor outlet. As an update, the regression-based model may be modified as shown in equation (2) below.

[0028] (2) TIT (corrected) = TIT + C*MFR + D*TR + E*PR + F*CR

[0029] where TIT corresponds to the original TIT formula of Equation (1), where C, D, E, and F are constants, MFR is the mass flow ratio of the inject fluid to the host fluid, TR is the temperature ratio of the inject fluid to the host fluid, PR is the pressure ratio of the inject fluid to the host fluid, and CR is the composition ratio of the inject fluid to the host fluid, where the inject fluid is the fluid injected into the gas turbine system 102 by the fluid injection power management system 150, and the host fluid is the main or existing fluid stream flowing within the gas turbine system 102 at the injection location 151. In some embodiments, the TIT(Modified) formula may include an additional ratio of a fluid property of the inject fluid to the host fluid, such as a moisture content ratio (MCR), an oxygen content ratio (OCR), a nitrogen content ratio (NCR), a content ratio of another specified gas, or any combination thereof. Additionally, in some embodiments, the TIT(Modified) formula may exclude one or more of the adjustments based on the MFR, TR, PR, and / or CR. For example, in some embodiments, the TIT(modified) formula may include one, two, or three adjustments to the original TIT formula in equation (1), as described in equations (3) and (4) below.

[0030] (3) TIT (corrected) = TIT + C*MFR + D*TR + E*PR + F*CR

[0031] (4) TIT (corrected) = TIT + C * MFR + D * TR

[0032] As previously shown in equation (3), the TIT(modified) equation may include only the original TIT equation in equation (1), along with adjustments based on MFR. As previously shown in equation (4), the TIT(modified) equation may include only the original TIT equation in equation (1), along with adjustments based on MFR and TR. In some embodiments, the combination of C*MFR+D*TR allows for adjustments to vary the average combustor inlet temperature due to gas injection. This change in inlet temperature causes a change in TIT, which is not accounted for in the original TIT equation. Considering only the absolute injected gas flow is not accurate because the compressor inlet mass flow rate varies with different ambient operating conditions and inlet guide vane positions.

[0033] FIG. 2 is a block diagram illustrating an embodiment of a physics-based model controller or control unit 200 (e.g., a model-based controller having one or more physics-based models) and / or a regression-based model controller or control unit 210 (e.g., a model-based controller having one or more regression-based models). In some embodiments, the physics-based model controller 200 and / or the regression-based model controller 210 may be included in the controller 130 and / or operably coupled to the controller 130 as part of a control system 202. The physics-based model controller 200 and / or the regression-based model controller 210 may include non-transitory code or instructions stored in a machine-readable medium (e.g., memory 142) and executed by a processor (e.g., processor 140) to implement the techniques disclosed herein. The control system 202 is configured to receive one or more inputs 204, such as infusion fluid properties 206 and host fluid properties 208, to refine the model-based control, as described in more detail below. Injection fluid properties 206 correspond to the injection fluid provided by fluid injection power management system 150, and host fluid properties correspond to the host fluid that receives the injection fluid. Injection fluid properties 206 and host fluid properties 208 may include mass flow rate, temperature, pressure, fluid composition, water content, or any combination thereof. Control system 202 is further configured to provide one or more outputs 224, such as gas turbine system control 226 for gas turbine system 102 and fluid injection control 228 for fluid injection power management system 150. For example, based on consideration of injection fluid properties 206 and host fluid properties 208, control system 202 may be configured to use model-based control, including modifications or upgrades described below, to improve control, such as gas turbine system control 226 and fluid injection control 228.

[0034] In some embodiments, the physics-based model controller 200 may use one or more physics-based models, such as an adaptive real-time engine simulator (ARES) model 212, which may be stored in memory 142 and used to simulate the operation of a system (e.g., the gas turbine system 102). Additionally, the disclosed physics-based model controller 200 may include one or more features of the gas turbine simulation and control system disclosed in U.S. Patent No. 7,742,904, entitled "METHOD AND SYSTEM FOR GAS TURBINE ENGINE SIMULATION USING ADAPTIVE KALMAN FILTER," which is incorporated herein by reference in its entirety for all purposes. Based on the output of the model (e.g., the ARES model 212), the physics-based model controller 200 may determine a number of parameters of the gas turbine system 102 that need to be adjusted (e.g., to improve or modify the performance of the gas turbine system 102). In some embodiments, the physics-based model controller 200 may be communicatively coupled to the controller 130 to receive information regarding the operation of the gas turbine engine system 102 (e.g., via the sensors 132). In such embodiments, the physics-based model controller 200 may further provide instructions to the controller 130 regarding one or more parameters of the gas turbine engine system 102 that may be adjusted based on the output of the model (e.g., the ARES model 212) to modify the operation of the gas turbine engine system 102.In some embodiments, the physics-based model controller 200 may be part of or function as the controller 130 (e.g., hardware, software, or a combination thereof), allowing the physics-based model controller 200 to communicate directly with sensors 132 and / or components (e.g., the compressor 108, the combustor 110, the turbine 114, the fluid injection power management system 150, or other suitable components) of the gas turbine system 102 to receive information and control the operation of the gas turbine system 102.

[0035] 1 , the ARES model 212 may simulate the operation of a model turbine system (e.g., a physics-based thermodynamic model of the gas turbine system 102). For example, the ARES model 212 may receive inputs regarding the operation of the gas turbine system 102 directly from the sensors 132 (e.g., via a network) or indirectly from another source (e.g., via the controller 130 or provided to an operator via the HMI 134). By way of particular example, the ARES model 212 may receive inputs from the sensors 132 including ambient conditions (A), the angle of the inlet guide vanes 121 (IGV), the amount of fuel (FUEL) flowing to the combustor 110, and / or the rotational speed (SPEED) of the gas turbine engine system 102 (e.g., RPM of the shaft 122). The ARES model 212 may output a modeled (M) power output (POW_M), such as power to the load 124, a modeled turbine exhaust temperature (EXHTEMP_MOD), and / or a modeled compressor 108 condition (C_M). The ARES model 212 may further include a Kalman filter embodiment to tune the ARES model 212 by incorporating tuning inputs, such as, for example, measured values ​​of power output (POW_A), measured values ​​of turbine exhaust temperature (EXTEMP_A), and measured values ​​of compressor condition (C_A). More specifically, the modeled values ​​may be compared to the measured values ​​to derive a difference between each value, which may then be used as an input to a Kalman filter gain matrix to generate an adjusted value of the normalized correction factor, which may then be used to tune the ARES model 212.

[0036] In the illustrated embodiment, the physics-based model controller 200 includes a fluid injection submodel 214. The fluid injection submodel 214 may model how the fluid provided by the fluid injection power management system 150 affects the gas turbine system 102. More specifically, the fluid injection submodel 214 may enable the ARES model 212 to take as input the mass flow rate of the injected fluid from the fluid injection power management system 150, the temperature of the injected fluid, the pressure of the injected fluid, the composition of the injected fluid, the water content of the injected fluid, or a combination thereof. The ARES model 212 may then use this added input to derive new outputs for the modeled power output (POW_M), the modeled turbine exhaust temperature (EXHTEMP_MOD), and / or the modeled compressor 108 conditions (C_M) via the physics-based thermodynamic model. For example, using the fluid injection submodel 214 in conjunction with the ARES model 212, the physics-based model controller 200 may receive and process information about the injection fluid (e.g., injection fluid properties 206) from the sensors 132 and / or HMI 134 and then use the information about the injection fluid independently and / or in combination with information about the host fluid (e.g., host fluid properties 208) to enable control adjustments for the gas turbine system 102. The host fluid may include a fluid stream that receives the injection fluid, such as a compressor discharge flow, a compressor bleed flow, a combustion and / or exhaust gas stream. In some embodiments, the fluid injection submodel 214, alone and / or in combination with the ARES model 212, may analyze the injection fluid and the host fluid as independent flows, combined flows, and / or ratios of various properties 206 and 208, enabling improved computer simulation of the gas turbine system 102, thereby improving control adjustments based on the injection fluid 206 properties (e.g., flow rate, pressure, temperature, fluid composition, water content).

[0037] The physics-based model controller 200 may then use the same inputs (e.g., ambient conditions (A), including the fluid injection power management system 150 ambient conditions, the angle of the inlet guide vanes 121 (IGVs), the amount of fuel (FUEL) flowing to the combustor 110, and / or the rotational speed (SPEED) of the gas turbine engine system 102) to derive new outputs incorporating the fluid injection submodel 214. The new outputs may be compared to measurements made of the actual power output, exhaust temperature, and / or compressor conditions, and the differences between the model outputs incorporating the fluid injection submodel 214 and the actual measurements may be used as inputs to a Kalman filter gain matrix to generate normalized correction factor adjustments, which are then used to adjust the ARES 212 and / or the fluid injection submodel 214. Thus, the fluid injection power management system 150 can be more optimally used with existing gas turbine systems 102.

[0038] In some embodiments, the regression-based model controller 210 can use the temperature function 216 (e.g., a “light-off” temperature function) to provide control through regression-based techniques rather than through physics-based modeling. For example, measurements of turbine inlet temperature (TIT), exhaust 118 temperature, etc., may be used to control the gas turbine engine system 102, for example, by adjusting fuel flow, air flow, etc. (e.g., via inlet guide vanes 121) to reach a desired reference temperature based on the temperature function 216. For example, the temperature function may be used to derive a temperature-based control curve, which is used to operate the gas turbine engine system 102 loaded, unloaded, and / or at base load. Instead of directly measuring combustion temperature, nozzle inlet temperature, etc., the temperature function 216 can use compressor discharge pressure, axial compressor discharge temperature, axial compressor inlet temperature, ambient temperature, etc. as inputs and derive a “light-off” temperature reference as an output, which is used to control the gas turbine engine system 102.

[0039] However, without the disclosed embodiments, the temperature function 216 and / or control curve would not incorporate information about the infusion fluid from the fluid infusion power management system 150. One approach would be to simply bias the temperature function 216 and resulting control curve by adding (or subtracting) a constant. Thus, the control curve may shift to the right or left (and / or up or down), but its shape and / or slope would be preserved. However, this simple bias can be improved by adding inputs including, for example, fluid properties of the infusion fluid supplied by the fluid infusion power management system 150, such as ambient conditions at the fluid infusion power management system 150, the injection location 151, and properties of the infusion fluid (e.g., mass flow rate, temperature, pressure, fluid composition, water content).

[0040] For example, the mass flow rate of the injection fluid provided by the fluid injection power management system 150 can be added to the mass flow rate of the host fluid at the injection location 151 to obtain a total mass flow rate that more closely approximates the actual flow. Depending on the injection location 151, the injection fluid may be injected into the compressor airflow (e.g., host fluid) discharged from the compressor 108 into the combustor 110, or the injection fluid may be injected into the compressor bleed flow (e.g., host fluid) from the bleed port of the compressor 108 to the turbine 114, or the injection fluid may be injected into the turbine 114 separately from the compressor bleed flow. The total combined flow (e.g., injection fluid plus host fluid) may be used as an input to the temperature function (216). In some embodiments, the fluid injection subfunction 218 may be used in the regression-based control 210. For example, fluid injection subfunction 218 may interface with temperature function 216 to add several values ​​to temperature function 216, such as the ambient temperature of fluid injection power management system 150, as well as properties of the injected fluid and host fluid (e.g., fluid composition, mass flow rate, pressure, temperature, water content). By adding properties of the injected fluid provided via fluid injection power management system 150, the techniques described herein may enable a regression-based control system to more efficiently use the added power. In some embodiments, the injected fluid and host fluid may be considered individually and / or as a ratio of each fluid property within temperature function (216) using fluid injection subfunction 218. As described above, Equation (2), Equation (3), or Equation (4) may be used in a modified turbine inlet temperature (TIT) function, which uses the injected fluid / host fluid ratio to incorporate the fluid injection properties and improve the accuracy of the TIT function.

[0041] 3 is a flowchart of an embodiment of a process 300 suitable for upgrading or otherwise manufacturing a control system 202, such as controller 130, which may include a physics-based model controller 200 and / or a regression-based model controller 210. In some embodiments, process 300 may be implemented as computer code or instructions stored in memory 142 and executed by processor 140. Process 300 may be performed in-situ on a controller already installed and operating a gas turbine system or on a controller provided as part of a new installation. That is, controller 130 may be upgraded in the field or may be upgraded via process 300 prior to installation at a new power plant site. In the illustrated embodiment, process 300 may determine (block 302) whether the control system (e.g., controller 130) being upgraded or manufactured has a physics-based controller and / or a regression-based controller.

[0042] If the controller being upgraded or manufactured is a physics-based model control 301 (e.g., physics-based model controller 200), process 300 may then use a physics-based model 304, such as ARES model 212. Additional modeling functionality may then be added (block 306). For example, physics-based model 304 may be adapted to incorporate fluid injection submodel 214, resulting in upgraded or modified physics-based model 308 having fluid injection submodel 214. The modified physics-based model 308 may further adapt and / or model the injected fluid provided by the fluid injection power management system 150 to better derive predicted outputs such as predicted turbine power, exhaust temperature, exhaust gas emissions, light-off temperature, combustion dynamics, combustion characteristics, turbine inlet temperature, component reliability and wear, and / or compressor conditions based on inputs such as ambient conditions (A), including the fluid injection power management system 150 ambient conditions, the angle of the inlet guide vanes 121 (IGV), the amount of fuel (FUEL) flowing to the combustor 110, and / or the rotational speed (SPEED) of the gas turbine engine system 102. The modified physics-based model 308 may then be used by the controller 130 to control the power generation system 100 using, for example, the physics-based model control as part of the updated model-based control 316.

[0043] If the process 300 determines (block 302) that the control to be upgraded or manufactured is a regression-based model control 303 (e.g., regression-based model controller 210), the process 300 may then use a regression-based model 310 (e.g., a temperature function), such as a turbine inlet temperature (TIT) function, an exhaust temperature function, and / or a combination thereof, and then add or otherwise update the regression-based model 310 (temperature function) to incorporate the characteristics of the injected fluid provided by the fluid injection power management system 150 (block 312). The result of the update or addition in block 312 is a modified regression-based model 314 (temperature function) that incorporates the fluid injection. For example, the additional information or parameters added to the regression-based model 310 (temperature function) may include characteristics of the injected fluid, including, but not limited to, fluid composition, temperature, pressure, mass flow rate, water content, or any combination thereof. As a further example, additional information or parameters added to the regression-based model 310 (temperature function) may include characteristics of the host fluid (e.g., discharge compressor flow, compressor bleed flow, combustion and / or exhaust gas flow) receiving the injected fluid, such that relative comparisons can be considered within the regression-based model 310 (temperature function). In some embodiments, as described above with reference to equations (2), (3), and (4), the regression-based model 310 (temperature function) may be modified to consider ratios of properties of the injected fluid to the host fluid, such as ratios of mass flow rate, temperature, pressure, water content, fluid composition, or any combination thereof. Fluid composition ratios may include ratios of oxygen content, nitrogen content, or other gas content. Similar ratios may be used to modify or refine other regression-based models for parameters of the gas turbine system 102. The updated regression-based model 314 (temperature function) using fluid injection may then be used by the controller 130 to control the power generation system 100, for example, using the regression-based model control as part of updated model-based control 316.

[0044] FIG. 4 is a flowchart of an embodiment of a model-based control process 320 for the gas turbine system 102 of FIGS. 1-3 . As shown, the process 320 includes operating the gas turbine system 102 (block 322), which may include a startup procedure, a steady-state procedure, a shutdown procedure, a part-load operating procedure, a full-load operating procedure, a grid stabilization procedure, or any combination thereof. In block 324, the process 320 further includes providing an injection fluid into a host fluid of the gas turbine system 102 at one or more injection points 151 for power management, as described in detail above. The injection points 151 may be in a compressor discharge casing, a bleed conduit, a turbine, or any combination thereof. Thus, the host fluid may include a main compressor flow to the combustor 110, a compressor bleed flow from the compressor 108 to the turbine 114, or a hot gas flow (e.g., a combustion gas flow and / or an exhaust gas flow) through the turbine 114.

[0045] At block 326, the process 320 includes modeling the gas turbine system 102, taking into account the properties of the injected fluid and the host fluid. The properties may include, for example, the mass flow rates of the injected fluid and the host fluid, fluid composition, temperature, pressure, water content, or any combination. As described in detail above, the modeling includes computer modeling using physics-based models, regression-based models, or any combination thereof. However, the modeling is refined or improved to model the impact of fluid injection on the operation of the gas turbine system 102. For example, the modeling may simulate or estimate the impact of the injected fluid properties independently of the host fluid, together with the host fluid, as a ratio of the injected fluid to the host fluid, or any combination thereof. The refined modeling with the injected fluid properties helps improve the computer model's ability to control the gas turbine system 102.

[0046] Thus, in block 328, the process 320 controls one or more operating parameters of the gas turbine system 102 based on the model (e.g., a physics-based model improved with the injected fluid information and / or a regression-based model). The control may include adjustments to fuel flow rate, fuel splitting among fuel nozzles, fuel type (e.g., liquid or gas fuel), fuel composition, inlet guide vane position, compressor bleed flow, combustor flame temperature, turbine inlet temperature, exhaust emissions, fluid injection via the fluid injection power management system 150, or any combination thereof. The process 320 further includes improving one or more aspects of the gas turbine system 102 based on the model (block 330). For example, by incorporating information about fluid injection into the model, the control of the gas turbine system 102 may provide more accurate control of the combustion process (e.g., combustion temperature), reduced undesirable exhaust emissions, increased efficiency and / or performance of the gas turbine system 102, improved speed regulation of the gas turbine system 102, and power generated by the generator, or any combination thereof.

[0047] Technical effects of the disclosed embodiments include a power generation system having a gas turbine system 102 and a fluid injection power management system 150, wherein the controller 130 (e.g., a model-based controller) is modified or improved to account for characteristics of an injection fluid used for power management. The model-based controller can include upgrades to one or more physics-based models, one or more regression-based models, or a combination thereof. The model-based controller can receive inputs regarding the injection locations 151, characteristics of the injection fluid provided by the fluid injection power management system 150 at the injection locations 151, and characteristics of a host fluid receiving the injection fluid at the injection locations 151. The model-based controller can analyze the characteristics of the injection fluid and the host fluid in combination with each other (e.g., as combined flows), independently of each other (e.g., as separate flows), as a ratio relative to each other, or any combination thereof. As described above, the fluid injection power management system 150 provides injection fluid into the gas turbine system 102 at various locations 151, thereby increasing mechanical power production. For example, the injection location 151 may include a compressor discharge casing, a compressor bleed conduit 155, or a supply conduit going into the turbine. The modified controller 130 enables improved model-based control of the gas turbine system 102 and the fluid injection power management system 150 by incorporating information about the injected fluid, not otherwise considered by the controller 130. Thus, the modified controller 130 may improve control of various operating parameters, including, but not limited to, ignition targets (e.g., ignition temperature, combustion gas temperature inside the combustor, turbine inlet temperature), combustion dynamics, and exhaust gas emissions (e.g., NO 2 ). X , CO X , SO X , unburned hydrocarbons), component life and reliability, power output, efficiency, or any combination thereof.

[0048] The subject matter detailed above may be governed by one or more of the provisions set out below.

[0049] Clause 1: In some embodiments, a system includes a gas turbine system having a compressor, a combustor, and a turbine. The system further includes a power management system configured to provide an injection fluid to a host fluid of the gas turbine system to manage or control power generation of the gas turbine system, the injection fluid comprising a gas mixture including oxygen. The system further includes a model-based controller configured to control operation of the gas turbine system, the model-based controller having one or more models that account for the injection fluid provided to the host fluid by the power management system.

[0050] Clause 2: The system of clause 1, wherein the one or more models include at least a physics-based model of the gas turbine system.

[0051] Clause 3: The system of clause 1 or 2, wherein the physics-based model includes a fluid injection model of the injection fluid supplied to the host fluid by the power management system.

[0052] Clause 4: The system of any one of clauses 1 to 3, wherein the physics-based model includes an Adaptive Real-Time Engine Simulator (ARES) model having the fluid injection model.

[0053] Clause 5: The system of any one of clauses 1 to 4, wherein the one or more models include at least a regression-based model of the gas turbine system.

[0054] Clause 6: The system of any one of clauses 1 to 5, wherein the regression-based model includes at least one fluid injection parameter related to the injection fluid supplied to the host fluid by the power management system.

[0055] Clause 7: The system of any one of clauses 1 to 6, wherein the regression-based model includes a turbine inlet temperature (TIT) function having the at least one fluid injection parameter.

[0056] Clause 8: The system of any one of clauses 1 to 7, wherein the one or more models include a ratio of one or more properties of the injection fluid to the host fluid.

[0057] Clause 9: The system described in any one of clauses 1 to 8, wherein the ratio of the one or more properties includes a fluid composition ratio of the injection fluid to the host fluid, a flow rate ratio of the injection fluid to the host fluid, a temperature ratio of the injection fluid to the host fluid, a pressure ratio of the injection fluid to the host fluid, a water content ratio of the injection fluid to the host fluid, or any combination thereof.

[0058] Clause 10: The system of any one of claims 1 to 9, wherein the one or more models take into account multiple fluid properties of the injected fluid, the multiple fluid properties including one or more of flow rate, fluid composition, fluid temperature, fluid pressure, water content, or any combination thereof.

[0059] Clause 11: The system of any one of clauses 1 to 10, wherein the power management system includes a tank of the injection fluid, an auxiliary compressor configured to compress the injection fluid, or a combination thereof.

[0060] Clause 12: The system of any one of clauses 1 to 11, wherein the power management system includes one or more fluid conduits coupled to a compressor discharge casing of the compressor, a compressor bleed conduit extending between the compressor and the turbine, or one or more stages of the turbine.

[0061] Clause 13: A system described in any one of clauses 1 to 12, wherein the one or more models are configured to input fluid injection characteristics of the injection fluid separately from host fluid characteristics, input fluid injection characteristics and host fluid characteristics in combination with each other, or a combination thereof.

[0062] Clause 14: The system of any one of clauses 1 to 13, wherein the model-based controller is configured to use the one or more models that take into account the injected fluid to adjust ignition temperature, combustion gas temperature, turbine inlet temperature, exhaust gas emissions, combustion dynamics, fuel flow, inlet guide vane position, compressor bleed flow, or any combination thereof.

[0063] Clause 15: In some embodiments, a system includes a model-based controller configured to control operation of a gas turbine system coupled to a power management system. The gas turbine system has a compressor, a combustor, and a turbine. The power management system is configured to provide an injection fluid to a host fluid of the gas turbine system to manage power generation of the gas turbine system, the injection fluid comprising a gas mixture including oxygen. The model-based controller has a processor, a memory, and one or more models that account for the injection fluid provided to the host fluid by the power management system.

[0064] Clause 16: The system described in clause 15, wherein the one or more models include a physics-based model of at least the gas turbine system, and the physics-based model includes a fluid injection model of the injection fluid supplied to the host fluid by the power management system.

[0065] Clause 17: The system described in clause 15 or 16, wherein the one or more models include at least a regression-based model of the gas turbine system, and the regression-based model includes at least one fluid injection parameter related to the injection fluid supplied to the host fluid by the power management system.

[0066] Item 18: The system of any one of items 15 to 17, wherein the one or more models include a ratio of one or more properties of the injection fluid to the host fluid, and the ratio of the one or more properties includes a fluid composition ratio of the injection fluid to the host fluid, a flow rate ratio of the injection fluid to the host fluid, a temperature ratio of the injection fluid to the host fluid, a pressure ratio of the injection fluid to the host fluid, a water content ratio of the injection fluid to the host fluid, or any combination thereof.

[0067] Clause 19: In some embodiments, a method includes controlling operation of a gas turbine system coupled to a power management system via a model-based controller. The gas turbine system has a compressor, a combustor, and a turbine. The power management system is configured to provide an injection fluid to a host fluid of the gas turbine system to manage power generation of the gas turbine system, the injection fluid comprising a gas mixture including oxygen. The model-based controller has one or more models that account for the injection fluid provided to the host fluid by the power management system.

[0068] Clause 20: The method of clause 19, wherein the one or more models include a physics-based model, a regression-based model, or a combination thereof, and the one or more models include a ratio of one or more properties of the injection fluid to the host fluid, and the ratio of the one or more properties includes a fluid composition ratio of the injection fluid to the host fluid, a flow rate ratio of the injection fluid to the host fluid, a temperature ratio of the injection fluid to the host fluid, a pressure ratio of the injection fluid to the host fluid, a water content ratio of the injection fluid to the host fluid, or any combination thereof.

[0069] The technology presented and claimed herein relates to and applies to tangible objects and specific examples of a practical nature that clearly improve the art, and is therefore not abstract, intangible, or mere theory. Furthermore, if any claim appended at the end of this specification contains one or more elements designated as "means for [performing] [a function]" or "steps for [performing] [a function]," such elements are intended to be construed under 35 U.S.C. §112(f). However, with respect to any claim containing elements designated in any other manner, such elements are not intended to be construed under 35 U.S.C. §112(f). [Explanation of symbols]

[0070] 100 Power Generation System 102 Gas Turbine System 104 Monitoring and Control Systems 106 Fuel Supply System 108 Compressor 110 Combustor 112 Fuel nozzle 114 Turbine 118 Exhaust Section 120 Air 121 Inlet guide vane (IGV) 122 Shaft 124 Load 126 Exhaust Gas 128 Heat Recovery Steam Generation (HRSG) Systems 129 Exhaust Stack 130 Controller 132 sensors 134 Human Machine Interface (HMI) Operator Interface 136 Actuator 140 processors 142 Memory Devices 150 Fluid Injection Power Management System 151 Injection position 152 Conduits or piping 153 Valve 154 Compressor discharge casing 155 Compressor bleed duct 156 Auxiliary compressor 157 Gas Source 158 Tank 200 Physics-based Model Controllers 202 Control System 204 Input 206 Injection fluid characteristics 208 Host Fluid Properties 210 Regression-Based Model Controller 212 Adaptive Real-Time Engine Simulator (ARES) Model 214 Fluid Injection Submodel 216 Temperature Function 218 Fluid Injection Subfunction 224 output 226 Gas Turbine System Control 228 Fluid Injection Control 300 processes Blocks 301-330

Claims

1. a gas turbine system (102) having a compressor (108), a combustor (110), and a turbine (114); a power management system (150) configured to provide an injector fluid to a host fluid of the gas turbine system (102) to manage power generation of the gas turbine system (102), the injector fluid comprising a gas mixture including oxygen; a model-based controller configured to control operation of the gas turbine system, the model-based controller including one or more models that account for the injection fluid provided to the host fluid by the power management system; System (100).

2. The system (100) of any preceding claim, wherein the one or more models include a physics-based model of at least the gas turbine system (102).

3. The system (100) of claim 2, wherein the physics-based model includes a fluid injection model (214) of the injection fluid provided to the host fluid by the power management system (150).

4. The system of claim 3 , wherein the physics-based model comprises an adaptive real-time engine simulator (ARES) model having the fluid injection model.

5. The system (100) of any preceding claim, wherein the one or more models include at least a regression-based model of the gas turbine system (102).

6. The system (100) of claim 5, wherein the regression-based model includes at least one fluid injection parameter related to the injection fluid provided to the host fluid by the power management system (150).

7. The system (100) of claim 6, wherein the regression-based model includes a turbine inlet temperature (TIT) function (216) having the at least one fluid injection parameter.

8. The system (100) of claim 1, wherein the one or more models include a ratio of one or more properties of the infusion fluid to the host fluid.

9. 9. The system (100) of claim 8, wherein the ratio of the one or more properties comprises a fluid composition ratio of the injectate fluid to the host fluid, a flow rate ratio of the injectate fluid to the host fluid, a temperature ratio of the injectate fluid to the host fluid, a pressure ratio of the injectate fluid to the host fluid, a water content ratio of the injectate fluid to the host fluid, or any combination thereof.

10. 2. The system (100) of claim 1, wherein the one or more models take into account a plurality of fluid properties of the injection fluid, the plurality of fluid properties comprising one or more of a flow rate, a fluid composition, a fluid temperature, a fluid pressure, a water content, or any combination thereof.

11. 2. The system of claim 1, wherein the power management system comprises a tank of the injectate fluid, a secondary compressor configured to compress the injectate fluid, or a combination thereof.

12. 2. The system of claim 1, wherein the power management system includes one or more fluid conduits coupled to a compressor discharge casing of the compressor, a compressor bleed conduit extending between the compressor and the turbine, or one or more stages of the turbine.

13. 2. The system (100) of claim 1, wherein the one or more models are configured to input fluid injection characteristics (206) of the injection fluid separately from host fluid characteristics (208), input the fluid injection characteristics (206) and the host fluid characteristics (208) in combination with each other, or a combination thereof.

14. 2. The system of claim 1, wherein the model-based controller is configured to use the one or more models that account for the injected fluid to adjust a light-off temperature, a combustion gas temperature, a turbine inlet temperature, an exhaust gas emission, combustion dynamics, a fuel flow, an inlet guide vane position, a compressor bleed flow, or any combination thereof.

15. a model-based controller (130) configured to control operation of a gas turbine system (102) coupled to a power management system (150), the gas turbine system (102) including a compressor (108), a combustor (110), and a turbine (114); the power management system (150) is configured to provide an injection fluid to a host fluid of the gas turbine system (102) to manage power generation of the gas turbine system (102), the injection fluid including a gas mixture including oxygen; and the model-based controller (130) including a processor (140), a memory (142), and one or more models that take into account the injection fluid provided to the host fluid by the power management system (150). System (100).

16. 16. The system (100) of claim 15, wherein the one or more models include a physics-based model of at least the gas turbine system (102), the physics-based model including a fluid injection model of the injection fluid provided to the host fluid by the power management system (150).

17. 16. The system (100) of claim 15, wherein the one or more models include a regression-based model of at least the gas turbine system (102), the regression-based model including at least one fluid injection parameter related to the injection fluid supplied to the host fluid by the power management system (150).

18. 16. The system (100) of claim 15, wherein the one or more models include a ratio of one or more properties of the injectate fluid to the host fluid, the ratio of the one or more properties including a fluid composition ratio of the injectate fluid to the host fluid, a flow rate ratio of the injectate fluid to the host fluid, a temperature ratio of the injectate fluid to the host fluid, a pressure ratio of the injectate fluid to the host fluid, a water content ratio of the injectate fluid to the host fluid, or any combination thereof.

19. controlling operation of a gas turbine system (102) coupled to a power management system (150) via a model-based controller (130), the gas turbine system (102) including a compressor (108), a combustor (110), and a turbine (114), the power management system (150) configured to provide an injection fluid to a host fluid of the gas turbine system (102) to manage power generation of the gas turbine system (102), the injection fluid including a gas mixture including oxygen, the model-based controller (130) including one or more models that take into account the injection fluid provided to the host fluid by the power management system (150); method.

20. 20. The method of claim 19, wherein the one or more models comprise a physics-based model, a regression-based model, or a combination thereof, and the one or more models comprise a ratio of one or more properties of the injectate fluid to the host fluid, the ratio of the one or more properties comprising a fluid composition ratio of the injectate fluid to the host fluid, a flow rate ratio of the injectate fluid to the host fluid, a temperature ratio of the injectate fluid to the host fluid, a pressure ratio of the injectate fluid to the host fluid, a water content ratio of the injectate fluid to the host fluid, or any combination thereof.

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