A state grid provincial multi-level dispatching operation solving method based on cooperative backup

Abstract

The present application relates to the technical field of power grid collaborative optimization, and particularly relates to a state grid-provincial multi-level dispatching operation solving method based on collaborative backup, comprising the following steps: according to each level target function participating in cross-provincial energy dispatching and backup dispatching, a multi-level dispatching model considering collaborative backup constraints is established; based on the augmented Lagrange relaxation method, the multi-level dispatching model is decomposed into sub-problems of the state dispatching level, the grid dispatching level and the provincial dispatching level; the target cascade method is used to collaboratively solve each sub-problem to obtain a globally optimal dispatching scheme. The state grid-provincial multi-level dispatching operation solving method provided by the present application can provide a reference for exploring a state grid-provincial multi-level collaborative dispatching mode by constructing a state-grid-provincial multi-level dispatching model considering a collaborative backup mechanism. In addition, by using the target cascade method for solving, both the actual power grid and the internal mechanism under each level are considered, and the optimization dispatching solving efficiency of the power system under the whole grid collaboration is improved.

Description

TECHNICAL FIELD

[0001] The present application relates to the technical field of power grid collaborative optimization, in particular to a method for solving the operation of multi-level dispatching of the State Grid and the provincial grid based on collaborative backup. BACKGROUND

[0002] New power systems are being accelerated to build, and the penetration rate of renewable energy represented by wind power and photovoltaic is rapidly increasing. Due to its inherent volatility and uncertainty, the randomness of the system net load has been significantly enhanced, which poses unprecedented challenges to the backup capacity and regulation capacity required for real-time balancing of power systems.

[0003] At present, China has built a production and operation system of "two-level market, three-level dispatching" under the market environment, with spot market and regional auxiliary service market as the main market, and national dispatching center (national dispatching), regional power grid dispatching center (grid dispatching), and provincial dispatching center (provincial dispatching) as the dispatching level. To meet this challenge, existing technical practices and research mainly develop along two paths: (1) Backup mechanism level: Traditional backup configuration mostly follows the principle of "provincial balance" or "regional balance", that is, each province or regional power grid is responsible for the backup capacity within its jurisdiction, mainly for self-protection. Although this mode can clearly define the safety responsibilities of each party, there are problems of backup resource redundancy and high calling cost in the whole network. In recent years, some research has begun to explore cross-regional or regional backup sharing and auxiliary service market, aiming to optimize the allocation of backup resources through market means. (2) Dispatching framework level: In order to realize "whole network mutual aid", the academic and industrial circles have researched multi-level collaborative dispatching framework, such as the two-level collaborative optimization model of national-grid and grid-provincial, aiming to solve the problem of cross-regional and cross-provincial power consumption and balance. However, the existing technical path mainly considers the above two in isolation, and fails to effectively integrate the cross-provincial and cross-regional collaborative backup mechanism with the national, grid, and provincial three-level dispatching system.

[0004] Although the prior art has made some progress in coordinated scheduling and standby sharing, there are still the following key defects when deeply integrating the two: (1) the standby resource configuration is localized, and the economy is insufficient; most of the existing multi-level scheduling models still simplify the standby as a rigid constraint that must be independently met by each province (or each region) when dealing with standby, which ignores the huge difference in standby cost between different provinces; for example, standby provided by pumped storage is cheaper than standby provided by conventional thermal power, which forces the system to call local standby with high cost and cannot utilize more economical standby resources from a distance, resulting in an increase in the overall operating cost of the system and waste of standby resources; (2) the potential of cross-regional mutual aid is not fully tapped, and flexible sharing is missing; although existing research emphasizes "whole network mutual aid", it mainly focuses on the mutual aid of electric energy; for standby, a key flexible resource, there is a lack of an effective sharing and trading mechanism that can penetrate the national-grid-provincial three-level system, which makes it impossible for a province with surplus, low-cost regulation capacity to effectively support another province with tight regulation capacity and high standby cost, limiting the overall flexibility and ability to cope with uncertainty of the system; (3) there is a lack of a unified energy-standby coordinated optimization framework; existing technologies fail to provide a unified optimization framework that can integrate the goals of the spot market (energy) and the ancillary service market (standby) with the responsibilities of the national, grid, and provincial scheduling systems; this leads to a sequential or decoupled decision-making process for energy scheduling and standby scheduling, which cannot achieve true joint clearing and global optimization, making it difficult to adapt to the actual production and operation system of "two-level market and three-level scheduling".

[0005] Therefore, how to deeply embed the coordinated standby mechanism into the national-grid-provincial three-level scheduling model, thereby realizing the unified optimization configuration of the whole network energy and standby resources under the premise of ensuring the independence of each level of scheduling, and improving the economy and flexibility of system operation, is a technical problem that needs to be solved at present. SUMMARY

[0006] The purpose of the present application is to provide a national-grid-provincial multi-level scheduling operation solving method based on coordinated standby, to solve the technical problem of how to deeply embed the coordinated standby mechanism into the national-grid-provincial three-level scheduling model, thereby realizing the unified optimization configuration of the whole network energy and standby resources under the premise of ensuring the independence of each level of scheduling, and improving the economy and flexibility of system operation.

[0007] The present application is implemented by the following technical scheme: a national-grid-provincial multi-level scheduling operation solving method based on coordinated standby, comprising the following steps:

[0008] According to the target functions of each level participating in cross-provincial energy scheduling and standby scheduling, a multi-level scheduling model considering coordinated standby constraints is established;

[0009] The multi-stage scheduling model is decomposed into sub-problems of a national dispatching level, a network dispatching level and a provincial dispatching level based on an augmented Lagrange relaxation method;

[0010] The sub-problems are solved cooperatively by using a target cascade method to obtain a globally optimal scheduling scheme.

[0011] According to a preferred embodiment, the target function of the national dispatching level is minimization of a national direct dispatching unit operation cost and a cross-region tie-line power transmission cost, and is expressed as follows:

[0012]

[0013] In the above formula, denotes a total number of time periods of a scheduling period, denotes a number of national generator units, denotes a national direct dispatching unit in a time period a generation cost coefficient, denotes a national direct dispatching unit output in a time period , denotes a cross-region tie-line power transmission cost coefficient, denotes a cross-region tie-line transmission power in a time period .

[0014] According to a preferred embodiment, the target function of the network dispatching level is minimization of a network direct dispatching unit operation cost, a standby cost, a pumped storage operation cost and a power transmission cost, and is expressed as follows:

[0015]

[0016] In the above formula, denotes a number of network generator units, denotes a network direct dispatching unit in a time period a generation cost coefficient, denotes a network direct dispatching unit output in a time period , denotes a network direct dispatching unit standby cost coefficient in a time period , denotes a network direct dispatching unit positive standby provided in a time period , denotes a number of network pumped storages, denotes a network pumped storage generation cost coefficient in a time period , denotes a network pumped storage in a time period Net output power, This represents the transmission cost coefficient for inter-provincial power transmission lines. Indicates the inter-provincial connection line during the time period The transmission power.

[0017] According to a preferred embodiment, the objective function of the provincial dispatching level is to minimize the operating costs of the directly dispatched generating units, reserve costs, pumped storage operating costs, and energy storage operating costs, as expressed below:

[0018]

[0019] In the above formula, This indicates the number of generator sets dispatched by the provincial dispatch center. Indicates the provincial direct dispatch units During the period The power generation cost coefficient, Indicates the provincial direct dispatch units During the period The backup cost coefficient, Indicates the provincial direct dispatch units During the period Provided as backup Indicates the provincial direct dispatch units During the period of efforts, This indicates the amount of water pumped out by the province. Indicates provincial-level water storage allocation During the period The power generation cost coefficient, Indicates provincial-level water storage allocation During the period Net output power, Indicates the amount of energy stored. Indicates energy storage During the period Operating cost coefficient, Indicates energy storage During the period Net output.

[0020] According to a preferred embodiment, the collaborative reserve constraint is that the sum of the total positive reserve provided by all resources of the provincial dispatch center and the inter-provincial net reserve obtained from network dispatch coordination equals the total reserve requirement of the provincial dispatch center, as expressed below:

[0021]

[0022] In the above formula, Indicates energy storage During the period Net output power, Indicates time period The cross-province net reserve obtained from the network dispatching cooperation, The total reserve demand of the province dispatching in the time period .

[0023] According to a preferred embodiment, the multi-level dispatching model further comprises system power balance constraints, direct dispatching unit constraints, tie-line constraints, pumped storage operation constraints, energy storage operation constraints, and line flow constraints.

[0024] According to a preferred embodiment, in the process of solving each of the sub-problems by using the target cascade method, the coordination variable transmitted between the national dispatching level and the network dispatching level is the exchange power of the cross-region tie-line, and the coordination variable transmitted between the network dispatching level and the province dispatching level is the exchange power and reserve capacity of the cross-province tie-line.

[0025] According to a preferred embodiment, the steps of iterative solving are as follows:

[0026] The national dispatching level takes the energy response and the multiplier of each network dispatching level in the last round as input, solves the national dispatching level sub-problem, and obtains the cross-region tie-line exchange power target of this round;

[0027] Each network dispatching level receives the cross-region tie-line exchange power target of this round, and takes the energy response , the reserve response , the multiplier , and the multiplier of each province dispatching level in the last round as input, solves the network dispatching level sub-problem, obtains the cross-province tie-line exchange power target and the reserve exchange target of this round, and feeds back the energy response of this round to the national dispatching level;

[0028] Each province dispatching level receives the cross-province tie-line exchange power target and the reserve exchange target of this round, and takes the corresponding multiplier as input, solves the province dispatching level sub-problem, and feeds back the energy response and the reserve response of this round to the network dispatching level;

[0029] Based on the deviation between the level targets and responses, it is judged whether the iteration converges, if it has converged, the iteration is terminated and the current solution is output, otherwise the multipliers are updated according to the deviation and the iteration is continued until convergence.

[0030] According to a preferred embodiment, the calculation expression of the deviation is as follows:

[0031]

[0032]

[0033]

[0034]

[0035] In the above formula, represents the energy deviation between the national regulation and the grid regulation level, represents the energy deviation between the grid regulation and the provincial regulation level, represents the standby deviation between the grid regulation and the provincial regulation level, represents the Frobenius norm.

[0036] According to a preferred embodiment, the expression of the multiplier updating strategy is as follows:

[0037]

[0038]

[0039]

[0040] In the above formula, represents the quadratic penalty factor.

[0041] The technical scheme of the present application has at least the following advantages and beneficial effects: (1) by constructing a national-grid-provincial multi-level dispatching model considering the collaborative standby mechanism, a reference can be provided for exploring a national-grid-provincial multi-level collaborative dispatching mode; (2) by using the target cascading method for solving, the actual situation and internal mechanism of the power grid at each level are considered, and the solving efficiency of the power system optimal dispatching under the whole network collaboration is improved. BRIEF DESCRIPTION OF DRAWINGS

[0042] Figure 1 The overall flowchart of the national-grid-provincial multi-level dispatching operation solving method based on collaborative standby provided for the embodiment 1 of the present application is shown in the figure;

[0043] Figure 2 The flowchart of the iterative solving provided for the embodiment 1 of the present application is shown in the figure. DETAILED DESCRIPTION

[0044] In order to make the purpose, technical scheme and advantages of the embodiments of the present application clearer, the technical scheme in the embodiments of the present application will be described clearly and completely below in combination with the drawings in the embodiments of the present application. Obviously, the described embodiments are part of the embodiments of the present application, rather than all the embodiments. The components of the embodiments of the present application described and shown in the drawings herein can be arranged and designed in various different configurations.

[0045] Embodiment 1

[0046] The embodiment provides a state grid province multi-level dispatching operation solving method based on cooperative backup, Figure 1 For the overall flowchart of the state grid province multi-level dispatching operation solving method based on cooperative backup, see Figure 1 The state grid province multi-level dispatching operation solving method based on cooperative backup includes the following steps:

[0047] Step S1, establish a multi-level dispatching model considering cooperative backup;

[0048] Step S11, construct the objective function;

[0049] In this embodiment, the provincial load characteristics, energy storage parameters, backup parameters, grid dispatching and direct dispatching unit parameters, cross-province tie line parameters, state dispatching and direct dispatching unit parameters, and cross-region tie line parameters are taken as boundary conditions, and the minimum operation cost is taken as the target to construct the objective function of each level participating in cross-province and cross-region energy dispatching and backup dispatching.

[0050] In some embodiments, the objective function of the state dispatching level is to minimize the state dispatching and direct dispatching unit operation cost and cross-region tie line transmission cost, and the expression is as follows:

[0051]

[0052] In the above formula, denotes the total number of time periods of the dispatching period, denotes the number of state dispatching generator units, denotes the state dispatching and direct dispatching unit in period the generation cost coefficient, denotes the state dispatching and direct dispatching unit in period the output, denotes the transmission cost coefficient of the cross-region tie line, denotes the transmission power of the cross-region tie line in period .

[0053] The objective function of the grid dispatching level is to minimize the grid dispatching and direct dispatching unit operation cost, backup cost, pumped storage operation cost and transmission cost, and the expression is as follows:

[0054]

[0055] In the above formula, denotes the number of grid dispatching generator units, denotes the grid dispatching and direct dispatching unit in period the generation cost coefficient, representing the grid regulation straight regulating unit in the time period , representing the grid regulation straight regulating unit in the time period , representing the grid regulation straight regulating unit in the time period provided positive reserve, representing the grid regulation pumped storage quantity, representing the grid regulation pumped storage in the time period , representing the grid regulation pumped storage in the time period , representing the transmission cost coefficient of the inter-provincial tie-line, representing the transmission power of the inter-provincial tie-line in the time period .

[0056] The objective function of the provincial regulation level is to minimize the provincial regulation straight regulating unit operation cost, reserve cost, pumped storage operation cost and energy storage operation cost, expressed as follows:

[0057]

[0058] In the above formula, representing the quantity of the provincial regulation generator, representing the provincial regulation straight regulating unit in the time period , representing the provincial regulation straight regulating unit in the time period , representing the provincial regulation straight regulating unit in the time period provided positive reserve, representing the provincial regulation straight regulating unit in the time period , representing the provincial regulation pumped storage quantity, representing the provincial regulation pumped storage in the time period , representing the provincial regulation pumped storage in the time period , representing the quantity of the energy storage, representing the energy storage in the time period , representing the energy storage in the time period Net output.

[0059] Step S12: Set constraints;

[0060] The constraints set in this embodiment include power balance constraints at each level of the system, direct-control unit constraints, tie line constraints, pumped storage operation constraints, energy storage operation constraints, line power flow constraints, and collaborative reserve constraints.

[0061] System power balance constraints;

[0062] In this embodiment, the system power balance constraints include:

[0063] A. The total power generation of the units directly dispatched by the national power grid is equal to the load allocated to the national power grid level, as expressed below:

[0064]

[0065] In the above formula, This indicates that the national dispatching units are operating during the specified time period. The load allocated to the national dispatch level itself;

[0066] B. The sum of the total power generation of the grid-dispatched units and the grid-dispatched pumped storage units, plus the net power input from the national grid, equals the total regional load, as expressed below:

[0067]

[0068] In the above formula, Indicates time period Net imported electricity from the national grid Indicates time period Total regional load;

[0069] C. The sum of the total power generation of the provincial dispatched units, the total power generation of the provincial pumped storage units, the total power generation of energy storage units, and the net power input from the grid dispatch equals the total load of the province, as expressed below:

[0070]

[0071] In the above formula, Indicates energy storage During the period Net output power, Indicates time period Net input power of grid regulation Indicates time period The total load of the province.

[0072] Constraints of directly controlled generating units;

[0073] In this embodiment, taking the national dispatch level as an example, the constraints of directly dispatched units include power constraints and ramp-up constraints:

[0074] D. Power constraint, specifically, the output of each direct-regulated unit is between the upper and lower limits set, expressed as follows:

[0075]

[0076] In the above formula, represents the lower limit of the output of the national direct-regulated unit, for example, a thermal power unit, represents the upper limit of the output of the thermal power unit;

[0077] E. Ramp constraint, specifically, the output change rate of the national direct-regulated unit in adjacent time periods is not greater than the maximum ramp rate set, expressed as follows:

[0078]

[0079] In the above formula, represents the maximum downward ramp power of the thermal power unit, represents the maximum upward ramp power of the thermal power unit.

[0080] It should be noted that the constraints of the direct-regulated units at the grid regulation level and the provincial regulation level and the direct-regulated units at the national regulation level are the same, and thus will not be described in detail here.

[0081] Interconnection line constraint;

[0082] In the present embodiment, the interconnection line constraint includes a cross-region interconnection line constraint and a cross-provincial interconnection line constraint:

[0083] F. Cross-region interconnection line constraint, specifically, the cross-region exchanged power is not greater than the transmission capacity of the interconnection line, expressed as follows:

[0084]

[0085] In the above formula, represents the lower limit of the cross-region interconnection line power, represents the upper limit of the cross-region interconnection line power.

[0086] G. Cross-provincial interconnection line constraint, specifically, the cross-provincial exchanged power is not greater than the transmission capacity of the interconnection line, expressed as follows:

[0087]

[0088] In the above formula, represents the lower limit of the cross-provincial interconnection line power, represents the upper limit of the cross-provincial interconnection line power.

[0089] Pumped storage operation constraint;

[0090] In the present embodiment, the pumped storage operation constraint includes an operation constraint, a storage capacity constraint, and a dynamic balance constraint:

[0091] H, operation constraint, specifically, the power generation of pumped storage is positive, and pumping is negative, and the expression is as follows:

[0092]

[0093] In the above formula, is negative, indicating that the maximum pumping power of the grid-regulated pumped storage is positive, indicating that the maximum power generation of the grid-regulated pumped storage is positive, indicating that the maximum power generation of the grid-regulated pumped storage .

[0094] I, reservoir capacity constraint, specifically, the reservoir capacity of pumped storage does not exceed the upper and lower limits of the set water volume, and the expression is as follows:

[0095]

[0096] In the above formula, indicates the water volume of the grid-regulated pumped storage in the time period , indicates the minimum water volume of the grid-regulated pumped storage in the time period , indicates the maximum water volume of the grid-regulated pumped storage in the time period .

[0097] J, dynamic balance constraint, and the specific expression is as follows:

[0098]

[0099] In the above formula, indicates the water volume conversion efficiency coefficient of the grid-regulated pumped storage .

[0100] K, after the end of a scheduling period, the reservoir capacity of pumped storage returns to the initial state, and the expression is as follows:

[0101]

[0102] Energy storage operation constraint;

[0103] In this embodiment, the energy storage operation constraint includes operation constraint, state of charge constraint, and energy balance constraint:

[0104] L, operation constraint, specifically, the charging and discharging power of energy storage does not exceed its rated power, and the expression is as follows:

[0105]

[0106] In the above formula, is negative, indicating that the energy storage the maximum charging power of the energy storage, is a positive value, indicating the state of charge of the energy storage the maximum discharging power of the energy storage.

[0107] M, state of charge constraint, specifically, the state of charge of the energy storage needs to be within the allowed range, the expression is as follows:

[0108]

[0109] In the above formula, indicates the state of charge of the energy storage in the time period , indicates the minimum state of charge allowed for the energy storage , indicates the maximum state of charge allowed for the energy storage .

[0110] N, energy balance constraint, specifically, the change of the state of charge of the energy storage is determined by the charging and discharging power, and returns to the initial state at the end of the dispatching period, the expression is as follows:

[0111]

[0112] In the above formula, indicates the charging and discharging power of the energy storage , indicates the rated capacity of the energy storage .

[0113] Line flow constraint;

[0114] O, in the embodiment, the line flow constraint specifically means that the flow of all transmission lines does not exceed the transmission capacity limit, the expression is as follows:

[0115]

[0116] In the above formula, indicates the active flow of the intra-provincial line in the time period , indicates the maximum transmission capacity of the intra-provincial line .

[0117] Cooperative reserve constraint;

[0118] P, in the embodiment, the cooperative reserve constraint is that the total positive reserve provided by the provincial dispatching and the cross-provincial net reserve obtained from the grid dispatching is equal to the total reserve demand of the provincial dispatching, the expression is as follows:

[0119]

[0120] In the above formula, representing the energy storage in the time period , the net output, representing the time period , the cross-province net reserve obtained from the grid dispatch coordination, representing the total reserve demand of the provincial dispatch in the time period .

[0121] Step S13, according to the target functions of each level participating in the cross-province area energy dispatch and reserve dispatch, a multi-level scheduling model considering the above constraints A to P is established.

[0122] Specifically, the multi-level scheduling operation solving method provided by the embodiment can provide a reference for exploring a multi-level coordinated dispatching mode of the state grid and the provincial grid by constructing a state-grid-provincial multi-level scheduling model considering a coordinated reserve mechanism.

[0123] Step S2, model solving;

[0124] In the embodiment, the multi-level scheduling model is decomposed into sub-problems of the state dispatch level, the grid dispatch level and the provincial dispatch level based on the augmented Lagrangian relaxation method, and each sub-problem is solved by using a target cascading method, and economic and physical information is transmitted between levels for iterative coordination, so that the convergence and optimization of the whole network operation cost are realized on the premise of ensuring the independence of the decision-making of each dispatch subject, to obtain a globally optimal scheduling scheme.

[0125] It should be noted that the augmented Lagrangian relaxation method is an optimization method in which a quadratic penalty term is introduced on the basis of the traditional Lagrangian relaxation method, and its core advantage lies in solving the problems of slow convergence and easy falling into local optimum of the traditional method.

[0126] In the multi-level scheduling model provided by the embodiment, two types of key coupling constraints are stored between levels, which are energy coupling constraints and reserve coupling constraints. The energy coupling constraints are the cross-area tie-line power exchange constraints between the state dispatch and the grid dispatch, and the cross-province tie-line power exchange constraints between the grid dispatch and the provincial dispatch. The reserve coupling constraints are the cross-province reserve capacity coordination constraints between the grid dispatch and the provincial dispatch.

[0127] The augmented Lagrangian relaxation method transforms the above coupling constraints into uncoupled sub-problems containing Lagrange multipliers and quadratic penalty terms by "relaxing" the coupling constraints into the target functions of each level, which not only retains the independence of the decision-making of each level, but also realizes global optimal coordination through multiplier iteration, as described in step S21.

[0128] Step S21, coordination between the state dispatch level and the grid dispatch level;

[0129] In the embodiment, the coordination variable transmitted between the state dispatch level and the grid dispatch level is the exchange power of the cross-area tie-line, and the specific coordination process is that the state dispatch level transmits the target variable , the network dispatch level feeds back response variables to the national dispatch level ;

[0130] To ensure consistency between the target and the response, the following augmented Lagrange coordination terms are added to the objective functions of the national dispatch level and the network dispatch level in this embodiment, and the expressions are as follows:

[0131]

[0132] In the above formula, represents the corresponding Lagrange multiplier in the th iteration.

[0133] Step S22, coordination between the network dispatch level and the provincial dispatch level;

[0134] In this embodiment, the coordination variables transmitted between the network dispatch level and the provincial dispatch level are the exchange power and the reserve capacity of the inter-provincial tie line, and the specific coordination process is that the network dispatch level transmits the target variables to the provincial dispatch level, and the provincial dispatch level feeds back the response variables to the network dispatch level;

[0135] Similarly, to ensure consistency between the target and the response, the following augmented Lagrange coordination terms of energy and reserve are added to the objective functions of the network dispatch level and the provincial dispatch level, and the expressions are as follows:

[0136]

[0137]

[0138]

[0139] In the above formula, represents the augmented Lagrange multiplier of the inter-provincial energy exchange, represents the augmented Lagrange multiplier of the inter-provincial reserve exchange, represents the penalty coefficient adjustment factor of the reserve coordination term, which is used to balance the convergence speed of energy and reserve coordination.

[0140] Step S23, iterative solution;

[0141] In this embodiment, the solution process is executed in a large iteration loop according to the order of transmitting the target from top to bottom and feeding back the response from bottom to top. It is assumed that the current is the Figure 2 th iteration, and the specific process is shown in FIG. 6, and the steps are as follows:

[0142] Step S231, the national dispatch level solves the sub-problem of the national dispatch level by taking the energy response and the multiplier of the last round of the network dispatch level under it as input, to obtain the target exchange power of the inter-regional tie line in this round ;

[0143] Step S232, each grid level receives the exchange power target of cross-zone tie-line in this round , and takes the energy response in the last round of its subordinate provincial level , backup response , multiplier , and multiplier as input, solves the grid level sub-problem to obtain the exchange power target of cross-provincial tie-line in this round and backup exchange target , and feeds back the energy response in this round to the national level;

[0144] Step S233, each provincial level receives the exchange power target of cross-provincial tie-line in this round and backup exchange target , and takes the corresponding multiplier as input, solves the provincial level sub-problem, and feeds back the energy response in this round and backup response to the grid level;

[0145] Thus, one complete solution is completed;

[0146] Step S234, at the end of each iteration, it is judged whether the iteration converges based on the deviation between the target and response of each level, if it has converged, the iteration is terminated and the current solution is output, otherwise the multiplier is updated according to the deviation and the iteration returns to step S231 until it converges.

[0147] In some embodiments, the calculation expression of the deviation is as follows:

[0148]

[0149]

[0150]

[0151]

[0152] In the above formula, denotes the energy deviation between the national level and the grid level, denotes the energy deviation between the grid level and the provincial level, denotes the backup deviation between the grid level and the provincial level, denotes the Frobenius norm.

[0153] Further, the expression of the multiplier updating strategy is as follows:

[0154]

[0155]

[0156]

[0157] In the above formula, represents a quadratic penalty factor.

[0158] Specifically, the embodiment is solved by adopting a target cascade method, which not only considers the actuality and internal mechanism of the power grid under each level, but also improves the solving efficiency of the power system optimization dispatching under the whole network cooperation.

[0159] The preferred embodiments of the present application have been described above with the preferred embodiments, but the present application is not limited to the above examples, and various modifications and changes can be made by those skilled in the art. Any modification, equivalent replacement, improvement, etc. made within the spirit and principle of the present application shall be included in the protection scope of the present application.

Claims

1. A method for solving the operation of multi-level dispatching of State Grid Province based on cooperative backup, characterized in that, The method comprises the following steps: According to the target functions of each level participating in the inter-provincial energy scheduling and standby scheduling, a multi-level scheduling model considering collaborative standby constraints is established; Based on the augmented Lagrange relaxation method, the multi-level scheduling model is decomposed into sub-problems of the national scheduling level, the grid scheduling level and the provincial scheduling level; The target cascade method is used to collaboratively solve each sub-problem to obtain a globally optimal scheduling scheme, wherein, in the process of collaborative solving, the coordination variable transmitted between the national scheduling level and the grid scheduling level is the exchange power of the inter-provincial tie line, and the coordination variable transmitted between the grid scheduling level and the provincial scheduling level is the exchange power and standby capacity of the inter-provincial tie line; The steps of iterative solving are as follows: The national dispatch level solves its sub-problem as input to get the target of the inter-area tie-line power exchange in this round and the multipliers The national dispatch level solves its sub-problem as input to get the target of the inter-area tie-line power exchange in this round , The national dispatch level solves its sub-problem as input to get the target of the inter-area tie-line power exchange in this round The corresponding Lagrange multiplier in the i-th iteration Each grid level receives the exchange power target of cross-zone tie-lines in this round , and the energy response of its subordinate province level in the last round , the reserve response , the multiplier , and the multiplier as inputs, solves the grid level sub-problem to obtain the exchange power target of cross-province tie-lines in this round , and the reserve exchange target , and feeds back the energy response of this round to the national level , denotes the augmented Lagrange multiplier of cross-province energy exchange denotes the augmented Lagrange multiplier of cross-province reserve exchange Each provincial dispatch level receives the exchange power target for the inter-provincial tie-line for this round and the backup exchange target and solves the provincial dispatch level sub-problem with the corresponding multipliers as inputs and feeds back the energy response for this round to the grid dispatch level and the backup response ; Based on the deviation between the target and the response of each level, it is judged whether the iteration converges, if the iteration converges, the iteration is terminated and the current solution is output, otherwise the multiplier is updated according to the deviation and the iteration is performed until the convergence.

2. The solution method for multi-level scheduling and operation of the State Grid provincial system based on collaborative backup as described in claim 1, characterized in that, The target function of the national scheduling level is to minimize the operation cost of the national direct-regulation unit and the transmission cost of the inter-provincial tie line, and the expression is as follows: In the above formula, denotes the total number of time periods of the dispatch cycle, denotes the number of national dispatch generator units, denotes the number of national dispatch direct dispatch generator units denotes the generation cost coefficient of the time period , denotes the output of the time period , denotes the transmission power of the cross-regional tie line in the time period , denotes the transmission power of the cross-regional tie line in the time period .

3. The method of claim 1, wherein the method is based on a coordinated backup of the provincial grid of the national grid, and the method is characterized in that, The target function of the grid scheduling level is to minimize the operation cost of the grid direct-regulation unit, the standby cost, the pumped storage operation cost and the transmission cost, and the expression is as follows: In the above formula, This indicates the total number of time periods in the scheduling cycle. This indicates the number of generator sets in the grid dispatching system. Indicates grid-dispatch and direct-dispatch units During the period The power generation cost coefficient, Indicates grid-dispatch and direct-dispatch units During the period of efforts, Indicates grid-dispatch and direct-dispatch units During the period The backup cost coefficient, Indicates grid-dispatch and direct-dispatch units During the period Provided as backup This indicates the amount of water pumped out by the grid. Indicates network survey and storage During the period The power generation cost coefficient, Indicates network survey and storage During the period Net output, This represents the transmission cost coefficient for inter-provincial power transmission lines. Indicates the inter-provincial connection line during the time period The transmission power.

4. The solution method for multi-level scheduling and operation of State Grid provincial grids based on collaborative backup as described in claim 1, characterized in that, The target function of the provincial scheduling level is to minimize the operation cost of the provincial direct-regulation unit, the standby cost, the pumped storage operation cost and the energy storage operation cost, and the expression is as follows: In the above formula, This indicates the total number of time periods in the scheduling cycle. This indicates the number of generator sets dispatched by the provincial dispatch center. Indicates the provincial direct dispatch units During the period The power generation cost coefficient, Indicates the provincial direct dispatch units During the period The backup cost coefficient, Indicates the provincial direct dispatch units During the period Provided as backup Indicates the provincial direct dispatch units During the period of efforts, This indicates the amount of water pumped out by the province. Indicates provincial-level water storage allocation During the period The power generation cost coefficient, Indicates provincial-level water storage allocation During the period Net output, Indicates the amount of energy stored. Indicates energy storage During the period Operating cost coefficient, Indicates energy storage During the period Net output.

5. The method of claim 1, wherein the method is based on a coordinated backup of the provincial grid of the national grid, and the method is characterized in that, The collaborative standby constraint is that the sum of the total positive standby provided by all resources of the provincial scheduling level and the inter-provincial net standby obtained from the grid scheduling level is equal to the total standby demand of the provincial scheduling level, and the expression is as follows: In the above formula, represents the number of provincial dispatching generators, represents the number of provincial dispatching and direct dispatching generators in the time period provided by the positive reserve, represents the number of provincial dispatching pumped storage, represents the number of provincial dispatching pumped storage in the time period net output, represents the number of energy storage, represents the number of energy storage in the time period net output, represents the time period cross-provincial net reserve obtained from network dispatching coordination, represents the total reserve demand of provincial dispatching in the time period .

6. The method of claim 1, wherein the method is based on a coordinated backup of the provincial grid of the national grid, and the method is characterized in that, The multi-level scheduling model further comprises system power balance constraints, direct-regulation unit constraints, tie line constraints, pumped storage operation constraints, energy storage operation constraints and line flow constraints.

7. The method of claim 1, wherein the method is a method for solving the operation of the power grid of a province based on the coordination of backup, and characterized in that, The expression of the deviation is as follows: In the above formula, denotes the energy bias between the national and grid levels, denotes the energy bias between the grid and provincial levels, denotes the reserve bias between the grid and provincial levels, denotes the Frobenius norm.

8. The method of claim 1, wherein the method is based on a coordinated backup of the provincial grid of the national grid, and the method is characterized in that, The expression of the multiplier updating strategy is as follows: In the above formula, denotes a quadratic penalty factor.

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