A method for identifying and scheduling high-risk units based on the N-1 frequency security criterion

Abstract

The present invention discloses a method for identifying and dispatching high-risk units based on the N-1 frequency security criterion. The method includes: establishing a linear primary frequency control model of the power system under the constraints of the dynamic frequency response of the power system and the primary frequency regulation reserve of the generating units, and then obtaining the lowest frequency point of the power system after a tripping fault; obtaining the maximum frequency modulation control ability of the power system after the tripping fault based on the lowest frequency point, and comparing it with the maximum output power of the tripping generating unit, so as to identify high-risk units; establishing a new power system pre-correction optimization dispatch model under the frequency security constraint after the high-risk unit trips based on the N-1 frequency security criterion, and then obtaining the output power of each generating unit and the primary frequency regulation reserve reserved before the fault as control instructions to realize the optimal dispatch of the power system. The method of the present invention can realize the optimal configuration of on-line units on the premise of avoiding the loss of stability of the frequency of the new power system caused by any generator tripping fault.

Description

Technical Field

[0001] The present invention relates to a unit scheduling method, belonging to the technical field of stable operation of power systems, and particularly relates to a high-risk unit identification and scheduling method based on the N-1 frequency security 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, thereby causing the new power system to face the risk of frequency instability. In addition, due to the influence of factors such as weather, the power generation power of new energy units may fluctuate violently, which will further exacerbate 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] Generally, generator units are scheduled regularly to ensure that the frequency of the power system can remain stable when any generator unit trips. According to the traditional N-1 frequency security criterion, the fault scale is usually considered to be the key factor affecting the frequency stability of the power system. Therefore, in the traditional power system scheduling method, the tripping of the generator unit with the maximum output power is regarded as the most serious fault. However, with the continuous grid connection of renewable energy and fast-response devices, the frequency response characteristics of generator units and their contributions to the system inertia have become more diverse. In this case, the generator unit with the maximum output power cannot be simply regarded as a high-risk unit, because after a fault occurs, the dynamic frequency response characteristics of the system are jointly affected by the fault scale and the frequency modulation control ability of the remaining power system. Therefore, it is urgent to model the quantitative relationship between the fault scale, the frequency modulation control ability of the remaining power system, and the dynamic frequency response characteristics of the system under primary frequency modulation control, and then develop a high-risk unit identification method and a unit optimal scheduling method to avoid potential frequency instability risks. Summary of the Invention

[0004] In order to solve the problems in the background art, the present invention provides a high-risk unit identification and scheduling method based on the N-1 frequency security criterion. The method of the present invention solves the pre-corrective optimization scheduling technical problem of maintaining the system frequency stability when the power system under the combined influence of low inertia and strong fluctuations encounters the most serious fault, and provides technical support for the stable operation of the new power system under low inertia.

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

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

[0007] S1: Establish a linear primary frequency control model of the power system under the constraints of the dynamic frequency response of the power system and the primary frequency regulation reserve of the generating units. Input the power shortage of the power system, the ultimate ramp rate of each generating unit, and the load damping coefficient into the linear primary frequency control model of the power system. After processing by the linear primary frequency control model of the power system, the lowest frequency point of the power system after the generating unit trips is output.

[0008] S2: Obtain the maximum frequency regulation control ability of the remaining online generating units in the power system after each generating unit trips according to the lowest frequency point of the power system after the generating unit trips, and compare it with the maximum output power of the tripped generating unit, so as to identify high-risk units.

[0009] S3: Based on the N-1 frequency security criterion, establish a new pre-corrective optimal dispatching model of the power system under frequency security constraints after the high-risk unit trips. Input the generation cost and primary frequency regulation reserve cost of the coal-fired generating units in the power system and the generation cost of the new energy generating units into the new pre-corrective optimal dispatching model of the power system. After processing by the new pre-corrective optimal dispatching model of the power system, the output power of each coal-fired generating unit, the primary frequency regulation reserve to be reserved before the fault, and the output power of the new energy generating units are output as control instructions to realize the optimal dispatching of the generating units in the power system.

[0010] The cost can be specifically measured by the generation power.

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

[0012]

[0013] Among them, M represents a very large constant parameter; f nadir and t nadir respectively represent the lowest frequency point of the power system after the generating unit trips and its time. b and w b respectively represent the bit in the binary expansion of the time t nadir of the lowest frequency point of the power system after the generating unit trips and its binary variable. represents the set of bits in the binary expansion of the time t nadir of the lowest frequency point of the power system after the generating unit trips; z b represents an auxiliary variable, z b = w b P def , P def represents the power shortage of the power system; f 0represents the system reference frequency at time t; H represents the inertia of the power system, that is, the sum of the inertias of each generator set in the power system. The generator sets in the power system include two types: coal-fired generator sets and new energy generator sets.

[0014] In the step S1 mentioned above, the dynamic frequency response constraint of the power system is specifically as follows:

[0015]

[0016] Among them, D represents the load damping coefficient, that is, the load power change caused by every 1% system frequency deviation; C equ represents the equivalent aggregated ramp rate of all coal-fired generator sets.

[0017] In the step S1 mentioned above, the primary frequency regulation reserve constraint of the generator set is specifically as follows:

[0018] The lowest frequency point f after the generator set trips and fails nadir is only related to the primary frequency regulation reserve released before t nadir and has nothing to do with the primary frequency regulation reserve released after t nadir Therefore, the primary frequency regulation reserve R i required by the generator set i to cope with the fault is divided into two parts, namely, the emergency primary frequency regulation reserve and the restoration primary frequency regulation reserve They respectively represent the primary frequency regulation reserve released by the generator set i before and after t nad The restoration primary frequency regulation reserve is used to restore the frequency to a new stable state after reaching the lowest point. The emergency primary frequency regulation reserve and the restoration primary frequency regulation reserve need to meet the following constraint conditions:

[0019] a) Primary frequency regulation reserve basic constraint:

[0020] By distinguishing the emergency primary frequency regulation reserve and the restoration primary frequency regulation reserve Furthermore, the fast-response generator sets with higher costs are concentrated on providing the emergency primary frequency regulation reserve, while the slow-response generator sets with lower costs are concentrated on providing the restoration primary frequency regulation reserve. The emergency primary frequency regulation reserve and the restoration primary frequency regulation reserve together form the primary frequency regulation reserve R i to be reserved before the fault. Therefore, there is:

[0021]

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

[0023] b) Ramp rate constraint:

[0024] The emergency primary frequency regulation reserve of generating unit i shall always satisfy the constraint of ramp rate adequacy, that is:

[0025]

[0026] where represents the ultimate ramp rate of the i-th generating unit in the power system.

[0027] represents the maximum output power that the i-th generating unit can increase before t nadir The meaning of this constraint is that when the ramp rate of generating unit i is low, even if there is enough primary frequency regulation reserve, the generating unit cannot provide enough active power compensation before t nadir before.

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

[0029] Power system operators shall reserve a certain amount of primary frequency regulation reserve before the fault to cope with potential frequency instability risks. Assume that the emergency primary frequency regulation reserve that generating unit i needs to provide at time t nadir is and its ramp rate is To ensure the system frequency safety after the generating unit trips, the sum of the ramp rates of all online coal-fired generating units shall be greater than the equivalent aggregated ramp rate C equ , and in addition, it shall be limited by the ultimate ramp rate and not greater than Therefore, there is:

[0030]

[0031] The emergency primary frequency regulation reserve constraint establishes the connection between the system equivalent aggregated ramp slope C eq and the single-unit ultimate ramp rate (related to the emergency primary frequency regulation reserve).

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

[0033] At time t nadir , the coal-fired generating unit provides of active power output to compensate for the power deficit. At this time, the frequency-sensitive load reduces by D(f 0 -f nadir)'s active power output. Therefore, the power balance constraint at the lowest frequency point can be expressed as:

[0034]

[0035] where n represents the total number of generating units in the power system.

[0036] e) Restoration of primary frequency regulation reserve constraint:

[0037] When constraints a) - d) are satisfied, the lowest system frequency point will be restricted within the allowed range. In addition, when there is sufficient restoration of primary frequency regulation reserve, the coal-fired generating units will continue to increase their output power after t nadir At this time, the system frequency gradually rises from the lowest point to a new steady state, i.e., the quasi-steady state frequency. Therefore, to meet the adequacy of primary frequency regulation reserve, the total primary frequency regulation reserve of the system should be greater than the power deficit P def in the generating unit tripping fault, that is:

[0038]

[0039] In the step S2 described above, the maximum frequency regulation control ability of the power system is specifically as follows:

[0040]

[0041] where represents the maximum frequency regulation control ability of the remaining online generating units after the j-th generating unit tripping fault in the power system; D represents the load damping coefficient; represents the limit ramp rate of the i-th generating unit in the power system.

[0042] In the step S2 described above, the maximum frequency regulation control ability of the remaining online generating units after each generating unit tripping fault in the power system is compared with the maximum output power of the generating units, so as to identify high-risk units, specifically as follows:

[0043] To ensure N-1 frequency security, power system operators usually need to verify the frequency regulation control ability of the power system composed of the remaining online generating units after each generating unit fault. Therefore, it is necessary to use the output power of the generating units in all fault cases as decision variables in the optimal dispatch problem. However, this will seriously increase the computational burden on the processor, making it difficult to apply in large-scale power systems with a large number of coal-fired generating units. In response to this, this method identifies high-risk units in the online units by simultaneously considering the fault scale and the maximum frequency regulation control ability of the remaining power system. The high-risk unit identification method proposed in the present invention is divided into two categories:

[0044] For each coal-fired power generation unit in the power system, compare the maximum frequency regulation control capacity of the remaining online power generation units after the tripping fault of the coal-fired power generation unit with the maximum output power of the tripped coal-fired power generation unit. If the maximum frequency regulation control capacity of the remaining online power generation units after the tripping fault of the coal-fired power generation unit is less than the maximum output power of the coal-fired power generation unit, then determine that the current coal-fired power generation unit is a high-risk unit that may cause the power system frequency to lose stability after the tripping fault.

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

[0046]

[0047] where, represents the output power of the j-th new energy unit; represents the maximum frequency regulation control capacity of the power system without the j-th new energy unit; D represents the load damping coefficient; represents the ultimate ramp rate of the i-th power generation unit in the power system.

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

[0049] Since the new energy unit may have significant power fluctuations within a dispatching period, it usually does not need to provide primary frequency regulation reserve to respond to the change of the system frequency. In addition, to avoid the frequency being lower than the allowable lower limit value after the tripping fault of the new energy unit, the output of any new energy unit should always not satisfy the above formula; by calculating the The power system operator can obtain the maximum output power of the new energy unit under the current operating state of the system, so that the new energy unit can adaptively meet the N-1 frequency security criterion.

[0050] In the step S3, the specific form of the new power system pre-correction optimization dispatching model is as follows:

[0051]

[0052] F 3 (R i ) = d i R i

[0053] where, U coal and U res represent the sets of coal-fired power generation units and new energy units respectively; F 1 () represents the generation cost of the i-th coal-fired power generation unit, P i represents the output power of the i-th coal-fired power generation unit; F 2() represents the power generation cost of the j-th new energy unit, represents the output power of the j-th new energy unit; F 3 () 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 fault of the i-th coal-fired power unit; a i , b i and c i respectively 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; and respectively represent the linear term parameter and constant term parameter of the power generation cost of the j-th new energy unit; d i represents the proportionality coefficient.

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

[0055] In the step S3 described above, the frequency security constraint is specifically as follows:

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

[0057]

[0058] Among them, P load,n represents the load power of the n-th node in the power system.

[0059] b) N-1 frequency security constraint after the tripping fault of high-risk coal-fired power units:

[0060]

[0061] Among them, and respectively represent the maximum and minimum output powers of the i-th coal-fired power unit; and respectively represent the primary frequency regulation reserve and its emergency primary frequency regulation reserve and restoration primary frequency regulation reserve after the tripping fault of the i-th coal-fired power unit; represents the maximum primary frequency regulation reserve of the i-th coal-fired power unit; H B represents the set of high-risk coal-fired power units; represents the limit ramp rate of the i-th generating unit in the power system; Denotes the time of the lowest frequency point after the generator set trips, and all The expanded bits are consistent; Denotes the power deficit after the power system trips, and its value is equal to the output power of generator set i, i.e., D denotes the load damping coefficient; Denotes the time of the lowest frequency point after the generator set trips The binary variable of bit b in the binary expansion of Denotes the trip fault auxiliary variable; H k Denotes the inertia of each remaining generator set in the power system after the coal-fired generator set trips; RoCoF max Denotes the maximum allowable frequency change rate of 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 at the initial stage of the trip, thus affecting the safe and stable operation of the system.

[0062] c) N-1 frequency safety constraint after the high-risk new energy generator set trips:

[0063]

[0064] Among them, And Respectively denote the minimum and maximum output powers of the jth new energy generator set; H j Denotes the inertia of the jth new energy generator set; The output power of any new energy generator set will always be limited by the maximum frequency modulation control ability Of, Will be updated according to the current operating state of the power system in each scheduling cycle.

[0065] The electronic device of the present invention includes: 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 as described above is implemented.

[0067] Based on quantitatively analyzing the relationship among the power deficit related to the fault scale, the unit's ultimate ramp rate, the lowest post-fault frequency point and its arrival time, the method of the present invention defines an inherent property of the power system, i.e., the maximum frequency modulation control ability, based on the system operation parameters, to characterize the maximum ability of the current system to compensate for the power deficit and control the system frequency without triggering the under-frequency load shedding relay protection device. Then, by comparing the capacity of the generating unit with the maximum frequency modulation control ability of the remaining power system after its tripping fault, the potential high-risk units that may cause the system frequency to become unstable after the tripping fault are identified. On this basis, a new type of power system pre-correction optimization scheduling model is established accordingly. This model distinguishes the N-1 frequency security constraints after the tripping faults of high-risk coal-fired generating units and high-risk new energy generating units, and outputs the output power and primary frequency modulation reserve of the on-line generating units as control commands by solving the model, finally realizing the optimal allocation of resources of the on-line units and the formulation of the generation plan.

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

[0069] 1) By analyzing the quantitative relationship among the fault scale, the unit's ultimate ramp rate, the lowest post-fault frequency point and its arrival time, the present invention establishes a linear primary frequency modulation control model of the power system under the constraints of the power system dynamic frequency response and the primary frequency modulation reserve of the generating unit. This model can closely combine the non-linear dynamic primary frequency modulation control process after the unit tripping fault into the unit optimal scheduling problem, so as to realize the optimal allocation of the on-line generating units on the premise of keeping the frequency stable when the system responds to the unit tripping fault.

[0070] 2) The present invention defines the maximum frequency modulation control ability of the power system, that is, the maximum power deficit that the power system can withstand without violating the system minimum frequency limit after a sudden tripping fault. On this basis, the maximum output power of the generating unit is compared with the maximum frequency modulation control ability of the remaining power system after its tripping fault, so that potential high-risk units that may cause the system frequency to become unstable after the tripping fault can be identified before formulating the system pre-correction optimization scheduling plan, realizing the supplement to the traditional N-1 frequency security criterion in the new power system with low inertia, and thus greatly reducing the calculation burden of the unit optimal scheduling problem, especially in a large-scale power system containing a large number of coal-fired generating units.

[0071] 3) The present invention formulates two different types of N-1 frequency security constraints and corresponding new power system pre-corrective optimization scheduling models according to the frequency response characteristics of high-risk coal-fired power generation units and high-risk new energy power generation units. Among them, the coal-fired power generation units can take preventive corrective measures in advance for any coal-fired power generation unit tripping fault according to the established scheduling model to cope with the risk of power system frequency instability in the case of all coal-fired power generation unit tripping faults. The new energy power generation units can calculate the maximum frequency modulation control ability of the remaining power system after the fault in each scheduling period, so as to obtain the maximum output power under the current operating state, and make the new energy power generation units adaptively meet the N-1 frequency security criterion.

[0072] The present invention can realize the resource optimization allocation and power generation plan formulation of on-line coal-fired power generation units on the premise of avoiding the loss of stability of the new power system frequency caused by any generator tripping fault, and at the same time enable the new energy power generation units to adaptively meet the N-1 frequency security criterion, providing technical support for the stable operation of the new power system under low inertia. Brief Description of the Drawings

[0073] Figure 1 is the flowchart of the method of the present invention;

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

[0075] Figure 3 is the comparison diagram of the output power of on-line units and the maximum frequency modulation control ability in Scenario 1 shown according to an exemplary embodiment;

[0076] Figure 4 is the comparison diagram of the output power of on-line units and the maximum frequency modulation control ability in Scenario 2 shown according to an exemplary embodiment;

[0077] Figure 5 is the dynamic frequency response curve diagram of the unit scheduling method based on the traditional N-1 frequency security criterion and the proposed method shown according to an exemplary embodiment. Detailed Embodiment

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

[0079] As Figure 1 shown, the purpose of the embodiment of the present invention is to provide a method for identifying and scheduling high-risk units based on the N-1 frequency security criterion to solve the pre-corrective optimization scheduling technical problem of maintaining the system frequency stability when the power system copes with the most serious faults under the combined influence of low inertia and strong fluctuations. The method includes the following steps:

[0080] S1: Establish a linear primary frequency control model of the power system under the constraints of the dynamic frequency response of the power system and the primary frequency regulation reserve of the generating units. Input the power deficit of the power system, the ultimate ramp rate of each generating unit, and the load damping coefficient into the linear primary frequency control model of the power system. After being processed by the linear primary frequency control model of the power system, the lowest frequency point of the power system after the generating unit tripping fault is output.

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

[0082]

[0083] Among them, M represents a constant parameter with a very large value; f nadir and t nadir respectively represent the lowest frequency point of the power system after the generating unit tripping fault and its time. b and w b respectively represent the bit in the binary expansion of the time t nadir of the lowest frequency point of the power system after the generating unit tripping fault and its binary variable. represents the set of bits in the binary expansion of the time t nadir of the lowest frequency point of the power system after the generating unit tripping fault; z b represents an auxiliary variable, z b = w b P def , P def represents the power deficit of the power system; f 0 represents the system reference frequency at time t; H represents the inertia of the power system, that is, the sum of the inertias of each generating unit in the power system. The generating units in the power system include two types: coal-fired generating units and new energy generating units.

[0084] To further linearize the dynamic frequency response constraint and the emergency primary frequency regulation reserve constraint of the power system into an optimizable and schedulable linear primary frequency control model of the power system, the present invention uses binary expansion and the big M method to approximate it. First, perform binary expansion on t nadir , and then substitute it into the dynamic frequency response constraint of the power system together with the power balance constraint at the lowest frequency point and the constraint for restoring the primary frequency regulation reserve, and we can get:

[0085]

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

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

[0088]

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

[0090] For the power deficit P def caused by the tripping fault of the generating unit in the power system, the coal-fired generating units reserved for primary frequency regulation can respond to the system frequency deviation through the droop control of the governor 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 corresponding time of the frequency lowest point is recorded as t nadir , the power deficit P def will be completely compensated by the power increment ΔP(t nadir ) of the coal-fired generating unit and the reduced load power D(f 0 -f nadir ). After that, the coal-fired generating unit continues to increase the output power, and the system frequency starts to rise from f nadir until a new stable state is reached. The above dynamic frequency response process of the power system can be quantitatively expressed as:

[0091]

[0092] Among them, f(t) represents the system frequency at time t; ΔP(t) represents the power increment of the coal-fired generating unit at time t. Integrating both sides of the equation from time 0 to t nadir , the lowest frequency point can be obtained as:

[0093]

[0094] It should be noted that the output power increment ΔP(t) of all coal-fired generating units mainly depends on the control parameters of the governors of each coal-fired generating unit, and it changes non-linearly with time. In this regard, the present invention approximates and equivalentizes it with a virtual generating unit with a constant ramp rate, that is

[0095]

[0096] C equ The value of is only related to t nadir and is constant. Therefore is a variable independent of time t and is equivalent to a virtual generating unit with a constant ramp rate of C equThe energy increased by the generating unit at time t nadir is as follows.

[0097] The energy increased by the frequency-sensitive load due to the load damping effect is the linearized load damping effect. The following approximation is made:

[0098]

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

[0100] The power system dynamic frequency response constraints establish a quantitative relationship between the power deficit P def related to the fault scale, the lowest frequency point f nadir equivalent aggregated ramp rate C equ and the lowest frequency time t nadir from the entire power system level.

[0101] The primary frequency regulation reserve constraints of the generating units are as follows:

[0102] The lowest frequency point f nadir after the generating unit trips is only related to the primary frequency regulation reserve released before time t nadir and has nothing to do with the primary frequency regulation reserve released after time t nadir Therefore, the primary frequency regulation reserve R i required by generating unit i to cope with the fault is divided into two parts, namely the emergency primary frequency regulation reserve and the restoration primary frequency regulation reserve They represent the primary frequency regulation reserve released by generating unit i before and after time t nad respectively. The restoration primary frequency regulation reserve is used to restore the frequency to a new stable state after reaching the lowest point. The operation of the emergency primary frequency regulation reserve and the restoration primary frequency regulation reserve needs to meet the following constraint conditions:

[0103] a) Basic constraint of primary frequency regulation reserve:

[0104] By distinguishing the emergency primary frequency regulation reserve and the restoration primary frequency regulation reserve it further enables the fast-response generating units with higher costs to concentrate on providing the emergency primary frequency regulation reserve, while the slow-response generating units with lower costs concentrate on providing the restoration primary frequency regulation reserve. The emergency primary frequency regulation reserve and the restoration primary frequency regulation reserve Together, they form the primary frequency regulation reserve R to be reserved before a fault i . Therefore, we have:

[0105]

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

[0107] b) Ramp rate constraint:

[0108] The emergency primary frequency regulation reserve of generating unit i shall always satisfy the constraint of ramp rate adequacy, that is:

[0109]

[0110] Among them, represents the ultimate ramp rate of the i-th generating unit in the power system;

[0111] represents the maximum output power that the i-th generating unit can increase before t nadir . The meaning of this constraint is that when the ramp rate of generating unit i is low, even if there is enough primary frequency regulation reserve, the generating unit cannot provide enough active power compensation before t nadir .

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

[0113] The power system operator shall reserve a certain amount of primary frequency regulation reserve before a fault to cope with potential frequency instability risks. Assume that the emergency primary frequency regulation reserve that generating unit i needs to provide at time t nadir is and its ramp rate is To ensure the system frequency safety after the generating unit trips, the sum of the ramp rates of all online coal-fired generating units shall be greater than the equivalent aggregated ramp rate C equ , and in addition, it shall not be greater than the limit ramp rate Therefore, we have:

[0114]

[0115] The emergency primary frequency regulation reserve constraint establishes the connection between the system equivalent aggregated ramp slope C eq and the single-unit ultimate ramp rate (related to the emergency primary frequency regulation reserve).

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

[0117] At time t nadir , the coal-fired power unit provides of active power output to compensate for the power deficit. At this time, the frequency-sensitive load reduces its active power output by D(f 0 - f nadir ). Therefore, the power balance constraint at the lowest frequency point can be expressed as:

[0118]

[0119] where n represents the total number of generating units in the power system.

[0120] e) Restoration of primary frequency regulation reserve constraint:

[0121] When constraints a) - d) are satisfied, the lowest system frequency point will be restricted within the allowable range. In addition, when there is sufficient restoration of primary frequency regulation reserve, the coal-fired power unit will continue to increase its output power after t nadir . At this time, the system frequency gradually rises from the lowest point to a new stable state, i.e., the quasi-steady state frequency. Therefore, to meet the adequacy of primary frequency regulation reserve, the total primary frequency regulation reserve of the system should be greater than the power deficit P def in the generating unit tripping fault, i.e.:

[0122]

[0123] S2: Obtain the maximum frequency regulation control ability of each remaining online generating unit in the power system after the generating unit tripping fault according to the lowest frequency point of the power system after the generating unit tripping fault, and compare it with the maximum output power of the tripped generating unit, so as to identify high-risk units.

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

[0125]

[0126] where represents the maximum frequency regulation control ability of the remaining online generating units after the j-th generating unit tripping fault in the power system; D represents the load damping coefficient; represents the limit ramp rate of the i-th generating unit in the power system.

[0127] This method aims to minimize the total operating cost without violating the system minimum frequency limit, and the system minimum frequency limit is usually set to 49.5 Hz. Therefore, to minimize the total operating cost, the system needs to operate in a critical state, that is, the lowest frequency point after the generating unit tripping fault is 49.5 Hz, i.e., f nadir= 49.5 Hz. In this regard, the maximum frequency regulation control ability of the power system is defined as: the maximum power deficit that the power system can withstand without violating the system's minimum frequency limit after a sudden tripping fault The specific calculation process is as follows:

[0128] First, sum both sides of the ramp rate constraint of the remaining online generating units except the j-th tripped generating unit, and we can get:

[0129]

[0130] Combining 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 restoration of primary frequency regulation reserve constraint, and the power system dynamic frequency response constraint can eliminate t nadir , and we get:

[0133]

[0134] The maximum P that satisfies this constraint bef is the maximum power deficit that the system can withstand after the j-th generating unit trips Solving according to the parabola characteristic, the above-mentioned maximum frequency regulation control ability of the power system can be obtained. It is only related to the operating parameters of the system, such as the system inertia H, the unit's limit ramp rate the load damping coefficient D, which quantitatively describes the maximum ability of the current system to compensate for power deficits and control system frequency without violating the system's minimum frequency limit, and is an inherent attribute of the power system.

[0135] Compare the maximum frequency regulation control ability of the remaining online generating units and the maximum output power of the generating units after each generating unit in the power system trips, so as to identify high-risk units, specifically as follows:

[0136] To ensure N-1 frequency security, power system operators usually need to verify the frequency regulation control ability of the power system composed of the remaining online generating units after each generating unit fails. Therefore, it is necessary to use the output power of the generating units in all fault cases as decision variables in the optimal dispatch problem. However, this will seriously increase the computational burden of the processor, making it difficult to apply in large-scale power systems with a large number of coal-fired generating units. In this regard, this method identifies high-risk units in online units by simultaneously considering the fault scale and the maximum frequency regulation control ability of the remaining power system. The high-risk unit identification methods proposed in this invention are divided into two categories:

[0137] For each coal-fired generating unit in the power system, compare the maximum frequency regulation control capacity of the remaining online generating units after the tripping fault of the coal-fired generating unit with the maximum output power of the tripped coal-fired generating unit. If the maximum frequency regulation control capacity of the remaining online generating units after the tripping fault of the coal-fired generating unit is less than the maximum output power of the coal-fired generating unit, then determine that the current coal-fired generating unit is a high-risk unit that may cause the power system frequency to lose stability after the tripping fault.

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

[0139]

[0140] where, represents the output power of the j-th new energy generating unit; represents the maximum frequency regulation control capacity of the power system without the j-th new energy generating unit; D represents the load damping coefficient; represents the ultimate ramp rate of the i-th generating unit in the power system.

[0141] Then determine that the current new energy generating unit is a high-risk unit that may cause the power system frequency to lose stability after the tripping fault.

[0142] Since the new energy generating unit may have significant power fluctuations within a scheduling period, it usually does not need to provide primary frequency regulation reserve to respond to the change of the system frequency. In addition, to avoid the frequency dropping below the allowable lower limit value after the tripping fault of the new energy generating unit, the output of any new energy generating unit should always not satisfy the above formula; by calculating the Power system operators can obtain the maximum output power of the new energy generating unit under the current operating state of the system, so that the new energy generating unit can adaptively meet the N-1 frequency security criterion.

[0143] S3: Based on the N-1 frequency security criterion, establish a new power system pre-correction optimal scheduling model under frequency security constraints after the tripping fault of high-risk units. Input the generation cost and primary frequency regulation reserve cost of the coal-fired generating units in the power system and the generation cost of the new energy generating units into the new power system pre-correction optimal scheduling model. After being processed by the new power system pre-correction optimal scheduling model, the output is the output power of each coal-fired generating unit, the primary frequency regulation reserve to be reserved before the fault, and the output power of the new energy generating units as control commands to realize the optimal scheduling of the generating units in the power system. The cost can be specifically measured by the generation power.

[0144] The new power system pre-correction optimal scheduling model is specifically as follows:

[0145]

[0146]

[0147] F 3 (R i ) = d i R i

[0148] Among them, U coal and U res respectively represent the sets of coal-fired power generation units and new energy generation units; F 1 () represents the power generation cost of the i-th coal-fired power generation unit, and P i represents the output power of the i-th coal-fired power generation unit; F 2 () represents the power generation cost of the j-th new energy generation unit, represents the output power of the j-th new energy generation unit; F 3 () represents the primary frequency regulation reserve cost of the i-th coal-fired power generation unit, and R i represents the primary frequency regulation reserve reserved before the fault of the i-th coal-fired power generation unit; a i , b i and c i respectively represent the quadratic term parameter, linear term parameter, and constant term parameter of the power generation cost of the i-th coal-fired power generation unit; and respectively represent the linear term parameter and constant term parameter of the power generation cost of the j-th new energy generation unit; d i represents the proportionality coefficient.

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

[0150] The frequency security constraints are as follows:

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

[0152]

[0153] Among them, P load,n represents the load power of the n-th node in the power system.

[0154] b) N-1 frequency security constraints after the tripping fault of high-risk coal-fired power generation units:

[0155]

[0156]

[0157] Among them, and respectively represent the maximum and minimum output powers of the i-th coal-fired power generation unit; and respectively represent the primary frequency regulation reserve, emergency primary frequency regulation reserve and restored primary frequency regulation reserve after the tripping fault of the i-th coal-fired power generation unit; represents the maximum primary frequency regulation reserve of the i-th coal-fired power generation unit; H B represents the set of high-risk coal-fired power generation units; represents the ultimate ramp rate of the i-th generating unit in the power system; represents the time of the lowest point of frequency after the tripping fault of the generating unit, and all expanded bits are consistent; represents the power deficit after the tripping fault of the power system, and its value is equal to the output power of generating unit i, that is D represents the load damping coefficient; represents the time of the lowest point of frequency after the tripping fault of the generating unit binary variable of bit b in the binary expansion of; represents the tripping fault auxiliary variable; H k represents the inertia of each remaining generating unit in the power system after the tripping fault of the coal-fired power generation unit; RoCoF max represents the maximum allowable frequency change rate of the power system. The maximum frequency change rate limit can ensure that the system has sufficient inertia after the fault to avoid a rapid drop in frequency at the initial stage of tripping, thus affecting the safe and stable operation of the system.

[0158] c) N-1 frequency safety constraint after the tripping fault of high-risk new energy generating units:

[0159]

[0160] Among them, and respectively represent the minimum and maximum output powers of the j-th new energy generating unit; H j represents the inertia of the j-th new energy generating unit; The output power of any new energy generating unit will always be limited by the maximum frequency modulation control ability of, will be updated according to the current operating state of the power system in each scheduling period.

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

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

[0163] Table 1 Operating parameters of generating units

[0164]

[0165] Table 2 Generation cost and primary frequency regulation reserve cost of generating units

[0166]

[0167]

[0168] The present invention sets three typical scenarios in Scenario 1 for the pre - corrective optimal dispatch of power systems based on N - 1 frequency security constraints. The specific scenarios are as follows: Scenario 1 (ignoring the load damping effect): The load damping effect is ignored in the N - 1 frequency security constraints; Scenario 2 (linearizing the load damping effect): The load damping effect is linearized in the N - 1 frequency security constraints; Scenario 3 (the method proposed by the present invention): The high - risk unit identification and dispatch method based on N - 1 frequency security proposed by the present invention is adopted.

[0169] Scenarios 1 - 3 are all based on optimized dispatch methods, aiming to control the lowest frequency point after the generator unit tripping fault at 49.5 Hz. In Scenario 1, to simplify the problem, the load damping effect is ignored. In Scenario 2, the influence of the load damping effect on the system's dynamic frequency response is simply linearized, and the power balance at the lowest frequency point is not considered. Therefore, neither Scenario 1 nor Scenario 2 can accurately estimate the lowest post - fault frequency of the system. This inaccuracy makes the "optimal" dispatch in Scenarios 1 and 2 no longer optimal. Scenario 3 adopts the linear primary frequency control model of the power system established by the present invention, and thus can accurately estimate the lowest post - fault frequency. As Figure 2 shown, the post - fault dynamic frequency response curves of these three scenarios after the tripping fault of the generator set with the maximum output power in Scenario 1 are compared. In addition, as shown in Table 3, due to the improvement of model accuracy, the method proposed by the present invention can significantly reduce the primary frequency regulation reserve cost, and thus reduce the total operation cost.

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

[0171]

[0172] In addition, the present invention defines the maximum frequency control ability, that is, the maximum power deficit that can be tolerated by the power system without violating the minimum frequency limit after the generator unit tripping fault. As Figure 3 shown, the output power of each type of online generator in Scenario 1 is compared with the maximum frequency control ability. Figure 3 In [figure number not provided], the maximum output power of a single generator unit is 210 MW, while the maximum frequency control ability of the remaining power system after the tripping fault of this generator unit is 236.7 MW, which is greater than 210 MW. Therefore, in Scenario 1, the tripping fault of the generator unit with the maximum output power will not cause the system frequency to be lower than the minimum frequency limit. In addition, as Figure 3 shown, the output power of any generator unit is less than its corresponding maximum frequency control ability of the remaining power system. Therefore, in Scenario 1, the dispatch results based on the traditional N - 1 frequency security criterion are consistent with those of the method proposed by the present invention.

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

[0174] As Figure 5 shown, the dynamic frequency response curves of the unit scheduling method based on the traditional N-1 frequency safety criterion and the proposed method after the tripping fault of the generator set of Category 9 in Scenario 2 are further compared. The unit scheduling method based on the traditional N-1 frequency safety criterion only focuses on the fault scale and thus cannot accurately identify the high-risk units that will cause the maximum frequency deviation after the actual tripping fault of the system. As Figure 5 shown, if the unit scheduling method proposed in the present invention, i.e., the unit scheduling method based on the improved N-1 frequency safety criterion, is adopted, the lowest point of the frequency after the unit tripping fault can be maintained above the minimum frequency limit of 49.5 Hz. At the same time, based on the maximum frequency modulation control ability analysis, the method proposed in the present invention can successfully identify high-risk coal-fired generator units and high-risk new energy units and adaptively adjust their output powers in the scheduling, thus ensuring the safe and stable system frequency in any generator set 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] A primary frequency modulation control model establishment unit establishes a linear primary frequency modulation control model of the power system under the constraints of the dynamic frequency response of the power system and the primary frequency modulation reserve of the generator sets, inputs the power deficit, the limit ramp rate of each generator set, and the load damping coefficient into the linear primary frequency modulation control model of the power system, and the linear primary frequency modulation control model of the power system outputs the lowest point of the frequency.

[0177] The maximum frequency modulation control ability calculation and high-risk unit identification unit calculates the maximum frequency modulation control ability of the power system composed of the remaining online generating units after the tripping fault of each generating unit according to the lowest frequency point, and compares it with the maximum output power of the generating unit. When the maximum output power of the generating unit is greater than the maximum frequency modulation control ability of the remaining power system after the corresponding unit tripping fault, this generating unit is identified as a high-risk unit that may cause the system frequency to lose stability after the tripping fault.

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

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

[0180] For the device embodiments, since they basically correspond to the method embodiments, the relevant parts can refer to the descriptions in the method embodiments. The device embodiments described above are only illustrative. The units described as separate components may or may not be physically separated, and the components shown as units may or may not be physical units, that is, they may be located in one place or distributed to multiple network units. Some or all of the modules can be selected according to actual needs to achieve the purpose of the solution of the present invention. Those of ordinary skill in the art can understand and implement it without creative work.

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

[0182] Correspondingly, the present invention also provides a computer-readable storage medium, on which computer instructions are stored, and when the instructions are executed by a processor, the high-risk unit identification and scheduling method based on the N-1 frequency security criterion as described above is implemented.

[0183] Other embodiments of the present application will be readily apparent to those skilled in the art upon consideration of the specification and practice of the disclosure herein. The present application is intended to cover any variations, uses, or adaptations of the present application, which follow the general principles of the present application and include known common knowledge or conventional technical means in the technical field not disclosed in the present application. The specification and examples are only regarded as exemplary, and the true scope and spirit of the present application are pointed out by the following claims.

[0184] It should be understood that the present application is not limited to the exact structures described above and shown in the drawings, and various modifications and changes can be made without departing from its scope. The scope of the present application is only limited 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 trips. 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 and the output power of the new energy unit that need to be reserved before the fault as control instructions, so as to achieve optimal dispatching of the power generation units in the power system. 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.

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 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.

3. 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 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 u-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: Among them, C equ represents the equivalent aggregate ramp rate of all coal-fired power units; d) Power balance constraint at the lowest frequency point: Where n represents the total number of generator sets in the power system; D represents the load damping coefficient; e) Restore the primary frequency regulation standby constraint:

4. 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 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.

5. 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 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.

6. 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 S3, the new power system pre-correction optimization dispatch model is specifically as follows: F3(R i )=d i R i Among them, U coa 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 7. The high-risk unit identification and scheduling method based on the N-1 frequency safety criterion according to claim 6 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.

8. 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 7.

9. 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 7 is implemented.

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