Gas turbine system with diffusion flame combustion and fuel mixing to reduce undesirable emissions - Patents.com

Abstract

A gas turbine system (1000, 2000, 3000) having a compressor section (10) configured to compress an oxidant stream and provide a compressed oxidant stream in a combustor section (20). The combustor section (20) is configured to receive an oxidant and a fuel gas mixture including at least a fuel gas and an inert gas separately, perform a diffusion flame combustion of the fuel and the oxidant in a combustion chamber, and provide a flue gas stream to a turbine section (30), which is configured to expand the flue gas stream and discharge the expanded flue gas stream at a turbine outlet. The gas turbine system also has a mixing unit (50) configured to mix at least the fuel gas and the inert gas and provide a fuel gas mixture in the combustor section (20) in a mixing ratio that depends on the flue gas content, for example on the measured or predicted NOx and / or CO and / or CO2 content of the flue gas. The mixing unit (50) is configured to mix at least the fuel gas and the inert gas under the control of a control unit (40) configured to control the operation of the gas turbine system.

Description

[Technical field]

[0001] The subject matter disclosed herein relates to a gas turbine system with diffusion flame combustion and fuel mixing to partially or completely reduce undesirable emissions, particularly NOx emissions, and possibly CO and / or CO2 emissions, by adjusting the fuel mix, which is advantageously based on the NOx and / or CO and / or CO2 content in the flue gas of the gas turbine system. [Background technology]

[0002] Conventional gas turbine engines operate by compressing an oxidizer, typically air, to high pressure, combusting a fuel with the oxidizer to generate a high-pressure, high-temperature flue gas stream, and then expanding the high-pressure, high-temperature flue gas stream through an expander to generate work and possibly electrical energy. Typically, gas turbine engines use as fuel natural gas, which is often primarily methane with much smaller amounts of slightly heavier hydrocarbons such as ethane, propane and butane, or liquefied petroleum gas, which is propane and / or butane with trace amounts of heavier hydrocarbons.

[0003] There are two types of gas turbine combustion systems: diffusion flames or premixed flames. In diffusion combustion systems, fuel and oxidant (e.g., air) are injected separately into the reaction zone of the combustor to produce a combustion that is completely or nearly stoichiometric. However, the fact that the combustion is completely or nearly stoichiometric in diffusion combustion systems makes it difficult (if not impossible) to control NOx emissions, especially the formation of "thermal NOx," which is formed from the oxidation of free nitrogen in the oxidant (e.g., air) or fuel. Thermal NOx is strongly dependent on the stoichiometric adiabatic flame temperature of the fuel, which is the temperature reached by burning a stoichiometric mixture of fuel and oxidant (e.g., air) in an insulated vessel, and more weakly dependent on the concentrations of oxygen and nitrogen.

[0004] In recent decades, emissions regulations have become more stringent to limit environmental damage. Attempts have been made to limit NOx emissions from diffusion flame combustion systems by adding water or steam directly to the reaction zone of the combustor to reduce the flame temperature. Other attempts have been made to remove NOx (and possibly CO and / or CO2) directly from the flue gas stream. For example, NOx emissions can be reduced by adding a selective catalytic reduction system downstream of the expander of a gas turbine system.

[0005] However, further tightening of emission requirements in recent years has led to the introduction and widespread use of premixed combustion systems such as Dry Low NOx (DLN) or Dry Low Emissions (DLE) combustors. In premixed combustors, fuel and oxidant (e.g. air) are mixed upstream of the reaction zone of the combustor and are therefore typically optimized for low NOx emission operation. For example, from EP 2204561 (A2) a system and method are known for mixing a secondary gas, e.g. alternative gas fuels such as hydrogen, ethane, butane, propane, LNG, or inert gases such as nitrogen and carbon dioxide, with a primary gas fuel, in particular natural gas, in a DLN gas turbine combustor. In these types of combustors, the amount of hydrogen mixed is limited due to the risk of flame instability and therefore a significant amount of natural gas is always present, resulting in significant CO and / or CO2 emissions. Premixed combustion therefore does not allow to reach a complete decarbonization of the system. Summary of the Invention [Problem to be solved by the invention]

[0006] However, even though conventional diffusion combustion systems may have NOx emission issues, at least in light of ever-increasing low emission requirements, they still offer greater fuel flexibility, greater flame stability, and lower (or even zero) CO and CO2 emissions than premixed combustors.

[0007] It would be desirable to have a gas turbine system with diffusion flame combustion that partially or completely reduces undesirable emissions, particularly NOx emissions and possibly CO and / or CO2 emissions.

[0008] In particular, it would be desirable to provide a solution that can provide greater fuel flexibility, greater flame stability, and lower CO and / or CO2 emissions than premixed combustors, for example a solution that can burn fuels with up to 100% hydrogen by volume (and e.g., up to 0% natural gas or another secondary fuel by volume). The hydrogen may be, for example, 50%, 60%, 70%, 80% or 90%, and may vary over time for different reasons.

[0009] In particular, it would be desirable to provide a solution that can be easily applied to gas turbine systems that are already installed and operating, so that these systems can comply with the more stringent emission requirements.

[0010] According to one aspect, the subject matter disclosed herein relates to a gas turbine system having a compressor section configured to compress an oxidant stream and provide a compressed oxidant stream at a combustor section, where a gas mixture of a fuel gas and an inert gas is further provided separately from the oxidant. The combustor section is configured to provide a flue gas stream to a turbine section configured to perform a diffusion flame combustion of the fuel and the oxidant in a combustion chamber, expand the flue gas stream and discharge the expanded flue gas stream at a turbine outlet. The gas turbine system also includes a mixing unit configured to mix at least the fuel gas and the inert gas and provide a gas mixture at the combustor section in a mixing ratio dependent on the content of the flue gas, e.g., on the NOx and / or CO and / or CO2 content of the flue gas. The mixing unit is configured to mix the fuel gas and the inert gas under the control of a control unit configured to control the operation of the gas turbine system.

[0011] Considering the possibility of retrofitting, such an innovative gas turbine system is particularly suitable for combusting air with hydrogen or a gas mixture containing hydrogen. Preferably, the inert gas is nitrogen or contains mainly nitrogen, since it is readily available and low cost. [Brief description of the drawings]

[0012] A complete understanding of the disclosed embodiments of the present invention and many of the attendant advantages thereof will be readily obtained as the same become better understood by reference to the following detailed description when considered in connection with the accompanying drawings, in which: [Figure 1] FIG. 1 is a simplified diagram of an embodiment of a gas turbine system having a fuel blend and a Continuous Emissions Monitoring System (CEMS). [Diagram 2] FIG. 2 is a simplified diagram of another embodiment of a gas turbine system having a fuel blend and a Predictive Emissions Monitoring System (PEMS). [Diagram 3] FIG. 3 is a simplified diagram of another embodiment of a gas turbine system having a fuel blend and predictive emissions monitoring system (PEMS) during a learning phase combined with a continuous emissions monitoring system (CEMS). DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0013] According to one aspect, the subject matter disclosed herein relates to a gas turbine system with diffusion flame combustion that allows for reducing undesirable emissions, particularly NOx emissions, and possibly CO and / or CO2 emissions, by mixing a fuel gas, for example hydrogen, with an inert gas, for example nitrogen, and possibly an additional fuel gas, for example natural gas. The amount of fuel gas, inert gas, and additional fuel gas in the gas mixture is controlled by a control unit that regulates the opening and closing of inlet valves that supply gas to the mixing unit. The mixing unit produces a gas mixture that is combusted with an oxidant, for example air, in a diffusion flame combustor of the gas turbine to produce flue gas, which is expanded in an expander of the gas turbine and typically drives equipment mechanically coupled to the gas turbine, for example a compressor or a generator. The flue gas may then be discharged to the atmosphere. To keep undesirable emissions (e.g., harmful emissions) low, the system is provided with a continuous emissions monitoring system, typically consisting of an arrangement of sensors, or a predictive emissions monitoring system, typically consisting of hardware and / or software analyzers, each of which measures or predicts the amounts of NOx and / or CO and / or CO2 in the expanding flue gas and provides the amounts to a control unit, which controls the content of the gas mixture based on the measured or predicted amounts.

[0014] Next, the embodiments of the present disclosure will be described in detail, and examples thereof will be illustrated in the drawings. The embodiments and drawings are provided as explanations of the present disclosure and should not be construed as limiting the present disclosure. In fact, it will be apparent to those skilled in the art that various modifications and variations can be made to the present disclosure without departing from the scope or spirit of the present disclosure. In the following description, similar reference numbers are used in the illustrations of the embodiment figures to indicate elements that perform the same or similar functions. Moreover, for clarity of illustration, some reference numbers may not be repeated in all figures.

[0015] 1 shows a simplified diagram of an embodiment of a gas turbine system with diffusion flame combustion and fuel mixing, generally designated by reference numeral 1000. The gas turbine system 1000 includes a compressor section 10, a combustor section 20, and a turbine section 30. Typically, the compressor section 10 and the turbine section 30 are mechanically coupled by a shaft 34. Advantageously, the shaft 34 is further mechanically coupled to a driven device 35, such as a compressor or a generator.

[0016] The compressor section 10 has a compressor inlet 11 and a compressor outlet 12 and is configured to receive an uncompressed oxidant stream, preferably air, more preferably ambient air at ambient pressure, at the compressor inlet, compress the oxidant, e.g., through one or more compressor stages, and provide a compressed oxidant stream at the compressor outlet 12. As will become apparent below, the compressed oxidant stream is then delivered to a combustor section 20 of the gas turbine system 1000.

[0017] The combustor section 20 has a combustor inlet 21 and a combustor outlet 22 and is configured to receive a compressed oxidant flow from the compressor section 10, and in particular from the compressor outlet 12. In other words, the combustor inlet 21 is fluidly coupled to the compressor outlet 12. The combustor section 20 is configured to perform a diffusion flame combustion of a fuel and an oxidant in a combustion chamber, the combustion chamber being fluidly coupled to the combustor inlet 21 for receiving the compressed oxidant and a fuel supply conduit 23 for receiving a fuel. As will be better explained below, the fuel received in the combustion chamber is a gas mixture of a fuel gas and an inert gas. The combustion occurring in the combustor section 20 generates a flue gas flow that is provided to the combustor outlet 22.

[0018] The combustor outlet 22 is fluidly coupled to a turbine section 30 having a turbine inlet 31 and a turbine outlet 32 ​​and configured to expand the flue gas stream, for example through one or more expansion stages, and discharge the expanded flue gas stream at the turbine outlet 32, which typically ends up in the atmosphere.

[0019] As already explained above, the combustor section 20 is configured to receive a gas mixture of at least a fuel gas and an inert gas, and the gas turbine system 1000 further comprises a mixing unit 50 configured to mix the fuel gas and the inert gas and provide the gas mixture to the combustor section 20. The mixing unit 50 has at least a fuel gas inlet 51, an inert gas inlet 52, and a gas mixture outlet 54, which is fluidly coupled to the fuel supply conduit 23 of the combustor section 20 to provide the gas mixture to the combustor section 20. In particular, the mixing unit 50 is disposed upstream of the combustor section 20.

[0020] According to a preferred embodiment, the fuel gas may be, for example, a gas mixture containing hydrogen or mainly hydrogen, for example containing at least 90% hydrogen (for example depending on the purity of the hydrogen fed to the mixing unit 50). According to a preferred embodiment, the inert gas may contain nitrogen and / or carbon dioxide and / or argon and / or helium and / or mixtures thereof. It is not excluded that H2O may be used as an "inert gas" (either alone or in combination with one or more other inert gases), preferably in the form of steam or sprayed or atomized water, even if it is less "inert". Preferably, the inert gas contains nitrogen or mainly nitrogen, for example containing at least 90% nitrogen (for example depending on the purity of the nitrogen fed to the mixing unit 50). For example, the inert gas may be nitrogen coming from an Air Separation Unit (ASU). By using a gas mixture containing hydrogen or mainly hydrogen as fuel gas, CO and CO2 emissions are very low (if not zero). This is not the case if natural gas or ammonia or LPG or biofuel or electric fuel or syngas is used instead as fuel.

[0021] There are many possibilities for the composition of the fuel gas mixture. According to a first possibility, the gas mixture fed to the combustor section 20 at a given time can, for example, substantially contain, for example, about 60% by volume of hydrogen and, for example, about 40% by volume of nitrogen. Advantageously, this composition of the gas mixture does not generate CO or CO2 in the flue gas, since the main product of this combustion is H20. It should also be noted that, in general, an increase in the inert components in the gas mixture can have a positive effect on the power output of the gas turbine system 1000, since it increases the expansion mass flow in the turbine section 30 (the inert gases are heated in the combustor section 20 and can expand in the turbine section 30), while the compression mass flow does not change (the amount of oxidant compressed by the compression section 10 does not change, since the inert gases do not affect the combustion reaction). According to certain operating conditions, if hydrogen is insufficient, the hydrogen content in the gas mixture may be, for example, less than 60% (e.g., if hydrogen is obtained from a renewable resource, especially an intermittent renewable resource), and additional fuel gas may be added to the gas mixture, as better explained below. According to other certain operating conditions, for example, at turbine start-up, additional fuel gas may be added to the gas mixture (or may completely replace hydrogen), as better explained below. It is noted that in general, the composition of the fuel gas mixture may not always be the same for different reasons (including that the composition is controlled by the control unit) and may vary from embodiment to embodiment.

[0022] As shown in Figures 1-3, the mixing unit 50, 150, 250 may further comprise an additional fuel gas inlet 53, 153, 253. For example, the additional fuel gas may contain natural gas and / or ammonia and / or liquefied petroleum gas (LPG) and / or biofuel (i.e., fuel produced from biomass) and / or electric fuel (i.e., fuel produced with fossil-free electricity or electricity derived from renewable sources) and / or syngas (i.e., gas mixture consisting mainly of hydrogen and carbon monoxide) and / or CO. The additional fuel gas may be mixed with the fuel gas and inert gas by the mixing unit 50, 150, 250, and the resulting gas mixture may be provided at the gas mixture outlet 54, 154, 254 of the mixing unit 50, 150, 250. The use of the additional fuel gas may be advantageous, especially during start-up of the gas turbine system 1000, 2000, 3000. For example, CO may react with O2 according to the following reaction: 2CO+O2→2CO2

[0023] With non-limiting reference to Figures 1-3, the gas turbine system 1000, 2000 and 3000 further comprises a control unit 40, 140, 240 configured to control the operation of the gas turbine system, in particular to control the opening and closing of the fuel gas regulating valves and the inert gas regulating valves of the mixing unit 50, 150, 250 and the additional fuel gas regulating valve (if additional fuel gas is provided). The mixing unit 50, 150, 250 produces a gas mixture under the control of the control unit 40, 140, 240. As will become clear from the following, the content of the flue gases at the turbine outlet 32, 132, 232, such as the content of NOx and / or the content of CO and / or the content of CO2, is measured and / or predicted and provided to the control unit 40, 140, 240. Advantageously, the control unit 40 adjusts the opening and closing of the regulating valves depending on the measured / predicted content of the flue gases. In other words, the gas mixture has a mixing ratio according to the measured / predicted content of the flue gases.

[0024] FIG. 1 shows an embodiment of the gas turbine system 1000 further comprising a continuous emission monitoring system (=CEMS) 70 fluidly coupled to the turbine outlet 32 ​​and configured to determine at least one parameter of the expanded flue gas stream at the turbine outlet 32. Typically, as already mentioned, the continuous emission monitoring system 70 consists of an arrangement of sensors capable of measuring one or more parameters to be controlled. Advantageously, the continuous emission monitoring system 70 can measure the amount of NOx in the expanded flue gas stream, and / or the amount of CO in the expanded flue gas stream, and / or the amount of CO2 in the expanded flue gas stream. The continuous emission monitoring system 70 can provide the parameter(s) to the control unit 40 which controls the operation of the gas turbine system 1000 based on the measured parameter(s), preferably at least the amount of NOx in the expanded flue gas stream and / or the amount of CO in the expanded flue gas stream and / or the amount of CO2 in the expanded flue gas stream. In particular, as previously mentioned, the control unit 40 may control the opening and closing of the regulator valve based on the parameter(s) detected by the continuous emissions monitoring system 70 .

[0025] Advantageously, the gas turbine system 1000 may further comprise instruments, in particular sensors, for measuring other parameters (which may also be fully or partially integrated in the mixing unit and / or in the compressor section and / or in the combustor section and / or in the turbine section), such as: Ambient pressure and temperature, and / or -expanded flue gas temperature, and / or Ambient relative humidity, and / or the pressure drop between the compressor inlet 11 and the ambient pressure, and / or the pressure drop between the turbine outlet 32 ​​and the ambient pressure, and / or the pressure and temperature of the oxidant (e.g. air) at the compressor outlet 12, and / or -flame temperature, and / or -flame stability and dynamics, and / or -Fuel composition and properties (pressure, temperature, Lower Heating Value (LHV), Modified Wobbe Index (MWI), combustion ratio...).

[0026] Advantageously, one or more of these other parameters can be provided to the control unit 40, which can take them into account to control the operation of the gas turbine system 1000, in particular to perform a trade-off between the amount of undesirable emissions (e.g. NOx and / or CO and / or CO2) and the gas turbine performance. Advantageously, the control unit 40 can also control the operation of the gas turbine system 1000, taking into account the ageing phenomena of the gas turbine system and / or the mechanical deterioration / wear of hot gas components (i.e. gas turbine components exposed to high temperature flows), for example based on predictions and gas turbine performance maps. The control unit 40 can further be connected to a fuel gas analyzer 60, which may be fluidly coupled to the gas mixture outlet 54, thereby providing information about the gas mixture at the gas mixture outlet 54. For example, the fuel gas analyzer 60 can measure the composition and properties specified above. Advantageously, the control unit 40 controls the content of the gas mixture further based on the information provided by the fuel gas analyzer 60.

[0027] Figure 2 shows another embodiment of a gas turbine system 2000 similar to the embodiment of Figure 1, but differing at least in that the parameter(s) of the expanded flue gas flow at the turbine outlet 132 are predicted instead of measured. The gas turbine system further comprises a predictive emission monitoring system 180 which receives information about the gas mixture at the gas mixture outlet 154 of the mixing unit 150. In particular, the predictive emission monitoring system 180 can be configured to receive at least the mixture ratio (e.g. of fuel and inert gas) or the content of the gas mixture (e.g. of fuel, inert gas and additional fuel) at the gas mixture outlet 154 of the mixing unit 150. Advantageously, information about the gas mixture (especially its content) is provided to the predictive emission monitoring system 180 by the control unit 140, which is connected to a fuel gas analyzer 160 fluidly coupled to the mixture outlet 154. In other words, the fuel gas analyzer 160 is configured to provide information about the gas mixture at the gas mixture outlet 154 (especially its actual content) to the control unit 140. Advantageously, the predictive emissions monitoring system 180 may be configured to receive information regarding the temperature and / or pressure of the gas mixture at the gas mixture outlet 154, which may be measured by the fuel gas analyzer 160 and provided to the control unit 140.

[0028] The predictive emissions monitoring system 180 is configured to predict, inter alia, based on information about the incoming gas mixture, at least one parameter of the expanded flue gas stream at the turbine outlet 32. Advantageously, the predictive emissions monitoring system 180 may predict the amount of NOx in the expanded flue gas stream and / or the amount of CO in the expanded flue gas stream and / or the amount of CO2 in the expanded flue gas stream.

[0029] The predictive emissions monitoring system 180 may provide parameter(s) to a control unit 140 that controls operation of the gas turbine system 2000 based on the predicted parameter(s), preferably based on at least the amount of NOx in the expanded flue gas stream and / or the amount of CO in the expanded flue gas stream and / or the amount of CO2 in the expanded flue gas stream. In particular, as previously mentioned, the control unit 140 may control the opening and closing of a regulator valve based on the parameter(s) predicted by the predictive emissions monitoring system 180.

[0030] Advantageously, the gas turbine system 2000 may further comprise equipment, in particular sensors, for measuring other parameters (which may also be fully or partially integrated into the mixing unit and / or the compressor section and / or the combustor section and / or the turbine section), such as: Ambient pressure and temperature, and / or -expanded flue gas temperature, and / or Ambient relative humidity, and / or the pressure drop between the compressor inlet 11 and the ambient pressure, and / or the pressure drop between the turbine outlet 32 ​​and the ambient pressure, and / or the pressure and temperature of the oxidant (e.g. air) at the compressor outlet 12, and / or -flame temperature, and / or -flame stability and dynamics, and / or -Fuel composition and properties (pressure, temperature, Lower Heating Value (LHV), Modified Wobbe Index (MWI), combustion ratio...).

[0031] Advantageously, one or more of these other parameters can be provided to the control unit 140, which can take them into account in controlling the operation of the gas turbine system 2000, in particular making a trade-off between the amount of undesirable emissions (e.g. NOx and / or CO and / or CO2) and the gas turbine performance. Advantageously, the control unit 140 can also control the operation of the gas turbine system 2000, taking into account ageing phenomena of the gas turbine system and / or mechanical degradation / wear of hot gas components (i.e. gas turbine components exposed to high temperature flows), for example based on predictions and gas turbine performance maps.

[0032] It should be noted that according to some embodiments, one or more emissions can be measured as shown in FIG. 1 and one or more emissions can be predicted as shown in FIG.

[0033] The embodiment of the gas turbine system 3000 of FIG. 3 is similar to the embodiment of FIG. 1 except that the predictive emissions monitoring system is configured to make predictions based on Artificial Intelligence (AI), and in particular comprises an artificial neural network configured to contribute to the predictions.

[0034] The predictive emissions monitoring system embodiment 280 is configured to be electrically coupled to a continuous emissions monitoring system 270 that is fluidly coupled to the turbine outlet 232 and has an input configured to measure the turbine emissions, in particular NOx emissions and / or CO2 emissions and / or CO emissions. Typically, the continuous emissions monitoring system 270 consists of an arrangement of sensors, in particular NOx meters and / or CO2 meters and / or CO meters. The system 270 and the connecting lines are depicted with dashed lines since the continuous emissions monitoring system may not be a permanent component of the gas turbine system and may only be present during the installation phase (e.g., during the first, e.g., 2-20 hours of operation) and / or during the initial operation phase (e.g., during the first, e.g., 200-2000 hours of operation) and / or during system operation checks. The AI-based predictive emissions monitoring system 280 may be configured to be set up (e.g., calibrated) at the factory and / or at installation and may be configured to be trained at the installation and / or during initial operation, the training being based on the emissions actually measured at the outlet of the gas turbine system.

[0035] According to some variations of the embodiment of FIG. 3, the continuous emissions monitoring system 270 may be permanently present and may be used for other purposes as well, for example to train the AI-based predictive emissions monitoring system 280.

[0036] The gas turbine system 1000, 2000, 3000 shown in Figures 1 to 3 can implement a method for reducing the content of undesirable emissions, such as harmful emissions, in particular NOx and / or CO and / or CO2, in the flue gas discharged from the turbine outlet 32, 132, 232 by adjusting the mixture ratio of the gas mixture of fuel gas and inert gas (and thus the content of the gas mixture of fuel gas, inert gas and additional fuel gas) supplied to the combustor section 20, 120, 220. As already mentioned, the content of NOx and / or CO and / or CO2 in the flue gas may be measured by the continuous emission monitoring system 70, 270 and / or predicted by the predictive emission monitoring system 180, 280, and the measured and / or predicted content is provided to the control unit 40, 140, 240 so that the mixture ratio or content of the gas mixture is adjusted by the control unit 40, 140, 240 (substantially in real time). However, the control unit 40, 140, 240 may also control the operation of the gas turbine system by optimizing other parameters, preferably by making a trade-off between the NOx and / or CO and / or CO2 content in the flue gas (maximum values ​​of which are regulated and vary from country to country) and the performance of the gas turbine system, such as power output and / or efficiency.

[0037] According to a first possibility, when the gas turbine system operating conditions are high temperature and high relative humidity of the ambient air (e.g. T=40° C., RH=0.85), the content of NOx and / or CO and / or CO2 in the flue gas is less than the content of NOx and / or CO and / or CO2 in the flue gas at ISO conditions (T=15° C., RH=0.6). The content of nitrogen in the gas mixture can therefore be reduced, which advantageously reduces the power output of the gas turbine system. According to another possibility, when the content of CO and / or CO2 in the flue gas increases, the power output can be kept substantially constant by increasing the hydrogen and nitrogen content in the gas mixture. According to another possibility, the volumetric content of inert gas can be increased up to the design limit of the diffusion flame combustion carried out by the combustor section of the system.

[0038] It should be noted that the gas turbine systems 1000, 2000, and 3000 disclosed herein may also be provided with other solutions and / or devices for reducing or eliminating pollutants in the exhaust gas, such as steam injection into the combustion chamber.

Claims

1. A gas turbine system (1000, 2000, 3000), a compressor section (10) having a compressor inlet (11) and a compressor outlet (12), the compressor section (10) configured to receive an uncompressed oxidant stream at said compressor inlet (11), compress said oxidant, and provide a compressed oxidant stream at said compressor outlet (12); a combustor section (20) having a combustor inlet (21), a combustor outlet (22) and a fuel supply conduit (23), said combustor inlet (21) being fluidly coupled to said compressor outlet (12), said combustor section (20) comprising a combustion chamber fluidly coupled to said combustor inlet (21), said combustor outlet (22) and said fuel supply conduit (23), said combustor section (20) configured for diffusion flame combustion of a fuel and an oxidant in said combustion chamber, and configured to provide a flue gas flow at said combustor outlet (22); a turbine section (30) having a turbine inlet (31) and a turbine outlet (32), said turbine inlet (31) fluidly coupled to said combustor outlet (22), said turbine section (30) configured to expand said flue gas flow and to discharge the expanded flue gas flow at said turbine outlet (32); a control unit (40) configured to control the operation of said gas turbine system (1000); Equipped with The gas turbine system (1000) further comprises a mixing unit (50) having a fuel gas inlet (51), an inert gas inlet (52), and a gas mixture outlet (54), the gas mixture outlet (54) being fluidly coupled to the fuel supply conduit (23) of the combustor section (20); The gas turbine system (1000) further comprises a fuel gas analyzer (60) configured to determine a content of the gas mixture at the gas mixture outlet (54) and provide the content to the control unit (40); The gas turbine system (1000, 2000, 3000), wherein the mixing unit (50) is configured to mix a fuel gas and an inert gas and provide a gas mixture at the gas mixture outlet (54) under the control of the control unit (40), the gas mixture having a mixing ratio that is dependent on the content of the flue gas.

2. The gas turbine system (1000, 2000, 3000) of claim 1, wherein the fuel gas is hydrogen or a gas mixture containing primarily hydrogen.

3. The inert gas may be nitrogen and / or carbon dioxide and / or argon and / or helium and / or H ２ 2. The gas turbine system (1000, 2000, 3000) of claim 1, wherein the inert gas comprises O and / or mixtures thereof, preferably the inert gas is nitrogen or a gas mixture mainly comprising nitrogen.

4. 2. The gas turbine system (1000, 2000, 3000) of claim 1, wherein the mixing unit (50, 150, 250) further comprises an additional fuel gas inlet (53, 153, 253), and the mixing unit (50, 150, 250) is configured to mix the fuel gas, the additional fuel gas and the inert gas and provide the gas mixture at the gas mixture outlet (54, 154, 254).

5. 5. The gas turbine system (1000, 2000, 3000) of claim 4, wherein the additional fuel gas comprises natural gas and / or ammonia and / or liquefied petroleum gas (LPG) and / or biofuel and / or electric fuel and / or syngas and / or CO.

6. 2. The gas turbine system of claim 1, further comprising a continuous emissions monitoring system configured to: measure at least one parameter of the expanded flue gas stream and provide the at least one parameter to the control unit, the at least one parameter being an amount of NOx in the expanded flue gas stream.

7. 7. The gas turbine system of claim 6, wherein the continuous emissions monitoring system is further configured to measure at least another parameter of the expanded flue gas stream and provide the at least another parameter to the control unit, the at least another parameter being an amount of CO and / or CO2 in the expanded flue gas stream.

8. 2. The gas turbine system of claim 1, further comprising a predictive emissions monitoring system configured to receive at least the mixing ratio or content of the gas mixture at the gas mixture outlet from the control unit, predict at least one parameter of the expanded flue gas stream, and provide the at least one parameter to the control unit, wherein the at least one parameter is an amount of NOx in the expanded flue gas stream.

9. 9. The gas turbine system of claim 8, wherein the predictive emissions monitoring system is further configured to predict at least another parameter of the expanded flue gas stream and provide the at least another parameter to the control unit, the at least another parameter being an amount of CO and / or CO2 in the expanded flue gas stream.

10. 10. The gas turbine system (1000, 2000, 3000) of claim 6, 7, 8 or 9, wherein the control unit (40, 140, 240) controls operation of the gas turbine system (1000, 2000, 3000) based on the at least one parameter that is measured or predicted.

11. 10. The gas turbine system (1000, 2000, 3000) according to claim 7 or 9, wherein the control unit (40, 140, 240) controls an operation of the gas turbine system (1000, 2000, 3000) based on the at least another parameter that is measured or predicted.

12. 2. The gas turbine system of claim 1, wherein the mixing unit comprises a fuel gas regulating valve and an inert gas regulating valve, and the control unit is configured to regulate opening and closing of the fuel gas regulating valve and the inert gas regulating valve.

13. 5. The gas turbine system of claim 4, wherein the mixing unit further comprises an adjusting valve for the additional fuel gas, and the control unit is configured to adjust the opening and closing of the adjusting valve for the additional fuel gas.

14. 10. The gas turbine system (3000) of claim 8 or 9, wherein the predictive emissions monitoring system (280) is configured to perform predictions based on artificial intelligence, in particular comprising an artificial neural network configured to contribute to the predictions.

15. a continuous emissions monitoring system (270) fluidly coupled to said turbine outlet (232) and electrically coupled to said predictive emissions monitoring system (280) and configured to measure turbine emissions; or an input configured to be electrically coupled to a continuous emissions monitoring system (270), said continuous emissions monitoring system (270) being fluidly coupled to said turbine outlet (232) and configured to measure turbine emissions; 15. The gas turbine system of claim 14, wherein the predictive emissions monitoring system is configured to be set up at a factory and / or at installation and configured to be trained at installation and / or during initial operation, the training being based on the measured emissions.

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