JP7012580B2 - Management equipment, management method and management system - Google Patents

Description

The present invention relates to a management device, a management method and a management system, and is suitable for application to, for example, a management device for managing an electric power system.

In the power system, the amount of power energy that can be stored is less than the power energy that is generated and consumed. Therefore, in the operation of the electric power system, it is necessary to observe the principle of "simultaneous equal amount" that keeps the difference between the demand amount and the power generation amount (supply amount) within a certain range. An electric power company operating in a vertically integrated system of power generation, transmission and distribution, and retail can control its own generator with some flexibility in order to achieve "simultaneous equal amount".

On the other hand, if the electric power company is separated into a power transmission and distribution business and a power generation / retail business due to the separation of power transmission and distribution due to the liberalization of electric power, the power transmission and distribution business will procure (purchase) adjustment power from the supply and demand adjustment market. , It is necessary to operate this.

Here, the "adjustment power" refers to the amount of power that can be adjusted for output such as the generator output for suppressing frequency fluctuation and supply-demand imbalance, and is roughly classified into frequency adjustment power and supply-demand adjustment power. Frequency adjustment power refers to governor-free and LFC (Load Frequency Control) / AFC (Automatic Frequency Control) that automatically adjusts the output according to frequency fluctuations from seconds to minutes, and supply and demand adjustment power is more than minutes order. It refers to ELD (Economic Load Dispatching Control) and DPC (Dispatching Power Control) that eliminate the long-cycle power supply-supply imbalance.

When procuring adjustment power, the cost required for procurement will ultimately be borne by the consumer as a transportation fee. Therefore, in order to curb electricity prices, it is important to properly plan the procurement of adjustment power under system constraints.

In order to keep the cost of procuring adjustment power low, it is desirable to follow the merit order in which the adjustment power is arranged in ascending order of cost. In addition, from the viewpoint of overall optimization, for example, when the country is divided into a plurality of areas, it is desirable to follow the wide area merit order across the areas instead of following the merit order within the area. However, in a power system such as Japan where the areas are loosely interconnected, the influence of the interconnection line on the transaction and activation of coordination power cannot be ignored.

Patent Document 1 describes optimization of generator start / stop / output allocation for the electric power market. Specifically, in Patent Document 1, the transaction of energy and adjustment power that minimizes the cost within the range of the tidal current constraint is performed by performing the optimization calculation with the cost as the objective function based on the market bid information and the tidal current constraint. It is supposed to formulate the state.

Further, Patent Document 2 describes a system stabilization method. Specifically, in Patent Document 2, the collapse of the separated system after the accident is suppressed by calculating the stabilization control amount for stabilizing the separated system from the tidal current state of the interconnection line before the accident. It is supposed to be.

U.S. Patent Application Publication No. 2004/0181420 Japanese Unexamined Patent Publication No. 2013-225965

By the way, Patent Document 1 merely discloses a technique of treating a system constraint as a linear tidal current constraint and performing an optimization operation under the constraint. Therefore, according to the invention disclosed in Patent Document 1, in the case where the areas are loosely interconnected, it is not possible to sufficiently procure the adjusting force across the areas, and the wide area merit order of the adjusting force can be obtained. There is a problem that it cannot be realized.

Further, in the technique described in Patent Document 2, stabilization control is performed so as to eliminate the imbalance between the power supply and demand in the separated system after the accident occurs, but the power supply and demand cannot be adjusted within the own area. Therefore, according to the invention disclosed in Patent Document 2, when the adjusting force (particularly, the frequency adjusting force) depends on the procurement from other areas, the frequency adjusting force in the separated system after the accident occurs. There is a problem that the frequency cannot be maintained stably only by the stabilization control because of the shortage.

The present invention has been made in consideration of the above points, and an object of the present invention is to propose a management device, a management method, and a management system that can achieve both cost reduction and maintenance of frequency stability of an electric power system by ordering a wide range of merits of adjustment power. It is a thing.

In order to solve such a problem, in the present invention, in the management device connected to the market management system for executing and managing the transactions in the electric power market and managing the electric power system, the planning information which is a plan for power procurement from the market management system. , And the system constraint, which is a technical constraint in the interconnection line connecting between the areas of the power system, is acquired, and the frequency fluctuation risk after the occurrence of the assumed accident for the interconnection line and the wide area merit order of the adjustment power are ordered. The frequency fluctuation risk evaluation unit that calculates the required interconnection line empty capacity, which is the free capacity of the interconnection line required to realize the above, and the calculated frequency fluctuation risk and the required interconnection line empty capacity . On the other hand, for one or more risk mitigation measure candidates registered in advance, the cost and effect of applying the risk mitigation measure candidate as a risk mitigation measure are evaluated respectively, and the risk for the frequency fluctuation risk is evaluated based on the evaluation result. A risk mitigation measure evaluation department has been established to select the risk mitigation measure candidates to be applied as mitigation measures.

Further, in the present invention, in the management method connected to the market management system that executes and manages the transactions in the electric power market and executed by the management device that manages the electric power system, the management device procures electricity from the market management system. Obtaining the plan information that is the plan for the above and the system constraint that is the technical constraint in the interconnection line connecting the areas of the power system, the frequency fluctuation risk after the occurrence of the assumed accident for the interconnection line, and The first step of calculating the required interconnection line free capacity, which is the free capacity of the interconnection line required to realize the wide-area merit order of the adjusting power, and the frequency fluctuation calculated by the management device. For one or more risk mitigation measure candidates registered in advance for the risk and the required interconnection free capacity , the cost and effect of applying the risk mitigation measure candidate as a risk mitigation measure are evaluated, respectively, and the evaluation result. Based on the above, a second step of selecting the risk mitigation measure candidate to be applied as the risk mitigation measure for the frequency fluctuation risk is provided.

Further, in the present invention, in the management system for managing the electric power system, the market management system for executing and managing the transactions in the electric power market and the management device connected to the market management system for managing the electric power system are provided. From the market management system, the management device acquires the planning information, which is a plan for power procurement, and the system constraint, which is a technical constraint in the interconnection line connecting the areas of the power system, and the interconnection line. Frequency fluctuation risk evaluation that calculates the frequency fluctuation risk after the occurrence of an assumed accident and the required interconnection free capacity, which is the free capacity of the interconnection line required to realize the wide-area merit order of adjustment power, respectively. The cost of applying the risk mitigation measure candidate as a risk mitigation measure for one or more risk mitigation measure candidates registered in advance for the calculated frequency fluctuation risk and the required interconnection free capacity . And the effect is evaluated, and based on the evaluation result, the risk mitigation measure evaluation department is set up to select the risk mitigation measure candidate to be applied as the risk mitigation measure for the frequency fluctuation risk.

According to the management device, management method and management system of the present invention, it is possible to effectively utilize the adjustment power that cannot be procured or activated due to the system restrictions of the interconnection line.

According to the present invention, it is possible to realize a management device, a management method, and a management system that can achieve both cost reduction and maintenance of frequency stability of an electric power system by ordering a wide range of merit of adjustment power.

It is a block diagram which shows the whole structure of the electric power system by 1st Embodiment. It is a block diagram which shows the logical structure of an integrated wide area reliability management apparatus, and the flow of information in an electric power system. It is a conceptual diagram used to explain the state of the power system in normal times. It is a conceptual diagram used to explain the state of the electric power system at the time of an accident. It is a conceptual diagram provided to explain the state of the electric power system after the accident is eliminated. It is a chart used to explain the power generation plan. It is a graph which provides the explanation of the interconnection line constraint. It is a chart provided for the explanation of the interconnection line constraint. It is a chart used to explain the adjustment power bidding information. It is a chart to be used for explanation of the adjustment power procurement plan. It is a conceptual diagram provided to explain the relationship between the wide area merit order, the interconnection line constraint, and the frequency. It is a graph used to explain the relationship between wide area merit order, interconnection line constraint and frequency. It is a conceptual diagram provided to explain the relationship between the wide area merit order, the interconnection line constraint, and the frequency. It is a flowchart which shows the processing procedure of the frequency fluctuation risk evaluation processing. (A) is a graph showing a specific example of the assumed demand fluctuation, and (B) is a characteristic waveform diagram showing an image of the frequency fluctuation obtained as a result of the frequency simulation for the assumed demand fluctuation of (A). (A) is a curve diagram showing an example of continuous demand fluctuation, and (B) to (D) are curve diagrams showing demand fluctuation to which the primary adjustment force to the tertiary adjustment force should respond. It is a curve diagram which shows an example of a demand fluctuation when all adjustment powers are satisfied. (A) to (C) are curve diagrams showing an example of demand fluctuation in a case where the primary adjustment force, the secondary adjustment force, or the tertiary adjustment force are insufficient, respectively. It is a waveform diagram which shows an example of the spectral waveform obtained by the spectral analysis when the primary adjustment power is insufficient. It is a figure which shows the screen composition of the 1st frequency fluctuation risk evaluation result screen. It is a figure which shows the screen composition of the 2nd frequency fluctuation risk evaluation result screen. It is a flowchart which shows the processing procedure of a risk mitigation measure evaluation process. It is a chart which shows an example of a risk mitigation measure candidate. It is a conceptual diagram provided to explain the effect of implementing risk mitigation measures. It is a conceptual diagram provided to explain the effect of implementing risk mitigation measures. It is a chart provided to explain the display form of the processing result of the risk mitigation measure evaluation process. It is a chart provided for the explanation of the auxiliary signal. It is a block diagram which shows the whole structure of the electric power system by 2nd Embodiment.

Hereinafter, one embodiment of the present invention will be described in detail with reference to the drawings.

The main user of the market-ready reliability management device of the present embodiment described below is a power transmission and distribution business operator having a power system. Transmission and distribution business operators have two aspects. The first aspect is the aspect as a system operator who owns electric power system equipment and stably transports electric power from a power plant to a consumer. The second aspect is the aspect as a final supply and demand adjuster that compensates for deviations from the actual and planned values of demand and power generation.

Regarding the first aspect, the power transmission and distribution business operator routinely monitors and stabilizes the power system by using the system stabilization system as a system operator. As part of this, the power transmission and distribution business operator, for example, when a failure occurs in a part of the power system, takes measures such as operating a circuit breaker to disconnect the location of the failure or the generator.

Regarding the second aspect, the power transmission and distribution business operator uses the market management system as the final supply / demand coordinator to determine when, from which generator, how much adjustment power, and at what cost. I plan on a daily basis. At this time, the power transmission and distribution business operator formulates such a plan while complying with technical restrictions (system restrictions) in various parts of the power system.

The power transmission and distribution business operator newly introduces the integrated wide area reliability management device of this embodiment and connects it to the equipment on the existing power system and the existing system stabilization system and the existing market management system. Harmonize the above two aspects (first aspect and second aspect) as a power transmission and distribution business operator. Among the names of the integrated wide area reliability management device, "integrated type" means to integrate the equipment, system stabilization system and market management system on the power system, and "wide area reliability management" is the second aspect. It means to support the procurement based on the wide-area merit order of the adjustment power expected in the first aspect.

(1) First Embodiment (1-1) Configuration of Electric Power System According to the Present Embodiment In FIG. 1, ES indicates the electric power system according to the above-described present embodiment as a whole. This power system ES is configured to include an integrated wide area reliability management device 1. The integrated wide area reliability management device 1 is a general-purpose computer device including a central control device 3, a main storage device 4, an auxiliary storage device 5, an input device 6, and a display device 7 connected to each other via an internal bus 2. Consists of.

The central control device 3 is a processor that controls the operation of the entire integrated wide area reliability management device 1. Further, the main storage device 4 is composed of, for example, a volatile semiconductor memory, and is used as a work memory of the central control device 3.

The auxiliary storage device 5 is composed of a large-capacity non-volatile storage device such as a hard disk device or an SSD (Solid State Drive). Various databases 8 and various programs 9 are stored in the auxiliary storage device 5. These programs 9 are loaded into the main storage device 4 and executed in the central control device 3 when the integrated wide area reliability management device 1 is started or when necessary, so that various processes of the integrated wide area reliability management device 1 as a whole are performed. Is executed.

The input device 6 is composed of, for example, a keyboard, a mouse, or the like, and is used when the user performs various operations. Further, the display device 7 is composed of, for example, a liquid crystal display or an organic EL (Electro Luminescence) display, and is used for displaying necessary information and a screen.

The integrated wide area reliability management device 1 is connected to the market management system 10. As described above, the market management system 10 formulates a power generation plan and a coordination power procurement plan (hereinafter referred to as a coordination power procurement plan) while complying with system restrictions in various parts of the power system 16, and is a wholesale power trading market to be described later. It is a computer system having a function of procuring necessary power and adjustment power from 11 and the supply / demand adjustment market 12.

The market management system 10 includes a wholesale power trading market 11 (more accurately, a device that manages transactions in the wholesale power trading market) in which power generation companies and retailers trade electricity, and a power generation company and a power transmission / distribution company. Is connected to the supply and demand adjustment market (more accurately, the device that manages the transaction in the supply and demand adjustment market) 12 that trades the adjustment power.

The integrated wide area reliability management device 1 is also connected to the system stabilization system 14 and the output variable device 15 via the communication line 13. The system stabilization system 14 is a computer having a function of executing stabilization processing for stabilizing the power system 16 by disconnecting the generator and the load from the power system when a system accident occurs in the power system 16. It is a system. Further, the variable output device 15 is composed of, for example, a generator capable of adjusting the output, and a power output device such as a converter, a power flow facility, and a storage battery. The power system 16 can be stabilized by adjusting the output of the variable output device 15.

Note that FIG. 1 is only a configuration example of the electric power system ES including the integrated wide area reliability management device 1 of the present embodiment, and is a connection between the market management system 10 and the wholesale electric power trading market 11 and an integrated type. The connection between the wide area reliability management device 1 and the system stabilization system 14 and / or the variable output device 15 is not always necessary.

Here, "adjustment power" will be described. For example, in the electric power system ES of FIG. 1, it is assumed that the retailer has concluded a contract with the power generation operator to procure a certain amount of electricity (planned value) per predetermined time.

This planned value is determined based on the medium- to long-term forecasts of electricity demand formulated by retailers, but the balance between actual electricity demand and supply fluctuates in the short term. If the demand for electricity exceeds the supply, the transmission and distribution business operator needs to procure and supplement the additional electricity as the final supply and demand coordinator. On the contrary, when the demand for electric power falls below the supply amount, the power transmission and distribution business operator needs to limit the electric power amount.

In preparation for such a case, the power transmission and distribution business operator purchases the right (option) from the power generation business operator to freely change the output of the generator or the like. Such rights are called "coordinating power." The "adjustment power" includes an "up adjustment power" that can procure an additional amount of electric power and a "lower adjustment power" that can limit the amount of electric power.

(1-2) Configuration of integrated wide area reliability management device and information flow in this power system FIG. 2 with the same reference numerals to the parts corresponding to FIG. 1 shows the logical configuration of the integrated wide area reliability management device 1 and the logical configuration of the integrated wide area reliability management device 1. The flow of information and instructions in this power system ES is shown. As shown in FIG. 2, the integrated wide area reliability management device 1 includes an input unit 20, a frequency fluctuation risk evaluation unit 21, a risk mitigation measure evaluation unit 22 and an output unit 23, an assumed accident database 24, and an assumed demand fluctuation database. 25 and a risk mitigation candidate database 26 are provided.

In the input unit 20, the frequency fluctuation risk evaluation unit 21, the risk mitigation measure evaluation unit 22, and the output unit 23, the central control device 3 (FIG. 1) of the integrated wide area reliability management device 1 is the auxiliary storage device 5 (FIG. 1). It is a functional unit embodied by executing the corresponding program 9 (FIG. 1) loaded from the main storage device 4 (FIG. 1). The specific functions of the input unit 20, the frequency fluctuation risk evaluation unit 21, the risk mitigation measure evaluation unit 22, and the output unit 23 will be described later.

Further, the assumed accident database 24, the assumed demand fluctuation database 25, and the risk mitigation measure candidate database 26 each constitute a part of the database 8 (FIG. 1) stored in the auxiliary storage device 5 of the integrated wide area reliability management device 1. It is a database. The assumed accident database 24 stores various accidents that are expected to occur in the power system 16 (FIG. 1) (hereinafter, these are referred to as assumed accidents), and the assumed demand fluctuation database 25 is assumed. Demand fluctuations (hereinafter referred to as assumed demand fluctuations) are stored. Further, in the risk mitigation measure candidate database 26, a plurality of mitigation measure candidates (hereinafter, this is referred to as risk mitigation measure candidate) for the risk of frequency fluctuation caused by an assumed accident or expected demand fluctuation (hereinafter, this is referred to as frequency fluctuation risk). Is stored).

These assumed accidents, assumed demand fluctuations, and risk mitigation measure candidates are prepared in advance by the user and stored in a corresponding database (assumed accident database 24, assumed demand fluctuation database 25, or risk mitigation measure candidate database 26).

In the electric power system ES of FIG. 1, the market management system 10 acquires the transaction result of the electric power transaction carried out by itself in the wholesale electric power trading market 11 from the wholesale electric power trading market 11 as transaction information 30, and obtains it from the supply and demand adjustment market 12. , The bid result of the adjustment power transaction carried out by oneself in the supply and demand adjustment market 12 is acquired as the adjustment power bid information 31.

Further, the market management system 10 is necessary for executing the power generation plan 32, which is a future power generation plan, and the power generation plan 32, based on the acquired transaction information 30 and the adjustment power bid information 31, within the range satisfying the system constraints. Formulate a coordination power procurement plan 33, which is a coordination power procurement plan. In the following, this grid constraint is a constraint on the interconnection line used when connecting the power grids of two electric power companies and accommodating electric power between the electric power companies (hereinafter, this is referred to as the interconnection line constraint 34). It is explained as if it is called). However, other transmission constraints can be applied instead of the interconnection line constraint 34. Then, the market management system 10 outputs the formulated power generation plan 32 and the adjustment power procurement plan 33 and the system constraint (here, the interconnection line constraint 34) used for this formulation to the integrated wide area reliability management device 1.

The input unit 20 of the integrated wide area reliability management device 1 takes in the power generation plan 32, the adjustment power procurement plan 33, and the interconnection line constraint 34 output from the market management system 10 and gives them to the frequency fluctuation risk evaluation unit 21. ..

The frequency fluctuation risk evaluation unit 21 is a list of assumed accidents stored in the power generation plan 32, the adjusting power procurement plan 33, the interconnection line constraint 34 given by the input unit 20, and the assumed accident database 24. Based on 35 and the assumed demand fluctuation 36 stored in the assumed demand fluctuation database 25, the frequency fluctuation risk 37 in the event of an assumed accident and the interconnection line necessary to realize the wide area merit order described later. (Hereinafter, this is referred to as the required interconnection line empty capacity 38) is calculated. Further, the frequency fluctuation risk evaluation unit 21 outputs the calculated frequency fluctuation risk 37 and the required interconnection free capacity 38 to the risk mitigation measure evaluation unit 22.

The risk mitigation measure evaluation unit 22 has each risk mitigation measure stored in advance in the risk mitigation measure candidate database 26 based on the frequency fluctuation risk 37 and the required interconnection line free capacity 38 given by the frequency fluctuation risk evaluation unit 21. Each candidate 39 is evaluated, and based on the evaluation result, the effect of applying the risk mitigation measure candidate 39 as a risk mitigation measure for each risk mitigation measure candidate 39 (hereinafter, this is referred to as a risk mitigation measure candidate effect 40). ) Are calculated respectively.

Further, the risk mitigation measure evaluation unit 22 has the frequency fluctuation risk 37 given by the frequency fluctuation risk evaluation unit 21, the risk mitigation measure candidate 39 for each frequency fluctuation risk 37 calculated as described above, and its effect (risk mitigation measure candidate). Based on the effect 40), the first or second frequency fluctuation risk evaluation result screens 60 and 70, which will be described later with respect to FIGS. 20 and 21, are generated, and the generated first or second frequency fluctuation risk evaluation result screen 60 is generated. By transmitting the screen data of, 70 to the display device 7, this is displayed on the display device 7.

Thus, the user can use the frequency fluctuation risk 37 based on the first or second frequency fluctuation risk evaluation result screens 60 and 70 displayed on the display device 7, and the risk for each risk mitigation measure candidate 39 for the frequency fluctuation risk 37. Confirm the mitigation measure candidate effect 40. Further, after that, the user selects the risk mitigation measure candidate 39 actually adopted as the risk mitigation measure from the risk mitigation measure candidates 39 by operating the input device 6. Then, the operation result of this user is given to the risk mitigation measure evaluation unit 22 as the selection result 41 from the input device 6.

Thus, the risk mitigation measure evaluation unit 22 determines the effect (risk mitigation measure candidate effect 40) when the risk mitigation measure according to the risk mitigation measure candidate 39 selected by the user is executed based on the selection result 41. It is transmitted to the market management system 10 via the output unit 23 as the mitigation effect 42.

Further, the risk mitigation measure evaluation unit 22 generates an auxiliary signal 43 for realizing the risk mitigation measure, and the generated auxiliary signal 43 is sequentially passed through the output unit 23 and the communication line 13 to the system stabilization system 14 and / or necessary. It is transmitted to the variable output device 15. Specifically, the set value 44, which is a combination of the accident aspect and the cutoff target, is transmitted as the auxiliary signal 43 to the system stabilization system 14, and the auxiliary signal 43 is transmitted to the variable output device 15. As a result, an operation mode switching command 45, which is a command to switch the operation mode to a specific mode, is transmitted.

In this way, the integrated wide area reliability management device 1 has the frequency fluctuation risk 37 and the risk mitigation measure candidate 39 in the trading state each time the transaction in the wholesale power trading market 11 and the supply / demand adjustment market 12 changes. The operator is notified of the effect (risk mitigation measure candidate effect 40), and the auxiliary signal 43 including the accident aspect and the set value 44 to be blocked or the operation mode switching command 45 is transmitted to the system stabilization system 14 and the output variable device 15. Output to.

Then, when the system stabilization system 14 subsequently detects the occurrence of a system accident based on the accident information 46 acquired from the power system 16, the generator or the generator is based on the set value 44 previously designated by the auxiliary signal 43. A cutoff command 47, which is a command to disconnect the load from the power system 16, is output to the power system 16. As a result, based on this cutoff command 47, the breaker installed on the power system 16 is opened, the generator and the load are cut off from the power system 16, and the power system is stabilized.

Further, when the variable output device 15 detects the occurrence of a system accident based on the accident information 46 acquired from the power system 16 after receiving the auxiliary signal 43, the output variable device 15 is based on the operation mode switching command 45 given as the auxiliary signal 43. Switch your own driving mode. The frequency stability of the power system 16 is maintained by changing the tidal current state by switching the operation mode of the variable output device 15 and providing the adjusting force.

Further, the market management system 10 reviews the interconnection line constraint 34 based on the risk mitigation effect 42 given by the integrated wide area reliability management device 1 as described above, and adjusts based on the revised interconnection line constraint 34. Reform the power procurement plan 33. Then, the market management system 10 outputs the adjustment power procurement plan 33 formulated at this time to the supply and demand adjustment market 12 as the adjustment power successful bid information 48.

(1-3) State of the power system during normal times, during an accident, and after the accident is eliminated Next, the state of the power system during normal times, during an accident, and after the accident is eliminated will be described with reference to FIGS. 3 to 5.

FIG. 3 shows the state of the power system in normal times. The power system is composed of a plurality of buses 50a to 50f and a plurality of branches 51a to 51h. Buses 50a to 50f correspond to substations, switchyards, and the like existing on the power system 16. Generators 52a to 52d and loads 53a to 53d are connected to the buses 50a to 50f, respectively. Further, the branches 51a to 51h correspond to the transmission lines on the power system 16 and connect the buses 50a to 50f to each other. Impedance, heat capacity, and stability corresponding to the transmission lines constituting the branches 51a to 51h are set in each branch 51a to 51h, respectively. The buses 50a to 50f are also set with system restrictions determined by the voltage and the like corresponding to the substations or switchyards constituting the buses 50a to 50f.

FIG. 4 shows the configuration and state of the power system at the time of the accident. The basic configuration and state are the same as in normal times, but in the case of the example of FIG. 4, an accident such as a short circuit or a ground fault has occurred at the accident point 54 on the branch 51d near the bus 50c. When a short circuit or a ground fault occurs on the power system 16, the short circuit current or the ground fault current flows into the accident point, and the power system 16 becomes unstable. Therefore, when such an accident occurs, it is necessary to promptly eliminate the accident.

FIG. 5 shows the configuration and state of the power system 16 after eliminating such an accident. The basic configuration and state are the same as in normal times, but the state of branch 51d is different in FIG. When an accident as shown in FIG. 4 occurs on the power system 16, the accident section is separated from the system to cause a power failure in order to eliminate the accident. The accident section is separated from the other power system 16 by opening the breakers and switches installed at both ends of the transmission line.

The accident section thus separated is the branch 51d in FIG. As a matter of course, since power cannot be transmitted via the branch 51d, power transmission is performed between the bus 50c and the bus 50d only via the branch 51e.

(1-4) Power Generation Plan Here, the power generation plan 32 will be described with reference to FIG. In the power generation plan 32, for example, the market management system 10 (FIG. 2) is based on the market transaction through the wholesale electricity transaction market 11 (FIG. 2) and the result of the bilateral transaction between the power generation operator and the retailer. , Unit commitment (generator start / stop plan), economic dispatch (generator output distribution), or both under the interconnection constraint 34 (FIG. 2), which is the system constraint in this embodiment. It is formulated by implementing it. If the results of market transactions and bilateral transactions do not violate the grid constraints, those results may be adopted as they are as the power generation plan 32.

However, if those results violate the grid constraint, the power generation plan 32 is reviewed to eliminate the grid constraint violation. As a result, as shown in FIG. 6, the output (generated power amount) of each generator is determined in time series every 30 minutes and output to the integrated wide area reliability management device 1. Here, only the interconnection line constraint 34 is assumed as the system constraint, but all the constraint information on the system may be used.

(1-5) Interconnector constraint Next, the interconnection constraint 34 (FIG. 2) will be described with reference to FIG. 7. In FIG. 7, times t ₀ to t ₁ are the situations before an accident occurs in the system, that is, normal times. The limit of the transmission capacity of the transmission line in normal times (hereinafter referred to as the transmission limit) is determined based on the transient stability limit, the voltage stability limit, the heat capacity limit, and the like of the transmission line.

Here, the "transient stability limit" refers to a limit flow in which the generator does not step out in a chain even if an accident occurs. Note that "step-out" means that a synchronous generator operating synchronously on the power system 16 accelerates or decelerates due to a disturbance such as an accident, and cannot continue synchronous operation with other generator groups. .. The "voltage stability limit" refers to a limit flow that can stably control the voltage without voltage collapse. Furthermore, the "heat capacity limit" refers to the limit of the current that physically flows through the transmission line, and if a current is passed beyond this, the transmission line will hang down above the specified value due to Joule heat, and in the worst case, it will burn out.

On the other hand, after time t1, _an accident has occurred in the power system 16 and the accident has been eliminated, that is, after the accident has been eliminated. As described above with respect to FIG. 5, when the accident is eliminated, the line where the accident of the transmission line has occurred is opened, so that the transmission limit in that section becomes smaller than in normal times. For example, if an accident occurs in a section that is operated on two lines in normal times as shown in FIG. 5, and the accident is eliminated by opening the line, the section after the accident is eliminated from the viewpoint of the heat capacity limit. The transmission limit of is about half of the transmission limit in normal times.

In this way, the power transmission limit of the section where the accident occurred is different before and after the accident, but either the power transmission limit before the accident (normal power transmission limit) or the power transmission limit after the accident is removed is interconnected. Whether to adopt it as the line constraint 34 depends on the system and operation policy. Generally, in the case of conservative operation, the transmission limit after accident elimination is set as the interconnection line constraint 34, and when the effect of equipment that operates after the accident occurs, such as the grid stabilization system 14, is expected. , The transmission limit in normal times is set as the interconnection line constraint 34.

FIG. 8 shows an example of the set interconnection line constraint 34. In this example, it is assumed that the interconnection constraint changes every day, but the same interconnection constraint may be applied throughout the year, and the interconnection constraint may change every hour. It is also good.

In the example of FIG. 8, for the section starting from "bus 50c" and ending at "bus 50d", the transmission limit from the start to the end on "January 1" is set to "3000 MW". It has been shown that the determinant factor is the "heat capacity" limit. In addition, the transmission limit from the end to the start is set to "1500 MW", and it is shown that the factor that determines this is also the "heat capacity" limit. In this way, different transmission limits may be set depending on the direction of the tidal current. On the other hand, the transmission limit from the beginning to the end of the same section on "January 3" is set to "2500MW", and the factor that determines this is the "transient stability" limit.

Although the interconnection line constraint 34 does not distinguish between the transmission limit in normal times and after the accident is eliminated, these may be clearly distinguished. In that case, the table in FIG. 8, the transmission limit in normal times (when the transmission limit shown in FIG. 8 is after the accident is eliminated) or after the accident is eliminated (when the transmission limit shown in FIG. 8 is in normal times). A line will be added to specify.

(1-6) Coordinating power bidding information FIG. 9 shows an example of coordinating power bidding information 31 (FIG. 2). The adjustment power bid information 31 includes the type, amount and price of the adjustment power that the bidder can provide (“primary adjustment power”, “secondary adjustment power” and “tertiary adjustment power” in the case of FIG. 9), and the adjustment power thereof. Including the available delivery time. Generally, this information is associated with the generator.

For example, in the case of the example of FIG. 9, for the "generator 52a", the "primary adjustment power" for "50" (MW) and "50" (for the 30-minute time zone starting from "0:00" You can bid for "secondary adjustment power" for "MW" and "tertiary adjustment power" for "50" (MW) at "1500" (yen / kW), but from "0:30" For the 30-minute time zone that starts, you can only bid for "primary adjustment power" for "100" (MW) at "1500" (yen / kW), and "secondary adjustment power" and "tertiary adjustment power". It is shown that "" has not been provided (the amount is "0" in each case).

The information on the type, amount and price of the adjusting power that can be delivered by the bidder and the available time of the adjusting power is not only linked to the generator but also uniquely linked to the bidder and the generator. Furthermore, if the bidder responsibly controls based on the command from the system operator, it does not have to be linked to the generator.

(1-7) Coordinating power procurement plan Next, the coordinating power procurement plan 33 will be described with reference to FIG. In the adjustment power procurement plan 33, the power transmission and distribution business operator plans to procure the adjustment power from the supply / demand adjustment market 12 by using the market management system 10. Similar to the power generation plan 32 (FIG. 6), the adjustment power procurement plan 33 also has transaction information 30 (FIG. 2) and adjustment under the interconnection line constraint 34 (FIG. 8) where the market management system 10 is a system constraint. It is formulated by implementing unit commitments, / or economic dispatches based on power bid information 31 (FIG. 9).

In the adjustment power procurement plan 33, for example, the procurement amount, price, and surplus capacity of each type of adjustment power in each generator are formulated in chronological order every 30 minutes. Since the view of FIG. 10 is the same as that of FIG. 9, the explanation here is omitted. The “remaining capacity” in FIG. 10 is input to the supply and demand adjustment market 12 (FIG. 2), but the bid is not made. It is the adjustment power. Instead of "remaining capacity", "bid amount" may be formulated. For the sake of simplicity, in the example of FIG. 10, the raising adjustment force and the lowering adjusting force are not distinguished, but they may be distinguished.

In the example of FIG. 10, for example, the following (A) to (D) can be seen.
(A) The power transmission and distribution business operator operates the power generation from the "generator 303A" (more accurately, the "generator 52a") every 30 minutes from "0:00" to "23:30". (From the operator), we plan to purchase the secondary adjustment power of "10" (MW) at the price of "1500" (yen / kW). The price here is not the price of the electric power itself, but the price of the right to change the output of the generator. Further, the "generator 52a" has a surplus capacity of the secondary adjustment force of "390" (MW) in all time zones.

(B) The power transmission and distribution business operator does not plan to procure the primary adjustment power from the "generator 52a" at all times every 30 minutes (value stored in the corresponding procurement amount column). However, both are "0").

(C) The power transmission and distribution business operator changes the primary adjustment power of "50" (MW) or "100" (MW) from "generator 52d" to "1500" (yen / kW) in each time zone every 30 minutes. ) Will be purchased at the price. In this case, the "generator 52d" has only "50" (MW) of spare capacity for the primary adjustment force in these time zones. In other words, even after the power transmission and distribution company has procured (successfully won) the primary adjustment power from the "generator 52d" by "50" (MW) or "100" (MW), it still additionally from the "generator 52d". It is possible to procure the primary adjustment power of "50" (MW).

(D) "Generator 52d" purchases "500" (MW) secondary adjustment power from "Generator 52d" at a price of "1000" (yen / kW) at each time zone every 30 minutes. It is expected to be. In this case, the "generator 52d" does not have a surplus capacity of the secondary adjusting force in these time zones (all the values stored in the corresponding surplus capacity column are "0"). In other words, the power transmission and distribution business operator can procure (successful) only "500" (MW) of secondary adjustment power from "generator 52d" and then procure additional secondary adjustment power from "generator 52d". Can not.

As mentioned above, adjustment power is a right with options. Transmission and distribution business operators are not obliged to actually exercise their rights after procuring coordination. That is, the power transmission and distribution business operator can maintain the amount of power received from the generator at a constant level even if, for example, the adjustment power is procured.

Further, the power transmission and distribution business operator may simultaneously procure different types of adjusting power from the same generator at the same time zone, for example. Then, the power transmission and distribution business operator may fluctuate the output of the generator or keep it constant. In FIG. 10, the primary adjustment power, the secondary adjustment power, and the tertiary adjustment power in the generator 52d coexist in the time zones of “0:00” and “23:30” (positive values in the corresponding procurement amount column). Is stored) indicates this.

In the adjustment power procurement plan 33 shown in FIG. 10, only the primary adjustment power, the secondary adjustment power, and the tertiary adjustment power are targeted as the types of the adjustment power. The types of these adjusting forces are mainly based on the response speed and duration of the adjusting forces. However, the types of these adjusting powers may be further classified according to the supply and demand adjustment market 12, for example, the adjusting powers of the fourth order or higher, and the output changes such as the raising adjustment power and the lowering adjustment power. It may be subdivided according to the direction of. Further, in FIGS. 6 and 10, the power generation plan 32 and the adjusting power procurement plan 33 have separate configurations, but the power generation plan 32 and the adjusting power procurement plan 33 may be integrated together.

(1-8) Relationship between wide area merit order, interconnection line constraint and frequency Next, the relationship between the wide area merit order, the interconnection line constraint 34 and the frequency will be described with reference to FIGS. 11 to 13.

FIG. 11 is a simplified representation of FIG. Generators 52a and 52b are interconnected to the area A including the buses 50a and 50b and the branches 51a to 51c in FIG. 3, and power is generated in the area B including the buses 50e and 50f and the branches 51f to 51h in FIG. The machines 52c and 52d are interconnected.

Here, as an example, as a conservative operation, the interconnection line constraint 34 is set to 1000 MW based on the transmission limit after accident elimination, and it is planned that a current of 1000 MW will already flow. It shall be. Further, it is assumed that each of the generators 52a to 52d has an adjusting power of 100 MW each.

The wide area merit order at this time is shown in FIG. The "wide area merit order" is an arrangement of electric power sources in the order of the lowest unit price of the adjusting power in a wide area across the area. Here, as an example, it is assumed that the unit price is cheaper in the order of the generator 52a, the generator 52b, the generator 52c, and the generator 52d.

Under this condition, for example, in order to compensate for the expected fluctuation of demand of 200 MW in Area B, it is considered to procure adjustment power. Based on the idea of wide area merit order, the adjustment power should be procured from the low-priced generators 52a and 52b.

However, here, the power flow of the interconnection line 51 is already planned to be full, and the adjustment power must be procured from the generator 52a and the generator 52b, and the transmission limit after the accident is eliminated is restricted by the interconnection line. It is assumed that it is set as 34 (FIG. 8). In this case, even if an accident occurs in the interconnection line 51, the adjusting force can be activated, and the frequency can be maintained stably, but the procurement cost of the adjusting force becomes high.

On the other hand, FIG. 13 shows a state when the transmission limit in normal times is set as the interconnection line constraint 34. Here, it is assumed that the interconnection line constraint is set to 1500 MW, while the planned tidal current is 1000 MW. In this case, in order to compensate for the expected fluctuation of demand of 200 MW in Area B, the adjustment power can be procured from the generator 52a and the generator 52b based on the above-mentioned wide area merit order for FIG. 12, and the adjustment power can be procured at low cost. can do. However, if an accident occurs in the interconnection line 51, the transmission limit of the interconnection line 51 will be 1000 MW after the accident is removed, so that the adjustment power of the generator 52a and the generator 52b cannot be activated and the frequency is stabilized. Cannot be maintained.

As described above, under the interconnection line constraint 34, the pursuit of the wide area merit order and the frequency maintenance may be in a dilemma relationship. Therefore, in order to achieve both the pursuit of wide-area merit order and frequency maintenance, it is important to evaluate the frequency fluctuation risk 37 (FIG. 2) linked with the supply and demand adjustment market 12 (FIG. 2).

(1-9) Frequency fluctuation risk evaluation process In consideration of the above points, FIG. 14 shows the frequency fluctuation risk evaluation unit 21 to which the power generation plan 32, the adjusting power procurement plan 33, and the interconnection line constraint 34 are given from the input unit. The processing procedure of the evaluation processing of the frequency fluctuation risk 37 (hereinafter, this is referred to as a frequency fluctuation risk evaluation processing) executed by the above is shown.

When the power generation plan 32, the adjusting power procurement plan 33, and the interconnection line constraint 34 are given from the input unit, the frequency fluctuation risk evaluation unit 21 starts the frequency fluctuation risk evaluation process shown in FIG. 14, and first, these power generation plans are started. 32, the power flow in the time section to be evaluated is calculated based on the adjustment power procurement plan 33 and the interconnection line constraint 34 (S1).

Subsequently, the frequency fluctuation risk evaluation unit 21 extracts the power transmission limit after the accident is removed from the interconnection line constraint 34, or calculates the power transmission limit after the accident is removed, and the power transmission limit after the accident is removed and the interconnection line current. The empty capacity of the interconnection line 51 is calculated based on the difference between the above and the above (S2).

Next, the frequency fluctuation risk evaluation unit 21 calculates the amount of adjusting force that can be activated within the free capacity of the interconnection line 51 for the assumed demand fluctuation 209 for each adjusting force type, and the adjustment force is excessive. Evaluate the shortfall (S3). Then, the frequency fluctuation risk evaluation unit 21 then determines, based on the evaluation result of step S3, whether or not the adjustable force that can be activated is insufficient in any one of the adjusting force types (S4).

Obtaining a negative result in this judgment means that the adjustment power is sufficient in all types and there is no risk of frequency fluctuation, but it may not be based on the wide area merit order. Thus, at this time, the frequency fluctuation risk evaluation unit 21 compares the adjustment power procurement plan 33 (FIG. 10) with the wide area merit order, and whether or not the adjustment power procurement plan 33 is based on the wide area merit order, that is, the adjustment power procurement plan. It is determined whether or not 33 plans to select the adjusting power in order from the cheapest power source (S5). Then, when the frequency fluctuation risk evaluation unit 21 obtains a positive result in this determination, the frequency fluctuation risk evaluation process ends.

On the other hand, when the frequency fluctuation risk evaluation unit 21 obtains a negative result in the judgment of step S5, the required interconnection line empty capacity 38 (FIG. 2) is calculated (S6), and then the frequency fluctuation risk evaluation process is terminated.

On the other hand, when the frequency fluctuation risk evaluation unit 21 obtains an affirmative result in the judgment of step S4, the frequency fluctuation risk evaluation unit 21 in the power system 16 after the accident elimination is based on the assumed demand fluctuation 36 (FIG. 2) and the characteristics of the adjustable force that can be activated. Evaluate frequency fluctuations (calculate frequency fluctuation risk) (S7).

Specifically, the frequency fluctuation risk evaluation unit 21 simulates the operation of the adjusting force with the control block and carries out the frequency simulation. A specific example of the assumed demand fluctuation 36 is shown in FIG. 15 (A), and an image of the frequency fluctuation obtained as a result of the frequency simulation for the assumed demand fluctuation 36 is shown in FIG. 15 (B). In this example, it is assumed that the demand increases at time _t0 , and the simulation result of the case where the adjustment power is satisfied and the simulation result of the case where the adjustment power is insufficient are shown.

In the case of the simulation result of FIG. 15B, in the case where the adjusting force is sufficient, the frequency drops to "f ₁ " immediately after the demand fluctuation occurs, but the frequency stops dropping due to the activation of the primary adjusting force. After that, the frequency returns to the original "f ₀ " by activating the secondary adjustment force. The tertiary adjustment force is mainly activated to change the output after the frequency is restored by the activation of the secondary adjustment force.

On the other hand, in the case where the primary adjustment power is insufficient, the frequency after the increase in demand continues to decrease as compared with the case where the adjustment power is sufficient, and the final adjustment power is finally activated at _time t2. The frequency becomes "f ₂ " and then returns to "f ₀ ".

In the case where the secondary adjustment force is insufficient, the frequency stops dropping at about "f ₁ " at time t ₁ due to the activation of the primary adjustment force, but the frequency may return until the time t ₃ when the tertiary adjustment force is activated. Can not. Furthermore, in the case where both the primary adjustment power and the secondary adjustment power are insufficient, the frequency continues to decrease, and if some measures are not taken, the system collapses. In this way, the frequency fluctuation risk is given by the frequency change width Δf and the change duration Δt with respect to the assumed disturbance.

In the cases shown in FIGS. 15A and 15B, a stepwise increase in demand was assumed, but on the other hand, for example, a continuous fluctuation as shown in FIG. 16A is assumed as a demand fluctuation. You may. Since the response speeds of the primary adjustment force, the secondary adjustment force, and the tertiary adjustment force are generally different, the regions to which they respond are separated as shown in FIGS. 16 (B) to 16 (D). FIG. 16B shows a demand fluctuation that the primary adjustment force should respond to, and is a fine fluctuation in seconds. Further, FIG. 16C shows a demand fluctuation that the secondary adjusting force should respond to, and is a gradual fluctuation in units of several tens of seconds to several minutes. Further, FIG. 16D shows a demand fluctuation that the tertiary adjustment force should respond to, and is a moderate fluctuation of a sufficient degree. If all the adjusting powers are satisfied, the frequency is kept almost constant as shown in FIG. 17 even if there is a demand fluctuation as shown in FIG. 16 (A).

On the other hand, the cases where the adjusting force is insufficient are shown in FIGS. 18 (A) to 18 (C). FIG. 18A shows a case where the primary adjustment force is insufficient, and the fine frequency fluctuation in seconds cannot be suppressed. Further, FIG. 18B shows a case where the secondary adjustment force is insufficient, and the frequency fluctuation in units of several tens of seconds to minutes cannot be suppressed. Further, FIG. 18C shows a case where the tertiary adjustment force is insufficient, and the frequency fluctuation cannot be sufficiently suppressed.

When assuming continuous demand fluctuations in this way, the fluctuation cycle of frequency fluctuations differs depending on the type of adjustment force that is insufficient. As the frequency fluctuation risk 37, the frequency fluctuation in the time series as shown in FIGS. 18 (A) to 18 (C) may be shown. For example, as shown in FIG. 19, spectral analysis using Fourier transform or the like is used. The fluctuation period in which the frequency fluctuation becomes remarkable may be extracted. FIG. 19 shows, as an example, the Fourier transform result when the primary adjustment force is insufficient, and the fluctuation of the period T1 exists at the intensity A1. As described above, the frequency fluctuation risk 37 is not limited to the frequency change width Δf and the change duration Δt described above, and may be expressed by using the frequency fluctuation period T or the spectral intensity A.

Further, although frequency simulation is assumed here as a specific frequency analysis method, it is not necessary to limit the method to this method, and another method such as simple calculation from the equation of motion of a generator or the like may be used. In this way, in step S7, the frequency fluctuation risk 37 is calculated, and then the frequency fluctuation risk evaluation process is terminated.

On the other hand, when the frequency fluctuation risk evaluation unit 21 finishes the frequency fluctuation risk evaluation process described above, the frequency fluctuation risk evaluation unit 21 displays the first frequency fluctuation risk evaluation result screen 60 as shown in FIG. 20 based on the processing result of the frequency fluctuation risk evaluation process. It is generated and displayed on the display device 17 (FIG. 2).

The first frequency fluctuation risk evaluation result screen 60 is a screen for displaying the frequency fluctuation risk 37 calculated by the frequency fluctuation risk evaluation process, and as shown in FIG. 20, the assumed accident content display field 61 and the assumed demand fluctuation. It is configured to include a waveform display field 62, an assumed frequency fluctuation risk content display field 63, and an assumed frequency fluctuation waveform display field 64.

Then, in the assumed accident content display field 61, the time of occurrence of the assumed accident targeted at that time (“target time” in FIG. 20), the content of the assumed accident (“assumed accident” in FIG. 20), and the assumed accident The pattern of the assumed demand fluctuation before and after the occurrence of the pattern (“estimated demand fluctuation” in FIG. 20) is displayed, and the waveform representing the assumed demand fluctuation in the pattern is displayed in the assumed demand fluctuation waveform display field 62.

Further, in the assumed frequency fluctuation risk content display field 63, the assumed change width of the frequency due to the assumed demand fluctuation (“frequency change width Δf” in FIG. 20) and the expected duration of the frequency fluctuation (FIG. 20). "Change duration Δt") and the change area of the frequency fluctuation waveform calculated by multiplying the frequency change width Δf and the change duration Δt (“change area Δf × Δt” in FIG. 20) are displayed. In the assumed frequency fluctuation waveform display field 64, a waveform showing the state of frequency waveform fluctuation before and after the occurrence of the assumed accident is displayed.

As described above with respect to FIG. 19, when the fluctuation period in which the frequency fluctuation becomes remarkable is extracted by the spectrum analysis, the frequency fluctuation risk evaluation unit 21 changes to the above-mentioned first frequency fluctuation risk evaluation result screen 60. Alternatively, the second frequency fluctuation risk evaluation result screen 70 as shown in FIG. 21 may be displayed on the display device 7 so as to be freely switchable from the first frequency fluctuation risk evaluation result screen 60.

The second frequency fluctuation risk evaluation result screen 70 is a screen for displaying the frequency fluctuation risk calculated by the frequency fluctuation risk evaluation process, similarly to the first frequency fluctuation risk evaluation result screen 60, and is shown in FIG. 21. As shown, it is configured to include an assumed accident content display field 71, an assumed demand fluctuation waveform display field 72, a spectrum information display field 73, and an assumed frequency fluctuation waveform display field 74.

Then, in the assumed accident content display field 71 and the assumed demand fluctuation waveform display field 72, the same information as the assumed accident content display field 61 and the assumed demand fluctuation waveform display field 62 of the first frequency fluctuation risk evaluation result screen 60 is displayed. Will be done.

Further, in the spectrum information display field 73, a frequency period (“period T” in FIG. 21) at which the frequency fluctuation calculated by the frequency analysis method is remarkable and the intensity of the spectrum (“spectral intensity A” in FIG. 21) are stored. In the assumed frequency fluctuation waveform display field 74, a waveform of the assumed frequency fluctuation (waveform in the upper part of FIG. 21) and a waveform representing the spectral intensity (waveform in the lower part of FIG. 21) are displayed.

(1-10) Risk Mitigation Measure Evaluation Process FIG. 22 shows a processing procedure of the risk mitigation measure evaluation process executed by the risk mitigation measure evaluation unit 22 (FIG. 2). The risk mitigation measure evaluation unit 22 follows the processing procedure shown in FIG. 22 to determine the effect of each risk mitigation measure candidate 39 registered in the risk mitigation measure candidate database 26 on the frequency fluctuation risk (risk mitigation measure candidate effect 40). Are evaluated respectively.

In practice, the risk mitigation measure evaluation unit 22 starts the risk mitigation measure evaluation process shown in FIG. 22 when the frequency fluctuation risk 37 and the required interconnection line free capacity 38 are given by the frequency fluctuation risk evaluation unit 21. Regarding FIG. 2, the frequency fluctuation risk 37 and the required interconnection line empty capacity 38 associated with the above-mentioned assumed accident list 35 and the assumed demand fluctuation 36, the assumed power flow state and the interconnection line constraint 34, and all the risk mitigation measures are taken. The candidate 39 and the candidate 39 are acquired (S10).

FIG. 23 shows an example of the risk mitigation measure candidate 39. Each risk mitigation candidate 39 includes information on the target and content of the mitigation measure, its effect (risk mitigation candidate effect 40), and the cost required for the mitigation measure. The risk mitigation measure candidate 39 can be classified into two types, for example, one that urgently activates the insufficient adjustment power and one that temporarily changes the tidal current to free up the interconnection line capacity.

Subsequently, the risk mitigation measure evaluation unit 22 evaluates the magnitude of the effect on the frequency fluctuation risk 37 and the cost required to execute the risk mitigation measure candidate 39 for each risk mitigation measure candidate 39 acquired in step S10 (. S11).

24 and 25 show examples of the effect of executing the risk mitigation measure based on the risk mitigation measure candidate 39 (risk mitigation measure candidate effect 40). FIG. 24 shows the tidal current state after the assumed accident is eliminated when the risk mitigation measures are not implemented. In the example of FIG. 24, since the tidal current flows 1000 MW with respect to the power transmission limit of 1000 MW, the adjustment force of the area A cannot be activated. At this time, for example, it is assumed that the generator in Area A outputs 500 MW, and a current of 200 MW flows from Area C toward Area B via the DC interconnection facility A.

On the other hand, FIG. 25 shows the tidal current state when “No. 1” and “No. 3” of the risk mitigation measure candidate 39 of FIG. 23 are executed. Due to the output change of the DC interconnection facility A of the risk mitigation measure candidate 39 of "No. 1", the output is increased by 500 MW to 700 MW, and the generator A is powered by the additional power control of the generator A of "NO.3". It is cut off from the system and the output becomes 0 MW. As a result, the tidal current state of the interconnection line changes, and the tidal current becomes 500 MW for the transmission limit of 1000 MW, so that the adjustment power of area A can be activated.

で示されるInjection Shift Factorを用いて評価可能である。「Injection Shift Factor」とは、任意のバスにおける電力の変化が任意のブランチに与える電力の変化の感度Ψ_(m、n),iを表したものである。（１）式の「ｍ」、「ｎ」及び「ｉ」はバス番号を示しており、ΔＰ_m,nがブランチの電力変化、ΔＰ_iがバスの電力変化を表している。（１）式を用いずに実際に潮流計算して効果を求めてもよい。 The effect of changing the interconnection line flow by the risk mitigation measures based on the risk mitigation measure candidates 39 of "No. 1" and "No. 3" is as follows.

It can be evaluated using the Injection Shift Factor indicated by. The "Injection Shift Factor" represents the sensitivity Ψ _{(m, n), i} of the change in power given to any branch by the change in power in any bus. “M”, “n” and “i” in the equation (1) represent bus numbers, ΔP _{m and n} represent branch power changes, and ΔP _i represents bus power changes. The effect may be obtained by actually calculating the tidal current without using the equation (1).

As described above, as a measure for changing the output of the variable output device 15 (FIG. 2), the frequency fluctuation risk 37 and the interconnection line constraint 34 are used to interconnect so that the frequency fluctuation risk 37 is equal to or less than the allowable value. The frequency fluctuation risk 37 is evaluated by changing the line constraint 34, and the required interconnection line empty capacity 38 is calculated. If the required interconnection line free capacity 38 is obtained, the injection shift factor may be used to determine the amount of risk mitigation measures triggered by the risk mitigation measure candidates 39 so that the required interconnection line free capacity 38 can be obtained.

のように表される。 The relationship between the frequency fluctuation risk 37 and the interconnection line constraint 34 may be obtained by executing a frequency simulation each time, or may be obtained by modeling using past information by regression analysis or machine learning. For example, when linear regression analysis is used, the relationship between the frequency fluctuation risk Δf and the interconnection line constraint P _limit is expressed by the following equation with the regression coefficient as C.

It is expressed as.

On the other hand, the risk mitigation measure based on the risk mitigation measure candidate 39 of "No. 2" and "No. 4" in FIG. 23 switches the operation mode of the generator and the variable output device 15 to temporarily activate the adjustment power. It is a countermeasure. For example, by changing the generator in the governor-locked state to governor-free operation or changing the DC interconnection facility A from constant output operation to governor-free operation, the adjustment power that cannot be activated is supplemented.

The effect of the risk mitigation measures based on these risk mitigation measure candidates 39 is evaluated by using, for example, frequency simulation, and the reduction amount of the frequency fluctuation risk 37 before and after the execution and the countermeasure cost are obtained for each risk mitigation measure candidate 39. In addition, the adjustment power procurement plan 33 (Fig. 2) is additionally input, and the amount that can be reduced in the adjustment power procurement cost by implementing the risk mitigation measure candidate 39 (the amount of reduction in the adjustment power procurement cost) is also calculated. May be good. In this case, the risk mitigation measure evaluation unit 22 collectively outputs these as the risk mitigation measure candidate effect 40.

Subsequently, the risk mitigation measure evaluation unit 22 ranks the risk mitigation measure candidate 39 based on the risk mitigation measure candidate effect 40 (S12). The viewpoints of ranking include frequency fluctuation risk 37 after executing risk mitigation measures based on risk mitigation measure candidate 39, reduction amount of frequency fluctuation risk 37, reduction amount of adjustment ability procurement cost, and countermeasure cost. A separate ranking may be created for each viewpoint, or one ranking may be created with weighting for each viewpoint.

の指標Indexを用いてランク付けすればよい。なお（３）式において、ΔＲは周波数変動リスク３７の低減量、ΔＰ_ｐは調整力調達コストの低減量、Ｐ_ｃは対策費用をそれぞれ表す。ただし、調整力調達コストの低減量ΔＰ_ｐを算出していない場合には、（３）式の右辺の分子をΔＲのみとすればよい。 For example, when generating one ranking, only the risk mitigation measure candidate 39 whose frequency fluctuation ranking after executing the risk mitigation measure based on the risk mitigation measure candidate 39 is equal to or less than the threshold value is extracted, and the extracted risk mitigation measure candidate is extracted. 39, the following formula

It may be ranked using the index Index of. In equation (3), ΔR represents the amount of reduction in frequency fluctuation risk 37, ΔP _p represents the amount of reduction in adjustment power procurement cost, and P _c represents the countermeasure cost. However, if the reduction amount ΔP _p of the adjustment power procurement cost has not been calculated, the numerator on the right side of the equation (3) may be only ΔR.

Next, the risk mitigation measure evaluation unit 22 displays the evaluation results for each of the corresponding risk mitigation measure candidates 39 executed as described above in order of rank on the display device 7 (S13). Specifically, as shown in FIG. 26, for example, the risk mitigation measure evaluation unit 22 includes the rank of the risk mitigation measure candidate 39 and the risk based on the risk mitigation measure candidate 39 as the contents of each applicable risk mitigation measure candidate 39. List the operation targets and contents in the mitigation measures, and as the risk mitigation measure candidate effect 40 based on the risk mitigation measure candidate 39, the index Index calculated by equation (3), the reduction amount ΔR of the frequency fluctuation risk 37, and the adjustment power procurement. The cost reduction amount ΔP _p and the countermeasure cost P _c are displayed.

Next, the risk mitigation measure evaluation unit 22 selects the risk mitigation measure candidate 39 to be armed from the ranked risk mitigation measure candidates 39 (S14). Here, "arming" means putting the vehicle into a standby state so that it can be executed immediately when the accident information is detected. In selecting, even if the risk mitigation measure candidate 39 specified by the user is selected from the risk mitigation measure candidates 39 listed on the display device 7 as described above, the risk mitigation measure evaluation unit 22 automatically performs the selection. The risk mitigation measure candidate 39 at the top of the ranking may be selected. The risk mitigation measure candidate 39 selected at this time is displayed on the display device 7 together with the risk mitigation effect 42 as a risk mitigation measure to be actually applied to the corresponding frequency fluctuation risk.

After that, the risk mitigation measure evaluation unit 22 generates an auxiliary signal 43 (FIG. 2) for putting the system stabilization system 14 and the output variable device 15 into the arm state (S14). The auxiliary signal 43 generated at this time includes information such as the operation associated with the assumed accident of the system stabilization system 14 and the output variable device 15. For example, as shown in FIG. 27, the validity period of the risk mitigation measure based on the risk mitigation measure candidate 39 selected in step S14, the destination of the auxiliary signal 43, and the specific risk mitigation measure based on the risk mitigation measure candidate 39. Information on various operations and assumed accidents is included in the auxiliary signal 43.

Then, the risk mitigation measure evaluation unit 22 ends the risk mitigation measure evaluation process after this.

The auxiliary signal 43 generated in step S15 is then transmitted from the output unit 23 (FIG. 2) to the system stabilization system 14 and / or the corresponding output variable device 15 via the communication line 13 (FIG. 2). .. Then, the system stabilization system 14 and the corresponding output variable device 15 that have received the auxiliary signal 43 hold the risk mitigation measures specified by the auxiliary signal 43 in the arm state during the valid period specified by the auxiliary signal 43. However, when the target accident information is detected in the power system 16 (FIG. 2), the risk mitigation measures are executed.

At this time, the system stabilization system 14 can originally acquire the protection relay information. In addition, if protection relay information can be directly obtained for other devices, risk mitigation measures can be implemented without problems. On the other hand, when the grid stabilization system 14 cannot acquire the protection relay information, a line for acquiring the protection relay information is installed, or the signal from the grid stabilization system 14 is input by connecting to the grid stabilization system 14. A method such as using it can be considered.

(1-11) Effect of the present embodiment As described above, the system stabilization system 14, the output variable device 15, and the market management system 10 are connected to the integrated wide area reliability management device 1 of the present embodiment. Therefore, the effect shown in the risk mitigation measure candidate 39 can be realized. As a result, it is possible to effectively utilize the adjustment power that cannot be procured or activated due to the interconnection line constraint 34, and it is possible to achieve both the pursuit of wide area merit order and the maintenance of frequency stability. In addition, by establishing such a technology, it is possible to define a new product for emergencies in the supply and demand adjustment market 12 (FIG. 2).

(2) Second Embodiment FIG. 28, in which the corresponding portions corresponding to those of FIGS. 1 and 2 are designated by the same reference numerals, shows the power system ES ′ according to the second embodiment. The electric power system ES'is different from the electric power system ES of the first embodiment only in that the integrated wide area reliability management device 1 is connected to the EMS (Energy Management System) 80. In FIG. 28, the integrated wide area reliability management device 1 is directly connected to the EMS, but may be connected via, for example, a communication line 13.

In the present embodiment, the integrated wide area reliability management device 1 transmits the auxiliary signal 43 not only to the system stabilization system 14 and / or the output variable device 15, but also to the EMS 80. Then, the EMS 80 causes an accident in the output power of the variable output device 15 by transmitting the LFC command signal 81 to the variable output device 15 that needs to support LFC (Load Frequency Control) based on the given auxiliary signal 43. Change according to the information.

By doing so, in addition to the effect obtained by the first embodiment, it is also possible to cope with the secondary adjustment force such as LFC activated by the signal from the center, which was not possible in the first embodiment. You can get the effect of being able to.

(3) Other Embodiments In the first and second embodiments described above, the case where the present invention is applied to the electric power system ES, ES'as shown in FIG. 1 or FIG. 28 will be described. However, the present invention is not limited to this, and can be widely applied to other electric power systems having various configurations.

The present invention is connected to a market management system that executes and manages transactions in the power market, and can be widely applied to management devices having various configurations for managing the power system.

1 ... Integrated wide area reliability management device, 3 ... Central control device, 4 ... Main storage device, 5 ... Auxiliary storage device, 8 ... Database, 9 ... Program, 10 ... Market management system, 11 …… Wholesale power trading market, 12 …… Supply and demand adjustment market, 14 …… System stabilization system, 15 …… Variable output equipment, 16 …… Power system, 21 …… Frequency fluctuation risk evaluation department, 22 …… Risk mitigation measures Evaluation Department, 24 ... Assumed accident database, 25 ... Assumed demand fluctuation database, 26 ... Risk mitigation measure candidate database, 30 ... Transaction information, 31 ... Coordinating power bid information, 32 ... Power generation plan, 33 ... Coordinating power procurement plan, 34 ... Interconnection line constraint, 35 ... Assumed accident list, 36 ... Assumed demand fluctuation, 37 ... Frequency fluctuation risk, 38 ... Required interconnection line free capacity, 39 ... Risk mitigation measures Candidate, 40 ... Risk mitigation measure Candidate effect, 42 ... Risk mitigation effect, 43 ... Auxiliary signal, 44 ... Set value, 45 ... Operation mode switching command, 46 ... Accident information, 48 ... Adjustment power successful bid Information, 60, 70 ... Frequency fluctuation risk evaluation result screen, 80 ... EMS, 81 ... LFC command signal, ES, ES'... Power system.

Claims (11)

In a management device that is connected to a market management system that executes and manages transactions in the power market and manages the power system.
From the market management system, the plan information that is a plan for power procurement and the system constraint that is the technical constraint in the interconnection line connecting the areas of the power system are acquired, and the accident that is assumed for the interconnection line The frequency fluctuation risk evaluation unit that calculates the frequency fluctuation risk after occurrence and the required interconnection line free capacity, which is the free capacity of the interconnection line required to realize the wide-area merit order of adjustment power, respectively.
For one or more risk mitigation measure candidates registered in advance for the calculated frequency fluctuation risk and the required interconnection line free capacity , the cost and effect when the risk mitigation measure candidate is applied as the risk mitigation measure. A management device including a risk mitigation measure evaluation unit that evaluates each of them and selects the risk mitigation measure candidate to be applied as a risk mitigation measure for the frequency fluctuation risk based on the evaluation result. A database of assumed accidents in which one or more assumed accidents, which are assumed accidents for the interconnection line, are registered in advance, and
Equipped with an assumed demand fluctuation database in which one or more assumed demand fluctuations, which are expected demand fluctuations, are registered in advance.
The frequency fluctuation risk evaluation unit
Based on the plan information and system constraints acquired from the market management system, the assumed accidents related to the interconnection line registered in the assumed accident database, and the assumed demand fluctuations registered in the assumed demand fluctuation database. The management device according to claim 1, wherein the frequency fluctuation risk and the required interconnection line empty capacity are calculated. The frequency fluctuation risk evaluation unit
The first aspect of claim 1 is characterized in that, as the frequency fluctuation risk, one or more of the product of the frequency change width of the power, the duration of the power change, the change width, and the duration is calculated. Management device. The frequency fluctuation risk evaluation unit
The management device according to claim 1, wherein as the frequency fluctuation risk, one or more of the fluctuation cycle and the intensity calculated by a predetermined frequency analysis method for the frequency fluctuation of electric power is calculated. The Risk Mitigation Measures Evaluation Department
When at least one of the reduction amount of the frequency fluctuation risk and the countermeasure cost and the reduction amount of the procurement cost of the adjusting power is applied to each of the risk mitigation measure candidates as the risk mitigation measure candidate. The management device according to claim 1, wherein each of the effects is calculated. The Risk Mitigation Measures Evaluation Department
Each risk mitigation candidate is ranked based on the effect of applying the risk mitigation candidate calculated for each risk mitigation candidate as the risk mitigation measure, and the risk is based on the ranking result. The management device according to claim 5, wherein the risk mitigation measure candidate to be applied as a mitigation measure is selected. The Risk Mitigation Measures Evaluation Department
An auxiliary signal is generated based on the risk mitigation measure candidate applied as the risk mitigation measure.
A system stabilization system that executes stabilization processing to stabilize the power system when an accident occurs in the power system, and a power output device that can adjust the output of the generated auxiliary signal. The management device according to claim 6, wherein the system stabilization system executes the stabilization process and / or adjusts the output power of the power output device by transmitting to at least one of them. The auxiliary signal is
The management device according to claim 7, wherein the corresponding risk mitigation measures include the validity period, operation, and assumed accident. The Risk Mitigation Measures Evaluation Department
The generated auxiliary signal is transmitted to the EMS (Energy Management System), and the auxiliary signal is transmitted to the EMS (Energy Management System).
EMS is
The management device according to claim 7, wherein the required output power of the power output device is changed according to the accident information based on the given auxiliary signal. In a management method that is connected to a market management system that executes and manages transactions in the power market and is performed by a management device that manages the power system.
The management device acquires from the market management system the planning information which is a plan for power procurement and the system constraint which is a technical constraint in the interconnection line connecting the areas of the power system, and the interconnection line The first step of calculating the risk of frequency fluctuation after the occurrence of an assumed accident and the required free capacity of the interconnection line, which is the free capacity of the interconnection line required to realize the wide-area merit order of the adjustment power, respectively. When,
When the management device applies the risk mitigation measure candidate as a risk mitigation measure to one or more risk mitigation measure candidates registered in advance for the calculated frequency fluctuation risk and the required interconnection free capacity . A management method comprising a second step of evaluating each of the costs and effects of the above, and selecting the risk mitigation measure candidate to be applied as the risk mitigation measure for the frequency fluctuation risk based on the evaluation result. In a management system that manages the power system
A market management system that executes and manages transactions in the electricity market,
It has a management device that is connected to the market management system and manages the power system.
The management device is
From the market management system, the plan information that is a plan for power procurement and the system constraint that is the technical constraint in the interconnection line connecting the areas of the power system are acquired, and the accident that is assumed for the interconnection line The frequency fluctuation risk evaluation unit that calculates the frequency fluctuation risk after occurrence and the required interconnection line free capacity, which is the free capacity of the interconnection line required to realize the wide-area merit order of adjustment power, respectively.
For one or more risk mitigation measure candidates registered in advance for the calculated frequency fluctuation risk and the required interconnection line free capacity , the cost and effect when the risk mitigation measure candidate is applied as the risk mitigation measure. A management system characterized by having a risk mitigation measure evaluation unit that evaluates each and selects the risk mitigation measure candidate to be applied as a risk mitigation measure for the frequency fluctuation risk based on the evaluation result.

Images