A method for optimizing intraday generation scheduling considering multiple deviations

Abstract

The application discloses a kind of day-ahead generation scheduling optimization methods considering multiple deviations, and relates to a kind of optimization method of day-ahead generation scheduling, to solve the problem that day-ahead generation scheduling formulated by day-ahead generation scheduling deviates greatly from actual power grid operation.Firstly, the day-ahead generation scheduling data is preprocessed, and then the overall analysis of day-ahead power balance is carried out; for the normal state of day-ahead power balance, the load rate of all units is sequentially adjusted, individually adjusted and power deviation adjusted based on the requirements of OMS system; for the deep adjustment state, the generation scheduling needs to be formulated according to the auxiliary service market quotation; for the three states of power rejection, excess and lack, the generation scheduling needs to be formulated according to the minimum or maximum generation capacity; after safety check adjustment, the final day-ahead generation scheduling is generated.The beneficial effect is to reduce the deviation of day-ahead generation scheduling from actual power grid operation.

Description

Technical Field

[0001] This invention relates to a method for optimizing intraday power generation plans. Background Technology

[0002] The intraday power generation plan is based on the previous day's power generation plan, and is formulated based on more accurate intraday forecasts and new intraday grid operation conditions. It is a power balance plan with higher accuracy, more comprehensive safety verification, better matching of power generation plan with power generation equipment capacity, more reasonable power generation completion progress, and greater guidance and feasibility for AGC.

[0003] However, due to the high probability of missing data and reliability issues in various forecast data, the daily power generation plan based on the day-ahead power generation plan may deviate significantly from the actual operation of the power grid, making it impossible to execute normally. Summary of the Invention

[0004] The purpose of this invention is to solve the problem that the daily power generation plan formulated based on the day-ahead power generation plan deviates significantly from the actual operation of the power grid, and to propose an optimization method for the daily power generation plan that takes into account multiple deviations.

[0005] The present invention discloses a method for optimizing intraday power generation plans considering multiple deviations, the optimization method comprising the following steps:

[0006] Step 1: Preprocess the day-ahead power generation plan data to obtain the day-ahead power balance.

[0007] Step 2: Perform an overall analysis of the day-ahead power balance obtained in Step 1 to obtain the intraday power balance status;

[0008] Step 3: Determine whether the intraday power balance status obtained in Step 2 is normal; if the result is yes, proceed to Step 4; otherwise, proceed to Step 7.

[0009] Step 4: Adjust the load rate of all units uniformly according to the current day plan, and calculate the initial planned adjustment power for each unit;

[0010] Step 5: Adjust the primary planned adjustment power of each unit calculated in Step 4 according to the unit's power generation capacity, and generate the secondary planned adjustment power for each unit.

[0011] Step Six: Based on the OMS system requirements, adjust the power deviation of each unit's secondary plan adjustment power generated in Step Five to generate the initial No. 1 intraday power generation plan, and then execute Step Thirteen;

[0012] Step 7: Determine whether the intraday power balance status obtained in Step 2 is a deep adjustment status; if the result is yes, proceed to Step 8; otherwise, proceed to Step 9.

[0013] Step 8: Formulate an initial intraday power generation plan for Unit 2 based on ancillary service market quotations, and then execute Step 13;

[0014] Step 9: Determine whether the intraday power balance status obtained in Step 2 indicates a power shortage. If the result is yes, proceed to Step 10; otherwise, proceed to Step 11.

[0015] Step 10: Develop an initial three-day power generation plan based on maximum power generation capacity, and then execute Step 13;

[0016] Step 11: Determine whether the intraday power balance status obtained in Step 2 is a state of power curtailment or a state of power surplus, and then proceed to Step 12;

[0017] Step 12: Develop an initial four-day power generation plan based on the minimum power generation capacity, and then execute Step 13;

[0018] Step 13: Perform safety checks on the initial intraday power generation plan No. 1 generated in Step 6, the initial intraday power generation plan No. 2 formulated in Step 8, the initial intraday power generation plan No. 3 formulated in Step 10, and the initial intraday power generation plan No. 4 formulated in Step 12, and generate the final intraday power generation plan.

[0019] Furthermore, the specific method for preprocessing the day-ahead power generation plan data in step one is as follows:

[0020] 1) Determine the unit's start-up, shutdown, and planned output for the day;

[0021] Read the unit output from the previous day's plan. If the output is not zero, it is assumed that the unit will be started at that time according to the previous day's plan; otherwise, it will be shut down.

[0022] The actual output of the current generating unit is obtained from the D5000 dispatch automation system. If the current generating unit is in the starting state but there is no power generation plan, for the unit that has just started up, the curve from the current output to 52% at a ramp rate of 15% and maintained is used as the day-ahead plan and included in subsequent calculations; for the unit that is already in normal operation, the set value curve of 52% of the unit capacity is used as the day-ahead plan and included in subsequent calculations.

[0023] 2) Identify the missing data in intraday load forecasts:

[0024] Based on the day-ahead load forecast and the current actual load, an intraday load forecast curve is generated using the shift method:

[0025] Daily load forecast = Day-ahead load forecast + (Actual load - Day-ahead load forecast)

[0026] 3) Identify the missing information in intraday new energy forecasts:

[0027] Based on the recent renewable energy forecast and the current actual renewable energy output, an intraday renewable energy forecast curve is formulated using the scaling-out method; the specific method is as follows:

[0028] When the actual renewable energy output P at time t0 t0 Lower than the current new energy forecast P' t0 of:

[0029] Daily New Energy Forecast P tx =Recent New Energy Forecast P' tx ×(P t0 ÷P' t0 )

[0030] When the actual renewable energy output P at time t0 t0 Higher than the recent new energy forecast P' t0 The calculation is no longer based on the ratio to the predicted power generation. To prevent the predicted daily renewable energy power generation from exceeding the installed capacity when the ratio factor is greater than 1, and considering the volatility of renewable energy power generation, an algorithm is adopted to reduce the gap between the predicted power generation and the theoretical maximum value when adjusting the predicted value. The reduction ratio is the ratio of the current actual gap to the predicted gap. The calculation is as follows:

[0031] Daily New Energy Forecast P tx =P maxt -P maxt ×(1-P' tx ÷P maxt )×(1-P t0 ÷P max0 )÷(1-P' t0 ÷P max0 )

[0032] Where P max0 and P maxt These represent the maximum theoretical power generation capacity of new energy sources at time 0 and time t, respectively, where wind power P max The figure represents the total installed capacity of wind power, and the figure represents the theoretical power generation curve of the total installed capacity of photovoltaic power under clear weather conditions.

[0033] 4) Identify any missing information in the daily water and electricity plan:

[0034] Daily hydropower plan = Current actual hydropower output;

[0035] 5) Determining the intraday curve planning refers to the planning curve of thermal power units that are not controlled by AGC:

[0036] Daily curve planning = Actual output of day-ahead curve-setting units;

[0037] 6) Determine the daily power generation limit for AGC units:

[0038] The AGC unit's power generation limits are read from the ancillary service platform. If reading the upper and lower limits for the day fails, the upper and lower limits that were successfully read from the platform last time are used instead. When AGC provides new upper and lower limits, they are compared with the values ​​on the ancillary service platform. The smaller value is taken when comparing the upper limit, and the larger value is taken when comparing the lower limit.

[0039] Furthermore, the specific method for obtaining the intraday power balance status in step two is as follows:

[0040] AGC unit generation capacity = load forecast + plant service network loss forecast + interconnection transmission plan - renewable energy forecast - hydropower plan - curve setting plan + forced adjustment capacity

[0041] Among them, the load forecast, plant power grid loss forecast and new energy forecast adopt ultra-short-term forecast, hydropower plan is a fixed value, fixed curve plan is an actual value, and the forced adjustment space is initially assigned to 0. When the calculated power generation space of the AGC unit is not within the adjustable space of the AGC unit, it is necessary to adjust the new energy forecast or adjust the tie line plan to apply for modification of the tie line.

[0042] At this point, the power generation space of the AGC unit = the upper / lower limit of the power generation capacity of the AGC unit;

[0043] Forced adjustment space = upper / lower limit of AGC unit power generation capacity - (load forecast + plant service network loss forecast + interconnection line transmission plan - new energy forecast - hydropower plan - fixed curve plan).

[0044] Furthermore, the intraday power balance state obtained in step two is divided into five types:

[0045] a) Normal state: After adjustment, the AGC unit is within the normal range and the deviation of the tie line is zero;

[0046] b) Deep adjustment status: After adjustment of the AGC unit, within the deep adjustment range, the tie line deviation is already zero;

[0047] c) Power curtailment status: The AGC units have been adjusted to the minimum, but renewable energy sources still need to be restricted before the tie line deviation can be reduced to zero;

[0048] d) Power surplus state: AGC units have been adjusted to the minimum, renewable energy to zero, but the interconnection line still has a positive power deviation;

[0049] e) Power shortage status: The AGC unit has been adjusted to the highest level, the new energy unit is at its maximum, but there is still a power receiving deviation in the interconnection line.

[0050] Furthermore, the specific method for uniformly adjusting the load rate of all units according to the current day plan in step four is as follows:

[0051] Under normal conditions, adjustments are made according to the principle of adjusting all units to the same load rate based on the day-ahead plan. That is, for a unit with a capacity of S, the total operating capacity of the AGC units is ∑S, and the total amount of adjustment required to the power generation plan is ∑ΔP.

[0052] In this step, the planned power adjustment for each unit is ΔP = S × ∑ΔP / ∑S;

[0053] Wherein, ∑ΔP=ΔP1+ΔP2+ΔP3+ΔP4+ΔP5(fixed curve)+ΔP6(connecting line deviation), that is, the sum of the deviations of the daily forecast values ​​of each item;

[0054] Among them, ΔP1 is the power generation and receiving deviation, that is, the deviation between the day-ahead load forecast and the intraday load forecast; ΔP2 is the tie line planning deviation, that is, the deviation between the day-ahead network loss forecast and the intraday network loss forecast for plant use; ΔP3 is the new energy deviation, that is, the deviation between the day-ahead forecast and the intraday forecast for new energy; ΔP4 is the hydropower deviation, that is, the deviation between the day-ahead forecast and the intraday forecast for hydropower planning; ΔP5 is the curve deviation, that is, the deviation between the day-ahead forecast and the intraday forecast for curve planning; ΔP6 is the tie line deviation, that is, the deviation between the day-ahead forecast and the intraday forecast for tie line transmission planning.

[0055] Furthermore, the specific method for individually adjusting the primary planned power output of each unit based on its generating capacity in step five is as follows:

[0056] All AGC units that are operational during the day are divided into Group A, Group B, and Group C.

[0057] Group A units are those whose current power generation plan exceeds their upward regulation capacity; Group B units are those whose current power generation plan is within their upward and downward regulation capacity; and Group C units are those whose current power generation plan is below their downward regulation capacity. The downward regulation capacity refers to the unit's downward regulation capacity without deep regulation, i.e., 50% when the current regulation capacity is below 50%.

[0058] For Group A units, Pa is the total amount by which the power generation plan exceeds the upper regulation capacity; for Group B units, Pb↑ is the upper regulation amount relative to the upper regulation capacity of the power generation plan, and Pb↓ is the lower regulation amount relative to the lower regulation capacity; for Group C units, Pc is the total amount by which the power generation plan exceeds the lower regulation capacity; under the premise of normal regulation of thermal power units, the following four cases are considered:

[0059] (1) When Pa > Pc and (Pa-Pc) < Pb↑;

[0060] Group A generating units formulate power generation plans based on maximum generating capacity, Group C generating units formulate power generation plans based on minimum generating capacity, and Group B generating units increase the active power generation of Pa-Pc portion according to the principle of adjusting the same load rate based on the current power generation plan, thereby achieving power balance again.

[0061] (2) When Pa < Pc and (Pc-Pa) < Pb↓;

[0062] The A and C groups of generating units will still formulate daily plans based on their maximum and minimum generating capacities, while the B group of generating units will reduce the active power generation of the Pc-Pa portion according to the principle of adjusting the same load rate based on the current generating plan, thereby achieving power balance again.

[0063] (3) When Pa > Pc and (Pa - Pc) > Pb↑;

[0064] At this time, the A group units and the B group units formulate power generation plans according to their maximum power generation capacity, and the C group units allocate the active power generation of Pa-Pc-Pb↑ according to the principle of adjusting the same load rate according to the current power generation plan, so as to achieve power balance again.

[0065] (4) If Pa < Pc and (Pc - Pa) > Pb↓;

[0066] Group B and Group C units formulate daily plans based on minimum generating capacity, while Group A units, based on maximum generating capacity, reduce the active power generation of the Pc-Pa-Pb↓ portion according to the principle of adjusting the same load rate.

[0067] Furthermore, the specific method for adjusting the power deviation of each unit's secondary plan based on the OMS system requirements in step six is ​​as follows:

[0068] The OMS system provides power adjustment requirements, including the priority adjustment order and the required adjustment amount. The principle of this adjustment step is: based on the initial power generation plan for the day, the adjustment amount shall not exceed 5% of the rated capacity, not exceed the required adjustment amount / 72 hours, and not exceed the unit's vertical adjustment capacity. According to the priority adjustment order, the units with increased demand and the units with decreased demand will be matched and adjusted one by one.

[0069] The beneficial effects of this invention are as follows: It addresses situations where unexpected changes occur within the day to the boundary conditions of the day-ahead power generation plan, preventing the direct generation and execution of the intraday plan. It resolves issues arising from eight types of deviations between the day-ahead and intraday plans, including: load forecasting deviation, plant service network loss forecasting deviation, tie-line plan deviation, new energy forecasting deviation, hydropower generation deviation, fixed-curve thermal power generation deviation, start-up mode deviation, and mismatch between the power generation plan and the vertical regulation capabilities of thermal power AGC units. Furthermore, it considers the remaining regulation capacity of each unit and the monthly power generation plan progress deviation compensation requirements given by the OMS system, performing corresponding power generation progress deviation compensation. Finally, after grid safety verification, it generates an intraday power generation plan with higher power balance accuracy, within capacity limits, considering power generation progress, and meeting grid safety operation requirements; thus reducing the actual deviation between the intraday power generation plan and grid operation. Attached Figure Description

[0070] Figure 1 This is a flowchart of a method for optimizing intraday power generation plans that considers multiple deviations, as described in Specific Implementation Method 1. Detailed Implementation

[0071] Combination Figure 1 This embodiment describes a method for optimizing intraday power generation plans that considers multiple deviations. The optimization method includes the following steps:

[0072] Step 1: Preprocess the day-ahead power generation plan data to obtain the day-ahead power balance.

[0073] Step 2: Perform an overall analysis of the day-ahead power balance obtained in Step 1 to obtain the intraday power balance status;

[0074] Step 3: Determine whether the intraday power balance status obtained in Step 2 is normal; if the result is yes, proceed to Step 4; otherwise, proceed to Step 7.

[0075] Step 4: Adjust the load rate of all units uniformly according to the current day plan, and calculate the initial planned adjustment power for each unit;

[0076] Step 5: Adjust the primary planned adjustment power of each unit calculated in Step 4 according to the unit's power generation capacity, and generate the secondary planned adjustment power for each unit.

[0077] Step Six: Based on the OMS system requirements, adjust the power deviation of each unit's secondary plan adjustment power generated in Step Five to generate the initial No. 1 intraday power generation plan, and then execute Step Thirteen;

[0078] Step 7: Determine whether the intraday power balance status obtained in Step 2 is a deep adjustment status; if the result is yes, proceed to Step 8; otherwise, proceed to Step 9.

[0079] Step 8: Formulate an initial intraday power generation plan for Unit 2 based on ancillary service market quotations, and then execute Step 13;

[0080] Step 9: Determine whether the intraday power balance status obtained in Step 2 indicates a power shortage. If the result is yes, proceed to Step 10; otherwise, proceed to Step 11.

[0081] Step 10: Develop an initial three-day power generation plan based on maximum power generation capacity, and then execute Step 13;

[0082] Step 11: Determine whether the intraday power balance status obtained in Step 2 is a state of power curtailment or a state of power surplus, and then proceed to Step 12;

[0083] Step 12: Develop an initial four-day power generation plan based on the minimum power generation capacity, and then execute Step 13;

[0084] Step 13: Perform safety checks on the initial intraday power generation plan No. 1 generated in Step 6, the initial intraday power generation plan No. 2 formulated in Step 8, the initial intraday power generation plan No. 3 formulated in Step 10, and the initial intraday power generation plan No. 4 formulated in Step 12, and generate the final intraday power generation plan.

[0085] In a preferred embodiment, the specific method for preprocessing the day-ahead power generation plan data in step one is as follows:

[0086] 2) Determine the unit's start-up, shutdown, and planned output for the day;

[0087] Read the unit output from the previous day's plan. If the output is not zero, it is assumed that the unit will be started at that time according to the previous day's plan; otherwise, it will be shut down.

[0088] The actual output of the current generating unit is obtained from the D5000 dispatch automation system. If the current generating unit is in the starting state but there is no power generation plan, for the unit that has just started up, the curve from the current output to 52% at a ramp rate of 15% and maintained is used as the day-ahead plan and included in subsequent calculations; for the unit that is already in normal operation, the set value curve of 52% of the unit capacity is used as the day-ahead plan and included in subsequent calculations.

[0089] 2) Identify the missing data in intraday load forecasts:

[0090] Based on the day-ahead load forecast and the current actual load, an intraday load forecast curve is generated using the shift method:

[0091] Daily load forecast = Day-ahead load forecast + (Actual load - Day-ahead load forecast)

[0092] 3) Identify the missing information in intraday new energy forecasts:

[0093] Based on the recent renewable energy forecast and the current actual renewable energy output, an intraday renewable energy forecast curve is formulated using the scaling-out method; the specific method is as follows:

[0094] When the actual renewable energy output P at time t0 t0 Lower than the current new energy forecast P' t0 of:

[0095] Daily New Energy Forecast P tx =Recent New Energy Forecast P' tx ×(P t0 ÷P' t0 )

[0096] When the actual renewable energy output P at time t0 t0 Higher than the recent new energy forecast P' t0 The calculation is no longer based on the ratio to the predicted power generation. To prevent the predicted daily renewable energy power generation from exceeding the installed capacity when the ratio factor is greater than 1, and considering the volatility of renewable energy power generation, an algorithm is adopted to reduce the gap between the predicted power generation and the theoretical maximum value when adjusting the predicted value. The reduction ratio is the ratio of the current actual gap to the predicted gap. The calculation is as follows:

[0097] Daily New Energy Forecast P tx =P maxt -P maxt ×(1-P' tx ÷P maxt )×(1-P t0 ÷P max0 )÷(1-P' t0 ÷P max0 )

[0098] Where P max0 and P maxt These represent the maximum theoretical power generation capacity of new energy sources at time 0 and time t, respectively, where wind power P max The figure represents the total installed capacity of wind power, and the figure represents the theoretical power generation curve of the total installed capacity of photovoltaic power under clear weather conditions.

[0099] 4) Identify any missing information in the daily water and electricity plan:

[0100] Daily hydropower plan = Current actual hydropower output;

[0101] 5) Determining the intraday curve planning refers to the planning curve of thermal power units that are not controlled by AGC:

[0102] Daily curve planning = Actual output of day-ahead curve-setting units;

[0103] 6) Determine the daily power generation limit for AGC units:

[0104] The AGC unit's power generation limits are read from the ancillary service platform. If reading the upper and lower limits for the day fails, the upper and lower limits that were successfully read from the platform last time are used instead. When AGC provides new upper and lower limits, they are compared with the values ​​on the ancillary service platform. The smaller value is taken when comparing the upper limit, and the larger value is taken when comparing the lower limit.

[0105] In a preferred embodiment, the specific method for obtaining the intraday power balance status in step two is as follows:

[0106] AGC unit generation capacity = load forecast + plant service network loss forecast + interconnection transmission plan - renewable energy forecast - hydropower plan - curve setting plan + forced adjustment capacity

[0107] Among them, the load forecast, plant power grid loss forecast and new energy forecast adopt ultra-short-term forecast, hydropower plan is a fixed value, fixed curve plan is an actual value, and the forced adjustment space is initially assigned to 0. When the calculated power generation space of the AGC unit is not within the adjustable space of the AGC unit, it is necessary to adjust the new energy forecast or adjust the tie line plan to apply for modification of the tie line.

[0108] At this point, the power generation space of the AGC unit = the upper / lower limit of the power generation capacity of the AGC unit;

[0109] Forced adjustment space = upper / lower limit of AGC unit power generation capacity - (load forecast + plant service network loss forecast + interconnection line transmission plan - new energy forecast - hydropower plan - fixed curve plan).

[0110] In a preferred embodiment, the intraday power balance state obtained in step two is divided into five types:

[0111] a) Normal state: After adjustment, the AGC unit is within the normal range and the deviation of the tie line is zero;

[0112] b) Deep adjustment status: After adjustment of the AGC unit, within the deep adjustment range, the tie line deviation is already zero;

[0113] c) Power curtailment status: The AGC units have been adjusted to the minimum, but renewable energy sources still need to be restricted before the tie line deviation can be reduced to zero;

[0114] d) Power surplus state: AGC units have been adjusted to the minimum, renewable energy to zero, but the interconnection line still has a positive power deviation;

[0115] e) Power shortage status: The AGC unit has been adjusted to the highest level, the new energy unit is at its maximum, but there is still a power receiving deviation in the interconnection line.

[0116] In a preferred embodiment, the specific method for uniformly adjusting the load rate of all units according to the day-ahead plan in step four is as follows:

[0117] Under normal conditions, adjustments are made according to the principle of adjusting all units to the same load rate based on the day-ahead plan. That is, for a unit with a capacity of S, the total operating capacity of the AGC units is ∑S, and the total amount of adjustment required to the power generation plan is ∑ΔP.

[0118] In this step, the planned power adjustment for each unit is ΔP = S × ∑ΔP / ∑S;

[0119] Wherein, ∑ΔP=ΔP1+ΔP2+ΔP3+ΔP4+ΔP5(fixed curve)+ΔP6(connecting line deviation), that is, the sum of the deviations of the daily forecast values ​​of each item;

[0120] Among them, ΔP1 is the power generation and receiving deviation, that is, the deviation between the day-ahead load forecast and the intraday load forecast; ΔP2 is the tie line planning deviation, that is, the deviation between the day-ahead network loss forecast and the intraday network loss forecast for plant use; ΔP3 is the new energy deviation, that is, the deviation between the day-ahead forecast and the intraday forecast for new energy; ΔP4 is the hydropower deviation, that is, the deviation between the day-ahead forecast and the intraday forecast for hydropower planning; ΔP5 is the curve deviation, that is, the deviation between the day-ahead forecast and the intraday forecast for curve planning; ΔP6 is the tie line deviation, that is, the deviation between the day-ahead forecast and the intraday forecast for tie line transmission planning.

[0121] In this implementation, for the deep adjustment state, the power generation plan needs to be formulated based on the ancillary service market price; for the three states of curtailment, surplus, and shortage, the power generation plan needs to be formulated based on the minimum or maximum power generation capacity.

[0122] In a preferred embodiment, the specific method for individually adjusting the primary planned power adjustment amount for each unit based on its generating capacity in step five is as follows:

[0123] All AGC units that are operational during the day are divided into Group A, Group B, and Group C.

[0124] Group A units are those whose current power generation plan exceeds their upward regulation capacity; Group B units are those whose current power generation plan is within their upward and downward regulation capacity; and Group C units are those whose current power generation plan is below their downward regulation capacity. The downward regulation capacity refers to the unit's downward regulation capacity without deep regulation, i.e., 50% when the current regulation capacity is below 50%.

[0125] For Group A units, Pa is the total amount by which the power generation plan exceeds the upper regulation capacity; for Group B units, Pb↑ is the upper regulation amount relative to the upper regulation capacity of the power generation plan, and Pb↓ is the lower regulation amount relative to the lower regulation capacity; for Group C units, Pc is the total amount by which the power generation plan exceeds the lower regulation capacity; under the premise of normal regulation of thermal power units, the following four cases are considered:

[0126] (1) When Pa > Pc and (Pa-Pc) < Pb↑;

[0127] Group A generating units formulate power generation plans based on maximum generating capacity, Group C generating units formulate power generation plans based on minimum generating capacity, and Group B generating units increase the active power generation of Pa-Pc portion according to the principle of adjusting the same load rate based on the current power generation plan, thereby achieving power balance again.

[0128] (2) When Pa < Pc and (Pc-Pa) < Pb↓;

[0129] The A and C groups of generating units will still formulate daily plans based on their maximum and minimum generating capacities, while the B group of generating units will reduce the active power generation of the Pc-Pa portion according to the principle of adjusting the same load rate based on the current generating plan, thereby achieving power balance again.

[0130] (3) When Pa > Pc and (Pa - Pc) > Pb↑;

[0131] At this time, the A group units and the B group units formulate power generation plans according to their maximum power generation capacity, and the C group units allocate the active power generation of Pa-Pc-Pb↑ according to the principle of adjusting the same load rate according to the current power generation plan, so as to achieve power balance again.

[0132] (4) If Pa < Pc and (Pc - Pa) > Pb↓;

[0133] Group B and Group C units formulate daily plans based on minimum generating capacity, while Group A units, based on maximum generating capacity, reduce the active power generation of the Pc-Pa-Pb↓ portion according to the principle of adjusting the same load rate.

[0134] In this implementation, assuming a normal power balance, although overall power balance has been achieved through the previous stage of adjustments, each unit's individual power generation plan cannot be guaranteed to be within its own regulation capacity. Therefore, individual adjustments are still needed for units exceeding their limits to ensure that the power generation plans of all AGC units are within their capacity while maintaining power balance. Under the four conditions of deep regulation, power curtailment, surplus, and shortage, the daily power generation plan has already been formulated and this step is unnecessary.

[0135] In a preferred embodiment, the specific method for adjusting the power deviation of each unit's secondary plan based on the OMS system requirements in step six is ​​as follows:

[0136] The OMS system provides power adjustment requirements, including the priority adjustment order and the required adjustment amount. The principle of this adjustment step is: based on the initial power generation plan for the day, the adjustment amount shall not exceed 5% of the rated capacity, not exceed the required adjustment amount / 72 hours, and not exceed the unit's vertical adjustment capacity. According to the priority adjustment order, the units with increased demand and the units with decreased demand will be matched and adjusted one by one.

[0137] In this embodiment, the task of this step is to further adjust the initial power generation plan, and to process the power adjustment requirements given by the OMS system while still ensuring that the overall power supply remains in balance during the day and that the power generation plans of each unit are within their daily power generation capacity.

[0138] The above description is merely a specific embodiment of the present invention, but the scope of protection of the present invention is not limited thereto. Any variations or substitutions that can be easily conceived by those skilled in the art within the technical scope disclosed in the present invention should be included within the scope of protection of the present invention. Therefore, the scope of protection of the present invention should be determined by the scope of the claims.

Claims

1. A method for optimizing intraday power generation plans considering multiple deviations, characterized in that, The optimization method includes the following steps: Step 1: Preprocess the day-ahead power generation plan data to obtain the day-ahead power balance. Step 2: Perform an overall analysis of the day-ahead power balance obtained in Step 1 to obtain the intraday power balance status; Step 3: Determine whether the intraday power balance status obtained in Step 2 is normal; if the result is yes, proceed to Step 4; otherwise, proceed to Step 7. Step 4: Adjust the load rate of all units uniformly according to the current day plan, and calculate the initial planned adjustment power for each unit; the specific method for the uniform adjustment is as follows: Under normal conditions, adjustments are made according to the principle of adjusting all units to the same load rate based on the day-ahead plan. That is, for a unit with a capacity of S, the total operating capacity of the AGC units is ∑S, and the total amount of adjustment required to the power generation plan is ∑ΔP. In this step, the planned power adjustment for each unit is ΔP = S × ∑ΔP / ∑S; Wherein, ∑ΔP=ΔP1+ΔP2+ΔP3+ΔP4+ΔP5 (fixed curve)+ΔP6 (connecting line deviation), which is the sum of the deviations of the daily forecast values ​​of each item; Among them, ΔP1 is the power generation and receiving deviation, i.e., the deviation between day-ahead load forecast and intraday load forecast; ΔP2 is the tie-line planning deviation, i.e., the deviation between day-ahead network loss forecast and intraday network loss forecast for plant use; ΔP3 is the renewable energy deviation, i.e., the deviation between day-ahead and intraday renewable energy forecast; ΔP4 is the hydropower deviation, i.e., the deviation between day-ahead and intraday hydropower planning; ΔP5 is the fixed curve deviation, i.e., the deviation between day-ahead and intraday fixed curve planning; ΔP6 is the tie-line deviation, i.e., the deviation between day-ahead and intraday tie-line transmission planning. Step 5: Based on the generating capacity of each unit, individually adjust the primary planned adjustment power of each unit calculated in Step 4 to generate the secondary planned adjustment power of each unit; the specific method for the individual adjustment is as follows: All AGC units that are operational during the day are divided into Group A, Group B, and Group C. Group A units are those whose current power generation plan exceeds their upward regulation capacity; Group B units are those whose current power generation plan falls within their upward and downward regulation capacity; and Group C units are those whose current power generation plan is below their downward regulation capacity. The downward regulation capacity refers to the unit's downward regulation capacity without requiring deep regulation, i.e., 50% when the current regulation capacity is below 50%. For Group A units, Pa is the total amount by which the power generation plan exceeds the upper regulation capacity; for Group B units, Pb↑ is the upper regulation amount relative to the upper regulation capacity of the power generation plan, and Pb↓ is the lower regulation amount relative to the lower regulation capacity; for Group C units, Pc is the total amount by which the power generation plan exceeds the lower regulation capacity; under the premise of normal regulation of thermal power units, the following four cases are considered: (1) When Pa > Pc and (Pa - Pc) < Pb↑; Group A generating units formulate power generation plans based on maximum generating capacity, Group C generating units formulate power generation plans based on minimum generating capacity, and Group B generating units increase the active power generation of Pa-Pc portion according to the principle of adjusting the same load rate based on the current power generation plan, thereby achieving power balance again. (2) When Pa < Pc and (Pc - Pa) < Pb↓; The A and C groups of generating units will still formulate daily plans based on their maximum and minimum generating capacities, while the B group of generating units will reduce the active power generation of the Pc-Pa portion according to the principle of adjusting the same load rate based on the current generating plan, thereby achieving power balance again. (3) When Pa > Pc and (Pa - Pc) > Pb↑; At this time, the A group units and the B group units formulate power generation plans according to their maximum power generation capacity, and the C group units allocate the active power generation of Pa-Pc-Pb↑ according to the principle of adjusting the same load rate according to the current power generation plan, so as to achieve power balance again. (4) If Pa < Pc and (Pc - Pa) > Pb↓; Group B and Group C units formulate daily plans based on minimum generating capacity, while Group A units reduce the active power generation of Pc-Pa-Pb↓ based on maximum generating capacity and the principle of adjusting the same load rate. Step Six: Based on the OMS system requirements, adjust the power deviation of each unit's secondary plan adjustment power generated in Step Five to generate the initial No. 1 intraday power generation plan, and then execute Step Thirteen; Step 7: Determine whether the intraday power balance status obtained in Step 2 is a deep adjustment status; if the result is yes, proceed to Step 8; otherwise, proceed to Step 9. Step 8: Formulate an initial intraday power generation plan for Unit 2 based on ancillary service market quotations, and then execute Step 13; Step 9: Determine whether the intraday power balance status obtained in Step 2 indicates a power shortage. If the result is yes, proceed to Step 10; otherwise, proceed to Step 11. Step 10: Develop an initial three-day power generation plan based on maximum power generation capacity, and then execute Step 13; Step 11: Determine whether the intraday power balance status obtained in Step 2 is a state of power curtailment or a state of power surplus, and then proceed to Step 12; Step 12: Develop an initial four-day power generation plan based on the minimum power generation capacity, and then execute Step 13; Step 13: Perform safety checks on the initial intraday power generation plan No. 1 generated in Step 6, the initial intraday power generation plan No. 2 formulated in Step 8, the initial intraday power generation plan No. 3 formulated in Step 10, and the initial intraday power generation plan No. 4 formulated in Step 12, and generate the final intraday power generation plan.

2. The method for optimizing intraday power generation plans considering multiple deviations according to claim 1, characterized in that, The specific method for preprocessing the day-ahead power generation plan data in step one is as follows: 1) Determine the unit's start-up, shutdown, and planned output for the day; Read the unit output from the previous day's plan. If the output is not zero, it is assumed that the unit will be started at that time according to the previous day's plan; otherwise, it will be shut down. The actual output of the current generating unit is obtained from the D5000 dispatch automation system. If the current generating unit is in the starting state but there is no power generation plan, for the unit that has just started up, the curve from the current output to 52% at a ramp rate of 15% and maintained is used as the day-ahead plan and included in subsequent calculations; for the unit that is already in normal operation, the set value curve of 52% of the unit capacity is used as the day-ahead plan and included in subsequent calculations. 2) Identify the missing data in intraday load forecasts: Based on the day-ahead load forecast and the current actual load, an intraday load forecast curve is generated using the shift method: Daily load forecast = Daily load forecast + (Actual load - Daily load forecast) 3) Identify the missing information in the intraday new energy forecast: Based on the recent renewable energy forecast and the current actual renewable energy output, an intraday renewable energy forecast curve is formulated using the scaling-out method; the specific method is as follows: When the actual renewable energy output P at time t0 t0 Lower than the current new energy forecast P' t0 of: Daily New Energy Forecast P tx =Recent New Energy Forecast P' tx ×(P t0 ÷P' t0 ) When the actual renewable energy output P at time t0 t0 Higher than the recent new energy forecast P' t0 The calculation is no longer based on the ratio to the predicted power generation. To prevent the predicted daily renewable energy power generation from exceeding the installed capacity when the ratio factor is greater than 1, and considering the volatility of renewable energy power generation, an algorithm is adopted to reduce the gap between the predicted power generation and the theoretical maximum value when adjusting the predicted value. The reduction ratio is the ratio of the current actual gap to the predicted gap. The calculation is as follows: Daily New Energy Forecast P tx =P maxt -P maxt ×(1-P' tx ÷P maxt )×(1-P t0 ÷P max0 ) ÷ (1-P' t0 ÷P max0 ) Where P max0 and P maxt These represent the maximum theoretical power generation capacity of new energy sources at time 0 and time t, respectively, where wind power P max The figure represents the total installed capacity of wind power, and the figure represents the theoretical power generation curve of the total installed capacity of photovoltaic power under clear weather conditions. 4) Identify any missing information in the daily water and electricity schedule: Daily hydropower plan = Current actual hydropower output; 5) Determining the intraday curve planning refers to the planning curve of thermal power units that are not controlled by AGC: Daily curve planning = Daily curve planning unit actual output; 6) Determine the daily power generation limit for AGC units: The AGC unit's power generation limits are read from the ancillary service platform. If reading the upper and lower limits for the day fails, the upper and lower limits that were successfully read from the platform last time are used instead. When AGC provides new upper and lower limits, they are compared with the values ​​on the ancillary service platform. The smaller value is taken when comparing the upper limit, and the larger value is taken when comparing the lower limit.

3. The method for optimizing intraday power generation plans considering multiple deviations according to claim 1, characterized in that, The specific method for obtaining the intraday power balance status in step two is as follows: AGC unit generation capacity = load forecast + plant service network loss forecast + interconnection transmission plan - renewable energy forecast - hydropower plan - curve setting plan + forced adjustment capacity Among them, the load forecast, plant power grid loss forecast and new energy forecast adopt ultra-short-term forecast, hydropower plan is a fixed value, fixed curve plan is an actual value, and the forced adjustment space is initially assigned to 0. When the calculated power generation space of the AGC unit is not within the adjustable space of the AGC unit, it is necessary to adjust the new energy forecast or adjust the tie line plan to apply for modification of the tie line. At this point, the AGC unit's power generation capacity equals the upper / lower limit of the AGC unit's power generation capacity; Forced adjustment space = upper / lower limit of AGC unit power generation capacity - (load forecast + plant service network loss forecast + interconnection line transmission plan - new energy forecast - hydropower plan - fixed curve plan).

4. The method for optimizing intraday power generation plans considering multiple deviations according to claim 3, characterized in that, The intraday power balance status obtained in step two is divided into five types: a) Normal state: After adjustment, the AGC unit is within the normal range and the deviation of the tie line is zero; b) Deep adjustment status: After adjustment of the AGC unit, within the deep adjustment range, the tie line deviation is already zero; c) Power curtailment status: The AGC unit has been adjusted to the minimum, but renewable energy sources still need to be restricted before the tie line deviation can be reduced to zero; d) Power surplus state: AGC units have been adjusted to the lowest level, renewable energy to zero, but the interconnection line still has a positive power deviation; e) Power shortage status: The AGC unit has been adjusted to the highest level, the new energy unit is at its maximum, but there is still a power receiving deviation in the interconnection line.

5. The method for optimizing intraday power generation plans considering multiple deviations according to claim 1, characterized in that, The specific method for adjusting the power deviation of each unit's secondary plan based on the OMS system requirements in step six is ​​as follows: The OMS system provides power adjustment requirements, including the priority order of adjustment and the amount of power to be adjusted. The principle of this adjustment step is: based on the initial power generation plan for the day, the adjustment amount shall not exceed 5% of the rated capacity, not exceed the amount of power to be adjusted / 72 hours, and not exceed the unit's vertical adjustment capacity. According to the priority order of adjustment, the units with increased power generation demand shall be matched and adjusted one by one with the units with decreased power generation demand.

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