Demand tracing-oriented intra-province-inter-province power grid operation reserve cost layered allocation method

Abstract

The invention discloses an intra-province-inter-province power grid operation reserve cost layered allocation method oriented to demand tracing. The method comprises the following steps: 1) constructing an intra-province-inter-province operation reserve cost layered allocation framework considering common demand sharing; 2) on the basis of an intra-province-inter-province operation standby cost layered allocation framework, taking the minimum regional power grid energy and standby total operation cost as an objective function, taking power grid operation constraints as conditions, and generating and executing various types of operation standby cost allocation schemes considering the uncertain superposition characteristics of market members; according to the method, the responsibility subject causing the inter-provincial operation standby support demand is considered, and reasonable allocation of the intra-provincial and inter-provincial total operation standby cost to the conventional unit and the net load members is realized.

Description

Technical Field

[0001] The present invention relates to the field of power systems and automation thereof, and in particular to a demand tracing-oriented intra-provincial and inter-provincial power grid operation standby cost layered allocation method. Background Art

[0002] Reserving operating reserves is a crucial technical means for power systems to cope with uncertainties such as renewable energy, random load fluctuations, and unit outages. With the increasing frequency and prevalence of extreme weather events in my country, operating reserve services will play an increasingly important role in ensuring power supply to the power grid. Under the deterministic scheduling decision-making model currently used in industry, the method for formulating a flexible adjustment resource operating reserve reservation plan is to predetermine the system's operating reserve requirements and then embed operating reserve requirements constraints into the scheduling decision model to determine the operating reserve that should be reserved for each flexible adjustment resource, thereby ensuring sufficient system operating margin.

[0003] Operating reserve requirements can be divided into two categories based on the factors that trigger them: emergency reserve requirements to address power shortages caused by generator failures; and net load reserve requirements to address power deviations caused by renewable energy and load forecasting errors. To ensure sufficient system reserve, the industry generally uses the maximum of the emergency reserve requirement and the net load reserve requirement as the final system operating reserve requirement.

[0004] After the optimal allocation of operating reserves is completed, operating reserve costs will be incurred (i.e., compensating the flexible adjustment resources for the costs incurred in providing operating reserves). In a market environment, adhering to the incentive compatibility principle of "whoever causes it, whoever bears it", the reserve demand should be traced and analyzed, and the operating reserve costs should be reasonably allocated to the market members that cause the operating reserve demand, thereby prompting new energy and other members that cause the operating reserve demand to actively reduce their own random fluctuation characteristics. With the continuous advancement of the construction of a high-proportion new energy power system, the operating reserve costs of the power grid will increase significantly, and its reasonable allocation will become more important. In response to this issue, scholars at home and abroad have carried out relevant research.

[0005] The industry generally shares operational reserve costs among market participants—conventional power sources, renewable energy sources, and users—based on the ratio of electricity generation to electricity consumption. For example, the PJM electricity market in the United States charges users a reserve fee based on their electricity consumption. Some studies have allocated reserve costs to generators based on their proportion of grid-connected electricity. These methods are simple and easy to implement, but they fail to account for the uncertainty of market participants and fail to reflect the true impact of each market participant on operational reserve.

[0006] Academics have conducted extensive research on methods for allocating backup costs that account for market member uncertainty. One study calculated the backup cost contribution rate to reflect the proportion of each type of uncertainty factor that contributes to the increased operating backup cost, and used this information to allocate system operating backup costs. Another study explored the primary risks of backup demand, such as random outages of conventional generators and net load forecast errors, and implemented a conditional risk backup model to allocate backup costs. These methods can account for market member uncertainty, but they only consider the characteristics of individual market members. In reality, system uncertainty is not simply the sum of individual market member uncertainties, and individual market member uncertainties cannot accurately reflect their impact on system operational backup demand.

[0007] To address these issues, some studies have constructed analytical correlations between renewable energy, random load fluctuations, and system reserve demand based on operational experience. These correlations were then embedded in market-clearing models, resulting in the derivation of reserve price components that represent the uncertainty of renewable energy and load, achieving a natural channeling of reserve costs through price signals. However, simple correlations based on operational experience cannot objectively reflect the true impact of market players on system operational reserve demand. Similarly, some studies have derived price components related to the random fluctuation characteristics of renewable energy based on opportunity-constrained scheduling optimization models. However, the application of such stochastic optimization models in actual power grid operations is limited, and these methods do not account for system uncertainty caused by generator failures. Some studies have implemented operational reserve cost allocation based on coalition game theory (such as Shapley values), but these methods are computationally complex. Some studies have also implemented operational reserve cost allocation based on substitution benefit theory. These methods measure the impact of market participants on system operational reserve demand based on the changes in system operational reserve costs (or reserve demand) before and after market participants join the system, thereby achieving cost allocation. However, in a few scenarios, the substitution benefits of some market members may be negative (meaning that due to the mutual offset of uncertainties, the impact of this market member on the system's backup demand is negative). At this time, this market member can actually obtain backup benefits, which is inconsistent with the actual operation of the system.

[0008] The aforementioned studies primarily explored the allocation of intra-provincial reserve costs. However, to achieve wide-area optimal allocation of reserve resources, my country has established regional reserve markets, promoting inter-provincial mutual assistance in reserve resources through cross-provincial and cross-regional reserve ancillary service transactions. Currently, research on the allocation of inter-provincial reserve costs is lacking. The Southern Regional Power Reserve Ancillary Service Market, which allocates inter-provincial reserve costs based on the proportion of monthly grid-connected or landed electricity generated by receiving provinces, fails to reflect the impact of different market players on inter-provincial reserve demand.

[0009] In summary, existing research has extensively and beneficially explored the quantification of market participants' impact on system operational reserve demand and the allocation of operational reserve costs based on this impact. In reality, the impact of market participants on system operational reserve demand is closely related to the quantification method used to quantify system operational reserve demand. Therefore, the allocation method for reserve costs should align with the quantification method used to quantify reserve demand. Regarding the currently widely used quantification method in industry, which takes the larger of the accident reserve demand and the net load reserve demand, different market participants have both common and unique requirements. Existing allocation methods for operational reserve costs generally fail to consider the actual reserve demand quantification method used in industry. This mismatch between allocation methods and quantification methods leads to inaccurate tracing of reserve demand and difficulty in achieving a reasonable allocation of reserve costs. Summary of the Invention

[0010] The present invention aims to provide a method for layered allocation of intra-provincial and inter-provincial power grid operation standby costs oriented to demand tracing, comprising the following steps:

[0011] 1) Establish a tiered allocation framework for intra-provincial and inter-provincial operational reserve costs that takes into account common needs;

[0012] 2) Based on the intra-provincial and inter-provincial operating reserve cost tiered allocation framework, with the lowest overall operating cost of regional power grid energy and reserve as the objective function and subject to grid operation constraints, various types of operating reserve cost allocation schemes that take into account the uncertain superposition characteristics of market members are generated and implemented;

[0013] Various types of operating reserve cost sharing plans include accident reserve cost sharing plans that take into account common demand sharing and net load reserve cost sharing plans that take into account improved substitution benefits.

[0014] Furthermore, the tiered allocation framework for intra-provincial and inter-provincial operation reserve costs taking into account the common demand allocation includes Scenario 1 and Scenario 2;

[0015] Scenario 1 means: the operating reserve provided by the province is less than the emergency reserve demand and the net load reserve demand;

[0016] Scenario 2 means that the operating reserve provided by the province is greater than the accident reserve demand or the net load reserve demand.

[0017] Furthermore, in the following scenario, the intra-provincial reserve cost is evenly decomposed into the accident reserve cost and the net load reserve cost; the inter-provincial reserve cost caused by the conventional units and the net load members is evenly decomposed into the accident reserve cost and the net load reserve cost, and the remaining inter-provincial reserve cost is all decomposed into the net load reserve cost;

[0018] Furthermore, under the second scenario, part of the intra-provincial standby costs caused by conventional units and net load members will be evenly decomposed into accident standby costs and net load standby costs, and the remaining intra-provincial standby costs will be all decomposed into net load standby costs; the inter-provincial standby costs will be all decomposed into net load standby costs.

[0019] Furthermore, the intra-provincial and inter-provincial operating reserve costs are as follows:

[0020]

[0021] Among them, C R,I and C R,O are the intra-provincial and inter-provincial operation standby costs respectively; i is the unit number within the province; N g is the number of units in the province; k is the number of units outside the province; L g is the number of units outside the province; R,I and λ R,O are the reserve prices for intra-provincial and inter-provincial operation respectively; R i and R k They are respectively provided as operating backup for each unit within the province and between provinces.

[0022] Furthermore, the steps of generating an accident standby cost allocation plan taking into account common demand allocation include:

[0023] 1) Sort all conventional units in ascending order of installed capacity, and set j = 1;

[0024] 2) Determine whether j is greater than the number of conventional units N g If not, go to step 3), if yes, go to step 6) to complete the accident backup cost allocation;

[0025] 3) After deducting the emergency standby demand caused by unit j-1, calculate the number of units from unit j to unit N. g The jointly caused accident reserve demand ΔR c,j ,Right now:

[0026] ΔR c,j =R c,j -R c,j-1 (2)

[0027] Where, ΔR c,j After deducting the emergency standby demand caused by unit j-1, the total number of units j to N is g The accident reserve demand caused by the joint; R c,j is the emergency standby demand caused by unit j;

[0028] 4) The emergency backup demand ΔR c,j The corresponding emergency standby cost is evenly distributed to unit j to unit N g ,Right now:

[0029]

[0030] in, Indicates the ΔR that unit i needs to bear c,j The corresponding accident backup cost; R c is the total emergency backup demand of the system; C c is the total system emergency backup cost;

[0031] 5) Set j = j + 1 and return to step 2);

[0032] 6) Complete the common demand allocation among all conventional units and calculate the emergency standby cost that each conventional unit needs to bear, that is:

[0033]

[0034] Among them, C c,i is the accident standby cost that unit i needs to bear.

[0035] Furthermore, in step 3), if j-1=0, the deducted emergency reserve demand is 0.

[0036] Furthermore, the steps of generating a net load reserve cost allocation plan that takes into account the improved substitution benefits include:

[0037] 1) Calculate the system's net load reserve requirement R when considering all net load members n , the method proposed in the literature is used to quantify the system net load reserve demand, and m = 1;

[0038] 2) Calculate the net load backup demand of the system without considering the net load member m, and obtain the change of the net load backup demand of the system before and after the member is added, that is:

[0039] v m =R n -R n,-m (5)

[0040] Among them, v m The change of the system net load backup demand before and after the net load member m is added. The subscript -m means that the net load member m is not considered.

[0041] 3) Calculate the historical average absolute forecast error of the net load member m, that is:

[0042]

[0043] Among them, e m is the historical average absolute forecast error of net load member m; t is the number of forecast time points; T is the number of forecast time points included in the calculation period; is the actual power of the net load member; is the predicted power of the net load member;

[0044] 4) Determine whether m is equal to the number of payload members N n If yes, go to step 5), otherwise, return to step 2);

[0045] 5) Calculate the impact ratio of each net load member on the system net load reserve demand characterized by substitution benefits, that is:

[0046]

[0047] Among them, V m is the influence ratio of net load member m on the system net load reserve demand characterized by substitution benefit;

[0048] 6) Calculate the impact ratio of each net load member on the system net load reserve demand characterized by the historical forecast error, that is:

[0049]

[0050] Among them, E m is the influence ratio of net load member m on the system net load reserve demand characterized by historical forecast error;

[0051] 7) Taking into account the substitution benefits and historical prediction errors, the comprehensive impact ratio of each net load member is formed, that is:

[0052] α m =β V V m +β E E m (9)

[0053] Among them, α m is the comprehensive influence ratio of net load member m; β V and β E are the proportions of the impact of substitution benefits and the impact of historical forecast errors respectively;

[0054] 8) According to the comprehensive impact ratio of net load members, calculate the net load backup cost that each net load member should bear, that is:

[0055] C n,m =α m C n (10)

[0056] Among them, C n,m is the net load backup cost that net load member m needs to bear; C n is the total net load backup cost of the system.

[0057] Furthermore, in step 2), the objective function is as follows:

[0058]

[0059] Where a is the number of the provincial power grid in the region; V is the set of provincial power grids in the region; t is the time period number; T is the time period set; g a is the unit number of province a; G a is the set of units in province a; b is the number of the provincial power grid outside province a; is the energy cost; It is the reserve cost within the province; To save standby costs; Quote for energy; Provide power for the unit; Provide quotes for up / down spare within the province; Intra-province up / down standby provided for units; Provide a quotation for inter-provincial up / down reserve for units in Province A to be provided to Province B; is the inter-provincial up / down reserve provided by units in province a to province b; σ is the inter-provincial reserve call penalty coefficient, which is a constant with a large value.

[0060] Furthermore, in step 2), the grid operation constraints include inter-provincial tie line transmission power constraints, power balance constraints, unit output upper and lower limit constraints, unit standby constraints, unit ramping constraints, system operation standby demand constraints, and line flow constraints;

[0061] The transmission power constraints of inter-provincial tie lines are as follows:

[0062]

[0063] Where, l T is the contact line number; n a is the node number; w a W is the wind turbine group number; a Assemble for wind turbines; The upper and lower limits of the transmission power of the tie line; Node n for province a a To inter-provincial communication line T The power transfer distribution factor; They are thermal power generation units and wind power generation units to node n a The incidence matrix elements of ; is the power forecast value of wind turbine and load. Transmit power to the tie line;

[0064] The power balance constraints are as follows:

[0065]

[0066] Where, is the amount of power between provinces a and b, a positive value indicates that power flows from province a to province b;

[0067] The calculation method is as follows:

[0068]

[0069] Where, L T,ab Represents the set of contact lines between provinces a and b.

[0070] The upper and lower limits of the unit output are as follows:

[0071]

[0072] Where, They are the upper and lower limits of the output of thermal power units respectively.

[0073] The unit reserve constraints are as follows:

[0074]

[0075] Where, They are the up / down climbing capabilities of thermal power units respectively.

[0076] The unit ramp constraints are as follows:

[0077]

[0078] The system operation backup requirement constraints are as follows:

[0079]

[0080] Where, They are the upper / lower reserve requirements of the provincial power grid respectively.

[0081] The line power flow constraints are as follows:

[0082]

[0083] Where, l is the number of the provincial line; P l 、 is the upper and lower limits of the transmission power of line l within the province; P l Transmit power to the line; Node n for province a a Power transfer distribution factor to line l.

[0084] The technical effects of the present invention are undoubted, and the beneficial effects of the present invention are as follows:

[0085] 1) Due to the discrete nature of the quantified maximum value of industrial operating reserve demand, different market members have both common and specific demands. The reserve costs incurred by common demands should be shared equally among all relevant market members, while the costs incurred by specific demands should be borne solely by the relevant market members. The proposed tiered allocation framework for operating reserve costs, which takes into account common demands, effectively accounts for these characteristics and achieves a reasonable decomposition of the system's total operating reserve cost into accident reserve costs and net load reserve costs.

[0086] 2) When the provincial operating reserve resources are unable to meet the provincial reserve demand, it is necessary to seek support from extra-provincial operating reserve resources. To this end, the present invention considers the responsible parties for the inter-provincial operating reserve support demand, and realizes the reasonable allocation of the total intra-provincial and inter-provincial operating reserve costs to conventional units and net load members.

[0087] 3) Due to the offsetting effects of market member forecast errors, traditional substitution benefit methods cannot effectively capture the impact of different market members on net load reserve demand. To address this issue, this paper introduces market member forecast errors based on substitution benefit to capture the combined impact of market members on the system's net load reserve demand, enabling a reasonable allocation of net load reserve costs across market members. BRIEF DESCRIPTION OF THE DRAWINGS

[0088] Figure 1 Schematic diagram of the method for quantifying standby demand for industrial operations;

[0089] Figure 2 A tiered allocation framework for intra-provincial and inter-provincial operational reserve costs to account for common needs;

[0090] Figure 3 The reserve for provincial resource reserves is less than the emergency reserve demand and net load reserve demand;

[0091] Figure 4 The situation where the operating reserve provided within the province is greater than the accident reserve demand or net load reserve demand.

[0092] Figure 5 The idea and process of allocating accident backup costs to take into account common needs;

[0093] Figure 6 Net load reserve cost allocation methodology process to account for improved substitution benefits;

[0094] Figure 7 The decomposition results of accident backup cost and net load backup cost under different methods are shown;

[0095] Figure 8 The allocation of intra-provincial and inter-provincial operating reserve costs under M1 and M3. DETAILED DESCRIPTION

[0096] The present invention will be further described below with reference to the following examples, but it should not be understood that the scope of the present invention is limited to the following examples. Without departing from the above technical ideas of the present invention, various substitutions and modifications can be made according to common technical knowledge and customary means in the art, and all should be included in the scope of protection of the present invention.

[0097] Example 1:

[0098] See also Figures 1 to 8 A method for layered allocation of intra-provincial and inter-provincial power grid operation reserve costs based on demand tracing includes the following steps:

[0099] 1) Establish a tiered allocation framework for intra-provincial and inter-provincial operational reserve costs that takes into account common needs;

[0100] 2) Based on the intra-provincial and inter-provincial operating reserve cost tiered allocation framework, with the lowest overall operating cost of regional power grid energy and reserve as the objective function and subject to grid operation constraints, various types of operating reserve cost allocation schemes that take into account the uncertain superposition characteristics of market members are generated and implemented;

[0101] Various types of operating reserve cost sharing plans include accident reserve cost sharing plans that take into account common demand sharing and net load reserve cost sharing plans that take into account improved substitution benefits.

[0102] The tiered allocation framework for intra-provincial and inter-provincial operation reserve costs taking into account the equalization of common demands includes Scenario 1 and Scenario 2;

[0103] Scenario 1 means: the operating reserve provided by the province is less than the emergency reserve demand and the net load reserve demand;

[0104] Scenario 2 means that the operating reserve provided by the province is greater than the accident reserve demand or the net load reserve demand.

[0105] In the first scenario, the intra-provincial reserve cost is evenly decomposed into the accident reserve cost and the net load reserve cost; the inter-provincial reserve cost caused by the conventional units and the net load members is evenly decomposed into the accident reserve cost and the net load reserve cost, and the remaining inter-provincial reserve costs are all decomposed into the net load reserve cost;

[0106] Under the second scenario, part of the intra-provincial standby costs caused by conventional units and net load members will be evenly decomposed into accident standby costs and net load standby costs, and the remaining intra-provincial standby costs will be all decomposed into net load standby costs; the inter-provincial standby costs will be all decomposed into net load standby costs.

[0107] The intra-provincial and inter-provincial operating standby costs are as follows:

[0108]

[0109] Among them, C R,I and C R,O are the intra-provincial and inter-provincial operation standby costs respectively; i is the unit number within the province; N g is the number of units in the province; k is the number of units outside the province; L g is the number of units outside the province; R,I and λ R,O are the reserve prices for intra-provincial and inter-provincial operation respectively; R i and R k They are respectively provided as operating backup for each unit within the province and between provinces.

[0110] The steps for generating an accident reserve cost allocation plan that takes into account common demand sharing include:

[0111] 1) Sort all conventional units in ascending order of installed capacity, and set j = 1;

[0112] 2) Determine whether j is greater than the number of conventional units N g If not, go to step 3), if yes, go to step 6) to complete the accident backup cost allocation;

[0113] 3) After deducting the emergency standby demand caused by unit j-1, calculate the number of units from unit j to unit N. g The jointly caused accident reserve demand ΔR c,j ,Right now:

[0114] ΔR c,j =R c,j -R c,j-1 (2)

[0115] Where, ΔR c,j After deducting the emergency standby demand caused by unit j-1, the total number of units j to N is g The accident reserve demand caused by the joint; R c,j is the emergency standby demand caused by unit j;

[0116] 4) The emergency backup demand ΔR c,j The corresponding emergency standby cost is evenly distributed to unit j to unit N g ,Right now:

[0117]

[0118] in, Indicates the ΔR that unit i needs to bear c,j The corresponding accident backup cost; R c is the total emergency backup demand of the system; C c is the total system emergency backup cost;

[0119] 5) Set j = j + 1 and return to step 2);

[0120] 6) Complete the common demand allocation among all conventional units and calculate the emergency standby cost that each conventional unit needs to bear, that is:

[0121]

[0122] Among them, C c,i is the accident standby cost that unit i needs to bear.

[0123] In step 3), if j-1=0, the deducted emergency reserve demand is 0.

[0124] The steps to generate a net load reserve cost allocation plan that accounts for improved substitution benefits include:

[0125] s1) Calculate the system's net load reserve requirement R when considering all net load members n , the method proposed in the literature is used to quantify the system net load reserve demand, and m = 1;

[0126] s2) Calculate the system's net load backup demand without considering the net load member m, and obtain the change in the system's net load backup demand before and after the member joins, namely:

[0127] v m =R n -R n,-m (5)

[0128] Among them, v m The change of the system net load backup demand before and after the net load member m is added. The subscript -m means that the net load member m is not considered.

[0129] s3) Calculate the historical average absolute forecast error of the net load member m, that is:

[0130]

[0131] Among them, e m is the historical average absolute forecast error of net load member m; t is the number of forecast time points; T is the number of forecast time points included in the calculation period; is the actual power of the net load member; is the predicted power of the net load member;

[0132] s4) Determine whether m is equal to the number of payload members N n If yes, go to step s5), otherwise, return to step s2);

[0133] s5) Calculate the impact ratio of each net load member on the system net load reserve demand characterized by substitution benefits, that is:

[0134]

[0135] Among them, V m is the influence ratio of net load member m on the system net load reserve demand characterized by substitution benefit;

[0136] s6) Calculate the influence ratio of each net load member on the system net load reserve demand as characterized by the historical forecast error, that is:

[0137]

[0138] Among them, E m is the influence ratio of net load member m on the system net load reserve demand characterized by historical forecast error;

[0139] s7) Taking into account the substitution benefits and historical prediction errors, the comprehensive impact ratio of each net load member is formed, that is:

[0140] α m =β V V m +β E E m (9)

[0141] Among them, α m is the comprehensive influence ratio of net load member m; β V and β E are the proportions of the impact of substitution benefits and the impact of historical forecast errors respectively;

[0142] s8) Calculate the net load standby cost that each net load member should bear based on the comprehensive impact ratio of the net load members, that is:

[0143] C n,m =α m C n (10)

[0144] Among them, C n,m is the net load backup cost that net load member m needs to bear; C n is the total net load backup cost of the system.

[0145] In step 2), the objective function is as follows:

[0146]

[0147] Where a is the number of the provincial power grid in the region; V is the set of provincial power grids in the region; t is the time period number; T is the time period set; g a is the unit number of province a; G ais the set of units in province a; b is the number of the provincial power grid outside province a; is the energy cost; It is the reserve cost within the province; To save standby costs; Quote for energy; Provide power for the unit; Provide quotes for up / down spare within the province; Intra-province up / down standby provided for units; Provide a quotation for inter-provincial up / down reserve for units in Province A to be provided to Province B; is the inter-provincial up / down reserve provided by units in province a to province b; σ is the inter-provincial reserve call penalty coefficient, which is a constant with a large value.

[0148] In step 2), the grid operation constraints include inter-provincial tie line transmission power constraints, power balance constraints, unit output upper and lower limit constraints, unit reserve constraints, unit ramp constraints, system operation reserve demand constraints, and line flow constraints;

[0149] The transmission power constraints of inter-provincial tie lines are as follows:

[0150]

[0151] Where, l T is the contact line number; n a is the node number; w a W is the wind turbine group number; a Assemble for wind turbines; The upper and lower limits of the transmission power of the tie line; Node n for province a a To inter-provincial communication line T The power transfer distribution factor; They are thermal power generation units and wind power generation units to node n a The incidence matrix elements of ; is the power forecast value of wind turbine and load. lT Transmit power to the tie line;

[0152] The power balance constraints are as follows:

[0153]

[0154] Where, is the amount of power between provinces a and b, a positive value indicates that power flows from province a to province b;

[0155] The calculation method is as follows:

[0156]

[0157] Where, L T,ab Represents the set of contact lines between provinces a and b.

[0158] The upper and lower limits of the unit output are as follows:

[0159]

[0160] Where, They are the upper and lower limits of the output of thermal power units respectively.

[0161] The unit reserve constraints are as follows:

[0162]

[0163] Where, They are the up / down climbing capabilities of thermal power units respectively.

[0164] The unit ramp constraints are as follows:

[0165]

[0166] The system operation backup requirement constraints are as follows:

[0167]

[0168] Where, The upper and lower reserve requirements of provincial power grids are respectively . Due to the influence of load and renewable energy forecast errors, some provincial power grids may experience insufficient lower reserve, which will lead to wind and solar power curtailment. Therefore, this paper also considers the situation of inter-provincial lower reserve supply.

[0169] The line power flow constraints are as follows:

[0170]

[0171] Where, l is the number of the provincial line; P l 、 is the upper and lower limits of the transmission power of line l within the province; P l Transmit power to the line; Node n for province a a Power transfer distribution factor to line l.

[0172] Example 2:

[0173] A method for layered allocation of intra-provincial and inter-provincial power grid operation reserve costs based on demand tracing includes the following steps:

[0174] 1) Establish a tiered allocation framework for intra-provincial and inter-provincial operational reserve costs that takes into account common needs;

[0175] 2) Based on the intra-provincial and inter-provincial operating reserve cost hierarchical allocation framework, with the lowest regional power grid energy and overall reserve operating cost as the objective function and the power grid operation constraints as the condition, various types of operating reserve cost allocation schemes that consider the uncertain superposition characteristics of market members are generated and implemented; specifically, the generated operating reserve cost allocation scheme should be the one that minimizes the regional power grid energy and overall reserve operating cost and complies with the power grid operation constraints.

[0176] Various types of operating reserve cost sharing plans include accident reserve cost sharing plans that take into account common demand sharing and net load reserve cost sharing plans that take into account improved substitution benefits.

[0177] Example 3:

[0178] A method for stratified allocation of intra-provincial and inter-provincial power grid operation reserve costs for demand tracing, with the same technical content as in Example 2. Furthermore, a framework for stratified allocation of intra-provincial and inter-provincial operation reserve costs that takes into account common demand allocation includes Case 1 and Case 2.

[0179] Scenario 1 means: the operating reserve provided by the province is less than the emergency reserve demand and the net load reserve demand;

[0180] Scenario 2 means that the operating reserve provided by the province is greater than the accident reserve demand or the net load reserve demand.

[0181] Example 4:

[0182] A method for tiered allocation of intra-provincial and inter-provincial power grid operation reserve costs for demand tracing, with the same technical content as any one of Examples 2-3, further comprising, in the first scenario, evenly decomposing the intra-provincial reserve costs into accident reserve costs and net load reserve costs; evenly decomposing the portion of the inter-provincial reserve costs jointly incurred by conventional units and net load members into accident reserve costs and net load reserve costs, and decomposing all the remaining inter-provincial reserve costs into net load reserve costs;

[0183] Example 5:

[0184] A method for layered allocation of intra-provincial and inter-provincial power grid operation reserve costs for demand tracing, with the same technical content as any one of Examples 2-4. Furthermore, under scenario 2, part of the intra-provincial reserve costs jointly caused by conventional units and net load members are evenly decomposed into accident reserve costs and net load reserve costs, and the remaining intra-provincial reserve costs are all decomposed into net load reserve costs; the inter-provincial reserve costs are all decomposed into net load reserve costs.

[0185] Example 6:

[0186] A method for layered allocation of intra-provincial and inter-provincial power grid operation standby costs for demand tracing, the technical content of which is the same as any one of Examples 2-5. Furthermore, the intra-provincial and inter-provincial operation standby costs are respectively as follows:

[0187]

[0188] Among them, C R,I and C R,O are the intra-provincial and inter-provincial operation standby costs respectively; i is the unit number within the province; N g is the number of units in the province; k is the number of units outside the province; L g is the number of units outside the province; R,I and λ R,O are the reserve prices for intra-provincial and inter-provincial operation respectively; R i and R k They are respectively provided as operating backup for each unit within the province and between provinces.

[0189] Example 7:

[0190] A method for stratified allocation of intra-provincial and inter-provincial power grid operation backup costs for demand tracing, with the same technical content as any one of Examples 2-6, further comprising the following steps of allocating the accident backup costs taking into account the common demand:

[0191] 1) Sort all conventional units in ascending order of installed capacity, and set j = 1;

[0192] 2) Determine whether j is greater than the number of conventional units N g If not, go to step 3), if yes, go to step 6) to complete the accident backup cost allocation;

[0193] 3) After deducting the emergency standby demand caused by unit j-1, calculate the number of units from unit j to unit N. g The jointly caused accident reserve demand ΔR c,j ,Right now:

[0194] ΔR c,j =R c,j -R c,j-1 (2)

[0195] Where, ΔR c,j After deducting the emergency standby demand caused by unit j-1, the total number of units j to N is g The accident reserve demand caused by the joint; R c,j is the emergency standby demand caused by unit j;

[0196] 4) The emergency backup demand ΔR c,j The corresponding emergency standby cost is evenly distributed to unit j to unit N g ,Right now:

[0197]

[0198] in, Indicates the ΔR that unit i needs to bear c,j The corresponding accident backup cost; R c is the total emergency backup demand of the system; C c is the total system emergency backup cost;

[0199] 5) Set j = j + 1 and return to step 2);

[0200] 6) Complete the common demand allocation among all conventional units and calculate the emergency standby cost that each conventional unit needs to bear, that is:

[0201]

[0202] Among them, C c,i is the accident standby cost that unit i needs to bear.

[0203] Example 8:

[0204] A method for layered allocation of intra-provincial and inter-provincial power grid operation reserve costs for demand tracing, the technical content of which is the same as any one of Examples 2-7. Further, in step 3), if j-1=0, the deducted accident reserve demand is 0.

[0205] Example 9:

[0206] A method for stratified allocation of intra-provincial and inter-provincial power grid operation reserve costs for demand tracing, the technical content of which is the same as any one of Examples 2-8, and further, the steps of allocating net load reserve costs taking into account improved substitution benefits include:

[0207] 1) Calculate the system's net load reserve requirement R when considering all net load members n , the method proposed in the literature is used to quantify the system net load reserve demand, and m = 1;

[0208] 2) Calculate the net load backup demand of the system without considering the net load member m, and obtain the change of the net load backup demand of the system before and after the member is added, that is:

[0209] v m =R n -R n,-m (5)

[0210] Among them, v m The change of the system net load backup demand before and after the net load member m is added. The subscript -m means that the net load member m is not considered.

[0211] 3) Calculate the historical average absolute forecast error of the net load member m, that is:

[0212]

[0213] Among them, em is the historical average absolute forecast error of net load member m; t is the number of forecast time points; T is the number of forecast time points included in the calculation period; is the actual power of the net load member; is the predicted power of the net load member;

[0214] 4) Determine whether m is equal to the number of payload members N n If yes, go to step 5), otherwise, return to step 2);

[0215] 5) Calculate the impact ratio of each net load member on the system net load reserve demand characterized by substitution benefits, that is:

[0216]

[0217] Among them, V m is the influence ratio of net load member m on the system net load reserve demand characterized by substitution benefit;

[0218] 6) Calculate the impact ratio of each net load member on the system net load reserve demand characterized by the historical forecast error, that is:

[0219]

[0220] Among them, E m is the influence ratio of net load member m on the system net load reserve demand characterized by historical forecast error;

[0221] 7) Taking into account the substitution benefits and historical prediction errors, the comprehensive impact ratio of each net load member is formed, that is:

[0222] α m =β V V m +β E E m (9)

[0223] Among them, α m is the comprehensive influence ratio of net load member m; β V and β E are the proportions of the impact of substitution benefits and the impact of historical forecast errors respectively;

[0224] 8) According to the comprehensive impact ratio of net load members, calculate the net load backup cost that each net load member should bear, that is:

[0225] C n,m =α m C n (10)

[0226] Among them, Cn,m is the net load backup cost that net load member m needs to bear; C n is the total net load backup cost of the system.

[0227] Example 10:

[0228] A method for layered allocation of intra-provincial and inter-provincial power grid operation standby costs for demand tracing, the technical content of which is the same as any one of Examples 2-9, further comprising:

[0229] In order to accurately consider the impact of line transmission capacity on reserve deliverability in the reserve delivery scenario, this section constructs a unified optimization decision-making model for regional power grid reserves. At the same time, separate models are established for the intra-provincial reserve supply and inter-provincial reserve supply of units, which can provide a basis for distinguishing the relevant market mechanisms for intra-provincial and inter-provincial reserve supply.

[0230] 1 Objective Function

[0231] The model takes the lowest overall operating cost of regional power grid energy and backup as the objective function, as shown in Equation (11).

[0232]

[0233] Where a is the number of the provincial power grid in the region; V is the set of provincial power grids in the region; t is the time period number; T is the time period set; g a is the unit number of province a; G a is the set of units in province a; b is the number of the provincial power grid outside province a; is the energy cost; It is the reserve cost within the province; To save standby costs; Quote for energy; Provide power for the unit; Provide quotes for up / down spare within the province; Intra-province up / down standby provided for units; Provide a quotation for inter-provincial up / down reserve for units in Province A to be provided to Province B; is the inter-provincial up / down reserve provided by units in province a to province b; σ is the inter-provincial reserve call penalty coefficient, which is a constant with a large value.

[0234] 2 Operational constraints

[0235] (1) Transmission power constraints of inter-provincial interconnection lines

[0236] The transmission power of inter-provincial interconnection lines should not exceed the upper and lower limits of their transmission capacity, as shown in formula (12).

[0237]

[0238] Where, l T is the contact line number; na is the node number; w a W is the wind turbine group number; a Assemble for wind turbines; The upper and lower limits of the transmission power of the tie line; Node n for province a a To inter-provincial communication line T The power transfer distribution factor; They are thermal power generation units and wind power generation units to node n a The incidence matrix elements of ; is the power forecast value of wind turbine and load.

[0239] (2) Intra-provincial operation constraints

[0240] 1) Power balance constraints

[0241] In a conventional scenario, the power generation and consumption of each province should be balanced, as shown in formula (13).

[0242]

[0243] Where, is the amount of power between provinces a and b. A positive value indicates that power flows from province a to province b, and a negative value indicates that power flows from province b to province a. The calculation method of is as follows.

[0244]

[0245] Where, L T,ab Represents the set of contact lines between provinces a and b.

[0246] 2) Upper and lower limits of unit output

[0247] In order to provide intra-provincial and inter-provincial up / down reserve, the output of thermal power units will not be able to reach their upper and lower limits, as shown in formula (15).

[0248]

[0249] Where, They are the upper and lower limits of the output of thermal power units respectively.

[0250] 3) Unit standby constraints

[0251] The total intra-provincial and inter-provincial reserve provided by the unit should not exceed its ramping capability, as shown in formula (16).

[0252]

[0253] Where, They are the up / down climbing capabilities of thermal power units respectively.

[0254] 4) Unit climbing constraints

[0255] The unit output must meet the ramp constraint, as shown in formula (17).

[0256]

[0257] 5) System operation backup demand constraints

[0258] The sum of the reserve provided by the province itself and the reserve provided by other provinces must meet the total system operation reserve demand of the provincial power grid itself, as shown in formula (18).

[0259]

[0260] Where, The upper and lower reserve requirements of provincial power grids are respectively . Due to the influence of load and renewable energy forecast errors, some provincial power grids may experience insufficient lower reserve, which will lead to wind and solar power curtailment. Therefore, this paper also considers the situation of inter-provincial lower reserve supply.

[0261] 6) Line flow constraints

[0262] The power flow of the provincial lines should not exceed the upper and lower limits of the line transmission capacity, as shown in formula (19).

[0263]

[0264] Where, l is the number of the provincial line; P l 、 is the upper and lower limits of the transmission power of line l within the province; P l Transmit power to the line; Node n for province a a Power transfer distribution factor to line l.

[0265] Example 11:

[0266] A demand tracing-oriented hierarchical allocation method for intra-provincial and inter-provincial power grid operation reserve costs is proposed as follows:

[0267] (1) A hierarchical allocation framework for intra-provincial and inter-provincial standby costs based on demand tracing

[0268] (a) Necessity Analysis of Cost Allocation Methods Matching the Quantification Methods of Industrial Operational Reserve Demand

[0269] This section will use the allocation method that takes into account substitution benefits as an example to analyze the necessity of matching the cost allocation means with the quantification method of industrial operation reserve demand.

[0270] The current commonly used quantification method of operating reserve demand in the industry and the changes in system operating reserve demand before and after the conventional units are connected (assuming that the net load reserve demand is greater than the accident reserve demand) are as follows: Figure 1 As shown. Figure 1 It can be seen that the current industrial sector mainly uses the maximum value of the accident backup demand and the net load backup demand as the system operation backup demand. This quantitative method of taking the maximum value causes the change of the system operation backup demand to have a discrete characteristic (the value of the system operation backup demand can only be equal to the value of the accident backup demand or the value of the net load backup demand, among which the part of the operation backup demand caused by the accident backup demand and the net load backup demand will be used to deal with the accident uncertainty and the net load uncertainty at the same time). Affected by this discrete characteristic, a certain type of market member will not cause a change in the system operation backup demand after being connected to the power grid. For example, in Figure 1 In the case shown, the emergency reserve demand caused by conventional units is less than the net load reserve demand caused by new energy and load. At this time, for the quantitative method of taking the maximum value, the system operation reserve demand before and after considering the conventional units will not change. The allocation method taking into account the substitution benefit measures the impact of the changes in the system operation reserve demand before and after the market members are connected to the system operation reserve demand, thereby achieving cost allocation. Therefore, for Figure 1 In the case shown, the approach that accounts for substitution benefits would assume that conventional units do not generate reserve demand and therefore do not bear reserve costs. However, conventional units actually generate operating reserve demand and share some reserve services with renewable energy and other loads. This shows that existing allocation methods that account for substitution benefits fail to account for the discrete nature of the system's operating reserve demand quantification method, resulting in inaccurate backup demand tracing. Conventional units benefit from operating reserve services without bearing the corresponding costs, resulting in irrational cost allocation.

[0271] In addition to substitution benefits, allocating standby costs according to the proportion of demand (risk) caused by market members is also a commonly used allocation method. Figure 1 In the example shown, renewable energy and loads will generate additional operational reserve requirements. The reserve costs incurred by these requirements should be borne solely by the renewable energy and loads, rather than shared proportionally among all market participants. This allocation method fails to account for the additional demand induced by a particular market participant under the maximum value quantification method, leading to irrational cost allocation.

[0272] In summary, the method for allocating operating reserve costs should align with the quantification of system operating reserve requirements. To address this, and considering the discrete nature of the industry's quantification methods based on maximum values, this paper proposes a tiered allocation framework for operating reserve costs within and between provinces, taking into account common requirements. This framework will be described in detail later.

[0273] (b) A tiered allocation framework for intra-provincial and inter-provincial operational reserve costs taking into account common demand

[0274] In order to accurately trace the power grid's operating reserve demand, this paper proposes a hierarchical allocation framework for the intra-provincial and inter-provincial operating reserve cost, taking into account the common demand allocation, under the condition of considering the quantification method of the operating reserve demand of the industry. Figure 2 shown.

[0275] First, the intra-provincial and inter-provincial operating reserve costs can be calculated based on the unit operating reserve reservation status and the intra-provincial and inter-provincial reserve prices, as shown in formula (1).

[0276]

[0277] Among them, C R,I and C R,O are the intra-provincial and inter-provincial operation standby costs respectively; i is the unit number within the province; N g is the number of units in the province; k is the number of units outside the province; L g is the number of units outside the province; R,I and λ R,O are the reserve prices for intra-provincial and inter-provincial operation respectively; R i and R k They are respectively provided as operating backup for each unit within the province and between provinces.

[0278] Subsequently, taking into account the idea of ​​equal sharing of common demands, the intra-provincial and inter-provincial operating reserve costs are decomposed into accident reserve costs and net load reserve costs, including two situations, which are explained in detail as follows.

[0279] Scenario 1: The operating reserve provided by the province is less than the emergency reserve demand and the net load reserve demand, such as Figure 3 As shown. Figure 3 It can be seen that in this case, all operating standby services provided within the province are jointly caused and shared by conventional units and net load members (new energy, load) (inter-provincial operating standby resources are used to meet operating standby needs that cannot be met by provincial operating standby resources). Therefore, the provincial standby cost will be evenly decomposed into accident standby costs and net load standby costs. As for inter-provincial standby services, conventional units and net load members jointly cause and share part of the inter-provincial operating standby services, while the remaining part of the inter-provincial operating standby services is caused and enjoyed solely by net load members. Therefore, in accordance with the principle of "whoever causes it, whoever bears it", the part of the inter-provincial standby cost caused jointly by conventional units and net load members will be evenly decomposed into accident standby costs and net load standby costs, and the rest will be decomposed entirely into net load standby costs.

[0280] Scenario 2: The operating reserve provided by the province is greater than the emergency reserve demand or net load reserve demand, such as Figure 4As shown. Figure 4 As can be seen, in this scenario, a portion of the intra-provincial operating reserve services are jointly incurred and enjoyed by conventional units and net load members. This portion of the intra-provincial reserve cost will be evenly allocated to the accident reserve cost and the net load reserve cost. The remaining operating reserve services are incurred solely by net load members, and this portion of the intra-provincial reserve cost will be fully allocated to the net load reserve cost. As for inter-provincial reserve services, they are all incurred and enjoyed by net load members, so the inter-provincial reserve cost will be fully allocated to the net load reserve cost.

[0281] This completes the decomposition of intra-provincial and inter-provincial reserve costs into accident reserve costs and net load reserve costs. On this basis, the present invention will further allocate accident reserve costs and net load reserve costs to each market member by combining the uncertain superposition characteristics of various market members.

[0282] (2) Allocation methods for various types of operating reserve costs considering the uncertain superposition characteristics of market members

[0283] (a) Method for allocating emergency reserve costs taking into account common demand

[0284] For emergency backup demand, the current common practice is to use the maximum capacity of a single unit in the system as the system emergency backup demand to cope with the power shortage caused by generator failure. Therefore, the quantification of emergency backup demand also has discrete characteristics. Therefore, the present invention adopts the idea of ​​allocating common demand to complete the allocation of emergency backup costs among conventional units. Its idea and specific process are as follows: Figure 5 shown.

[0285] The detailed steps of the proposed method for allocating accident standby costs taking into account common needs are as follows:

[0286] 1) Sort all conventional units in ascending order of installed capacity, and set j = 1;

[0287] 2) Determine whether j is greater than the number of conventional units N g If it is not greater than, go to step 3), otherwise, go to step 6) to complete the accident standby cost allocation;

[0288] 3) After deducting the emergency standby demand caused by unit j-1 (if j-1=0, the deducted emergency standby demand is 0), the number of units j to N is determined. g The accident backup demand caused by the two factors is shown in Formula 2:

[0289] ΔR c,j =R c,j -R c,j-1 (2)

[0290] Where, ΔR c,jAfter deducting the emergency standby demand caused by unit j-1, the total number of units j to N is g The accident reserve demand caused by the joint; R c,j is the emergency reserve demand caused by unit j (i.e., the installed capacity of unit j);

[0291] 4) ΔR c,j The corresponding emergency standby cost is evenly distributed to unit j to unit N g , as shown in formula 3:

[0292]

[0293] in, Indicates the ΔR that unit i needs to bear c,j The corresponding accident backup cost; R c is the total emergency backup demand of the system; C c is the total system emergency backup cost;

[0294] 5) Set j = j + 1 and return to step 2);

[0295] 6) Complete the common demand sharing among all conventional units and calculate the emergency standby cost that each conventional unit needs to bear, as shown in formula (4):

[0296]

[0297] Among them, C c,i is the accident standby cost that unit i needs to bear.

[0298] This completes the allocation of emergency standby costs among the conventional units. As can be seen from the above allocation process, for emergency standby demand caused by all conventional units, the corresponding standby costs will be evenly shared among the units. However, for the unit with the largest installed capacity, which alone causes a portion of the emergency standby demand, the corresponding standby costs will be borne entirely by that unit, in line with the "who causes, who pays" allocation principle.

[0299] (b) Net load reserve cost allocation method taking into account improved substitution benefits

[0300] Cost-sharing methods that account for substitution benefits are derived from the renowned economic theory of the Vickrey-Clarke-Groves (VCG) mechanism. This mechanism characterizes a market member's contribution to system costs or demand as the change in system costs or demand before and after the market member joins the system. It has been widely used in cost sharing and revenue allocation. However, for net load reserve cost sharing, due to the mutually offsetting nature of forecast errors among market members, it is possible that the entry of a particular market member may actually lead to a decrease in the system's net load reserve demand. In this case, based on the substitution benefit, the market member's impact on the system's net load reserve demand is negative (i.e., the market member is considered to have contributed to meeting the net load reserve demand), resulting in a reserve benefit. However, in reality, this market member does not actively provide reserve services, and its forecast error still exists, making it the responsible party for net load reserve. Allowing this market member to receive reserve benefits would violate the principle of "cause, pay" and would provide little incentive for it to reduce its own forecast error.

[0301] In response to the above problems, the present invention improves the cost allocation method that takes substitution benefits into account, and further introduces the market member prediction error on the basis of the traditional substitution benefit, so as to comprehensively consider the prediction randomness of the market members themselves and the impact of the market members on the net load reserve demand under the influence of the mutual offset of the prediction errors among different members, and form the comprehensive influence of the market members on the net load reserve demand.

[0302] The net load standby cost allocation method for calculating and improving substitution efficiency proposed in the present invention is as follows: Figure 6 shown.

[0303] The detailed steps of the proposed method are described as follows:

[0304] 1) Calculate the system's net load reserve requirement (R) when considering all net load members n ), the method proposed in the literature is used to quantify the system net load reserve demand, and m = 1;

[0305] 2) Calculate the net load reserve demand of the system without considering the net load member m, and obtain the change of the net load reserve demand of the system before and after the member is connected. This reflects the impact of the member on the net load reserve demand of the system after considering the mutual offset of the prediction errors between different members, as shown in formula (5):

[0306] v m =R n -R n,-m (5)

[0307] Among them, v m The change of the system net load backup demand before and after the net load member m is added. The subscript -m means that the net load member m is not considered.

[0308] 3) Calculate the historical average absolute forecast error of net load member m, which reflects the impact of this member on the system net load reserve demand when only considering the member's own forecast randomness, as shown in Equation 6:

[0309]

[0310] Among them, e m is the historical average absolute forecast error of net load member m; t is the number of forecast time points; T is the number of forecast time points included in the calculation period. Considering that the historical forecast error of net load members is an important basis for quantifying the net load reserve demand of the system, the historical forecast error is used to measure the impact of net load members on the net load reserve demand of the system, and the calculation period considered is consistent with the historical data considered for quantifying the system reserve demand in 1). is the actual power of the net load member; is the predicted power of the net load member;

[0311] 4) Determine whether m is equal to the number of payload members (N n ), if so, it indicates that the calculation of all payload members has been completed, go to step 5), otherwise, return to step 2);

[0312] 5) Calculate the impact ratio of each net load member on the system net load reserve demand characterized by substitution benefits, as shown in formula (7):

[0313]

[0314] Among them, V m is the ratio of the influence of net load member m on the system net load reserve demand as characterized by substitution benefit, wherein the max function is introduced to avoid a negative value of the influence of a net load member on the system net load reserve demand as characterized by substitution benefit;

[0315] 6) Calculate the impact ratio of each net load member on the system net load reserve demand characterized by the historical forecast error, as shown in Equation 8:

[0316]

[0317] Among them, E m is the influence ratio of net load member m on the system net load reserve demand characterized by historical forecast error;

[0318] 7) Taking into account the substitution benefits and historical prediction errors, the comprehensive impact ratio of each net load member is formed, as shown in Formula 9:

[0319] α m =β V Vm +β E E m (9)

[0320] Among them, α m is the comprehensive influence ratio of net load member m; β V and β E are the proportions of the impact of substitution benefits and the impact of historical forecast errors, which can be adjusted according to the allocation preference. V and β E The values ​​of are all set to 0.5;

[0321] 8) According to the comprehensive impact ratio of net load members, calculate the net load backup cost that each net load member should bear, as shown in formula (10):

[0322] C n,m =α m C n (10)

[0323] Among them, C n,m is the net load backup cost that net load member m needs to bear; C n is the total net load backup cost of the system.

[0324] Thus, the net load reserve cost is allocated between renewable energy and load. The proposed method comprehensively considers the prediction randomness of net load members themselves and the mutual offset of prediction errors between different members, which can more effectively reflect the impact of net load members on the system net load reserve demand.

[0325] In summary, the present invention proposes a tiered allocation method for the intra-provincial and inter-provincial power grid operation reserve costs based on demand tracing. Based on the system operation reserve demand quantification method commonly used in the industry, it traces the influence of different market members on the system's intra-provincial and inter-provincial reserve demand, thereby achieving a reasonable allocation of intra-provincial and inter-provincial reserve costs among various market members. While ensuring flexible adjustment of resource benefits, it promotes the subject that causes reserve demand to actively reduce its own uncertainty. This method mainly includes the following two features:

[0326] 1) A tiered allocation framework for intra- and inter-provincial backup costs based on demand tracing is proposed. Taking existing allocation methods that take substitution benefits into account as an example, the necessity of matching backup cost allocation methods with industrial demand quantification methods is analyzed. On this basis, a tiered allocation framework for intra- and inter-provincial operating backup costs that takes into account common demand quantification methods is proposed. Combined with the industrial demand quantification method of taking the maximum value, intra- and inter-provincial backup costs are first decomposed into accident backup costs and net load backup costs, enabling accurate tracing of backup demand among market members of different categories. Subsequently, based on the impact of each market member on accident backup or net load backup, the backup costs are allocated among market members of the same category.

[0327] 2) A method for allocating various types of operating reserve costs that considers the combined uncertainties of market members is proposed. For the emergency reserve demand determined by the maximum capacity of a single unit, a method for allocating emergency reserve costs that accounts for common demand is adopted, taking into account the discrete characteristics caused by taking the maximum value. For the net load reserve demand determined by the overall system net load forecast error, a method for allocating net load reserve costs that takes into account the coupled impact of the forecast errors of different market members is proposed, taking into account the improved substitution benefits. This method can take into account the combined characteristics of the forecast errors of different market members as well as their own uncertainties. This allows for the traceability and allocation of the two types of reserve costs among the corresponding market members.

[0328] The present invention conducts research on the allocation of upper operating standby costs. For lower operating standby costs, the responsible entities only include new energy and loads, and the proposed improved substitution benefit method can be used for direct allocation.

[0329] Example 12:

[0330] The verification of a demand tracing-oriented hierarchical allocation method for intra-provincial and inter-provincial power grid operation reserve costs is as follows:

[0331] The simulation results on the grid structure of a regional power grid composed of three IEEE 30-node systems show that the proposed layered allocation method for backup costs can achieve a more reasonable allocation of operating backup costs. The specific steps of the method are as follows:

[0332] ① Based on the reserved operating reserve of the units and the intra-provincial and inter-provincial standby prices, the intra-provincial and inter-provincial operating standby costs are calculated; ② Based on the cost sharing idea taking into account common needs, the intra-provincial and inter-provincial operating standby costs are decomposed into accident standby costs and net load standby costs; ③ Based on the cost sharing idea taking into account common needs, the accident standby costs are allocated among the conventional units; ④ Based on the cost sharing idea taking into account the improved substitution benefits, the net load standby costs are allocated between new energy sources and loads.

[0333] (1) Example

[0334] Based on actual renewable energy and load data from a provincial power grid in my country (with a renewable energy penetration rate of 30%), a case study was conducted using a regional power grid consisting of three IEEE 30-node systems as the grid structure. Operating reserve cost allocation was performed on a specific standby receiving system within the regional power grid. It should be noted that the allocation method proposed in this paper is ex post and does not involve solving a scheduling optimization model. Therefore, it can effectively maintain computational efficiency even when applied to large-scale systems. The purpose of using a small-scale system for this case study simulation is to facilitate analysis of the rationale of different allocation methods. In the simulation, the renewable energy and load data were scaled to match the test system. The system to be allocated operating reserve costs includes six conventional units and two wind turbines. In this case study, cost allocation is performed only for operating reserve. Before cost allocation, the market clearing process is performed (with a 15-minute clearing granularity, meaning a total of 96 clearing periods per day) to obtain the operating status of market members and the total operating reserve cost of the system. The maximum downward forecast error of the renewable energy forecast, the maximum upward forecast error of the load forecast, the power generation / consumption of each market member on the operation day, and the installed capacity of each unit are shown in Table 1.

[0335] Table 1 Market member parameters

[0336]

[0337] The simulation will compare the following alternative cost allocation methods:

[0338] M1: The proposed method for stratified allocation of intra-provincial and inter-provincial power grid operation standby costs for demand tracing;

[0339] M2: Same as M1, but the net load operation reserve cost adopts the allocation method taking into account the traditional substitution benefit (for market members with negative substitution benefits, the impact is treated as 0 to avoid the situation where fees are paid to the reserve responsible party;

[0340] M3: Same as M1, but directly taking into account the idea of ​​common demand sharing, the total operating reserve cost is decomposed into accident reserve cost and net load reserve cost, without considering the characteristic that when the provincial operating reserve resources cannot meet the provincial reserve demand, it is necessary to seek reserve support from other provinces;

[0341] M4: Directly use the traditional substitution benefit method to complete the allocation of total operating reserve costs within and between provinces to each market member;

[0342] M5: Traditional method for allocating total operating reserve costs within and between provinces taking into account the generation / consumption ratio of market members;

[0343] M6: A method for allocating total operating reserve costs within and between provinces that takes into account the risk ratio of market members, quantifying the risk of a market member based on the reserve demand (installed capacity, estimated maximum forecast error) caused by the market member itself.

[0344] (2) Verification of the effectiveness of the operating standby cost allocation method

[0345] (a) Comparative analysis of overall allocation results of operating standby costs

[0346] The total system operation standby cost for the 96 clearing periods during the operation day is shown in Table 2, and the system operation standby cost allocation results under different methods are shown in Table 3.

[0347] Table 2 System operation standby cost

[0348]

[0349] Table 3 System operation standby cost allocation results under different methods (×10 4 $)

[0350]

[0351]

[0352] Table 3 shows that the difference in allocation results between M2 and proposed method M1 is primarily reflected in the allocation of wind power to load. M2 uses substitution benefits to characterize the impact of net load members on the system's net load reserve demand. Due to the offsetting of forecast errors between different net load members, the net load reserve demand actually decreases in some clearing periods after the addition of wind turbine 2. M2 assumes that wind turbine 2 does not incur reserve costs during these periods, resulting in a lower reserve cost for wind turbine 2, comparable to that of wind turbine 1. However, Table 1 shows that wind turbine 2's forecast error is 10.7% higher than that of wind turbine 1. Wind turbine 2 actually has significant forecast randomness and should bear a higher reserve cost. To address this issue, proposed method M1 introduces forecast errors based on substitution benefits to account for the uncertainty inherent in market members. Ultimately, in M1, wind turbine 2 bears a higher reserve cost than wind turbine 1, effectively encouraging net load market members to proactively improve their forecast accuracy.

[0353] M3 does not consider the relationship between the supply and demand of intra-provincial and inter-provincial reserve, but directly allocates the intra-provincial and inter-provincial reserve costs as a whole. The price difference between inter-provincial reserve and intra-provincial reserve (in this example, the price of inter-provincial reserve is higher than that of intra-provincial reserve) causes the subject responsible for accident reserve to bear more reserve costs compared to M1, while the subject responsible for net load reserve bears less reserve costs. The reason for the above difference is that in each clearing period, the system net load reserve demand is generally greater than the system accident reserve demand. Therefore, as described in Section 1.2, the net load market members will bear more inter-provincial reserve costs in M1, so the total net load reserve cost of M1 will eventually be higher than that of M3. Figure 7 The next section will further analyze the necessity of considering the intra-provincial and inter-provincial reserve supply and demand relationship when allocating reserve costs, using specific cases.

[0354] M4 directly uses the traditional substitution benefit method to allocate the system's overall operating reserve costs to each market member, without considering the industry's most valuable operating reserve demand quantification method. Since the installed capacity of thermal power units 3-6 is relatively small, their connection does not cause an increase in the system's operating reserve demand. Therefore, the reserve cost borne by thermal power units 3-6 in M4 is 0. The reserve cost borne by conventional units is much lower than that of net load market members, such as Figure 7 However, in reality, thermal power units 3-6 are responsible for the system's operational reserve requirements and should bear the associated reserve costs. This demonstrates the need for the operational reserve cost allocation method to match the quantification method for the system's operational reserve requirements.

[0355] M5 allocates system operating reserve costs based on the generation / consumption ratio of market members. As shown in Table 1, the load's electricity consumption far exceeds the generation of other market members, resulting in a high burden of system operating costs. However, as shown in Tables 1 and 3, the load's forecast error is similar to that of the two wind turbines, yet the reserve cost incurred is 5.8 times the average reserve cost of the wind turbines. Therefore, the traditional allocation method based on generation / consumption ratio fails to quantify the uncertainty of each market member and its impact on system reserve demand, making it difficult to achieve a reasonable allocation of reserve costs.

[0356] M6 shares the operating reserve cost based on the risk ratio of market members. As shown in Table 1, the sum of the reserve demand caused by the six conventional units themselves (i.e., the sum of the installed capacity of all units) is much higher than the sum of the reserve demand caused by the net load members. Therefore, under the risk ratio sharing mode, the conventional units bear high system operating costs, such as Figure 7As shown. However, in the actual operation reserve demand quantification process, the total operation reserve demand of the system is not the accumulation of the demands of each market member itself. The discrete characteristics of taking the maximum value result in the conventional units having less impact on the actual operation reserve demand of the system than the net load market members. Specifically, in 96 clearing periods, the cumulative reserve demand caused by the net load market members alone reached 2572MW, while the cumulative reserve demand caused by the conventional units alone was only 273MW. Therefore, the net load market members should bear more reserve costs, which is inconsistent with the allocation result of M6. The method M1 proposed in the present invention takes into account the quantitative method of the system operation reserve demand, and the resulting allocation result is more reasonable. Therefore, it once again reflects the necessity of the operation reserve cost allocation method matching the quantitative method of the system operation reserve demand.

[0357] (b) The necessity of considering the relationship between intra-provincial and inter-provincial reserve supply and demand in the allocation method

[0358] In order to further illustrate the necessity of considering the intra-provincial and inter-provincial reserve supply and demand relationship in the operating reserve cost allocation method, the following takes clearing period 25 as an example to further explain the intra-provincial and inter-provincial reserve cost allocation results of the M1 and M3 methods.

[0359] The supply and demand of the operating reserve of the system to be allocated during this clearing period is shown in Table 4, and the composition of the system operating reserve cost is shown in Table 5.

[0360] Table 4 System operation reserve supply and demand in period 25

[0361]

[0362] As can be seen from Table 4, during this clearing period, the provincial reserve supply can cope with the system accident reserve demand, but it is difficult to effectively cope with the net load reserve demand, thus requiring the support of extra-provincial reserve resources, which causes inter-provincial operation reserve costs. Considering the above situation, the inter-provincial operation reserve costs in the proposed method M1 will be borne entirely by the net load market members (e.g. Figure 8 As shown in the figure, it complies with the principle of “whoever causes it, bears the responsibility”. However, M3 does not consider the supply and demand relationship between the intra-provincial and inter-provincial standby costs, but decomposes the total cost of the intra-provincial and inter-provincial standby costs as a whole into the accident standby cost and the net load standby cost. Therefore, the conventional units also bear the inter-provincial standby cost (such as Figure 8 As shown in Tables 4 and 5, due to the higher inter-provincial reserve costs, the reserve costs ultimately borne by conventional units are higher than those allocated using M1. In summary, allocation method M3 fails to consider the supply and demand relationship between intra- and inter-provincial reserve costs, resulting in conventional units also bearing the more expensive inter-provincial reserve costs, which violates the allocation principle of "whoever causes it, pays for it." Therefore, it is necessary to consider the supply and demand of reserve within and between provinces when allocating operating reserve costs.

[0363] The present invention proposes a hierarchical allocation method for the operation reserve cost of the intra-provincial and inter-provincial power grid for demand tracing. The method first considers the discrete characteristics of the maximum value quantification method in the industry, proposes an allocation method that takes into account the common demand, decomposes the intra-provincial and inter-provincial reserve costs into accident reserve costs and net load reserve costs, and realizes the accurate tracing of the reserve demand matching the demand quantification method. Subsequently, considering the superposition characteristics of the uncertainty of different categories of market members, the accident reserve and net load reserve costs are further allocated to each market member through common demand allocation and improved substitution benefits. While ensuring the flexible adjustment of resource benefits, the present invention encourages the responsible parties that cause reserve demand to actively reduce their own uncertainty, which is of great significance for the power system to deal with uncertainties such as new energy, random load fluctuations, and unit failure and outage.

Claims

1. A method for stratified allocation of intra-provincial and inter-provincial power grid operation reserve costs based on demand tracing, characterized in that: The following steps are involved: 1) Establish a tiered allocation framework for intra-provincial and inter-provincial operational reserve costs that takes into account common needs; 2) Based on the intra-provincial and inter-provincial operating reserve cost tiered allocation framework, with the lowest overall operating cost of regional power grid energy and reserve as the objective function and subject to grid operation constraints, various types of operating reserve cost allocation schemes that take into account the uncertain superposition characteristics of market members are generated and implemented; Various types of operating reserve cost sharing plans include accident reserve cost sharing plans that take into account common demand sharing and net load reserve cost sharing plans that take into account improved substitution benefits.

2. The method for layered allocation of intra-provincial and inter-provincial power grid operation standby costs based on demand tracing according to claim 1 is characterized in that: The tiered allocation framework for intra-provincial and inter-provincial operation reserve costs taking into account the equalization of common demands includes Scenario 1 and Scenario 2; Scenario 1 means: the operating reserve provided by the province is less than the emergency reserve demand and the net load reserve demand; Scenario 2 means that the operating reserve provided by the province is greater than the accident reserve demand or the net load reserve demand.

3. The method for stratified allocation of intra-provincial and inter-provincial power grid operation standby costs based on demand tracing according to claim 2 is characterized in that: In the first scenario, the intra-provincial standby cost is evenly decomposed into accident standby cost and net load standby cost; part of the inter-provincial standby cost caused by conventional units and net load members is evenly decomposed into accident standby cost and net load standby cost, and the remaining inter-provincial standby costs are all decomposed into net load standby cost.

4. The method for stratified allocation of intra-provincial and inter-provincial power grid operation standby costs based on demand tracing according to claim 2 is characterized in that: Under the second scenario, part of the intra-provincial standby costs caused by conventional units and net load members will be evenly decomposed into accident standby costs and net load standby costs, and the remaining intra-provincial standby costs will be all decomposed into net load standby costs; the inter-provincial standby costs will be all decomposed into net load standby costs.

5. The method for layered allocation of intra-provincial and inter-provincial power grid operation standby costs based on demand tracing according to claim 2 is characterized in that: The intra-provincial and inter-provincial operating standby costs are as follows: Among them, C R,I and C R,O are the intra-provincial and inter-provincial operation standby costs respectively; i is the unit number within the province; N g is the number of units in the province; k is the number of units outside the province; L g is the number of units outside the province; R,I and λ R,O are the reserve prices for intra-provincial and inter-provincial operation respectively; R i and R k They are respectively provided as operating backup for each unit within the province and between provinces.

6. The method for layered allocation of intra-provincial and inter-provincial power grid operation standby costs based on demand tracing according to claim 1 is characterized in that: The steps for generating an accident reserve cost allocation plan that takes into account common demand sharing include: 1) Sort all conventional units in ascending order of installed capacity, and set j = 1; 2) Determine whether j is greater than the number of conventional units N g If not, go to step 3), if yes, go to step 6) to complete the accident backup cost allocation; 3) After deducting the emergency standby demand caused by unit j-1, calculate the number of units from unit j to unit N. g The jointly caused accident reserve demand ΔR c,j ,Right now: ΔR c,j =R c,j -R c,j-1 (2) Where, ΔR c,j After deducting the emergency standby demand caused by unit j-1, the total number of units j to N is g The accident reserve demand caused by the joint; R c,j is the emergency standby demand caused by unit j; 4) The emergency backup demand ΔR c,j The corresponding emergency standby cost is evenly distributed to unit j to unit N g ,Right now: in, Indicates the ΔR that unit i needs to bear c,j The corresponding accident backup cost; R c is the total emergency backup demand of the system; C c is the total system emergency backup cost; 5) Set j = j + 1 and return to step 2); 6) Complete the common demand allocation among all conventional units and calculate the emergency standby cost that each conventional unit needs to bear, that is: Among them, C c,i is the accident standby cost that unit i needs to bear.

7. A method for stratified allocation of intra-provincial and inter-provincial power grid operation standby costs based on demand tracing according to claim 6, characterized in that: In step 3), if j-1=0, the deducted emergency reserve demand is 0.

8. The method for layered allocation of intra-provincial and inter-provincial power grid operation standby costs based on demand tracing according to claim 1 is characterized in that: The steps to generate a net load reserve cost allocation plan that accounts for improved substitution benefits include: 1) Calculate the system's net load reserve requirement R when considering all net load members n , the method proposed in the literature is used to quantify the system net load reserve demand, and m = 1; 2) Calculate the net load backup demand of the system without considering the net load member m, and obtain the change of the net load backup demand of the system before and after the member is added, that is: v m =R n -R n,-m (5) Among them, v m The change of the system net load backup demand before and after the net load member m is added. The subscript -m means that the net load member m is not considered. 3) Calculate the historical average absolute forecast error of the net load member m, that is: Among them, e m is the historical average absolute forecast error of net load member m; t is the number of forecast time points; T is the number of forecast time points included in the calculation period; is the actual power of the net load member; is the predicted power of the net load member; 4) Determine whether m is equal to the number of payload members N n If yes, go to step 5), otherwise, return to step 2); 5) Calculate the impact ratio of each net load member on the system net load reserve demand characterized by substitution benefits, that is: Among them, V m is the influence ratio of net load member m on the system net load reserve demand characterized by substitution benefit; 6) Calculate the impact ratio of each net load member on the system net load reserve demand characterized by the historical forecast error, that is: Among them, E m is the influence ratio of net load member m on the system net load reserve demand characterized by historical forecast error; 7) Taking into account the substitution benefits and historical prediction errors, the comprehensive impact ratio of each net load member is formed, that is: a m =b V V m +b E E m (9) Among them, α m is the comprehensive influence ratio of net load member m; β V and β E are the proportions of the impact of substitution benefits and the impact of historical forecast errors respectively; 8) According to the comprehensive impact ratio of net load members, calculate the net load backup cost that each net load member should bear, that is: C n,m =α m C n (10) Among them, C n,m is the net load backup cost that net load member m needs to bear; C n is the total net load backup cost of the system.

9. The method for layered allocation of intra-provincial and inter-provincial power grid operation standby costs based on demand tracing according to claim 1 is characterized in that: In step 2), the objective function is as follows: Where a is the number of the provincial power grid in the region; V is the set of provincial power grids in the region; t is the time period number; T is the time period set; g a is the unit number of province a; G a is the set of units in province a; b is the number of the provincial power grid outside province a; is the energy cost; It is the reserve cost within the province; To save standby costs; Quote for energy; Provide power for the unit; Provide quotes for up / down spare within the province; Intra-province up / down standby provided for units; Provide a quotation for inter-provincial up / down reserve for units in Province A to be provided to Province B; The inter-provincial up / down backup provided by the units in Province A to Province B.

10. The method for layered allocation of intra-provincial and inter-provincial power grid operation standby costs based on demand tracing according to claim 1, characterized in that: In step 2), the grid operation constraints include inter-provincial tie line transmission power constraints, power balance constraints, unit output upper and lower limit constraints, unit reserve constraints, unit ramp constraints, system operation reserve demand constraints, and line flow constraints; The transmission power constraints of inter-provincial tie lines are as follows: Where, l T is the contact line number; n a is the node number; w a W is the wind turbine group number; a Assemble for wind turbines; The upper and lower limits of the transmission power of the tie line; Node n for province a a To inter-provincial communication line T The power transfer distribution factor; They are thermal power generation units and wind power generation units to node n a The incidence matrix elements of ; is the power forecast value of wind turbine and load; Transmit power to the tie line; The power balance constraints are as follows: Where, is the amount of power between provinces a and b, a positive value indicates that power flows from province a to province b; The calculation method is as follows: Where, L T,ab Represents the set of contact lines between provinces a and b. The upper and lower limits of the unit output are as follows: Where, They are the upper and lower limits of the output of thermal power units respectively. The unit reserve constraints are as follows: Where, They are the up / down climbing capabilities of thermal power units respectively. The unit ramp constraints are as follows: The system operation backup requirement constraints are as follows: Where, They are the upper / lower reserve requirements of the provincial power grid respectively. The line power flow constraints are as follows: Where, l is the number of the provincial line; P l 、 is the upper and lower limits of the transmission power of line l within the province; P l Transmit power to the line; Node n for province a a Power transfer distribution factor to line l.

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