Power system inertia safety domain evaluation method, device, equipment and medium

Abstract

The invention relates to the technical field of electric power system management, and provides an electric power system inertia safety domain evaluation method, device, equipment and medium, and the method comprises the steps: obtaining each generator speed regulator model parameter of an electric power system, and constructing an electric power system frequency dynamic response model based on each generator speed regulator model parameter; acquiring an active power disturbance quantity after active power disturbance occurs in the power system; on the basis of the active power disturbance quantity and a power system frequency dynamic response model, calculating critical inertia, including a frequency safety critical inertia value and a regulation economy critical inertia value; dividing an inertia operation domain of the power system into a plurality of inertia operation intervals according to the critical inertia; and the current inertia level of the power system is evaluated based on the system real-time inertia and the plurality of inertia operation intervals of the power system. According to the embodiment of the invention, objective quantification and multi-dimensional analysis of the inertia level of the system are realized by constructing a dual evaluation system fusing the frequency safety and the regulation economy.

Description

Technical Field

[0001] This disclosure relates to the field of power system management technology, and more specifically, to a method, apparatus, equipment, and medium for evaluating the inertia safety domain of a power system. Background Technology

[0002] With the transformation of the global energy structure and the large-scale grid connection of new energy sources such as wind power, the proportion of new energy power generation in the energy generation structure continues to rise, and many power systems are gradually evolving into low-inertia power systems. Due to their inherent characteristics, low-inertia power systems have significantly weakened inertia support capabilities and poorer frequency regulation capabilities, which greatly reduces the frequency security of the power system. Insufficient system inertia has a serious impact on the safe operation of the power system. During grid faults, a rapid drop in frequency can trigger low-frequency load shedding protection, causing large-scale power outages on the user side.

[0003] In related technologies, the focus of addressing frequency safety issues caused by inertia decline is mainly on estimating the equivalent inertia of the system and calculating the critical inertia under frequency safety constraints. Some scholars, based on safety constraints such as the initial rate of change of frequency and the maximum frequency deviation, have proposed the concept of an "inertia safety domain." By calculating the critical inertia value for frequency safety and dividing the operating domain into different safety intervals, they have provided a preliminary framework for inertia assessment after disturbances. However, existing methods generally have two limitations: first, the criteria for dividing the safety intervals often rely on empirical settings, lacking objective quantitative basis and exhibiting strong subjectivity; second, their analytical dimensions are relatively singular, focusing only on frequency safety and failing to consider the economic value inherent in inertia resource regulation itself. Summary of the Invention

[0004] This disclosure provides at least one method, apparatus, device, and medium for evaluating the inertia security domain of a power system. By constructing a dual evaluation system that integrates frequency security and control economy, it achieves objective quantification and multi-dimensional analysis of the system inertia level.

[0005] This disclosure provides a method for evaluating the inertia safety domain of a power system, including: Obtain the model parameters of each generator governor in the power system, and construct a frequency dynamic response model of the power system based on the model parameters of each generator governor; After an active power disturbance occurs in the power system, the active power disturbance amount is obtained; and based on the active power disturbance amount and the power system frequency dynamic response model, the critical inertia of the power system is calculated; wherein, the critical inertia includes the frequency safety critical inertia value and the regulation economy critical inertia value. The inertia operating domain of the power system is divided into multiple inertia operating intervals based on the critical inertia; and the current inertia level of the power system is evaluated based on the real-time inertia of the power system and the multiple inertia operating intervals.

[0006] In some possible embodiments, obtaining the model parameters of each generator governor in the power system includes: Input a step-type frequency deviation signal to each generator speed controller and collect output data of mechanical power change corresponding to each generator speed controller; Discrete integration is performed on the output data of the mechanical power change corresponding to each generator speed controller to obtain the ramp response data corresponding to the mechanical power of each generator speed controller. The ramp response data corresponding to the mechanical power of each generator governor are fitted to obtain the model parameters of each generator governor.

[0007] In some possible embodiments, calculating the critical inertia of the power system based on the active power disturbance and the power system frequency dynamic response model includes: Based on the power system frequency dynamic response model, the analytical expressions for the initial rate of change of system frequency and the extreme values ​​of frequency deviation are determined. Based on the analytical expression of the initial rate of change of frequency, the preset maximum rate of change of frequency limit, and the active power disturbance, the first frequency safety critical inertia value is calculated. Based on the analytical expression of the frequency deviation extreme value, the preset frequency deviation extreme value limit, and the active power disturbance, the second frequency safety critical inertia value is calculated. The larger of the first frequency safety critical inertia value and the second frequency safety critical inertia value is determined as the frequency safety critical inertia value.

[0008] In some possible embodiments, calculating the critical inertia of the power system based on the active power disturbance and the power system frequency dynamic response model includes: Based on the analytical expressions for the initial rate of change of frequency and the extreme value of frequency deviation, the marginal benefit of inertia improvement is defined; wherein, the marginal benefit is the amount by which the absolute value of the initial rate of change of frequency and the extreme value of frequency deviation decreases when the real-time inertia of the system increases; Calculate the overall sensitivity of the marginal benefit to the real-time inertia change of the real-time system; and determine at least two critical inertia values ​​for economical control based on the numerical range of the overall sensitivity.

[0009] In some possible embodiments, dividing the inertia operating domain of the power system into multiple inertia operating intervals based on the critical inertia includes: Using the frequency safety critical inertia value as the dividing point, the inertia operating domain is divided into a frequency unsafe region and a frequency safe region; Within the frequency safety region, the frequency safety region is divided into a high-economic-efficiency control region, a medium-economic-efficiency control region, and a low-economic-efficiency control region, using the at least two critical inertia values ​​for control economy as dividing points.

[0010] In some possible embodiments, assessing the current inertia level of the power system based on the real-time inertia of the power system and the plurality of inertia operating ranges includes: Based on the real-time inertia of the power system and the critical inertia value for frequency security, the frequency security evaluation index of the power system is determined. The economic evaluation index for regulation is determined based on the inertia operating range of the system's real-time inertia. The current inertia level of the power system is assessed based on the frequency security evaluation index and the regulation economy evaluation index.

[0011] In some possible embodiments, assessing the current inertia level of the power system based on the frequency security evaluation index and the regulation economy evaluation index includes: Determine whether the frequency of the power system is safe based on the frequency security evaluation indicators; If the frequency of the power system is safe, the power system will be reassessed after a preset time period. If the frequency of the power system is not secure, an inertia control scheme is generated based on the frequency security evaluation index and the control economy evaluation index, and the inertia control scheme is executed to adjust the inertia of the power system. After a preset time period, the power system is re-evaluated.

[0012] This disclosure provides a power system inertia safety domain assessment device, including: The model building module is used to obtain the model parameters of each generator governor in the power system, and to build a frequency dynamic response model of the power system based on the model parameters of each generator governor. The inertia calculation module is used to obtain the active power disturbance after an active power disturbance occurs in the power system; and to calculate the critical inertia of the power system based on the active power disturbance and the frequency dynamic response model of the power system; wherein, the critical inertia includes the frequency safety critical inertia value and the regulation economy critical inertia value. The inertia assessment module is used to divide the inertia operating domain of the power system into multiple inertia operating intervals based on the critical inertia; and to assess the current inertia level of the power system based on the real-time inertia of the power system and the multiple inertia operating intervals.

[0013] In some possible embodiments, the model building module is specifically used for: Input a step-type frequency deviation signal to each generator speed controller and collect output data of mechanical power change corresponding to each generator speed controller; Discrete integration is performed on the output data of the mechanical power change corresponding to each generator speed controller to obtain the ramp response data corresponding to the mechanical power of each generator speed controller. The ramp response data corresponding to the mechanical power of each generator governor are fitted to obtain the model parameters of each generator governor.

[0014] In some possible embodiments, the inertia calculation module is specifically used for: Based on the power system frequency dynamic response model, the analytical expressions for the initial rate of change of system frequency and the extreme values ​​of frequency deviation are determined. Based on the analytical expression of the initial rate of change of frequency, the preset maximum rate of change of frequency limit, and the active power disturbance, the first frequency safety critical inertia value is calculated. Based on the analytical expression of the frequency deviation extreme value, the preset frequency deviation extreme value limit, and the active power disturbance, the second frequency safety critical inertia value is calculated. The larger of the first frequency safety critical inertia value and the second frequency safety critical inertia value is determined as the frequency safety critical inertia value.

[0015] In some possible embodiments, the inertia calculation module is specifically used for: Based on the analytical expressions for the initial rate of change of frequency and the extreme value of frequency deviation, the marginal benefit of inertia improvement is defined; wherein, the marginal benefit is the amount by which the absolute value of the initial rate of change of frequency and the extreme value of frequency deviation decreases when the real-time inertia of the system increases; Calculate the overall sensitivity of the marginal benefit to the real-time inertia change of the real-time system; and determine at least two critical inertia values ​​for economical control based on the numerical range of the overall sensitivity.

[0016] In some possible embodiments, the inertia assessment module is specifically used for: Using the frequency safety critical inertia value as the dividing point, the inertia operating domain is divided into a frequency unsafe region and a frequency safe region; Within the frequency safety region, the frequency safety region is divided into a high-economic-efficiency control region, a medium-economic-efficiency control region, and a low-economic-efficiency control region, using the at least two critical inertia values ​​for control economy as dividing points.

[0017] In some possible embodiments, the inertia assessment module is specifically used for: Based on the real-time inertia of the power system and the critical inertia value for frequency security, the frequency security evaluation index of the power system is determined. The economic evaluation index for regulation is determined based on the inertia operating range of the system's real-time inertia. The current inertia level of the power system is assessed based on the frequency security evaluation index and the regulation economy evaluation index.

[0018] In some possible embodiments, the inertia assessment module is specifically used for: Determine whether the frequency of the power system is safe based on the frequency security evaluation indicators; If the frequency of the power system is safe, the power system will be reassessed after a preset time period. If the frequency of the power system is not secure, an inertia control scheme is generated based on the frequency security evaluation index and the control economy evaluation index, and the inertia control scheme is executed to adjust the inertia of the power system. After a preset time period, the power system is re-evaluated.

[0019] This disclosure provides a computer device including a processor, a memory, and a bus. The memory stores machine-readable instructions executable by the processor. When the computer device is running, the processor communicates with the memory via the bus. When the machine-readable instructions are executed by the processor, they perform the power system inertia safety domain assessment method as described in any of the above possible embodiments.

[0020] This disclosure provides a computer-readable storage medium storing a computer program that, when executed by a processor, implements the power system inertia safety domain assessment method as described in any of the possible embodiments above.

[0021] The power system inertia safety domain assessment method, device, equipment, and medium provided in this disclosure can accurately obtain key parameters reflecting system frequency safety and control economy by constructing a power system frequency dynamic response model and calculating critical inertia in combination with active power disturbance. Furthermore, by comprehensively dividing the inertia operating range by combining the critical inertia value for frequency safety and the critical inertia value for control economy, and assessing the current inertia level based on the real-time inertia of the system, the state of power system inertia can be comprehensively and accurately determined, effectively balancing system frequency safety and control economy, and ensuring the stable operation and scientific control of the power system.

[0022] To make the above-mentioned objects, features and advantages of this disclosure more apparent and understandable, preferred embodiments are described below in detail with reference to the accompanying drawings. Attached Figure Description

[0023] To more clearly illustrate the technical solutions of the embodiments of this disclosure, the accompanying drawings referenced in the embodiments will be briefly described below. These drawings are incorporated in and constitute a part of this specification. They illustrate embodiments conforming to this disclosure and, together with the specification, serve to explain the technical solutions of this disclosure. It should be understood that the following drawings only show some embodiments of this disclosure and should not be considered as limiting the scope. Those skilled in the art can obtain other related drawings based on these drawings without creative effort.

[0024] Figure 1 A flowchart of a power system inertia safety domain assessment method provided by an embodiment of this disclosure is shown; Figure 2 A flowchart of a method for obtaining generator speed governor model parameters provided in an embodiment of this disclosure is shown; Figure 3 A flowchart of a method for calculating the critical inertia value for frequency safety provided in an embodiment of this disclosure is shown; Figure 4 A flowchart of a method for calculating the critical inertia value for economical regulation provided in an embodiment of this disclosure is shown; Figure 5 A flowchart of a method for assessing the current inertia level of a power system provided by an embodiment of this disclosure is shown; Figure 6 A schematic diagram of the structure of a power system inertia safety domain evaluation device provided in an embodiment of this disclosure is shown. Figure 7 A schematic diagram of the structure of a computer device provided in an embodiment of this disclosure is shown. Detailed Implementation

[0025] To make the objectives, technical solutions, and advantages of the embodiments of this disclosure clearer, the technical solutions of the embodiments of this disclosure will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only a part of the embodiments of this disclosure, and not all of them. The components of the embodiments of this disclosure described and shown in the accompanying drawings can generally be arranged and designed in various different configurations. Therefore, the following detailed description of the embodiments of this disclosure provided in the accompanying drawings is not intended to limit the scope of the claimed disclosure, but merely represents selected embodiments of this disclosure. All other embodiments obtained by those skilled in the art based on the embodiments of this disclosure without inventive effort are within the scope of protection of this disclosure.

[0026] It should be noted that similar labels and letters in the following figures indicate similar items. Therefore, once an item is defined in one figure, it does not need to be further defined and explained in subsequent figures.

[0027] In this document, the term "and / or" merely describes a relationship, indicating that three relationships can exist. For example, A and / or B can represent three cases: A alone, A and B simultaneously, and B alone. Furthermore, the term "at least one" in this document means any combination of at least two of any one or more elements. For example, including at least one of A, B, and C can mean including any one or more elements selected from the set consisting of A, B, and C.

[0028] To facilitate understanding of this embodiment, the executing entity of the power system inertia safety domain assessment method provided in this disclosure will first be described in detail. The executing entity of the power system inertia safety domain assessment method provided in this disclosure is a computer device. This computer device can be a terminal device or a server. The terminal device can also be a mobile device, user terminal, terminal, handheld device, computing device, vehicle-mounted device, wearable device, etc. The server can be an independent physical server, a server cluster or distributed system composed of multiple physical servers, or a cloud server providing basic cloud computing services such as cloud services, cloud databases, cloud computing, cloud storage, big data, and artificial intelligence platforms. Optionally, this method can also be applied to an implementation environment composed of computer devices and servers.

[0029] The method for evaluating the inertia safety domain of a power system provided in this application will be described in detail below with reference to the accompanying drawings. See also Figure 1 The diagram shows a flowchart of a power system inertia safety domain assessment method provided in this embodiment of the present disclosure. The method includes the following steps S101 to S103: S101, obtain the model parameters of each generator speed governor in the power system, and construct the frequency dynamic response model of the power system based on the model parameters of each generator speed governor.

[0030] Understandably, generator speed governors are devices that maintain the stability of the power system frequency. Their main function is to dynamically adjust the generator's output power based on real-time changes in the power system frequency, ensuring that the system frequency remains near its rated value. When the power system load fluctuates, such as a sharp increase in electricity demand during peak industrial production periods or a decrease in load due to reduced residential electricity consumption at night, the system frequency will deviate from its rated value. At this time, the generator speed governor senses the frequency deviation signal and adjusts the generator's mechanical power input, for example, by changing the coal feed rate of a coal-fired generator or the water flow rate of a hydroelectric generator, thereby adjusting the generator's electrical power output and gradually restoring the system frequency to stability.

[0031] Here, the generator speed governor model parameters quantitatively describe the dynamic regulation characteristics of the speed governor, and may include the generator's effective inertia, damping, and regulation coefficient. The generator's effective inertia reflects the generator rotor's energy storage capacity, and its value is determined by physical characteristics such as rotor mass and rotation radius. Taking a large hydro-generator as an example, its rotor mass is large, its rotation radius is long, and its effective inertia is high. When the system frequency changes, the rotor speed changes relatively smoothly, providing ample time for the speed governor to adjust, which helps maintain system frequency stability. The damping parameter measures the speed governor's ability to suppress system oscillations. After the power system is disturbed, frequency oscillations may occur, and the magnitude of the damping parameter directly affects the decay rate of the oscillations. If the damping parameter is too small, system oscillations will last for a long time, causing the frequency to deviate from the rated value for an extended period, threatening the stable operation of the system; while a suitable damping parameter can effectively suppress oscillations, allowing the system frequency to quickly recover to stability. The regulation coefficient reflects the speed governor's response sensitivity to frequency deviations, determining the amplitude and speed at which the speed governor adjusts the generator's output power when a frequency deviation is detected. The larger the adjustment coefficient, the faster the speed controller responds to frequency deviations, the greater the adjustment force, and the more timely it can correct frequency deviations.

[0032] For example, when obtaining the parameters of each generator governor model, a parameter identification method can be used, referring to... Figure 2 As shown, when obtaining the model parameters of each generator speed governor in the power system, the following steps S201~S203 may be included: S201 inputs a step-type frequency deviation signal to each generator speed controller and collects the output data of the mechanical power change corresponding to each generator speed controller.

[0033] Understandably, step signals are abrupt and can simulate the rapid frequency changes in a power system when subjected to sudden disturbances. By precisely controlling the amplitude and duration of the input signal, the response characteristics of the speed governor under different frequency deviations can be obtained. Simultaneously, output data on the mechanical power change corresponding to each generator speed governor are collected. These data reflect how the speed governor adjusts the generator's mechanical power input after receiving the frequency deviation signal.

[0034] S202, the output data of the mechanical power change corresponding to each generator speed governor are discretely integrated to obtain the ramp response data corresponding to the mechanical power of each generator speed governor.

[0035] Specifically, discrete integration can convert discrete mechanical power change data into continuous ramp response data, which can more intuitively reflect the dynamic adjustment process of the governor under the action of a step signal. Through discrete integration processing, noise and interference in the data can be eliminated, improving the accuracy and reliability of the data.

[0036] S203, respectively, fit the ramp response data corresponding to the mechanical power of each generator speed governor to obtain the model parameters of each generator speed governor.

[0037] Here, by employing appropriate fitting algorithms, such as the least squares method, to fit the ramp response data, the transfer function or state-space model of the speed governor can be obtained. From this, model parameters for each generator speed governor, such as effective inertia, damping, and regulation coefficients, can be extracted. These parameters will provide accurate basic data for constructing a power system frequency dynamic response model, ensuring that the model can accurately simulate the frequency dynamic response characteristics of the power system.

[0038] In some possible embodiments, to improve the speed of online analysis, a second-order linear polynomial function can be used to fit the ramp response data corresponding to the mechanical power of each generator governor, i.e.: ; in, It is represented as the unified structural transfer function of the governor response during the active frequency support process of the i-th generator. Mathematically, it can also be regarded as a quadratic polynomial function fitting function for the transient active ramp response of the generator. Let the effective inertia of generator i be denoted as ; This is represented by the damping of the i-th generator; It is represented as the regulation coefficient of the i-th generator.

[0039] Specifically, after obtaining the model parameters of each generator speed governor, a dynamic frequency response model of the power system can be constructed based on these parameters. By comprehensively considering factors such as the regulation characteristics of the generator speed governor, the dynamic behavior of the generator, the network topology of the power system, and the dynamic characteristics of the load, numerical analysis methods and circuit theory are used to accurately quantify and describe the interaction between these factors. This allows for accurate simulation of the dynamic evolution of the system frequency over time when the power system is subjected to various disturbances (such as sudden increases or decreases in active power, changes in reactive power, etc.). For example, during the model construction process, the impact of transmission line impedance on power transmission and frequency distribution, as well as the response characteristics of different types of loads (such as asynchronous motor loads, constant impedance loads, etc.) to frequency changes, can be considered.

[0040] Here, the power system frequency dynamic response model includes dynamic adjustment models corresponding to each generator speed governor, which can simulate the response actions and adjustment patterns of different speed governors when facing frequency fluctuations. Each generator speed governor, due to its own design and parameter settings, has different adjustment methods when responding to frequency changes. By constructing corresponding dynamic adjustment models, it is possible to simulate in detail how each speed governor changes the mechanical power input of the generator according to a predetermined adjustment strategy based on the frequency deviation signal, thereby affecting the generator's electrical power output, and realistically reproducing the actual behavior of the speed governor during the power system frequency regulation process.

[0041] In some possible embodiments, to improve the speed of online analysis, a second-order linear polynomial function can be used to fit the ramp response data corresponding to the mechanical power of each generator governor, i.e.: ; in, It is represented as the unified structural transfer function of the governor response during the active frequency support process of the i-th generator. Mathematically, it can also be regarded as a quadratic polynomial function fitting function for the transient active ramp response of the generator. Let the effective inertia of generator i be denoted as ; This is represented by the damping of the i-th generator; It is represented as the regulation coefficient of the i-th generator.

[0042] Furthermore, after obtaining the model parameters of each generator governor (i.e., the parameters in the fitting function mentioned above)... , , (e.g., parameters), and the fitted function can be completed using the above-mentioned generator speed governors. As a dynamic adjustment model corresponding to each generator speed governor, this model can describe the dynamic adjustment characteristics of each speed governor when facing frequency fluctuations.

[0043] In some possible embodiments, the power system frequency dynamic response model may also include a generator rotor motion model that reflects the dynamic motion process of the generator rotor under the combined action of electromagnetic torque and mechanical torque, and a network power flow model that describes the transmission and distribution of power in the power system on equipment such as transmission lines and transformers, without being specifically limited here.

[0044] S102, after an active power disturbance occurs in the power system, the active power disturbance amount is obtained; and based on the active power disturbance amount and the frequency dynamic response model of the power system, the critical inertia of the power system is calculated.

[0045] Here, active power disturbance refers to a sudden change in active power in the power system caused by various reasons, which disrupts the original active power balance of the power system and causes disturbance to the active power of the power system. This change may be an increase or a decrease. For example, a large industrial load suddenly being connected to a region, or a generator unit of a power plant going out of operation due to a fault, will cause disturbance to the active power of the power system.

[0046] Specifically, after obtaining the active power disturbance, the critical inertia of the power system can be calculated based on this disturbance and the previously constructed power system frequency dynamic response model. Critical inertia is a key indicator measuring the power system's ability to maintain frequency stability in the face of active power disturbances. It is used to assess the minimum inertia level required by the power system under different operating scenarios to ensure the safe, stable, and economically efficient operation of the system. It can include the frequency safety critical inertia value and the regulation economy critical inertia value.

[0047] The frequency safety critical inertia value refers to the minimum inertia value that a power system must possess to ensure that its frequency remains within a specified safe range (for example, the allowable deviation range for power system frequency in some regions is typically ±0.2Hz). Here, the inertia of a power system is the kinetic energy stored in rotating components such as generator rotors. When the system is subjected to active power disturbances, the inertia can release or absorb energy, slowing down the rate of frequency change. If the power system's inertia is below this value, the frequency may exceed the safe range when subjected to active power disturbances. Excessive frequency changes may cause mechanical damage to power equipment, affecting its normal operation and lifespan, and also severely impacting the quality of electricity supply to users, causing some frequency-sensitive equipment to malfunction. The economical critical inertia value, on the other hand, is the inertia value corresponding to the lowest operating cost of the power system while meeting certain frequency regulation requirements, from an economic operation perspective. For example, in some cases, maintaining frequency stability may require additional spinning reserve capacity, which increases operating costs. The economical critical inertia value is a reasonable inertia value determined after balancing frequency regulation and operating costs.

[0048] For example, refer to Figure 3 As shown, the calculation of the frequency safety critical inertia value may include the following steps S301~S304: S301, Based on the power system frequency dynamic response model, determine the analytical expression for the initial rate of change of system frequency and the analytical expression for the extreme value of frequency deviation.

[0049] Understandably, the dynamic frequency response model of a power system comprehensively considers various parameters and operating characteristics of the power system. Through analysis and derivation of this model, the mathematical relationship between the initial rate of change of system frequency and parameters such as active power disturbance and system inertia can be obtained, i.e., the analytical expression for the initial rate of change of system frequency. Similarly, analytical expressions between the extreme values ​​of frequency deviation and these parameters can also be obtained. These analytical expressions provide a theoretical basis for subsequent calculations.

[0050] Here, the time-domain expression for the frequency deviation of the center of inertia of the parabola approximation is: ; in, The time-domain expression for the deviation of the center frequency of inertia, expressed as a parabolic approximation (in the Laplace domain), describes the deviation of the center frequency of inertia from the rated frequency in a power system. This is represented as the total power deficit suffered by the power system; Represented as the overall inertia of the power system; This represents the time it takes for the center frequency deviation of the inertia to reach its extreme value after an active disturbance occurs.

[0051] Here, the mechanical power output in the frequency domain can be expressed as: ; in, It represents the mechanical power output in the frequency domain, indicating the variation of mechanical power in the power system in the Laplace domain, which is related to parameters such as the system's frequency deviation and overall inertia; This is expressed as the change in power at the initial moment; It is represented as the transfer function of the power system (global dependence); it describes the dynamic relationship between inputs (such as power disturbances) and outputs (such as frequency deviations, mechanical power changes) in the power system.

[0052] When the inertia center frequency deviation reaches its extreme value, the change in total mechanical power equals the system's transient active power deficit, that is: ; in, It represents the change in total mechanical power when the frequency deviation of the inertia center reaches its extreme value, reflecting the adjustment of mechanical power in the system when the frequency deviation reaches its maximum. Expressed as the damping coefficient of the power system; These are represented as the model parameters of the i-th generator speed governor; It is represented as the overall gain coefficient of the power system.

[0053] Furthermore, we can obtain a statement about The quadratic equation in one variable can be used to determine the time it takes for the extreme value of the inertia center frequency deviation to arrive, according to the quadratic formula. Furthermore, the extreme values ​​of the inertia center frequency deviation can be obtained. : .

[0054] Meanwhile, assuming the total active power disturbance of the system approximates a step response, the initial rate of change of the inertia center frequency is the maximum rate of change of frequency during the process from the moment the disturbance occurs until the frequency reaches its extreme value. The initial rate of change of frequency at the moment the active power disturbance occurs can be obtained by differentiating the frequency. : .

[0055] S302, based on the analytical expression of the initial frequency change rate, the preset maximum frequency change rate limit, and the active power disturbance, the first frequency safety critical inertia value is calculated.

[0056] Understandably, the preset maximum frequency change rate limit is determined based on the safe operation requirements of the power system and the tolerance of the equipment. For example, different key equipment in a power system, such as generators, have varying degrees of sensitivity to frequency changes. Excessive frequency changes can increase the mechanical stress on the generator rotor, and prolonged exposure to this condition will accelerate fatigue damage to rotor components and shorten the equipment's lifespan. Therefore, the maximum frequency change rate limit can be set by comprehensively considering the physical characteristics of the equipment, manufacturing standards, and the overall stability requirements of the power system.

[0057] Specifically, during the calculation process, the first frequency safety critical inertia value that satisfies the maximum frequency change rate limit can be obtained based on the analytical expression of the initial frequency change rate, the maximum frequency change rate limit, and the active power disturbance. This value represents the minimum inertia required by the power system to ensure that the initial frequency change does not exceed the safe range under the current active power disturbance and maximum frequency change rate limit.

[0058] Here, the first frequency safety critical inertia value based on RoCoF constraints can be defined as: ; in, Represented as the first frequency safety critical inertia value based on RoCoF constraints; This is expressed as the maximum rate of change limit of frequency.

[0059] S303, based on the analytical expression of the frequency deviation extreme value, the preset frequency deviation extreme value limit, and the active power disturbance, the second frequency safety critical inertia value is calculated.

[0060] Understandably, the frequency deviation extreme limit is also set based on the power system's safe operation standards and user requirements. When the frequency deviation exceeds a certain range, it will affect the user's power quality, and some frequency-sensitive industrial equipment may fail to operate normally, leading to production interruptions or a decline in product quality. Simultaneously, excessive frequency deviation may also trigger the power system's protection devices, causing unnecessary power outages. Using the analytical expression for the frequency deviation extreme value, combined with the preset frequency deviation extreme limit and active power disturbance, a second frequency safety critical inertia value that satisfies the frequency deviation extreme limit can be derived. This value reflects the minimum inertia level required for the power system to maintain frequency stability, considering the frequency deviation extreme value.

[0061] Here, based on the frequency offset extrema The second frequency safety critical inertia value of the constraint can be defined as: ; in, Represented as frequency offset extrema The second frequency safety critical inertia value under constraint; This is expressed as the extreme limit of frequency deviation.

[0062] S304, the larger of the first frequency safety critical inertia value and the second frequency safety critical inertia value is determined as the frequency safety critical inertia value.

[0063] Specifically, since the initial rate of change of frequency and the extreme value of frequency deviation are both key factors affecting the frequency security of the power system, in order to ensure that the frequency of the power system meets both the initial rate of change limit and the extreme value of deviation limit when subjected to active power disturbances, the larger of the first and second critical inertia values ​​for frequency security can be taken as the final critical inertia value for frequency security. Its expression can be represented as: .

[0064] This provides more stringent safety guarantees, ensuring that the power system can maintain its frequency within a safe range when faced with various possible power disturbances, avoiding equipment damage, power outages, and other problems caused by frequency anomalies, and achieving safe and stable operation of the power system.

[0065] Understandably, in the operation of a power system, it is necessary not only to ensure the safety and stability of the frequency but also to consider economic efficiency. To determine the inertia value corresponding to the lowest operating cost of the power system while meeting certain frequency regulation requirements, the calculation of the critical inertia value for economical regulation can refer to... Figure 4 As shown, the process includes the following steps S401~S402: S401, based on the analytical expression of the initial rate of change of frequency and the extreme value of frequency deviation, define the marginal benefit of inertia improvement.

[0066] Understandably, when considering the economics of inertia control, the complex market mechanisms involved in inertia cost and pricing hinder rapid analysis after disturbances. Therefore, this disclosure simplifies the analysis from the perspective of frequency benefits brought by increasing inertia and proposes marginal benefit as an indicator to quantify economics. The economic value of inertia is mainly reflected in frequency recovery after disturbances; increasing system inertia can improve frequency stability and ensure the safe and stable operation of the power system. Based on this, the reduction in the absolute value of characteristic frequency after increasing inertia is defined as frequency gain, which can be used as a mapping of economic benefits. Economics can be reflected by calculating the marginal benefit after increasing inertia.

[0067] Specifically, marginal benefit refers to the reduction in the absolute value of the initial rate of change of frequency and the extreme value of frequency deviation when the real-time inertia of the system increases. By defining marginal benefit, the degree to which the increase in inertia improves the frequency regulation effect can be quantified. From a physical perspective, when the system inertia increases, the system stores more kinetic energy in the face of active power disturbances, which can better buffer the impact of power changes, thereby slowing down the initial rate of change of frequency and reducing the absolute value of the initial rate of change of frequency. At the same time, the increase in inertia also helps to suppress the amplitude of frequency fluctuations and reduce the absolute value of the extreme value of frequency deviation.

[0068] Here, marginal benefit can be expressed by the following formula: .

[0069] S402, calculate the comprehensive sensitivity of the marginal benefit to the real-time inertia change of the real-time system; and determine at least two critical inertia values ​​for economical regulation based on the numerical range of the comprehensive sensitivity.

[0070] Understandably, during the calculation process, the influence of various factors on sensitivity can be considered, such as the system's load characteristics, the type and parameters of the power generation equipment, etc. Different load characteristics respond differently to frequency changes, and some frequency-sensitive loads may make the sensitivity calculation more complex; and the cost and effectiveness of inertia adjustment also vary among different types of power generation equipment.

[0071] Furthermore, since the numerical range of the overall sensitivity may exhibit different characteristics, the relationship between the marginal benefit of inertia improvement and operating costs may change within different numerical intervals. Therefore, based on the calculated numerical range of the overall sensitivity, at least two critical inertia values ​​for economical regulation can be determined. For example, when the overall sensitivity is high, it means that increasing the inertia by a small amount can significantly improve the frequency regulation effect, which may correspond to a lower critical inertia value for economical regulation; while when the overall sensitivity is low, a larger amount of inertia is needed to achieve a certain frequency regulation effect, which corresponds to a higher critical inertia value for economical regulation.

[0072] In this disclosure, the inertia values ​​at comprehensive sensitivities of 0.1 and 0.01 are taken as the critical values ​​for the overall economic efficiency of system control, that is: ; in, , It can be expressed as the critical inertia value for economic regulation that divides the overall sensitivity with respect to changes in inertia into three stages: high, medium, and low.

[0073] In some other embodiments, the inertia values ​​corresponding to comprehensive sensitivity of 0.05 and 0.005 can also be taken as the critical inertia values ​​for control economy under different division methods, without specific limitations. Different comprehensive sensitivity values ​​can be selected according to the specific operating characteristics of the power system, load characteristics, and different requirements for economy and frequency stability, so as to meet diverse analysis and control needs.

[0074] In this way, by determining multiple critical inertia values ​​for economic regulation, the economic efficiency under different inertia levels can be more comprehensively evaluated, providing more choices and basis for power system operation decisions, thereby achieving optimal control of operating costs while ensuring frequency stability.

[0075] S103, the inertia operating domain of the power system is divided into multiple inertia operating intervals according to the critical inertia; and the current inertia level of the power system is evaluated based on the real-time inertia of the power system and the multiple inertia operating intervals.

[0076] Specifically, after obtaining the critical inertia of the power system, the inertia operating domain of the power system can be divided into multiple inertia operating intervals based on the frequency safety critical inertia value and at least two regulation economic critical inertia values. The frequency safety critical inertia value is the minimum inertia value necessary to ensure that the power system frequency remains within a specified safe range, while the regulation economic critical inertia value is the inertia value that minimizes operating costs while meeting frequency regulation requirements. Based on these critical inertia values, the power system inertia operating domain can be divided into multiple intervals, each interval corresponding to a specific operating state and characteristic of the power system.

[0077] For example, in order to comprehensively evaluate the performance of power system inertia level in two important dimensions of frequency security and economy, the division of inertia operating domain can follow the following steps (1)~(2): (1) Using the frequency safety critical inertia value as the dividing point, the inertia operating domain is divided into a frequency unsafe region and a frequency safe region; (2) Within the frequency safety region, the frequency safety region is divided into a high-economic control region, a medium-economic control region, and a low-economic control region, using the at least two critical inertia values ​​of control economy as dividing points.

[0078] Specifically, the critical inertia value for frequency safety is determined based on the requirements for safe operation of the power system and the tolerance of the equipment. When the system inertia is lower than this value, it will be affected by active power disturbances, and the frequency may exceed the safe range, causing damage to power equipment and users. Therefore, the area below this value can be defined as the frequency unsafe area; the area above this value is the frequency safe area, thereby clarifying the state of the power system in terms of frequency safety.

[0079] Furthermore, the critical inertia value for economic efficiency in regulation is determined by comprehensively considering frequency regulation needs and operating costs. Different critical inertia values ​​correspond to different levels of economic efficiency. Therefore, this can be used as a dividing point to refine the economic assessment within the frequency safety zone. The high economic efficiency regulation zone indicates that at this inertia level, the power system meets frequency regulation requirements and operating costs are relatively low, with reasonable resource allocation. The medium economic efficiency regulation zone represents a moderate level of economic efficiency. The low economic efficiency regulation zone suggests that there may be high operating costs or unreasonable resource allocation, requiring optimization and adjustment, thus providing a precise basis for power system economic operation decisions.

[0080] Here, the inertial operating domain of the power system can be divided into the following four regions: .

[0081] In some other embodiments, in order to more precisely assess the power system inertia level, a greater number of controllability critical inertia values ​​can be set, and then the frequency safety zone can be more finely divided based on these new critical inertia values, without being specifically limited here.

[0082] Specifically, based on the real-time inertia of the power system and the multiple inertia operating ranges defined above, the current inertia level of the power system can be assessed. Real-time inertia is the actual inertia value possessed by the power system at a specific moment, directly reflecting its ability to withstand frequency changes in real time. By comparing the real-time inertia with the ranges of each inertia operating range, the current state of the power system's inertia level can be accurately determined. Different ranges correspond to different operational risks and states, providing crucial information for power system operation monitoring and decision-making. For example, if the real-time inertia is in a low inertia range and close to the frequency safety critical inertia value, then corresponding measures need to be taken, such as increasing generator output or activating energy storage devices, to improve the power system's inertia and ensure frequency stability and safe system operation.

[0083] Here, refer to Figure 5 As shown, to ensure the accuracy and usability of the assessment results when evaluating the current inertia level of the power system, the following steps S501~S503 may be included: S501, Based on the real-time inertia of the power system and the frequency security critical inertia value, determine the frequency security evaluation index of the power system.

[0084] Understandably, frequency security is one of the core elements ensuring stable operation of a power system. The system's real-time inertia, a key parameter reflecting its ability to withstand frequency disturbances, directly determines the amplitude and recovery speed of frequency fluctuations. When the system's real-time inertia is large, it can buffer frequency disturbances caused by sudden changes in active power (such as generator failure or heavy load), resulting in relatively small frequency fluctuations and a faster recovery to near the rated frequency. Conversely, if the system's real-time inertia is small, the same frequency disturbance may cause larger frequency fluctuations, longer recovery times, and even frequency instability, thus affecting the safe operation of the entire power system.

[0085] Here, by calculating the real-time inertia of the power system and the frequency safety critical inertia value, the frequency safety evaluation index of the power system can be determined. The ratio method can be used to calculate the difference between the real-time system inertia and the frequency safety critical inertia value, and the ratio of the two values. By setting a reasonable frequency safety quantification threshold, the degree of system frequency safety can be further quantified and evaluated.

[0086] Specifically, the frequency security index can be calculated based on the real-time inertia and frequency security critical inertia value of the power system using the following formula: ; Among them, the sign of the frequency security evaluation index reflects whether the system's inertia level is sufficient to cope with the current disturbance and maintain the system's frequency security. When A positive value indicates that the system inertia is higher than the frequency safety inertia threshold, meaning the system frequency can remain safe in the face of the current disturbance. The magnitude represents the frequency safety margin corresponding to the system inertia; when A negative value indicates that the system inertia is below the frequency safety inertia threshold, and the system frequency is at risk of being unsafe. The magnitude indicates the severity; in such cases, efforts must be made to increase the overall inertia level to ensure frequency safety.

[0087] Furthermore, multiple threshold ranges with different levels can be set. For example, when the calculated ratio is greater than 0.2, the system frequency safety level can be classified as "high safety level," indicating that the system's real-time inertia is much higher than the frequency safety critical inertia value, the system has strong resistance to frequency disturbances, the frequency can remain stable within a safe range, and the risk of frequency instability is extremely low. When the ratio is between 0 and 0.2, it is classified as "medium safety level," meaning that the system's real-time inertia is slightly higher than the frequency safety critical inertia value. Although it can ensure the basic safety of the system frequency, there may still be a certain risk of frequency fluctuation when facing large-scale frequency disturbances, requiring close monitoring of the system. Operating status: When the ratio is between -0.1 and 0, it is classified as "low safety level," indicating that the system's real-time inertia is close to the frequency safety critical inertia value, and the system's frequency safety margin is small. Corresponding preventative measures need to be taken during operation, such as adjusting power generation output in advance and optimizing system operation modes, to prevent frequency instability. When the ratio is less than -0.1, it is classified as "dangerous level," at which point the system's real-time inertia is below the frequency safety critical inertia value, and the system frequency faces a significant risk of instability. Immediate emergency control measures must be taken, such as quickly starting backup power and disconnecting some non-critical loads, to ensure system frequency safety. By setting reasonable quantitative thresholds for frequency safety, a clear and explicit basis for frequency safety assessment can be provided for power system operation and dispatch, helping to take timely and effective measures to maintain the stable operation of the power system.

[0088] In some other embodiments, the difference method can also be used to calculate the difference between the system's real-time inertia and the frequency safety critical inertia value. The sign and magnitude of this difference can intuitively reflect the current inertia level of the system relative to the frequency safety requirements. If the difference is positive and large, it indicates that the system's real-time inertia is sufficient, and the frequency can be well maintained within the safe range when facing active power disturbances, with a high system frequency safety margin. Conversely, if the difference is negative or small, it indicates that the system's real-time inertia is insufficient, the risk of frequency instability is high, and corresponding measures need to be taken to increase the system inertia.

[0089] S502, determine the economic evaluation index of regulation based on the inertia operation range of the real-time inertia of the system.

[0090] Specifically, the operation of a power system must consider not only frequency security but also economic efficiency. The real-time inertia of the system changes with its operating state, and different inertia operating ranges correspond to different control strategies and economic costs. Here, based on the inertia operating range in which the system's real-time inertia is located, and by comprehensively considering factors such as power generation costs, equipment losses, and energy utilization efficiency, the economic evaluation indicators for control can be determined.

[0091] For example, the system's real-time inertia can be... With the control of economic boundary value The relative size is defined as an indicator for evaluating the economic efficiency of regulation. Its calculation expression is as follows: ; in, The economic efficiency of current system inertia regulation can be quantitatively assessed, including frequency insecurity zones and high-efficiency regulation zones. Defined as 100%, at the current inertia level, the frequency benefit (economic benefit) generated by increasing inertia is very high; while when the inertia is in the low-economic control zone... Defined as 0, the change in the characteristic value of the inertia frequency is not significant and produces almost no economic benefit; the medium-economic control zone is processed by linear normalization, and this region is... The data is uniformly mapped to the 0-100% range, where the smaller the inertia, the higher the economic efficiency of regulation.

[0092] In some other embodiments, cost-benefit analysis can be used to determine the economic evaluation indicators for power system regulation. This involves calculating the unit frequency adjustment cost under different inertia operating ranges, i.e., the cost required to adjust a certain frequency. This indicator can intuitively reflect the economic cost of maintaining frequency stability under different inertia levels. Equipment loss rates can also be calculated to assess equipment losses under different inertia operating ranges, as well as energy utilization rates to measure the system's effective use of energy. These economic evaluation indicators for power system regulation can accurately quantify the economic costs required for regulation under different inertia levels, providing data support for formulating economically reasonable regulation schemes.

[0093] S503, based on the frequency security evaluation index and the regulation economy evaluation index, assess the current inertia level of the power system.

[0094] Understandably, after determining the frequency security evaluation indicators and the regulation economy evaluation indicators respectively, these two important dimensions of indicators can be integrated to conduct a comprehensive and in-depth assessment of the current inertia level of the power system.

[0095] In some possible implementations, multi-objective decision analysis methods, such as the Analytic Hierarchy Process (AHP) and fuzzy comprehensive evaluation, can be employed to assign weights and perform comprehensive calculations on frequency security evaluation indicators and regulation economic evaluation indicators. The AHP decomposes complex problems into multiple levels by constructing a hierarchical model, determining the relative importance weights of each indicator. The fuzzy comprehensive evaluation method utilizes fuzzy mathematics theory to quantify fuzzy indicators, comprehensively considering the influence of various factors. Through these methods, comprehensive scores can be calculated at different inertia levels, and the rationality of the current inertia level of the power system can be judged based on the comprehensive score.

[0096] A high overall score indicates that the current inertia level performs well in terms of both frequency security and economy, and the system is operating ideally. Conversely, a low overall score indicates deficiencies in either frequency security or economy, requiring appropriate control measures. For instance, if the frequency security evaluation index shows insufficient system frequency security margin, while the control economy evaluation index shows high operating costs, then a comprehensive approach can be taken, including increasing system inertia while optimizing the operation of power generation equipment and selecting lower-cost frequency regulation methods. This will optimize the power system's inertia level and ensure safe, economical, and stable system operation.

[0097] Specifically, assessing the current inertia level of the power system and deciding whether to take control measures may include the following steps (a) to (c): (a) Determine whether the frequency of the power system is safe based on the frequency security evaluation index; (b) If the frequency of the power system is safe, the power system shall be reassessed after a preset time period; (c) If the frequency of the power system is not safe, an inertia control scheme is generated based on the frequency safety evaluation index and the control economy evaluation index, and the inertia control scheme is executed to adjust the inertia of the power system. The power system is then re-evaluated after a preset time period.

[0098] Here, the frequency security evaluation index is a parameter calculated based on the real-time inertia of the power system and the critical inertia value for frequency security. It can intuitively and accurately reflect the current security status of the system frequency. Taking the index calculated using the ratio method as an example, when judging whether the power system frequency is safe, different ratio ranges correspond to different security levels: when the ratio is greater than 0.2, the system is at a "high security level," with real-time inertia far exceeding the critical inertia value, strong resistance to disturbances, and stable frequency, thus it can be judged as safe; when the ratio is between 0 and 0.2, it is at a "medium security level," with real-time inertia slightly higher than the critical value, basically ensuring frequency security, but there is a risk of fluctuation in the face of large disturbances. Judgment needs to be based on real-time operating data and historical experience. When load fluctuations are small and there are no potential risks, it is relatively safe. If the ratio is within the acceptable range, close monitoring is required; if the ratio is between -0.1 and 0, it indicates a "low safety level," meaning the real-time inertia is close to the critical value, the safety margin is small, and there is a high risk of instability. It is generally considered unsafe, but the actual judgment should consider the operating conditions and load forecast. If the load is stable and the future increase is not large, the observation period can be extended and preventive measures can be taken. If the load is high and the future increase is large, the inertia needs to be increased immediately; if the ratio is less than -0.1, the system is in a "dangerous level," meaning the real-time inertia is below the critical value, the risk of instability is high, and it must be immediately determined to be unsafe and emergency control measures must be taken quickly.

[0099] In some possible implementations, in addition to the frequency security evaluation index obtained by the ratio method, other relevant frequency monitoring data can be combined for comprehensive judgment. For example, the frequency deviation of the system can be monitored in real time, that is, the difference between the actual system frequency and the rated frequency (usually 50Hz or 60Hz). If the frequency deviation continues to exceed a certain threshold (e.g., ±0.2Hz) and there is no obvious convergence trend, then even if the frequency security evaluation index does not reach the "danger level", the system frequency can be judged to be unsafe. In addition, the rate of change of the system frequency can be observed, that is, the speed at which the frequency changes over time. If the rate of change of the frequency is too large, it indicates that the system is subjected to severe frequency disturbances, and the system frequency may face the risk of instability, requiring comprehensive judgment in conjunction with the frequency security evaluation index.

[0100] In some other embodiments, frequency security assessment can also consider the system's network structure and operating mode. Different network structures and operating modes have different impacts on system frequency. For example, in a ring network power system, due to the existence of multiple loops, the distribution of system inertia is more complex, and the propagation and impact of frequency disturbances differ from those in a radial network. When assessing whether the system frequency is secure, it is also necessary to fully consider the characteristics of the network structure, analyze the propagation of frequency disturbances in different loops, and the mutual influence between loops. Simultaneously, the system's operating mode also affects frequency security assessment. For example, in a power system employing distributed generation, the output fluctuations of distributed power sources are significant, and their impact on system inertia is also complex. When assessing whether the system frequency is secure, the output and operating status of distributed power sources, as well as their coordination and control with the main grid, can be comprehensively considered.

[0101] Furthermore, determining that the power system's frequency is in a safe state does not mean that the current operating state can be maintained indefinitely without any adjustments. This is because the operating conditions of the power system are constantly changing; load fluctuations, generator malfunctions, and uncertainties in renewable energy output can all cause changes in the system's inertia level, thereby affecting the safety of the system's frequency. Therefore, it is necessary to reassess the power system after a predetermined period to promptly detect changes in the system's inertia level and frequency safety status.

[0102] The length of the preset time period needs to be reasonably determined based on the actual situation of the power system. For power systems with large load fluctuations and frequent changes in operating conditions, the preset time period can be set shorter, such as 15 to 30 minutes. This is because the load changes rapidly in such power systems, which may cause significant changes in the system inertia level within a short period of time, thus affecting the safety of the system frequency. For example, in a power system near an industrial park, the production load of industrial users may change significantly with adjustments to production plans. During peak production periods during the day, the load may increase sharply, while during off-peak production periods at night, the load may decrease sharply. If the preset time period is set too long, changes in the system inertia level and frequency safety status may not be detected in time, thus missing the optimal adjustment opportunity.

[0103] Meanwhile, for power systems with relatively stable loads and minimal changes in operating conditions, the preset time period can be appropriately extended, for example, to 1 to 2 hours. The load changes in these power systems are relatively gradual, and the system inertia level is relatively stable, making significant changes over a longer period less likely. For example, in a power system primarily used by residential users, while residential electricity load may fluctuate somewhat throughout the day, the overall change is relatively small. Setting the preset time period to 1 to 2 hours allows for timely detection of changes in system inertia level and frequency safety status, while also reducing the frequency of assessments and lowering operating costs.

[0104] Understandably, when reassessing the power system after a preset time period, it is necessary to collect and calculate relevant system data again, including real-time system inertia, frequency safety critical inertia values, and the operating status of generating equipment. Then, based on this data, frequency safety evaluation indicators and control economic evaluation indicators are recalculated, and the current inertia level of the power system is assessed using the aforementioned method. If the assessment results show that the system frequency remains safe, the current operating status can be maintained, but changes in system inertia and related indicators need to be continuously monitored. If the assessment results show that the system frequency safety situation has deteriorated, or the overall score has significantly decreased, further analysis of the causes is needed, and corresponding measures should be taken for adjustment. For example, if a decrease in real-time system inertia is found, it may be due to the failure and shutdown of some generating equipment; in this case, backup generating equipment needs to be activated promptly to increase system inertia and ensure system frequency safety.

[0105] Specifically, when a power system's frequency is determined to be unsafe, immediate measures are needed to adjust the system inertia to restore frequency safety. Here, a reasonable inertia control scheme can be generated based on frequency safety evaluation indicators and economic efficiency evaluation indicators. Frequency safety evaluation indicators clearly define the degree and cause of system frequency insecurity. For example, if the frequency safety evaluation indicators show that the system inertia is far below the critical inertia value for frequency safety and the frequency deviation is large, then the system needs to significantly increase its inertia to stabilize the frequency. Economic efficiency evaluation indicators, on the other hand, consider the economic costs required to increase system inertia. For example, if the economic efficiency evaluation indicators show that the cost of using a certain frequency regulation method is high, while another frequency regulation method is lower in cost and has comparable effectiveness, then the lower-cost frequency regulation method should be given priority when generating an inertia control scheme.

[0106] For example, when generating an inertia control scheme, multiple frequency regulation methods can be considered comprehensively. A common method is to increase spinning reserve capacity. Spinning reserve refers to generator units that are already connected to the grid but not yet operating at full capacity. These units can rapidly increase their output to provide additional inertia support. For instance, when the system frequency drops, spinning reserve units can be started immediately to increase power output, thereby increasing system inertia and stabilizing the system frequency. When selecting spinning reserve units, factors such as start-up time, output adjustment speed, and operating costs should be considered comprehensively. Units with short start-up times, fast output adjustment speeds, and low operating costs should be given priority.

[0107] In some other embodiments, frequency regulation can also be achieved by deploying energy storage devices. These devices can release energy when the system frequency drops, providing additional power support and thus increasing system inertia. Common energy storage devices include battery storage, flywheel storage, and supercapacitor storage, each with different characteristics and application scenarios. For example, battery storage has the advantages of high energy density and large storage capacity, but its charging and discharging speed is relatively slow; flywheel storage has the advantages of fast charging and discharging speed and long lifespan, but its energy density is relatively low. When generating an inertia control scheme, it is necessary to select a suitable energy storage device based on the actual needs of the system and the characteristics of the energy storage device.

[0108] For example, after generating an inertia control scheme, the scheme can be executed to adjust the inertia of the power system. During execution, the changes in system frequency and the operating status of various frequency regulation methods should be closely monitored. For instance, when starting a spinning standby unit, it is necessary to monitor the unit's output adjustment in real time to ensure that the unit can increase its output as expected; when putting an energy storage device into operation, it is necessary to monitor the charging and discharging status of the energy storage device in real time to ensure that the energy storage device can release energy normally.

[0109] Here, after implementing the inertia control scheme, the power system can be reassessed after a preset time period. The length of the preset time period also needs to be determined based on the actual situation of the power system. Generally speaking, for situations using fast frequency regulation methods (such as starting spinning standby units or activating energy storage devices), the preset time period can be set shorter, such as 5 to 10 minutes, to allow for timely evaluation of the frequency regulation effect. For situations using slower frequency regulation methods such as demand response technology, the preset time period can be appropriately extended, such as 30 minutes to 1 hour.

[0110] The power system inertia safety domain assessment method, device, equipment, and medium provided in this disclosure can accurately obtain key parameters reflecting system frequency safety and control economy by constructing a power system frequency dynamic response model and calculating critical inertia in combination with active power disturbance. Furthermore, by comprehensively dividing the inertia operating range by combining the critical inertia value for frequency safety and the critical inertia value for control economy, and assessing the current inertia level based on the real-time inertia of the system, the state of power system inertia can be comprehensively and accurately determined, effectively balancing system frequency safety and control economy, and ensuring the stable operation and scientific control of the power system.

[0111] Those skilled in the art will understand that, in the above-described method of the specific implementation, the order in which each step is written does not imply a strict execution order and does not constitute any limitation on the implementation process. The specific execution order of each step should be determined by its function and possible internal logic.

[0112] Based on the same inventive concept, this disclosure also provides a power system inertia security domain assessment device corresponding to the power system inertia security domain assessment method. Since the principle of the device in this disclosure for solving the problem is similar to the power system inertia security domain assessment method described above, the implementation of the device can refer to the implementation of the method, and the repeated parts will not be described again.

[0113] Reference Figure 6 The diagram shown is a schematic of a power system inertia safety domain assessment device 600 provided in an embodiment of this disclosure. The device includes: The model building module 601 is used to obtain the model parameters of each generator governor in the power system and to build a frequency dynamic response model of the power system based on the model parameters of each generator governor. The inertia calculation module 602 is used to obtain the active power disturbance amount after the active power disturbance occurs in the power system; and to calculate the critical inertia of the power system based on the active power disturbance amount and the frequency dynamic response model of the power system; wherein, the critical inertia includes the frequency safety critical inertia value and the regulation economy critical inertia value. The inertia assessment module 603 is used to divide the inertia operating domain of the power system into multiple inertia operating intervals according to the critical inertia; and to assess the current inertia level of the power system based on the real-time inertia of the power system and the multiple inertia operating intervals.

[0114] In some possible embodiments, the model building module 601 is specifically used for: Input a step-type frequency deviation signal to each generator speed controller and collect output data of mechanical power change corresponding to each generator speed controller; Discrete integration is performed on the output data of the mechanical power change corresponding to each generator speed controller to obtain the ramp response data corresponding to the mechanical power of each generator speed controller. The ramp response data corresponding to the mechanical power of each generator governor are fitted to obtain the model parameters of each generator governor.

[0115] In some possible embodiments, the inertia calculation module 602 is specifically used for: Based on the power system frequency dynamic response model, the analytical expressions for the initial rate of change of system frequency and the extreme values ​​of frequency deviation are determined. Based on the analytical expression of the initial rate of change of frequency, the preset maximum rate of change of frequency limit, and the active power disturbance, the first frequency safety critical inertia value is calculated. Based on the analytical expression of the frequency deviation extreme value, the preset frequency deviation extreme value limit, and the active power disturbance, the second frequency safety critical inertia value is calculated. The larger of the first frequency safety critical inertia value and the second frequency safety critical inertia value is determined as the frequency safety critical inertia value.

[0116] In some possible embodiments, the inertia calculation module 602 is specifically used for: Based on the analytical expressions for the initial rate of change of frequency and the extreme value of frequency deviation, the marginal benefit of inertia improvement is defined; wherein, the marginal benefit is the amount by which the absolute value of the initial rate of change of frequency and the extreme value of frequency deviation decreases when the real-time inertia of the system increases; Calculate the overall sensitivity of the marginal benefit to the real-time inertia change of the real-time system; and determine at least two critical inertia values ​​for economical control based on the numerical range of the overall sensitivity.

[0117] In some possible embodiments, the inertia assessment module 603 is specifically used for: Using the frequency safety critical inertia value as the dividing point, the inertia operating domain is divided into a frequency unsafe region and a frequency safe region; Within the frequency safety region, the frequency safety region is divided into a high-economic-efficiency control region, a medium-economic-efficiency control region, and a low-economic-efficiency control region, using the at least two critical inertia values ​​for control economy as dividing points.

[0118] In some possible embodiments, the inertia assessment module 603 is specifically used for: Based on the real-time inertia of the power system and the critical inertia value for frequency security, the frequency security evaluation index of the power system is determined. The economic evaluation index for regulation is determined based on the inertia operating range of the system's real-time inertia. The current inertia level of the power system is assessed based on the frequency security evaluation index and the regulation economy evaluation index.

[0119] In some possible embodiments, the inertia assessment module 603 is specifically used for: Determine whether the frequency of the power system is safe based on the frequency security evaluation indicators; If the frequency of the power system is safe, the power system will be reassessed after a preset time period. If the frequency of the power system is not secure, an inertia control scheme is generated based on the frequency security evaluation index and the control economy evaluation index, and the inertia control scheme is executed to adjust the inertia of the power system. After a preset time period, the power system is re-evaluated.

[0120] Based on the same technical concept, this disclosure also provides a computer device. (See also...) Figure 7 The diagram shows the structure of a computer device 700 provided in this embodiment of the present disclosure, including a processor 701, a memory 702, and a bus 703. The memory 702 stores execution instructions and includes a main memory 7021 and an external memory 7022. The main memory 7021, also called internal memory, is used to temporarily store computational data in the processor 701, as well as data exchanged with external memory 7022 such as a hard disk. The processor 701 exchanges data with the external memory 7022 through the main memory 7021.

[0121] In this embodiment, the memory 702 is specifically used to store application code that executes the solution of this application, and its execution is controlled by the processor 701. That is, when the computer device 700 is running, the processor 701 communicates with the memory 702 through the bus 703, so that the processor 701 executes the application code stored in the memory 702, and then executes the method described in any of the foregoing embodiments.

[0122] The memory 702 may be, but is not limited to, random access memory (RAM), read-only memory (ROM), programmable read-only memory (PROM), erasable programmable read-only memory (EPROM), electrically erasable programmable read-only memory (EEPROM), etc.

[0123] Processor 701 may be an integrated circuit chip with signal processing capabilities. The aforementioned processor can be a general-purpose processor, including a Central Processing Unit (CPU), a Network Processor (NP), etc.; it can also be a Digital Signal Processor (DSP), an Application Specific Integrated Circuit (ASIC), a Field Programmable Gate Array (FPGA), or other programmable logic devices, discrete gate or transistor logic devices, or discrete hardware components. It can implement or execute the methods, steps, and logic block diagrams disclosed in the embodiments of this invention. The general-purpose processor can be a microprocessor or any conventional processor.

[0124] It is understood that the structures illustrated in the embodiments of this application do not constitute a specific limitation on the computer device 700. In other embodiments of this application, the computer device 700 may include more or fewer components than illustrated, or combine some components, or split some components, or have different component arrangements. The illustrated components may be implemented in hardware, software, or a combination of software and hardware.

[0125] This disclosure also provides a computer-readable storage medium storing a computer program that, when executed by a processor, performs the steps of the power system inertia safety domain assessment method described in the above-described method embodiments. The storage medium can be a volatile or non-volatile computer-readable storage medium.

[0126] This disclosure also provides a computer program product carrying program code. The program code includes instructions that can be used to execute the steps of the power system inertia security domain assessment method described in the above method embodiments. For details, please refer to the above method embodiments, which will not be repeated here.

[0127] The aforementioned computer program product can be implemented through hardware, software, or a combination thereof. In one optional embodiment, the computer program product is specifically embodied in a computer storage medium; in another optional embodiment, the computer program product is specifically embodied in a software product, such as a software development kit (SDK), etc.

[0128] Those skilled in the art will clearly understand that, for the sake of convenience and brevity, the specific working processes of the systems and devices described above can be referred to the corresponding processes in the foregoing method embodiments, and will not be repeated here. In the several embodiments provided in this disclosure, it should be understood that the disclosed systems and methods can be implemented in other ways. The device embodiments described above are merely illustrative. For example, the division of units is only a logical functional division; in actual implementation, there may be other division methods. Furthermore, multiple units or components may be combined or integrated into another system, or some features may be ignored or not executed. Another point is that the displayed or discussed mutual coupling or direct coupling or communication connection may be through some communication interfaces; the indirect coupling or communication connection of devices or units may be electrical, mechanical, or other forms.

[0129] The units described as separate components may or may not be physically separate. The components shown as units may or may not be physical units; that is, they may be located in one place or distributed across multiple network units. Some or all of the units can be selected to achieve the purpose of this embodiment according to actual needs.

[0130] In addition, the functional units in the various embodiments of this disclosure can be integrated into one processing unit, or each unit can exist physically separately, or two or more units can be integrated into one unit.

[0131] If the aforementioned functions are implemented as software functional units and sold or used as independent products, they can be stored in a processor-executable, non-volatile, computer-readable storage medium. Based on this understanding, the technical solution of this disclosure, in essence, or the part that contributes to the prior art, or a portion of the technical solution, can be embodied in the form of a software product. This computer software product is stored in a storage medium and includes several instructions to cause a computer device (which may be a personal computer, server, or network device, etc.) to execute all or part of the steps of the methods described in the various embodiments of this disclosure. The aforementioned storage medium includes various media capable of storing program code, such as USB flash drives, portable hard drives, read-only memory (ROM), random access memory (RAM), magnetic disks, or optical disks.

[0132] Finally, it should be noted that the above-described embodiments are merely specific implementations of this disclosure, used to illustrate the technical solutions of this disclosure, and not to limit it. The protection scope of this disclosure is not limited thereto. Although this disclosure has been described in detail with reference to the foregoing embodiments, those skilled in the art should understand that any person skilled in the art can still modify or easily conceive of changes to the technical solutions described in the foregoing embodiments, or make equivalent substitutions for some of the technical features, within the scope of the technology disclosed in this disclosure. Such modifications, changes, or substitutions do not cause the essence of the corresponding technical solutions to deviate from the spirit and scope of the technical solutions of the embodiments of this disclosure, and should all be covered within the protection scope of this disclosure. Therefore, the protection scope of this disclosure should be determined by the protection scope of the claims.

Claims

1. A method for evaluating the inertia security domain of a power system, characterized in that, include: Obtain the model parameters of each generator governor in the power system, and construct a frequency dynamic response model of the power system based on the model parameters of each generator governor; After an active power disturbance occurs in the power system, the active power disturbance amount is obtained; Based on the active power disturbance and the power system frequency dynamic response model, the critical inertia of the power system is calculated; wherein, the critical inertia includes the frequency safety critical inertia value and the regulation economy critical inertia value. The inertia operating domain of the power system is divided into multiple inertia operating intervals based on the critical inertia; and the current inertia level of the power system is evaluated based on the real-time inertia of the power system and the multiple inertia operating intervals.

2. The method according to claim 1, characterized in that, The acquisition of the model parameters of each generator governor in the power system includes: Input a step-type frequency deviation signal to each generator speed controller and collect output data of mechanical power change corresponding to each generator speed controller; Discrete integration is performed on the output data of the mechanical power change corresponding to each generator speed controller to obtain the ramp response data corresponding to the mechanical power of each generator speed controller. The ramp response data corresponding to the mechanical power of each generator governor are fitted to obtain the model parameters of each generator governor.

3. The method according to claim 1, characterized in that, The calculation of the critical inertia of the power system based on the active power disturbance and the power system frequency dynamic response model includes: Based on the power system frequency dynamic response model, the analytical expressions for the initial rate of change of system frequency and the extreme values ​​of frequency deviation are determined. Based on the analytical expression of the initial rate of change of frequency, the preset maximum rate of change of frequency limit, and the active power disturbance, the first frequency safety critical inertia value is calculated. Based on the analytical expression of the frequency deviation extreme value, the preset frequency deviation extreme value limit, and the active power disturbance, the second frequency safety critical inertia value is calculated. The larger of the first frequency safety critical inertia value and the second frequency safety critical inertia value is determined as the frequency safety critical inertia value.

4. The method according to claim 1, characterized in that, The calculation of the critical inertia of the power system based on the active power disturbance and the power system frequency dynamic response model includes: Based on the analytical expressions for the initial rate of change of frequency and the extreme value of frequency deviation, the marginal benefit of inertia improvement is defined; wherein, the marginal benefit is the amount by which the absolute value of the initial rate of change of frequency and the extreme value of frequency deviation decreases when the real-time inertia of the system increases; Calculate the overall sensitivity of the marginal benefit to the real-time inertia change of the real-time system; and determine at least two critical inertia values ​​for economical control based on the numerical range of the overall sensitivity.

5. The method according to claim 3 or 4, characterized in that, The step of dividing the inertia operating domain of the power system into multiple inertia operating intervals based on the critical inertia includes: Using the frequency safety critical inertia value as the dividing point, the inertia operating domain is divided into a frequency unsafe region and a frequency safe region; Within the frequency safety region, the frequency safety region is divided into a high-economic-efficiency control region, a medium-economic-efficiency control region, and a low-economic-efficiency control region, using the at least two critical inertia values ​​for control economy as dividing points.

6. The method according to claim 1, characterized in that, The assessment of the current inertia level of the power system based on the real-time inertia of the power system and the multiple inertia operating ranges includes: Based on the real-time inertia of the power system and the critical inertia value for frequency security, the frequency security evaluation index of the power system is determined. The economic evaluation index for regulation is determined based on the inertia operating range of the system's real-time inertia. The current inertia level of the power system is assessed based on the frequency security evaluation index and the regulation economy evaluation index.

7. The method according to claim 6, characterized in that, The assessment of the current inertia level of the power system based on the frequency security evaluation index and the regulation economic evaluation index includes: Determine whether the frequency of the power system is safe based on the frequency security evaluation indicators; If the frequency of the power system is safe, the power system will be reassessed after a preset time period. If the frequency of the power system is not safe, an inertia control scheme is generated based on the frequency safety evaluation index and the control economy evaluation index, and the inertia control scheme is executed to adjust the inertia of the power system. After a preset time period, the power system is re-evaluated.

8. A power system inertia safety domain assessment device, characterized in that, include: The model building module is used to obtain the model parameters of each generator governor in the power system, and to build a frequency dynamic response model of the power system based on the model parameters of each generator governor. The inertia calculation module is used to obtain the active power disturbance amount after an active power disturbance occurs in the power system. Based on the active power disturbance and the power system frequency dynamic response model, the critical inertia of the power system is calculated; wherein, the critical inertia includes the frequency safety critical inertia value and the regulation economy critical inertia value. The inertia assessment module is used to divide the inertia operating domain of the power system into multiple inertia operating intervals based on the critical inertia; and to assess the current inertia level of the power system based on the real-time inertia of the power system and the multiple inertia operating intervals.

9. A storage medium having a computer program stored thereon, characterized in that, When the computer program is executed by a processor, it implements the method of any one of claims 1 to 7.

10. A computer device, comprising a storage medium, a processor, and a computer program stored on the storage medium and executable on the processor, characterized in that, When the processor executes the computer program, it implements the method of any one of claims 1 to 7.

Images