A demand-oriented in-province and inter-province power grid operation backup cost hierarchical allocation method

Abstract

The application discloses a kind of in-province-in-province power grid operation backup cost layered allocation methods for demand traceability, comprising the following steps: 1) build in-province-in-province operation backup cost layered allocation framework considering common demand allocation;2) based on in-province-in-province operation backup cost layered allocation framework, with the minimum total operation cost of regional power grid energy and backup as objective function, with power grid operation constraint as condition, generate and execute each type of operation backup cost allocation scheme considering the superposition characteristics of market member uncertainty;The application considers the responsibility subject causing inter-provincial operation backup support demand, realizes the reasonable allocation of in-province, inter-provincial total operation backup cost to conventional unit and net load member.

Description

Technical Field

[0001] This invention relates to the field of power systems and their automation, specifically a demand-based method for hierarchical allocation of reserve operating costs for intra-provincial and inter-provincial power grids. Background Technology

[0002] Reserved operational reserves are a crucial technical means for power systems to cope with uncertainties such as new energy sources, random load fluctuations, and unit outages. With the increasing frequency and extent of extreme weather events in my country, operational reserve services will play an increasingly important role in ensuring power supply. Under the current deterministic dispatch decision-making model adopted in industry, the method for formulating operational reserve reserve plans for flexible adjustment resources is as follows: System operational reserve requirements are pre-defined, and then operational reserve requirement constraints are embedded in the dispatch decision model to determine the operational reserves that each flexible adjustment resource should reserve, thereby ensuring that the system has sufficient operational margin.

[0003] Based on the factors that trigger operational reserve requirements, they can be divided into two categories: one is the contingency reserve requirement to address power deficits caused by generator failures; the other is the net load reserve requirement to address power deviations caused by new energy sources and load forecasting errors. To ensure the adequacy of system reserves, the industry currently generally uses the maximum of the contingency reserve requirement and the net load reserve requirement as the final system operational reserve requirement.

[0004] After optimizing the allocation of operational reserves, operational reserve costs are incurred (i.e., the expenses incurred by flexible adjustment resources in providing operational reserves). In a market environment, adhering to the incentive compatibility principle of "whoever causes it, bears it," a source analysis of reserve demand should be conducted, and operational reserve costs should be reasonably allocated to market participants that cause operational reserve demand. This will encourage participants such as renewable energy sources that cause operational reserve demand to proactively reduce their own random fluctuation characteristics. With the continuous advancement of the construction of high-proportion renewable energy power systems, grid operational reserve costs will increase significantly, making their reasonable allocation even more important. Domestic and international scholars have already conducted relevant research on this issue.

[0005] In industry, operating reserve costs are typically allocated among market participants, including conventional power sources, renewable energy sources, and users, based on the generation / consumption ratio. For example, the US PJM electricity market charges users reserve fees according to their consumption ratio; some studies allocate reserve costs to power generators based on their on-grid electricity volume. These methods are simple and easy to implement, but they do not consider the uncertainties of market participants and fail to reflect the true impact of each market participant on operating reserves.

[0006] The academic community has conducted extensive research on methods for allocating reserve costs that take into account the uncertainties of market participants. Some studies calculate reserve cost contribution rates to reflect the proportion of each type of uncertainty factor contributing to the increase in operating reserve costs, and allocate system operating reserve costs accordingly. Other studies explore the main risks causing reserve demand, such as random outages of conventional generators and net load forecasting errors, and achieve reserve cost allocation by establishing conditional risk reserve models. While these methods can consider the uncertainties of market participants, they only consider the characteristics of the market participants themselves. In reality, system uncertainty is not a simple summation of the uncertainties of individual market participants, and the individual uncertainties of market participants cannot accurately reflect their impact on the system's operating reserve demand.

[0007] To address these issues, some studies have constructed analytical correlations between renewable energy sources, random load fluctuations, and system reserve demand based on operational experience, embedding these correlations into market clearing models to derive reserve price components characterizing the uncertainty of renewable energy sources and loads. This allows for the natural allocation of reserve costs through price signals. However, simple correlations based on operational experience cannot objectively reflect the true impact of market participants on system reserve demand. Similarly, some studies have derived price components related to the random fluctuation characteristics of renewable energy sources based on opportunity-constrained scheduling optimization models. However, the application scenarios of opportunity-constrained stochastic optimization models in actual power grid operation are limited, and these methods do not consider the system uncertainty caused by generator outages. Some studies have implemented reserve cost allocation based on coalition game theory (such as Shapley values), but these methods have high computational complexity. Other studies have considered substitution benefit theory in allocating reserve costs. These methods measure the influence of market participants on system reserve demand based on changes in system reserve costs (or reserve demand) before and after their integration, thereby achieving cost allocation. However, in a few scenarios, some market participants may have negative substitution benefits (meaning that due to the offsetting effects of uncertainties, the market participant's impact on the system's reserve requirements is negative). In this case, the market participant can actually obtain reserve benefits, which differs from the actual operating conditions of the system.

[0008] The aforementioned studies primarily explored the allocation of intra-provincial operating reserve costs. However, to achieve broader optimization of reserve resource allocation, my country has established regional reserve markets, promoting inter-provincial mutual assistance of reserve resources through cross-provincial and inter-regional reserve ancillary service transactions. Currently, there is a lack of research on inter-provincial reserve cost allocation. The Southern Regional Power Reserve Ancillary Service Market uses a method where receiving provinces allocate inter-provincial reserve costs proportionally based on monthly on-grid or localized power generation, failing to reflect the impact of different market participants on inter-provincial reserve demand.

[0009] In summary, existing research has extensively and beneficially explored the quantification of the impact of market participants on system operational reserve requirements and the allocation of operational reserve costs based on this quantification. In reality, the impact of market participants on system operational reserve requirements is closely related to the quantification method of these requirements; therefore, the allocation method for reserve costs should match the quantification method of reserve requirements. The current industry standard of using the larger of contingency reserve requirements and net load reserve requirements reveals both common and specific needs among different market participants. However, existing operational reserve cost allocation methods generally do not consider the actual quantification methods used in industry. This mismatch between allocation methods and quantification methods leads to inaccurate tracing of reserve requirements and makes it difficult to achieve a reasonable allocation of reserve costs. Summary of the Invention

[0010] The purpose of this invention is to provide a demand-based, source-based method for tiered allocation of reserve costs for intra-provincial and inter-provincial power grid operations, comprising the following steps:

[0011] 1) Construct a hierarchical allocation framework for intra-provincial and inter-provincial operational reserve costs that takes into account the sharing of common needs;

[0012] 2) Based on the hierarchical allocation framework of intra-provincial and inter-provincial operating reserve costs, with the objective function of minimizing the regional power grid energy and overall operating cost of reserves, and with power grid operation constraints as conditions, various types of operating reserve cost allocation schemes are generated and executed, taking into account the superimposed uncertainties of market participants.

[0013] The cost-sharing schemes for various types of operational standby include accident standby cost-sharing schemes that take into account the sharing of common needs and net load standby cost-sharing schemes that take into account the benefits of improved alternatives.

[0014] Furthermore, the provincial-interprovincial operating reserve cost tiered allocation framework that takes into account the sharing of common needs includes Scenario 1 and Scenario 2;

[0015] Scenario 1 refers to a situation where the operational reserve provided within the province is less than the emergency reserve requirement and the net load reserve requirement.

[0016] Scenario 2 refers to a situation where the operational reserve provided within the province exceeds the emergency reserve requirement or the net load reserve requirement.

[0017] Furthermore, in the following scenario, the provincial reserve cost is allocated equally to the contingency reserve cost and the net load reserve cost; the inter-provincial reserve cost jointly caused by conventional units and net load members is allocated equally to the contingency reserve cost and the net load reserve cost, and the remaining inter-provincial reserve cost is allocated entirely to the net load reserve cost.

[0018] Furthermore, in Scenario 2, a portion of the provincial reserve costs jointly incurred by conventional units and net load members are allocated equally to contingency reserve costs and net load reserve costs, while the remaining provincial reserve costs are allocated entirely to net load reserve costs; inter-provincial reserve costs will be allocated entirely to net load reserve costs.

[0019] Furthermore, the operating standby costs within and between provinces are as follows:

[0020]

[0021] Among them, C R,I and C R,O These represent the operating reserve costs within and between provinces, respectively; i represents the unit number within the province; N g L represents the number of generating units within the province; k represents the unit number outside the province; L g The number of units located outside the province; λ R,I and λ R,O These are the standby prices for intra-provincial and inter-provincial operations, respectively; R i and R k These are operational reserves provided for units within and between provinces.

[0022] Furthermore, the steps for generating an accident reserve cost allocation scheme that takes into account the sharing of common needs include:

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

[0024] 2) Determine if j is greater than the number of conventional generating units N. g If not, proceed to step 3); if yes, proceed to step 6 to complete the allocation of accident reserve costs.

[0025] 3) After deducting the emergency reserve requirements caused by unit j-1, the computer groups j to N g Commonly caused accident reserve requirements 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 reserve requirements caused by unit j-1, units j to N g Commonly caused emergency backup requirements; R c,j Backup requirements for accidents caused by unit j;

[0028] 4) The emergency reserve requirement ΔR c,j The corresponding emergency standby costs are averaged and allocated to units j to N. g ,Right now:

[0029]

[0030] in, This indicates the ΔR that unit i needs to bear. c,j The corresponding emergency backup cost; R c For system-wide emergency backup requirements; C c Total system failover cost;

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

[0032] 6) Allocate common requirements among all conventional generating units and calculate the emergency standby cost to be borne by each conventional generating unit, i.e.:

[0033]

[0034] Among them, C c,i The emergency backup cost that unit i needs to bear.

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

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

[0037] 1) Calculate the system's net load reserve requirement R when considering all net load members. n The system net load reserve requirement is quantified using the method proposed in the literature, while setting m=1;

[0038] 2) Calculate the system's net load reserve requirement without considering net load member m, and obtain the changes in the system's net load reserve requirement before and after this member's access, i.e.:

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

[0040] Among them, v m This describes the change in the system's net load reserve requirement before and after the net load member m is connected; the subscript -m indicates that net load member m is not considered.

[0041] 3) Calculate the historical average absolute prediction error of net load member m, i.e.:

[0042]

[0043] Among them, e m t represents the historical average absolute prediction error of net load member m; t represents the prediction time point number; T represents the number of prediction time points included in the calculation period. The actual power of the net load members; Forecast power for net load members;

[0044] 4) Determine if m is equal to the number of net load members N. n If yes, proceed to step 5); otherwise, return to step 2.

[0045] 5) Calculate the proportion of the impact of each net load member on the system's net load reserve requirement, as characterized by substitution benefits, i.e.:

[0046]

[0047] Among them, V m The proportion of the net load member m to the system net load reserve requirement, characterized by substitution benefits;

[0048] 6) Calculate the proportion of the impact of each net load member on the system net load reserve requirement, as characterized by historical forecast errors, i.e.:

[0049]

[0050] Among them, E m The proportion of the net load member m to the system net load reserve requirement, characterized by historical prediction errors;

[0051] 7) Taking into account both substitution benefits and historical forecast errors, the overall impact ratio of each net load member is determined, i.e.:

[0052] α m =β V V m +β E E m (9)

[0053] Where, α m The overall influence ratio of net load member m; β V and β E These represent the proportions of the impact of substitution benefits and the impact of historical prediction errors, respectively.

[0054] 8) Calculate the net load reserve cost to be borne by each net load member based on the overall impact ratio of the net load members, i.e.:

[0055] C n,m =α m C n (10)

[0056] Among them, C n,m Net load reserve costs to be borne by net load member m; C n This represents the total net load reserve cost of the system.

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

[0058]

[0059] In the formula, a is the provincial power grid number within the region; V is the set of provincial power grids within the region; t is the time period number; T is the time period set; g a For unit number in province A; G a 'b' represents the set of generating units in province a; 'b' represents the number of the provincial power grid outside of province a. Energy cost; For reserve costs within the province; For inter-provincial backup costs; Price energy; To provide power to the generator unit; For backup quotes within the province; Provincial-level backup / standby for the generating unit; Quotations for inter-provincial standby / backup services provided by generating units in province A to province B; σ represents the inter-provincial reserve provided by the unit in province a to province b; σ is the penalty coefficient for inter-provincial reserve call-up, which is a constant with a large value.

[0060] Furthermore, in step 2), the power 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 ramping constraints, system operation reserve demand constraints, and line power flow constraints.

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

[0062]

[0063] In the formula, l T For the contact line number; n a Number the nodes; w a For wind turbine generator number; W a A collection of wind turbine units; These are the upper and lower limits of the transmission power of the tie line; For node n in province a a To inter-provincial connecting lines T The power transfer distribution factor; These represent the distances from thermal power units and wind power units to node n, respectively. a The elements of the correlation matrix; These are the predicted power values ​​for wind turbines and loads. To transmit power to the tie line;

[0064] The power balance constraints are as follows:

[0065]

[0066] In the formula, This represents the 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] In the formula, L T,ab This represents the set of connecting lines between provinces a and b.

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

[0071]

[0072] In the formula, These represent the upper and lower limits of the output of thermal power units, respectively.

[0073] The unit's standby constraints are as follows:

[0074]

[0075] In the formula, These refer to the uphill / downhill climbing capabilities of thermal power units.

[0076] The unit's ramp-up constraints are as follows:

[0077]

[0078] The system's standby requirements are constrained as follows:

[0079]

[0080] In the formula, These represent the upstream and downstream reserve requirements of the provincial power grid.

[0081] The power flow constraints for the lines are as follows:

[0082]

[0083] In the formula, l is the number of the route within the province; P l , P represents the upper and lower limits of transmission power for line l within the province; l For line transmission power; For node n in province a a The power transfer distribution factor to line l.

[0084] The technical effects of this invention are undeniable, and its beneficial effects are as follows:

[0085] 1) Due to the discrete nature of the quantification method for operational reserve requirements in the industry, there are common and specific needs among different market participants. Reserve costs arising from common needs should be shared equally among the relevant market participants, while reserve costs arising from specific needs should be borne solely by the relevant market participants. The hierarchical allocation framework for operational reserve costs proposed in this invention, which considers the sharing of common needs, can effectively take into account the above characteristics, achieving a reasonable decomposition of the total system operational reserve cost into contingency reserve cost and net load reserve cost.

[0086] 2) Support from inter-provincial operational reserve resources is only needed when the province's operational reserve resources are insufficient to meet the province's reserve requirements. To this end, this invention considers the responsible parties for the inter-provincial operational reserve support needs, and achieves a reasonable allocation of the total operational reserve costs within and between provinces to conventional units and net load members.

[0087] 3) Due to the offsetting effects of market participants' forecasting errors, traditional substitution benefit methods cannot effectively characterize the impact of different market participants on net load reserve requirements. To address this issue, this invention introduces market participant forecasting errors into the substitution benefit framework, characterizing the comprehensive impact of market participants on system net load reserve requirements, and enabling a reasonable allocation of net load reserve costs among market participants. Attached Figure Description

[0088] Figure 1 A schematic diagram illustrating how to quantify the backup demand for industrial operations;

[0089] Figure 2 A tiered allocation framework for intra-provincial and inter-provincial operational reserve costs, taking into account the sharing of common needs;

[0090] Figure 3 The reserve of provincial resources is less than the emergency reserve requirement and the net load reserve requirement;

[0091] Figure 4 The situation where the operational reserve provided for the province exceeds the emergency reserve requirement or the net load reserve requirement.

[0092] Figure 5 The approach and process for allocating accident reserve costs to take into account common needs;

[0093] Figure 6 A process for allocating net load reserve costs to take into account the benefits of improved alternatives;

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

[0095] Figure 8 This describes the allocation of intra-provincial and inter-provincial operational reserve costs under M1 and M3. Detailed Implementation

[0096] The present invention will be further described below with reference to embodiments, but it should not be construed that the scope of the present invention is limited to the following embodiments. Various substitutions and modifications made based on ordinary technical knowledge and common practices in the art without departing from the above-described technical concept of the present invention should be included within the scope of protection of the present invention.

[0097] Example 1:

[0098] See Figures 1 to 8 A demand-based method for hierarchical allocation of reserve operating costs for intra-provincial and inter-provincial power grids includes the following steps:

[0099] 1) Construct a hierarchical allocation framework for intra-provincial and inter-provincial operational reserve costs that takes into account the sharing of common needs;

[0100] 2) Based on the hierarchical allocation framework of intra-provincial and inter-provincial operating reserve costs, with the objective function of minimizing the regional power grid energy and overall operating cost of reserves, and with power grid operation constraints as conditions, various types of operating reserve cost allocation schemes are generated and executed, taking into account the superimposed uncertainties of market participants.

[0101] The cost-sharing schemes for various types of operational standby include accident standby cost-sharing schemes that take into account the sharing of common needs and net load standby cost-sharing schemes that take into account the benefits of improved alternatives.

[0102] The provincial-interprovincial operating reserve cost tiered allocation framework that takes into account the sharing of common needs includes Scenario 1 and Scenario 2;

[0103] Scenario 1 refers to a situation where the operational reserve provided within the province is less than the emergency reserve requirement and the net load reserve requirement.

[0104] Scenario 2 refers to a situation where the operational reserve provided within the province exceeds the emergency reserve requirement or the net load reserve requirement.

[0105] In the following scenario, the provincial reserve cost is allocated equally to the contingency reserve cost and the net load reserve cost; the inter-provincial reserve cost caused by both conventional units and net load members is allocated equally to the contingency reserve cost and the net load reserve cost, and the remaining inter-provincial reserve cost is allocated entirely to the net load reserve cost.

[0106] In Scenario 2, the portion of provincial reserve costs jointly incurred by conventional units and net load members is allocated equally to contingency reserve costs and net load reserve costs, while the remaining provincial reserve costs are allocated entirely to net load reserve costs; inter-provincial reserve costs will be allocated entirely to net load reserve costs.

[0107] The intra-provincial and inter-provincial operating standby costs are shown below:

[0108]

[0109] Among them, C R,I and C R,O These represent the operating reserve costs within and between provinces, respectively; i represents the unit number within the province; N g L represents the number of generating units within the province; k represents the unit number outside the province; L g The number of units located outside the province; λ R,I and λ R,O These are the standby prices for intra-provincial and inter-provincial operations, respectively; R i and R k These are operational reserves provided for units within and between provinces.

[0110] The steps for generating an accident reserve cost allocation scheme that takes into account the common needs include:

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

[0112] 2) Determine if j is greater than the number of conventional generating units N. g If not, proceed to step 3); if yes, proceed to step 6 to complete the allocation of accident reserve costs.

[0113] 3) After deducting the emergency reserve requirements caused by unit j-1, the computer groups j to N g Commonly caused accident reserve requirements 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 reserve requirements caused by unit j-1, units j to N g Commonly caused emergency backup requirements; R c,j Backup requirements for accidents caused by unit j;

[0116] 4) The emergency reserve requirement ΔR c,j The corresponding emergency standby costs are averaged and allocated to units j to N. g ,Right now:

[0117]

[0118] in, This indicates the ΔR that unit i needs to bear. c,j The corresponding emergency backup cost; R c For system-wide emergency backup requirements; C c Total system failover cost;

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

[0120] 6) Allocate common requirements among all conventional generating units and calculate the emergency standby cost to be borne by each conventional generating unit, i.e.:

[0121]

[0122] Among them, C c,i The emergency backup cost that unit i needs to bear.

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

[0124] The steps involved in generating a net load reserve cost allocation scheme that incorporates improved alternative benefits include:

[0125] s1) Calculate the system's net load reserve requirement R when considering all net load members. n The system net load reserve requirement is quantified using the method proposed in the literature, while setting m=1;

[0126] s2) Calculate the system's net load reserve requirement without considering net load member m, and obtain the change in the system's net load reserve requirement before and after the member's access, i.e.:

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

[0128] Among them, v m This describes the change in the system's net load reserve requirement before and after the net load member m is connected; the subscript -m indicates that net load member m is not considered.

[0129] s3) Calculate the historical average absolute prediction error of net load member m, i.e.:

[0130]

[0131] Among them, e m t represents the historical average absolute prediction error of net load member m; t represents the prediction time point number; T represents the number of prediction time points included in the calculation period. The actual power of the net load members; Forecast power for net load members;

[0132] s4) Determine if m is equal to the number of net load members N n If yes, proceed to step s5); otherwise, return to step s2.

[0133] s5) Calculate the proportion of the impact of each net load member on the system net load reserve requirement, as characterized by the substitution benefit, i.e.:

[0134]

[0135] Among them, V m The proportion of the net load member m to the system net load reserve requirement, characterized by substitution benefits;

[0136] s6) Calculate the proportion of the impact of each net load member on the system net load reserve requirement, as characterized by historical prediction errors, i.e.:

[0137]

[0138] Among them, E m The proportion of the net load member m to the system net load reserve requirement, characterized by historical prediction errors;

[0139] s7) Taking into account both substitution benefits and historical forecast errors, the overall impact ratio of each net load member is determined, i.e.:

[0140] α m =β V V m +β E E m (9)

[0141] Where, α m The overall influence ratio of net load member m; β V and β E These represent the proportions of the impact of substitution benefits and the impact of historical prediction errors, respectively.

[0142] s8) Based on the overall impact ratio of net load members, calculate the net load reserve cost to be borne by each net load member, i.e.:

[0143] C n,m =α m C n (10)

[0144] Among them, C n,m Net load reserve costs to be borne by net load member m; C n This represents the total net load reserve cost of the system.

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

[0146]

[0147] In the formula, a is the provincial power grid number within the region; V is the set of provincial power grids within the region; t is the time period number; T is the time period set; g a For unit number in province A; G a'b' represents the set of generating units in province a; 'b' represents the number of the provincial power grid outside of province a. Energy cost; For reserve costs within the province; For inter-provincial backup costs; Price energy; To provide power to the generator unit; For backup quotes within the province; Provincial-level backup / standby for the generating unit; Quotations for inter-provincial standby / backup services provided by generating units in province A to province B; σ represents the inter-provincial reserve provided by the unit in province a to province b; σ is the penalty coefficient for inter-provincial reserve call-up, which is a constant with a large value.

[0148] In step 2), the power 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 ramping constraints, system operation reserve demand constraints, and line power flow constraints.

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

[0150]

[0151] In the formula, l T For the contact line number; n a Number the nodes; w a For wind turbine generator number; W a A collection of wind turbine units; These are the upper and lower limits of the transmission power of the tie line; For node n in province a a To inter-provincial connecting lines T The power transfer distribution factor; These represent the distances from thermal power units and wind power units to node n, respectively. a The elements of the correlation matrix; This represents the predicted power values ​​for wind turbines and loads. P lT To transmit power to the tie line;

[0152] The power balance constraints are as follows:

[0153]

[0154] In the formula, This represents the 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] In the formula, L T,ab This represents the set of connecting lines between provinces a and b.

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

[0159]

[0160] In the formula, These represent the upper and lower limits of the output of thermal power units, respectively.

[0161] The unit's standby constraints are as follows:

[0162]

[0163] In the formula, These refer to the uphill / downhill climbing capabilities of thermal power units.

[0164] The unit's ramp-up constraints are as follows:

[0165]

[0166] The system's standby requirements are constrained as follows:

[0167]

[0168] In the formula, These are the upstream and downstream reserve requirements of provincial power grids. However, due to load and renewable energy forecasting errors, some provincial power grids may experience insufficient downstream reserves, leading to wind and solar power curtailment. Therefore, this paper also considers the downstream reserve supply situation between provinces.

[0169] The power flow constraints for the lines are as follows:

[0170]

[0171] In the formula, l is the number of the route within the province; P l , P represents the upper and lower limits of transmission power for line l within the province; l For line transmission power; For node n in province a a The power transfer distribution factor to line l.

[0172] Example 2:

[0173] A demand-source-oriented method for hierarchical allocation of reserve costs for intra-provincial and inter-provincial power grid operations includes the following steps:

[0174] 1) Construct a hierarchical allocation framework for intra-provincial and inter-provincial operational reserve costs that takes into account the sharing of common needs;

[0175] 2) Based on the provincial-interprovincial hierarchical allocation framework for operating reserve costs, with the objective function of minimizing the regional power grid energy and overall reserve operating costs, and with power grid operation constraints as conditions, various types of operating reserve cost allocation schemes are generated and executed, taking into account the superimposed uncertainties of market participants. Specifically, the generated operating reserve cost allocation scheme should be the scheme with the lowest regional power grid energy and overall reserve operating costs, and should also meet the power grid operation constraints.

[0176] The cost-sharing schemes for various types of operational standby include accident standby cost-sharing schemes that take into account the sharing of common needs and net load standby cost-sharing schemes that take into account the benefits of improved alternatives.

[0177] Example 3:

[0178] A hierarchical allocation method for intra-provincial and inter-provincial power grid operation reserve costs based on demand sourcing, with the same technical content as in Example 2, further comprising a hierarchical allocation framework for intra-provincial and inter-provincial operation reserve costs that takes into account the sharing of common demands, including Situation 1 and Situation 2.

[0179] Scenario 1 refers to a situation where the operational reserve provided within the province is less than the emergency reserve requirement and the net load reserve requirement.

[0180] Scenario 2 refers to a situation where the operational reserve provided within the province exceeds the emergency reserve requirement or the net load reserve requirement.

[0181] Example 4:

[0182] A hierarchical allocation method for the reserve cost of intra-provincial and inter-provincial power grid operation based on demand tracing, with the same technical content as any one of embodiments 2-3, further wherein, in the following case, the intra-provincial reserve cost is averaged and allocated to the contingency reserve cost and the net load reserve cost; the inter-provincial reserve cost jointly caused by conventional units and net load members is averaged and allocated to the contingency reserve cost and the net load reserve cost, and the remaining inter-provincial reserve cost is allocated to the net load reserve cost.

[0183] Example 5:

[0184] A hierarchical allocation method for intra-provincial and inter-provincial power grid operation reserve costs based on demand tracing, with technical content identical to any one of embodiments 2-4. Further, in scenario two, a portion of the intra-provincial reserve costs jointly caused by conventional units and net load members are averaged and allocated to contingency reserve costs and net load reserve costs, while the remaining intra-provincial reserve costs are all allocated to net load reserve costs; inter-provincial reserve costs are all allocated to net load reserve costs.

[0185] Example 6:

[0186] A demand-source-oriented method for hierarchical allocation of intra-provincial and inter-provincial power grid operation reserve costs, with technical content identical to any one of embodiments 2-5, further wherein the intra-provincial and inter-provincial operation reserve costs are as follows:

[0187]

[0188] Among them, C R,I and C R,O These represent the operating reserve costs within and between provinces, respectively; i represents the unit number within the province; N g L represents the number of generating units within the province; k represents the unit number outside the province; L g The number of units located outside the province; λ R,I and λ R,O These are the standby prices for intra-provincial and inter-provincial operations, respectively; R i and R k These are operational reserves provided for units within and between provinces.

[0189] Example 7:

[0190] A demand-based method for hierarchical allocation of reserve costs for intra-provincial and inter-provincial power grid operations, with technical content identical to any one of embodiments 2-6, further comprising the following steps for allocating contingency reserve costs, including the sharing of common demands:

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

[0192] 2) Determine if j is greater than the number of conventional generating units N. g If not, proceed to step 3); if yes, proceed to step 6 to complete the allocation of accident reserve costs.

[0193] 3) After deducting the emergency reserve requirements caused by unit j-1, the computer groups j to N g Commonly caused accident reserve requirements 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 reserve requirements caused by unit j-1, units j to N g Commonly caused emergency backup requirements; R c,j Backup requirements for accidents caused by unit j;

[0196] 4) The emergency reserve requirement ΔR c,j The corresponding emergency standby costs are averaged and allocated to units j to N. g ,Right now:

[0197]

[0198] in, This indicates the ΔR that unit i needs to bear. c,j The corresponding emergency backup cost; R c For system-wide emergency backup requirements; C c Total system failover cost;

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

[0200] 6) Allocate common requirements among all conventional generating units and calculate the emergency standby cost to be borne by each conventional generating unit, i.e.:

[0201]

[0202] Among them, C c,i The emergency backup cost that unit i needs to bear.

[0203] Example 8:

[0204] A hierarchical allocation method for reserve operation costs of intra-provincial and inter-provincial power grids oriented to demand tracing, with the same technical content as any one of embodiments 2-7, further wherein, in step 3), if j-1=0, the deducted emergency reserve demand is 0.

[0205] Example 9:

[0206] A demand-source-oriented method for tiered allocation of reserve costs for intra-provincial and inter-provincial power grid operations, with technical content identical to any one of Examples 2-8, further comprising the following steps for allocating net load reserve costs considering improved substitution benefits:

[0207] 1) Calculate the system's net load reserve requirement R when considering all net load members. n The system net load reserve requirement is quantified using the method proposed in the literature, while setting m=1;

[0208] 2) Calculate the system's net load reserve requirement without considering net load member m, and obtain the changes in the system's net load reserve requirement before and after this member's access, i.e.:

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

[0210] Among them, v m This describes the change in the system's net load reserve requirement before and after the net load member m is connected; the subscript -m indicates that net load member m is not considered.

[0211] 3) Calculate the historical average absolute prediction error of net load member m, i.e.:

[0212]

[0213] Among them, em t represents the historical average absolute prediction error of net load member m; t represents the prediction time point number; T represents the number of prediction time points included in the calculation period. The actual power of the net load members; Forecast power for net load members;

[0214] 4) Determine if m is equal to the number of net load members N. n If yes, proceed to step 5); otherwise, return to step 2.

[0215] 5) Calculate the proportion of the impact of each net load member on the system's net load reserve requirement, as characterized by substitution benefits, i.e.:

[0216]

[0217] Among them, V m The proportion of the net load member m to the system net load reserve requirement, characterized by substitution benefits;

[0218] 6) Calculate the proportion of the impact of each net load member on the system net load reserve requirement, as characterized by historical forecast errors, i.e.:

[0219]

[0220] Among them, E m The proportion of the net load member m to the system net load reserve requirement, characterized by historical prediction errors;

[0221] 7) Taking into account both substitution benefits and historical forecast errors, the overall impact ratio of each net load member is determined, i.e.:

[0222] α m =β V V m +β E E m (9)

[0223] Where, α m The overall influence ratio of net load member m; β V and β E These represent the proportions of the impact of substitution benefits and the impact of historical prediction errors, respectively.

[0224] 8) Calculate the net load reserve cost to be borne by each net load member based on the overall impact ratio of the net load members, i.e.:

[0225] C n,m =α m C n (10)

[0226] Among them, Cn,m Net load reserve costs to be borne by net load member m; C n This represents the total net load reserve cost of the system.

[0227] Example 10:

[0228] A demand-based method for hierarchical allocation of reserve operation costs for intra-provincial and inter-provincial power grids, with technical content identical to any one of embodiments 2-9, further...

[0229] To accurately consider the impact of line transmission capacity on standby deliverability in standby delivery scenarios, this section constructs a unified optimization decision-making model for regional power grid standby. At the same time, models are built separately for intra-provincial standby supply and inter-provincial standby supply, which can provide a basis for distinguishing the relevant market mechanisms for intra-provincial and inter-provincial standby supply.

[0230] 1 Objective Function

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

[0232]

[0233] In the formula, a is the provincial power grid number within the region; V is the set of provincial power grids within the region; t is the time period number; T is the time period set; g a For unit number in province A; G a 'b' represents the set of generating units in province a; 'b' represents the number of the provincial power grid outside of province a. Energy cost; For reserve costs within the province; For inter-provincial backup costs; Price energy; To provide power to the generator unit; For backup quotes within the province; Provincial-level backup / standby for the generating unit; Quotations for inter-provincial standby / backup services provided by generating units in province A to province B; σ represents the inter-provincial reserve provided by the unit in province a to province b; σ is the penalty coefficient for inter-provincial reserve call-up, which is a constant with a large value.

[0234] 2. Operational Constraints

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

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

[0237]

[0238] In the formula, l T For the contact line number; na Number the nodes; w a For wind turbine generator number; W a A collection of wind turbine units; These are the upper and lower limits of the transmission power of the tie line; For node n in province a a To inter-provincial connecting lines T The power transfer distribution factor; These represent the distances from thermal power units and wind power units to node n, respectively. a The elements of the correlation matrix; These are the predicted power values ​​for wind turbines and loads.

[0239] (2) Intra-provincial operational constraints

[0240] 1) Power balance constraints

[0241] Under normal circumstances, the power generation / consumption of each province should be kept in balance, as shown in equation (13).

[0242]

[0243] In the formula, This represents the power flow between provinces a and b. A positive value indicates that power flows from province a to province b, while a negative value indicates that power flows from province b to province a. The calculation method is shown below.

[0244]

[0245] In the formula, L T,ab This represents the set of connecting lines between provinces a and b.

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

[0247] To provide backup power within and between provinces, the output of thermal power units will not be able to reach their upper and lower limits, as shown in equation (15).

[0248]

[0249] In the formula, These represent the upper and lower limits of the output of thermal power units, respectively.

[0250] 3) Unit standby constraints

[0251] The total amount of provincial and inter-provincial reserves provided by the unit should not exceed its ramping capacity, as shown in equation (16).

[0252]

[0253] In the formula, These refer to the uphill / downhill climbing capabilities of thermal power units.

[0254] 4) Unit ramp-up constraints

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

[0256]

[0257] 5) System operational backup requirements constraints

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

[0259]

[0260] In the formula, These are the upstream and downstream reserve requirements of provincial power grids. However, due to load and renewable energy forecasting errors, some provincial power grids may experience insufficient downstream reserves, leading to wind and solar power curtailment. Therefore, this paper also considers the downstream reserve supply situation between provinces.

[0261] 6) Power flow constraints of the line

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

[0263]

[0264] In the formula, l is the number of the route within the province; P l , P represents the upper and lower limits of transmission power for line l within the province; l For line transmission power; For node n in province a a The power transfer distribution factor to line l.

[0265] Example 11:

[0266] A demand-source-oriented method for hierarchical allocation of intra-provincial and inter-provincial power grid operation reserve costs, as detailed below:

[0267] (1) A demand-based, inter-provincial reserve cost tiered allocation framework

[0268] (a) Necessity analysis of matching cost allocation methods with the quantitative methods of industrial operational reserve requirements

[0269] This section will take the cost allocation method that takes into account substitution benefits as an example to analyze the necessity of matching cost allocation methods with the quantitative methods of industrial operational reserve requirements.

[0270] Current industry practices for quantifying operational reserve requirements and the changes in system operational reserve requirements before and after the commissioning of conventional units (assuming net load reserve requirements are greater than contingency reserve requirements), such as... Figure 1 As shown. By Figure 1 It is evident that the current industry primarily uses the maximum of contingency reserve demand and net load reserve demand as the system operating reserve demand. This extreme value quantification method results in discrete characteristics for changes in system operating reserve demand (the value of system operating reserve demand can only be equal to the value of contingency reserve demand or the value of net load reserve demand; the portion of operating reserve demand resulting from the combined effects of contingency reserve demand and net load reserve demand will be used to simultaneously address both contingency uncertainty and net load uncertainty). Due to this discrete characteristic, the connection of a certain type of market participant to the grid will not cause a change in system operating reserve demand. For example, in... Figure 1 In the illustrated case, the emergency reserve demand caused by conventional units is less than the net load reserve demand caused by new energy sources and existing loads. In this situation, using the maximum / minimum quantification method, the system's operational reserve demand will not change before and after considering the conventional units. However, the cost allocation method that takes into account substitution benefits measures the impact on the system's operational reserve demand by assessing the changes in the system's operational reserve demand before and after market participants join, thereby achieving cost allocation. Therefore, for Figure 1 In the illustrated case, the substitution benefit method assumes that conventional units do not generate reserve demand and therefore do not bear reserve costs. However, conventional units actually generate operational reserve demand and share some reserve services with renewable energy and loads. Therefore, the existing allocation method that considers substitution benefits does not take into account the discrete nature of the quantification of system operational reserve demand, leading to inaccurate reserve demand tracing. Conventional units enjoy operational reserve services without bearing corresponding costs, resulting in unreasonable cost allocation.

[0271] Besides substitution benefits, allocating reserve costs according to the proportion of demand (risk) generated by market participants is also a commonly used method. However, for Figure 1 In the example shown, new energy sources and loads will generate additional operational reserve requirements. The reserve costs incurred by these requirements should be borne solely by the new energy sources and loads, rather than being proportionally shared among all market participants. Therefore, this allocation method fails to account for the additional demand generated by a particular type of market participant under the extreme value quantification approach, which will also lead to unreasonable cost allocation.

[0272] In summary, the method for allocating operating reserve costs should be compatible with the quantification method of system operating reserve requirements. Considering the discrete characteristics caused by the industry's extreme value quantification method, this invention proposes a hierarchical allocation framework for intra-provincial and inter-provincial operating reserve costs that takes into account the sharing of common requirements, which will be described in detail later.

[0273] (b) A tiered allocation framework for intra-provincial and inter-provincial operating reserve costs, taking into account the sharing of common needs.

[0274] To achieve accurate traceability of power grid operation reserve requirements, this invention, considering the industry's method of quantifying operation reserve requirements by taking the maximum value, proposes a hierarchical allocation framework for intra-provincial and inter-provincial operation reserve costs that takes into account the sharing of common needs. Figure 2 As shown.

[0275] First, based on the reserve status of the unit's operation and the reserve prices within and between provinces, the operating reserve costs within and between provinces can be calculated, as shown in Equation (1).

[0276]

[0277] Among them, C R,I and C R,O These represent the operating reserve costs within and between provinces, respectively; i represents the unit number within the province; N g L represents the number of generating units within the province; k represents the unit number outside the province; L g The number of units located outside the province; λ R,I and λ R,O These are the standby prices for intra-provincial and inter-provincial operations, respectively; R i and R k These are operational reserves provided for units within and between provinces.

[0278] Subsequently, taking into account the idea of ​​sharing common needs, the operating reserve costs within and between provinces are decomposed into accident reserve costs and net load reserve costs, which include two scenarios, as detailed below.

[0279] Scenario 1: The operational reserve provided within the province is less than the contingency reserve requirement and the net load reserve requirement, such as... Figure 3 As shown. By Figure 3 As can be seen, in this scenario, all operational reserve services provided within the province are jointly incurred and shared by conventional generating units and net load members (new energy sources and loads) (inter-provincial operational reserve resources are used to address operational reserve needs that cannot be met by intra-provincial operational reserve resources). Therefore, intra-provincial reserve costs will be evenly distributed among contingency reserve costs and net load reserve costs. Regarding inter-provincial reserve services, conventional generating units and net load members jointly incur and share a portion of the inter-provincial operational reserve services, while the remaining portion is incurred and shared solely by net load members. Therefore, following the principle of "whoever incurs, bears," the portion of inter-provincial reserve costs jointly incurred by conventional generating units and net load members will be evenly distributed among contingency reserve costs and net load reserve costs, while the remainder will be entirely allocated to net load reserve costs.

[0280] Scenario 2: The operational reserve provided within the province exceeds the contingency reserve requirement or net load reserve requirement, such as... Figure 4As shown. By Figure 4 Therefore, in this scenario, a portion of the operational reserve services provided within the province are jointly incurred and utilized by conventional units and net load members. This portion of the provincial reserve cost will be evenly distributed among contingency reserve costs and net load reserve costs. The remaining operational reserve services are solely incurred by net load members, and this portion of the provincial reserve cost will be entirely allocated to net load reserve costs. As for inter-provincial reserve services, they are entirely incurred and utilized by net load members; therefore, inter-provincial reserve costs will be entirely allocated to net load reserve costs.

[0281] This completes the decomposition of intra-provincial and inter-provincial reserve costs into contingency reserve costs and net load reserve costs. Building on this, the present invention will further allocate contingency reserve costs and net load reserve costs to each market participant, taking into account the overlapping uncertainties of various market participants.

[0282] (2) Cost allocation methods for various types of operating reserves considering the superimposed uncertainty of market participants

[0283] (a) Method for allocating contingency reserve costs taking into account common needs

[0284] For contingency reserve requirements, the current common practice is to use the maximum capacity of a single unit within the system as the system's contingency reserve requirement to cope with the power deficit caused by generator failures. Therefore, the quantification of contingency reserve requirements also has discrete characteristics. This invention adopts a common requirement amortization approach to distribute contingency reserve costs among conventional units. The approach and specific process are as follows: Figure 5 As shown.

[0285] The detailed steps of the proposed method for allocating accident reserve costs based on shared common needs are described below:

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

[0287] 2) Determine if j is greater than the number of conventional generating units N. g If it is not greater than, proceed to step 3); otherwise, proceed to step 6 to complete the allocation of emergency reserve costs.

[0288] 3) After deducting the emergency reserve requirement caused by unit j-1 (if j-1 = 0, then the deducted emergency reserve requirement is 0), determine the emergency reserve requirement from unit j to unit N. g The emergency backup requirements caused by the joint events are shown in Equation 2:

[0289] ΔR c,j =R c,j -R c,j-1 (2)

[0290] Where, ΔR c,jAfter deducting the emergency reserve requirements caused by unit j-1, units j to N g Commonly caused emergency backup requirements; R c,j For the emergency backup requirements caused by unit j (i.e., the installed capacity of unit j);

[0291] 4) ΔR c,j The corresponding emergency standby costs are averaged and allocated to units j to N. g As shown in Equation 3:

[0292]

[0293] in, This indicates the ΔR that unit i needs to bear. c,j The corresponding emergency backup cost; R c For system-wide emergency backup requirements; C c Total system failover cost;

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

[0295] 6) Allocate common requirements among all conventional units and calculate the emergency standby cost to be borne by each conventional unit, as shown in equation (4):

[0296]

[0297] Among them, C c,i The emergency backup cost that unit i needs to bear.

[0298] This completes the allocation of emergency standby costs among the conventional generating units. As can be seen from the above allocation process, for emergency standby needs jointly caused by all conventional generating units, the corresponding standby costs will be shared among the units. However, for the unit with the largest installed capacity, which alone causes a portion of the emergency standby needs, the corresponding standby costs will be borne entirely by that unit, which conforms to the principle of "whoever causes it, bears it".

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

[0300] Cost allocation methods that take into account substitution benefits originate from the well-known economic theory of the Vickrey-Clarke-Groves (VCG) mechanism. This mechanism characterizes the contribution of market participants to system costs or demand as changes in system costs or demand before and after a market participant's entry, and is widely used in cost allocation and revenue distribution. However, for net load reserve cost allocation, due to the mutually offsetting characteristics of forecast errors among market participants, there may be situations where the entry of a certain market participant actually leads to a decrease in the system's net load reserve demand. In this case, according to substitution benefits, the impact of this market participant on the system's net load reserve demand is negative (i.e., the market participant is considered to have contributed to meeting the net load reserve demand), and they will instead receive reserve benefits. However, in reality, this market participant did not actively provide reserve services, and their forecast error still exists; therefore, this market participant should still be the responsible party for net load reserve. Allowing this market participant to receive reserve benefits would violate the "whoever causes it, bears the responsibility" principle and would make it difficult to incentivize them to reduce their own forecast errors.

[0301] To address the aforementioned issues, this invention improves the cost allocation method that takes into account substitution benefits. Based on the traditional substitution benefits, it further introduces market member forecasting errors to comprehensively consider the forecasting randomness of market members themselves and the impact of market members on net load reserve demand under the mutual cancellation of forecasting errors among different members, thus forming the comprehensive influence of market members on net load reserve demand.

[0302] The process of the net load reserve cost allocation method proposed in this invention, which includes consideration of improved substitution benefits, is as follows: Figure 6 As shown.

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

[0304] 1) Calculate the system's net load reserve requirement (R) considering all net load members. n The system net load reserve requirement is quantified using the method proposed in the literature, while setting m=1;

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

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

[0307] Among them, v m This describes the change in the system's net load reserve requirement before and after the net load member m is connected; the subscript -m indicates that net load member m is not considered.

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

[0309]

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

[0311] 4) Determine if m is equal to the number of net load members (N) n If yes, it means that the calculation of all net load members has been completed, and proceed to step 5); otherwise, return to step 2.

[0312] 5) Calculate the proportion of the impact of each net load member on the system net load reserve requirement as characterized by the substitution benefit, as shown in Equation (7):

[0313]

[0314] Among them, V m Let m be the proportion of the net load member m whose influence on the system net load reserve demand is characterized by substitution benefits. A max function is introduced to avoid the influence of a certain net load member on the system net load reserve demand characterized by substitution benefits being negative.

[0315] 6) Calculate the proportion of the impact of each net load member on the system net load reserve requirement, as characterized by historical prediction errors, as shown in Equation 8:

[0316]

[0317] Among them, E m The proportion of the net load member m to the system net load reserve requirement, characterized by historical prediction errors;

[0318] 7) Taking into account both the substitution benefits and historical forecast errors, the overall impact ratio of each net load member is determined, as shown in Equation 9:

[0319] α m =β V Vm +β E E m (9)

[0320] Where, α m The overall influence ratio of net load member m; β V and β E These represent the proportions of the impact of substitution benefits and the impact of historical prediction errors, respectively, and can be adjusted according to allocation preferences. β V and β E The value is set to 0.5;

[0321] 8) Calculate the net load reserve cost to be borne by each net load member based on the overall impact ratio of the net load members, as shown in equation (10):

[0322] C n,m =α m C n (10)

[0323] Among them, C n,m Net load reserve costs to be borne by net load member m; C n This represents the total net load reserve cost of the system.

[0324] Thus, the allocation of net load reserve costs between renewable energy sources and the load itself is completed. The proposed method comprehensively considers the forecasting randomness of the net load members themselves as well as the mutual cancellation characteristics of forecasting errors among different members, and can more effectively reflect the impact of net load members on the system's net load reserve demand.

[0325] In summary, this invention proposes a demand-based, source-tracing method for hierarchical allocation of intra-provincial and inter-provincial power grid operation reserve costs. Based on the quantification methods for system operation reserve demand commonly used in industry, it traces the influence of different market participants on intra-provincial and inter-provincial reserve demand, thereby achieving a reasonable allocation of intra-provincial and inter-provincial reserve costs among various market participants. While ensuring flexible resource adjustment benefits, it also encourages entities that generate reserve demand to proactively reduce their own uncertainties. This method mainly includes the following two characteristics:

[0326] 1) A hierarchical allocation framework for intra-provincial and inter-provincial reserve costs, oriented towards demand sourcing, is proposed. Taking the existing allocation method that considers substitution benefits as an example, the necessity of matching the reserve cost allocation method with the industry's demand quantification method is analyzed. Based on this, a hierarchical allocation framework for intra-provincial and inter-provincial operational reserve costs, taking into account the sharing of common demand, is proposed. Combined with the industry's demand quantification method that takes the maximum value, intra-provincial and inter-provincial reserve costs are first decomposed into contingency reserve costs and net load reserve costs, realizing accurate sourcing of reserve demand among market members of different product categories. Subsequently, based on the impact of each product category market member on contingency reserve or net load reserve, the reserve costs are allocated among market members of the same product category.

[0327] 2) A cost allocation method for various types of operational reserve is proposed, taking into account the superimposed uncertainties of market participants. For contingency reserve requirements determined by the maximum capacity of a single unit, considering the discrete characteristics caused by taking the maximum value, a cost allocation method that considers the sharing of common requirements is adopted. For net load reserve requirements determined by the overall net load forecast error of the system, considering the coupled effects of forecast errors from different market participants, a net load reserve cost allocation method that considers the benefits of improved substitution is proposed, which can take into account both the superimposed characteristics of forecast errors from different market participants and their own uncertainties. Thus, the source and allocation of the two types of reserve costs among the corresponding market participants are realized.

[0328] This invention focuses on the allocation of operating reserve costs. For operating reserve costs, the responsible parties are only new energy sources and loads, and the proposed improved substitution benefit method can be used for direct allocation.

[0329] Example 12:

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

[0331] Simulation results on a regional power grid structure consisting of three IEEE 30-node systems demonstrate that the proposed hierarchical allocation method for reserve costs achieves a more reasonable allocation of operational reserve costs. The specific steps are as follows:

[0332] ① Calculate the operating reserve costs within and between provinces based on the reserve status of the generating units and the reserve prices within and between provinces; ② Decompose the operating reserve costs within and between provinces into contingency reserve costs and net load reserve costs based on the cost-sharing principle that takes into account common needs; ③ Allocate the contingency reserve costs among the conventional generating units based on the cost-sharing principle that takes into account common needs; ④ Allocate the net load reserve costs among new energy sources and loads based on the cost-sharing principle that takes into account the benefits of improvement and substitution.

[0333] (1) Example description

[0334] Based on actual renewable energy and load data of a provincial power grid in my country (renewable energy penetration rate of 30%), this paper conducts a case study analysis using a regional power grid consisting of three IEEE 30-node systems as the network structure, and focuses on the allocation of operating reserve costs for a specific backup receiving-end system within the regional power grid. It should be noted that the allocation method proposed in this invention is a post-hoc allocation and does not involve solving a scheduling optimization model; therefore, it can effectively guarantee computational efficiency even when applied to large-scale systems. The purpose of using a small-scale system for the case study simulation is to facilitate the analysis of the rationality of different allocation methods. In the simulation, the renewable energy and load data were scaled to match the test system. The system for which operating reserve costs are to be allocated includes six conventional generating units and two wind turbine units. In the case study, this invention only focuses on the cost allocation of the operating reserve. Before cost allocation, this invention first conducts market clearing (clearing granularity is 15 minutes, i.e., a day includes 96 clearing periods) to obtain the operating status of market participants and the total operating reserve cost of the system. The maximum downward forecast error of new energy, the maximum upward forecast error of load, the power generation / consumption of each market member on the operating 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 methods for allocating runtime standby costs:

[0338] M1: The hierarchical allocation method for the reserve operation cost of intra-provincial and inter-provincial power grids based on demand sourcing proposed in this invention;

[0339] M2: Same as M1, but the net load operating standby cost adopts an allocation method that takes into account the traditional substitution benefits (for market members with negative substitution benefits, the impact is treated as 0 to avoid paying fees to the standby responsibility entity).

[0340] M3: Same as M1, but directly takes into account the idea of ​​sharing common needs and decomposes the total operating reserve cost into accident reserve cost and net load reserve cost. It does not take into account the characteristic that when the operating reserve resources in the province cannot meet the reserve needs of the province, it is necessary to seek reserve support from outside the province.

[0341] M4: The traditional substitution benefit method is directly used to allocate the total operating reserve cost within and between provinces to each market member;

[0342] M5: Traditional method for allocating total operating reserve costs within and between provinces based on the proportion of electricity generation / consumption of market members;

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

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

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

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

[0347] Table 2 System Operating Backup Costs

[0348]

[0349] Table 3. Allocation results of system operation standby costs under different methods (×10) 4 $)

[0350]

[0351]

[0352] As shown in Table 3, compared with the proposed method M1, the main difference in the allocation results of M2 lies in the allocation results between wind power and load. M2 uses substitution benefits to characterize the impact of net load members on the system's net load reserve requirement. Due to the mutual cancellation of prediction errors among different net load members, the system's net load reserve requirement actually decreases during some clearing periods after considering the connection of wind turbine 2. M2 assumes that wind turbine 2 does not need to bear reserve costs during these periods, thus the final reserve cost borne by wind turbine 2 is less, comparable to that of wind turbine 1. However, as shown in Table 1, the prediction error of wind turbine 2 is 10.7% higher than that of wind turbine 1, indicating that wind turbine 2 actually has greater prediction randomness and should bear more reserve costs. To address this issue, the proposed method M1 introduces prediction error based on substitution benefits to account for the uncertainty of market members themselves. Ultimately, in M1, the reserve cost borne by wind turbine 2 is higher than that of wind turbine 1, which can more effectively encourage net load market members to actively improve their prediction accuracy.

[0353] M3 does not consider the supply and demand relationship of reserve within and between provinces, but directly allocates the reserve costs of both provinces as a whole. The price difference between inter-provincial and intra-provincial reserves (in this example, the price of inter-provincial reserves is higher than that of intra-provincial reserves) results in the contingency reserve responsibility entity bearing more reserve costs compared to M1, while the net load reserve responsibility entity bears less reserve costs. The reason for this difference is that during each clearing period, the system net load reserve demand is generally greater than the system contingency reserve demand. Therefore, as described in Section 1.2, net load market participants will bear more inter-provincial reserve costs in M1, so the final total net load reserve cost of M1 will be higher than that of M3. Figure 7 As shown. The next subsection will further analyze the necessity of considering the supply and demand relationship of reserve costs within and between provinces in the reserve cost allocation method, using specific cases.

[0354] M4 directly uses the traditional substitution benefit method to allocate the overall system operating reserve cost to each market member, without considering the industry's optimal quantification method for operating reserve demand. Since the installed capacity of thermal power units 3-6 is relatively small, their connection has not increased 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 far lower than that of net load market members. Figure 7 As shown. However, in reality, thermal power units 3-6 are all responsible for the system's operational reserve requirements and should bear the relevant reserve costs. This highlights the necessity of matching the operational reserve cost allocation method with the quantification method of the system's operational reserve requirements.

[0355] M5 allocates system operating reserve costs based on the power generation / consumption ratio of market members. As shown in Table 1, the load's power consumption is significantly higher than the power generation of other market members, thus the load bears a high share of system operating costs. However, as shown in Tables 1 and 3, the load's forecasting error is similar to that of the two wind turbine units, yet its reserve cost is 5.8 times the average reserve cost of the wind turbine units. Therefore, the traditional allocation method based on the power generation / consumption ratio cannot quantify the uncertainties of each market member and their impact on system reserve requirements, making it difficult to achieve a reasonable allocation of reserve costs.

[0356] M6 allocates operating reserve costs based on the risk proportions of market members. As shown in Table 1, the sum of reserve requirements caused by the six conventional units themselves (i.e., the sum of the installed capacity of all units) is far higher than the sum of reserve requirements caused by net load members. Therefore, under the risk proportion allocation model, the conventional units bear a high share of system operating costs, such as... Figure 7As shown. However, in the actual quantification of operational reserve demand, the total operational reserve demand of the system is not simply the sum of the individual demands of each market participant. The discrete nature of taking the maximum and minimum values ​​means that the impact of conventional units on the actual operational reserve demand of the system is less than that of net load market participants. Specifically, in the 96 clearing periods, the cumulative reserve demand caused by net load market participants alone reached 2572MW, while the cumulative reserve demand caused by conventional units alone was only 273MW. Therefore, net load market participants should bear more reserve costs, which is inconsistent with the allocation result of M6. The method M1 proposed in this invention takes into account the quantification method of system operational reserve demand, and the allocation result is more reasonable. This again demonstrates the necessity of matching the operational reserve cost allocation method with the quantification method of system operational reserve demand.

[0357] (b) Explanation of the necessity of considering the supply and demand relationship of reserves within and between provinces in the allocation method.

[0358] To further clarify the necessity of considering the supply and demand relationship of reserves within and between provinces in the operation reserve cost allocation method, the following uses clearing period 25 as an example to further illustrate the allocation results of reserves within and between provinces using methods M1 and M3.

[0359] The supply and demand of the system's operational reserve during this clearing period is shown in Table 4, and the composition of the system's operational reserve cost is shown in Table 5.

[0360] Table 4 shows the operational and standby supply and demand of the systems in time period 25.

[0361]

[0362] As shown in Table 4, during this clearing period, the provincial reserve supply can meet the system failure reserve demand, but it is difficult to effectively meet the net load reserve demand, thus requiring support from inter-provincial reserve resources, which incurs inter-provincial operating reserve costs. Considering the above situation, the inter-provincial operating reserve costs in the proposed method M1 will be entirely borne by the net load market members (e.g., Figure 8 As shown), this conforms to the principle of "whoever causes it, bears the cost." However, M3 does not consider the supply and demand relationship of reserve within and between provinces; instead, it decomposes the total cost of reserve within and between provinces as a whole into accident reserve cost and net load reserve cost. Therefore, conventional units also bear the inter-provincial reserve cost (e.g., Figure 8 As shown in Tables 4 and 5, the reserve costs borne by conventional units are ultimately higher than those allocated by M1 due to the higher inter-provincial reserve costs. In summary, allocation method M3 fails to consider the supply and demand of reserve costs within and between provinces, resulting in conventional units also bearing the higher inter-provincial reserve costs, which violates the principle of "whoever causes it, bears it." Therefore, it is necessary to consider the supply and demand of reserve costs within and between provinces during the allocation of operating reserve costs.

[0363] This invention proposes a hierarchical allocation method for reserve costs in intra-provincial and inter-provincial power grids, oriented towards demand sourcing. First, considering the discrete nature of the industry's extreme value quantification method, this method proposes an allocation approach that takes into account the sharing of common demand, decomposing intra-provincial and inter-provincial reserve costs into contingency reserve costs and net load reserve costs, thus achieving accurate sourcing of reserve demand that matches the demand quantification method. Subsequently, considering the superimposed uncertainties of different market participants, contingency reserve and net load reserve costs are further allocated to each market participant through common demand sharing and improved substitution benefits. This invention, while ensuring the benefits of flexible resource adjustment, incentivizes the responsible parties who generate reserve demand to proactively reduce their own uncertainties, which is of great significance for power systems to cope with uncertainties such as new energy sources, random load fluctuations, and unit outages.

Claims

1. A demand-based, source-oriented method for hierarchical allocation of reserve costs for intra-provincial and inter-provincial power grid operations, characterized in that... Includes the following steps: Step 1) Construct a hierarchical allocation framework for intra-provincial and inter-provincial operational reserve costs that takes into account the sharing of common needs; Step 2) Based on the hierarchical allocation framework of intra-provincial and inter-provincial operating reserve costs, with the objective function of minimizing the regional power grid energy and overall reserve operating costs, and with power grid operation constraints as conditions, generate and execute various types of operating reserve cost allocation schemes that take into account the superimposed uncertainties of market participants. The cost allocation schemes for various types of operational standby include accident standby cost allocation schemes that take into account the sharing of common needs and net load standby cost allocation schemes that take into account the benefits of improved alternatives; The provincial-interprovincial operating reserve cost tiered allocation framework that takes into account the sharing of common needs includes Scenario 1 and Scenario 2; Scenario 1 refers to a situation where the operational reserve provided within the province is less than the emergency reserve requirement and the net load reserve requirement. Scenario 2 refers to a situation where the operational reserve provided within the province exceeds the emergency reserve requirement or the net load reserve requirement. The intra-provincial and inter-provincial operating standby costs are shown below: （1） Among them, C R,I and C R,O These represent the operating reserve costs within and between provinces, respectively; i represents the unit number within the province; N g L represents the number of generating units within the province; k represents the unit number outside the province; L g The number of units located outside the province; λ R,I and λ R,O These are the standby prices for intra-provincial and inter-provincial operations, respectively; R i and R k These are operational reserves provided for units within and between provinces; The steps for generating an accident reserve cost allocation scheme that takes into account the common needs include: Step a1) Sort all conventional units in ascending order of installed capacity, and set j=1; Step a2) Determine if j is greater than the number of conventional generating units N. g If not, proceed to step a3); if yes, proceed to step a6) to complete the allocation of accident reserve costs. Step a3) After deducting the emergency reserve requirements caused by unit j-1, the computer group from j to N... g Commonly caused accident backup requirements ,Right now: （2） in, After deducting the emergency reserve requirements caused by unit j-1, units j to N g Emergency backup requirements caused by joint events; Backup requirements for accidents caused by unit j; Step a4) Determine emergency backup requirements The corresponding emergency standby costs are averaged and allocated to units j to N. g ,Right now: （3） in, This indicates the responsibility that unit i needs to bear. The corresponding emergency backup cost; R c For system-wide emergency backup requirements; C c Total system failover cost; Step a5) Let j = j + 1, and return to step a2). Step a6) Complete the amortization of common requirements among all conventional units and calculate the emergency standby cost to be borne by each conventional unit, i.e.: （4） Among them, C c,i The emergency backup costs to be borne by unit i; The steps involved in generating a net load reserve cost allocation scheme that incorporates improved alternative benefits include: Step b1) Calculate the system's net load reserve requirement R when considering all net load members. n The system net load reserve requirement is quantified using the method proposed in the literature, while setting m=1; Step b2) Calculate the system's net load reserve requirement without considering net load member m, and obtain the change in the system's net load reserve requirement before and after the member's access, i.e.: （5） Among them, v m This describes the change in the system's net load reserve requirement before and after the net load member m is connected; the subscript -m indicates that net load member m is not considered. Step b3) Calculate the historical average absolute prediction error of net load member m, i.e.: （6） Among them, e m t represents the historical average absolute prediction error of net load member m; t represents the prediction time point number; T represents the number of prediction time points included in the calculation period. The actual power of the net load members; Forecast power for net load members; Step b4) Determine if m is equal to the number of net load members N. n If yes, proceed to step b5; otherwise, return to step b2. Step b5) Calculate the proportion of the impact of each net load member on the system net load reserve requirement, as characterized by the substitution benefit, i.e.: （7） Among them, V m The proportion of the net load member m to the system net load reserve requirement, characterized by substitution benefits; Step b6) Calculate the proportion of the impact of each net load member on the system net load reserve requirement, as characterized by historical prediction errors, i.e.: （8） Among them, E m The proportion of the net load member m to the system net load reserve requirement, characterized by historical prediction errors; Step b7) Taking into account both substitution benefits and historical forecast errors, the overall impact ratio of each net load member is determined, i.e.: （9） Where, α m The overall influence ratio of net load member m; β V and β E These represent the proportions of the impact of substitution benefits and the impact of historical prediction errors, respectively. Step b8) Calculate the net load reserve cost to be borne by each net load member based on the overall impact ratio of the net load members, i.e.: （10） Among them, C n,m Net load reserve costs to be borne by net load member m; C n The total net load reserve cost of the system; In step 2), the objective function is as follows: （11） In the formula, 'a' represents the provincial power grid number within the region; For the provincial power grid set within the region; t is the time period number; T is the time period set; g a For unit number in province A; G a 'b' represents the set of generating units in province a; 'b' represents the number of the provincial power grid outside of province a. Energy cost; For reserve costs within the province; For inter-provincial backup costs; Price energy; To provide power to the generator unit; , For backup quotes within the province; , Provincial-level backup / standby for the generating unit; , Quotations for inter-provincial standby / backup services provided by generating units in province A to province B; , For inter-provincial up / down standby provided by the unit in province A to province B.

2. The method for hierarchical allocation of reserve operation costs for intra-provincial and inter-provincial power grids based on demand sourcing, as described in claim 1, is characterized in that... In one scenario, intra-provincial reserve costs are allocated equally to contingency reserve costs and net load reserve costs; inter-provincial reserve costs incurred jointly by conventional units and net load members are allocated equally to contingency reserve costs and net load reserve costs, while the remaining inter-provincial reserve costs are allocated entirely to net load reserve costs.

3. The method for hierarchical allocation of intra-provincial and inter-provincial power grid operation reserve costs based on demand sourcing as described in claim 1, characterized in that, In Scenario 2, the portion of provincial reserve costs jointly incurred by conventional units and net load members is allocated equally to contingency reserve costs and net load reserve costs, while the remaining provincial reserve costs are allocated entirely to net load reserve costs; inter-provincial reserve costs will be allocated entirely to net load reserve costs.

4. The method for hierarchical allocation of intra-provincial and inter-provincial power grid operation reserve costs based on demand sourcing as described in claim 1, characterized in that, In step 3), if j-1=0, then the deducted emergency reserve requirement is 0.

5. A method for hierarchical allocation of intra-provincial and inter-provincial power grid operation reserve costs based on demand sourcing, as described in claim 1, is characterized in that... In step 2), the power 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 ramping constraints, system operation reserve demand constraints, and line power flow constraints. The power constraints for inter-provincial tie lines are as follows: （12） In the formula, l T For the contact line number; n a Number the nodes; w a For wind turbine generator number; W a A collection of wind turbine units; , These are the upper and lower limits of the transmission power of the tie line; For node n in province a a To inter-provincial connecting lines T The power transfer distribution factor; , These represent the distances from thermal power units and wind power units to node n, respectively. a The elements of the correlation matrix; , These are the predicted power values ​​for wind turbines and loads; To transmit power to the tie line; The power balance constraints are as follows: （13） In the formula, This represents the 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: （14） In the formula, L T,ab This represents the set of connecting lines between provinces a and b. The upper and lower limits of the unit's output are constrained as follows: （15） In the formula, , These are the upper and lower limits of the output of thermal power units, respectively. The unit's standby constraints are as follows: （16） In the formula, , These refer to the uphill / downhill climbing capabilities of thermal power units; The unit's ramp-up constraints are as follows: （17） The system's standby requirements are constrained as follows: （18） In the formula, , These refer to the upstream / downstream reserve requirements of the provincial power grid; The power flow constraints for the lines are as follows: （19） In the formula, l is the number of the route within the province; , P represents the upper and lower limits of transmission power for line l within the province; l For line transmission power; For node n in province a a The power transfer distribution factor to line l.

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