JP6626797B2 - Steam injection gas turbine and control method thereof - Google Patents

Description

  The present invention relates to a steam injection gas turbine, and more particularly, to a steam injection gas turbine for injecting a part of steam generated from exhaust heat of the gas turbine into the gas turbine and a control method thereof.

  As a method of reducing NOx discharged from a gas turbine, a method of generating steam using thermal energy of exhaust gas from a gas turbine and injecting the generated steam into a combustor to reduce a flame temperature and suppress generation of thermal NOx. There is. There is also a system for injecting generated steam into a combustor for the purpose of increasing the output of a gas turbine.

  Patent Literature 1 has two steam injection systems to a combustor, a first steam system for injecting steam upstream of a flame zone with respect to a flow of combustion gas in the combustor, and a downstream steam system for a downstream side of the flame zone. A second steam system for injecting steam, controlling a steam flow rate of the first steam system according to the flow rate and composition of the fuel, and a steam flow rate of the second steam system according to a required steam flow rate of the steam consuming equipment. The invention of a steam injection gas turbine for controlling pressure is disclosed.

  In this steam injection gas turbine, the steam injection of the first steam system has the above-described NOx reduction effect, and the steam injection of the second steam system has the effect of increasing the output. However, when such a steam injection gas turbine is started, steam may be condensed into drain water in a low-temperature steam piping system immediately after the start of steam injection. When this drain water is jetted out of the steam injection nozzle into the flame, there is a possibility that the stability of combustion is impaired.

  Patent Document 2 discloses a control of a steam injection system in a combined cycle power plant in which a drain generated in a steam injection piping system is positively removed at the time of start-up of the power plant so that stable combustion operation characteristics can be obtained. For the purpose of providing a method and an apparatus therefor, prior to the start-up of the gas turbine apparatus, drain water is supplied at the pressure of the auxiliary steam while warming up a steam piping system by supplying steam of a separate auxiliary boiler. The invention of discharging to the outside of the system is disclosed.

JP 2014-173572 A Japanese Patent Publication No. 7-30685

  As described above, in the conventional steam injection gas turbine, if the method of discharging the drain water generated at the time of startup to the outside of the system is adopted, the injected steam is drained until the steam injection system is completely warmed up. And is discharged. As a result, since no steam is supplied to the flame zone, the low NOx effect is reduced. Another problem is that a separate facility for treating the discharged drain water is required.

  The present invention has been made based on the above-described matter, and an object of the present invention is to provide a steam injection gas turbine capable of reducing NOx even at the time of startup and capable of downsizing a drain water treatment facility, and a control method thereof. Things.

In order to solve the above problem, for example, a configuration described in the claims is adopted. The present application includes a plurality of means for solving the above-described problems, but for example, a compressor that compresses air to generate high-pressure combustion air, and combusts the combustion air and fuel. A steam injection gas turbine for injecting steam into the combustor, comprising: a combustor for generating combustion gas; and a turbine driven by the combustion gas generated by the combustor, wherein the steam injection system includes two systems. And injecting the steam into a position where most of the injected steam mixes with the combustion air or the fuel on the upstream side of the flame zone with respect to the flow of the combustion gas in the combustor. In the steam system and downstream of the flame zone with respect to the flow of the combustion gas in the combustor, most of the injected steam is mixed with the combustion gas, and the remaining part of the steam is mixed with the combustion gas. flow On the other hand, on the upstream side of the flame zone, a second steam system that injects steam into a position where the steam is mixed with the combustion air, a steam flow rate of the first steam system, and a steam flow rate of the second steam system An individually controllable flow rate control mechanism, and a drain amount detection unit that detects an amount of drain water flowing into the combustor at the start of steam injection, wherein the drain amount detection unit detects a metal temperature of the combustor. A metal temperature measuring means for measuring; and a calculating part for calculating an amount of the drain water based on a metal temperature of the combustor measured by the metal temperature measuring means, wherein the flow rate control mechanism includes a drain amount detecting means. The steam flow rate of the two systems is controlled based on a signal indicating the amount of the drain water detected by the system.

  ADVANTAGE OF THE INVENTION According to this invention, when starting a steam injection gas turbine, reduction of NOx can be aimed at, maintaining combustion stability. In addition, the drain water treatment equipment can be downsized.

FIG. 1 is a system flow diagram showing an example of an overall configuration of a thermoelectric variable cogeneration system using a first embodiment of a steam injection gas turbine and a control method thereof according to the present invention. FIG. 3 is a characteristic diagram showing a behavior of a burner metal temperature at the time of startup in the first embodiment of the steam injection gas turbine and the control method thereof according to the present invention. FIG. 1 is a block diagram illustrating an example of a drain detection circuit at the time of startup in a first embodiment of a steam injection gas turbine and a control method thereof according to the present invention. FIG. 1 is a block diagram showing the configuration of a controller constituting a first embodiment of a steam injection gas turbine and a control method thereof according to the present invention. FIG. 3 is a characteristic diagram showing an output characteristic of a first steam amount with respect to a fuel flow rate in a first steam flow rate command calculation unit constituting the first embodiment of the steam injection gas turbine and the control method thereof according to the present invention. FIG. 2 is a characteristic diagram showing an output characteristic of a first steam amount with respect to an IGV opening degree in a first steam flow rate command calculation unit configuring the first embodiment of the steam injection gas turbine and the control method thereof according to the present invention. FIG. 2 is a characteristic diagram illustrating output characteristics of a first steam amount with respect to a rotation speed in a first steam flow rate command calculation unit included in the first embodiment of the steam injection gas turbine and the control method thereof according to the present invention. FIG. 3 is a characteristic diagram showing an output characteristic of a first steam amount with respect to a second steam amount in a first steam flow rate command calculation unit constituting the first embodiment of the steam injection gas turbine and the control method thereof according to the present invention. FIG. 3 is a characteristic diagram showing output characteristics of a second steam amount with respect to a steam pressure in a second steam flow command calculation unit constituting the first embodiment of the steam injection gas turbine and the control method thereof according to the present invention. FIG. 3 is a characteristic diagram illustrating output characteristics of a second steam amount with respect to a pressure ratio in a second steam flow command calculation unit that constitutes the first embodiment of the steam injection gas turbine and the control method thereof according to the present invention. It is a system flow figure showing an example of composition of a 2nd embodiment of a steam injection gas turbine and a control method of the present invention. It is a system flow figure showing an example of composition of a 3rd embodiment of a steam injection gas turbine of the present invention and its control method. It is a system flow figure showing an example of composition of a 4th embodiment of a steam injection gas turbine of the present invention and its control method. It is a system flow figure showing other examples of composition of a 4th embodiment of a steam injection gas turbine and a control method of the present invention.

  Hereinafter, embodiments of a steam injection gas turbine and a control method thereof according to the present invention will be described with reference to the drawings.

  FIG. 1 is a system flow diagram showing an example of the entire configuration of a thermoelectric variable cogeneration system using the first embodiment of the steam injection gas turbine and the control method thereof according to the present invention. As shown in FIG. 1, the thermoelectric variable cogeneration system mainly includes a steam injection gas turbine 4, an exhaust heat recovery boiler 5, and a steam system 300.

  Among them, the steam injection gas turbine 4 mainly includes a compressor 1 that compresses the air 100 to generate high-pressure combustion air 101, a combustion air 101 introduced from the compressor 1, and a fuel system 200. The combustion apparatus 2 includes a plurality of combustors 2 that combust fuel 201 to generate combustion gas 106 and a turbine 3 into which the combustion gas 106 generated by the combustor 2 is introduced.

  The turbine 3 is divided into a gas generator 3a and a power turbine 3b. The gas generator 3a is connected to the compressor 1 by a shaft 21a and drives the compressor 1. On the other hand, the power turbine 3b is connected to the generator 20 by the shaft 21b, and drives the generator 20.

  The combustor 2 is stored in a combustor casing 7 and a combustor cover 8. The combustor casing 7 is attached to the turbine casing 23. A fuel nozzle 9 is inserted at the center of the upstream end of the combustor 2, and a substantially cylindrical combustor liner 10 that separates unburned air and burned combustion gas is disposed downstream of the fuel nozzle 9. A liner flow sleeve 11 is provided on the outer peripheral side of the combustor liner 10. The liner flow sleeve 11 is substantially cylindrical and fastened to the combustor casing 7 so as to be substantially coaxial with the combustor liner 10.

  Downstream of the combustor liner 10 is a transition piece 12 that guides combustion gas to the turbine 3. The downstream end of the combustor liner 10 is inserted into the upstream end of the transition piece 12. A transition piece flow sleeve 13 is provided outside the transition piece 12. The downstream end of the liner flow sleeve 11 is inserted into the upstream end of the transition piece flow sleeve 13.

  At the downstream end of the axial center of the fuel nozzle 9, a thermocouple 27 for detecting a metal temperature is provided. The metal temperature signal detected by the thermocouple 27 is input to a controller 400 described later.

  The inlet of the compressor 1 is provided with an inlet guide vane (IGV) for adjusting the opening thereof to adjust the suction flow rate of the air 100. The inlet guide vane (IGV) is provided with an opening detector 19 for detecting the opening. The signal detected by the opening detector 19 is input to a controller 400 described later.

  The high-pressure combustion air 101 coming out of the compressor 1 flows from the space in the turbine casing 23 to the space between the transition piece 12 and the transition piece flow sleeve 13 from the opening on the turbine side (downstream side). Then, when flowing to the combustor liner side (upstream side), the transition piece 12 is cooled from the outside. Then, it flows toward the upstream side of the combustor through a substantially annular space between the combustor liner 10 and the liner flow sleeve 11. At that time, the combustor liner 10 is cooled from the outside.

  A part of the air (102) flows into the combustor liner 10 from the cooling holes provided in the combustor liner 10 as liner cooling air, and is used for film cooling. Another part of the air (103) flows into the combustor liner 10 as dilution air from the plurality of dilution holes 14 provided in the combustor liner 10, and mixes with the combustion gas 105 to enter the transition piece 12. Inflow.

  Further, another part of the air (110) flows into the combustor liner 10 from the plurality of combustion holes 30 provided in the combustor liner 10 as secondary combustion air, and cannot be completely burned by the combustion air 104. Used for combustion with fuel.

  The remaining air (104) flows into the combustor liner 10 from the swirler 17 provided on the outer periphery of the fuel nozzle 9 as combustion air, and is used for combustion together with the fuel ejected from the fuel nozzle 9. At this time, if the fuel flow rate is large, all of the injected fuel cannot be completely burned by the combustion air 104, so that the fuel is burned on the downstream side together with the secondary combustion air 110 described above.

  Then, the high-temperature combustion gas 105 is mixed with the liner cooling air 102 and the dilution air 103, and is sent to the turbine 3 as the combustion gas 106. After driving the gas generator 3 a of the turbine 3, the combustion gas 106 is sent to the power turbine 3 b as a gas generator exhaust gas 107. The low-pressure turbine exhaust gas 108 that has exited the power turbine 3b is recovered as heat by the exhaust heat recovery boiler 5 and then exhausted as exhaust gas 109.

  Here, the compressor 1 has a differential pressure detector 465 for detecting a differential pressure (pressure ratio) between the suction air pressure and the discharge air pressure, a pressure detector 462 for detecting the discharge air pressure, and a rotational speed of the compressor. And a compressor rotation speed detector 22 which is provided. Various signals detected by the differential pressure detector 465, the pressure detector 462, and the compressor speed detector 22 are input to a controller 400 described later.

  The fuel system 200 of the gas turbine is provided with a fuel flow control valve 202 and a fuel flow meter 203 that detects the flow rate of the fuel 201, and the power output of the steam injection gas turbine 4 is adjusted by adjusting the fuel flow rate. it can. The signal detected by the fuel flow meter 203 is input to a controller 400 described later.

Next, the steam system will be described.
The exhaust heat recovery boiler 5 includes a feed water heater 24, a boiler 25, and a steam superheater 26, and the generated steam is consumed by the steam consuming equipment 6 via the steam supply system 300. As the steam consuming equipment 6, equipment such as a factory that requires a heat source can be considered. A process steam flow control valve 313 is provided in the process steam pipe 303 for supplying steam to the steam consuming equipment 6, and controls the amount of steam to be sent.

  A steam pressure gauge 305 for detecting the pressure of the steam generated from the heat recovery steam generator 5 and a steam thermometer 306 for detecting the temperature of the steam are provided in the main pipe from the heat recovery steam generator 5. Further, a steam discharge system 304 is provided to discharge the steam generated by the exhaust heat recovery boiler 5 to the atmosphere as needed. A steam release valve 314 is provided in the pipe of the steam release system 304 to control the amount of released steam. Various signals detected by the steam pressure gauge 305 and the steam thermometer 306 are input to a controller 400 described later.

  On the other hand, when the amount of steam generated in the exhaust heat recovery boiler 5 exceeds the amount of steam required in the steam consuming facility 6, excess steam can be injected into the steam injection gas turbine 4. In the present embodiment, steam is injected into the combustor 2. The variable thermoelectric cogeneration system injects the surplus steam into the gas turbine and increases the output of the generator 20 to change the thermoelectric ratio.

  In the first embodiment of the steam injection gas turbine and the control method thereof according to the present invention, the injection steam system is divided into a first steam system 301 and a second steam system 302. Each system is provided with a first steam flow control valve 311 and a second steam flow control valve 312 so that each flow rate can be adjusted. An opening command is output from the controller 400 described later to the first steam flow control valve 311 and the second steam flow control valve 312.

  The first steam system 301 includes a steam pipe 321 having one end connected to the steam supply system 300 and the other end connected to a steam flange 351 provided on the combustor cover 8. A flow control valve 311 is provided. The first steam 331 passing through the inside of the first steam system 301 is injected into the inside of the combustor 2 from a steam nozzle 352 provided on the combustor cover 8.

  The injection position of the first steam 331 is on the upstream side of the flame zone with respect to the flow of the combustion gas 105, and is a position where most of the injected steam is mixed with the combustion air 104 or the fuel 201. More specifically, the fuel is injected into a space outside the combustor liner 10 and surrounded by the combustor casing 7, the combustor cover 8, and the combustor liner 10.

  The combustion air 104 at this position is air after the high-pressure combustion air 101 is branched off from the liner cooling air 102 and the dilution air 103, and most of the combustion air is consumed for combustion with the fuel. The first steam 331 mixed in the gas 104 has a great effect of lowering the temperature of the flame zone, and greatly contributes to the reduction of NOx.

  The second steam system 302 includes a steam pipe 322 having one end connected to the steam supply system 300 and the other end connected to a steam injection port 15 provided in the combustor casing 7. A steam flow control valve 312 is provided. The second steam 332 that passes through the inside of the second steam system 302 first flows through a substantially annular space between the combustor casing 7 and the liner flow through groove 11. This space and the space in the turbine casing 23 are separated by a partition wall 18. Thus, mixing of the steam flowing into the combustor and the compressed air in the turbine casing 23 is suppressed. Further, the steam flows over the entire area in the circumferential direction on the outer peripheral side of the liner flow sleeve 11. Therefore, even if there is only one steam injection port 15 for 71 combustor casings, it is possible to achieve uniform moisture in the combustor circumferential direction.

  The liner flow sleeve 11 is provided with a plurality of steam injection holes 16 in the circumferential direction. Further, all or a part of these faces all or a part of the dilution hole 14 provided in the combustor liner 10. Most of the steam having passed through the steam injection hole 16 facing the dilution hole 14 flows into the combustor liner 10 through the dilution hole 14. Therefore, most of the second steam 332, 332a, mixes with the combustion gas after the combustion on the downstream side of the flame zone with respect to the flow of the combustion gas.

  The injected steam mixes with the combustion gas 105 and the dilution air 103 after combustion, and thus does not directly affect the flame zone. Therefore, the output can be increased by injecting excess steam into the combustor 2 without affecting the stability of combustion. Further, since this injection position is on the upstream side of the turbine, the energy of the steam can be effectively converted into power by the turbine 3.

  Further, when the combustion gas 105 flows into the turbine, the temperature is reduced by mixing with the steam. Therefore, if the output is the same, the metal temperature of the transition piece 12 and the turbine 3 can be reduced, and the reliability and life can be improved. improves. Further, since the fuel flow rate for the steam mixture can be increased, the output and the efficiency can be improved by the amount of the mixed steam at the same turbine inflow temperature.

  Next, a method for controlling a steam flow rate in the first embodiment of the steam injection gas turbine and the control method therefor according to the present invention will be described with reference to FIGS. FIG. 2 is a characteristic diagram showing the behavior of the burner metal temperature at startup in the first embodiment of the steam injection gas turbine and the control method of the present invention, and FIG. 3 is a diagram of the steam injection gas turbine and the control method of the present invention. FIG. 3 is a block diagram illustrating an example of a drain detection circuit at the time of startup according to the first embodiment.

First, a method of controlling a steam flow rate during warming up of two steam systems while detecting a drain amount in two stages will be described, and then a method of controlling a steam flow rate after drain discharge is completed will be described.
When the steam injection gas turbine 4 starts and the turbine exhaust gas 108 shown in FIG. 1 is sent to the exhaust heat recovery boiler 5, steam starts to be generated. When the pressure detected by the steam pressure gauge 305 becomes higher than a predetermined pressure, first, the second steam flow control valve 312 of the second steam system 302 is opened to start injecting steam into the combustor 2. . Further, the process steam flow control valve 313 to the steam consuming facility 6 is opened to start feeding air to the steam consuming facility 6. When the air supply is started, the pressure detected by the steam pressure gauge 305 decreases.

  In order to maintain the steam pressure at a predetermined pressure, the gas turbine load command value or the rotation speed command value increases, and the fuel flow control valve 202 further opens. In this way, when controlling the fuel flow rate with the control target being to keep the steam pressure constant, the heat-based steam control in the thermoelectric variable cogeneration system is performed. In this case, since the power generation amount 20 changes, the difference from the power consumption amount is adjusted by the power transmission amount from the power system.

  On the other hand, when priority is given to controlling power over heat, such as when the thermoelectric variable cogeneration system is not connected to the power system, the fuel flow increases when the power request command value increases, and the steam flow increases. Pressure increases. As the steam pressure increases, the maximum steam amount that can be used in the steam consuming facility 6 also increases. Here, the steam pressure has been described as an example of the signal for starting the steam injection into the combustor 2, but the signal is not limited to this. For example, a preset fuel flow rate, power generation amount, compressor rotation speed, or the like may be used.

  By the way, at the start of the steam injection into the combustor 2, since the temperature of the second steam pipe 322 is low, the heat of the steam is deprived and a part of the steam becomes drain water in the second steam pipe 322. The generated drain water flows into the combustor from the steam injection port 15 and flows along with the flow of steam or air, and adheres to the outer wall surface of the combustor liner 10 and the wall surface of the fuel nozzle 9. If the drain water adheres, the metal temperature of the combustor liner 10 and the fuel nozzle 9 decreases. In the present embodiment, a thermocouple 27 is provided at the axial center downstream end of the fuel nozzle 9 as a fuel nozzle metal temperature detecting means to measure the burner metal temperature.

  The behavior of the metal temperature at the time of such startup will be described. In FIG. 2, the horizontal axis represents time, and the vertical axis represents burner metal temperature. Time t0 indicates a start time, and time t1 indicates a time when steam injection is started. As shown in FIG. 2, the burner metal temperature T tends to increase with time even when steam is not injected into the combustor 2 according to the start.

  At time t1, when the steam injection is started when the burner metal temperature T is T1, the burner metal temperature T decreases due to the attachment of the drain water to the burner 9, and the temperature becomes T0, which is the saturation temperature from T1.

  After time t1, the burner metal temperature T changes to T0 for a while until time t2, but after time t2, the burner metal temperature T starts to rise again. This is because the temperature of the second steam pipe 322 rises and the inflow of the drain water decreases, and the drain water that has flowed first flows down or evaporates, and the drain water disappears from the fuel nozzle 9. It is because. Therefore, the presence or absence of drain water can be detected by measuring the burner metal temperature T.

  An example of such a drain detection circuit at the time of startup will be described with reference to FIG. The drain detection circuit 450 is one circuit included in the controller 400 in the present embodiment. It is determined from the burner metal temperature that drain water has run out, and a signal for permitting the start of the next steam injection (the first steam flow control valve 311 of the first steam system 301 is opened to operate the combustor 2) (A signal for permitting the start of steam injection into the apparatus).

  As illustrated in FIG. 3, the drain detection circuit 450 includes a signal holding calculation unit 451, a saturated steam temperature calculation unit 452, a drain detection calculation unit 453, a timer calculation unit 454, and a logical product calculation unit 455. I have. Further, the drain detection circuit 450 includes a steam injection start signal 461 that becomes 1 when steam injection is started, a burner metal temperature signal detected by the thermocouple 27, and a compressor air pressure signal detected by the pressure detector 462. , A steam pressure signal detected by the steam pressure gauge 305, an air flow signal 463, and a steam flow signal 464. Also, the drain detection circuit 450 outputs a signal for permitting the start of steam injection, which is the next operation permission signal 476, to another circuit of the controller 400.

  The signal holding calculation unit 451 receives the steam injection start signal 461 and the burner metal temperature signal, and holds the burner metal temperature signal at the start of the steam injection. The held burner metal temperature signal 471 at the start of steam injection is output to the drain detection calculation unit 453. This burner metal temperature signal 471 corresponds to the burner metal temperature T1 at time t1 in FIG.

  The saturated steam temperature calculating section 452 receives the air pressure signal, the steam pressure signal, the air flow rate signal 463, and the steam flow rate signal 464, calculates the saturated steam temperature signal 472 therefrom, and calculates the drain detection calculating section 453. Output to This saturated steam temperature signal 472 corresponds to the burner metal temperature T0 in FIG. Here, the air flow signal 463 is, for example, a controller 400 that outputs a compressor speed signal detected by the compressor speed detector 22 and an opening signal of an inlet guide vane (IGV) detected by the opening detector 19. Etc. can be calculated. Further, the steam flow signal 464 may use first and second steam flow values 411 and 412 calculated by the controller 400 described later.

  The drain detection calculation unit 453 includes a burner metal temperature signal (T shown in FIG. 2) detected by the thermocouple 27 and a burner metal temperature signal 471 at the start of steam injection from the signal holding calculation unit 451 (T1 shown in FIG. 2). And the saturated steam temperature signal 472 (T0 shown in FIG. 2) from the saturated steam temperature calculating section 452, calculate the drain amount, and when it is determined that the drain water has run out, set the drain non-detection signal 474 to 1 The signal is output to the AND operation unit 455 as a signal.

  As shown in FIG. 2, first, the drain detection calculation unit 453 calculates ΔT by subtracting the saturated steam temperature T0 from the burner metal temperature T1 at the start of steam injection. Then, the ratio of the temperature difference obtained by subtracting the saturated steam temperature T0 from the current burner metal temperature T with respect to ΔT is calculated, and when the ratio exceeds a predetermined threshold 473, the drain non-detection signal 474 is set to 1. It is determined that the drain water has run out. In the present embodiment, the threshold 473 is set to 0.8. As a result, as shown in FIG. 2, until the time t3, the drain non-detection signal 474 is output as 0 with the drain amount large, and after the time t3, the drain non-detection signal 474 is output as the drain water is not detected.

  The timer calculation unit 454 receives the steam injection start signal 461 and outputs a predetermined time lapse signal 475 to the logical product calculation unit 455 when a preset time has elapsed. The reason for providing the timer calculation unit 454 is as follows. It is predicted that the above-mentioned decrease in the burner metal temperature due to the drain water occurs not only once but also several times intermittently. This can occur, for example, when the drain water starts to collect again in the middle of the low-temperature pipe from which the drain water has been discharged and is pushed out by the flow of steam.

  In this case, when it is determined that the drain water has run out at the timing when the burner metal temperature once rises again and the steam injection into the first steam system is started, but the drain water flows in again thereafter, the combustion is started. May cause instability. Therefore, in the present embodiment, the timer operation unit 454 sets the timer signal 475 to 0 output for a certain period of time after the start of steam injection, assuming that drain water may be present.

  The AND operation unit 455 receives the drain non-detection signal 474 from the drain detection operation unit 453 and the predetermined time lapse signal 475 from the timer operation unit 454, and outputs the next operation permission as an AND signal. The signal 476 is output. Therefore, for example, even if the drain non-detection signal 474 is 1, if there is no predetermined time elapsed signal from the timer calculation unit 454, the signal 476 permitting the start of the next steam injection is not output.

  Returning to FIG. 1, the method of controlling the steam flow rate in the present embodiment will be further described. Based on the output of the next operation permission signal 476 of the drain detection circuit 450 described above, it is determined that the drain water has run out, and then steam injection for opening the first steam flow control valve 311 of the first steam system 301 is started.

  The steam 331 of the first steam system 301 that has begun to flow first fills the steam header 350. Then, the steam is ejected from the steam nozzle 352 into the combustor, mixed with the combustion air 104, and used for combustion. By mixing the steam with the combustion air 104, the local temperature of the flame zone is reduced, and the generated NOx can be reduced.

  On the other hand, since the temperature of the combustor cover 8 is low at the time of startup, the heat of the steam is taken away, and a part of the steam becomes drain water in the steam header 350. The generated drain water accumulates at the lowermost portion of the steam header 350, flows into the combustor from the steam nozzle 352 by the pressure of the steam, and adheres to the wall surface of the fuel nozzle 9. When the drain water adheres, the burner metal temperature of the fuel nozzle 9 decreases again. The behavior of the burner metal temperature at this time is the same as that of FIG. 2, and the temperature in the first steam pipe 321 and the steam header 350 rises to reduce the inflow of the drain water. When the drain water disappears from the fuel nozzle 9 by flowing down or evaporating, the burner metal temperature gradually rises to the original temperature. Therefore, the drain detection circuit 450 described above can similarly detect the presence or absence of drain water. Note that the timer calculation unit 454 of the drain detection circuit 450 executes the trigger with the start of injection of the steam 331 of the first steam system 301 as a trigger.

  While drain water is being detected (the next operation permission signal 476 from the drain detection circuit 450 is 0), the opening of the first steam flow control valve 311 is smaller than the opening required for low NOx operation. Is also set small. This is to prevent a large amount of drain water from flowing in and to secure combustion stability.

  Finally, after confirming that the drain water has run out from the burner metal temperature, the first steam flow control valve 311 of the first steam system 301 is set to an opening required for low NOx control to suppress NOx emissions. . At this time, the temperature in the first steam pipe 321 and the steam header 350 is sufficiently high, and there is no drain water. Therefore, even if low NOx control is performed in the first steam system 301, the combustion is stable. Does not impair the performance.

  As described above, by starting the injection from the second steam system 302 first, it is possible to prevent the drain water from flowing from the first steam system 301 which greatly affects the combustion stability. Thus, it is possible to warm up the second steam system 302 while ensuring the stability of combustion at the start of steam injection. Next, by setting the flow rate of the first steam system 301 to a small amount and warming up the first steam system 301, the first steam system 301 after branching off from the second steam system 302 without impairing combustion stability. One steam system 301 can be warmed up. With the above means, the warm-up of the two steam systems is completed while detecting the drain amount in two stages.

  Next, a method of controlling the steam flow rate after the drain water is completely discharged will be described with reference to the drawings. FIG. 4 is a block diagram showing the processing contents of a controller constituting a first embodiment of the steam injection gas turbine and the control method of the present invention, and FIG. 5 is a block diagram of the steam injection gas turbine of the present invention and the control method thereof. FIG. 6 is a characteristic diagram showing an output characteristic of a first steam amount with respect to a fuel flow rate in a first steam flow rate command calculation unit constituting the first embodiment. FIG. FIG. 7 is a characteristic diagram showing an output characteristic of a first steam amount with respect to an IGV opening degree in a first steam flow rate command calculating unit constituting the embodiment; FIG. 7 is a first embodiment of a steam injection gas turbine and a control method thereof according to the present invention; FIG. 8 is a characteristic diagram showing an output characteristic of the first steam amount with respect to the number of revolutions in the first steam flow rate command calculation unit constituting the embodiment. FIG. Configure FIG. 9 is a characteristic diagram showing an output characteristic of the first steam amount with respect to the second steam amount in the first steam flow rate command calculation unit. FIG. 9 shows a first embodiment of a steam injection gas turbine and a control method thereof according to the present invention. FIG. 10 is a characteristic diagram showing an output characteristic of the second steam amount with respect to the steam pressure in the second steam flow rate command calculation unit. FIG. 10 shows a steam injection gas turbine according to the first embodiment of the present invention and a control method thereof. FIG. 9 is a characteristic diagram illustrating output characteristics of a second steam amount with respect to a pressure ratio in a second steam flow command calculation unit.

  As shown in FIG. 4, the controller 400 includes a first steam flow rate command calculation unit 401, a first steam flow rate control valve opening degree command calculation unit 402, a second steam flow rate command calculation unit 403, and a second steam flow rate command calculation unit 403. 404 and a drain detection circuit 450. The controller 400 also includes a fuel flow signal detected by the fuel flow meter 203, an opening signal of the inlet guide vane (IGV) detected by the opening detector 19, and a compressor detected by the compressor rotation speed detector 22. The rotation speed signal, the steam temperature signal detected by the steam thermometer 306, the steam pressure signal detected by the steam pressure gauge 306, and the differential pressure (pressure ratio between the suction air pressure and the discharge air pressure detected by the differential pressure detector 465) ) Signal is input. The controller 400 outputs an opening command 421 to the first steam flow control valve 311 and an opening command 422 to the second steam flow control valve 312, respectively.

  The first steam flow command calculation unit 401 receives a fuel flow signal, an IGV opening signal, and a compressor speed signal, and calculates a first steam flow command value signal 411 from these signals. More specifically, as shown in FIG. 5, with respect to the fuel flow rate, the first steam flow rate is set to increase as the fuel flow rate increases. As a result, an increase in the amount of NOx emission when the fuel flow rate increases can be suppressed.

  In addition, as shown in FIG. 6, the IGV opening is set such that the first steam flow rate decreases as the IGV opening increases. Similarly, as shown in FIG. 7, the first steam flow rate is set so as to decrease as the rotation speed increases with respect to the compressor rotation speed. When the IGV opening or the rotation speed increases, the combustion air may increase and the combustion may become unstable. On the other hand, by controlling in this way, it is possible to reduce the moisture content and maintain the combustion stability.

  The first steam flow command calculation unit 401 receives the next operation permission signal 476 from the drain detection circuit 450 and the second steam flow command value signal 412 from the second steam flow command calculation unit 403. . The relationship between the second steam flow rate command value signal 412 and the first steam flow rate command value signal 411 will be described later.

  The first steam flow control valve opening degree command calculation unit 402 receives the first steam flow command value 411, the steam temperature signal, and the steam pressure signal from the first steam flow command calculation unit 401, and receives the first steam flow signal. An opening command signal 421 for the flow control valve 311 is calculated. By reflecting the steam temperature signal and the steam pressure signal in the calculation, the flow rate of the steam can be controlled with higher accuracy.

  The second steam flow command calculation unit 403 receives the steam pressure signal and the pressure ratio signal, and calculates a second steam flow command value signal 412 from these signals. More specifically, the steam pressure is set as shown in FIG. 9, and the pressure ratio is set as shown in FIG.

  The second steam flow control valve opening degree command calculation unit 402 receives the second steam flow command value 412, the steam temperature signal, and the steam pressure signal from the second steam flow command calculation unit 403, and inputs the second steam flow signal. An opening command signal 422 for the flow control valve 312 is calculated. By reflecting the steam temperature signal and the steam pressure signal in the calculation, the flow rate of the steam can be controlled with higher accuracy.

The second steam flow command calculation unit 403 will be described by way of example of a control method for increasing excess power by injecting excess steam that cannot be consumed by the steam consuming facility 6 into the steam injection gas turbine 4.
As shown in FIG. 9, the second steam flow command calculation unit 403 starts the opening operation of the second steam flow control valve 312 when the steam pressure increases and reaches a predetermined value, and thereafter, the steam The second steam flow command value 412 is set so that the pressure 305 is substantially constant. As a result, even when the fuel flow rate 203 changes and the amount of steam generated in the exhaust heat recovery boiler 5 changes, or even when the amount of steam used in the steam consuming equipment 6 changes, the steam pressure is reduced. Can be kept constant.

  Further, the second steam flow command calculation unit 403 limits the maximum value of the second steam flow command value 412 based on the pressure ratio as shown in FIG. Thus, it is possible to prevent the second steam flow rate from becoming too large, so that the pressure ratio of the steam injection gas turbine 4 becomes high, and the compressor surge margin becomes too small.

  As described above, according to the present embodiment, when the amount of steam required in the steam consuming facility 6 changes, the amount of steam injected into the steam injection gas turbine 4 is changed to change the thermoelectric ratio. In operation, NOx emissions can be minimized while maintaining stable combustion.

  Lastly, control of the first steam flow rate in consideration of the second steam flow rate will be described. In the second steam 332 shown in FIG. 1, a part (322b) of the second steam other than most of the steam 332a flowing into the combustor liner 10 from the dilution hole 14 is the secondary combustion air 110 and the combustion air. Mixing with NO. 104 for use in combustion contributes to a reduction in NOx emissions. At that time, when the flow rate of the second steam 332 increases or decreases, the flow ratio of most of the steam 332a to a part of the steam 332b contributing to the reduction of NOx, and the respective flow rates increase or decrease.

  In this embodiment, even if the flow rate of the second steam 332b contributing to the reduction of NOx is increased or decreased, the first steam flow rate shown in FIG. The signal of the second steam flow command value 412 is input to the command calculation unit 401, and as shown in FIG. 8, the first steam flow command value is controlled based on the second steam flow command value.

  Specifically, the first steam flow rate command value is gradually decreased with the increase of the second steam flow rate command value, and when the second steam flow rate command value is excessive, the first steam flow rate command value is decreased. Set to 0. Thus, the moisture contained in the combustion air 104 and the secondary combustion air 110 is controlled to be appropriate. With this control, even when the second steam flow rate increases or decreases, low NOx and stable combustion can be maintained. Further, within the limit value, the low NOx combustion can be maintained as described above according to the change in the fuel flow rate and the air flow rate independently of the increase and decrease in the second steam flow rate.

  Furthermore, even when the demand for heat in the steam consuming equipment 6 increases and the second steam flow rate decreases, the first steam is mixed into the combustion air 104, so that the NOx can be reduced only by the second steam. Since the amount of steam required for lowering NOx can be reduced as compared with the case where the temperature is reduced, more heat demand can be met.

  As described above, according to the present embodiment, when the consumption of steam is small, the thermoelectric variable cogeneration system in which excess steam is injected into the combustor to increase the amount of power generation while also suppressing NOx emissions. In the system, even if a part of the second steam is mixed with the combustion air to reduce the NOx, it is possible to prevent the flame from extinguishing against changes in the fuel flow rate, the air flow rate, and the second steam flow rate. NOx and a stable and highly reliable gas turbine can be supplied.

  In addition, a large amount of excess steam can be injected into the combustor, and the range of change in the thermoelectric ratio can be increased, thereby improving usability. Conversely, even when the consumption of steam is large and the amount of steam that can be injected into the combustor is small, the first steam can be mixed with the combustion air 104 having high sensitivity to the amount of generated NOx, so that the low NOx effect is reduced. Can be maintained.

  Furthermore, in comparison with the treatment after discharging the high-temperature drain water out of the system, the equipment for treating the high-temperature water can be reduced, and the thermal energy of the drain water can be used internally, thus saving energy. Also.

  According to the above-described first embodiment of the steam injection gas turbine of the present invention and the control method therefor, when starting up the steam injection gas turbine 4, it is possible to reduce NOx while maintaining combustion stability. In addition, the drain water treatment equipment can be downsized.

  Hereinafter, a second embodiment of a steam injection gas turbine and a control method thereof according to the present invention will be described with reference to the drawings. FIG. 11 is a system flow diagram showing an example of the configuration of the second embodiment of the steam injection gas turbine and the control method thereof according to the present invention. 11, the same reference numerals as those shown in FIGS. 1 to 10 denote the same parts, and a detailed description thereof will be omitted.

  The second embodiment of the steam injection gas turbine and the control method thereof according to the present invention shown in FIG. 11 is constituted by substantially the same equipment as the first embodiment, but differs in the following constitution. In the present embodiment, one end of a drain water communication pipe 353 communicating with the steam header 350 is connected to the lowermost portion of the steam header 350. A water spray nozzle 354 is attached to the other end of the drain water communication pipe 353. The water spray nozzle 354 opens toward an annular space between the combustor liner 10 and the liner flow sleeve 11.

  In the present embodiment, the drain water generated at the start of the steam injection accumulates at the lowermost portion of the steam header 350, flows through the drain water communication pipe 353 due to the pressure of the steam, and jets out as fine water droplets from the water spray nozzle 354. . Since the ejection position is the annular space between the combustor liner 10 and the liner flow sleeve 11, the gas evaporates in the process of mixing with the combustion air 104 flowing therethrough. As a result, when used for combustion in the combustor liner 10, the flame temperature is reduced, which is effective in suppressing NOx.

  Unlike the steam nozzle 352, the water spray nozzle 354 can spray water into fine droplets. Therefore, as compared with the case where the drain water is ejected from the steam nozzle 352, the evaporation is faster, and the possibility that the drain water reaches the flame as a liquid and impairs the combustion stability can be reduced.

  From this, even if the opening degree of the first steam flow control valve 311 at the start of steam injection is set to be larger than that in the first embodiment, the possibility of impairing combustion stability can be reduced. . As a result, the drain water is discharged earlier, so that the starting time can be shortened.

  In the first embodiment, the burner metal temperature is used as the drain amount detecting means. In the present embodiment, a thermocouple is provided in the water spray nozzle 354 to use the metal temperature of the water spray nozzle 354. You can also. The metal temperature of the water spray nozzle 354 is close to the saturation temperature of the drain water during drain discharge, and close to the steam supply temperature when drain water is exhausted. Therefore, in the first embodiment, the description has been given based on the burner metal temperature. The drain detection control can be similarly performed based on the metal temperature of the water spray nozzle.

  Further, since the water spray nozzle 354 is located farther from the flame than the burner, the burner metal temperature is more suitable for determining the combustion stability by drain water. However, since the water spray nozzle 354 is not directly exposed to a high-temperature flame, there is an advantage of using the water spray nozzle metal temperature in extending the life of the drain amount detecting means.

  According to the above-described second embodiment of the steam injection gas turbine and the control method of the present invention, the same effects as those of the above-described first embodiment can be obtained.

  Further, according to the above-described second embodiment of the steam injection gas turbine and the control method of the present invention, the drain water communication pipe 353 and the water spray nozzle 354 are provided, so that the evaporation of the drain water can be accelerated. it can. This can reduce the possibility of impairing combustion stability due to the start of steam injection.

  Hereinafter, a third embodiment of the steam injection gas turbine and the control method thereof according to the present invention will be described with reference to the drawings. FIG. 12 is a system flow diagram showing an example of the configuration of the third embodiment of the steam injection gas turbine and the control method thereof according to the present invention. 12, the same reference numerals as those shown in FIGS. 1 to 11 denote the same parts, and a detailed description thereof will be omitted.

  The third embodiment of the steam injection gas turbine and the control method for the same according to the present invention shown in FIG. 12 is configured by substantially the same equipment as the first embodiment, but differs in the following configuration. In the present embodiment, a thermocouple 28 is provided on the outer surface of the combustor liner 10 as an example of a liner metal temperature detecting unit. The installation position is desirably near the liner dilution hole 14.

  As described above, at the start of the steam injection into the combustor 2, part of the drain water generated due to the low temperature of the second steam pipe 322 adheres to the outer surface of the combustor liner 10. Further, the remaining part flows on the flow of steam or air and adheres to the wall surface of the fuel nozzle 9. At that time, if the generated amount of the drain water is small, the drain water evaporates during flowing down, and it is considered that the thermocouple 27 installed at the downstream end of the axial center of the fuel nozzle 9 cannot detect the drain water. In this case, it is considered that the drain water has not reached the fuel nozzle 9, so that the combustion stability is ensured. However, since there is no change in the thermocouple 27, there is a problem that it is difficult to determine that the drain water has run out.

  On the other hand, in the present embodiment, a thermocouple 28 as a liner metal temperature detector is also provided on the outer surface of the combustion liner 10 and used for determination in accordance with the burner metal temperature to determine whether there is drain water. Has improved the detection accuracy. For example, when both the liner metal temperature and the burner metal temperature are lowered, it can be determined that a large amount of drain water is mixed. Next, when only the liner metal temperature is lowered, it can be determined that although the second steam 332 is mixed with drain water, it is not so large as to cause unstable combustion. Finally, if neither the liner metal temperature nor the burner metal temperature has decreased, it can be determined that drain water is not mixed. As described above, by determining the presence or absence of the drain water by combining the liner metal temperature and the burner metal temperature, the detection accuracy can be improved. Also, by combining the metal temperature of the water spray nozzle 354 shown in the second embodiment with the burner metal temperature or the liner metal temperature, the accuracy of detecting the drain water can be increased.

  According to the above-described third embodiment of the steam injection gas turbine and the control method of the present invention, the same effects as those of the above-described first embodiment can be obtained.

  According to the above-described third embodiment of the steam injection gas turbine and the control method of the present invention, the presence / absence of drain water is determined by combining the liner metal temperature and the burner metal temperature. Can be increased.

  Hereinafter, a fourth embodiment of a steam injection gas turbine and a control method thereof according to the present invention will be described with reference to the drawings. FIG. 13 is a system flow diagram showing an example of the configuration of a fourth embodiment of the steam injection gas turbine and the control method therefor according to the present invention, and FIG. 14 is a fourth embodiment of the steam injection gas turbine and the control method therefor according to the present invention. FIG. 21 is a system flow diagram showing another example of the configuration of the embodiment. 13 and 14, the same reference numerals as those shown in FIGS. 1 to 12 denote the same parts, and a detailed description thereof will be omitted.

  An example of the fourth embodiment of the steam injection gas turbine and the control method for the same according to the fourth embodiment of the present invention shown in FIG. 13 is configured by substantially the same equipment as the first embodiment, but differs in the following configuration. In the present embodiment, the detection surface of the flame detector 29 is inserted up to the wall surface of the combustor liner 10 and used as a drain amount detection means for control.

  The flame detector 29 may be provided, for example, for the purpose of detecting ignition at the time of starting the gas turbine, separately from the drain amount detecting means which is the object of the present embodiment. By using this flame detector also for detecting the drain amount, it is not necessary to provide a separate detector for detecting the drain amount, and the cost can be reduced.

  Generally, when drain water is mixed in the flame of the combustor 2, the brightness of the flame increases. For this reason, the flame detector detects such an increase in the brightness of the flame. When the luminance is high, drain water is mixed, and when the luminance is low, it can be determined that drain water has disappeared. Thus, the flame detector 29 can be used as a drain amount detecting means.

  As another example in the present embodiment, as shown in FIG. 14, instead of a flame detector, one end of a pressure conduit 31 is inserted up to the wall surface of the combustor liner 10 and a pressure fluctuation detector is inserted at the other end. 32 are installed.

  When drain water is mixed into the flame of the combustor 2 and combustion becomes unstable, the position of the flame and the heat generation fluctuate with time, and the pressure in the combustor liner 10 fluctuates. If this is detected by the pressure fluctuation detector 32, it can be determined that drain water is mixed when the pressure fluctuation is large and drain water has disappeared when the pressure fluctuation is small. In this manner, the pressure conduit 31 and the pressure fluctuation detector 32 can be used as drain amount detecting means.

  In the case according to FIG. 14, only the pressure conduit 31 faces the hot combustion gas and the pressure fluctuation detector 32 can be installed outside the combustor casing 7. The pressure conduit 31 exposed to a high temperature is heat-resistant and inexpensive, and the expensive and low-heat-resistance pressure fluctuation detector 32 can be installed in a place in a low-temperature environment. Reliability can be improved.

  According to the above-described fourth embodiment of the steam injection gas turbine and the control method of the present invention, the same effects as those of the above-described first embodiment can be obtained.

  Further, according to the above-described fourth embodiment of the steam injection gas turbine and the control method thereof according to the present invention, it is possible to increase the reliability while suppressing the cost for the drain amount detecting means.

1: compressor, 2: combustor, 3: turbine, 4: steam injection gas turbine, 5: exhaust heat recovery boiler, 6: steam consuming equipment, 7: combustor casing, 8: combustor cover, 9: fuel nozzle , 10: combustor liner, 11: liner flow sleeve, 12: transition piece, 13: transition piece flow sleeve, 14: dilution hole, 15: steam injection port, 16: steam injection hole, 17: swirler, 18: partition wall , 20: generator, 23: turbine casing, 25: boiler, 29: flame detector, 31: pressure pipe, 32: pressure fluctuation detector, 100: air, 101: combustion air, 102: liner cooling air, 103: dilution air, 104: combustion air, 105: combustion gas, 106: combustion gas, 107: gas generator exhaust gas, 108: turbine exhaust gas, 109: exhaust gas, 110: secondary combustion air, 20 : Fuel system, 201: fuel, 202: fuel flow control valve, 203: fuel flow meter, 300: steam supply system, 301: first steam system, 302: second steam system, 303: process steam piping, 304 : Steam release system, 311: first steam flow control valve, 312: second steam flow control valve, 313: process steam flow control valve, 314: steam discharge valve, 331: first steam, 332: second steam , 350: steam header, 351: steam flange, 352: steam nozzle, 353: drain water communication pipe, 354: water spray nozzle

Claims (9)

A compressor that compresses air to produce high-pressure combustion air;
A combustor that generates combustion gas by burning the combustion air and fuel,
A turbine driven by combustion gas generated by the combustor, and a steam injection gas turbine that injects steam into the combustor,
The steam injection system is branched into two systems,
A first steam system that injects the steam into a position where most of the injected steam mixes with the combustion air or the fuel on the upstream side of the flame zone with respect to the flow of the combustion gas in the combustor;
Downstream of the flame zone with respect to the flow of the combustion gas in the combustor, most of the injected steam mixes with the combustion gas, and the remaining part of the steam flows into the flame zone with respect to the flow of the combustion gas. A second steam system for injecting steam into a position where the steam is mixed with the combustion air,
A flow control mechanism capable of individually controlling the steam flow rate of the first steam system and the steam flow rate of the second steam system,
Drain amount detection means for detecting the amount of drain water flowing into the combustor at the start of steam injection,
The drain amount detection means, a metal temperature measurement means for measuring the metal temperature of the combustor, and an arithmetic unit for calculating the amount of the drain water based on the metal temperature of the combustor measured by the metal temperature measurement means, With
The steam injection gas turbine, wherein the flow rate control mechanism controls the steam flow rates of the two systems based on a signal indicating the amount of the drain water detected by the drain amount detection unit. The steam injection gas turbine according to claim 1,
At the start of steam injection into the combustor, the flow rate control mechanism injects steam from the second steam system, and after confirming that the amount of drain water detected by the drain amount detection means has disappeared, A steam injection gas turbine for starting injection of steam of a first steam system. The steam injection gas turbine according to claim 1 or 2,
A plurality of steam nozzles for injecting first steam from the first steam system;
A steam header communicating with each of the plurality of steam nozzles,
A water spray nozzle communicating with the lowermost portion of the steam header,
The steam injection gas turbine, wherein an outlet of the water spray nozzle is opened at a position upstream of a flame zone in the flow of the combustion air. The steam injection gas turbine according to any one of claims 1 to 3 ,
The combustor includes a combustor liner forming a combustion chamber for burning the combustion air and the fuel, and a burner for injecting the fuel into the combustor liner,
The steam injection gas turbine, wherein the metal temperature measuring means of the drain amount detecting means measures at least one of a metal temperature of the burner and a metal temperature of the combustor liner. The steam injection gas turbine according to claim 3,
Before SL combustor includes a combustor liner forming a combustion chamber for combusting the fuel with the combustion air, and a burner for injecting said fuel into said combustor liner,
Wherein the metal temperature measuring means of the drain amount detecting means measures at least one metal temperature of the metal temperature of the burner, the metal temperature of the combustor liner, and the metal temperature of the water spray nozzle. gas turbine. The steam injection gas turbine according to any one of claims 1 to 5 ,
The drain amount detection unit includes a saturated steam temperature calculation unit that calculates a saturation temperature of the steam to be injected,
A steam injection gas turbine, comprising: a calculating unit that calculates the amount of the drain water based on the saturated temperature of the steam calculated by the saturated steam temperature calculating unit and the metal temperature. The steam injection gas turbine according to claim 6 ,
The drain amount detection unit includes a signal holding storage unit that stores the metal temperature immediately before steam injection,
A steam injection gas turbine, comprising: a calculation unit that calculates the amount of the drain water based on the metal temperature stored in the signal holding storage unit, the saturation temperature of the steam, and the metal temperature. The steam injection gas turbine according to any one of claims 1 to 7 ,
A timer operation unit that measures time from the start of steam injection of the first steam system or the second steam system,
A steam injection gas turbine, wherein the steam flow rate of the two systems is controlled based on a signal from the timer calculation unit and a signal from the drain amount detection unit. A compressor that compresses air to produce high-pressure combustion air;
A combustor that generates combustion gas by burning the combustion air and fuel,
A turbine driven by the combustion gas generated by the combustor;
A first steam system that injects the steam into a position where most of the injected steam mixes with the combustion air or the fuel on the upstream side of the flame zone with respect to the flow of the combustion gas in the combustor;
Downstream of the flame zone with respect to the flow of the combustion gas in the combustor, most of the injected steam mixes with the combustion gas, and the remaining part of the steam flows into the flame zone with respect to the flow of the combustion gas. A second steam system for injecting steam into a position where the steam is mixed with the combustion air,
A flow control mechanism capable of individually controlling the steam flow rate of the first steam system and the steam flow rate of the second steam system,
A drain amount detection means for detecting an amount of drain water flowing into the combustor at the start of steam injection, a control method of a steam injection gas turbine, comprising:
The drain amount detection means, a metal temperature measurement means for measuring the metal temperature of the combustor, and an arithmetic unit for calculating the amount of the drain water based on the metal temperature of the combustor measured by the metal temperature measurement means, With
A step of injecting steam from the second steam system at the start of steam injection into the combustor;
After confirming that the amount of drain water detected by the drain amount detecting means has been exhausted, a procedure of injecting a small amount of steam from the first steam system,
Starting the injection of the steam of the first steam system, starting the control of the steam flow rate of the first steam system based on the signal of the amount of the drain water detected by the drain amount detecting means. A method for controlling a steam injection gas turbine, comprising:

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