Control device, control amount calculation method, and program

Abstract

Provided is a control device that, in a plant including a gas turbine and a CO2 collection device, can estimate an exhaust gas flow rate and CO2 concentration corresponding to a change in the load of the gas turbine, the exhaust gas flow rate and CO2 concentration being required for controlling the CO2 collection device. This control device, which is for a plant including a gas turbine and a CO2 collection device, comprises: a means for calculating an intake flow rate on the basis of the temperature of air suctioned by a compressor and an IGV opening; a means for calculating a fuel flow rate on the basis of a fuel instruction value; a means for calculating an exhaust gas flow rate on the basis of the intake flow rate and the fuel flow rate; and a means for calculating a CO2 concentration contained in the exhaust gas on the basis of the exhaust gas flow rate and the fuel flow rate.

Description

Title of Invention CONTROL DEVICE, CONTROL VARIABLE CALCULATION METHOD, AND PROGRAM Technical Field

[0001] The present disclosure relates to a control device, a control variable calculation method, and a program for a plant including a gas turbine and a CO2 capture plant. The present disclosure claims priority based on Japanese Patent Application No. 2023-019762, filed in Japan on February 13, 2023, the content of which is incorporated herein by reference. Background Art

[0002] Disclosed in PTL 1 is a CO2 capture plant that removes CO2 from a CO2-containing exhaust gas and that captures the removed CO2, the exhaust gas being discharged from a boiler. The CO2 capture plant includes an absorption tower that removes CO2 in an exhaust gas and a regeneration tower that removes CO2 from absorbing liquid with CO2 absorbed thereinto at the absorption tower so as to regenerate the absorbing liquid. The absorbing liquid regenerated at the regeneration tower is reused at the absorption tower. Extraction of CO2 from absorbing liquid at the regeneration tower requires steam as a heat source. The amount of steam is related to a CO2 capturing rate, and it is possible to achieve a target CO2 capturing rate by appropriately controlling the amount of steam. In PTL 1, the amount of steam required to achieve a target CO2 capturing rate is determined based on the amount of circulation of absorbing liquid circulating between the regeneration tower and the absorption tower. Then, the amount of circulation of absorbing liquid required to achieve the target capturing rate is determined based on a measured value of the amount of exhaust gas and a measured value of the concentration of CO2 contained in an exhaust gas. Then, the flow rate of steam determined based on those values is controlled such that the target CO2 capturing rate can be maintained.

[0003] The CO2 capture plant may be applied to a power generation plant such as a gas turbine or a gas turbine combined cycle. Citation List Patent Literature

[0004] [PTL 1] Japanese Unexamined Patent Application Publication No. 2011-528 Summary of Invention Technical Problem

[0005] In the case of the technique disclosed in PTL 1, a desired absorbing liquid flow rate and a desired steam flow rate are determined by using the amount of exhaust gas and CO2 concentration obtained by directly measuring an exhaust gas. However, measured values may be measured with measurement delay, and in a case where there is an excessive change in exhaust gas flow rate or CO2 concentration, an error may occur regarding follow-up control with respect to a target value. In a case where a gas turbine or a gas turbine combined cycle is combined with a CO2 capture plant in a power generation plant where a sudden load change is expected, there may be a time period in which a target CO2 capturing rate cannot be achieved.

[0006] The present disclosure provides a control device, a control variable calculation method, and a program with which it is possible to solve the above-described problems. Solution to Problem

[0007] According to the present disclosure, there is provided a control device for a plant including a gas turbine and a CO2 capture plant that captures CO2 from an exhaust gas discharged by the gas turbine, the device including intake air flow rate calculation methods for calculating an intake air flow rate, which is a flow rate of air sucked by a compressor of the gas turbine, based on a temperature of the air sucked by the compressor and an opening degree of an inlet guide vane (IGV) of the gas turbine, fuel flow rate calculation methods for calculating a fuel flow rate of fuel supplied to a combustor of the gas turbine based on a fuel command of the gas turbine, exhaust gas flow rate calculation methods for calculating a flow rate of the exhaust gas based on the intake air flow rate and the fuel flow rate, and CO2 concentration calculation methods for calculating concentration of CO2 contained in the exhaust gas based on the flow rate of the exhaust gas and the fuel flow rate.

[0008] According to the present disclosure, there is provided a control variable calculation method for a plant including a gas turbine and a CO2 capture plant that captures CO2 from an exhaust gas discharged by the gas turbine, the method including a step of calculating an intake air flow rate, which is a flow rate of air sucked by a compressor of the gas turbine, based on a temperature of the air sucked by the compressor and an opening degree of an inlet guide vane (IGV) of the gas turbine, a step of calculating a fuel flow rate of fuel supplied to a combustor of the gas turbine based on a fuel command of the gas turbine, a step of calculating a flow rate of the exhaust gas based on the intake air flow rate and the fuel flow rate, and a step of calculating concentration of CO2 contained in the exhaust gas based on the flow rate of the exhaust gas and the fuel flow rate.

[0009] According to the present disclosure, there is provided a program for a plant including a gas turbine and a CO2 capture plant that captures CO2 from an exhaust gas discharged by the gas turbine, the program causing a computer to execute a process including a step of calculating an intake air flow rate, which is a flow rate of air sucked by a compressor of the gas turbine, based on a temperature of the air sucked by the compressor and an opening degree of an inlet guide vane (IGV) of the gas turbine, a step of calculating a fuel flow rate of fuel supplied to a combustor of the gas turbine based on a fuel command of the gas turbine, a step of calculating a flow rate of the exhaust gas based on the intake air flow rate and the fuel flow rate, and a step of calculating concentration of CO2 contained in the exhaust gas based on the flow rate of the exhaust gas and the fuel flow rate. Advantageous Effects of Invention

[0010] According to the control device, the control variable calculation method, and the program described above, it is possible to estimate an exhaust gas flow rate or CO2 concentration in accordance with a change in load, and thus it is possible to accurately follow up a target CO2 capturing value even in a case where the speed of changes in load is high. Brief Description of Drawings

[0011] Fig. 1 is a schematic diagram showing an example of a plant according to a first embodiment. Fig. 2 is a block diagram showing an example of a control variable estimation unit according to the first embodiment. Fig. 3 is a flowchart showing an example of a process of estimating an exhaust gas flow rate and CO2 concentration according to the first embodiment. Fig. 4 is a block diagram showing an example of a control variable estimation unit according to a second embodiment. Fig. 5 is a block diagram showing an example of a control variable estimation unit according to a third embodiment. Fig. 6 is a block diagram showing an example of a control variable estimation unit according to a fourth embodiment. Fig. 7 is a schematic diagram showing an example of a plant according to a fifth embodiment. Fig. 8 is a block diagram showing an example of a control variable estimation unit according to the fifth embodiment. Fig. 9 is a diagram showing an example of a hardware configuration of a gas turbine control device according to each embodiment. Description of Embodiments

[0012] Hereinafter, a method for estimation of an exhaust gas flow rate and CO2 concentration according to the present disclosure will be described with reference to Figs. 1 to 9. <First Embodiment (Configuration) Fig. 1 is a schematic diagram showing an example of a plant according to a first embodiment. A plant 100 includes a gas turbine 10 and a CO2 capture plant 20. The gas turbine 10 includes a compressor 12 that compresses air, a casing 13 that feeds the compressed air, a combustor 16 that mixes the compressed air and a fuel gas with each other and that performs combustion to generate a high-temperature combustion gas, a fuel supply system 15 that supplies the fuel gas to the combustor 16, a turbine 17 that is driven by the combustion gas generated by the combustor 16, and a gas turbine control device 30. An inlet guide vane (IGV) 11 is provided on an inlet side of the compressor 12. The IGV 11 adjusts the amount of air flowing into the compressor 12. A fuel flow rate adjustment valve 14 is provided upstream of the fuel supply system 15. The flow rate of the fuel gas supplied to the combustor 16 is changed as the opening degree of the fuel flow rate adjustment valve 14 is adjusted. Although only one fuel supply system 15 is shown in Fig. 1, there is a case where a plurality of fuel supply systems 15 are present, and in such a case, the fuel flow rate adjustment valve 14 may be provided for each system. A bleed air flow path 18 that connects the compressor 12 and the turbine 17 to each other is provided. The bleed air flow path 18 is provided to partially remove a compressed air from the compressor 12 and to supply, to the turbine 17, the compressed air cooled to a predetermined temperature at a cooler 19. A temperature sensor lAis provided on the inlet side of the compressor 12. The temperature sensor 1A measures the atmospheric temperature and outputs the atmospheric temperature to the gas turbine control device 30. A hygrometer IB may be provided on the inlet side of the compressor 12. The hygrometer IB measures the atmospheric humidity and outputs the atmospheric humidity to the gas turbine control device 30.

[0013] The gas turbine control device 30 controls the gas turbine 10. For example, the gas turbine control device 30 controls the flow rate of a combustion gas supplied to the combustor 16 by adjusting the opening degree of the fuel flow rate adjustment valve 14 based on a fuel command (control signal output (CSO)). For example, the gas turbine control device 30 controls the amount of air sucked by the compressor 12 by adjusting the opening degree of the IGV 11. The gas turbine control device 30 includes a control variable estimation unit 31. The control variable estimation unit 31 estimates the amount of control required to determine the amount of steam required for the CO2 capture plant 20 to achieve a target CO2 capturing rate, that is, the flow rate of an exhaust gas supplied to the CO2 capture plant 20 and the CO2 concentration in the exhaust gas, and transmits the estimated values to the CO2 capture plant 20.

[0014] The CO2 capture plant 20 receives an exhaust gas discharged by the gas turbine 10 and captures CO2 from the exhaust gas. The CO2 capture plant 20 includes a control device 21. The control device 21 acquires an exhaust gas flow rate and CO2 concentration that are transmitted from the gas turbine control device 30 and calculates the amount of steam for achieving a target CO2 capturing rate. For example, a method of determining the amount of circulation of absorbing liquid for achieving a target CO2 capturing rate in accordance with the exhaust gas flow rate and the CO2 concentration and calculating the amount of steam for achieving the target CO2 capturing rate in accordance with the determined amount of circulation of absorbing liquid is disclosed in PTL 1. The control device 21 operates the CO2 capture plant 20 based on the calculated amount of steam and the calculated amount of circulation of absorbing liquid such that the target CO2 capturing rate can be maintained.

[0015] (Configuration of Control Variable Estimation Unit) Next, a method of estimating an exhaust gas flow rate and CO2 concentration by means of the control variable estimation unit 31 will be described with reference to Fig. 2. In a case where the CO2 capture plant 20 is used in combination with a device in which the degree of a change in the amount of exhaust gas supply is small, a measurement value of the exhaust gas flow rate or CO2 concentration may be used. However, in a case where the CO2 capture plant 20 is used in combination with a device such as a gas turbine in which the speed of changes in load is high, responses of measurement equipment for the exhaust gas flow rate and the CO2 concentration cannot keep up with the speed of changes in load, and thus a measurement value of an exhaust gas flow rate or CO2 concentration of a slightly earlier time is obtained in a case where the exhaust gas flow rate or the CO2 concentration is excessively changed in accordance with a change in load. However, in the present embodiment, the control variable estimation unit 31 estimates an exhaust gas flow rate or CO2 concentration based on a parameter (for example, a parameter for a change in output such as a fuel flow rate or an intake air flow rate) that changes in accordance with a change in load in the gas turbine 10 so as to estimate an exhaust gas flow rate or CO2 concentration while following up changes in load. Fig. 2 is a block diagram showing an example of the control variable estimation unit 31 according to the first embodiment. The control variable estimation unit 31 includes intake air flow rate calculation methods 32, fuel flow rate calculation methods 33, exhaust gas flow rate calculation methods 34, fuel-air ratio calculation methods 35, and CO2 concentration calculation methods 36. The control variable estimation unit 31 acquires an IGV opening degree, the atmospheric temperature measured by the temperature sensor 1 A, and a CSO.

[0016] The intake air flow rate calculation methods 32 acquire an IGV opening degree and the atmospheric temperature (may be referred to as a compressor inlet temperature) on the inlet side of the compressor 12 which is measured by the temperature sensor 1A and calculates the flow rate (may be referred to as a compressor intake air flow rate) of air sucked by the compressor 12. For example, the intake air flow rate calculation methods 32 include a lookup table that defines a correspondence relationship between an IGV opening degree, the atmospheric temperature, and a compressor intake air flow rate, and calculates an intake air flow rate of the compressor 12 based on the IGV opening degree, a temperature measured by the temperature sensor 1 A, and the lookup table. Alternatively, the intake air flow rate calculation methods 32 may acquire a measured value of the output of the gas turbine 10 instead of the IGV opening degree, and may calculate an intake air flow rate of the compressor 12 based on the measured value of the output of the gas turbine 10, a temperature measured by the temperature sensor 1A, and a lookup table that defines a correspondence relationship between the output of the gas turbine, the atmospheric temperature, and the compressor intake air flow rate. Alternatively, a sensor that measures the compressor intake air flow rate may be provided on the inlet side of the compressor 12, and an intake air flow rate measured by the sensor may be used instead of calculating an intake air flow rate by means of the intake air flow rate calculation methods 32. In a case of using a lookup table, the compressor intake air flow rate is calculated by performing interpolation calculation regarding data not registered in the table. Interpolation calculation may also be performed in relation to lookup tables as follows.

[0017] The fuel flow rate calculation methods 33 acquire a CSO and calculates the flow rate of fuel supplied to the combustor 16. For example, the fuel flow rate calculation methods 33 include a lookup table that defines a correspondence relationship between a CSO and a fuel flow rate, and calculates a fuel flow rate based on the CSO and the lookup table. Alternatively, the fuel flow rate calculation methods 33 may acquire a measured value of the output of the gas turbine 10 instead of the CSO, and may calculate a fuel flow rate based on the measured value of the output of the gas turbine 10 and a lookup table that defines a correspondence relationship between the output of the gas turbine and a fuel flow rate. Alternatively, a sensor that measures the flow rate of a fuel gas supplied to the combustor 16 may be provided, and a fuel flow rate measured by the sensor may be used instead of calculating a fuel flow rate by means of the fuel flow rate calculation methods 33.

[0018] The exhaust gas flow rate calculation methods 34 calculate an exhaust gas flow rate by obtaining the sum of the intake air flow rate of the compressor 12 that is calculated by the intake air flow rate calculation methods 32 and the fuel flow rate that is calculated by the fuel flow rate calculation methods 33. The control variable estimation unit 31 transmits, to the CO2 capture plant 20, the exhaust gas flow rate that is calculated by the exhaust gas flow rate calculation methods 34.

[0019] The fuel-air ratio calculation methods 35 calculate a fuel-air ratio by dividing the fuel flow rate that is calculated by the fuel flow rate calculation methods 33 by the intake air flow rate of the compressor 12 that is calculated by the intake air flow rate calculation methods 32.

[0020] The CO2 concentration calculation methods 36 acquire the fuel-air ratio calculated by the fuel-air ratio calculation methods 35 to calculate CO2 concentration. For example, the CO2 concentration calculation methods 36 include a lookup table that defines a correspondence relationship between a fuel-air ratio and CO2 concentration, and calculates CO2 concentration based on the fuel-air ratio calculated by the fuel-air ratio calculation methods 35 and the lookup table. Alternatively, the CO2 concentration calculation methods 36 may calculate the CO2 concentration based on a chemical calculation formula. For example, the CO2 concentration calculation methods 36 acquire the fuel flow rate calculated by the fuel flow rate calculation methods 33 and the compressor intake air flow rate of the compressor 12 calculated by the intake air flow rate calculation methods 32, calculates the C content from the fuel flow rate and the composition of fuel (for example, what percentage of carbon is contained), calculates the O content from the compressor intake air flow rate and the composition of the atmosphere (for example, what percentage of oxygen is contained), and calculates the amount of CO2 generated in a case where C and O completely react with each other. In the first embodiment, it is assumed that the composition of fuel like C, H, N, S, and the like is invariable and the proportion of each molecule is a fixed value. The control variable estimation unit 31 transmits, to the CO2 capture plant 20, an estimated value of the CO2 concentration calculated by the CO2 concentration calculation methods 36.

[0021] (Operation) Next, the flow of a process of calculating an exhaust gas flow rate and CO2 concentration will be described with reference to Fig. 3. Fig. 3 is a flowchart showing an example of a process of calculating an exhaust gas flow rate and CO2 concentration according to the first embodiment. The control variable estimation unit 31 acquires the state quantity of the gas turbine 10 (step SI). Examples of the state quantity of the gas turbine 10 include an IGV opening degree, a compressor inlet temperature, and a CSO. Next, the control variable estimation unit 31 (the intake air flow rate calculation methods 32) calculates a compressor intake air flow rate based on a compressor inlet temperature and an IGV opening degree (step S2). Next, the control variable estimation unit 31 (the fuel flow rate calculation methods 33) calculates a fuel flow rate based on a CSO (step S3). Next, the control variable estimation unit 31 (the exhaust gas flow rate calculation methods 34) calculates an exhaust gas flow rate based on the compressor intake air flow rate calculated in step S2 and the fuel flow rate calculated in step S3 (step S4). Next, the control variable estimation unit 31 (the fuel-air ratio calculation methods 35) calculates a fuel-air ratio based on the compressor intake air flow rate calculated in step S2 and the fuel flow rate calculated in step S4 (step S5). Next, the control variable estimation unit 31 (the CO2 concentration calculation methods 36) calculates CO2 concentration based on the fuel-air ratio calculated in step S5 (step S6). Next, the control variable estimation unit 31 transmits, to the control device 21 of the CO2 capture plant 20, the exhaust gas flow rate calculated in step S4 and the CO2 concentration calculated in step S6 (step S7). The CO2 capture plant 20 uses estimated values of the exhaust gas flow rate and the CO2 concentration to control the flow rate of absorbing liquid and the flow rate of steam. The order in which step S2 and step S3 are performed may be reversed.

[0022] (Effects) As described above, according to the present embodiment, estimated values of an exhaust gas flow rate and CO2 concentration are calculated based on the state quantity of the gas turbine, and the CO2 capture plant 20 is notified of these values. Accordingly, the CO2 capture plant 20 can control the flow rate of absorbing liquid and the flow rate of steam based on estimated values of an exhaust gas flow rate and CO2 concentration corresponding to the load of the gas turbine, without depending on the measured values of an exhaust gas flow rate and CO2 concentration measured with measurement delay. Therefore, it is possible to always perform, even with respect to an exhaust gas discharged from the gas turbine 10 in which the speed of changes in load is high, control for achieving a target CO2 capturing rate.

[0023] <Second Embodiment In the first embodiment, the composition of fuel combusted in the gas turbine 10 is invariable (a fixed value) at the time of calculation of CO2 concentration. However, the proportions of molecules (CH4, H2H4, CO2, and the like) contained in a fuel gas vary in practice, and thus the concentration of generated CO2 differs depending on the variation. Since the relationship between a CSO and a fuel flow rate also changes, an exhaust gas flow rate is also influenced. In a second embodiment, the composition of fuel is changed in accordance with the measured composition of fuel.

[0024] Fig. 4 shows an example of the control variable estimation unit 31 according to the second embodiment. The same components as those in the first embodiment are given the same reference numerals, and the description thereof will be omitted. The control variable estimation unit 31 includes the intake air flow rate calculation methods 32, fuel flow rate calculation methods 33a, the exhaust gas flow rate calculation methods 34, the fuel-air ratio calculation methods 35, and CO2 concentration calculation methods 36a. The control variable estimation unit 31 acquires, for example, a measured value of the composition of fuel that is measured by a sensor (not shown) provided for the fuel supply system 15 or an estimated value of the composition of fuel that is calculated through a predetermined method, in addition to an IGV opening degree, the atmospheric temperature measured by the temperature sensor 1 A, and a CSO.

[0025] The fuel flow rate calculation methods 33a acquire the CSO and the measured value or the estimated value of the composition of fuel, and calculates a fuel flow rate. For example, the fuel flow rate calculation methods 33a include a lookup table that defines a correspondence relationship between a CSO, the composition of fuel, and a fuel flow rate, and calculates a fuel flow rate based on the CSO, the measured value or the estimated value of the composition of fuel, and the lookup table. Alternatively, the fuel flow rate calculation methods 33a may calculate the influence on a fuel flow rate by changing the density of fuel in accordance with the composition of fuel, and may calculate a fuel flow rate matching the composition of fuel by reflecting, in the result of fuel flow rate calculation, the change in density of fuel.

[0026] The CO2 concentration calculation methods 36a acquire a fuel-air ratio calculated by the fuel-air ratio calculation methods 35 and the measured value or the estimated value of the composition of fuel to calculate CO2 concentration. For example, the CO2 concentration calculation methods 36a include a lookup table that defines a correspondence relationship between a fuel-air ratio, the composition of fuel, and CO2 concentration, and calculates the CO2 concentration based on the fuel-air ratio calculated by the fuel-air ratio calculation methods 35, the measured value or the estimated value of the composition of fuel, and the lookup table. Alternatively, the CO2 concentration calculation methods 36a may calculate the amount of carbon or hydrogen contained in each molecule based on the composition of fuel, and may calculate the CO2 concentration based on a chemical calculation formula with the calculated amount of carbon or hydrogen.

[0027] (Operation) Next, the flow of a process of calculating an exhaust gas flow rate and CO2 concentration in the second embodiment will be described with reference to Fig. 3. The processing identical to that of the first embodiment will be briefly described. First, the control variable estimation unit 31 acquires the state quantity of the gas turbine 10 (step SI). Next, the control variable estimation unit 31 (the intake air flow rate calculation methods 32) calculates a compressor intake air flow rate based on a compressor inlet temperature and an IGV opening degree (step S2). Next, the control variable estimation unit 31 (the fuel flow rate calculation methods 33a) calculates a fuel flow rate based on a C SO and a measured value or an estimated value of the composition of fuel (step S3). Next, the control variable estimation unit 31 (the exhaust gas flow rate calculation methods 34) calculates an exhaust gas flow rate based on the compressor intake air flow rate calculated in step S2 and the fuel flow rate calculated in step S3 (step S4). Next, the control variable estimation unit 31 (the fuel-air ratio calculation methods 35) calculates a fuel-air ratio based on the compressor intake air flow rate calculated in step S2 and the fuel flow rate calculated in step S4 (step S5). Next, the control variable estimation unit 31 (the CO2 concentration calculation methods 36a) calculates CO2 concentration based on the fuel-air ratio calculated in step S5 and the measured value or the estimated value of the composition of fuel (step S6). Next, the control variable estimation unit 31 transmits, to the control device 21 of the CO2 capture plant 20, the exhaust gas flow rate calculated in step S4 and the CO2 concentration calculated in step S6 (step S7).

[0028] (Effects) According to the second embodiment, in addition to the effect of the first embodiment, it is possible to accurately estimate CO2 concentration and an exhaust gas flow rate in accordance with a change in composition of fuel.

[0029] <Third Embodiment In the first embodiment, a change in humidity in the atmosphere is not taken into consideration. However, in practice, the humidity of air sucked by the compressor 12 of the gas turbine 10 varies and the concentration of CO2 discharged is influenced by humidity. Since the density of air to be sucked changes as humidity changes, a compressor intake air flow rate and an exhaust gas flow rate also change. Therefore, in the third embodiment, the concentration of CO2 is changed in accordance with the atmospheric humidity.

[0030] Fig. 5 shows an example of the control variable estimation unit 31 according to the third embodiment. The same components as those in the first embodiment are given the same reference numerals, and the description thereof will be omitted. The control variable estimation unit 31 includes intake air flow rate calculation methods 32b, the fuel flow rate calculation methods 33, the exhaust gas flow rate calculation methods 34, the fuel-air ratio calculation methods 35, and CO2 concentration calculation methods 36b. The control variable estimation unit 31 acquires the atmospheric humidity measured by the hygrometer IB in addition to an IGV opening degree, the atmospheric temperature measured by the temperature sensor 1 A, and a CSO.

[0031] The intake air flow rate calculation methods 32b acquire the IGV opening degree, the compressor inlet temperature that is measured by the temperature sensor 1 A, and the atmospheric humidity on the inlet side of the compressor 12 that is measured by the hygrometer IB, and calculates a compressor intake air flow rate. For example, the intake air flow rate calculation methods 32 include a lookup table that defines a correspondence relationship between an IGV opening degree, the atmospheric temperature, the atmospheric humidity, and an intake air flow rate, and calculates an intake air flow rate of the compressor 12 based on the IGV opening degree, a temperature measured by the temperature sensor 1A, humidity measured by the hygrometer IB, and the lookup table. Alternatively, the intake air flow rate calculation methods 32b may acquire a measured value of the output of the gas turbine 10 instead of the IGV opening degree, and may calculate the intake air flow rate of the compressor 12 based on the measured value of the output of the gas turbine 10, a temperature measured by the temperature sensor 1 A, humidity measured by the hygrometer IB, and a lookup table that defines a correspondence relationship between the output of the gas turbine, the atmospheric temperature, the atmospheric humidity, and the compressor intake air flow rate. Alternatively, the intake air flow rate calculation methods 32b may calculate the influence on a compressor intake air flow rate by changing the density of air in accordance with humidity, and may calculate a compressor intake air flow rate matching the atmospheric humidity by reflecting, in the result of compressor intake air flow rate calculation, the change in density of air.

[0032] The CO2 concentration calculation methods 36b acquire a fuel-air ratio calculated by the fuel-air ratio calculation methods 35 and the atmospheric humidity measured by the hygrometer IB to calculate CO2 concentration. For example, the CO2 concentration calculation methods 36b include a lookup table that defines a correspondence relationship between a fuel-air ratio, the atmospheric humidity, and CO2 concentration, and calculates the CO2 concentration based on the fuel-air ratio calculated by the fuel-air ratio calculation methods 35, the atmospheric humidity measured by the hygrometer IB, and the lookup table. Alternatively, the CO2 concentration calculation methods 36b may calculate the amount of carbon or hydrogen contained in each molecule in accordance with the atmospheric humidity, and may calculate the CO2 concentration based on a chemical calculation formula with the values thereof.

[0033] (Operation) Next, the flow of a process of calculating an exhaust gas flow rate and CO2 concentration in the third embodiment will be described with reference to Fig. 3. First, the control variable estimation unit 31 acquires the state quantity of the gas turbine 10 (step SI). Next, the control variable estimation unit 31 (the intake air flow rate calculation methods 32b) calculates a compressor intake air flow rate based on a compressor inlet temperature, an IGV opening degree, and a measured value of the atmospheric humidity (step S2). Next, the control variable estimation unit 31 (the fuel flow rate calculation methods 33) calculates a fuel flow rate based on a CSO (step S3). Next, the control variable estimation unit 31 (the exhaust gas flow rate calculation methods 34) calculates an exhaust gas flow rate based on the compressor intake air flow rate calculated in step S2 and the fuel flow rate calculated in step S3 (step S4). Next, the control variable estimation unit 31 (the fuel-air ratio calculation methods 35) calculates a fuel-air ratio based on the compressor intake air flow rate calculated in step S2 and the fuel flow rate calculated in step S4 (step S5). Next, the control variable estimation unit 31 (the CCh concentration calculation methods 36b) calculates CO2 concentration based on the fuel-air ratio calculated in step S5 and the measured value of the atmospheric humidity (step S6). Next, the control variable estimation unit 31 transmits, to the control device 21 of the CO2 capture plant 20, the exhaust gas flow rate calculated in step S4 and the CO2 concentration calculated in step S6 (step S7).

[0034] (Effects) According to the third embodiment, in addition to the effect of the first embodiment, it is possible to accurately estimate CO2 concentration and an exhaust gas flow rate in accordance with a change in atmospheric humidity. Although a case where the configuration of the control variable estimation unit 31 is combined with the configuration in the first embodiment has been described as an example, the configuration of the control variable estimation unit 31 according to a fourth embodiment can be combined with the second embodiment.

[0035] <Fourth Embodiment In the first embodiment, the combustion efficiency of the combustor 16 is not taken into consideration at the time of calculation of the concentration of CO2. However, in practice, a change in combustion efficiency causes a change in the amount of CO2 generated, and the concentration of CO2 is influenced. For example, in a case where there is a decrease in combustion efficiency, fuel may not be completely burned and CO may be generated instead of CO2. Therefore, in a fourth embodiment, the concentration of CO2 is changed in accordance with measured combustion efficiency.

[0036] Fig. 6 shows an example of the control variable estimation unit 31 according to the fourth embodiment. The same components as those in the first embodiment are given the same reference numerals, and the description thereof will be omitted. The control variable estimation unit 31 includes the intake air flow rate calculation methods 32, the fuel flow rate calculation methods 33, the exhaust gas flow rate calculation methods 34, the fuel-air ratio calculation methods 35, and CO2 concentration calculation methods 36c. The control variable estimation unit 31 acquires an IGV opening degree, the atmospheric temperature measured by the temperature sensor 1 A, and a CSO. The control variable estimation unit 31 acquires or estimates the combustion efficiency of the combustor 16. For example, the control variable estimation unit 31 includes a function that outputs combustion efficiency when a measured value of the output of the gas turbine 10 and a turbine inlet temperature (the temperature of a combustion gas on an inlet side of the turbine 17) are input, and inputs the measured value of the output of the gas turbine and a measured value or an estimated value of the turbine inlet temperature to the function to estimate the combustion efficiency.

[0037] The CO2 concentration calculation methods 36c acquire a fuel-air ratio calculated by the fuel-air ratio calculation methods 35 and an estimated value of the combustion efficiency to calculate CO2 concentration. For example, the CO2 concentration calculation methods 36b include a lookup table that defines a correspondence relationship between a fuel-air ratio, combustion efficiency, and CO2 concentration, and calculates the CO2 concentration based on the fuel-air ratio calculated by the fuel-air ratio calculation methods 35, the estimated value of the combustion efficiency, and the lookup table. Alternatively, the CO2 concentration calculation methods 36c may calculate the amount of carbon or hydrogen contained in each molecule in accordance with the combustion efficiency, and may calculate the CO2 concentration based on a chemical calculation formula with the calculated amount of carbon or hydrogen.

[0038] (Operation) Next, the flow of a process of calculating an exhaust gas flow rate and CO2 concentration in the fourth embodiment will be described with reference to Fig. 3. First, the control variable estimation unit 31 acquires the state quantity of the gas turbine 10 (step SI). Next, the control variable estimation unit 31 (the intake air flow rate calculation methods 32) calculates an intake air flow rate based on a compressor inlet temperature and an 1GV opening degree (step S2). Next, the control variable estimation unit 31 (the fuel flow rate calculation methods 33) calculates a fuel flow rate based on a CSO (step S3). Next, the control variable estimation unit 31 (the exhaust gas flow rate calculation methods 34) calculates an exhaust gas flow rate based on the compressor intake air flow rate calculated in step S2 and the fuel flow rate calculated in step S3 (step S4). Next, the control variable estimation unit 31 (the fuelair ratio calculation methods 35) calculates a fuel-air ratio based on the compressor intake air flow rate calculated in step S2 and the fuel flow rate calculated in step S4 (step S5). Next, the control variable estimation unit 31 (the CO2 concentration calculation methods 36c) calculates CO2 concentration based on the fuel-air ratio calculated in step S5 and an estimated value of the combustion efficiency of the combustor 16 (step S6). Next, the control variable estimation unit 31 transmits, to the control device 21 of the CO2 capture plant 20, the exhaust gas flow rate calculated in step S4 and the CO2 concentration calculated in step S6 (step S7).

[0039] (Effects) According to the fourth embodiment, in addition to the effect of the first embodiment, it is possible to accurately estimate CO2 concentration and an exhaust gas flow rate in accordance with a change in combustion efficiency. Although a case where the configuration of the control variable estimation unit 31 is combined with the configuration in the first embodiment has been described as an example, the configuration of the control variable estimation unit 31 according to a fourth embodiment can be combined with any one or more of the second embodiment and the third embodiment.

[0040] <F i fth Embodiment (Configuration) Fig. 7 is a schematic diagram showing an example of a plant according to a fifth embodiment. A plant 100’ is a plant in which the CO2 capture plant 20 is combined with a gas turbine combined cycle including an exhaust gas recirculation (EGR) system. The plant 100’ includes the gas turbine 10, a heat recovery steam generator (HRSG) 40, a steam turbine 41, and the CO2 capture plant 20. An exhaust gas discharged from the gas turbine 10 is sent to the HRSG 40, and after being used in the HRSG 40, the exhaust gas is sent to the CO2 capture plant 20. The HRSG 40 recovers heat from the exhaust gas, generates high-pressure steam, medium-pressure steam, and low-pressure steam, supplies the steam to the steam turbine 41, and supplies the low-pressure steam to a regeneration tower 23 of the CO2 capture plant 20. The HRSG 40 sends the exhaust gas after heat recovery to the CO2 capture plant 20. The CO2 capture plant 20 includes an absorption tower 22 and the regeneration tower 23, and extracts CO2 from the exhaust gas sent from the HRSG 40 by causing absorbing liquid to circulate between the absorption tower 22 and the regeneration tower 23. The low-pressure steam supplied from the HRSG 40 is used for the extraction of CCh, the low-pressure steam used during the extraction of CO2 is condensed into low-pressure hot water, and the generated low-pressure hot water is supplied to the HRSG 40 from the CO2 capture plant 20. The plant 100’ includes an EGR system 50 that returns, to an inlet of the gas turbine 10, a part of the exhaust gas for circulation, the exhaust gas being sent from the HRSG 40 to the CO2 capture plant 20. A part of the exhaust gas sent by the HRSG 40 is sucked into the compressor 12 together with the atmosphere. In a case where the EGR system 50 is included, a gas containing a substance after combustion such as CO2 is sucked. Therefore, unlike the first to fourth embodiments, it is not possible to estimate the concentration of CO2 contained in an exhaust gas simply based on the composition of air and the composition of fuel. Therefore, in the fifth embodiment, CO2 concentration corresponding to an EGR flow rate (the flow rate of a gas returned through the EGR system 50) or an EGR ratio (the ratio of an EGR flow rate to a compressor intake air flow rate) is calculated.

[0041] Fig. 8 shows an example of the control variable estimation unit 31 according to the fifth embodiment. The same components as those in the first embodiment are given the same reference numerals, and the description thereof will be omitted. The control variable estimation unit 31 includes intake air flow rate calculation methods 32d, the fuel flow rate calculation methods 33, the exhaust gas flow rate calculation methods 34, the fuel-air ratio calculation methods 35, and CO2 concentration calculation methods 36d. The control variable estimation unit 31 acquires a measured value or an estimated value of an EGR flow rate or an EGR ratio in addition to an IGV opening degree, the atmospheric temperature measured by the temperature sensor 1 A, and a CSO. An EGR ratio is the ratio of an EGR flow rate to a compressor intake air flow rate. The EGR flow rate can be measured, for example, by using an orifice or the like provided in the EGR system 50.

[0042] The intake air flow rate calculation methods 32d acquire the IGV opening degree, a compressor inlet temperature that is measured by the temperature sensor 1A, and the EGR flow rate or the EGR ratio, and calculates a compressor intake air flow rate. For example, the intake air flow rate calculation methods 32 include a lookup table that defines a correspondence relationship between an IGV opening degree, the atmospheric temperature, an EGR flow rate or an EGR ratio, and a compressor intake air flow rate, and calculates an intake air flow rate of the compressor 12 based on the IGV opening degree, a temperature measured by the temperature sensor 1 A, the EGR flow rate or the EGR ratio acquired by the control variable estimation unit 31, and the lookup table. Alternatively, the intake air flow rate calculation methods 32d may acquire a measured value of the output of the gas turbine 10 instead of the IGV opening degree, and may calculate an intake air flow rate based on the measured value of the output of the gas turbine 10, a temperature measured by the temperature sensor 1 A, the EGR flow rate or the EGR ratio, and a lookup table that defines a correspondence relationship between the output of the gas turbine, the atmospheric temperature, an EGR flow rate or an EGR ratio, and an intake air flow rate. Alternatively, the intake air flow rate calculation methods 32d may calculate the influence on a compressor intake air flow rate by changing the density of a gas sucked by the compressor 12 in accordance with the EGR flow rate or the EGR ratio, and may calculate a compressor intake air flow rate matching the EGR flow rate or the EGR ratio by reflecting, in the result of compressor intake air flow rate calculation, the change in gas density.

[0043] The CO2 concentration calculation methods 36d acquire a fuel-air ratio calculated by the fuel-air ratio calculation methods 35 and the EGR flow rate or the EGR ratio to calculate CO2 concentration. For example, the CO2 concentration calculation methods 36d include a lookup table that defines a correspondence relationship between a fuel-air ratio, an EGR flow rate or an EGR ratio, and CO2 concentration, and calculates the CO2 concentration based on the fuel-air ratio calculated by the fuel-air ratio calculation methods 35, the EGR flow rate or the EGR ratio acquired by the control variable estimation unit 31, and the lookup table. Alternatively, the CO2 concentration calculation methods 36b may calculate the amount of carbon or hydrogen contained in each molecule in accordance with the EGR flow rate or the EGR ratio, and may calculate the CO2 concentration based on a chemical calculation formula with the values thereof.

[0044] (Operation) Next, the flow of a process of calculating an exhaust gas flow rate and CO2 concentration in the fifth embodiment will be described with reference to Fig. 3. First, the control variable estimation unit 31 acquires the state quantity of the gas turbine 10 (step SI). Next, the control variable estimation unit 31 (the intake air flow rate calculation methods 32d) calculates a compressor intake air flow rate based on a compressor inlet temperature, an IGV opening degree, and an EGR flow rate or an EGR ratio (step S2). Next, the control variable estimation unit 31 (the fuel flow rate calculation methods 33) calculates a fuel flow rate based on a CSO (step S3). Next, the control variable estimation unit 31 (the exhaust gas flow rate calculation methods 34) calculates an exhaust gas flow rate based on the compressor intake air flow rate calculated in step S2 and the fuel flow rate calculated in step S3 (step S4). Next, the control variable estimation unit 31 (the fuel-air ratio calculation methods 35) calculates a fuel-air ratio based on the compressor intake air flow rate calculated in step S2 and the fuel flow rate calculated in step S4 (step S5). Next, the control variable estimation unit 31 (the CO2 concentration calculation methods 36d) calculates CO2 concentration based on the fuel-air ratio calculated in step S5 and the EGR flow rate or the EGR ratio (step S6). Next, the control variable estimation unit 31 transmits, to the control device 21 of the CO2 capture plant 20, the exhaust gas flow rate calculated in step S4 and the CO2 concentration calculated in step S6 (step S7).

[0045] (Effects) According to the fifth embodiment, even in the case of a plant including the EGR system 50, it is possible to accurately estimate CO2 concentration and an exhaust gas flow rate. Although a case where the configuration of the control variable estimation unit 31 is combined with the configuration in the first embodiment has been described as an example, the configuration of the control variable estimation unit 31 according to the fifth embodiment can be combined with any one or more of the second to fourth embodiments.

[0046] As described above, in the case of the control variable estimation unit 31 according to the first to second embodiments, in the plants 100 and 100’ including the gas turbine 10 and the CO2 capture plant 20, it is possible to estimate an exhaust gas flow rate and CO2 concentration while following up changes in load of the gas turbine 10 regarding an exhaust gas flow rate and CO2 concentration required to control the CO2 capture plant 20. Accordingly, even in a case where the speed of changes in load is high, it is possible to appropriately operate the CO2 capture plant 20 and to maintain a target CO2 capturing rate. In each of the above-described embodiments, the control variable estimation unit 31 is provided in the gas turbine control device 30. However, the present disclosure is not limited thereto. For example, the control variable estimation unit 31 may be provided as an independent device. In the first to fourth embodiments, a plant including a gas turbine and a CO2 capture plant has been described as an example. However, the methods for estimation of an exhaust gas flow rate and CO2 concentration estimation of the first to fourth embodiments may be applied to a plant including a gas turbine, a steam turbine, an HRSG, and a CO2 capture plant (a plant obtained by excluding the EGR system from the configuration shown in Fig. 7). In the fifth embodiment, a plant including a gas turbine, a steam turbine, an HRSG, an EGR system, and a CO2 capture plant has been described as an example. However, the method for estimation of an exhaust gas flow rate and CO2 concentration in the fifth embodiment may be applied to a plant including a gas turbine, an EGR system, and a CO2 capture plant (a plant in which an EGR system that returns an exhaust gas discharged by the turbine 17 to the inlet side of the compressor 12 is added to the configuration shown in Fig. 1).

[0047] Fig. 9 is a diagram showing an example of a hardware configuration of the gas turbine control device according to each embodiment. A computer 900 includes a CPU 901, a main storage device 902, an auxiliary storage device 903, an input and output interface 904, and a communication interface 905. The gas turbine control device 30 described above is implemented in the computer 900. Each of the functions described above is stored in the auxiliary storage device 903 in the form of a program. The CPU 901 reads out the program from the auxiliary storage device 903, expands the program in the main storage device 902, and executes the above-described processing according to the program. The CPU 901 allocates a storage area in the main storage device 902 according to the program. The CPU 901 allocates a storage area for storing data being processed, in the auxiliary storage device 903 according to the program.

[0048] A program for implementing all or a part of the functions of the gas turbine control device 30 may be recorded on a computer-readable recording medium, and the program recorded on the recording medium may be read by a computer system and executed to perform processes by each functional unit. The "computer system" herein includes an OS and hardware such as peripheral devices. The "computer system" also includes a homepage providing environment (or a display environment) in a case where a WWW system is used. The "computer-readable recording medium" refers to a portable medium such as a CD, a DVD, or a USB, or a storage device such as a hard disk built into the computer system. In a case where the program is distributed to the computer 900 through a communication line, the computer 900 to which the program is distributed may expand the program in the main storage device 902 and execute the processing described above. The program described above may be for realization of a part of the above functions, or may realize the above-described functions in combination with a program already recorded in the computer system.

[0049] While some embodiments of the present disclosure have been described above, these embodiments have been presented by way of example only, and are not intended to limit the scope of the invention. These embodiments can be implemented in various other forms, and various omissions, replacements, and changes can be made without departing from the gist of the invention. These embodiments and modifications thereof are included in the scope of the invention described in the claims and the equivalent scope thereof, as well as in the scope and gist of the invention.

[0050] <Appendix> The control device, the control variable calculation method, and the program described in each embodiment are understood as follows, for example.

[0051] (1) A control device according to a first aspect is a control device for a plant including a gas turbine and a CO2 capture plant that captures CO2 from an exhaust gas discharged by the gas turbine, the device including intake air flow rate calculation methods for calculating an intake air flow rate, which is a flow rate of air sucked by a compressor of the gas turbine, based on a temperature of the air sucked by the compressor and an opening degree of an inlet guide vane (IGV) of the gas turbine, fuel flow rate calculation methods for calculating a fuel flow rate of fuel supplied to a combustor of the gas turbine based on a fuel command of the gas turbine, exhaust gas flow rate calculation methods for calculating a flow rate of the exhaust gas based on the intake air flow rate and the fuel flow rate, and CO2 concentration calculation methods for calculating concentration of CO2 contained in the exhaust gas based on the flow rate of the exhaust gas and the fuel flow rate. Accordingly, it is possible to control the flow rate of absorbing liquid and the flow rate of steam based on estimated values of an exhaust gas flow rate and CO2 concentration corresponding to the load of the gas turbine. Therefore, it is possible to always perform, even with respect to an exhaust gas discharged from the gas turbine 10 in which the speed of changes in load is high, control for achieving a target CO2 capturing rate.

[0052] (2) The control device according to a second aspect is the control device of (1), in which the fuel flow rate calculation methods calculate the fuel flow rate based on the fuel command and fuel composition of the fuel, and the CO2 concentration calculation methods calculate the CO2 concentration based on the flow rate of the exhaust gas, the fuel flow rate, and the fuel composition. Accordingly, it is possible to accurately estimate CO2 concentration and an exhaust gas flow rate in accordance with a change in composition of fuel.

[0053] (3) The control device according to a third aspect is the control device of (1) or (2), in which the intake air flow rate calculation methods calculate the intake air flow rate based on the temperature, the opening degree, and humidity of the air sucked by the compressor, and the CO2 concentration calculation methods calculate the CO2 concentration based on the flow rate of the exhaust gas, the fuel flow rate, and the humidity. Accordingly, it is possible to accurately estimate CO2 concentration and an exhaust gas flow rate in accordance with a change in atmospheric humidity.

[0054] (4) The control device according to a fourth aspect is the control device of any one of (1) to (3), in which the CO2 concentration calculation methods calculate the CO2 concentration based on the flow rate of the exhaust gas, the fuel flow rate, and a combustion efficiency of the combustor. Accordingly, it is possible to accurately estimate CO2 concentration and an exhaust gas flow rate in accordance with a change in combustion efficiency.

[0055] (5) The control device according to a fifth aspect is the control device according to any one of (1) to (4), in which the plant includes an exhaust gas recirculation system that circulates a part of the exhaust gas discharged by the gas turbine to an inlet side of the gas turbine, the intake air flow rate calculation methods calculate the intake air flow rate based on the temperature, the opening degree, and a circulation flow rate indicating a flow rate of the exhaust gas circulated by the exhaust gas recirculation system, and the CO2 concentration calculation methods calculate the CO2 concentration based on the flow rate of the exhaust gas, the fuel flow rate, and the circulation flow rate. Accordingly, even in the case of a plant including the EGR system 50, it is possible to accurately estimate CO2 concentration and an exhaust gas flow rate.

[0056] (6) The control device according to a sixth aspect is the control device according to any one of (1) to (5), in which the flow rate of the exhaust gas and the CO2 concentration are transmitted to a control device of the CO2 capture plant. Accordingly, regarding the CO2 capture plant, it is possible to perform operation such that a target CO2 capturing rate is achieved regardless of a change in load of the gas turbine or the like.

[0057] (7) A control variable calculation method according to a seventh aspect is a control variable calculation method for a plant including a gas turbine and a CO2 capture plant that captures CO2 from an exhaust gas discharged by the gas turbine, the method including a step of calculating an intake air flow rate, which is a flow rate of air sucked by a compressor of the gas turbine, based on a temperature of the air sucked by the compressor and an opening degree of an inlet guide vane (IGV) of the gas turbine, a step of calculating a fuel flow rate of fuel supplied to a combustor of the gas turbine based on a fuel command of the gas turbine, a step of calculating a flow rate of the exhaust gas based on the intake air flow rate and the fuel flow rate, and a step of calculating concentration of CO2 contained in the exhaust gas based on the flow rate of the exhaust gas and the fuel flow rate.

[0058] (8) A program according to an eighth aspect is a program for a plant including a gas turbine and a CO2 capture plant that captures CO2 from an exhaust gas discharged by the gas turbine, the program causing a computer to execute a process including a step of calculating an intake air flow rate, which is a flow rate of air sucked by a compressor of the gas turbine, based on a temperature of the air sucked by the compressor and an opening degree of an inlet guide vane (IGV) of the gas turbine, a step of calculating a fuel flow rate of fuel supplied to a combustor of the gas turbine based on a fuel command of the gas turbine, a step of calculating a flow rate of the exhaust gas based on the intake air flow rate and the fuel flow rate, and a step of calculating concentration of CO2 contained in the exhaust gas based on the flow rate of the exhaust gas and the fuel flow rate. Industrial Applicability

[0059] According to the control device, the control variable calculation method, and the program described above, it is possible to estimate an exhaust gas flow rate or CO2 concentration in accordance with a change in load, and thus it is possible to accurately follow up a target CO2 capturing value even in a case where the speed of changes in load is high. Reference Signs List

[0060] 100, 100’: plant 10: gas turbine 11: IGV 12: compressor 13: casing 14: fuel flow rate adjustment valve 15: fuel supply system 16: combustor 17: turbine 18: bleed air flow path 19: cooler 1 A: temperature sensor IB: hygrometer 20: CO2 capture plant 21: control device 22: absorption tower 23: regeneration tower 30: gas turbine control device 31: control variable estimation unit 32, 32b, 32d: intake air flow rate calculation methods 33, 33a: fuel flow rate calculation methods 34: exhaust gas flow rate calculation methods 35: fuel-air ratio calculation methods 36, 36a, 36b, 36c, 36d: CCh concentration calculation methods 40: ERSG 41: steamturbine 50: EGR system 900: computer 901: CPU 902: main storage device 903: auxiliary storage device 904: input and output interface 905: communication interface

Claims

1. A control device for a plant including a gas turbine and a CO2 capture plant that captures CO2 from an exhaust gas discharged by the gas turbine, the device comprising: intake air flow rate calculation methods for calculating an intake air flow rate, which is a flow rate of air sucked by a compressor of the gas turbine, based on a temperature of the air sucked by the compressor and an opening degree of an inlet guide vane (IGV) of the gas turbine;fuel flow rate calculation methods for calculating a fuel flow rate of fuel supplied to a combustor of the gas turbine based on a fuel command of the gas turbine;exhaust gas flow rate calculation methods for calculating a flow rate of the exhaust gas based on the intake air flow rate and the fuel flow rate; andCO2 concentration calculation methods for calculating concentration of CO2 contained in the exhaust gas based on the flow rate of the exhaust gas and the fuel flow rate.

2. The control device according to Claim 1,wherein the fuel flow rate calculation methods calculate the fuel flow rate based on the fuel command and fuel composition of the fuel, andthe CO2 concentration calculation methods calculate the CO2 concentration based on the flow rate of the exhaust gas, the fuel flow rate, and the fuel composition.

3. The control device according to Claim 1 or 2,wherein the intake air flow rate calculation methods calculate the intake air flow rate based on the temperature, the opening degree, and humidity of the air sucked by the compressor, andthe CO2 concentration calculation methods calculate the CO2 concentration based on the flow rate of the exhaust gas, the fuel flow rate, and the humidity.

4. The control device according to Claim 1 or 2,wherein the CO2 concentration calculation methods calculate the CO2 concentration based on the flow rate of the exhaust gas, the fuel flow rate, and a combustion efficiency of the combustor.

5. The control device according to Claim 1 or 2,wherein the plant includes an exhaust gas recirculation system that circulates a part of the exhaust gas discharged by the gas turbine to an inlet side of the gas turbine,the intake air flow rate calculation methods calculate the intake air flow rate based on the temperature, the opening degree, and a circulation flow rate indicating a flow rate of the exhaust gas circulated by the exhaust gas recirculation system, andthe CO2 concentration calculation methods calculate the CO2 concentration based on the flow rate of the exhaust gas, the fuel flow rate, and the circulation flow rate.

6. The control device according to Claim 1 or 2,wherein the flow rate of the exhaust gas and the CO2 concentration are transmitted to a control device of the CO2 capture plant.

7. A control variable calculation method for a plant including a gas turbine and a CO2 capture plant that captures CO2 from an exhaust gas discharged by the gas turbine, the method comprising:a step of calculating an intake air flow rate, which is a flow rate of air sucked by a compressor of the gas turbine, based on a temperature of the air sucked by the compressor and an opening degree of an inlet guide vane (IGV) of the gas turbine;a step of calculating a fuel flow rate of fuel supplied to a combustor of the gas turbine based on a fuel command of the gas turbine;a step of calculating a flow rate of the exhaust gas based on the intake air flow rate and the fuel flow rate; anda step of calculating concentration of CO2 contained in the exhaust gas based on the flow rate of the exhaust gas and the fuel flow rate.

8. A program for a plant including a gas turbine and a CO2 capture plant that captures CO2 from an exhaust gas discharged by the gas turbine, the program causing a computer to execute a process comprising:a step of calculating an intake air flow rate, which is a flow rate of air sucked by a compressor of the gas turbine, based on a temperature of the air sucked by the compressor and an opening degree of an inlet guide vane (IGV) of the gas turbine;a step of calculating a fuel flow rate of fuel supplied to a combustor of the gas turbine based on a fuel command of the gas turbine;a step of calculating a flow rate of the exhaust gas based on the intake air flow rate and the fuel flow rate; anda step of calculating concentration of CO2 contained in the exhaust gas based on the flow rate of the exhaust gas and the fuel flow rate.INTERNATIONAL SEARCH REPORT International application No. PCT / JP2023 / 031542A. CLASSIFICATION OF SUBJECT MATTERF02C 7 / 00(2OO6.Ol)i; F01D25 / 00(2006.01)1; F02C 3 / 30(2006.01)1; F02C 6 / 00(2006.01)1; F02C 7 / 042(2006.01)1;F02C 9 / 22(2006.01)1; F02C9 / 50(2006.01)1; F23R 3 / 00(2006.01)iFI: F02C7 / 00 A; F02C7 / 042; F02C9 / 50; F02C6 / 00 E; F02C9 / 22 A; F01D25 / 00 V; F02C3 / 30 D; F23R3 / 00 BAccording to International Patent Classification (IPC) or to both national classification and IPCB.FIELDS SEARCHEDMinimum documentation searched (classification system followed by classification symbols)F02C7 / 00; F01D25 / 00; FO2C3 / 3O; F02C6 / 00; F02C7 / 042; F02C9 / 22; F02C9 / 50; F23R3 / 00Documentation searched other than minimum documentation to the extent that such documents are included in the fields searchedPublished examined utility model applications of Japan 1922-1996Published unexamined utility model applications of Japan 1971-2023Registered utility model specifications of Japan 1996-2023Published registered utility model applications of Japan 1994-2023Electronic data base consulted during the international search (name of data base and, where practicable, search terms used)C. DOCUMENTS CONSIDERED TO BE RELEVANTCategory* Citation of document, with indication, where appropriate, of the relevant passages Relevant to claim No. Y Y JP 2021-161924 A (MITSUBISHI POWER, LTD.) 11 October 2021 (2021-10-11) paragraphs [0013]-[0070], fig. 1-10 JP 2016-37883 A (MITSUBISHI HITACHI POWER SYSTEMS, LTD.) 22 March 2016 (2016-03-22) paragraphs [0028]-[0107], fig. 1-18 1-8 1-8 Y JP 2002-129984 A (ISHIKA WAJIMA HARIMA HEAVY IND. CO., LTD.) 09 May 2002 (2002-05-09) paragraph [0026] 1-8 Y US 6230103 Bl (POWER TECH ASSOCIATES, INC.) 08 May 2001 (2001-05-08) column 1, line 58 to column 2, line 59, fig. 1A-5 1-8 Y JP 2015-102071 A (MITSUBISHI HITACHI POWER SYSTEMS, LTD.) 04 June 2015 (2015-06-04) paragraphs [0021]-[0081], fig. 1-24 2-6|« / | Further documents are listed in the continuation of Box C. | Z | See patent family annex.* Special categories of cited documents:“A” document defining the general state of the art which is not considered“T” later document published after the international filing date or priority“O”“P”to be of particular relevanceearlier application or patent but published on or after the international filing datedocument which may throw doubts on priority claim(s) or which is cited to establish the publication date of another citation or other special reason (as specified)document referring to an oral disclosure, use, exhibition or other meansdocument published prior to the international filing date but later than the priority date claimed‘Y’date and not in conflict with the application but cited to understand the principle or theory underlying the inventiondocument of particular relevance; the claimed invention cannot be considered novel or cannot be considered to involve an inventive step when the document is taken alonedocument of particular relevance; the claimed invention cannot be considered to involve an inventive step when the document is combined with one or more other such documents, such combination being obvious to a person skilled in the aitdocument member of the same patent familyDate of the actual completion of the international searchDate of mailing of the international search report21 September 2023Name and mailing address of the ISA / JPJapan Patent Office (ISA / JP)3-4-3 Kasumigaseki, Chiyoda-ku, Tokyo 100-8915JapanAuthorized officer10 October 2023Telephone No.INTERNATIONAL SEARCH REPORT International application No. PCT / JP2023 / 031542 C. DOCUMENTS CONSIDERED TO BE RELEVANT Category* Citation of document, with indication, where appropriate, of the relevant passages Relevant to claim No. Y JP 2004-169667 A (MITSUBISHI HEAVY INDUSTRIES, LTD.) 17 June 2004 (2004-06-17) claim 4 3 Y Y JP 2013-83254 A (ALSTOM TECHNOLOGY LTD.) 09 May 2013 (2013-05-09) paragraphs [0029]-[0043], fig. 1-6 JP 2020-139480 A (MITSUBISHI HITACHI POWER SYSTEMS, LTD.) 03 September 2020 (2020-09-03) paragraphs [0024]-[0053], fig. 1-4 5 6 A JP 2013-22520 A (CENTRAL RESEARCH INSTITUTE OF ELECTRIC POWER INDUSTRY) 04 February 2013 (2013-02-04) entire text, all drawings 1-8 A A JP 2021-21332 A (MITSUBISHI POWER, LTD.) 18 February 2021 (2021-02-18) entire text, all drawings WO 2014 / 132932 Al (MITSUBISHI HITACHI POWER SYSTEMS, LTD.) 04 September 2014 (2014-09-04) entire text, all drawings 1-8 1-8 A JP 2006-132931 A (HITACHI, LTD.) 25 May 2006 (2006-05-25) entire text, all drawings 1-8 A P, A JP 2005-300019 A (NIIGATA POWER SYSTEMS CO., LTD.) 27 October 2005 (2005-10-27) entire text, all drawings WO 2023 / 095362 Al (MITSUBISHI POWER, LTD.) 01 June 2023 (2023-06-01) entire text, all drawings 1-8 1-8INTERNATIONAL SEARCH REPORT International application No. PCT / JP2023 / 031542 Information on patent family members Paten cited in t document search report Publication date (day / month / year) Patent family me mber(s) Publication date (day / month / year) JP 2021-161924 A 11 October 2021 US 2023 / 0151766 Al paragraphs [0023]-[0101], fig. 1-10 WO 2021 / 200256 Al CN 115427671 A JP 2016-37883 A 22 March 2016 US 2017 / 0292458 Al paragraphs [0046]-[0128], fig. 1-18 WO 2016 / 021390 Al KR 10-2017-0007424 A CN 106460678 A JP 2002-129984 A 09 May 2002 (Family: none) US 6230103 Bl 08 May 2001 (Family: none) JP 2015-102071 A 04 June 2015 (Family: none) JP 2004-169667 A 17 June 2004 (Family: none) JP 2013-83254 A 09 May 2013 US 2013 / 0086883 Al paragraphs [0036]-[ 1-6 )05 1], fig- EP 2578839 Al DE 102012019354 Al JP 2020-139480 A 03 September 2020 US 2022 / 0136416 Al paragraphs [0029)-( 1-4 0059], fig. WO 2020 / 175012 Al EP 3916207 Al CA 3131362 Al JP 2013-22520 A 04 February 2013 (Family: none) JP 2021-21332 A 18 February 2021 US 2022 / 0228515 Al WO 2021 / 015260 Al EP 4006324 Al CA 3147402 Al WO 2014 / 132932 Al 04 September 2014 US 2015 / 0354466 Al CN 104968918 A KR 10-2015-0099865 A JP 2006-132931 A 25 May 2006 US 2002 / 0043063 Al US 2001 / 0000049 Al EP 887530 A2 CN 1207453 A KR 1999-007373 A JP 11-72027 A JP 2005-300019 A 27 October 2005 (Family: none) wo 2023 / 095362 Al 01 June 2023 (Family: none)

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