Control device, control method, and program

Abstract

The present invention provides a control device, control method, and program that can appropriately correct the control of a gas turbine. [Solution] The control device is a control device for a gas turbine comprising a compressor, a combustor that burns fuel with air compressed by the compressor, and a turbine driven by combustion gas generated in the combustor, and comprises a control unit that controls the gas turbine, and an automatic correction unit that corrects the control of the gas turbine by the control unit based on the result of estimating the possibility of combustion oscillation occurring based on operating data of the gas turbine which includes at least data representing the flow rate of water flowing into the compressor.

Description

Technical Field

[0001] The present disclosure relates to a control device, a control method, and a program.

Background Art

[0002] Patent Document 1 discloses the following gas turbine control method. That is, the gas turbine control method disclosed in Patent Document 1 includes a gas turbine having a combustor and a first database storing optimal operating conditions in the combustor, and at least one of the fuel flow rate or the air flow rate supplied to the combustor is varied in a state where combustion vibration does not occur in the gas turbine to search for optimal operating conditions, update the stored content of the first database according to the obtained operating conditions, and adjust at least one of the fuel flow rate or the air flow rate supplied to the combustor according to the optimal operating conditions. In this gas turbine control method, a second database storing the load sensitivity, which is the correlation between the operation amounts of the fuel flow rate, air flow rate, ratio of pilot fuel, and ratio of top hat fuel in the gas turbine and the load amount of the gas turbine, is provided. Using the load sensitivity stored in the second database, the load fluctuation amount with respect to the operation amount of at least one of the fuel flow rate or the air flow rate supplied to the combustor is predicted according to the optimal operating conditions obtained by the search, adjustment is performed according to the prediction result, and the stored content of the first database is updated according to the adjustment result.

[0003] Furthermore, Patent Document 2 discloses a gas turbine that aims to provide a safe operating system using the same, which can achieve both improved output and improved thermal efficiency by spraying liquid droplets into the intake air introduced into the compressor inlet with simple equipment suitable for practical use. The gas turbine disclosed in Patent Document 2 is a gas turbine comprising a compressor that compresses and discharges supplied air, a combustor in which the air discharged from the compressor and fuel are burned, and a turbine driven by the combustion gas of the combustor, and includes a spraying device installed upstream of the compressor that sprays water droplets into the air supplied to the compressor to lower the temperature of the air entering the compressor below the ambient temperature, and vaporizes the sprayed water droplets introduced into the compressor along with this lowered temperature air as they flow down inside the compressor, a detection device that detects the humidity of the air supplied to the compressor, and a control device that controls the amount of sprayed from the spraying device based on the detection signal. Furthermore, Patent Document 2 states that when the amount of steam and water injected into the combustor are constant, increasing the amount of water spray upstream of the compressor reduces the NOx concentration in the gas turbine exhaust gas, but increases the combustion oscillation of the combustor. [Prior art documents] [Patent Documents]

[0004] [Patent Document 1] Japanese Patent Publication No. 2010-084523 [Patent Document 2] Japanese Patent Application Publication No. 11-072029 [Overview of the Initiative] [Problems that the invention aims to solve]

[0005] As described in Patent Document 2, it is expected that the output of a gas turbine can be improved by introducing water into the gas turbine compressor and evaporating it within the compressor. However, introducing water into the compressor affects the combustion state of the combustor and changes the combustion margin.

[0006] For changes in combustion margin during general operation, for example, a database storing past optimal operating conditions, as described in Patent Document 1, can be used to adjust at least one of the fuel flow rate or air flow rate supplied to the combustor according to the optimal operating conditions, thereby correcting combustion oscillations that occur during gas turbine operation. However, Patent Document 1 does not mention operation in which water is introduced into the gas turbine compressor to improve output, and there was a problem that the correction may not be performed appropriately.

[0007] This disclosure was made to solve the above-mentioned problems and aims to provide a control device, control method, and program that can appropriately correct the control of a gas turbine. [Means for solving the problem]

[0008] To solve the above problems, the control device according to the present disclosure is a control device for a gas turbine comprising a compressor, a combustor that burns fuel with air compressed by the compressor, and a turbine driven by combustion gas generated in the combustor, comprising a control unit that controls the gas turbine, and an automatic correction unit that corrects the control of the gas turbine by the control unit based on the result of estimating the possibility of combustion oscillation occurring based on operating data of the gas turbine which includes at least data representing the flow rate of water flowing into the compressor.

[0009] The control method relating to this disclosure is a control method for a gas turbine comprising a compressor, a combustor that burns fuel with air compressed by the compressor, and a turbine driven by combustion gas generated in the combustor, and includes the steps of controlling the gas turbine and correcting the control of the gas turbine by the control unit based on the result of estimating the possibility of combustion oscillation occurring based on operating data of the gas turbine, which includes at least data representing the flow rate of water flowing into the compressor.

[0010] The program relating to this disclosure controls a gas turbine comprising a compressor, a combustor that burns fuel using air compressed by the compressor, and a turbine driven by combustion gas generated in the combustor, and causes a computer to perform the following steps: controlling the gas turbine; and correcting the control of the gas turbine by the control unit based on the result of estimating the possibility of combustion oscillations occurring based on operating data of the gas turbine, which includes at least data representing the flow rate of water flowing into the compressor. [Effects of the Invention]

[0011] According to the control device, control method, and program of this disclosure, the control of a gas turbine can be appropriately corrected. [Brief explanation of the drawing]

[0012] [Figure 1] This is a schematic diagram of a gas turbine according to an embodiment of the present disclosure. [Figure 2] This diagram shows the schematic configuration of a gas turbine control device for controlling the gas turbine shown in Figure 1. [Figure 3] Figure 2 is a schematic diagram showing an example of the configuration of the stability region map created by the automatic correction unit. [Figure 4] This is another schematic diagram showing an example of the configuration of the stability region map created by the automatic correction unit in Figure 2. [Figure 5] This is a schematic diagram illustrating the stability region map created by the automatic correction unit shown in Figure 2. [Figure 6] This is a schematic diagram illustrating a comparative example to explain the stability region map created by the automatic correction unit in Figure 2. [Figure 7] Figure 2 is a schematic diagram showing how the automatic correction unit automatically corrects the operating point of the gas turbine. [Figure 8] This is another schematic diagram showing how the automatic correction unit in Figure 2 automatically corrects the operating point of the gas turbine. [Figure 9] Figure 2 is a flowchart showing an example of the operation of the automatic correction unit. [Figure 10] It is a schematic block diagram showing the configuration of a computer according to at least one embodiment.

Embodiments for Carrying Out the Invention

[0013] Hereinafter, a control device, a control method, and a program according to embodiments of the present disclosure will be described with reference to FIGS. 1 to 10. In each figure, the same or corresponding configurations are denoted by the same reference numerals, and the description thereof will be omitted as appropriate.

[0014] First, referring to FIG. 1, a configuration example of a gas turbine 1 which is a control target of a gas turbine control device according to at least one embodiment of the present disclosure will be described. FIG. 1 is a schematic configuration diagram of a gas turbine according to one embodiment of the present disclosure.

[0015] The gas turbine 1 includes a compressor 3, a plurality of combustors 2, and a turbine 6. The compressor 3 includes an intake chamber 5, compresses the air B taken in from the intake chamber 5, and generates compressed air (hereinafter, appropriately referred to as "combustion air A"). The intake chamber 5 includes a plurality of spray nozzles 51 that spray water droplets into the air B supplied to the compressor 3. The combustor 2 mixes the combustion air A generated by the compressor 3 and the fuel F, and generates combustion gas. The turbine 6 is driven by the combustion gas and drives, for example, a generator (not shown). Further, the compressor 3 and the turbine 6 rotate, for example, with the same axis of rotation. In the gas turbine 1 having such a configuration, the combustor 2 is supplied with the combustion air A from the compressor 3 and the fuel F supplied from the fuel supply system 4, and these are mixed and burned to generate combustion gas. Also, water W sprayed into the air B is supplied from the water supply system 14. The combustion gas generated in the combustor 2 flows into the turbine 6 and functions as a working medium for driving the turbine 6. Further, the gas turbine 1 is provided with a plurality of sensors such as a temperature sensor 32 for detecting the air inlet temperature of the compressor 3, a pressure sensor 33 for detecting pressure fluctuations in the fuel device 2, and an acceleration sensor 34 for detecting the vibration of the combustor 2.

[0016] The fuel supply system 4 includes a fuel supply source 7 that stores the fuel F supplied to the combustor 2, and the fuel F is supplied via a fuel supply line 8 connected to the fuel supply source 7. The fuel supply line 8 is equipped with a flow meter 10 for detecting the flow rate of the fuel F. The fuel supply line 8 is equipped with a shut-off valve 24 for shutting off the fuel F. Downstream of the shut-off valve 24, it branches into multiple lines for supplying fuel F to multiple fuel injection nozzles provided in the combustor 2. Specifically, the multiple fuel injection nozzles provided in the combustor 2 include a main fuel injection nozzle, a pilot fuel injection nozzle, and a top-hat fuel injection nozzle. Downstream of the shut-off valve 24, it branches into a main fuel supply line 28a for supplying fuel F to the main fuel injection nozzle, a pilot fuel supply line 28b for supplying fuel F to the pilot fuel injection nozzle, and a top-hat fuel supply line 28c for supplying fuel F to the top-hat fuel injection nozzle. The main fuel supply line 28a, pilot fuel supply line 28b, and top-hat fuel supply line 28c are each provided with flow control valves 26a, 26b, and 26c, respectively, allowing for independent control of the fuel F supply flow rate to each fuel injection nozzle.

[0017] Water W is stored in the water supply source 17, and water W is supplied through the water supply line 16 connected to the water supply source 17. The water supply line 16 is provided with a flow control valve 18 for adjusting the flow rate of water W, a shut-off valve 13 for shutting off water W, and a flow meter 15 for detecting the flow rate of water W. The flow rate of water W sprayed into the air B from the plurality of spray nozzles 51 in the intake chamber 5 can be controlled and can also be turned off (to zero). The water W sprayed from the spray nozzles 51 evaporates in the compressor 3, and the compressor 3 is in a state of wet compression (oversaturated fog), improving the output of the gas turbine 1. In wet compression, the flow rate of water W is adjusted by control to obtain a desired output improvement amount. Hereinafter, the flow rate of water W is also referred to as the wet compression flow rate WCF or simply "WCF". The unit of WCF is represented by the mass of water per unit time and can be, for example, t / hour (tons per hour), kg / s (kilograms per second), etc.

[0018] Subsequently, a gas turbine control device 300 for controlling the gas turbine 1 having the above configuration will be described. FIG. 2 is an overall configuration diagram of the gas turbine control device 300 for controlling the gas turbine 1 of FIG. 1. The gas turbine control device 300 is an example of a configuration of the "control device" according to the present disclosure.

[0019] As shown in FIG. 2, the gas turbine control device 300 includes a control unit 10 and an automatic correction unit 200. The gas turbine control device 300 is a control device for the gas turbine 1 including a compressor 3, a combustor 2 that burns fuel with the air compressed by the compressor 3, and a turbine 6 driven by the combustion gas generated in the combustor 2. In the present embodiment, the control unit 10 controls the gas turbine 1 based on an instruction from an external integrated control device (not shown) or the like. The automatic correction unit 200 corrects the control of the gas turbine 1 by the control unit 10 based on the estimation result of the possibility of occurrence of combustion vibration estimated based on the past operation data of the gas turbine 1 including at least data representing the flow rate of water flowing into the compressor 3.

[0020] The control unit 100 is a main control device that is located near the gas turbine 1, which is the object to be controlled (for example, at the site where the gas turbine 1 is installed), and is capable of sending and receiving various signals (for example, plant state variables and control signals) to and from the gas turbine 1. The automatic correction unit 200 is an external computing device that is capable of sending and receiving various signals to and from the control unit 100. By implementing some functions of the gas turbine control device 300 with the automatic correction unit 200 in this way, the memory capacity and computing capacity of the control unit 100, which is located near the gas turbine 1, can be reduced. The automatic correction unit 200 may be operated from a terminal in a remote location via a network.

[0021] The control unit 100 and the automatic correction unit 200 are, for example, computers equipped with a CPU, RAM, ROM, etc. The control unit 100 and the automatic correction unit 200 realize various functions by having the processor (CPU) execute programs stored in memory (RAM or ROM).

[0022] The control unit 100 acquires measurement data measured by a sensor group SEN, which includes multiple sensors such as the flow meter 10, flow meter 15, temperature sensor 32, pressure sensor 33, and acceleration sensor 34 shown in Figure 1, and controls the actuator group ACT, which includes multiple actuators such as the shut-off valve 13, shut-off valve 24, flow control valve 18, and flow control valves 26a to 26c shown in Figure 1, thereby controlling the gas turbine 1.

[0023] The automatic correction unit 200 is a functional block composed of a combination of hardware and software, and includes a data acquisition unit 201, a stable region prediction unit 202, a combustion vibration level detection unit 203, a correction amount calculation unit 204, an automatic adjustment unit 205, and an adjustment effect evaluation unit 206. The data acquisition unit 201 acquires operating data of the gas turbine 1 from the control unit 100. In this embodiment, the operating data is data acquired or generated by the control unit 100, and includes, for example, plant state variables, combustion vibration values, data representing control functions, data representing correction functions, etc. The operating data acquired from the control unit 100 by the data acquisition unit 201 also includes at least the wet compression flow rate WCF. This wet compression flow rate WCF is the flow rate measured by a flow meter 15 installed in the water supply line 16. In addition to the wet compression flow rate WCF mentioned above, the operating data acquired by the data acquisition unit 201 may also include data necessary for controlling the operation of the gas turbine 1. Some examples of other data included in the operating data include the combustion load command value CLCSO related to the fuel supply system 4, the lower heating value LHV which is measured by a calorimeter in the fuel supply system 4 and is related to the combustion state, and the gas turbine inlet air temperature T1C (GT inlet Temperature) which can be detected by the temperature sensor 32 installed at the gas turbine inlet. Note that T1C may be the temperature of the atmosphere, etc., and is not limited to what is measured by the gas turbine inlet temperature sensor 32. In addition, the operating data may also include, for example, the gas turbine output (e.g., generator output), the IGV opening command value (Inlet Guide Vane opening command value), intake air temperature, the turbine bypass ratio (turbine bypass flow rate / intake air flow rate), which is the ratio of intake air flow rate to turbine bypass flow rate, the pressure ratio (=compressor discharge pressure / atmospheric pressure), the fuel flow rate ratio to each nozzle (PL ratio, TH ratio, etc.) described later, and the pressure fluctuations and acceleration of the combustor 2.Furthermore, the wet compression flow rate WCF includes, for example, data indicating whether wet compression is turned on or off (for example, "0" if off, a value other than "0" if on, or data indicating on or off), and data indicating the flow rate when wet compression is turned on. The data acquisition unit 201 may acquire operating data from, for example, an external integrated control device (not shown). Wet compression (supersaturated fog) is performed by the control unit 100 in response to instructions from an external integrated control device (not shown) when it is necessary to further increase the output during rated operation. The data acquisition unit 201 stores the operating data acquired from the control unit 100 in the database DB1 for a certain period of time, for example, for each predetermined condition.

[0024] Here, a detailed example of the control of the gas turbine 1 by the control unit 100 will be described. The control unit 100 calculates control parameters (or operating parameters) for controlling the gas turbine 1 in response to input information such as instructions from an external integrated control device (not shown), detection results from the sensor group SEN, the control status of the actuator group ACT, and predetermined setting information. The control unit 100 calculates the corresponding control parameters by inputting the input information into a function, table, etc., that shows the relationship between the input information and the control parameters, for example.

[0025] For example, the control unit 100 calculates the combustion load command value CLCSO based on the input information. The combustion load command value CLCSO is a dimensionless value of the gas turbine inlet combustion gas temperature (the temperature of the fuel gas at the turbine 6 body inlet that flows from the combustor 2 to the turbine 6), that is, a value proportional to the gas turbine inlet combustion gas temperature (for example, Japanese Patent Publication No. 4119909). Next, the control unit 100 determines the pilot ratio (hereinafter also referred to as the "PL ratio"), which is the ratio of the pilot fuel gas flow rate (weight flow rate) to the total fuel gas flow rate (weight flow rate), the top hat ratio (hereinafter also referred to as the "TH ratio"), which is the ratio of the top hat fuel gas flow rate (weight flow rate) to the total fuel gas flow rate (weight flow rate), and the main ratio, which is the ratio of the main fuel gas flow rate (weight flow rate) to the total fuel gas flow rate (weight flow rate). Subsequently, the control unit 100 determines the respective weight flow rates, i.e., the pilot fuel gas flow rate, the top hat fuel gas flow rate, and the main fuel gas flow rate, based on these pilot ratio, top hat ratio, and main ratio. Furthermore, the control unit 100 determines the Cv value of the pilot fuel flow control valve 28b, the top-hat fuel flow control valve 28c, and the main fuel flow control valve 28a based on the pilot fuel gas flow rate, top-hat fuel gas flow rate, and main fuel gas flow rate. Then, based on the respective Cv values ​​of these flow control valves 28a to 28c, it determines the respective opening command values ​​for each flow control valve 28a to 28c. Similarly, for bypass valves, the combustor bypass valve opening command value is determined based on the combustion load command value CLCSO. For example, the opening command values ​​for each of these valves are control parameters. Alternatively, the control parameters may be considered to include the fuel flow rate ratio to each nozzle (PL ratio, TH ratio, etc.).

[0026] In this embodiment, the control unit 100 calculates control parameters for controlling the flow control valve 18 based on the wet compression flow rate WCF and the like included in the input information or information generated based on the input information (hereinafter collectively referred to as input information).

[0027] Furthermore, the control unit 100 controls the gas turbine 1 based on the calculated control parameters. For example, the control unit 100 outputs a corresponding control command by inputting the deviation between the calculated control parameters and the target values ​​corresponding to those control parameters to the PI controller. The control command output from the control unit 100 is transmitted to the gas turbine 1, thereby executing the control of the gas turbine 1. In this embodiment, the control unit 100 controls the gas turbine 1 based on control parameters for controlling the gas turbine 1 calculated based on the input information. As described above, the input information includes at least the wet compression flow rate WCF (or data corresponding to it). That is, in this embodiment, the control unit 100 controls the gas turbine 1 based on input information that includes at least data representing the flow rate of water flowing into the compressor 3. Here, the data representing the flow rate of water flowing into the compressor 3 may be data that directly represents the wet compression flow rate WCF (data representing the flow rate), or it may be data that indirectly represents it (for example, data represented using control parameters such as valve opening).

[0028] Next, the functional blocks of the automatic correction unit 200 other than the data collection unit 201 described above will be explained. The stable region prediction unit 202 performs multiple regression analysis, etc., using past operating data stored in the database DB1 to calculate the stable region of the operating point and create one or more stable region maps MAP that represent the stable region. In this embodiment, the operating point is an operating state (or control state) determined by a combination of multiple operating data (or control parameters). The stable region is an area of ​​operating points where the operating state is predicted (estimated) to be stable (for example, an area consisting of operating points where combustion vibration is predicted not to occur).

[0029] Figure 3 shows an example of the stability region map MAP1. In this embodiment, the stability region prediction unit 202 creates a stability region map in consideration of the wet compression flow rate WCF. In this embodiment, the wet compression flow rate WCF is accumulated in the database DB1 as operation data, and the wet compression flow rate WCF is used as an axis (element) when creating the stability region map. Figure 3 shows an example of creating a stability region map MAP1 including a predicted stability region C1 obtained based on other operation data (other than the wet compression flow rate WCF) belonging to each predetermined interval of the values of the wet compression flow rate WCF. The predicted stability region C1 is a region where combustion vibration is predicted not to occur. In the example shown in Figure 3, the stability region map MAP1 defines the predicted stability region C1 regarding the operation points based on the PL ratio and the TH ratio which are control parameters. The stability region map MAP1 divides the wet compression flow rate WCF into five intervals of WCF = 0, 0 < WCF ≦ Wa, Wa < WCF ≦ Wb, Wb < WCF ≦ Wc, and Wc < WCF (where 0 < Wa < Wb < Wc) (where WCF = 0 is a point), and includes five stability region maps MAP1a, MAP1b, MAP1c, MAP1d, and MAP1e for each interval. Here, the stability region map MAP1a includes the predicted stability region C1 estimated based on the operation data when WCF = 0 (off). On the other hand, each predicted stability region C1 of the stability region maps MAP1b to MAP1e is estimated based on the operation data obtained at a WCF having a certain width. Therefore, the predicted stability region C1 of the stability region map MAP1a is easier to have a higher prediction accuracy than each predicted stability region C1 of the other stability region maps MAP1b to MAP1e. Figure 4 shows the stability region map MAP1a when WCF = 0. According to the stability region map MAP1a, when the operation point is determined by the combination of the PL ratio and the TH ratio located within the predicted stability region C1a where combustion vibration shown by the dashed line does not occur when WCF is 0, it is estimated that combustion vibration does not occur. Note that the stability region map MAP1 shown in Figure 3 is configured as a plurality of two-dimensional maps with different wet compression flow rates WCF, but it may be configured as a three-dimensional or higher-dimensional map without being limited to the number of control parameters.The stability region map created by the stability region prediction unit 202 is a multidimensional map that defines the relationship between multiple operating data sets, which do not include data representing the wet compression flow rate WCF, for example, where the range of applicable wet compression flow rate WCF is defined, and the predicted stable region C1, which is a region where combustion oscillations are less likely to occur. Examples of axes for the stability region map MAP include the PL ratio and TH ratio, as well as load command value CLCSO, gas turbine inlet air temperature T1C, etc.

[0030] Figure 5 is a schematic diagram illustrating the effects of the stability region map created by the stability region prediction unit 202 in Figure 2. In Figure 5, the stability region map is created as the range of possible operating points for the gas turbine 1, defined by the pilot fuel ratio (PL ratio) and top-hat fuel ratio (TH ratio) included in the operating data or control parameters. The predicted stable region C1 is shown when the wet compression flow rate WCF is "0" (off) (dashed line), "α" (single-dotted line), and twice "α" (double-dotted line). The automatic correction unit 200 automatically corrects the control parameters so that the operating point of the gas turbine 1 is included in the predicted stable region C1 based on the stability region map, thereby enabling the gas turbine control device 300 to suitably avoid combustion oscillations even when the wet compression flow rate WCF changes. Figure 6 shows, for comparison, what happens when the predicted stable region C1 is set regardless of the wet compression flow rate WCF. If the predicted stable region C1 is set regardless of the wet compression flow rate WCF, the predicted stable region C1 will be limited to the shaded region AR1 shown in Figure 6. Region AR1 is the region where the predicted stable region C1 overlaps when the wet compression flow rate WCF is "0", "α", and twice "α". As shown in Figure 6, it can be seen that the predicted stable region C1 becomes narrower when the wet compression flow rate WCF is not considered. Therefore, in this embodiment, as described above, the stability region prediction unit 202 creates a stability region map considering the wet compression flow rate WCF, so that the predicted stable region C1 included in the stability region map does not become narrower.

[0031] Furthermore, the combustion vibration level detection unit 203 detects an increase in the combustion vibration level by, for example, comparing the combustion vibration value obtained from the control unit 100 with one or more predetermined reference values. The combustion vibration value is a value indicating the magnitude of the combustion vibration, and is a value calculated by the control unit 100 based on, for example, the results of frequency analysis of the measured values ​​of the pressure sensor 33 and the acceleration sensor 34.

[0032] Furthermore, when the combustion vibration level detection unit 203 detects an increase in the combustion vibration level, the correction amount calculation unit 204 calculates a correction amount to correct the control of the control unit 100. Figure 7 shows an example of a correction amount calculated by the correction amount calculation unit 204. In Figure 7, in the stable region map MAP created by the stable region prediction unit 202 with the PL ratio and TH ratio as the two axes, the correction amount calculation unit 204 calculates a correction amount for the operating point DP1-1 where an increase in the combustion vibration level has been detected, so that the operating point DP-1 moves closer to the center of the predicted stable region C1-1 (for example, so that the operating point DP1-1, which is close to the boundary of the region, moves to an operating point DP1-2 in a region further from the boundary).

[0033] Furthermore, the automatic adjustment unit 205 corrects the control of the control unit 100 by generating a correction function based on the correction amount calculated by the correction amount calculation unit 204, for example, to correct the function (referred to as the generating function) that shows the relationship between the input information and control parameters used by the control unit 100, and transmitting it to the control unit 100. The control unit 100 corrects the control of the gas turbine 1 by correcting the generating function using the correction function received from the automatic adjustment unit 205 (for example, the target values ​​of the PL ratio and TH ratio are changed).

[0034] Furthermore, if the automatic adjustment unit 205 corrects the control of the control unit 100, the adjustment effect evaluation unit 206 evaluates, for example, the magnitude of the combustion vibration value after a predetermined time, and determines whether or not to recreate the predicted stable region C1 using the stable region prediction unit 202 based on the evaluation result. If the adjustment effect evaluation unit 206 determines to recreate it, the stable region prediction unit 202 recreates the predicted stable region C1. Figure 8 shows an example in which the stable region prediction unit 202 creates a new predicted stable region C1 again according to the judgment result of the adjustment effect evaluation unit 206. In the example shown in Figure 8, the predicted stable region C1-1 has been changed to a new predicted stable region C1-2.

[0035] Next, with reference to Figure 9, the processing flow in the automatic correction unit 200 will be explained. In the processing shown in Figure 9, first, the data acquisition unit 201 collects operating data (combustion vibration values, various state quantities, etc.) from the control unit 100 (step S1). Next, the stable region prediction unit 202 predicts the stable region (generates a stable region map) (step S2). Next, the combustion vibration level detection unit 203 determines whether or not an increase in the combustion vibration level has been detected (step S3). If an increase in the combustion vibration level is detected (step S3: YES), the correction amount calculation unit 204 calculates the correction amount (generates a correction function) (step S4). Next, the automatic adjustment unit 205 performs automatic adjustment (automatic correction) of the control unit 100's control of PL ratio, TH ratio, etc. (step S5). Next, the adjustment effect evaluation unit 206 evaluates the adjustment effect (step S6). Furthermore, after step S6, or if no increase in combustion vibration level is detected (step S3: NO), the process in step S1 is executed again, for example, after a predetermined time.

[0036] The control device, control method, and program described above are gas turbine control devices 300 (control devices) for a gas turbine 1 comprising a compressor 3, a combustor 2 that burns fuel using air compressed by the compressor 3, and a turbine 6 driven by the combustion gas generated in the combustor 2. The control device 300 includes a control unit 100 that controls the gas turbine 1, and an automatic correction unit 200 that corrects the control of the gas turbine 1 by the control unit 100 based on the results of estimating the possibility of combustion oscillations occurring based on operating data of the gas turbine 1, which includes at least data representing the flow rate of water W (wet compression flow rate WCF) flowing into the compressor 3 (stable region map MAP). With this configuration, the control of the gas turbine 1 by the control unit 100 can be corrected based on the results of estimating the possibility of combustion oscillations occurring based on operating parameters including past water W flow rates (stable region map MAP). Therefore, according to the control device, control method, and program of the embodiment, the control of the gas turbine 1 can be appropriately corrected even when water is flowed into the compressor 3.

[0037] While embodiments of this invention have been described above with reference to the drawings, the specific configuration is not limited to the embodiments described above, and design changes and the like that do not depart from the spirit of this invention are also included.

[0038] <Computer Configuration> Figure 10 is a schematic block diagram showing the configuration of a computer according to at least one embodiment. The computer 90 includes a processor 91, main memory 92, storage 93, and an interface 94. The control unit 100 and automatic correction unit 200 described above are implemented in the computer 90. The operation of each of the above-described processing units is stored in storage 93 in the form of a program. The processor 91 reads the program from storage 93, loads it into main memory 92, and executes the above-described processing according to the program. The processor 91 also allocates memory areas in main memory 92 corresponding to each of the above-described storage units according to the program.

[0039] The program may be for implementing some of the functions that the computer 90 is to perform. For example, the program may perform functions in combination with other programs already stored in storage, or in combination with other programs implemented in other devices. In other embodiments, the computer may include a custom LSI (Large Scale Integrated Circuit) such as a PLD (Programmable Logic Device) in addition to, or instead of, the above configuration. Examples of PLDs include PAL (Programmable Array Logic), GAL (Generic Array Logic), CPLD (Complex Programmable Logic Device), FPGA (Field Programmable Gate Array), etc. In this case, some or all of the functions implemented by the processor may be implemented by the integrated circuit.

[0040] Examples of storage 93 include HDDs (Hard Disk Drives), SSDs (Solid State Drives), magnetic disks, magneto-optical disks, CD-ROMs (Compact Disc Read Only Memory), DVD-ROMs (Digital Versatile Disc Read Only Memory), and semiconductor memory. Storage 93 may be an internal medium directly connected to the bus of the computer 90, or an external medium connected to the computer 90 via an interface 94 or a communication line. Furthermore, if this program is distributed to the computer 90 via a communication line, the computer 90 that receives the program may expand it into main memory 92 and execute the above processing. In at least one embodiment, storage 93 is a tangible storage medium that is not temporary.

[0041] <Note> Embodiments of this disclosure can be understood, for example, as follows:

[0042] (1) The control device (gas turbine control device 300) according to the first embodiment is a control device for a gas turbine 1 comprising a compressor 3, a combustor 2 that burns fuel with air compressed by the compressor 3, and a turbine 6 driven by combustion gas generated in the combustor 2, comprising a control unit 100 that controls the gas turbine, and an automatic correction unit 200 that corrects the control of the gas turbine by the control unit 100 based on the result of estimating the possibility of combustion oscillation occurring based on operating data of the gas turbine which includes at least data representing the flow rate of water flowing into the compressor 3. According to this embodiment and each of the following embodiments, the control of the gas turbine can be appropriately corrected.

[0043] (2) The control device (gas turbine control device 300) according to the second embodiment is the control device (gas turbine control device 300) of (1), wherein the automatic correction unit determines the amount of the correction based on a plurality of multidimensional maps MAP1a to 1e that define the relationship between the control parameters of the gas turbine and the predicted stable region C1, which is a region in which combustion vibration is less likely to occur, for each predetermined flow rate of water.

[0044] (3) The control device (gas turbine control device 300) according to the third embodiment is the control device (gas turbine control device 300) of (1) or (2), wherein the automatic correction unit determines the amount of the correction based on a multidimensional map MAP1a (where WCF=0) that defines the relationship between the control parameters of the gas turbine when the data representing the flow rate of the water is zero and the predicted stable region which is a region in which combustion vibration is unlikely to occur, when no water is flowing into the compressor.

[0045] (4) A control method relating to a fourth aspect is a control method for a gas turbine comprising a compressor, a combustor for burning fuel with air compressed by the compressor, and a turbine driven by combustion gas generated in the combustor, comprising the steps of controlling the gas turbine and correcting the control of the gas turbine by the control unit based on the result of estimating the possibility of combustion oscillation occurring based on operating data of the gas turbine, which includes at least data representing the flow rate of water flowing into the compressor.

[0046] (5) The program according to the fifth embodiment causes a computer to perform the following steps in the control of a gas turbine comprising a compressor, a combustor that burns fuel with air compressed by the compressor, and a turbine driven by combustion gas generated in the combustor: controlling the gas turbine and correcting the control of the gas turbine by the control unit based on the result of estimating the possibility of combustion oscillation occurring based on operating data of the gas turbine which includes at least data representing the flow rate of water flowing into the compressor. [Explanation of symbols]

[0047] 1 Gas Turbine 2 Combustor 3. Compressor 4 Fuel supply system 5. Intake chamber 6 Turbines 7 Fuel supply source 8 Fuel supply line 10 Flow meter 13 Shut-off valve 14 Water sources 15 Flow meter 16 Water supply lines 17 Water sources 18 Flow control valve 24 Shut-off valve 26a, 26b, 26c Flow control valves 28a Main fuel supply line 28b Pilot fuel supply line 28c Top Hat Fuel Supply Line 51 Spray nozzle 32 Temperature Sensors 33 Pressure Sensor 34. Accelerometer 100 Control Unit 200 Automatic Correction Unit 201 Data Acquisition Unit 202 Stability Region Prediction Unit 203 Combustion vibration level detection unit 204 Correction amount calculation unit 205 Automatic adjustment unit 206 Adjustment Effect Evaluation Department 300 Gas Turbine Control System DB1 Database

Claims

1. A control device for a gas turbine comprising a compressor, a combustor that burns fuel using air compressed by the compressor, and a turbine driven by the combustion gas generated in the combustor, A control unit for controlling the gas turbine, An automatic correction unit corrects the control of the gas turbine by the control unit based on the results of estimating the possibility of combustion vibration occurring based on the operating data of the gas turbine, which includes at least data representing the flow rate of water flowing into the compressor, A control device equipped with the following features.

2. The automatic correction unit determines the amount of the correction based on a plurality of multidimensional maps defined for each predetermined flow rate of water, which represent the relationship between the control parameters of the gas turbine and the predicted stable region, which is a region where combustion vibration is less likely to occur. The control device according to claim 1.

3. When no water is flowing into the compressor, the automatic correction unit determines the amount of correction based on the multidimensional map that defines the relationship between the control parameters of the gas turbine when the data representing the water flow rate is zero and the predicted stable region, which is a region in which combustion oscillations are less likely to occur. The control device according to claim 2.

4. A control method for a gas turbine comprising a compressor, a combustor that burns fuel using air compressed by the compressor, and a turbine driven by the combustion gas generated in the combustor, The steps include controlling the gas turbine, The steps include correcting the control of the gas turbine based on the results of estimating the possibility of combustion oscillations occurring based on the operating data of the gas turbine, which includes at least data representing the flow rate of water flowing into the compressor, A control method including

5. In the control of a gas turbine comprising a compressor, a combustor that burns fuel using air compressed by the compressor, and a turbine driven by the combustion gas generated in the combustor, The steps include controlling the gas turbine, The steps include correcting the control of the gas turbine based on the results of estimating the possibility of combustion oscillations occurring based on the operating data of the gas turbine, which includes at least data representing the flow rate of water flowing into the compressor, A program that causes a computer to execute something.

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