High-risk unit identification and scheduling method based on N-1 frequency safety criterion

Abstract

The invention discloses a high-risk unit identification and scheduling method based on an N-1 frequency safety criterion. The method comprises the following steps: establishing a linear primary frequency modulation control model of the power system under dynamic frequency response constraint of the power system and primary frequency modulation standby constraint of a generator set, and further obtaining the lowest frequency point of the power system after a tripping fault; obtaining the maximum frequency modulation control capability after the tripping fault of the power system according to the lowest point of the frequency, and comparing the maximum frequency modulation control capability with the maximum output power of the tripping generator set, so as to identify a high-risk unit; based on an N-1 frequency safety criterion, a novel electric power system pre-correction optimization scheduling model after a high-risk unit tripping fault is established under frequency safety constraints, and then output power of each generator set and primary frequency modulation reserved before the fault are obtained to serve as control instructions, so that optimization scheduling of an electric power system is achieved. According to the method, the optimal configuration of the on-line unit can be realized on the premise that the frequency of the novel power system is prevented from losing stability due to the tripping fault of any generator.

Description

Technical Field

[0001] The invention relates to a unit dispatching method and to the technical field of stable operation of power systems, and in particular to a high-risk unit identification and dispatching method based on an N-1 frequency safety criterion. Background Art

[0002] With the large-scale access of new energy units with low power generation costs to the power system, traditional coal-fired power units are gradually being replaced by asynchronous power generation technologies represented by new energy units. This replacement process will inevitably lead to a decrease in the overall inertia of the power system, which in turn puts the new power system at risk of frequency instability. In addition, due to the influence of factors such as weather, the power generation of new energy units may fluctuate violently, which will further aggravate the instability of the system frequency. Under the dual influence of low inertia and strong fluctuations, frequency stability has become an urgent problem to be solved in the development of new power systems.

[0003] Typically, generators are scheduled regularly to ensure that the frequency of the power system remains stable when any generator trips. According to the traditional N-1 frequency safety criterion, the fault scale is generally considered to be a key factor affecting the frequency stability of the power system. Therefore, in the traditional power system scheduling method, the tripping of the generator with the maximum output power is regarded as the most serious fault. However, with the continuous grid connection of renewable energy and fast response equipment, the frequency response characteristics of the generator set and its contribution to the system inertia have become more diverse. In this case, the generator set with the maximum output power cannot be simply regarded as a high-risk unit, because after the fault occurs, the dynamic frequency response characteristics of the system are jointly affected by the fault scale and the frequency control capability of the remaining power system. Therefore, it is urgent to model the quantitative relationship between the fault scale and the frequency control capability of the remaining power system and the dynamic frequency response characteristics of the system under primary frequency control, and then formulate a high-risk unit identification method and a unit optimization scheduling method to avoid potential frequency instability risks. Summary of the invention

[0004] In order to solve the problems existing in the background technology, the present invention provides a high-risk unit identification and dispatching method based on the N-1 frequency safety criterion. The method of the present invention solves the technical problem of pre-correction optimization dispatching to maintain the system frequency stability when dealing with the most serious faults under the combined influence of low inertia and strong fluctuations, and provides technical guarantee for the stable operation of new power systems under low inertia.

[0005] The technical solution adopted by the present invention is:

[0006] The high-risk unit identification and scheduling method based on the N-1 frequency safety criterion of the present invention includes:

[0007] S1: A linear primary frequency regulation control model of the power system is established under the constraints of the dynamic frequency response of the power system and the primary frequency regulation reserve of the generator set. The power shortage of the power system, the maximum climbing rate of each generator set and the load damping coefficient are input into the linear primary frequency regulation control model of the power system. After processing, the linear primary frequency regulation control model of the power system outputs the lowest frequency point of the power system after the generator set trips.

[0008] S2: According to the lowest frequency point of the power system after the generator set trips, the maximum frequency control capability of the remaining online generator sets after each generator set in the power system trips is obtained, and compared with the maximum output power of the tripped generator set, so as to identify high-risk units.

[0009] S3: Based on the N-1 frequency safety criterion, a new power system pre-correction optimization dispatching model is established under frequency safety constraints after a high-risk unit tripping fault. The power generation cost and primary frequency regulation reserve cost of the coal-fired power units in the power system and the power generation cost of the new energy units are input into the new power system pre-correction optimization dispatching model. After processing, the new power system pre-correction optimization dispatching model outputs the output power of each coal-fired power unit and the primary frequency regulation reserve to be reserved before the fault and the output power of the new energy unit as control instructions to achieve optimal dispatch of the power system's power generating units.

[0010] The cost can be measured in terms of power generation.

[0011] In step S1, the linear primary frequency modulation control model of the power system is specifically as follows:

[0012]

[0013] Among them, M represents a constant parameter with a large value; f nadir and t nadir They represent the lowest frequency point and time of the power system after the generator set trips, b and w respectively. b They represent the time t when the frequency of the power system reaches the lowest point after the generator set trips. nadir The bits in the binary expansion of and its binary variant, Indicates the time t when the frequency of the power system reaches the lowest point after the generator set trips nadir The set of bits in the binary expansion of b represents auxiliary variables, z b =w b P def , P def represents the power shortage of the power system; f0 represents the system reference frequency at time t; H represents the inertia of the power system, that is, the sum of the inertia of each generator set in the power system. The generator sets in the power system include coal-fired power units and new energy units.

[0014] In step S1, the dynamic frequency response constraints of the power system are specifically as follows:

[0015]

[0016] Where D represents the load damping coefficient, that is, the load power change caused by 1% system frequency deviation; C equ Represents the equivalent aggregate ramp rate of all coal-fired power units.

[0017] In step S1, the primary frequency regulation standby constraints of the generator set are specifically as follows:

[0018] The lowest frequency point f after the generator set trips nadir Only with nadir It is related to the primary frequency regulation reserve released before, but to the nadir The primary frequency regulation reserve released after the fault is irrelevant, so the primary frequency regulation reserve R reserved for generator set i to deal with the fault is i It is divided into two parts, namely emergency primary frequency regulation and standby and restore primary frequency regulation standby They represent the generator set i at t nad The frequency modulation reserve released before and after, and the frequency modulation reserve restored Used to restore the frequency to a new stable state after reaching the lowest point. Emergency primary frequency regulation standby and restore primary frequency regulation standby The operation must meet the following constraints:

[0019] a) Basic constraints for primary frequency regulation standby:

[0020] By distinguishing emergency primary frequency regulation and restore primary frequency regulation standby As a result, the high-cost fast-response generator sets are focused on providing emergency primary frequency regulation reserves, while the low-cost slow-response generator sets are focused on providing recovery primary frequency regulation reserves and emergency primary frequency regulation reserves. and restore primary frequency regulation standby Together they form the primary frequency regulation reserve R that needs to be reserved before a fault occurs. i . Therefore, we have:

[0021]

[0022] Among them, R i , and They respectively represent the primary frequency regulation reserve reserved before the failure of the i-th generator set in the power system, its emergency primary frequency regulation reserve and the restored primary frequency regulation reserve.

[0023] b) Climbing rate constraint:

[0024] Emergency primary frequency regulation standby of generator set i The ramp rate adequacy constraint must always be met, namely:

[0025]

[0026] in, Represents the limit ramp rate of the i-th generator set in the power system.

[0027] Indicates that the i-th generator set is at t nadir The constraint means that when the ramp rate of generator set i is low, even if there is enough primary frequency regulation reserve, the generator set i will nadir It is also impossible to provide sufficient active power compensation.

[0028] c) Emergency primary frequency regulation reserve constraints:

[0029] The power system operator needs to reserve a certain amount of primary frequency regulation before a fault occurs to deal with the potential risk of frequency instability. Assume that generator set i needs to nadir The emergency primary frequency regulation standby is provided at all times Its climbing rate is To ensure the system frequency safety after the generator set trips, the sum of the ramp rates of all online coal-fired power units should be greater than the equivalent aggregate ramp rate C equ In addition, the limit of the climbing rate should not be greater than So we have:

[0030]

[0031] The emergency primary frequency regulation reserve constraint establishes the system equivalent aggregate climbing slope C eq The relationship between it and the single-machine maximum climbing rate (related to the emergency primary frequency regulation standby).

[0032] d) Power balance constraint at the lowest frequency point:

[0033] In t nadir At this time, coal-fired power units provide The active output of the frequency-sensitive load is reduced by D(f0-f nadir ) active output. Therefore, the power balance constraint at the lowest frequency point can be expressed as:

[0034]

[0035] Where n represents the total number of generator sets in the power system.

[0036] e) Restore the primary frequency regulation standby constraint:

[0037] When constraints a) to d) are met, the lowest frequency point of the system will be limited to the allowed range. In addition, if there is enough reserve for primary frequency regulation, the coal-fired power unit will nadir After that, the output power will continue to increase. At this time, the system frequency gradually rises from the lowest point to a new stable state, namely the quasi-steady-state frequency. Therefore, in order to meet the adequacy of the primary frequency regulation reserve, the total primary frequency regulation reserve of the system Should be greater than the power shortage P in the generator set trip fault def ,Right now:

[0038]

[0039] In step S2, the maximum frequency regulation control capability of the power system is as follows:

[0040]

[0041] in, It represents the maximum frequency control capability of the remaining online generator sets after the jth generator set in the power system trips; D represents the load damping coefficient; Represents the limit ramp rate of the i-th generator set in the power system.

[0042] In step S2, the maximum frequency regulation control capability of the remaining online generator sets after each generator set in the power system trips and the maximum output power of the generator set are compared to identify high-risk generator sets, as follows:

[0043] In order to ensure the safety of N-1 frequency, the power system operator usually needs to verify the frequency control capability of the power system composed of the remaining online generator sets after each generator set fails. Therefore, it is necessary to use the output power of all generator sets under all fault conditions as decision variables in the optimization scheduling problem. However, this will seriously increase the computational burden of the processor, making it difficult to apply in large-scale power systems containing a large number of coal-fired power units. In this regard, this method considers both the scale of the fault and the maximum frequency control capability of the remaining power system, and then identifies the high-risk units among the online units. The risk unit identification methods improved by the present invention are divided into two categories:

[0044] For each coal-fired power unit in the power system, the maximum frequency regulation control capability of the remaining online generator sets after the coal-fired power unit trips is compared with the maximum output power of the tripped coal-fired power unit. If the maximum frequency regulation control capability of the remaining online generator sets after the coal-fired power unit trips is less than the maximum output power of the coal-fired power unit, the current coal-fired power unit is determined to be a high-risk unit that may cause the power system frequency to lose stability after the trip.

[0045] For each new energy unit in the power system, when the new energy unit satisfies the following formula:

[0046]

[0047] in, represents the output power of the jth renewable energy unit; represents the maximum frequency regulation control capability of the power system when there is no j-th renewable energy unit; D represents the load damping coefficient; Represents the limit ramp rate of the i-th generator set in the power system.

[0048] It is determined that the current new energy unit is a high-risk unit that may cause the power system frequency to lose stability after a tripping failure.

[0049] Since the power of renewable energy units may fluctuate significantly during a dispatch cycle, they usually do not need to provide a frequency regulation reserve to respond to changes in system frequency. In addition, to avoid the frequency falling below the allowed lower limit after the renewable energy unit trips, the output of any renewable energy unit should not always satisfy the above formula; by calculating the remaining power system after the fault, The power system operator can obtain the maximum output power of the renewable energy units under the current operating state of the system, so that the renewable energy units can adaptively meet the N-1 frequency safety criteria.

[0050] In step S3, the new power system pre-correction optimization dispatch model is specifically as follows:

[0051]

[0052] F3(R i ) = d i R i

[0053] Among them, U coal and U res They represent the collection of coal-fired power units and new energy units respectively; F1() represents the power generation cost of the i-th coal-fired power unit, P i represents the output power of the i-th coal-fired power unit; F2() represents the power generation cost of the j-th new energy unit, represents the output power of the jth renewable energy unit; F3() represents the primary frequency regulation reserve cost of the i-th coal-fired power unit, R i represents the primary frequency regulation reserve reserved before the failure of the i-th coal-fired power unit; a i , b i and c i They represent the quadratic term parameter, linear term parameter and constant term parameter of the power generation cost of the i-th coal-fired power unit respectively; and They represent the linear parameter and constant parameter of the power generation cost of the j-th renewable energy unit respectively; d i Represents the proportionality factor.

[0054] The power generation cost of coal-fired power units in the power system includes the quadratic term parameter a of the power generation cost of the i-th coal-fired power unit i , first-order parameter b i and constant parameter c i The power generation cost of the new energy unit includes the first-order parameter of the power generation cost of the j-th new energy unit and constant term parameters

[0055] In step S3, the frequency safety constraints are specifically as follows:

[0056] a) Power balance constraints of coal-fired power units and new energy units:

[0057]

[0058] Among them, P load,n Represents the load power of the nth node in the power system.

[0059] b) N-1 frequency safety constraints after high-risk coal-fired power units trip fault:

[0060]

[0061] in, and Respectively represent the maximum and minimum output power of the i-th coal-fired power unit; and They represent the primary frequency regulation reserve after the tripping fault of the i-th coal-fired power unit, its emergency primary frequency regulation reserve and the recovery primary frequency regulation reserve respectively; represents the maximum primary frequency regulation reserve of the i-th coal-fired power unit; H B Represents a collection of high-risk coal-fired power units; represents the limit ramp rate of the i-th generator set in the power system; Indicates the time when the frequency reaches the lowest point after the generator set trips. The expanded bits are consistent; It represents the power shortage after the power system trips and its value is equal to the output power of generator set i, that is, D represents the load damping coefficient; Indicates the time when the frequency reaches the lowest point after the generator set trips The binary variable of bit b in the binary expansion of ; Indicates the trip fault auxiliary variable; H k Represents the inertia of each remaining generating unit in the power system after the coal-fired generating unit trips; RoCoF max It indicates the maximum frequency change rate allowed in the power system. The maximum frequency change rate limit can ensure that the system has sufficient inertia after a fault to avoid a rapid drop in frequency in the initial stage of tripping, which will affect the safety and stability of the system.

[0062] c) N-1 frequency safety constraints after high-risk renewable energy units trip fault:

[0063]

[0064] in, and Respectively represent the minimum and maximum output power of the j-th renewable energy unit; H j Represents the inertia of the jth renewable energy unit; the output power of any renewable energy unit will always be subject to the maximum frequency control capability restrictions, It will be updated in each dispatch cycle based on the current operating status of the power system.

[0065] The electronic device of the present invention comprises: a memory and a processor coupled to each other, wherein the memory stores program data, and the processor calls the program data to execute the method as described above.

[0066] The computer-readable storage medium of the present invention stores program data thereon, and when the program data is executed by a processor, the method described above is implemented.

[0067] The method of the present invention defines an intrinsic property of the power system based on the system operation parameters, namely, the maximum frequency regulation control capability, based on the quantitative analysis of the power shortage related to the fault scale, the connection between the unit's extreme climbing rate and the lowest frequency point after the fault and its arrival time, to characterize the maximum capability of the current system to compensate for the power shortage and control the system frequency without triggering the low-frequency load shedding relay protection device. Then, by comparing the capacity of the generator set with the maximum frequency regulation control capability of the remaining power system after its tripping fault, the potential high-risk units that may cause the system frequency to lose stability after the tripping fault are identified. On this basis, a new type of pre-correction optimization scheduling model for the power system is established accordingly. The model distinguishes the N-1 frequency safety constraints after the tripping fault of high-risk coal-fired power units and high-risk new energy units, and outputs the output power and primary frequency regulation standby of the online generator set as control instructions by solving the model, and finally realizes the resource optimization allocation and power generation plan formulation of the online units.

[0068] The beneficial effects of the present invention are:

[0069] 1) The present invention establishes a linear primary frequency regulation control model for a power system under the constraints of the dynamic frequency response of the power system and the primary frequency regulation standby of the generator set by analyzing the quantitative relationship between the fault scale, the unit's extreme climbing rate, and the lowest frequency point after the fault and its arrival time. The model can closely integrate the nonlinear dynamic primary frequency regulation control process after the unit tripping fault into the unit optimization scheduling problem, thereby enabling the system to achieve optimal configuration of online generator sets while maintaining frequency stability when dealing with unit tripping faults.

[0070] 2) The present invention defines the maximum frequency regulation control capability of the power system, that is, the maximum power shortage that the power system can bear after a sudden tripping fault without violating the system's minimum frequency limit. On this basis, the maximum output power of the generator set is compared with the maximum frequency regulation control capability of the remaining power system after its tripping fault, so that potential high-risk units that may cause system frequency instability after a tripping fault can be identified before formulating a system pre-correction optimization scheduling plan, thereby supplementing the traditional N-1 frequency safety criterion in the new low-inertia power system, thereby greatly reducing the computational burden of the unit optimization scheduling problem, especially in large-scale power systems containing a large number of coal-fired power units.

[0071] 3) The present invention formulates two different types of N-1 frequency safety constraints and corresponding new power system pre-correction optimization scheduling models according to the frequency response characteristics of high-risk coal-fired power units and high-risk new energy units. The coal-fired power units can take preventive correction measures in advance for any coal-fired power unit tripping failure according to the established scheduling model to deal with the risk of power system frequency losing stability in the event of a tripping failure of all coal-fired power units. The new energy units can obtain the maximum output power in the current operating state by calculating the maximum frequency regulation control capability of the remaining power system after the failure in each scheduling cycle, so as to enable the new energy units to adaptively meet the N-1 frequency safety criteria.

[0072] The present invention can realize the optimal resource allocation and power generation plan formulation of online coal-fired power units under the premise of avoiding the frequency instability of the new power system caused by the tripping failure of any generator unit. At the same time, it can enable the new energy units to adaptively meet the N-1 frequency safety criterion, providing technical guarantee for the stable operation of the new power system under low inertia. BRIEF DESCRIPTION OF THE DRAWINGS

[0073] Figure 1 is a flow chart of the method of the present invention;

[0074] Figure 2 is a dynamic frequency response curve diagram after a unit trip fault under different schemes according to an exemplary embodiment;

[0075] Figure 3 is a comparison diagram of the output power of the online unit and the maximum frequency regulation control capability in scenario 1 according to an exemplary embodiment;

[0076] Figure 4 is a comparison diagram of the output power of the online unit and the maximum frequency regulation control capability in scenario 2 according to an exemplary embodiment;

[0077] Figure 5 It is a dynamic frequency response curve diagram of a unit scheduling method based on a traditional N-1 frequency safety criterion and a proposed method according to an exemplary embodiment. DETAILED DESCRIPTION

[0078] The present invention is further described in detail below with reference to the accompanying drawings and specific embodiments.

[0079] like Figure 1 As shown, the purpose of the embodiment of the present invention is to provide a high-risk unit identification and scheduling method based on the N-1 frequency safety criterion to solve the pre-correction optimization scheduling technical problem of maintaining system frequency stability when the power system responds to the most serious fault under the combined influence of low inertia and strong fluctuations. The method includes the following steps:

[0080] S1: A linear primary frequency regulation control model of the power system is established under the constraints of the dynamic frequency response of the power system and the primary frequency regulation reserve of the generator set. The power shortage of the power system, the maximum climbing rate of each generator set and the load damping coefficient are input into the linear primary frequency regulation control model of the power system. After processing, the linear primary frequency regulation control model of the power system outputs the lowest frequency point of the power system after the generator set trips.

[0081] The linear primary frequency regulation control model of the power system is as follows:

[0082]

[0083] Among them, M represents a constant parameter with a large value; f nadir and t nadir They represent the lowest frequency point and time of the power system after the generator set trips, b and w respectively. b They represent the time t when the frequency of the power system reaches the lowest point after the generator set trips. nadir The bits in the binary expansion of and its binary variant, Indicates the time t when the frequency of the power system reaches the lowest point after the generator set trips nadir The set of bits in the binary expansion of b represents auxiliary variables, z b =w b P def , P def represents the power shortage of the power system; f0 represents the system reference frequency at time t; H represents the inertia of the power system, that is, the sum of the inertia of each generator set in the power system. The generator sets in the power system include coal-fired power units and new energy units.

[0084] In order to further linearize the power system dynamic frequency response constraints and emergency primary frequency regulation reserve constraints into a power system linear primary frequency regulation control model that can be optimally dispatched, the present invention uses binary expansion and large M method to approximate them. First, for t nadir Perform binary expansion, and then substitute it into the power system dynamic frequency response constraint together with the power balance constraint at the lowest frequency point and the primary frequency regulation reserve constraint to obtain:

[0085]

[0086] Among them, the nonlinear term is a continuous variable P def and a binary variable w b The linear combination of the product of can be further linearized by the big M method. Finally, the power system dynamic frequency response constraints and emergency primary frequency regulation reserve constraints are converted into the above-mentioned b Linear primary frequency regulation control model of power system.

[0087] The dynamic frequency response constraints of the power system are as follows:

[0088]

[0089] Where D represents the load damping coefficient, that is, the load power change caused by 1% system frequency deviation; C equ Represents the equivalent aggregate ramp rate of all coal-fired power units.

[0090] For the power shortage P caused by the tripping fault of the generator set in the power system def The coal-fired power units reserved for primary frequency regulation can respond to the system frequency deviation through the droop control of the speed regulator and gradually increase the unit output power. At the same time, the frequency-sensitive load will gradually reduce its output power when the system frequency decreases. Therefore, when the frequency reaches the lowest point f nadir The time corresponding to the lowest frequency point is recorded as t nadir , power shortage P def will be increased by the output power increment of coal-fired power units ΔP(t nadir ) and the reduced load power D(f0-f nadir ) is fully compensated. After that, the coal-fired power units continue to increase their output power, and the system frequency begins to change from f nadir The above power system dynamic frequency response process can be quantitatively expressed as:

[0091]

[0092] Where f(t) represents the system frequency at time t; ΔP(t) represents the power increment of the coal-fired power unit at time t. nadir Integrating, we can get the lowest frequency point as:

[0093]

[0094] It is worth noting that the output power increment ΔP(t) of all coal-fired power units mainly depends on the control parameters of the speed regulators of each coal-fired power unit, which varies nonlinearly with time. For this reason, the present invention uses a virtual generator set with a constant ramp rate to approximate the equivalent, that is,

[0095]

[0096] C equ The value of t nadir is constant, so is a variable that is independent of time t and is equivalent to a machine with a constant ramp rate of C equ The generator set is at t nadir The energy increased.

[0097] The energy added to the frequency-sensitive load due to the load damping effect is given by the linearized load damping effect, and the following approximation is made:

[0098]

[0099] This approximate method slightly underestimates the role of load damping effect in the primary frequency control process, so this method is conservative, and the resulting deviation can be regarded as a safety margin in power system dispatch. Finally, the above power system dynamic frequency response constraints are obtained.

[0100] The power system dynamic frequency response constraint establishes the power shortage P related to the fault scale at the level of the entire power system. def , the lowest frequency point f nadir , equivalent aggregate climbing rate C equ and the frequency minimum time t nadir The quantitative relationship between them.

[0101] The primary frequency regulation standby constraints of the generator set are as follows:

[0102] The lowest frequency point f after the generator set trips nadir Only with nadir It is related to the primary frequency regulation reserve released before, but to the nadir The primary frequency regulation reserve released after the fault is irrelevant, so the primary frequency regulation reserve R reserved for generator set i to deal with the fault is i It is divided into two parts, namely emergency primary frequency regulation and standby and restore primary frequency regulation standby They represent the generator set i at t nad The frequency modulation reserve released before and after, and the frequency modulation reserve restored Used to restore the frequency to a new stable state after reaching the lowest point. Emergency primary frequency regulation standby and restore primary frequency regulation standby The operation must meet the following constraints:

[0103] a) Basic constraints for primary frequency regulation standby:

[0104] By distinguishing emergency primary frequency regulation and restore primary frequency regulation standby As a result, the high-cost fast-response generator sets are focused on providing emergency primary frequency regulation reserves, while the low-cost slow-response generator sets are focused on providing recovery primary frequency regulation reserves and emergency primary frequency regulation reserves. and restore primary frequency regulation standby Together they form the primary frequency regulation reserve R that needs to be reserved before a fault occurs. i. Therefore, we have:

[0105]

[0106] Among them, R i , and They respectively represent the primary frequency regulation reserve reserved before the failure of the i-th generator set in the power system, its emergency primary frequency regulation reserve and the restored primary frequency regulation reserve.

[0107] b) Climbing rate constraint:

[0108] Emergency primary frequency regulation standby of generator set i The ramp rate adequacy constraint must always be met, namely:

[0109]

[0110] in, represents the limit ramp rate of the i-th generator set in the power system;

[0111] Indicates that the i-th generator set is at t nadir The constraint means that when the ramp rate of generator set i is low, even if there is enough primary frequency regulation reserve, the generator set i will nadir It is also impossible to provide sufficient active power compensation.

[0112] c) Emergency primary frequency regulation reserve constraints:

[0113] The power system operator needs to reserve a certain amount of primary frequency regulation before a fault occurs to deal with the potential risk of frequency instability. Assume that generator set i needs to nadir The emergency primary frequency regulation standby is provided at all times Its climbing rate is To ensure the system frequency safety after the generator set trips, the sum of the ramp rates of all online coal-fired power units should be greater than the equivalent aggregate ramp rate C equ In addition, the limit of the climbing rate should not be greater than So we have:

[0114]

[0115] The emergency primary frequency regulation reserve constraint establishes the system equivalent aggregate climbing slope C eq The relationship between it and the single-machine maximum climbing rate (related to the emergency primary frequency regulation standby).

[0116] d) Power balance constraint at the lowest frequency point:

[0117] In t nadirAt this time, coal-fired power units provide The active output of the frequency-sensitive load is reduced by D(f0-f nadir ) active output. Therefore, the power balance constraint at the lowest frequency point can be expressed as:

[0118]

[0119] Where n represents the total number of generator sets in the power system.

[0120] e) Restore the primary frequency regulation standby constraint:

[0121] When constraints a) to d) are met, the lowest frequency point of the system will be limited to the allowed range. In addition, if there is enough reserve for primary frequency regulation, the coal-fired power unit will nadir After that, the output power will continue to increase. At this time, the system frequency gradually rises from the lowest point to a new stable state, namely the quasi-steady-state frequency. Therefore, in order to meet the adequacy of the primary frequency regulation reserve, the total primary frequency regulation reserve of the system Should be greater than the power shortage P in the generator set trip fault def ,Right now:

[0122]

[0123] S2: According to the lowest frequency point of the power system after the generator set trips, the maximum frequency control capability of the remaining online generator sets after each generator set in the power system trips is obtained, and compared with the maximum output power of the tripped generator set, so as to identify high-risk units.

[0124] The maximum frequency control capability of the power system is as follows:

[0125]

[0126] in, It represents the maximum frequency control capability of the remaining online generator sets after the jth generator set in the power system trips; D represents the load damping coefficient; Represents the limit ramp rate of the i-th generator set in the power system.

[0127] This method aims to minimize the total operating cost without violating the system minimum frequency limit, which is usually set to 49.5 Hz. Therefore, in order to minimize the total operating cost, the system needs to operate in a critical state, that is, the lowest frequency point after the generator set trips is 49.5 Hz, that is, f nadir=49.5Hz. In this regard, the maximum frequency control capability of the power system is defined as: the maximum power shortage that the power system can withstand without violating the minimum frequency limit of the system after a sudden tripping fault The calculation process is as follows:

[0128] First, sum both sides of the ramp rate constraints of the remaining online generators except the j-th tripped generator, and we get:

[0129]

[0130] Combined with the power balance constraint at the lowest frequency point, we can get:

[0131]

[0132] Further substituting the power balance constraint at the lowest frequency point, the primary frequency regulation reserve constraint, and the power system dynamic frequency response constraint into the system, t nadir ,have to:

[0133]

[0134] The maximum P that satisfies this constraint bef This is the maximum power shortage that the system can withstand after the jth generator set trips. By solving according to the parabolic characteristics, the maximum frequency control capability of the above power system can be obtained. Only related to the system operating parameters, such as system inertia H, unit maximum climbing rate The load damping coefficient D quantitatively describes the maximum ability of the current system to compensate for power shortages and control system frequency without violating the system's minimum frequency limit. It is an inherent property of the power system.

[0135] The maximum frequency regulation control capability of the remaining online generator sets after each generator set trips in the power system is compared with the maximum output power of the generator sets to identify high-risk units, as follows:

[0136] In order to ensure the safety of N-1 frequency, the power system operator usually needs to verify the frequency control capability of the power system composed of the remaining online generator sets after each generator set fails. Therefore, it is necessary to use the output power of all generator sets under all fault conditions as decision variables in the optimization scheduling problem. However, this will seriously increase the computational burden of the processor, making it difficult to apply in large-scale power systems containing a large number of coal-fired power units. In this regard, this method considers both the scale of the fault and the maximum frequency control capability of the remaining power system, and then identifies the high-risk units among the online units. The risk unit identification methods improved by the present invention are divided into two categories:

[0137] For each coal-fired power unit in the power system, the maximum frequency regulation control capability of the remaining online generator sets after the coal-fired power unit trips is compared with the maximum output power of the tripped coal-fired power unit. If the maximum frequency regulation control capability of the remaining online generator sets after the coal-fired power unit trips is less than the maximum output power of the coal-fired power unit, the current coal-fired power unit is determined to be a high-risk unit that may cause the power system frequency to lose stability after the trip.

[0138] For each new energy unit in the power system, when the new energy unit satisfies the following formula:

[0139]

[0140] in, represents the output power of the jth renewable energy unit; represents the maximum frequency regulation control capability of the power system when there is no j-th renewable energy unit; D represents the load damping coefficient; Represents the limit ramp rate of the i-th generator set in the power system.

[0141] It is determined that the current new energy unit is a high-risk unit that may cause the power system frequency to lose stability after a tripping failure.

[0142] Since the power of renewable energy units may fluctuate significantly during a dispatch cycle, they usually do not need to provide a frequency regulation reserve to respond to changes in system frequency. In addition, to avoid the frequency falling below the allowed lower limit after the renewable energy unit trips, the output of any renewable energy unit should not always satisfy the above formula; by calculating the remaining power system after the fault, The power system operator can obtain the maximum output power of the renewable energy units under the current operating state of the system, so that the renewable energy units can adaptively meet the N-1 frequency safety criteria.

[0143] S3: Based on the N-1 frequency safety criterion, a new power system pre-correction optimization dispatching model is established under the frequency safety constraint after the high-risk unit tripping fault. The power generation cost of the coal-fired power units in the power system and the primary frequency regulation reserve cost and the power generation cost of the new energy units are input into the new power system pre-correction optimization dispatching model. After processing, the new power system pre-correction optimization dispatching model outputs the output power of each coal-fired power unit and the primary frequency regulation reserve and the output power of the new energy unit that need to be reserved before the fault as control instructions to achieve the optimal dispatch of the power generation units in the power system. The cost can be specifically measured by the power generation power.

[0144] The new power system pre-correction optimization dispatch model is as follows:

[0145]

[0146]

[0147] F3(R i ) = d i R i

[0148] Among them, U coal and U res They represent the collection of coal-fired power units and new energy units respectively; F1() represents the power generation cost of the i-th coal-fired power unit, P i represents the output power of the i-th coal-fired power unit; F2() represents the power generation cost of the j-th new energy unit, represents the output power of the jth renewable energy unit; F3() represents the primary frequency regulation reserve cost of the i-th coal-fired power unit, R i represents the primary frequency regulation reserve reserved before the failure of the i-th coal-fired power unit; a i , b i and c i They represent the quadratic term parameter, linear term parameter and constant term parameter of the power generation cost of the i-th coal-fired power unit respectively; and They represent the linear parameter and constant parameter of the power generation cost of the j-th renewable energy unit respectively; d i Represents the proportionality factor.

[0149] The power generation cost of coal-fired power units in the power system includes the quadratic term parameter a of the power generation cost of the i-th coal-fired power unit i , first-order parameter b i and constant parameter c i The power generation cost of the new energy unit includes the first-order parameter of the power generation cost of the j-th new energy unit and constant term parameters

[0150] The frequency safety constraints are as follows:

[0151] a) Power balance constraints of coal-fired power units and new energy units:

[0152]

[0153] Among them, P load,n Represents the load power of the nth node in the power system.

[0154] b) N-1 frequency safety constraints after high-risk coal-fired power units trip fault:

[0155]

[0156]

[0157] in, and Respectively represent the maximum and minimum output power of the i-th coal-fired power unit; and They represent the primary frequency regulation reserve after the tripping fault of the i-th coal-fired power unit, its emergency primary frequency regulation reserve and the recovery primary frequency regulation reserve respectively; represents the maximum primary frequency regulation reserve of the i-th coal-fired power unit; H B Represents a collection of high-risk coal-fired power units; represents the limit ramp rate of the i-th generator set in the power system; Indicates the time when the frequency reaches the lowest point after the generator set trips. The expanded bits are consistent; It represents the power shortage after the power system trips and its value is equal to the output power of generator set i, that is, D represents the load damping coefficient; Indicates the time when the frequency reaches the lowest point after the generator set trips The binary variable of bit b in the binary expansion of ; Indicates the trip fault auxiliary variable; H k Represents the inertia of each remaining generating unit in the power system after the coal-fired generating unit trips; RoCoF max It indicates the maximum frequency change rate allowed in the power system. The maximum frequency change rate limit can ensure that the system has sufficient inertia after a fault to avoid a rapid drop in frequency in the initial stage of tripping, which will affect the safety and stability of the system.

[0158] c) N-1 frequency safety constraints after high-risk renewable energy units trip fault:

[0159]

[0160] in, and Respectively represent the minimum and maximum output power of the j-th renewable energy unit; H j Represents the inertia of the jth renewable energy unit; the output power of any renewable energy unit will always be subject to the maximum frequency control capability restrictions, It will be updated in each dispatch cycle based on the current operating status of the power system.

[0161] In order to further understand the present invention, the present invention selects the RTS-79 test system for example simulation, and sets up two different application scenarios: 1) Scenario 1 is a traditional power system scenario, that is, the unit climbing rate and system inertia in the power system are sufficient. In this safe situation, the traditional N-1 frequency safety criterion can ensure the stability of the system frequency after any generator unit trips, so Scenario 1 is mainly used to prove that the proposed method is superior to the existing method in terms of operating cost; 2) Scenario 2 is a new power system scenario that is currently booming, that is, a large number of coal-fired power units are replaced by new energy units. In this low-inertia situation, the system operates close to a critical state, and the traditional N-1 frequency safety criterion cannot effectively identify the high-risk generator units that cause the most serious frequency deviation after the tripping fault, thus causing the system to face the risk of unstable frequency after the fault. However, this frequency safety problem can be successfully solved by the risk unit identification and scheduling method improved by the present invention. The present invention sets the minimum frequency allowed by the system to 49.5Hz.

[0162] The RTS-79 test system simulated by the present invention has 11 different types of generator sets, the operating parameters of the generator sets are shown in Table 1, and the power generation cost and the primary frequency regulation standby cost are shown in Table 2. The present invention uses the CPLEXMILP solver on the MATLAB platform to optimize scenarios 1 and 2, and then establishes a SIMULINK model to simulate the dynamic frequency response process after the unit trips. Specifically, scenario 1 is a high load (3450MW) low new energy output (360MW) scenario, and all 11 types of generator sets provide power supply, while scenario 2 is a low load (2850MW) high new energy output (594.6MW) scenario, and only some generator sets (1-4, 7-11) provide power supply.

[0163] Table 1 Generator operating parameters

[0164]

[0165] Table 2 Generator power generation cost and primary frequency regulation standby cost

[0166]

[0167]

[0168] The present invention sets three typical schemes in scenario 1 to perform pre-correction optimization scheduling of the power system based on N-1 frequency safety constraints. The specific schemes are as follows: Scheme 1 (ignoring load damping effect): ignoring the load damping effect in the N-1 frequency safety constraint; Scheme 2 (linearizing load damping effect): linearizing the load damping effect in the N-1 frequency safety constraint; Scheme 3 (the method proposed in the present invention): adopting the high-risk unit identification and scheduling method based on N-1 frequency safety proposed in the present invention.

[0169] Schemes 1 to 3 are all based on optimized scheduling methods, aiming to control the lowest frequency point after the generator unit trips to 49.5Hz. In Scheme 1, in order to simplify the problem, the load damping effect is ignored. In Scheme 2, the impact of the load damping effect on the dynamic frequency response of the system is simply linearized, and the power balance at the lowest frequency point is not considered. Therefore, neither Scheme 1 nor Scheme 2 can accurately estimate the lowest frequency point of the system after the fault. This inaccuracy makes the "optimal" scheduling in Schemes 1 and 2 no longer optimal. Scheme 3 adopts the linear primary frequency modulation control model of the power system established by the present invention, so it can accurately estimate the lowest frequency point after the fault. Figure 2 As shown, the post-fault dynamic frequency response curves of the three schemes after the maximum output power generator set tripped fault in scenario 1 are compared. In addition, as shown in Table 3, due to the improvement of model accuracy, the method proposed in the present invention can significantly reduce the primary frequency regulation standby cost, thereby reducing the total operation cost.

[0170] Table 3 Comparison of operation costs under different schemes

[0171]

[0172] In addition, the present invention defines the maximum frequency control capability, that is, the maximum power deficit that the generator set can withstand after a trip failure without violating the system minimum frequency limit. Figure 3 As shown, the output power of each type of online generator in scenario 1 is compared with the maximum frequency control capability. Figure 3 The maximum output power of a single generator set is 210MW, and the maximum frequency control capacity of the remaining power system after the generator set trips is 236.7MW, which is greater than 210MW. Therefore, in scenario 1, the tripping of the generator set with the maximum output power will not cause the system frequency to fall below the minimum frequency limit. In addition, if Figure 3 As shown, the output power of any generator set is less than the maximum frequency control capability of the corresponding remaining power system. Therefore, in scenario 1, the dispatch result based on the traditional N-1 frequency safety criterion is consistent with the dispatch result of the method proposed in the present invention.

[0173] This is different in Scenario 2 because the most severe unit trip fault in Scenario 2 is not caused by the generator set with the highest output power. Figure 4 As shown, according to the traditional N-1 frequency safety criteria, as long as the tripping fault of the new energy unit (category 11, the maximum output power generator with a power shortage of 189.1MW after the tripping fault) does not cause the system frequency to be lower than the minimum frequency limit, scenario 2 will be considered safe for any generator unit tripping fault. However, the dynamic frequency response characteristics after the unit tripping fault depend not only on the fault scale (i.e., the power shortage), but also on the inertia of the remaining power system and the unit ramp rate. Category 9 generators are high-risk generators in scenario 2, and the tripping fault of this unit will cause a power shortage of 186.5MW. However, in order to avoid the system frequency being lower than the minimum frequency limit, the system can only withstand a power shortage of 179.9MW at most after the tripping fault, so the power system in scenario 2 is prone to frequency instability in the current operating state. In order to ensure the frequency safety of the power system in the tripping fault of any generator unit, according to the method proposed in the present invention, i.e., the maximum frequency regulation control capability analysis, the output power of the unit (category 9) should be limited to less than 179.9MW.

[0174] like Figure 5 As shown in the figure, the dynamic frequency response curves of the unit dispatching method based on the traditional N-1 frequency safety criterion and the proposed method after the tripping fault of the category 9 generator unit in scenario 2 are further compared. The unit dispatching method based on the traditional N-1 frequency safety criterion only focuses on the fault scale, and therefore cannot accurately identify the high-risk units that will cause the maximum frequency deviation after the real tripping fault of the system. Figure 5 As shown, if the method proposed in the present invention, i.e., the unit dispatching method based on the improved N-1 frequency safety criterion, is adopted, the lowest frequency point after the unit tripping fault can be maintained above the minimum frequency limit of 49.5Hz. At the same time, based on the maximum frequency regulation control capability analysis, the method proposed in the present invention can successfully identify high-risk coal-fired power units and high-risk new energy units, and adaptively adjust their output power during dispatching, thereby ensuring the safety and stability of the system frequency in any generator unit tripping fault.

[0175] Corresponding to the embodiment of the method of the present invention, the present invention also provides an embodiment of a high-risk unit identification and scheduling device based on the N-1 frequency safety criterion, which is as follows:

[0176] The primary frequency regulation control model establishing unit establishes the linear primary frequency regulation control model of the power system under the dynamic frequency response constraint of the power system and the primary frequency regulation reserve constraint of the generator set. The power shortage, the maximum climbing rate of each generator set and the load damping coefficient are input into the linear primary frequency regulation control model of the power system. The linear primary frequency regulation control model of the power system outputs the lowest frequency point.

[0177] The maximum frequency control capability calculation and high-risk unit identification unit calculates the maximum frequency control capability of the power system composed of the remaining online generator sets after each generator set trips according to the lowest frequency point, and compares it with the maximum output power of the generator set. When the maximum output power of the generator set is greater than the maximum frequency control capability of the remaining power system after the corresponding unit trips, the generator set is identified as a high-risk unit that may cause the system frequency to lose stability after a trip.

[0178] The pre-correction optimization dispatching model establishing unit establishes a new power system pre-correction optimization dispatching model under the frequency safety constraint after the high-risk unit tripping fault based on the N-1 frequency safety criterion, and inputs the power generation cost and primary frequency regulation reserve cost of the coal-fired power unit and the power generation cost of the new energy unit into the new power system pre-correction optimization dispatching model. The new power system pre-correction optimization dispatching model outputs the output power of each coal-fired power unit and the primary frequency regulation reserve to be reserved before the fault and the output power of the new energy unit as control instructions to achieve optimal dispatch of the online power generating units.

[0179] Regarding the device in the above embodiment, the specific manner in which each module performs operations has been described in detail in the embodiment of the method, and will not be elaborated here.

[0180] For the device embodiment, since it basically corresponds to the method embodiment, the relevant parts can refer to the partial description of the method embodiment. The device embodiment described above is only schematic, in which the units described as separate components may or may not be physically separated, and the components displayed as units may or may not be physical units, that is, they may be located in one place, or they may be distributed on multiple network units. Some or all of the modules can be selected according to actual needs to achieve the purpose of the scheme of the present invention. Ordinary technicians in this field can understand and implement it without paying creative work.

[0181] Correspondingly, the present invention also provides an electronic device, comprising: one or more processors; a memory for storing one or more programs; when the one or more programs are executed by one or more processors, the one or more processors implement the high-risk unit identification and scheduling method based on the N-1 frequency safety criterion as described above.

[0182] Accordingly, the present invention also provides a computer-readable storage medium having computer instructions stored thereon, which, when executed by a processor, implements a high-risk unit identification and scheduling method based on the N-1 frequency safety criterion as described above.

[0183] Those skilled in the art will readily appreciate other embodiments of the present application after considering the specification and practicing the disclosure disclosed herein. The present application is intended to cover any modification, use or adaptation of the present application, which follows the general principles of the present application and includes common knowledge or customary techniques in the art that are not disclosed in the present application. The specification and examples are intended to be exemplary only, and the true scope and spirit of the present application are indicated by the following claims.

[0184] It should be understood that the present application is not limited to the precise structures that have been described above and shown in the drawings, and that various modifications and changes may be made without departing from the scope thereof. The scope of the present application is limited only by the appended claims.

Claims

1. A high-risk unit identification and scheduling method based on N-1 frequency safety criteria, characterized in that: include: S1: A linear primary frequency regulation control model of the power system is established under the constraints of the dynamic frequency response of the power system and the primary frequency regulation reserve of the generator set. The power shortage of the power system, the limit climbing rate of each generator set and the load damping coefficient are input into the linear primary frequency regulation control model of the power system. After processing, the linear primary frequency regulation control model of the power system outputs the lowest frequency point of the power system after the generator set trips; S2: According to the lowest frequency point of the power system after the generator set trips, the maximum frequency control capability of the remaining online generator sets after each generator set trips in the power system is obtained, and compared with the maximum output power of the tripped generator set, so as to identify high-risk units; S3: Based on the N-1 frequency safety criterion, a new power system pre-correction optimization dispatching model is established under frequency safety constraints after a high-risk unit tripping fault. The power generation cost and primary frequency regulation reserve cost of the coal-fired power units in the power system and the power generation cost of the new energy units are input into the new power system pre-correction optimization dispatching model. After processing, the new power system pre-correction optimization dispatching model outputs the output power of each coal-fired power unit and the primary frequency regulation reserve to be reserved before the fault and the output power of the new energy unit as control instructions to achieve optimal dispatch of the power system's power generating units.

2. The high-risk unit identification and scheduling method based on the N-1 frequency safety criterion according to claim 1 is characterized in that: In step S1, the linear primary frequency modulation control model of the power system is specifically as follows: Where M represents a constant parameter; f nadir and t nadir They represent the lowest frequency point and time of the power system after the generator set trips, b and w respectively. b They represent the time t when the frequency of the power system reaches the lowest point after the generator set trips. nadir The bits in the binary expansion of and its binary variant, Indicates the time t when the frequency of the power system reaches the lowest point after the generator set trips nadir The set of bits in the binary expansion of b represents auxiliary variables, z b =w b P def , P def represents the power shortage of the power system; f0 represents the system reference frequency at time t; H represents the inertia of the power system, that is, the sum of the inertia of each generator set in the power system. The generator sets in the power system include coal-fired power units and new energy units.

3. The high-risk unit identification and scheduling method based on the N-1 frequency safety criterion according to claim 2 is characterized in that: In step S1, the dynamic frequency response constraints of the power system are specifically as follows: Where D represents the load damping coefficient; C equ Represents the equivalent aggregate ramp rate of all coal-fired power units.

4. The high-risk unit identification and scheduling method based on the N-1 frequency safety criterion according to claim 2 is characterized in that: In step S1, the primary frequency regulation standby constraints of the generator set are specifically as follows: a) Basic constraints for primary frequency regulation standby: Among them, R i , and They represent the primary frequency regulation reserve reserved before the failure of the i-th generator set in the power system, its emergency primary frequency regulation reserve and the restored primary frequency regulation reserve respectively; b) Climbing rate constraint: in, represents the limit ramp rate of the i-th generator set in the power system; c) Emergency primary frequency regulation reserve constraints: d) Power balance constraint at the lowest frequency point: Where n represents the total number of generator sets in the power system; e) Restore the primary frequency regulation standby constraint:

5. The high-risk unit identification and scheduling method based on the N-1 frequency safety criterion according to claim 2 is characterized in that: In step S2, the maximum frequency regulation control capability of the power system is as follows: in, It represents the maximum frequency control capability of the remaining online generator sets after the jth generator set in the power system trips; D represents the load damping coefficient; Represents the limit ramp rate of the i-th generator set in the power system.

6. The high-risk unit identification and scheduling method based on the N-1 frequency safety criterion according to claim 2 is characterized in that: In step S2, the maximum frequency regulation control capability of the remaining online generator sets after each generator set in the power system trips and the maximum output power of the generator set are compared to identify high-risk generator sets, as follows: For each coal-fired power unit in the power system, the maximum frequency control capability of the remaining online generating units after the coal-fired power unit trips is compared with the maximum output power of the tripped coal-fired power unit. If the maximum frequency control capability of the remaining online generating units after the coal-fired power unit trips is less than the maximum output power of the coal-fired power unit, the current coal-fired power unit is determined to be a high-risk unit. For each new energy unit in the power system, when the new energy unit satisfies the following formula: in, represents the output power of the jth renewable energy unit; represents the maximum frequency regulation control capability of the power system when there is no j-th renewable energy unit; D represents the load damping coefficient; represents the limit ramp rate of the i-th generator set in the power system; The current new energy units are judged as high-risk units.

7. The high-risk unit identification and scheduling method based on the N-1 frequency safety criterion according to claim 2 is characterized in that: In step S3, the new power system pre-correction optimization dispatch model is specifically as follows: F3(R i )=d i R i Among them, U coal and U res They represent the collection of coal-fired power units and new energy units respectively; F1() represents the power generation cost of the i-th coal-fired power unit, P i represents the output power of the i-th coal-fired power unit; F2() represents the power generation cost of the j-th new energy unit, represents the output power of the jth renewable energy unit; F3() represents the primary frequency regulation reserve cost of the i-th coal-fired power unit, R i represents the primary frequency regulation reserve reserved before the failure of the i-th coal-fired power unit; a i , b i and c i They represent the quadratic term parameter, linear term parameter and constant term parameter of the power generation cost of the i-th coal-fired power unit respectively; and They represent the linear parameter and constant parameter of the power generation cost of the j-th renewable energy unit respectively; d i represents the proportionality coefficient; The power generation cost of coal-fired power units in the power system includes the quadratic term parameter a of the power generation cost of the i-th coal-fired power unit i , first-order parameter b i and constant parameter c i The power generation cost of the new energy unit includes the first-order parameter of the power generation cost of the j-th new energy unit and constant term parameters 8. The high-risk unit identification and scheduling method based on the N-1 frequency safety criterion according to claim 7 is characterized in that: In step S3, the frequency safety constraints are specifically as follows: a) Power balance constraints of coal-fired power units and new energy units: Among them, P load,n represents the load power of the nth node in the power system; b) N-1 frequency safety constraints after high-risk coal-fired power units trip fault: in, and Respectively represent the maximum and minimum output power of the i-th coal-fired power unit; and They represent the primary frequency regulation reserve after the tripping fault of the i-th coal-fired power unit, its emergency primary frequency regulation reserve and the recovery primary frequency regulation reserve respectively; represents the maximum primary frequency regulation reserve of the i-th coal-fired power unit; H B Represents a collection of high-risk coal-fired power units; represents the limit ramp rate of the i-th generator set in the power system; Indicates the time when the frequency reaches the lowest point after the generator set trips; It indicates the power shortage after the power system trips; D indicates the load damping coefficient; Indicates the time when the frequency reaches the lowest point after the generator set trips The binary variable of bit b in the binary expansion of ; Indicates the trip fault auxiliary variable; H k Represents the inertia of each remaining generating unit in the power system after the coal-fired generating unit trips; RoCoF max Indicates the maximum frequency change rate allowed in the power system; c) N-1 frequency safety constraints after high-risk renewable energy units trip: in, and Respectively represent the minimum and maximum output power of the j-th renewable energy unit; H j Represents the inertia of the j-th new energy unit.

9. An electronic device, characterized in that: include: A memory and a processor coupled to each other, wherein the memory stores program data, and the processor calls the program data to execute the method according to any one of claims 1 to 8.

10. A computer-readable storage medium having program data stored thereon, characterized in that: When the program data is executed by a processor, the method according to any one of claims 1 to 8 is implemented.

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