JP2017020346A - Thermoelectric variable cogeneration system - Google Patents

Abstract

PROBLEM TO BE SOLVED: To provide a thermoelectric variable cogeneration system which secures combustion stability of a gas turbine combustor to reduce an amount of NOx emission when variation occurs in fuel flow of a gas turbine or an amount of used steam of a steam consumption facility.SOLUTION: In a thermoelectric variable cogeneration system, it is provided with: a first steam system for infusing a part of steam to a position on an upstream side of a flame zone in a gas turbine combustor; a second steam system for infusing the other part of steam to a position on a downstream side of the flame zone; a fuel flow rate detector of fuel to be supplied to the gas turbine combustor; steam flow rate detection means of steam to be infused to the gas turbine combustor through the second steam system; a steam supply system for supplying steam provided with a steam pressure detector, from an exhaust heat recovery boiler; and a steam temperature detector, and a controller for controlling an amount of infused steam to be supplied to the gas turbine combustor by adjusting aperture of a first steam flow rate adjustment valve provided in the first steam system on the basis of detection values of the fuel flow rate detector and the steam flow rate detection means is installed.SELECTED DRAWING: Figure 1

Description

  The present invention includes a steam injection gas turbine that injects a part of steam generated by using exhaust heat of the gas turbine as a heat source into the gas turbine, and changes the amount of steam injection injected into the gas turbine. The present invention relates to a variable thermoelectric cogeneration system capable of changing the ratio of heat (steam) and electric power that can be supplied to the outside, and more particularly to a variable thermoelectric cogeneration system that controls the amount of steam injected into a gas turbine.

  A thermoelectric power generator equipped with a thermoelectric variable gas turbine that can supply both heat and electric power and can change the thermoelectric ratio, which is the ratio of heat (steam) and electric power, according to the demand ratio of the required heat and electric power. The variable cogeneration system is expected as a highly efficient distributed power source with low energy loss.

  Among this thermoelectric variable cogeneration system, as a steam injection system that injects steam into the gas turbine combustor of the thermoelectric variable gas turbine, steam is injected upstream of the flame zone with respect to the flow of combustion gas in the gas turbine combustor. A first steam system and a second steam system that injects steam downstream of the flame zone, and the first steam system injects through the first steam system according to the fuel flow rate and fuel composition. The technology of a variable thermoelectric cogeneration system configured to control the flow rate of steam and control the flow rate of the second steam injected through the second steam system according to the required steam requirement in the steam consuming equipment is disclosed in Japanese Patent Application Laid-Open No. 2014-2014. No. 173572 (Patent Document 1).

JP 2014-173572 A

  In the thermoelectric variable cogeneration system disclosed in Japanese Patent Application Laid-Open No. 2014-173572, it is generated when the first steam flow rate injected from the first steam system is increased upstream of the flame zone in the gas turbine combustor. Nitrogen oxide (NOx) is reduced, but if the flow rate of the injected steam is excessive than the flow rate required for NOx reduction, there is a possibility of extinguishing the flame.

  Therefore, the thermoelectric variable cogeneration system disclosed in Japanese Patent Application Laid-Open No. 2014-173572 discloses means for controlling the first steam amount injected into the gas turbine combustor according to the fuel flow rate and the fuel composition. Yes.

  However, as the fuel flow rate increases, the flame formed in the gas turbine combustor becomes longer, and a part of the increased fuel flows into dry combustion air (for example, through the combustion holes) in which the first steam is not mixed. Secondary combustion air), and the amount of NOx emissions generated increases.

  Therefore, it is conceivable to increase the amount of the first steam injected into the gas turbine combustor in order to reduce the NOx emission amount. However, as the moisture at the flame base increases due to the injected steam, the flame temperature and oxygen are increased. The concentration decreases and the possibility of extinction increases.

  On the other hand, in the gas turbine combustor, the portion where the fuel is burned with the dry combustion air that is the source of NOx is not mixed with moisture, so the NOx reduction effect is limited.

  Of the first steam flow and the second steam flow injected into the gas turbine combustor, the second steam flow is controlled according to the required steam requirement in the steam consuming equipment, and thus the injection is performed. When the second steam flow rate is high and the fuel flow rate is low, or when the injected second steam flow rate is high and the air flow rate is high, the second steam flow rate is set downstream of the flame zone in the gas turbine combustor. When a part of the second steam to be injected through the steam system is mixed with the combustion air, the total steam flow of the first and second steam flows to be injected becomes excessive. May cause extinction.

  It is an object of the present invention to ensure the combustion stability of a gas turbine combustor when the fuel flow rate due to a gas turbine load change or the amount of steam used in a steam consuming facility changes, and the gas turbine combustor It is an object to provide a variable thermoelectric cogeneration system that makes it possible to reduce the amount of NOx discharged from the boiler.

  The thermoelectric variable cogeneration system of the present invention includes a compressor that compresses air, a gas turbine combustor that generates combustion gas by burning fuel using the compression air compressed by the compressor, and gas turbine combustion A gas turbine equipped with a turbine driven by combustion gas generated by the generator, an exhaust heat recovery boiler that generates steam using exhaust gas discharged from the turbine of the gas turbine as a heat source, and steam generated by the exhaust heat recovery boiler A steam supply system that supplies steam to a steam consumption facility, and a thermoelectric variable cogeneration system that injects a part of the steam supplied to the steam supply system into a gas turbine through a steam injection system connected to the steam supply system. As a system, a first part of the steam is injected into a position upstream of the flame zone with respect to the flow of the combustion gas in the gas turbine combustor. A steam system and a second steam system for injecting another part of the steam to a position downstream of the flame zone with respect to the flow of the combustion gas in the gas turbine combustor are disposed, and through the first steam system A first steam flow adjusting valve for adjusting a flow rate of the first steam to be injected and a second steam flow adjusting valve for adjusting a flow rate of the second steam to be injected through the second steam system; A second fuel flow detector is installed in each of the second steam systems to detect the fuel flow rate of the fuel supplied to the gas turbine combustor, and the second steam system is injected into the gas turbine combustor. A steam flow detection means for detecting a steam flow is installed, a steam pressure detector and a steam temperature detector are installed in the steam supply system, respectively, and a detected value of the fuel flow detected by the fuel flow detector and the steam flow The second detected by the detecting means A controller for controlling the amount of injected steam supplied to the gas turbine combustor by adjusting the opening degree of the first steam flow rate adjusting valve provided in the first steam system based on the detected value of the steam flow rate is installed. It is characterized by that.

  The thermoelectric variable cogeneration system of the present invention includes a compressor that compresses air, a gas turbine combustor that generates combustion gas by burning fuel using the compression air compressed by the compressor, and a gas Generated in a gas turbine equipped with a turbine driven by combustion gas generated in a turbine combustor, an exhaust heat recovery boiler that generates steam using the exhaust gas discharged from the turbine of the gas turbine as a heat source, and an exhaust heat recovery boiler In a steam supply system for supplying steam to a steam consuming facility, and a thermoelectric variable cogeneration system for injecting a part of the steam supplied to the steam supply system into a gas turbine through a steam injection system connected to the steam supply system, As part of the steam injection system, a part of steam injected into the upstream side of the flame zone with respect to the flow of combustion gas in the gas turbine combustor A first steam system for injecting, and a second steam system for injecting another part of the steam to be injected into a position downstream of the flame zone with respect to the flow of the combustion gas in the gas turbine combustor. A first steam flow rate adjusting valve for adjusting the flow rate of the first steam injected through the first steam system and a second steam flow rate adjusting valve for adjusting the flow rate of the second steam injected through the second steam system Are installed in the first steam system and the second steam system, respectively, a fuel flow detector for detecting the fuel flow rate of the fuel supplied to the gas turbine combustor is installed, and the gas turbine combustion is installed in the second steam system. A fuel flow rate detecting means for detecting the flow rate of the second steam injected into the vessel, a steam pressure detector and a steam temperature detector are installed in the steam supply system, respectively, and the fuel flow rate detected by the fuel flow rate detector Based on the detected value of A controller for controlling the amount of injected steam to be supplied to the gas turbine combustor by adjusting the opening of a first steam flow rate adjusting valve provided in one steam system, the controller comprising the fuel flow rate detector; The first steam for controlling the opening degree of the first steam flow rate adjusting valve by calculating the steam flow rate of the first steam that is the amount of injected steam supplied to the gas turbine combustor through the first steam system based on A first computing unit that outputs a flow rate command value, and a second amount of injected steam that is supplied to the gas turbine combustor through the second steam system based on the detected value of the steam pressure detected by the steam pressure detector. A second arithmetic unit that outputs a second steam flow command value for controlling the opening degree of the second steam flow control valve by calculating the steam flow rate of the first steam, The second steam flow rate command value calculated by the second calculator is The first steam flow rate command value is input and the first steam flow rate command value is output, and the opening degree of the first steam flow rate adjustment valve and the second steam are determined based on the detected values of the steam temperature detector and the steam pressure detector. It is configured to limit the opening degree of the flow regulating valve.

  According to the present invention, when the fuel flow rate due to the gas turbine load change or the amount of steam used in the steam consuming equipment changes, the combustion stability of the gas turbine combustor is ensured, and the gas turbine combustor A variable thermoelectric cogeneration system that makes it possible to reduce the amount of NOx discharged from the engine can be realized.

It is a system flow figure showing composition of a thermoelectric variable type cogeneration system of the 1st example of the present invention. It is a block diagram which shows the structure of the controller which controls the steam valve in the thermoelectric variable type cogeneration system of 1st Example of this invention. It is a graph which shows the relationship between the fuel flow rate which is an example of the steam flow control in the thermoelectric variable type cogeneration system of 1st Example of this invention, and the 1st steam flow rate. It is a graph which shows the relationship between the IGV opening degree which is an example of the steam flow control in the thermoelectric variable type cogeneration system of 1st Example of this invention, and the 1st steam flow. It is a graph which shows the relationship between the compressor rotation speed which is an example of the steam flow control in the thermoelectric variable type cogeneration system of 1st Example of this invention, and the 1st steam flow. It is a graph which shows the relationship between the 2nd steam flow which is an example of the steam flow control in the thermoelectric variable type cogeneration system of 1st Example of this invention, and the 1st steam flow. It is a graph which shows the relationship between the steam pressure which is an example of the steam flow control in the thermoelectric variable type cogeneration system of 1st Example of this invention, and a 2nd steam flow rate. It is a graph which shows the relationship between the pressure ratio of the gas turbine which is an example of the steam flow control in the thermoelectric variable type cogeneration system of 1st Example of this invention, and a 2nd steam flow rate. It is a system flow figure showing the structure of the thermoelectric variable type cogeneration system of 2nd Example of this invention.

  A thermoelectric variable cogeneration system according to a first embodiment of the present invention will be described below with reference to the drawings.

  FIG. 1 is a system flow diagram showing an overall configuration of a thermoelectric variable cogeneration system according to a first embodiment of the present invention.

  As shown in FIG. 1, a thermoelectric variable cogeneration system according to a first embodiment of the present invention includes, as main devices, a gas turbine 4 and an exhaust heat recovery boiler that generates steam using the exhaust gas of the gas turbine 4 as a heat source. 5 and a steam supply system 300 for supplying steam generated in the exhaust heat recovery boiler 5.

  Among them, the gas turbine 4 mainly supplies the compressor 1 that compresses the air 100 to generate high-pressure combustion air 101 and the compressed air 101 introduced from the compressor 1 to the combustion chamber 50 to externally. A plurality of gas turbine combustors 2 that combust the fuel 201 supplied from the engine to generate high-temperature and high-pressure combustion gases 106, and high-temperature and high-pressure combustion gases 106 generated in the combustion chambers 50 of these gas turbine combustors 2. The turbine 3 is introduced from the gas turbine combustor 2 and driven.

  An inlet guide vane (IGV) 19 is installed in the intake portion of the compressor 1 to adjust the suction flow rate of the air 100 sucked into the compressor 1.

  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 through a shaft 21a of the gas generator, and the compressor 1 is driven by the rotation of the gas generator 3a.

  On the other hand, the power turbine 3b is connected to the generator 20 by a power turbine shaft 21b, and drives the generator 20 by the rotation of the power turbine 3b. A rotation speed detector 22 is attached to the shaft 21a so that the rotation speed of the compressor 1 can be known.

  The gas turbine combustor 2 is stored inside a combustor casing 7, and a combustor cover 8 is attached to one end of the combustor casing 7. The combustor casing 7 is attached to the turbine casing 23.

  A fuel nozzle 9 is installed at the center of the upstream end of the gas turbine combustor 2, and a substantially cylindrical combustor liner 10 that separates unburned air and burned combustion gas is provided downstream of the fuel nozzle 9. Is installed.

  Inside the combustor liner 10, the combustion chamber 50 is formed in which the fuel 201 supplied from the outside is burned by the supplied compressed air 101 to generate the high-temperature and high-pressure combustion gas 106.

  A liner flow sleeve 11 is installed on the outer peripheral side of the combustor liner 10. The liner flow sleeve 11 is generally cylindrical and fastened inside the combustor outer cylinder 7 so as to be substantially coaxial with the combustor liner 10.

  A tail cylinder 12 that guides the combustion gas 106 generated in the combustion chamber 50 to the turbine 3 is installed downstream of the combustor liner 10. The downstream end of the combustor liner 10 is inserted into the upstream end of the transition piece 12.

  A tail tube flow sleeve 13 is installed on the outer peripheral side of the tail tube 12. The downstream end of the liner flow sleeve 11 is inserted into the upstream end of the transition piece flow sleeve 13.

  In the thermoelectric variable cogeneration system having the above-described configuration, the high-pressure combustion air 101 pressurized by the compressor 1 is moved from the space in the turbine casing 23 to the space between the transition piece 12 and the transition piece flow sleeve 13. It flows in from the opening on the side (downstream side).

When the combustion air 101 flows to the combustor liner 10 side (upstream side), the tail cylinder 12 is cooled from the outside.
Thereafter, the combustion air 101 flows through the generally annular space between the combustor liner 10 and the liner flow sleeve 11 toward the upstream side of the gas turbine combustor 2. Cool from outside.

  Further, a part 102 of the combustion air 101 flows into the combustor liner 10 from the cooling holes provided in the combustor liner 10 and is used for film cooling.

  Another portion 103 of the combustion air 101 flows into the combustor liner 10 through a plurality of dilution holes 14 provided in the combustor liner 10 and mixes with the combustion gas 105 flowing down in the combustor liner 10. Then flows into the tail cylinder 12.

  Further, the secondary combustion air 110 which is another part of the combustion air 101 flows into the combustor liner 10 from a plurality of combustion holes 30 provided in the combustor liner 10 and is combusted by the combustion air 104 described later. Used for combustion with fuel that could not be exhausted.

  The remaining combustion air 104 of the combustion air 101 flows into the combustor liner 10 from the swirler 17 provided on the outer periphery of the fuel nozzle 9 and is used for combustion together with the fuel ejected from the fuel nozzle 9.

  At this time, when the fuel flow rate is large, not all of the injected fuel can be combusted by the combustion air 104, so that it combusts with the secondary combustion air 110 on the downstream side of the combustor liner 10.

  The combustion results in a high-temperature combustion gas 105, and the combustion gas 106 mixed with the cooling air 102 and the dilution air 103 is sent from the gas turbine combustor 2 to the turbine 3 to drive the turbine 3.

  The low-pressure turbine exhaust gas 108 exiting the turbine 3 is supplied to the exhaust heat recovery boiler 5 as a heat source, generates steam in the exhaust heat recovery boiler 5, and is recovered by the exhaust heat recovery boiler 5 before being exhausted. The gas 109 is exhausted from the exhaust heat recovery boiler 5 to the outside.

  The fuel system 200 that supplies fuel to the gas turbine combustor 2 is provided with a fuel flow rate adjustment valve 202. By adjusting the fuel flow rate with the fuel flow rate adjustment valve 202, the power generation output of the gas turbine can be adjusted.

  In addition, a fuel flow meter 203 serving as a fuel flow rate detecting means is provided, and the fuel flow rate can be detected.

  Here, as the fuel flow rate detecting means, instead of the fuel flow meter 203 described in the present embodiment, for example, an opening degree of the flow rate control valve, an opening degree command to the flow rate control valve, or the like can be used. This is because if the fuel pressure and temperature are substantially constant, the fuel flow rate is a function of the valve opening.

  On the other hand, when the fuel pressure and temperature change, the fuel flow rate can be detected with higher accuracy by detecting the fuel pressure and temperature and using them to calculate the flow rate.

  Next, the steam system of the thermoelectric variable cogeneration system according to the first embodiment of the present invention will be described with reference to FIG.

  In the variable thermoelectric cogeneration system according to the first embodiment of the present invention shown in FIG. 1, the exhaust heat recovery boiler 5 heats the feed water supplied from the feed water heater 24 and the feed water heater 24 for heating the feed water. The steam 25 is generated by the steam 25 and the steam superheater 26 that superheats the steam supplied from the boiler 25, and the superheated steam generated by the steam superheater 26 is steamed from the exhaust heat recovery boiler 5. It is supplied to the steam consuming equipment 6 through the supply system 300 and consumed.

  The steam consuming equipment 6 may be equipment requiring a heat source such as a factory.

  In order to supply the steam supplied through the steam supply system 300 to the steam consuming equipment 6, a process steam flow control valve 313 is installed in the process steam pipe 303 connected to the steam supply system 300, and this process steam flow control valve By adjusting 313, the amount of steam supplied to the steam consuming equipment 6 through the process steam pipe 303 is controlled.

  On the other hand, when the amount of steam generated in the exhaust heat recovery boiler 5 exceeds the amount of steam necessary for the steam consuming equipment 6, surplus steam is injected into the gas turbine combustor 2 and the generator 20 of the gas turbine 4 The thermoelectric variable cogeneration system makes the thermoelectric ratio variable by increasing the output.

  In the thermoelectric variable cogeneration system of the first embodiment, the steam generated from the exhaust heat recovery boiler 5 is connected to a steam supply system 300 to which steam is supplied, and a part of the steam supplied through the steam supply system 300 is used. The steam system supplied to the gas turbine combustor 2 is divided into two systems of a first steam system 301 and a second steam system 302.

  A steam flow rate adjusting valve 311 and a steam flow rate adjusting valve 312 are connected to the first steam system 301 and the second steam system 302 respectively connected to the steam supply system 300 to which the steam generated from the exhaust heat recovery boiler 5 is supplied. Are provided so that the flow rate of the steam flowing through the first steam system 301 and the second steam system 302 and injected into the gas turbine combustor 2 can be adjusted by the control operation of the controller 400 described later. Has been.

  Of these first steam system 301 and second steam system 302, the steam injection position of the gas turbine combustor 2 that injects steam into the gas turbine combustor 2 through the first steam system 301 is the combustion gas. The steam injection position a where most of the injected steam is mixed with the combustion air 104 or the fuel 201 is set on the upstream side of the flame zone 120 with respect to this flow.

  More specifically, as shown in the gas turbine combustor 2 of FIG. 1 as a steam injection position a, it is outside the combustor liner 10 and is surrounded by the combustor casing 7, the combustor cover 8, and the combustor liner 10. The steam supplied through the first steam system 301 is injected into the space as the first steam 321.

  The combustion air 104 at the steam injection position a of the gas turbine combustor 2 is the combustion air 104 after the high-pressure air 101 branches off from the liner cooling air 102 and the dilution air 103, and most of the combustion air 104 is combusted with the fuel 201. Since it is consumed, the first steam 321 mixed with the combustion air 104 at the steam injection position a has a large effect of lowering the temperature of the flame zone 120 and greatly contributes to the reduction of NOx.

  Next, a steam injection position for injecting steam into the gas turbine combustor 2 through the second steam system 302 will be described.

    The combustor outer cylinder 7 is provided with a steam injection port 15, and the first steam connected to the steam supply system 300 to which the steam generated in the exhaust heat recovery boiler 5 is supplied. Of the system 301 and the second steam system 302, the second steam system 302 is connected.

  The second steam 322 supplied through the second steam system 302 and injected into the gas turbine combustor 2 is first a generally annular space between the combustor outer cylinder 7 and the liner flow sleeve 11. Flowing.

  This space and the space in the turbine casing 23 are separated by a partition wall 18. Accordingly, mixing of the steam 322 flowing into the gas turbine combustor 2 and the compressed air 101 in the turbine casing 23 is suppressed.

  The injected second steam 322 flows on the outer peripheral side of the flow sleeve 11 in the entire circumferential direction. Therefore, even if there is one steam port 15 with respect to one of the combustor outer cylinders 7, the moisture in the circumferential direction of the gas turbine combustor 2 can be made uniform.

  The liner flow sleeve 11 is provided with a plurality of steam injection holes 16 in the circumferential direction. Further, all or part of the vapor injection hole 16 faces all or part of the dilution hole 14 provided in the liner 10.

  Of these, most of the second steam 322 that has 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 322 is mixed with the combustion gas 105 after combustion on the downstream side of the flame zone 120 with respect to the flow of the combustion gas 105 flowing in the gas turbine combustor 2.

  Specifically, as shown as a steam injection position b in the gas turbine combustor 2 in FIG. 1, downstream of the combustor liner 10 with respect to the flow of the combustion gas 105 in the gas turbine combustor 2, In addition, the second steam 322 supplied through the second steam system 302 is injected into the steam injection position b which becomes the combustion chamber 50 inside the combustor liner 10.

  At the steam injection position b, the second steam 322 supplied and injected through the second steam system 302 is mixed with the combustion gas 105 and the diluted air 103 after combustion in the combustion chamber 50 of the gas turbine combustor 2. Therefore, the flame zone 120 is not directly affected.

  Therefore, the output can be increased by injecting the second steam 322 as surplus steam into the gas turbine combustor 2 without affecting the stability of combustion in the gas turbine combustor 2.

  In addition, since the steam injection position b in the gas turbine combustor 2 that injects the second steam 322 is located on the upstream side of the gas flow with respect to the turbine 3, the energy of the steam is effectively made in the turbine 3. It can be converted into power.

  Further, when the combustion gas 105, 106 generated in the gas turbine combustor 2 flows into the gas generator turbine 3a of the turbine 3, the temperature is lowered by mixing with the steam. 11 and the metal temperature of the gas generator turbine 3a constituting the turbine 3 can be lowered, and the reliability and life are improved.

  Further, since the fuel flow rate of the fuel 201 supplied to the gas turbine combustor 2 can be increased by the amount of the steam mixture, if the temperature of the combustion gas 106 flowing into the turbine 3 is the same turbine inlet temperature, the steam is mixed. The output and efficiency can be improved by the amount.

  In addition, among the second steam 322, the other part of the steam 322 a of the second steam 322 is changed in flow direction by the flow of the combustion air 101 and mixed with the secondary combustion air 110 and the combustion air 104. Used for combustion.

  When all of the second steam 322 flows into the combustor liner 10 from the dilution hole 14, the first steam 321 is mixed with the combustion air 104, so that NOx can be reduced. Since the combustion air 110 does not contain moisture, the NOx reduction effect by the first steam 321 decreases as the fuel flow rate increases.

  On the other hand, when the other steam 322a of the second steam 322 is mixed with the secondary combustion air 110 as in the present embodiment, the second steam mixed with the secondary air even if the fuel flow rate increases. Reduction of NOx can be achieved by the effect of the other part of the steam 322.

  Next, control of the steam flow rate of the steam injected into the gas turbine combustor 2 will be described.

  In the thermoelectric variable cogeneration system according to the first embodiment of the present invention shown in FIG. 1, the gas turbine 4 is started, compressed air 101 introduced from the compressor 1 is supplied, and fuel is produced in the gas turbine combustor 2. 201 is combusted to generate a high-temperature combustion gas 106, and the gas generator turbine 3 a constituting the turbine 3 is driven by the combustion gases 105 and 106 generated by the gas turbine combustor 2.

  The gas turbine exhaust gas 107 discharged by driving the gas generator turbine 3a of the turbine 3 then flows into the power turbine 3b and drives the power turbine 3b. The gas turbine exhaust gas 108 discharged by driving the power turbine 3b is supplied to the exhaust heat recovery boiler 5. The exhaust heat recovery boiler 5 generates steam using the gas turbine exhaust gas 108 as a heat source.

  The steam generated in the exhaust heat recovery boiler 5 measures the steam pressure and the steam temperature by the steam pressure gauge 305 and the steam temperature detector 306 installed in the steam supply system 300 for supplying the steam generated in the exhaust heat recovery boiler 5, respectively. Then, those measured values are input to the controller 400.

  In the controller 400, when the steam pressure measured by the steam pressure gauge 305 becomes larger than a predetermined set pressure, a first steam flow control valve installed in the first steam system 301 connected to the steam supply system 300 is used. The valve 311 is opened to inject the first steam 321 into the steam injection position a of the gas turbine combustor 2 through the first steam system 301.

  A steam supply system 300 that supplies steam generated in the exhaust heat recovery boiler 5 is connected to a steam supply system 303 that supplies steam to the steam consumption facility 6 that is a facility that consumes steam. The air system 303 is provided with a steam flow rate adjusting valve 313 for adjusting the amount of steam supplied to the steam consuming facility 6.

  The controller 400 requires the steam consuming equipment 6 to open the flow control valve 313 installed in the steam system 303 based on the steam pressure measured by the steam pressure gauge 305 and a preset set pressure. Start supplying steam for consumption.

  When the supply of steam to the steam consuming facility 6 is started through the steam system 303, the steam pressure 305a measured by the steam pressure gauge 305, which is the pressure of the steam supplied from the exhaust heat recovery boiler 5 to the steam supply system 300, decreases. .

  Therefore, in order to maintain the steam pressure 305a of the steam flowing down the steam supply system 300 at a predetermined pressure, the gas turbine load command value or the rotational speed command value increases, and the fuel that supplies the fuel 201 to the gas turbine combustor 2 The opening degree of the fuel flow rate adjustment valve 202 provided in the system 200 is further opened.

  Thus, in the thermoelectric variable cogeneration system of the present embodiment that controls the fuel flow rate with the control target of making the steam pressure 305a of the steam flowing down the steam supply system 300 constant, steam control with priority to heat is performed.

  In this case, since the power generation amount of the generator 20 constituting the gas turbine 4 changes, the difference from the power consumption amount adjusts the power transmission amount from the power system.

  On the other hand, in the thermoelectric variable cogeneration system of the present embodiment, when the power control command is given priority over heat, such as when the generator 20 is not connected to the power system, the power request command value becomes large. As the fuel flow rate increases, the steam pressure 305a of the steam flowing down the steam supply system 300 increases.

  By the way, when the steam pressure 305a of the steam flowing down the steam supply system 300 increases, the maximum amount of steam that can be used in the steam consuming facility 6 to which steam is supplied through the steam supply system 300 and the steam system 303 also increases.

  In addition, the amount of steam generated in the exhaust heat recovery boiler 5 increases or the amount of steam consumed in the consumption facility 6 decreases, so that the steam pressure 305a of the steam flowing down the steam supply system 300 is further increased. Then, the second steam flow rate adjustment valve 312 provided in the second steam system 302 branched from the steam supply system 300 is opened, and steam is injected into the gas turbine combustor 2 through the second steam system 302. Start.

  For example, as shown in FIG. 7 to be described later, the second steam flow rate control valve 312 controls the steam steam pressure 305a measured by the steam pressure detector 305 installed in the steam supply system 300 so that the measured value of the steam is almost constant. As described above, the opening degree of the second steam flow rate adjustment valve 312 is controlled by the valve opening degree command value 422 commanded from the controller 400.

  The opening degree of the first steam flow control valve 311 installed in the first steam system 301 is determined and controlled as follows by the controller 400 shown in FIG.

  That is, the controller 400 detects the fuel flow rate signal detected by the fuel flow meter 203 installed in the fuel system 200 and the second steam flow rate 322 that is the amount of injected steam supplied to the gas turbine combustor 2. The detection signal of the second steam flow rate 322 detected by the second steam flow rate detection means 60 installed in the second steam system 302 and the steam supply system 300 that supplies the steam generated in the exhaust heat recovery boiler 5 are installed. The steam pressure signal detected by the steam pressure detector 305 and the steam temperature signal detected by the steam thermometer 306 installed in the steam supply system 300 are input.

  Further, the controller 400 includes an IGV opening signal detected by an opening detector 19 of a compressor inlet guide vane (IGV) installed at the inlet of the compressor 1, and a compressor rotation installed on the shaft 21 a of the gas turbine 4. You may comprise so that the compressor rotation speed signal detected with the number detector 22 may be input.

  Of the fuel flow rate, the IGV opening degree, the number of rotation detection signals, and the detection signal of the second steam flow rate 322 detected by the second steam flow rate detection means 60, at least the fuel flow rate signal detected by the fuel flow meter 203 The detection signal of the second steam flow rate 322 detected by the second steam flow rate detection means 60 installed in the second steam system 302 is the first to obtain the first steam flow command value 411 installed in the controller 400. The first steam flow rate command value 411 for operating the first steam flow rate control valve 311 installed in the first steam system 301 is calculated by the calculation of the first computing unit 401. Is done.

  Specifically, in the first computing unit 401, the fuel flow rate signal of the fuel 201 detected by the fuel flow meter 203 has the relational characteristic between the first steam amount and the fuel flow rate shown in FIG. The first steam flow rate is set to increase when the fuel flow rate increases. Thereby, the increase in NOx emission amount when the fuel flow rate increases can be suppressed.

  Moreover, in the said 1st calculator 401, the 1st steam volume shown in FIG. 4 with respect to the IGV opening degree signal detected with the opening degree detector 19 of the compressor inlet guide vane (IGV) as needed. The IGV detected by the opening detector 19 of the compressor inlet guide vane (IGV) is set so as to calculate the first steam flow rate command value 411 so as to have a relational characteristic between the IGV opening and the IGV opening. The first steam flow rate command value 411 is calculated so that the first steam flow rate decreases as the opening degree signal increases.

  Similarly, in the first computing unit 401, the first steam amount and the compressor rotational speed shown in FIG. 5 are applied to the compressor rotational speed signal detected by the compressor rotational speed detector 22 as necessary. Is set to calculate the first steam flow rate command value 411 so that the first steam flow rate increases when the compressor rotational speed detected by the compressor rotational speed detector 22 increases. The first steam flow rate command value 411 is calculated so as to decrease.

  By the way, when the IGV opening of the compressor or the compressor rotational speed increases, the amount of combustion air may increase and combustion may become unstable. In response to this, if necessary, the moisture in the combustion air can be reduced by performing the above-described control by the first computing unit 401 to maintain the combustion stability of the gas turbine combustor 2. .

  In the thermoelectric variable cogeneration system of the present embodiment, as shown in FIG. 2, the first steam flow rate command value 411 calculated and output by the first calculator 401 provided in the controller 400 is: The controller 400 is provided with an input of a second computing unit 402 for obtaining the opening degree of the first steam flow rate adjusting valve 311, and the first steam flow rate command value 411 is calculated by the calculation by the second computing unit 402. A valve opening command value 421 serving as an opening command for the first steam flow control valve 311 is calculated, and injected into the gas turbine combustor 2 through the first steam system 301 based on the valve opening command value 421. The opening degree of the first steam flow rate adjusting valve 311 for adjusting the flow rate of the first steam 321 is operated.

  When calculating the valve opening command value 421, the steam pressure signal detected by the steam pressure detector 305 and the steam thermometer 306 respectively installed in the steam supply system 300 in the calculation of the second calculator 402, and Based on the steam temperature signal, the steam density ρ can be calculated by the calculation by the steam density calculator 405 provided in the controller 400.

  By reflecting the steam density ρ calculated by the steam density calculator 405 in the calculation of the second calculator 402, the valve opening degree of the first steam flow rate adjustment valve 311 calculated by the second calculator 402 is calculated. Since the command value 421 can be accurately calculated, the steam calculated by the steam density calculator 405 based on the steam pressure signal and the steam temperature signal detected by the steam pressure detector 305 and the steam thermometer 306, respectively. Is reflected in the calculation of the second calculator 402, whereby the flow rate of the first steam 321 adjusted by the first steam flow rate adjustment valve 311 can be controlled with higher accuracy.

  That is, in the calculation of the second calculator 402, the temperature of the steam detected by the steam thermometer 306 becomes high, the steam pressure signal and the steam temperature signal detected by the steam pressure detector 305 and the steam thermometer 306. The first steam flow rate for adjusting the flow rate of the first steam 321 injected into the gas turbine combustor 2 through the first steam system 301 when the steam density ρ obtained from the calculation by the steam density computing unit 405 decreases. A valve opening command value 421 is output from the second computing unit 402 in a direction to open the opening of the control valve 311 to control the opening of the first steam flow control valve 311.

  On the contrary, the temperature of the steam detected by the steam thermometer 306 is lowered, and it is obtained by calculation of the steam density calculator 405 from the steam pressure signal and the steam temperature signal detected by the steam pressure detector 305 and the steam thermometer 306. When the steam density ρ increases, a valve opening command value 421 is output from the second calculator 402 in a direction to close the opening of the first steam flow control valve 311 to open the first steam flow control valve 311. It is configured to control the degree.

  In the thermoelectric variable cogeneration system of the present embodiment, as shown in FIG. 2, the second steam flow rate 322 that is the amount of injected steam supplied into the gas turbine combustor 2 through the second steam system 302 is detected. The second steam flow rate detection means 60 is installed in the second steam system 302 and is supplied into the gas turbine combustor 2 through the second steam system 302 detected by the second steam flow rate detection means 60. The detected value of the second steam flow rate 322 is configured to be input to the first calculator 401 of the controller 400.

  The detected value of the second steam flow rate 322 detected by the second steam flow rate detection means 60 is input to the first computing unit 401 of the controller 400, so that the first computing unit 401 Based on the detected value of the second steam flow rate 322 detected by the second steam flow rate detection means 60, which is an actual measurement value of the second steam flow rate 322 supplied into the gas turbine combustor 2 through the steam system 302. The first steam flow command value 411 for operating the first steam flow control valve 311 is calculated.

  As the second steam flow rate detecting means 60 for detecting the steam flow rate of the second steam 322 flowing through the second steam system 302, the second steam is detected as shown in FIGS. A flow meter 60 that is installed in the system 302 and detects the steam flow rate of the second steam 322 flowing through the second steam system 302 can be considered.

  Alternatively, as the second steam flow rate detection means 60, a valve opening degree detector (not shown) for detecting the opening degree of the second steam flow rate adjustment valve 312 installed in the second steam system 302, or the first A command value detector (not shown) for commanding the valve opening degree to the second steam flow rate adjusting valve 312 may be considered.

  Further, in the thermoelectric variable cogeneration system of this embodiment, as shown in the controller 400 of FIG. 2, the controller 400 is provided with the third arithmetic unit 403 for obtaining the second steam flow rate command value 412. The third computing unit 403 uses the steam pressure detected by the steam pressure detector 305 as an input signal, and flows down the second steam system 302 by computation and is installed in the second steam system 302. The second steam flow rate command value 412 for commanding the steam flow rate of the second steam 322 whose flow rate is regulated by the steam flow rate regulating valve 312 is calculated and output to the fourth computing unit 404.

  Then, in the fourth computing unit 404, a valve opening command value 422 that serves as an opening command for the second steam flow rate control valve 312 based on the second steam flow rate command value 412 computed by the third computing unit 403. And the opening degree of the second steam flow rate adjustment valve 312 is adjusted.

  Further, the second steam flow rate command value 412 calculated by the third computing unit 403 is replaced with the second steam flow rate detecting means 60 for detecting the second steam flow rate 322, and the first computing unit 401 is replaced. You may comprise so that it may input into. In this case, the installation of the second steam flow rate detection means 60 can be eliminated.

  In the thermoelectrically variable cogeneration system of the present embodiment, when the third computing unit 403 is installed in the controller 400, the third computing unit 403 uses the second steam amount and the steam pressure shown in FIG. When the steam pressure detected by the steam pressure detector 305 increases and reaches a predetermined value, the second steam flow control valve 312 starts to open, and the steam pressure 305 is substantially constant. The second steam flow rate command value 412 is set to be output.

  By configuring the third computing unit 403 in this way, the fuel flow rate 203 of the fuel 201 changes to change the amount of steam generated in the exhaust heat recovery boiler 5, or the steam used in the steam consuming facility 6. Even when the amount changes, the steam pressure of the steam supplied from the exhaust heat recovery boiler 5 to the steam supply system 300 can be kept constant.

  In the thermoelectric variable cogeneration system of the present embodiment, as shown in FIG. 2, the second steam flow rate command value 412 calculated and output by the third calculator 403 provided in the controller 400 is The input of the fourth arithmetic unit 404 for obtaining the opening degree of the second steam flow rate adjusting valve 312 provided in the controller 400 becomes an input to the second steam flow rate command value 412 by the calculation by the fourth arithmetic unit 404. A valve opening command value 422 serving as an opening command for the second steam flow rate control valve 312 is calculated.

  When calculating the valve opening command value 422, the steam pressure signal and steam detected by the steam pressure detector 305 and the steam thermometer 306 installed in the steam supply system 300 in the calculation of the fifth calculator 405. Therefore, the steam pressure signal and the steam temperature signal are reflected in the calculation of the fourth computing unit 404 to be adjusted by the second steam flow rate control valve 312. Thus, the flow rate of the second steam 322 can be controlled with higher accuracy.

  That is, in the calculation of the fourth calculator 404, the steam temperature detected by the steam thermometer 306 is high, and the steam pressure signal and steam temperature signal detected by the steam pressure detector 305 and the steam thermometer 306 are used. When the density ρ of the obtained steam decreases, the second steam that adjusts the flow rate of the second steam 322 that adjusts the flow rate of the second steam 322 that is injected into the gas turbine combustor 2 through the second steam system 302. The opening degree of the flow control valve 312 is controlled to open.

  Conversely, when the steam temperature detected by the steam thermometer 306 is low and the steam pressure ρ obtained from the steam pressure signal and the steam temperature signal detected by the steam pressure detector 305 and the steam thermometer 306 increases, The second steam flow rate adjusting valve 312 for adjusting the flow rate of the second steam 322 is configured to be controlled in the closing direction.

  Further, in the calculation of the fourth calculator 404, the flow rate value is set so that the maximum value of the second steam flow rate command value 412 becomes the relational characteristic between the second steam amount and the GT pressure ratio shown in FIG. It is also possible to limit based on the pressure ratio of the gas turbine.

  By configuring in this way, it is possible to prevent the flow rate of the second steam 322 from becoming too large, the pressure ratio of the gas turbine from becoming high, and the compressor surge margin from becoming too small.

  As described above, in the thermoelectric variable cogeneration system of the present embodiment, when the amount of steam necessary for the steam consuming equipment 6 changes, the amount of steam injected into the gas turbine 4 is changed to change the thermoelectric ratio. When performing the operation, NOx emission can be minimized while maintaining stable combustion.

  Next, steam flow control of the first steam 321 in consideration of the steam flow rate of the second steam 322 in the thermoelectric variable cogeneration system of the present embodiment will be described.

  Of the steam systems that are connected to the steam supply system 300 that supplies the steam generated in the exhaust heat recovery boiler 5 and branched from the steam supply system 300 to the first steam system 301 and the second steam system 302, the second As shown in FIG. 1, the steam supplied into the combustor liner 10 of the gas turbine combustor 2 through the steam system 302 is upstream of the dilution hole 14 provided in the combustor liner 10. Another part of the steam 322 a injected into the combustor liner 10 from the combustion hole 30 provided in the combustor liner 10 and the dilution hole 14 provided in the combustor liner 10, the combustor liner. 10 is a part of the second steam 322 injected into the steam 322b.

  The other steam 322a of the second steam 322 injected into the combustor liner 10 from the combustion hole 30 is generated in the combustor liner 10 of the gas turbine combustor 2 with the secondary combustion air 110 and the combustion. Mixing with air 104 and using it for the combustion of fuel 201 contributes to a reduction in NOx emissions.

  At this time, if the steam flow rate of the second steam 322 injected into the gas turbine combustor 2 through the second steam system 302 increases or decreases, the inside of the combustor liner 10 passes through the dilution hole 14 provided in the combustor liner 10. In the combustor liner 10, a part of the steam 322 b of the second steam 322 flowing into the combustor liner 10 and a combustion hole 30 provided in the combustor liner 10 located upstream of the dilution hole 14 in the combustor liner 10. The flow rate ratio of the second steam 322 to another part of the steam 322a that contributes to the reduction of NOx, and the part of the steam 322b of the second steam 322 and the second steam 322 The flow rates of the other partial steams 322a increase or decrease.

  In the thermoelectric variable cogeneration system of the present embodiment, even if the flow rate of the other steam 322a of the second steam 322 contributing to low NOx is increased or decreased, the combustion stability of the flame of the gas turbine combustor 2 2 and the low NOx performance, the signal of the second steam flow rate command value 412 calculated by the third calculator 403 of the controller 400 shown in FIG. 2 is input to the first calculator 401. .

  In the first computing unit 401, for example, when the flow rate of the second steam amount is small, the maximum of the first steam amount is obtained so that the relational characteristic between the first steam amount and the second steam amount shown in FIG. 6 is obtained. The first computing unit has such a characteristic that the value becomes substantially constant and the maximum value of the first steam amount gradually decreases when the flow rate of the second steam amount increases beyond a certain value. The first steam flow rate command value 411 output from 401 is calculated.

  Further, the controller 400 shown in FIG. 2 is configured to feed back the second steam flow rate command value 412 calculated by the third calculator 403 so as to be input to the first calculator 401. Therefore, the first computing unit 401 reflects the second steam flow rate command value 412 fed back from the third computing unit 403, and operates the first steam flow rate control valve 311. 411 is calculated.

    In the relational characteristic between the first steam amount that is the flow rate of the first steam 321 and the second steam amount that is the flow rate of the second steam 322 shown in FIGS. 6, for example, when the flow rate of the second steam amount is small, the maximum value of the first steam amount is almost equal so that the relational characteristic between the first steam amount and the second steam amount shown in FIG. When the flow rate of the second steam amount increases beyond a certain value, the output from the first computing unit 401 is such that the maximum value of the first steam amount gradually decreases. By calculating the first steam flow rate command value 411, the moisture contained in the combustion air 104 and the secondary combustion air 110 supplied to the gas turbine combustor 2 is controlled to be appropriate.

  By controlling in this way, even when the steam flow rate of the second steam 322 increases or decreases, low NOx combustion and stable combustion can be maintained in the gas turbine combustor 2.

  Further, even when the combustion flow rate or the air flow rate of the fuel 201 changes independently of the increase or decrease of the steam flow rate of the second steam 322, low NOx combustion can be maintained as in the case described above.

  Furthermore, the demand for heat in the steam consuming facility 6 increases, and the steam supply system 300 that supplies the steam generated in the exhaust heat recovery boiler 5 branches to the first steam system 301 and the second steam system 302. Even when the steam flow rate of the second steam 322 supplied into the gas turbine combustor 2 through the second steam system 302 is reduced, the gas turbine combustor 2 through the first steam system 301. Since the first steam 321 supplied into the inside of the gas turbine combustor 2 is mixed into the combustion air 104, it is necessary for reducing NOx compared to the case where the NOx is reduced only by the second steam 322. Since the amount of steam can be reduced, more heat demand can be met.

  As described above, in the thermoelectrically variable cogeneration system of the present embodiment, when steam consumption is small, surplus steam is injected into the gas turbine combustor 2 to reduce NOx emissions, and the amount of power generated In the thermoelectric variable cogeneration system that increases the amount of fuel, even when a part of the second steam 322 is supplied to the gas turbine combustor 2 and mixed with the combustion air to reduce NOx, the fuel flow rate, air flow rate, It is possible to provide a thermoelectric variable cogeneration system having a gas turbine that can be prevented from extinguishing with respect to the change in the second steam flow rate, has low NOx combustion, and is stable and highly reliable.

  In addition, since a large amount of surplus steam can be injected into the gas turbine combustor 2, it is possible to provide a variable thermoelectric cogeneration system with an improved usability by increasing the variation range of the thermoelectric ratio.

  Conversely, even when the amount of steam consumed 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 a high sensitivity to the amount of NOx produced. Thermoelectric variable cogeneration system can be provided.

  According to this embodiment, when the fuel flow rate due to the gas turbine load change or the steam amount used in the steam consuming equipment changes, the combustion stability of the gas turbine combustor is ensured and the gas turbine combustion is ensured. A variable thermoelectric cogeneration system that can reduce the amount of NOx discharged from the vessel can be realized.

  Next, a thermoelectric variable cogeneration system according to a second embodiment of the present invention will be described with reference to FIG.

  The thermoelectric variable cogeneration system according to the second embodiment of the present invention shown in FIG. 9 has the same basic configuration as the thermoelectric variable cogeneration system according to the first embodiment shown in FIGS. A description of the common configuration is omitted, and only a different configuration will be described below.

  The thermoelectric variable cogeneration system according to the second embodiment of the present invention shown in FIG. 9 is different from the thermoelectric variable cogeneration system according to the second embodiment in that the second supply through the second steam system 302 is different. Instead of directly supplying the steam 322 to the gas turbine combustor 2, the second steam 322 is supplied to the newly installed regenerator 27 through the second steam system 302.

  In the thermoelectric variable cogeneration system according to the second embodiment of the present invention shown in FIG. 9, the air 101 compressed by the compressor 1 is once extracted outside the gas turbine 4 and then regenerated. The high-temperature air 111 is supplied to the gas turbine combustor 2 by supplying the second steam 322 to the gas turbine combustor 2.

  In the regenerator 27, the gas generator turbine 3a and the power turbine 3b of the turbine 3 are sequentially driven, and the exhaust heat of the turbine exhaust gas 108 discharged from the power turbine 3b is used as a heat source to compress the air extracted from the compressor 1. By heating the air 101 and supplying the gas turbine combustor 2 with the high-temperature air 111 that is heated by the injection of the second steam 322, the flow rate of fuel required in the gas turbine fuel unit 2 is saved and increased. Efficiency can be improved.

  In the thermoelectric variable cogeneration system of the present embodiment, the second steam 322 supplied through the second steam inflow system 302 connected to the steam supply system 300 to which the steam generated from the exhaust heat recovery boiler 5 is supplied is provided. The high pressure air 101 is injected on the upstream side of the regenerator 27.

  The high-pressure air 101 is heated by the regenerator 27 by the exhaust heat of the turbine exhaust gas 108 to become high-temperature air 111. This high-temperature air 111 flows into the combustor casing, and the thermoelectric variable cogeneration system in the first embodiment. As described above, the cooling air 102, the dilution air 103, the combustion air 104, and the secondary air 110 are used.

  At this time, most of the air does not flow into the flame zone 120 inside the gas turbine combustor 2 as the cooling air 102 and the dilution air 103, but merges with the combustion gas 105 after combustion. Similarly to the thermoelectric variable cogeneration system of the embodiment, steam can be injected into the gas turbine combustor 2 without impairing the stability of the flame.

  Further, the advantage of the thermoelectric variable cogeneration system of the present embodiment is that the exhaust heat of the gas turbine exhaust gas 108 can be recovered not only with steam but also with high-pressure air, so that the maximum amount of steam generated can be reduced. It is suitable for a system that requires a small amount of steam and consumes a large amount of power, that is, a system with a small thermoelectric ratio.

  Also in the thermoelectric variable cogeneration system of the present embodiment described above, the NOx emission amount can be minimized while maintaining stable combustion by the steam injection using the steam control as described above.

  According to this embodiment, when the fuel flow rate due to the gas turbine load change or the steam amount used in the steam consuming equipment changes, the combustion stability of the gas turbine combustor is ensured and the gas turbine combustion is ensured. A variable thermoelectric cogeneration system that can reduce the amount of NOx discharged from the vessel can be realized.

  1: compressor, 2: gas turbine combustor, 3: turbine, 3a: gas generator turbine, 3b: power turbine, 4: gas turbine, 5: exhaust heat recovery boiler, 6: steam consumption equipment, 7: combustor casing 8, combustor cover, 9: fuel nozzle, 10: combustor liner, 11: liner flow sleeve, 12: tail tube, 13: tail tube flow sleeve, 14: dilution hole, 15: steam injection port, 16: steam Injection hole, 17: air swirler, 18: partition, 19: inlet guide vane (compressor), 20: generator, 21a: shaft (gas generator), 21b: shaft (power turbine), 22: rotation speed detector , 23: Turbine casing, 24: Feed water heater, 25: Boiler, 26: Steam superheater, 30: Combustion hole, 50: Combustion chamber, 60: Second steam flow rate detection means, 100: Gaster Suction air (atmospheric pressure), 101: compressed 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, 120: flame zone, 200: 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: steam supply system to steam consuming equipment, 304: steam discharge system, 305: steam pressure detector, 306: steam temperature detector, 311: first steam Flow rate control valve, 312: Second steam flow rate control valve, 313: Steam flow rate control valve for sending air to the steam consumption facility, 314: Steam release valve, 321: First steam, 322 : Second steam, 322a: other part of steam of second steam, 322b: part of steam of second steam, 400: controller, 401: first computing unit, 402: second Computing unit 403: third computing unit 404: fourth computing unit 405: steam density computing unit 411: first steam flow rate command value 412: second steam flow rate command value 421: first The valve opening command value of the steam flow control valve of 422: The valve opening command value of the second steam flow control valve.

Claims (7)

Compressor for compressing air, gas turbine combustor for combusting fuel using compression air compressed by compressor and generating combustion gas, and turbine driven by combustion gas generated by gas turbine combustor A gas turbine equipped with an exhaust heat recovery boiler that generates steam using exhaust gas discharged from the turbine of the gas turbine as a heat source, a steam supply system that supplies steam generated in the exhaust heat recovery boiler to a steam consuming facility, In a thermoelectric variable cogeneration system that injects a part of steam supplied to a steam supply system into a gas turbine through a steam injection system connected to the steam supply system,
As the steam injection system, a first steam system for injecting a part of the steam to a position upstream of the flame zone with respect to the flow of the combustion gas in the gas turbine combustor, and a combustion gas in the gas turbine combustor Arranging a second steam system for injecting another part of the steam at a position downstream of the flame zone with respect to the flow;
A first steam flow rate adjusting valve for adjusting a flow rate of the first steam injected through the first steam system, and a second steam flow rate adjusting valve for adjusting a flow rate of the second steam injected through the second steam system. Installed in the first steam system and the second steam system,
A fuel flow detector for detecting the fuel flow rate of the fuel to be supplied to the gas turbine combustor;
Installing a steam flow rate detecting means for detecting a flow rate of the second steam injected into the gas turbine combustor in the second steam system;
A steam pressure detector and a steam temperature detector are respectively installed in the steam supply system,
A first steam flow rate adjusting valve provided in the first steam system based on a detected value of the fuel flow rate detected by the fuel flow rate detector and a detected value of the second steam flow rate detected by the steam flow rate detecting means. The thermoelectric variable cogeneration system is equipped with a controller for controlling the amount of injected steam supplied to the gas turbine combustor by adjusting the opening of the gas turbine. In the thermoelectric variable cogeneration system according to claim 1,
The steam flow rate detecting means is a flow meter for detecting a flow rate of steam flowing through the second steam system, a detector for detecting an opening degree of a second steam flow rate adjusting valve installed in the second steam system, or A thermoelectrically variable cogeneration system, characterized by being a command value detector for commanding the opening degree of the second steam flow rate regulating valve. In the thermoelectric variable cogeneration system according to claim 1,
The controller calculates a command value of a steam flow rate of the second steam supplied to the second steam system in accordance with a detection signal detected by a steam detection means for detecting a state of steam supplied to the steam consuming facility. And a second steam flow regulating valve provided in the second steam system is controlled based on the calculated steam flow command value. The thermoelectric variable cogeneration system according to claim 3,
The steam detection means for detecting the state of the steam supplied to the steam consuming equipment includes a steam pressure detector for detecting the pressure of the steam installed in the steam system for supplying the steam generated in the exhaust heat recovery boiler, and the steam supply system. A detector that detects the opening of a third steam flow rate adjusting valve installed in a steam system that supplies steam to the steam consuming equipment, or a command value that commands the opening of the third steam flow rate adjusting valve; A thermoelectric variable cogeneration system characterized by being a detector. Compressor for compressing air, gas turbine combustor for combusting fuel using compression air compressed by compressor and generating combustion gas, and turbine driven by combustion gas generated by gas turbine combustor A gas turbine equipped with an exhaust heat recovery boiler that generates steam using exhaust gas discharged from the turbine of the gas turbine as a heat source, a steam supply system that supplies steam generated in the exhaust heat recovery boiler to a steam consuming facility, In a thermoelectric variable cogeneration system that injects a part of steam supplied to a steam supply system into a gas turbine through a steam injection system connected to the steam supply system,
As the steam injection system, a first steam system for injecting a part of steam injected into a position upstream of the flame zone with respect to the flow of combustion gas in the gas turbine combustor, and combustion in the gas turbine combustor A second steam system for injecting another part of the steam to be injected at a position downstream of the flame zone with respect to the gas flow;
A first steam flow rate adjusting valve for adjusting a flow rate of the first steam injected through the first steam system, and a second steam flow rate adjusting valve for adjusting a flow rate of the second steam injected through the second steam system. Installed in the first steam system and the second steam system,
A fuel flow detector for detecting the fuel flow rate of the fuel to be supplied to the gas turbine combustor;
Installing a steam flow rate detecting means for detecting a flow rate of the second steam injected into the gas turbine combustor in the second steam system;
A steam pressure detector and a steam temperature detector are respectively installed in the steam supply system,
The amount of injected steam supplied to the gas turbine combustor by adjusting the opening of the first steam flow rate adjusting valve provided in the first steam system based on the detected value of the fuel flow rate detected by the fuel flow rate detector. Installed a controller to control
The controller calculates a steam flow rate of the first steam, which is an injection steam amount supplied to the gas turbine combustor through the first steam system based on the fuel flow rate detector, and calculates a first steam flow rate adjustment valve. A first computing unit that outputs a first steam flow rate command value that controls the opening degree of
Based on the detected value of the steam pressure detected by the steam pressure detector, the second steam is calculated by calculating the steam flow rate of the second steam that is the amount of injected steam supplied to the gas turbine combustor through the second steam system. A second computing unit for outputting a second steam flow rate command value for controlling the opening degree of the flow rate regulating valve;
The first computing unit is configured to input the second steam flow rate command value computed by the second computing unit and output the first steam flow rate command value,
The opening degree of the first steam flow rate adjustment valve and the opening degree of the second steam flow rate adjustment valve are limited based on the detection values of the steam temperature detector and the steam pressure detector. Thermoelectric variable cogeneration system. The thermoelectric variable cogeneration system according to claim 5,
The second computing unit provided in the controller is a second steam supplied to the second steam system according to a detection signal detected by a steam detection means for detecting a state of the steam supplied to the steam consuming equipment. The steam flow command value is calculated, and the second steam flow control valve provided in the second steam system is controlled based on the calculated second steam flow command value. system. The thermoelectric variable cogeneration system according to claim 6,
Steam detection means for detecting the state of the steam supplied to the steam consuming equipment is a steam pressure detector for detecting the pressure of the steam installed in the steam supply system for supplying the steam generated in the exhaust heat recovery boiler to the steam consuming equipment. , A detector for detecting an opening degree of a third steam flow rate adjusting valve installed in the steam system for supplying steam to the steam consuming equipment via the steam supply system, or an opening degree of the third steam flow rate adjusting valve A thermoelectrically variable cogeneration system, characterized by being a detector for command values for commanding.

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