KR102744629B1 - Linear inertia constraint modeling method for considering frequency stability in power generation plan - Google Patents

Abstract

According to the present invention, a linear inertia constraint modeling method considering frequency stability in a power generation plan includes a step of modeling and linearizing an average rate of change of frequency (hereinafter referred to as RoCoF) constraint by considering the primary frequency response of a synchronous generator connected to a power system and a load change in response to a frequency change, and a step of modeling and linearizing a minimum frequency constraint by considering a change in the primary frequency response capability of the power system so that the lowest frequency does not exceed the lowest frequency limit in each planned time section of a unit commitment (UC) of the generator start-up and shutdown plan. Through this, the present invention effectively derives a linear inertia constraint condition considering frequency stability in a generator start-up and shutdown plan, and provides an effect of being able to decide whether to put in a synchronous generator by considering the frequency stability when an expected accident occurs in the power system.

Description

{LINEAR INERTIA CONSTRAINT MODELING METHOD FOR CONSIDERING FREQUENCY STABILITY IN POWER GENERATION PLAN}

The present invention relates to a linear inertia constraint modeling method for modeling linear inertia constraint conditions that take frequency stability into account in a power generation plan.

The inertia of a power system refers to the ability of the system to resist frequency changes. If the inertia of a power system decreases, frequency changes due to supply and demand imbalances become more severe, making it difficult to maintain frequency stability in the system.

The inertia of the power system is provided by the kinetic energy of the rotating body of the generator that is operated synchronously. In the case of large-scale power systems, in the past, power was mostly supplied by synchronous generators, so a sufficient level of system inertia could be maintained in terms of frequency stability. However, today, as the proportion of power supplied by asynchronous power sources such as wind power or solar power generation increases for the purpose of low-carbon and decarbonization of the power system, the inertia of the power system is gradually decreasing.

In order to maintain frequency stability in a system where the proportion of asynchronous power generation has increased, sufficient system inertia and primary frequency response must be secured. In order to secure system inertia, methods for directly securing it through a synchronous generator or assisting inertia through power electronic equipment such as BESS are being studied, but the fundamental securing of system inertia is achieved through the introduction of a synchronous generator.

Therefore, a method for securing system inertia to maintain frequency stability is needed in the generator start-up and shutdown plan that determines the input of a synchronous generator.

The information contained in this background section has been prepared to promote understanding of the background of the invention and may include matters that are not prior art and are already known to those skilled in the art.

The present invention proposes a linear inertia constraint modeling device and a linear inertia constraint modeling method capable of determining whether to introduce a synchronous generator by considering frequency stability when a power system accident occurs by deriving a single generator frequency response model by equivalentizing it to a single generator, determining linear inertia constraint parameters considering frequency stability in a power generation plan, and modeling linear inertia constraint conditions considering frequency stability in a generator start-up and shutdown plan.

The linear inertia constraint modeling method considering frequency stability in the power generation plan of the present invention includes a step of modeling and linearizing an average rate of change of frequency (hereinafter referred to as RoCoF) constraint considering the primary frequency response of a synchronous generator connected to a power system and the load change for the frequency change, and a step of modeling and linearizing a minimum frequency constraint considering the change in the primary frequency response capability of the power system so that the lowest frequency does not exceed the lowest frequency limit in each planned time section of the generator start-up and shutdown plan (Unit Commitment, UC).

The step of modeling and linearizing the above average RoCoF constraint can constrain the size of the average RoCoF in each planned time interval of the generator start-up and shutdown plan (Unit Commitment, UC) so as not to exceed the size of the critical RoCoF.

The above critical RoCoF size can be applied as a threshold value of a RoCoF protection relay.

The step of modeling and linearizing the above minimum frequency constraint may include a step of dividing the power system according to the operating mode of the pumped-storage generator, whose start-up and shutdown are determined by the generator start-up and shutdown plan (Unit Commitment, UC).

The operation mode of the above-mentioned pump-storage generator may include a power generation mode in which the pump-storage generator operates to generate power, and a non-generation mode in which the pump-storage generator operates in a pumping mode without operating in the above-mentioned power generation mode, or in which all pump-storage generators are stopped.

The step of modeling and linearizing the above minimum frequency constraint may include a step of modeling a linear minimum frequency constraint so as to determine the minimum frequency with different time constants for each power system classified according to the operation mode of the above-mentioned pump generator.

The above average RoCoF constraint and the above minimum frequency constraint are implemented as analytical expressions derived through the RFR model, which is a single-generator frequency response model, and the nonlinear inertia constraint through the analytical expression of the frequency can be linearized by a piecewise linearization method based on the Max-Affine function, which is suitable for linearizing a multivariable function.

The above average RoCoF constraint and the above minimum frequency constraint can be modeled so that the load change degree according to the frequency change can be considered differently for each planning time of the generator start-up and shutdown plan (Unit Commitment, UC) in the average RoCoF constraint and the minimum frequency constraint by including a load attenuation coefficient in the linearization variable.

An additional step may be included to model a first-order steady-state frequency constraint such that the first-order steady-state frequency does not exceed the critical frequency during each time interval of the generator start-up and shutdown schedule (Unit Commitment, UC).

A linear inertia constraint modeling method considering frequency stability in a power generation plan of the present invention includes a step of modeling a linear inertia constraint condition considering frequency stability of a power system, and a step of determining whether to put in a synchronous generator so as to satisfy frequency stability when an expected accident of the power system occurs through a generator start-up and shutdown plan (Unit Commitment, UC) based on the modeled linear inertia constraint condition.

The step of modeling the above linear inertia constraint condition can calculate the average RoCoF and the lowest frequency through the linearized linear inertia constraint condition by equivalentizing various types of generators connected to the power system as a single generator.

The above linear inertia constraint condition may include a step of modeling the rate of change of frequency (hereinafter referred to as RoCoF) constraint as an average RoCoF constraint that considers the first frequency response of the synchronous generator and the load change in response to the frequency change of the power system.

The above average RoCoF constraint can prevent continuous generation loss in the power system that may occur when a frequency change rate relay (RoCoF relay) that operates to protect power generation facilities is operated due to excessive RoCoF when RoCoF exceeding a threshold value is continuously measured during a delay time (Time delay), and can prevent excessive securing of system inertia due to the instantaneous RoCoF constraint.

The above linear inertia constraint condition may include a step including a modeled minimum frequency constraint that takes into account changes in the first-order frequency response capability of the power system.

The above minimum frequency constraint can be applied differently depending on the operating mode of the pumped-storage generator whose start/stop is determined in the power generation plan.

The above minimum frequency constraint can be used to restrict the minimum frequency in each planned time section of the generator start-up and shutdown plan (Unit Commitment, UC) from exceeding the minimum standard of the frequency maintenance criterion in the event of an assumed accident.

The step of modeling the above linear inertia constraint condition can reflect the influence of system load change on frequency change in the average RoCoF constraint and the lowest frequency constraint by considering the load damping factor for frequency as one of the linearization variables.

According to the present invention, input data for applying linear inertia constraint conditions to a generator start-up and shutdown plan are collected, the collected input data are analyzed by a generator start-up and shutdown plan (Unit Commitment, UC) program, and then the parameters of linear inertia constraints considering frequency stability in the power generation plan are determined using the data analyzed by the generator start-up and shutdown plan program, thereby making it possible to determine whether to put in a synchronous generator considering frequency stability when an expected accident occurs in a power system.

In addition, the present invention can derive a single generator frequency response model that minimizes the number of variables by equivalentizing various types of generators connected to a power system into a single generator and then minimizing the number of variables with the equivalent single generator, and by modeling constraints for a generator start-up and shutdown plan (Unit Commitment, UC) through the single generator frequency response model, it provides an environment in which linear inertia constraint conditions that consider frequency stability in a generator start-up and shutdown plan can be effectively derived.

In addition, the present invention models linear inertia constraint conditions that take into account the frequency stability of a power system, and determines whether to introduce a synchronous generator to satisfy the frequency stability when a power system fault occurs through a generator start-up and shutdown plan (Unit Commitment, UC) based on the modeled linear inertia constraint conditions, thereby providing an environment in which the system inertia required for stable operation of a power system can be secured.

In addition, the present invention models and linearizes an average rate of change of frequency (hereinafter referred to as RoCoF) constraint by considering the primary frequency response of a synchronous generator connected to a power system and load changes in response to frequency changes, and models and linearizes a minimum frequency constraint by considering changes in the primary frequency response capability of the power system so that the lowest frequency does not exceed the lowest frequency limit in each planned time section of a generator start-up and stop plan (Unit Commitment, UC), thereby providing an environment in which system inertia can be stably secured by considering frequency stability when planning a generator start-up and stop plan.

FIG. 1 is a diagram schematically illustrating a generator start-up and shutdown planning system considering frequency stability according to one embodiment of the present invention.
FIG. 2 is a block diagram of a linear inertia constraint parameter determination device according to one embodiment of the present invention.
FIG. 3 is a block diagram of a single generator frequency response modeling device according to one embodiment of the present invention.
FIG. 4 is a block diagram of a linear inertial constraint modeling device according to one embodiment of the present invention.
FIG. 5 is a flowchart briefly illustrating a process of modeling a single generator frequency response, determining linear inertia constraint parameters, and then modeling linear inertia constraint conditions in a generator start-up and shutdown planning system considering frequency stability according to one embodiment of the present invention.
FIG. 6 is a flowchart briefly illustrating a process of determining parameters of linear inertia constraints in consideration of frequency stability in a power generation plan according to one embodiment of the present invention.
FIG. 7 is a flowchart briefly illustrating a process of equivalentizing various types of generators to a single generator, deriving a single generator frequency response model for inertia constraints, and modeling constraints for a generator start-up and shutdown plan (Unit Commitment, UC) according to one embodiment of the present invention.
FIG. 8 is a flowchart briefly illustrating a process of modeling and linearizing linear inertia constraint conditions in consideration of frequency stability in a power generation plan according to one embodiment of the present invention, and determining whether to introduce a synchronous generator based on the linear inertia constraint conditions so as to satisfy frequency stability when an expected accident occurs in a power system.
FIG. 9 is a diagram briefly illustrating an average RoCoF constraint among linear inertia constraint conditions of a generator start-up and shutdown plan according to one embodiment of the present invention.
FIG. 10 is a diagram briefly illustrating the concept of instantaneous RoCoF and average RoCoF according to one embodiment of the present invention.
FIG. 11 is a diagram briefly illustrating a minimum frequency constraint among linear inertia constraint conditions of a generator start-up and shutdown plan according to one embodiment of the present invention.
FIG. 12 is a diagram briefly illustrating a step of dividing a power system according to an operating mode of a pumped-storage generator in a step of modeling and linearizing a minimum frequency constraint according to one embodiment of the present invention.
FIG. 13 is a diagram illustrating a reduced frequency response model (RFR) according to one embodiment of the present invention.
FIG. 14 is a diagram schematically illustrating an example of comparing a system frequency calculated by a sophisticated system model and an RFR model according to one embodiment of the present invention.
FIG. 15 is a diagram briefly illustrating a first-order steady-state frequency constraint among linear inertia constraint conditions of a generator start-up and shutdown plan according to one embodiment of the present invention.

Hereinafter, with reference to the attached drawings, embodiments of the present invention will be described in detail so that those skilled in the art can easily practice the present invention. However, the present invention may be implemented in various different forms and is not limited to the embodiments described herein. In addition, in order to clearly describe the present invention in the drawings, parts that are not related to the description are omitted, and similar parts are assigned similar drawing reference numerals throughout the specification.

Throughout the specification, when a part is said to "include" a certain component, this does not mean that it excludes other components, but rather that it may include other components, unless otherwise specifically stated. In addition, terms such as "part," "unit," and "module" described in the specification mean a unit that processes at least one function or operation, which may be implemented by hardware, software, or a combination of hardware and software.

In this specification, the power system or grid refers to electrical facilities physically interconnected to supply electricity produced at power plants to electricity users, i.e., power generation facilities, transmission and distribution facilities, distribution facilities, and other auxiliary facilities.

Now, with reference to FIGS. 1 to 15, a linear inertia constraint modeling device and a linear inertia constraint modeling method of a generator start-stop planning system considering frequency stability according to one embodiment of the present invention will be described in detail.

FIG. 1 is a diagram schematically illustrating a generator start-up and stop planning system considering frequency stability according to one embodiment of the present invention. At this time, the generator start-up and stop planning system (10) considering frequency stability only illustrates a schematic configuration necessary for explanation according to an embodiment of the present invention, and is not limited to this configuration.

Referring to FIG. 1, a generator start-up and shutdown planning system (10) considering frequency stability according to one embodiment of the present invention includes a linear inertia constraint parameter determination device (100), a single generator frequency response modeling device (200), and a linear inertia constraint modeling device (300).

The above linear inertia constraint parameter determination device (100) collects input data for applying linear inertia constraint conditions to a generator start-up and shutdown plan, and can analyze the collected input data using a generator start-up and shutdown plan (Unit Commitment, UC) program. Here, the input data can include input data of individual generators including the inertia constant of a synchronous generator, the generator gain of the synchronous generator, and the capacity of the synchronous generator.

And, the linear inertia constraint parameter determination device (100) can determine the parameters of the linear inertia constraint that consider frequency stability in the power generation plan using the data analyzed in the generator start-up and shutdown plan program. Here, the parameters of the linear inertia constraint can include system inertia, single generator gain, and load damping coefficient.

The above single generator frequency response modeling device (200) can equate various types of generators connected to a power system to a single generator, derive a single generator frequency response model that minimizes the number of variables with the equivalent single generator, and model constraints for a generator start-up and shutdown plan (Unit Commitment, UC) through the single generator frequency response model. Here, the equivalent single generator can reduce a number of high-order systems, such as turbine and governor models, to a single first-order system, and include a single generator gain and a single time constant as variables.

In addition, the single generator frequency response model may include at least one of the amount of generation loss in the event of a power system fault, the inertia of the power system, the load damping coefficient, the single generator gain, or the single generator time constant as a linearization variable.

The above linear inertia constraint modeling device (300) models linear inertia constraint conditions that take into account the frequency stability of a power system, and can determine whether to put in a synchronous generator to satisfy the frequency maintenance criteria when an expected accident occurs in the power system through a generator start-up and shutdown plan (Unit Commitment, UC) based on the modeled linear inertia constraint conditions.

In addition, the linear inertia constraint modeling device (300) can model and linearize the average rate of change of frequency (hereinafter referred to as RoCoF) constraint by considering the inertia and first frequency response of a synchronous generator connected to a power system and the load change in response to the frequency change of the power system.

In addition, the linear inertia constraint modeling device (300) can model and linearize the minimum frequency constraint by considering changes in the primary frequency response capability of the power system and load changes due to system inertia and frequency changes so that the minimum frequency does not exceed the minimum frequency limit in each planned time section of the generator start-up and shutdown plan (Unit Commitment, UC).

In addition, the linear inertia constraint modeling device (300) can model the first steady-state frequency constraint so that the first steady-state frequency does not exceed the critical frequency in each time section of the generator start-up and shutdown plan (Unit Commitment, UC).

FIG. 2 is a block diagram of a linear inertia constraint parameter determination device according to one embodiment of the present invention. At this time, the linear inertia constraint parameter determination device (100) only shows a schematic configuration necessary for explanation according to an embodiment of the present invention, and is not limited to this configuration.

Referring to FIG. 2, a linear inertia constraint parameter determination device (100) according to one embodiment of the present invention includes a parameter determination control module (110), a data collection module (120), an analysis module (130), and a parameter determination module (140).

The above parameter determination control module (110) collects input data for applying linear inertia constraint conditions to a generator start-up and stop plan, analyzes the collected input data using a generator start-up and stop plan (Unit Commitment, UC) program, and controls the operation of each part to determine parameters of linear inertia constraints that take frequency stability into account in the power generation plan using the data analyzed by the generator start-up and stop plan program.

The above data collection module (120) can collect input data for applying linear inertia constraint conditions to the generator start/stop plan.

In addition, the data collection module (120) may include an input data collection unit (122) according to one embodiment of the present invention.

The above input data collection unit (122) can collect input data for applying linear inertia constraint conditions to the generator start-up and shutdown plan. Here, the input data can include input data of individual generators including the inertia constant of the synchronous generator, the generator gain of the synchronous generator, and the capacity of the synchronous generator.

The above analysis module (130) can analyze the collected input data using a generator start-up and shutdown plan (Unit Commitment, UC) program.

In addition, the analysis module (130) may include a generator start-up and shutdown plan analysis unit (132) according to one embodiment of the present invention.

The above generator start-up and shutdown plan analysis unit (132) can analyze the input data collected from the data collection module (120) using a generator start-up and shutdown plan (Unit Commitment, UC) program.

The above parameter determination module (140) can determine the parameters of linear inertia constraints that take frequency stability into account in the power generation plan using data analyzed in the generator start-up and shutdown plan program.

The above parameter determination module (140) can determine parameters determined as constants in the linearization step of the linear inertia constraint. Here, the parameters of the linear inertia constraint can include system inertia, single generator gain, and load damping coefficient.

And, the system inertia can be determined by excluding the inertia of the assumed fault generator from the inertia of all generators connected to the power system and operated. In addition, the single generator gain can be determined by excluding the generator gains of the assumed fault generators from the gains of the generators providing the first frequency response among the generators connected to the power system and operated, and the single generator gain can be determined so that it is not overestimated by considering the spare capacity that individual generators can change the output. And, the load attenuation coefficient can be determined by converting the input load attenuation coefficient into a system basis.

The present invention can model and linearize the average rate of change of frequency (RoCoF) constraint and the lowest frequency constraint by using the parameters of the linear inertia constraint derived from the linear inertia constraint parameter determination device (100).

The present invention can determine the assumed accident generator generation loss amount and the single generator time constant, which are determined as constants, respectively, under the frequency change rate constraint and the minimum frequency constraint. Here, the assumed accident generator generation loss amount can be determined as the assumed accident generator loss amount of the maximum capacity.

In addition, the single generator time constant can be determined by applying the average value of the time constants at the time of violation of the frequency stability of the power system by utilizing the power configuration result of the generator start-up and shutdown plan to which inertia constraints are not applied, and adding a correction constant so as to correct the error of the linearization method and the error of the frequency analytical expression.

In addition, the time constant applied in the above minimum frequency constraint can be determined according to the operating status of the pump generator whose start/stop is determined in the generator start/stop plan.

Figure 3 is a block diagram of a single generator frequency response modeling device according to one embodiment of the present invention. At this time, the single generator frequency response modeling device (200) only shows a schematic configuration necessary for explanation according to an embodiment of the present invention, and is not limited to this configuration.

Referring to FIG. 3, a single generator frequency response modeling device (200) according to one embodiment of the present invention includes a frequency response modeling control module (210), a transmission/reception module (230), an equivalent module (230), and a single generator modeling module (240).

The above frequency response modeling control module (210) can equate various types of generators connected to a power system to a single generator, derive a single generator frequency response model that minimizes the number of variables with the equated single generator, and control the operation of each part to model constraints for a generator start/stop plan (Unit Commitment, UC) through the single generator frequency response model.

The above-mentioned transmission/reception module (220) can transmit and receive data required for parameter determination and inertial constraint modeling with the linear inertial constraint parameter determination device (100) and the linear inertial constraint modeling device (300).

The above equivalent module (230) can equivalentize various types of generators connected to a power system into a single generator.

In addition, the equivalent module (230) may include a single generator equivalent unit (232) according to one embodiment of the present invention.

The above single generator equivalent unit (232) can equivalentize various types of generators connected to a power system into one single generator.

The above single generator modeling module (240) can derive a single generator frequency response model that minimizes the number of variables with the equivalent single generator, and can model constraints for the generator start-up and shutdown schedule (Unit Commitment, UC) through the single generator frequency response model. Here, the equivalent single generator can reduce multiple high-order systems, such as turbine and governor models, to a single first-order system, and include a single generator gain and a single time constant as variables.

In addition, the single generator modeling module (240) may include a frequency response modeling unit (242) and a constraint modeling unit (244) according to one embodiment of the present invention.

The above frequency response modeling unit (242) can derive a single generator frequency response model that minimizes the number of variables with the equivalent single generator.

The above constraint modeling unit (244) can model constraints for the generator start-up and shutdown plan (Unit Commitment, UC) using the single generator frequency response model.

In addition, the single generator frequency response model may include at least one of the amount of generation loss in the event of a power system fault, the inertia of the power system, the load damping coefficient, the single generator gain, or the single generator time constant as a linearization variable.

Here, the above generation loss amount may include the generation amount of a generator with the largest capacity among the generators connected to the power system when the generator is lost. In addition, the above generation loss amount may include a momentary change in generation or load due to an expected accident in the power system.

In addition, the single generator modeling module (240) can derive the single generator frequency response model as an analytical expression derived through a reduced frequency response model (RFR) in the step of deriving the single generator frequency response model, and can implement an average rate of change of frequency (hereinafter referred to as RoCoF) constraint or a minimum frequency constraint in the step of modeling constraints.

Here, the average rate of change of frequency (RoCoF) constraint is linearized by considering the inertia and primary frequency response of a synchronous generator connected to a power system and the load change in response to the frequency change of the power system, and the size of the average RoCoF in each planned time section of the generator start-up and shutdown plan (Unit Commitment, UC) can be restricted so that it does not exceed the size of the critical RoCoF.

In addition, the minimum frequency constraint can be linearized into a linear minimum frequency constraint so that the power system is divided according to the operation mode of the pump-storage generator, the start/stop of which is determined by the unit commitment (UC) of the generator, and the minimum frequency is determined with a different time constant for each power system divided according to the operation mode of the pump-storage generator.

The above average RoCoF constraint or the above minimum frequency constraint can be applied as a load damping coefficient as a linearization variable when modeling linear inertia constraints.

The time constant of the above single generator frequency response model can be determined by adding a correction constant to the average time constant to correct the error of the linearization method and the error of the frequency analytical expression.

Figure 4 is a block diagram of a linear inertial constraint modeling device according to one embodiment of the present invention. At this time, the linear inertial constraint modeling device (300) only shows a schematic configuration necessary for explanation according to an embodiment of the present invention, and is not limited to this configuration.

Referring to FIG. 4, a linear inertia constraint modeling device (300) according to one embodiment of the present invention includes a control module (310), an average RoCoF modeling module (320), a minimum frequency constraint modeling module (330), a first-order steady-state frequency constraint modeling module (340), and a synchronous generator input/output decision module (350).

The above control module (310) models linear inertia constraint conditions that take into account the frequency stability of the power system, and can control the operation of each part to determine whether to put in a synchronous generator that satisfies the frequency maintenance criteria when an expected accident occurs in the power system through a generator start-up and stop plan (Unit Commitment, UC) based on the modeled linear inertia constraint conditions.

In addition, the control module (310) models and linearizes an average rate of change of frequency (hereinafter referred to as RoCoF) constraint by considering the inertia and primary frequency response of a synchronous generator connected to a power system and load changes in response to frequency changes in the power system, and controls the operation of each part to model and linearize a minimum frequency constraint by considering changes in the primary frequency response capability of the power system and load changes in response to system inertia and frequency changes so that the minimum frequency does not exceed the minimum frequency limit in each planned time section of the generator start-up and shutdown plan (Unit Commitment, UC).

The above average RoCoF modeling module (320) can model and linearize the average rate of change of frequency (hereinafter referred to as RoCoF) constraint by considering the inertia and primary frequency response of a synchronous generator connected to a power system and the load change in response to the frequency change of the power system.

Additionally, the average RoCoF modeling module (320) may include a RoCoF linearization unit (322) according to one embodiment of the present invention.

The above RoCoF linearization unit (322) can model and linearize the average RoCoF constraint so that the size of the average RoCoF in each planned time section of the generator start-up and shutdown plan (Unit Commitment, UC) does not exceed the size of the critical RoCoF. Here, the critical RoCoF size can be applied as the threshold value of the RoCoF protection relay.

The above minimum frequency constraint modeling module (330) can model and linearize the minimum frequency constraint by considering changes in the primary frequency response capability of the power system and load changes due to system inertia and frequency changes so that the minimum frequency does not exceed the minimum frequency limit in each planned time section of the generator start-up and shutdown plan (Unit Commitment, UC).

In addition, the minimum frequency constraint modeling module (330) may include a pump generator operation mode analysis unit (332) and a minimum frequency constraint linearization unit (334) according to one embodiment of the present invention.

The above-mentioned pump-storage generator operation mode analysis unit (332) can divide the power system according to the operation mode of the pump-storage generator, in which the start/stop is determined by the generator start/stop plan (Unit Commitment, UC), when modeling and linearizing the minimum frequency constraint. Here, the operation mode of the pump-storage generator can include a power generation mode in which the pump-storage generator is operated for power generation and a non-generation mode in which the pump-storage generator is operated in pumping mode without being operated in the power generation mode or in which all pump-storage generators are stopped.

The above minimum frequency constraint linearization unit (334) models and linearizes the above minimum frequency constraint, and can model the linear minimum frequency constraint so as to determine the minimum frequency with different time constants for each power system classified according to the operation mode of the positive-storage generator.

The above average RoCoF constraint and the above minimum frequency constraint are implemented as analytical expressions derived through the RFR model, which is a single-generator frequency response model, and the nonlinear inertia constraint through the analytical expression of the frequency can be linearized by a piecewise linearization method based on the Max-Affine function, which is suitable for linearizing a multivariable function.

In addition, the above average RoCoF constraint and the above minimum frequency constraint can be modeled so that the load change degree according to the frequency change can be considered differently for each planning time of the generator start-up and shutdown plan (Unit Commitment, UC) in the average RoCoF constraint and the minimum frequency constraint by including a load attenuation coefficient in the linearization variable.

The above first steady-state frequency constraint modeling module (340) can model the first steady-state frequency constraint so that the first steady-state frequency does not exceed the critical frequency in each time section of the generator start-up and shutdown plan (Unit Commitment, UC).

The above synchronous generator input/output decision module (350) can determine whether to input a synchronous generator to satisfy the frequency maintenance standard in the event of an expected power system accident through a generator start/stop plan (Unit Commitment, UC) based on the modeled linear inertia constraint condition.

A linear inertia constraint modeling device (300) according to one embodiment of the present invention can model the linear inertia constraint condition for calculating the average RoCoF and the lowest frequency through a reduced frequency response model (RFR) that equates various types of generators connected to a power system to a single generator.

A linear inertia constraint modeling device (300) according to one embodiment of the present invention can model the linear inertia constraint condition as an average RoCoF constraint that considers the inertia and first frequency response of a synchronous generator and the load change for the frequency change of a power system.

At this time, the average RoCoF constraint can prevent continuous generation loss of the power system that may occur when a frequency change rate relay (RoCoF relay) that operates to protect the power generation facility is operated due to excessive RoCoF when RoCoF exceeding the threshold value is continuously measured during the delay time (Time delay), and can prevent excessive securing of the system inertia that the instantaneous RoCoF constraint has.

In addition, the linear inertia constraint condition may include a minimum frequency constraint modeled by considering the change in the first-order frequency response capability of the power system. The minimum frequency constraint may have different constraint expressions applied depending on the operation mode of the pump-storage generator whose start/stop is determined in the power generation plan. In addition, the minimum frequency constraint may prevent excessive frequency drop due to a decrease in system inertia, thereby preventing unintended operation of an under-frequency relay (UFR).

And, a linear inertia constraint modeling device (300) according to one embodiment of the present invention can reflect the influence of system load change on frequency change in average RoCoF constraint and lowest frequency constraint by considering a load damping factor for frequency as one of the linearization variables when modeling the linear inertia constraint condition.

FIG. 5 is a flowchart briefly illustrating a process of modeling a single generator frequency response, determining linear inertia constraint parameters, and then modeling linear inertia constraint conditions in a generator start-up and shutdown planning system considering frequency stability according to one embodiment of the present invention. In this case, the following flowchart is explained using the same drawing symbols as those in FIGS. 1 to 4.

Referring to FIG. 5, a generator start-up and shutdown planning system (10) considering frequency stability according to one embodiment of the present invention can equate various types of generators connected to a power system to a single generator and derive a single generator frequency response model that minimizes the number of variables with the equated single generator (S102).

And, a generator start-up and shutdown planning system (10) considering frequency stability according to one embodiment of the present invention collects input data for applying linear inertia constraint conditions to a generator start-up and shutdown plan, analyzes the collected input data using a generator start-up and shutdown plan (Unit Commitment, UC) program, and determines parameters of linear inertia constraints considering frequency stability in a power generation plan using the data analyzed by the generator start-up and shutdown plan program (S104).

And, the generator start-up and shutdown plan system (10) considering frequency stability according to one embodiment of the present invention can model the inertia constraint of the generator start-up and shutdown plan (Unit Commitment, UC) considering frequency stability of the power system through a single generator frequency response model derived as an analytical expression of an equivalent single generator (S106).

A generator start-up and shutdown planning system (10) considering frequency stability according to one embodiment of the present invention can model the limit rate of change of frequency (hereinafter referred to as RoCoF) constraint as an average RoCoF constraint that considers the inertia and primary frequency response of a synchronous generator and the load change in response to the frequency change of a power system.

A generator start-up and shutdown planning system (10) considering frequency stability according to one embodiment of the present invention can model a minimum frequency constraint by considering changes in the primary frequency response capability of a power system and load changes due to system inertia and frequency changes so that the minimum frequency does not exceed the minimum frequency limit in each planned time section of a generator start-up and shutdown plan (Unit Commitment, UC).

And, the generator start-up and shutdown planning system (10) considering frequency stability according to one embodiment of the present invention can model linear inertia constraint conditions considering frequency stability of a power system in the generator start-up and shutdown planning (Unit Commitment, UC) by linearizing the modeled average RoCoF constraint and the minimum frequency constraint, respectively (S108).

And, the generator start-up and shutdown planning system (10) considering frequency stability according to one embodiment of the present invention can determine whether to put in a synchronous generator to meet the frequency maintenance standard when an expected accident occurs in the power system through the generator start-up and shutdown plan (Unit Commitment, UC) based on the modeled linear inertia constraint condition (S110).

FIG. 6 is a flowchart briefly illustrating a process of determining parameters of linear inertia constraints in consideration of frequency stability in a power generation plan according to one embodiment of the present invention. In this case, the following flowchart is explained using the same drawing symbols as those of FIGS. 1 to 4.

Referring to FIG. 6, a linear inertia constraint parameter determination device (100) according to one embodiment of the present invention can collect input data for applying linear inertia constraint conditions to a generator start-up and shutdown plan (S210). Here, the input data can include input data of individual generators including an inertia constant of a synchronous generator, a generator gain of the synchronous generator, and a capacity of the synchronous generator.

A linear inertia constraint parameter determination device (100) according to one embodiment of the present invention can analyze the collected input data using a generator start-up and shutdown plan (Unit Commitment, UC) program (S220).

And, the linear inertia constraint parameter determination device (100) according to one embodiment of the present invention can determine the parameters of the linear inertia constraint that considers frequency stability in the power generation plan using the data analyzed in the generator start-up and stop plan program (S230).

A linear inertia constraint parameter determination device (100) according to one embodiment of the present invention can determine parameters determined as constants in a linearization step of a linear inertia constraint. Here, the parameters of the linear inertia constraint can include system inertia, single generator gain, and load damping coefficient.

The above system inertia can be determined by excluding the inertia of the assumed fault generator from the inertia of all generators connected to and operating in the power system. In addition, the single generator gain can be determined by excluding the generator gain of the assumed fault generator from the gains of generators providing the first frequency response among the generators connected to and operating in the power system, and the single generator gain can be determined so that it is not overestimated by considering the spare capacity that individual generators can vary their outputs. In addition, the load attenuation coefficient can be determined by converting the input load attenuation coefficient into a system basis.

FIG. 7 is a flowchart briefly illustrating a process of equivalentizing various types of generators to a single generator, deriving a single generator frequency response model for inertia constraints, and modeling constraints for a generator start-up and shutdown plan (Unit Commitment, UC) according to one embodiment of the present invention. In this case, the following flowchart is explained using the same drawing symbols as those of FIGS. 1 to 4.

Referring to FIG. 7, a single generator frequency response modeling device (200) according to one embodiment of the present invention can equate various types of generators connected to a power system to one single generator (S310).

Here, the equivalent single generator can be reduced from multiple higher-order systems, such as turbine and governor models, into a single first-order system, which can include a single generator gain and a single time constant as variables.

And, a single generator frequency response modeling device (200) according to one embodiment of the present invention can derive a single generator frequency response model to minimize the number of constraint variables (S320). The single generator frequency response model can include at least one of a power loss amount in the event of an assumed power system fault, power system inertia, a load damping coefficient, a single generator gain, or a single generator time constant as a linearization variable.

In addition, the above-mentioned power generation loss amount may include the power generation amount of a generator with the largest capacity among the generators connected to the power system when that generator is lost, or may include an instantaneous change in power generation or load due to an expected accident in the power system.

And, a single generator frequency response modeling device (200) according to one embodiment of the present invention can model a constraint for a generator start-up and shutdown plan (Unit Commitment, UC) using the derived single generator frequency response model (S330).

In addition, a single generator frequency response modeling device (200) according to one embodiment of the present invention can implement an average rate of change of frequency (hereinafter referred to as RoCoF) constraint or a minimum frequency constraint as an analytical expression derived through a reduced frequency response model (RFR) when deriving the single generator frequency response model.

In addition, the above average rate of change of frequency (RoCoF) constraint is linearized by considering the inertia and primary frequency response of a synchronous generator connected to a power system and the load change in response to the frequency change of the power system, and the size of the average RoCoF in each planned time section of the generator start-up and shutdown plan (Unit Commitment, UC) can be restricted so that it does not exceed the size of the critical RoCoF.

The above minimum frequency constraint can be linearized into a linear minimum frequency constraint so that the power system is divided according to the operation mode of the pump-storage generator, the start/stop of which is determined by the unit commitment (UC) of the generator, and the minimum frequency is determined with a different time constant for each power system divided according to the operation mode of the pump-storage generator.

Additionally, the above average RoCoF constraint or the above minimum frequency constraint can be applied as a load damping coefficient as a linearization variable when modeling linear inertia constraints.

The time constant of the above single generator frequency response model can be determined by adding a correction constant to the average time constant to correct the error of the linearization method and the error of the frequency analytical expression.

FIG. 8 is a flowchart briefly illustrating a process of modeling and linearizing linear inertia constraint conditions considering frequency stability in a power generation plan according to one embodiment of the present invention, and determining whether to introduce a synchronous generator based on the linear inertia constraint conditions so as to satisfy a frequency maintenance criterion when a power system accident occurs. In this case, the following flowchart is explained using the same drawing symbols as those in FIGS. 1 to 4.

Referring to FIG. 8, a linear inertia constraint modeling device (300) according to one embodiment of the present invention can model a generator start-stop plan (Unit Commitment, UC) inertia constraint equation that takes into account the frequency stability of a power system (S410).

And, a linear inertia constraint modeling device (300) according to one embodiment of the present invention can model and linearize an average rate of change of frequency (hereinafter referred to as RoCoF) constraint by considering the inertia and first frequency response of a synchronous generator connected to a power system and the load change in response to the frequency change of the power system (S420).

For example, the constraint formula for the average RoCoF constraint is as shown in Equation 1 below.

Here, is the critical RoCoF size [Hz/s], is the systematic inertia [pu] of the linear function of the average RoCoF size at time t, is at time t is the normalized load attenuation coefficient [pu], is the generator gain [pu] of the linear function of the average RoCoF size at time t, is a parameter of the average RoCoF size linear function.

FIG. 9 is a diagram briefly illustrating an average RoCoF constraint among linear inertia constraint conditions of a generator start-up and shutdown plan according to one embodiment of the present invention, and FIG. 10 is a diagram briefly illustrating the concept of instantaneous RoCoF and average RoCoF according to one embodiment of the present invention.

Referring to FIGS. 9 and 10, the linear inertia constraint condition can be modeled as a rate of change of frequency (hereinafter referred to as RoCoF) constraint that considers the inertia and first-order frequency response of a synchronous generator and the load change for the frequency change of the power system.

In addition, the above average RoCoF constraint can prevent continuous generation loss of the power system that may occur when a frequency change rate relay (RoCoF relay) that operates to protect power generation facilities is operated due to excessive RoCoF when RoCoF exceeding the threshold value is continuously measured during the delay time (Time delay), and can prevent excessive securing of system inertia caused by the instantaneous RoCoF constraint.

And, the linear inertia constraint modeling device (300) according to one embodiment of the present invention can model and linearize the minimum frequency constraint by considering the change in the primary frequency response capability of the power system and the load change according to the system inertia and frequency change so that the minimum frequency does not exceed the minimum frequency limit in each planned time section of the generator start-up and shutdown plan (Unit Commitment, UC) (S430).

For example, the constraint for the lowest frequency constraint is as shown in mathematical expression 2 below.

Here, is the power generation operation status of the entire power generator (generation: 1, others: 0), is the critical minimum frequency deviation size [Hz], is the system inertia [pu] of the linear function of the minimum frequency deviation size at time t, is at time t is the normalized load attenuation coefficient [pu], is the generator equivalent gain [pu] of the linear function of the minimum frequency deviation magnitude at time t. And, is a parameter of the linear function of the minimum frequency deviation size (power generation operation), is a parameter of the linear function of the minimum frequency deviation size (non-generating operation).

FIG. 11 is a diagram briefly illustrating a minimum frequency constraint among linear inertia constraint conditions of a generator start-up and shutdown plan according to one embodiment of the present invention, and FIG. 12 is a diagram briefly illustrating a step of dividing a power system according to an operation mode of a pump-storage generator in a step of modeling and linearizing a minimum frequency constraint according to one embodiment of the present invention.

Referring to FIGS. 11 and 12, the minimum frequency constraint can be applied differently depending on the operation mode of the pumped-storage generator whose start/stop is determined in the power generation plan. In addition, the minimum frequency constraint can prevent excessive frequency drop due to a decrease in system inertia, thereby preventing unintended operation of the under-frequency relay (UFR).

In addition, the step of modeling the above linear inertia constraint condition can reflect the influence of the system load change on the frequency change in the average RoCoF constraint and the lowest frequency constraint by considering the load damping factor for the frequency as one of the linearization variables.

FIG. 13 is a diagram illustrating a reduced frequency response model (RFR) according to one embodiment of the present invention, and FIG. 14 is a diagram briefly illustrating an example of comparing a system frequency calculated by a sophisticated system model and an RFR model according to one embodiment of the present invention.

Referring to FIGS. 13 and 14, a linear inertia constraint modeling device (300) according to one embodiment of the present invention can calculate an average RoCoF and a minimum frequency through a reduced frequency response model (RFR) that equates various types of generators connected to a power system to a single generator.

Here, the above average RoCoF constraint and the above minimum frequency constraint are implemented as analytical expressions derived through the RFR model, which is a single-generator frequency response model, and the nonlinear inertia constraint through the analytical expression of the frequency can be linearized by a piecewise linearization method based on the Max-Affine function, which is suitable for linearizing a multivariable function.

In addition, the above average RoCoF constraint and the above minimum frequency constraint can be modeled so that the load change degree according to the frequency change can be considered differently for each planning time of the generator start-up and shutdown plan (Unit Commitment, UC) in the average RoCoF constraint and the minimum frequency constraint by including a load attenuation coefficient in the linearization variable.

FIG. 15 is a diagram briefly illustrating a first-order steady-state frequency constraint among linear inertia constraint conditions of a generator start-up and shutdown plan according to one embodiment of the present invention.

Referring to FIG. 15, a linear inertia constraint modeling device (300) according to one embodiment of the present invention can model a first steady-state frequency constraint so that the first steady-state frequency does not exceed the critical frequency in each time section of a generator start-up/stop plan (Unit Commitment, UC) (S440).

For example, the constraint equation for the first-order steady-state frequency constraint is as shown in mathematical expression 3 below.

Here, is the critical first-order steady-state frequency deviation size [Hz], is at time t is the normalized load attenuation coefficient [pu], is the generator equivalent gain [pu] of the linear function of the minimum frequency deviation magnitude at time t. And, is the system base [MVA], is the rated frequency [Hz], is the maximum power generation capacity of the g generator [MW].

And, the linear inertia constraint modeling device (300) according to one embodiment of the present invention can determine whether to put in a synchronous generator to satisfy the frequency maintenance criterion when an expected accident occurs in the power system through a generator start-up and shutdown plan (Unit Commitment, UC) based on the modeled linear inertia constraint condition (S450).

In this way, the present invention collects input data for applying linear inertia constraint conditions to a generator start-up and shutdown plan, analyzes the collected input data with a generator start-up and shutdown plan (Unit Commitment, UC) program, and then determines parameters of linear inertia constraints considering frequency stability in a power generation plan using the data analyzed by the generator start-up and shutdown plan program, thereby making it possible to determine whether to put in a synchronous generator considering frequency stability when an expected accident occurs in a power system.

In addition, the present invention can derive a single generator frequency response model that minimizes the number of variables by equating various types of generators connected to a power system to a single generator and then using the equated single generator, and provides an environment in which a constraint for a generator start-up and shutdown plan (Unit Commitment, UC) can be modeled through the single generator frequency response model, thereby effectively deriving linear inertia constraint conditions that take frequency stability into account in the generator start-up and shutdown plan.

In addition, the present invention models linear inertia constraint conditions that take into account the frequency stability of a power system, and determines whether to put in a synchronous generator to satisfy a frequency maintenance criterion when a power system accident occurs through a generator start-up and shutdown plan (Unit Commitment, UC) based on the modeled linear inertia constraint conditions, thereby providing an environment in which the system inertia required for stable operation of a power system can be secured.

In addition, the present invention models and linearizes an average rate of change of frequency (hereinafter referred to as RoCoF) constraint by considering the inertia and primary frequency response of a synchronous generator connected to a power system and the load change in response to the frequency change of the power system, and models and linearizes a minimum frequency constraint by considering the change in the primary frequency response capability of the power system and the load change according to the system inertia and frequency change so that the minimum frequency does not exceed the minimum frequency limit in each planned time section of the unit commitment (UC) of the generator, thereby providing an environment in which the system inertia can be stably secured by considering frequency stability when planning the start and stop of the generator.

The embodiments of the present invention described above are not implemented only through devices and methods, but may also be implemented through a program that realizes a function corresponding to the configuration of the embodiments of the present invention or a recording medium on which the program is recorded. Such a recording medium can be executed not only on a server but also on a user terminal.

Although the embodiments of the present invention have been described in detail above, the scope of the present invention is not limited thereto, and various modifications and improvements made by those skilled in the art using the basic concept of the present invention defined in the following claims also fall within the scope of the present invention.

Claims (17)

A step for modeling and linearizing the average rate of change of frequency (RoCoF) constraints by considering the primary frequency response of a synchronous generator connected to a power system and the load change in response to frequency changes, and
A step for modeling and linearizing the minimum frequency constraint by considering the change in the primary frequency response capability of the power system so that the minimum frequency does not exceed the minimum frequency limit in each planned time section of the generator start-up and shutdown plan (Unit Commitment, UC).
A linear inertia constraint modeling method considering frequency stability in a power generation plan including . In paragraph 1,
The step of modeling and linearizing the above average RoCoF constraint is:
A linear inertia constraint modeling method that considers frequency stability in a power generation plan, characterized in that the size of the average RoCoF in each planned time interval of the generator start-up and shutdown plan (Unit Commitment, UC) is constrained so that it does not exceed the size of the critical RoCoF. In paragraph 2,
The above critical RoCoF size is,
A linear inertia constraint modeling method considering frequency stability in a power generation plan characterized by the application of threshold values of RoCoF protection relays. In paragraph 1,
The step of modeling and linearizing the above minimum frequency constraint is:
A step for dividing the power system according to the operating mode of the pumped-storage generator, whose start-up and shutdown are determined by the generator start-up and shutdown plan (Unit Commitment, UC).
A linear inertia constraint modeling method considering frequency stability in a power generation plan including . In Article 4,
The operating mode of the above-mentioned positive-storage generator is:
A linear inertia constraint modeling method considering frequency stability in a power generation plan characterized by including a power generation mode in which a pump-storage generator operates in power generation mode and a non-generation mode in which the pump-storage generator operates in pumping mode or all pump-storage generators are stopped without operating in the power generation mode. In Article 5,
The step of modeling and linearizing the above minimum frequency constraint is:
A step for modeling a linear minimum frequency constraint to determine the minimum frequency with different time constants for each power system classified according to the operation mode of the above-mentioned pump generator.
A linear inertia constraint modeling method considering frequency stability in a power generation plan including . In paragraph 1,
The above average RoCoF constraint and the above minimum frequency constraint are,
A linear inertia constraint modeling method that considers frequency stability in a power generation plan, characterized by being implemented as an analytical expression derived from the RFR model, which is a single-generator frequency response model, and in which the nonlinear inertia constraint through the analytical expression of frequency is linearized by a piecewise linearization method based on the Max-Affine function. In paragraph 1,
The above average RoCoF constraint and the above minimum frequency constraint are,
A linear inertia constraint modeling method that considers frequency stability in a power generation plan, characterized in that the load change degree according to the frequency change can be considered differently for each planning time of the generator start-up and shutdown plan (Unit Commitment, UC) by including a load attenuation coefficient in the linearization variable and the average RoCoF constraint and the minimum frequency constraint. In paragraph 1,
Step of modeling the first steady-state frequency constraint so that the first steady-state frequency does not exceed the critical frequency in each time interval of the generator start-up and shutdown schedule (Unit Commitment, UC).
A linear inertia constraint modeling method considering frequency stability in a development plan that includes more. A step for modeling linear inertia constraint conditions considering the frequency stability of the power system, and
A step for deciding whether to put in a synchronous generator so that the frequency maintenance standard can be met in the event of an expected power system accident through a generator start-up and shutdown plan (Unit Commitment, UC) based on the modeled linear inertia constraint conditions.
A linear inertia constraint modeling method considering frequency stability in a power generation plan including . In Article 10,
The steps for modeling the above linear inertia constraints are:
A linear inertia constraint modeling method that considers frequency stability in a power generation plan, characterized by calculating the average RoCoF and the lowest frequency through linear inertia constraint conditions by equating various types of generators connected to a power system to a single generator. In Article 10,
The above linear inertia constraints are,
Step of modeling the rate of change of frequency (RoCoF) constraint as an average RoCoF constraint that considers the primary frequency response of the synchronous generator and the load change in response to the frequency change of the power system.
A linear inertia constraint modeling method considering frequency stability in a power generation plan including . In Article 12,
The above average RoCoF constraints are,
A linear inertia constraint modeling method that considers frequency stability in a power generation plan, characterized by preventing continuous generation loss in a power system that may be caused by the operation of a frequency change rate relay (RoCoF relay) that operates to protect power generation facilities when RoCoF exceeding a threshold value is continuously measured during a delay time (time delay), and preventing excessive acquisition of system inertia due to instantaneous RoCoF constraints. In Article 10,
The above linear inertia constraints are,
A step that includes a modeled minimum frequency constraint that takes into account the variation in the first-order frequency response capability of the power system.
A linear inertia constraint modeling method considering frequency stability in a power generation plan including . In Article 14,
The above minimum frequency constraint is,
A linear inertia constraint modeling method that considers frequency stability in a power generation plan, characterized by applying constraints differently depending on the operating mode of a pump-storage generator whose start/stop is determined in the power generation plan. In Article 15,
The above minimum frequency constraint is,
A linear inertia constraint modeling method that considers frequency stability in a power generation plan, characterized by restricting the minimum frequency in each planned time section of the generator start-up and shutdown plan (Unit Commitment, UC) so that it does not exceed the minimum standard of the frequency maintenance standard in the event of an assumed accident. In Article 10,
The steps for modeling the above linear inertia constraints are:
A linear inertia constraint modeling method that considers frequency stability in a power generation plan, characterized by reflecting the influence of system load changes on frequency changes under average RoCoF constraints and minimum frequency constraints by considering the load damping factor for frequency as one of the linearization variables.