KR101595619B1 - Turbine control device, turbine control method, and recording medium storing turbine control program - Google Patents

Abstract

SUMMARY OF THE INVENTION The present invention provides a turbine control device capable of stably controlling the system frequency even in a load operation.
A turbine control device (7) according to the present invention includes a system information acquiring section (15) for acquiring system information relating to an operation state of a power system to which a power generation plant is connected, And a speed control unit (11) for adjusting the speed based on information.

Description

TECHNICAL FIELD [0001] The present invention relates to a turbine control apparatus, a turbine control method, and a turbine control program,

The present invention relates to a turbine control apparatus, turbine control method, and turbine control program for a power generation turbine.

BACKGROUND ART [0002] Japanese Patent Application Laid-Open No. 5-340204 (Patent Document 1), for example, is known as a background art in the technical field. The patent document 1 discloses a turbine control apparatus that enables stable control in the case where the control of the turbine rotational speed in the no-load region of the turbine, particularly, the low rotational region becomes unstable.

Specifically, the turbine control apparatus of Patent Document 1 has a revolution number detection device for detecting the actual revolution number of the turbine and a nonlinear function code for outputting a nonlinear function corresponding to the revolution number. The turbine control apparatus of Patent Document 1 includes an adder for calculating a deviation between a rotation number setting signal and a rotation number signal from the rotation number setting device and a nonlinear adjustment rate calculator for calculating a rotation number deviation signal and a nonlinear function output do.

Japanese Patent Application Laid-Open No. 5-340204

Patent Document 1 discloses a technique that enables stable control in a no-load region of a turbine, particularly in a low-rotation region. However, stable control of the turbine in the vicinity of the rated rotational speed of the turbine . However, in the technical field, it is required to develop a technique that enables stable control of the system frequency even during load operation. Accordingly, the present invention provides a turbine control device, a turbine control method, and a turbine control program that can stably control the system frequency flexibly even during a load operation.

Means for Solving the Problems In order to solve the above problems, the turbine control apparatus of the present invention includes a speed control section that adjusts an adjustment parameter of the turbine rotation speed on the basis of the system information related to the operation state of the power system.

According to the present invention, since the rotational speed of the turbine can be controlled based on the system information related to the operation state of the power system (hereinafter, simply referred to as the system) connected to the power generation plant, stable control of the system frequency It becomes possible.

BRIEF DESCRIPTION OF THE DRAWINGS Fig. 1 is a diagram showing a control algorithm of a rapid load control of a steam turbine implemented in a general turbine control device (comparative example); Fig.
2 is a schematic block diagram of a power generation system according to a first embodiment of the present invention;
3 is a schematic configuration diagram of a system information supply source in the first embodiment;
4 is a schematic configuration view of a turbine control apparatus according to the first embodiment;
5 is a view showing a control algorithm of the steady-state load control of the steam turbine in the first embodiment;
6 is a flowchart showing the processing procedure of the smooth load control of the steam turbine in the first embodiment;
7 is a diagram showing a variable algorithm of the adjustment rate in the first embodiment;
8 is a diagram showing an example of a relationship between a variation characteristic of a systematic frequency and a variation characteristic of a variation component value (a first contribution value R1 described later) of a correction rate corresponding thereto;
9 is a diagram showing an example of a relationship between a variation characteristic of the system information and a variation characteristic of a variation component value of the adjustment ratio corresponding thereto (second contribution value R2 described later);
10 is a diagram (schematic diagram) showing an example of a result of the rapid load control in the turbine control apparatus of the first embodiment.
11 is a view showing a control algorithm of the smooth load control of the steam turbine in the turbine control apparatus of the second embodiment;
12 is a diagram showing a variable algorithm of the adjustment ratio in the second embodiment;

Hereinafter, a turbine control apparatus and a turbine control method according to various embodiments of the present invention will be described with reference to the drawings.

First Embodiment

First, before describing the turbine control apparatus according to the first embodiment of the present invention, it is assumed that the governor control method (comparative example) of the steam turbine generally performed in the power generation plant at present and various tasks assumed in the method Will be described.

The thermal power plant supplies the steam generated from the boiler to the steam turbine, which drives the generator directly connected to the steam turbine and the steam turbine. In addition, the thermal power generation plant adjusts the steam flow rate supplied to the steam turbine, which is a power generation facility, and controls the rotation speed (system frequency) of the steam turbine according to the value of the power generation command from the central power supply station.

At this time, the turbine rotation speed (system frequency: 50 Hz or 60 Hz) is controlled by adjusting the amount of steam flowing into the steam turbine based on the system contribution ratio called the adjustment rate (speed adjustment rate: adjustment parameter). The steady control of the steam flow rate (rotation speed of the steam turbine) based on this adjustment rate suppresses the fluctuation of the system frequency caused by the variation of the total load amount and the total supply amount of power of the system. Control of the rotational speed (system frequency) of such a steam turbine is referred to as rapid load control or governor pre-control.

The adjustment rate is a parameter indicating how much load (amount of power) is to be adjusted for fluctuation of the system frequency. Further, since the system frequency is synchronized with the revolution number of the generator, it is equivalent to the revolution number of the steam turbine directly connected to the generator.

Fig. 1 is a diagram showing a control algorithm of the steady-state load control of a steam turbine currently practiced in a power generation plant. In this control algorithm, first, for example, a speed deviation? V between an actual value (actual rotational speed) of the rotational speed (systematic frequency) detected by the speed sensor mounted on the shaft of the steam turbine and the rated rotational speed is calculated . Then, the reciprocal of the adjustment rate R (hereinafter referred to as gain G) is multiplied by the speed deviation? V. The deviation signal ΔS (= G · ΔV: hereinafter referred to as a speed adjustment signal ΔS) multiplied by the gain G is added to the governor setting signal S0 set in accordance with the amount of power (load) required by the generator.

Then, the required opening amount of the additive valve is calculated based on the signal S (hereinafter referred to as the steady load control signal S) obtained by adding the speed adjusting signal? S to the governor setting signal S0, and the required opening amount is calculated between the boiler and the steam turbine And is output to an add / drop valve installed in a pipe connecting the pipe. The opening degree of the addition / subtraction valve is adjusted based on the opening degree demand input to the addition / subtraction valve, and the steam flow rate supplied to the steam turbine is adjusted. Further, in the thermal power generation plant employing the above-mentioned steady-state load control method of the steam turbine, the adjustment rate R is usually a constant value (about 5 to 7%).

Now, for example, a case where the adjustment ratio R is 5% is considered in this speed control method. In this case, the speed adjustment signal is adjusted in the range of -100% to 100% with respect to the system frequency fluctuation in the range of ± 5%. Therefore, in this case, when the system frequency fluctuates by 1%, the speed adjustment signal? S corresponding to the steam flow rate of 20% of the rated steam flow rate is added to or subtracted from the previously set governor setting signal S0.

In addition, the steady-state load control can stabilize the system frequency and reduce the steam supply amount when the rotational speed of the steam turbine rises due to system accidents or the like. Therefore, the steady- Action. For example, when the adjustment ratio R of the power generation plant is 5%, the speed adjustment signal? S becomes -100% at the point when the rotational speed of the steam turbine reaches 105% of the rated speed, %, The addition / subtraction valve is completely closed, and the rotation speed of the steam turbine is adjusted. On the other hand, when the rotational speed of the turbine is 95% of the rated speed, the speed adjustment signal? S becomes 100%, the smooth load control signal S corresponding to the steam flow rate of the 100% load is output to the add / The rotational speed of the turbine is adjusted.

When the adjustment rate R is low in the above-mentioned steady-state load control system of the steam turbine, a large steam flow rate is adjusted by a slight variation of the system frequency. That is, in this case, the rapid-load control of the steam turbine becomes the high-speed (high-gain) rapid-load control (the fast-response control). However, in the rapid load control of the high gain, the change of the rapid load control signal S (S0 + DELTA S) becomes abrupt or occurs frequently. In this case, the fluctuation of the generator output and the sudden opening and closing operation of the add / drop valve cause the stability of the power generation plant to deteriorate. Further, when the supply amount of the steam rapidly increases and a temperature rise or a thermal stress exceeding the upper limit value occurs, the thermal stress of the steam turbine increases and accumulates. This thermal stress is a main cause of deterioration of mechanical equipment such as a rotor or a blade of a steam turbine, and there is a possibility that the service life of the equipment is shortened.

On the other hand, if the adjustment ratio R is made high in the rapid-load control system, the smooth-load control of the steam turbine becomes the smooth-speed load control at a low temperature. However, in this case, although the stability of the power generation plant is improved, it is difficult to absorb the fluctuation of the system frequency in the power generation plant, and the stability of the system may be lowered.

In the actual thermal power generation plant, the above-mentioned value of the adjustment rate R is a constant value regardless of the operation state of the other power generation system connected to the thermal power generation plant and the power supply and demand of the system. Therefore, in a system in which a power generation system (for example, a photovoltaic power generation system, a wind power generation system, or the like) in which the amount of supplied power greatly fluctuates due to weather or the like, for example, even if the system becomes unstable, And it becomes difficult to control the stability of the system.

The present invention proposes a method for controlling the rapid load of a steam turbine and a turbine control apparatus employing the method, which can solve the above-mentioned various problems.

[Configuration and Operation of Power Plant]

(1) Configuration

2 is a schematic block configuration diagram of a power generation plant having a turbine control apparatus according to the first embodiment. Fig. 2 shows only the components related to the turbine control device for convenience of explanation. In this embodiment, an example in which the power generation plant is a thermal power generation plant will be described.

The power generation plant 10 includes a boiler 1, a steam turbine 2, a generator 3, an add / drop valve 4, a pipe 5, a speed sensor 6, a turbine control device 7).

The boiler 1 is connected to the steam turbine 2 through a pipe 5 and an add / drop valve 4 is installed in the middle of the pipe 5. The turbine shaft of the steam turbine 2 is connected to the rotary shaft of the generator 3 so that the steam turbine 2 is directly connected to the generator 3. Further, a speed sensor 6 for detecting the rotational speed of the steam turbine 2 is mounted on the steam turbine 2.

The turbine control device (7) is electrically connected to the speed sensor (6) and always detects the rotational speed of the steam turbine (2). The turbine control device 7 is connected to the add / drop valve 4 via an oil pressure and controls the opening degree of the add / drop valve 4 to control the flow rate of the steam flowing from the boiler 1 to the steam turbine 2 .

Although not shown in FIG. 2, the power generation plant 10 (generator 3) is connected to various other power generation systems via power transmission lines, thereby establishing a system. The power generation plant 10 (turbine control device 7) is connected to the grid information supply source 20 via a communication network such as a network, for example, From the systematic information supply source (20).

3 is a schematic configuration diagram of the system information supply source 20 in this embodiment. In the present embodiment, the systematic information supply source 20 is a system information source system that is calculated from an external facility (for example, a central power supply station, etc.) of the power generation plant 10 as systematic information on the operation status of the system including the power generation plant 10 Time supply / demand forecast information 21 to the turbine control device 7. [ At this time, in the present embodiment, the systematic information supply source 20 transmits the real-time supply / demand forecast information 21 (systematic information) to the VPN (Virtual Private Network) 22, the router 23, To the turbine control device (7).

(2) Operation

In the power plant 10 having the above-described configuration, the boiler 1 first heats the water by burning fuel such as petroleum or coal, for example, and pressurizes the high-temperature high-pressure steam generated at that time through the pipe 5 To the steam turbine (2). Then, the steam turbine 2 is rotated by the high-temperature high-pressure steam supplied from the boiler 1 to drive the generator 3. Thereby, the power generation plant 10 generates electric power and supplies the electric power to the system.

In this embodiment, when rotating the steam turbine 2, the turbine control device 7 controls the turbine 2 such that the system frequency of the electric power generated by the generator 3 becomes a predetermined frequency (50 Hz or 60 Hz) (Rotation number) of the steam turbine 2 is controlled by controlling the opening degree of the addition / At this time, in this embodiment, the turbine control device 7 is based on the system information acquired from the system information source 20 and the actual data of the rotational speed of the steam turbine 2 acquired from the speed sensor 6 So that the steam turbine 2 is controlled at a constant speed.

[Configuration of the turbine control device]

Fig. 4 is an internal configuration (hardware configuration) of the turbine control device 7 of the present embodiment. 4, only the components related to the rapid load control of the steam turbine 2 are shown in order to simplify the explanation.

The turbine control device 7 includes a control section 11 (speed control section), a first storage section 12, a second storage section 13, a rotation speed detection section 14 (rotation speed acquisition section) A system information acquiring section 15, and an output section 16. These constituent parts are electrically connected to each other via the bus 17.

The control unit 11 is constituted by, for example, a CPU (Central Processing Unit), and functions as an arithmetic processing unit and a control unit. More specifically, the control unit 11 uses the various programs recorded in the first storage unit 12, the second storage unit 13, and the like to control the overall operation of the turbine control apparatus 7 or a part thereof . For this reason, the control of the governor load of the steam turbine 2, which will be described later, is also executed by the control section 11. [

The first storage unit 12 is constituted by, for example, a ROM (Read Only Memory), and stores a program used by the control unit 11, operation parameters, and the like. Therefore, the program (turbine control program) used in the steady-state load control processing of the steam turbine 2 to be described later, the parameters required for its execution, and the like are stored in the first storage section 12.

The second storage unit 13 is constituted by, for example, a RAM (Random Access Memory). In the second storage unit 13, for example, necessary programs and necessary parameters stored in the first storage unit 12 are temporarily stored and expanded during the steady-state load control processing of the steam turbine 2, which will be described later .

The rotational speed detecting section 14 is an input interface electrically connected to the speed sensor 6 mounted on the steam turbine 2. [ The turbine control device 7 (the control section 11) controls the speed sensor 6 via the rotation speed detection section 14, for example, during the rapid load control of the steam turbine 2, (Actual rotation speed) detected by the rotation speed detection unit.

The system information acquiring unit (15) is an input interface for acquiring system information from the system information source (20). For this reason, for example, at the time of controlling the steady-state load of the steam turbine 2 to be described later, the turbine control device 7 acquires the system information via the system information acquiring section 15. [

The output section 16 is an interface for outputting the governor load control signal Sv (an add / drop valve command signal) generated by the steady load control processing of the steam turbine 2 to be described later to the add / drop valve 4. The turbine control device 7 outputs the steady load control signal Sv to the add / drop valve 4 via the output section 16 during the steady-state load control of the steam turbine 2, which will be described later.

[Method of controlling the rapid load of the steam turbine]

Next, the method of controlling the smooth load of the steam turbine 2 (the method of controlling the steam flow rate) performed by the turbine control device 7 of the present embodiment will be described with reference to Figs. 5 and 6. Fig.

5 is a diagram showing a control algorithm of the rapid load control of the steam turbine 2 implemented in the turbine control device 7. In Fig. More specifically, Fig. 5 is a diagram showing an algorithm for calculating a smooth load control signal Sv (an acceleration / deceleration valve command signal) generated by the control unit 11 in the steady-state control processing of the steam turbine 2. [ 6 is a flowchart showing the processing procedure of the rapid load control of the steam turbine 2 in the present embodiment.

In the present embodiment, the control unit 11 controls the steady-state load control program of the steam turbine 2 stored in the first storage unit 12 (ROM) And develops it in the storage unit 13 (RAM). Then, the control unit 11 uses the rapid load control program to perform various calculation processes described below according to the calculation algorithm shown in Fig. 5, and performs the smooth load control process of the steam turbine 2. [ That is, in the present embodiment, the control unit 11 executes the rapid load control processing of the steam turbine 2 by using software.

In the present embodiment, the rotational speed of the steam turbine 2 (the steam flow rate supplied to the steam turbine 2) is controlled on the basis of the adjustment rate similarly to the above-described comparative example (Fig. 1). At this time, the adjustment rate is sequentially adjusted based on the actual data (actual rotation speed) of the rotation speed detected by the speed sensor 6 and the system information supplied from the system information supply source 20. [ In addition, since the actual rotation speed and the system information vary with time, the adjustment ratio calculated in this embodiment (hereinafter, referred to as the variable adjustment ratio Rv) also changes with time.

The turbine control device 7 first sets the actual data of the rotational speed detected by the speed sensor 6 (the actual rotational speed) to the rotational speed detection portion (the actual rotational speed) 14) (step S1). Further, as described above, since the number of revolutions of the steam turbine 2 is equal to the system frequency, information corresponding to the actual data of the system frequency is actually acquired in step S1.

Subsequently, the turbine control device 7 acquires the system information supplied from the system information supply source 20 via the system information acquiring unit 15 (step S2). At this time, in this embodiment, real-time supply / demand prediction information 21 calculated at the external facility of the power generation plant 10 is acquired via the network as the system information (see Figs. 2 and 3). In the present embodiment, the processing of step S2 may be executed before step S1, or the processing of step S2 may be executed in parallel with the processing of step S1.

Subsequently, the control section 11 calculates the speed deviation? V by subtracting the actual rotation speed from the rated rotation speed (step S3). This calculation processing corresponds to the arithmetic processing executed in the subtraction block 31 (subtraction section) in Fig. The information of the rated rotational speed is stored in advance in the first storage section 12 in the turbine control device 7 and is stored in the first storage section 12 And is read and used in the second storage unit 13.

Subsequently, the control unit 11 calculates a fluctuation component value (hereinafter referred to as a first contribution value R1) of the adjustment ratio corresponding to the variation of the systematic frequency (actual rotation speed) based on the acquired actual rotation speed (step S4 ). The control unit 11 calculates a fluctuation component value (hereinafter referred to as a second contribution value R2) of the adjustment rate corresponding to the fluctuation (load fluctuation) of the operating state of the system based on the acquired system information (step S5 ). In the present embodiment, the processing of step S5 may be executed before step S4, or the processing of step S5 may be executed in parallel with the processing of step S4.

Subsequently, the control unit 11 calculates the variable adjustment ratio Rv using the first contribution value R1 and the second contribution value R2 (step S6). The series of calculation processing from step S4 to step S6 corresponds to the calculation processing executed in the variable adjustment ratio calculation block 32 (variable adjustment ratio calculation part) in Fig. The processing of calculating the variable adjustment ratio Rv in steps S4 to S6 will be described later in detail with reference to the drawings.

Subsequently, the control unit 11 multiplies the speed deviation? V calculated in step S3 by the reciprocal of the variable adjustment ratio Rv calculated in step S6, that is, the variable gain Gv (= 1 / Rv) Gv? V) (step S7). This calculation processing corresponds to the arithmetic processing executed in the gain multiplication block 33 (speed adjustment signal generator) in Fig.

Subsequently, the controller 11 adds the governor setting signal S0 to the speed adjustment signal? SV (= Gv? V) to calculate the smooth load control signal Sv (= S0 +? Sv) (step S8). This calculation processing corresponds to the arithmetic processing executed in the addition block 34 (addition section) in Fig. The information of the governor setting signal S0 is stored in advance in the first storage section 12 in the turbine control device 7 and is stored in the first storage section 12 at the time of the rapid load control of the steam turbine 2. [ To the second storage unit 13 and used.

Then, the control unit 11 calculates the corresponding increase / decrease valve opening degree from the smooth load control signal Sv generated in step S8 and outputs the increase / decrease valve opening degree to the add / drop valve 4 via the output unit 16 And controls the opening degree of the add / drop valve 4, that is, the rotation speed (system frequency) of the steam turbine 2 (step S9) based on the rapid load control signal Sv. In the turbine control device 7 of this embodiment, the smooth load control of the steam turbine 2 is performed in this manner.

[Calculation and adjustment of variable tuning rate]

(1) Calculation method of variable adjustment rate

Next, the process of calculating the variable adjustment ratio Rv in step S4 to step S6 in Fig. 6 will be described in more detail with reference to Fig. 7 is a diagram showing an algorithm for calculating the variable adjustment ratio Rv and an algorithm for the arithmetic processing executed in the variable adjustment ratio calculation block 32 in Fig.

The calculation process in the calculation block 32a (first contribution value calculation section) of the first contribution value R1 in Fig. 7 corresponds to the process in step S4 in Fig. The calculation processing in the calculation block 32b (second contribution value calculation section) of the second contribution value R2 in Fig. 7 corresponds to the processing in step S5 in Fig. The calculation processing in the calculation block 32c (variable adjustment ratio calculation section) of the variable adjustment ratio Rv in Fig. 7 corresponds to the processing in step S6 in Fig.

In this embodiment, as shown in Fig. 7, in the calculation processing (processing of step S6) in the calculation block 32c of the variable adjustment ratio Rv, not only the first contribution value R1 and the second contribution value R2, The variable adjustment ratio Rv is calculated using the adjustment ratio R0. More specifically, in the calculation block 32c of the variable adjustment ratio Rv, the variable adjustment ratio Rv is calculated by subtracting the first contribution value R1 and the second contribution value R2 from the base adjustment ratio R0 (Rv = R0-R1-R2). The information on the base adjustment ratio R0 is previously stored in the first storage unit 12 in the turbine control device 7 and is stored in advance in the first storage unit 12 And is read and used in the second storage unit 13.

(2) Adjustment method of variable adjustment rate

Next, a method of adjusting the variable adjustment ratio Rv in the present embodiment will be described. In the method for adjusting the variable adjustment ratio Rv of the present embodiment, the variable adjustment ratio Rv is reduced so that the high-gain governor load control (fast response control) is executed when the systematic frequency f changes abruptly and / or when it is predicted . This improves the responsiveness to the variation of the system frequency f.

On the other hand, when the system frequency f changes gently (including a case where the system frequency does not change) and / or if it is predicted, the variable adjustment ratio Rv is increased so that the load control of the load speed is performed. Thus, the stability of the power generation plant 10 is improved. Further, in the present embodiment, the variable width of each contribution value and the base adjustment ratio R0 are appropriately set so that the variable adjustment ratio Rv varies in a range of about 3 to 7%.

Hereinafter, one example of calculating the first contribution value R1 and one example of calculating the second contribution value R2 for realizing the method of adjusting the variable adjustment rate Rv of the present embodiment described above will be described in detail with reference to the drawings.

(3) Example of calculation of the first contribution value R1

A calculation example of the first contribution value R1 will be described with reference to Figs. 8A and 8B. 8A shows the time variation characteristic of the system frequency f (60 Hz). The horizontal axis of the characteristic shown in FIG. 8A is time t, and the vertical axis shows the time variation characteristic of the steam turbine 2 ) ≪ / RTI > 8B is a diagram showing the time variation characteristic of the first contribution value R1 corresponding to the time variation characteristic of the system frequency f shown in Fig. 8A, and the abscissa of the characteristic shown in Fig. 8B is time t And the vertical axis is the first contribution value R1.

In the example shown in Figs. 8A and 8B, when the rate of change of the system frequency f with respect to time increases, the absolute value of the first contribution value R1 is increased, and when the rate of change of the system frequency f with time becomes small , The absolute value of the first contribution value R1 is made small. Further, when the system frequency f rises, the first contribution value R1 is set to a positive value, and when the system frequency falls, the first contribution value R1 is set to a negative value. In the example shown in Figs. 8A and 8B, for example, the value of the first contribution value R1 is set to 0 in a period in which the system frequency f is slightly fluctuated.

In the calculation block 32a of the first contribution value R1 in Fig. 7, the first contribution value R1 is obtained based on the relationship between the system frequency f and the first contribution value R1. Further, the relationship between the system frequency f and the first contribution value R1 as shown in A and B of Fig. 8 can be determined by using a relational expression (empirical expression) between the two obtained based on past performance data, for example Or may be defined using a correspondence table between them. In this case, the relational expression or correspondence table between them is stored in the first storage unit 12. [ The relationship between the system frequency f and the first contribution value R1 and the variable width of the first contribution value R1 are not limited to the examples shown in Figs. 8A and 8B. For example, the power plant 10 The performance (specification), the configuration of the system (the type, configuration, etc. of other power generation systems), and the like.

8A and 8B show an example in which the first contribution value R1 is calculated by using the relationship between the time variation characteristic of the system frequency f and the time variation characteristic of the first contribution value R1 for convenience of explanation . As described above, since the system frequency f and the rotational speed of the steam turbine 2 correspond one-to-one, the time variation characteristic of the actual rotational speed of the steam turbine 2 detected by the speed sensor 6 and the first contribution value The relationship with the time variation characteristic of R1 is also the same as the relationship shown by A and B in Fig. Therefore, when calculating the first contribution value R1, the relationship between the time variation characteristic of the system frequency f and the time variation characteristic of the first contribution value R1 can be calculated, instead of the relationship between the time variation characteristic of the system frequency f and the time variation characteristic of the first contribution value R1, The relationship between the time variation characteristic of the actual rotation speed and the time variation characteristic of the first contribution value R1 may be used.

(4) Example of calculation of the second contribution value R2

Next, a calculation example of the second contribution value R2 will be described with reference to Figs. 9A and 9B. 9A is a diagram showing the time variation characteristic (demand forecast curve) of the demand forecast value P. The horizontal axis of the characteristic shown in FIG. 9A is the time t, and the vertical axis is the demand forecast value P. FIG. 9B is a diagram showing the time variation characteristic of the second contribution value R2 corresponding to the time variation characteristic of the demand forecast value P shown in Fig. 9A, and the horizontal axis of the characteristic shown in Fig. 9B is time t And the vertical axis is the second contribution value R2.

In the example shown in FIGS. 9A and 9B, when it is predicted that the rate of change of the demand forecast value P is large, the absolute value of the second contribution value R2 is increased. On the other hand, when it is predicted that the rate of change of the demand forecast value P becomes small, the absolute value of the second contribution value R2 is made small. In the present embodiment, the second contribution value R2 is a positive value when the demand forecast value P rises, and the second contribution value R2 is a negative value when the demand forecast value P is lowered.

In the calculation block 32b of the second contribution value R2 in Fig. 7, the second contribution value R2 is obtained based on the relationship between the demanded demand value P and the second contribution value R2. The relationship between the demanded demand value P and the second contribution value R2 as shown in A and B of FIG. 9 can be determined by using a relational equation (empirical formula) obtained based on past performance data, for example, Or may be defined using a correspondence table between them. In this case, the relational expression or correspondence table between them is stored in the first storage unit 12. [ The relationship between the demand forecast value P and the second contribution value R2 and the variable width of the second contribution value R2 are not limited to the examples shown in Figs. 9A and 9B. For example, the performance of the power plant 10 (Specifications) of the power generation system, the configuration of the system (the type, configuration, etc. of other power generation systems), and the like.

In the case where the first contribution value R1 and the second contribution value R2 are calculated as described above, when the rate of change of the systematic frequency f and / or the demand predicted value P becomes high, the first contribution value R1 and / or the second contribution value R2 . As a result, the variable adjustment ratio Rv becomes smaller and the variable gain Gv becomes larger. That is, in the present embodiment, when the system frequency f changes abruptly and / or when it is predicted, the control of the steam turbine 2 becomes the high-speed governor load control (fast response control).

On the other hand, when the rate of change of the systematic frequency f and / or the demand predicted value P is low, the first contribution value R1 and / or the second contribution value R2 becomes small. As a result, the variable adjustment ratio Rv is increased and the variable gain Gv is decreased. That is, in this embodiment, when the systematic frequency f changes gently and / or when it is predicted, the control of the steam turbine 2 becomes a steady load control at a low level.

An example (a control result example) of the variation characteristic of the grid frequency f (60 Hz) obtained when the rapid load control method is executed will be described with reference to Figs. 10A and 10B. 10A is a schematic diagram of the time variation characteristic of the system frequency f in the case where the governor load control method of the present embodiment is not employed and FIG. Fig. 3 is a schematic diagram of the time variation characteristic of the system frequency f in the case of Fig. In each drawing, the horizontal axis represents time t and the vertical axis represents system frequency f.

As shown in Figs. 10A and 10B, when the rapid load control method of the present embodiment is adopted, fluctuation of the system frequency f can be greatly suppressed in a time period in which the system frequency f is abruptly changed. In addition, in the present embodiment, the fluctuation of the system frequency f can be further reduced even in a time zone in which the system frequency f changes gently, and the stability of the power plant 10 can be improved.

[Various effects]

As described above, in the rapid load control method of the present embodiment, the smooth load control of the steam turbine 2 is performed while appropriately adjusting the adjustment rate based on the system information (demand forecast value P). Therefore, in this embodiment, it is possible to flexibly adjust the system frequency (stable control) according to the operating state of the system (load fluctuation state) even during the load operation (near the rated rotation speed). In addition, in the present embodiment, because the prediction data is used as the system information, the smooth load control can be performed in consideration of the future operating conditions of the system, so that more stable control of the system frequency can be achieved.

Further, in this embodiment, the response performance of the rapid load control can be suitably changed according to the operating state of the system. Therefore, various problems assumed in the above-mentioned comparative example can be solved. Concretely, the stability of the plant is prioritized and the response performance of the rapid load control is lowered, so that the longevity of the facilities of the power plant 10 and the stabilization of the combustion can be realized. Further, in the present embodiment, since the rapid load control is performed by using the system information (demand forecast value P), many power generation systems in which the amount of supplied power fluctuates greatly due to, for example, weather of solar power generation, wind power generation, The stability of the system frequency can be improved.

Second Embodiment

Next, the turbine control apparatus and its turbine control method according to the second embodiment will be described. In the present embodiment, a steep load control method (control algorithm) different from the steady load control method (control algorithm) of the steam turbine of the first embodiment is used. However, the configuration of the power generation plant and the configuration of the turbine control device are the same as those of the power generation plant of the first embodiment and the configuration of the turbine control device (Figs. 2 and 4). Therefore, only the method of controlling the rapid load of the steam turbine will be described here with reference to Figs. 11 and 12. Fig.

11 is a diagram showing a control algorithm of the steady-state load control of the steam turbine in the present embodiment. 12 is a diagram showing an algorithm for calculating the variable adjustment ratio Rv in the present embodiment, and is a diagram showing an algorithm of the arithmetic processing executed in the variable adjustment ratio calculation block 35 in Fig. In the control algorithm of the rapid load control of this embodiment shown in Figs. 11 and 12, the same reference numerals are assigned to the same components as the control algorithms of the smooth load control in the first embodiment (Figs. 5 and 7) .

As apparent from comparison between Fig. 11 and Fig. 5 and comparison between Fig. 12 and Fig. 7, in the present embodiment, the variable adjustment ratio Rv is adjusted (changed) based only on the system information. That is, in this embodiment, as the variation component value of the adjustment ratio, only the second contribution value R2 calculated based on the system information is used, and the first contribution value R1 corresponding to the variation of the actual rotation speed (systematic frequency) Do not.

For this reason, in the governor load control method of the present embodiment, the processing of step S4 in FIG. 6 (processing of calculating the first contribution value R1 based on the actual rotation speed) is omitted. In this embodiment, the variable adjustment ratio Rv is calculated in the same manner as in the first embodiment except that the first contribution value R1 is not calculated, and the smooth load control of the steam turbine is performed.

As described above, in the governor load control method of the present embodiment, the governor load control of the steam turbine is performed while appropriately adjusting the adjustment ratio based on the system information. Thus, various effects similar to those of the first embodiment can be obtained. In the first embodiment, the variable adjustment ratio Rv is calculated in consideration of the first contribution value R1 corresponding to the variation of the systematic frequency f. Therefore, from the viewpoint of the responsiveness to the sudden change of the systematic frequency f, The load control method is more advantageous than the speed control method of the second embodiment.

[Various Modifications]

The configuration of the present invention is not limited to the configuration described in the above-described various embodiments, and includes various modifications, for example, as follows.

(1) First Modification

In the above embodiments, the adjustment rate is used as the adjustment parameter of the rotational speed of the steam turbine 2 in the rapid load control process of the turbine control device 7, but the present invention is not limited to this . For example, gain may be used as an adjustment parameter of the rotational speed of the steam turbine 2. [

In this case, the variable gain Gv is directly adjusted based only on the actual value of the system frequency f (the actual rotational speed of the steam turbine 2) and the system information (demand forecast value) or the system information. Specifically, for example, the variable adjustment ratio calculation block 32 in Fig. 5 is changed to a gain calculation block. In this case, since the gain is the reciprocal of the adjustment rate, the relationship between the system frequency f and the first contribution value R1 as shown in Figs. 8A and 8B and the demand as shown in Figs. 9A and 9B The relationship between the predicted value P and the second contribution value R2 is appropriately changed.

(2) Second Modification

In the above-described various embodiments, an example has been described in which the system information is acquired from the outside via a network, but the present invention is not limited to this. For example, in the case where grid information such as a demand forecast curve of the system is accumulated in the database in the turbine control device 7 and / or the power generation plant 10 in advance, the turbine control device 7 and / The system information may be acquired directly from the database in the power generation plant 10. [ In this case, the configuration of the turbine control device 7 can be changed from a database in the turbine control device 7 and / or the power generation plant 10 to a configuration capable of appropriately selecting system information suitable for the current state by the operator You can.

(3) Third Modification

In the above-described various embodiments, the demand prediction data (demand forecast curve) is used as the system information, but the present invention is not limited to this. Any information can be used as the system information if it is information on the operation status of the system to which the power generation plant 10 is connected.

For example, when a power generation system using natural energy such as sunlight is connected to a system to which the power generation plant 10 belongs, weather information (including weather prediction information) can also be used as system information. In this case, the weather information may be used as systematic information (second systematic information) different from the above-described demand forecast data, or may be used instead of the demand forecast data.

In the case of the former, a plurality of kinds of system information having different kinds are used for the smooth load control of the steam turbine 2. Therefore, in this case, the fluctuation component value (third contribution value) of the adjustment rate corresponding to the second system information such as the weather information is separately formed, and the correspondence relation between the second system information and the corresponding third contribution value , The third contribution value is obtained.

(4) Fourth Modification

In the above-described various embodiments, the example in which the rapid load control processing of the turbine control device 7 is realized by software has been described, but the present invention is not limited to this. For example, all or some of the blocks other than the variable adjustment ratio calculation block 32 among the various blocks constituting the control algorithm of the rapid load control shown in Fig. 5 may be configured by hardware.

(5) Modification 5

In the above-described various embodiments, an example in which the constant speed load control processing of the present invention is always performed has been described, but the present invention is not limited to this. For example, the period during which the system frequency f is slightly fluctuated may be a configuration that does not perform the above-described rapid load control processing (a configuration that forms a dead band).

(6) Modification 6

In the above-described various embodiments, an example has been described in which the turbine control program (the rapid load control program) is previously mounted (stored) in the first storage unit 12 of the turbine control device 7, It is not limited. A turbine control program may be mounted on the turbine control device 7 separately from the outside to execute the above-mentioned rapid load control process. In this case, the turbine control program may be distributed from a medium such as an optical disk or a semiconductor memory, or may be downloaded via a communication network such as the Internet.

(7) Seventh Modification

In the above-described various embodiments, the example of applying the rapid-load control method in the above-described turbine control apparatus to the thermal power generation plant is described, but the present invention is not limited to this. The present invention is applicable to any power generation plant as long as the power plant needs to adjust the flow rate of the fluid and stably control the rotational speed of the turbine. For example, the above-described rapid load control method of the present invention can be applied to a power plant using a gas turbine as well as a steam turbine.

While the turbine control apparatus and the turbine control method according to various embodiments and various modified examples of the present invention have been described above, the technical scope of the present invention should be determined based on the description of the claims, It is not limited to the modified example.

1: Boiler
2: Steam turbine
3: generator
4: Increasing valve
5: Piping
6: Speed sensor
7: Turbine control device
10: Power generation plant
11:
12: First storage unit
13: Second storage unit
14:
15:
16: Output section
17: Bus
20: System information source
21: Supply and demand forecast information
22: VPN
23: Router
24: Plant network
31: Subtraction block
32, 35: Variable adjustment ratio calculation block
32a: calculation block of the first contribution value
32b: calculation block of the second contribution value
32c: calculation block of variable tuning rate
33: gain multiplication block
34: Addition block

Claims (5)

A system information acquiring section that acquires system information relating to an operation state of a power system to which a power generation plant is connected;
And a second fluctuation component value calculating step of calculating a first fluctuation component value of the adjustment ratio corresponding to the fluctuation of the operating state of the system based on the system information, And a variable speed control unit
And,
And the speed control section adjusts the rotational speed of the turbine using the variable adjustment ratio. The method according to claim 1,
Further comprising a rotational speed acquiring section that acquires information on a rotational speed of the turbine,
Wherein the speed control section calculates a second variation component value of the adjustment ratio corresponding to the variation of the system frequency on the basis of the rotation speed of the turbine and sets the second variation component value as the adjustment parameter, 2 < / RTI > variation component value. delete Acquiring system information related to an operation state of a power system to which a power generation plant is connected,
Calculating a first variation component value of the adjustment ratio corresponding to the variation of the operating state of the system based on the system information,
Calculating a variable adjustment ratio from a preset base adjustment rate and the first variation component value as adjustment parameters of the turbine rotation speed in the power plant,
Adjusting the rotational speed of the turbine using the variable tuning rate
≪ / RTI > A process of acquiring grid information on the operation status of the power system to which the power generation plant is connected,
Processing for calculating a first variation component value of the adjustment ratio corresponding to the variation of the operation state of the system based on the system information,
A process of calculating a variable adjustment ratio from a preset base adjustment rate and the first variation component value as adjustment parameters of the turbine rotation speed in the power generation plant,
A process of adjusting the rotational speed of the turbine using the variable tuning rate
To a turbine control device and executes the turbine control program.

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