Data-driven power distribution line theoretical line loss calculation method and system

Abstract

The application relates to a data-driven power distribution line theoretical line loss calculation method and system, which comprises the following steps: firstly, pre-processing line measurement data, distribution transformer measurement data and tie-in junction measurement data; then, calculating the no-load loss and load loss of each connection distribution transformer in the network; on the basis of automatically calculating the distribution transformer gear, the branch loss of each node of the distribution transformer is calculated; the no-load loss, load loss and branch loss of the distribution transformer in the network are accumulated to obtain the network loss; and the ratio of the network loss to the network input power is obtained, that is, the power distribution line theoretical line loss value.

Description

Technical Field

[0001] This invention belongs to the field of power distribution technology, and in particular relates to a data-driven method and system for calculating theoretical line losses of power distribution lines. Background Technology

[0002] Theoretical line loss calculation for distribution lines is crucial for accurate diagnosis of technical losses in distribution networks. Theoretical losses in distribution lines consist of transformer no-load losses, transformer load losses, and losses in each branch line. Transformer no-load losses are largely unaffected by changes in the connected load and are voltage-type losses. Transformer load losses vary with the connected load and are proportional to the square of the load current, making them current-type losses. Branch line losses are generated by the impedance of the conductor through which current flows and are also proportional to the square of the load current, making them current-type losses. By calculating 10kV theoretical line losses, patterns in line losses can be quickly identified, weak points can be located, and key technical points for loss reduction can be found, thereby improving the economic operation of distribution lines.

[0003] The theoretical line loss calculation of power distribution lines mainly adopts the forward power flow back substitution method. However, due to the limitations of the accuracy of line topology parameters and basic parameters, there are many line loss problems that cannot be calculated. In addition, the calculation and analysis are generally carried out on typical days, which has certain limitations and biases when the line operation mode is varied, and long-term dynamic simulation calculations cannot be performed.

[0004] The theoretical line loss calculation object of a power distribution line can be regarded as a multi-port network. All the power input to the network includes: the power input from the substation to the network, the backfeed power input from each distribution transformer to the network, and the power input from other lines at the tie gate to the network. All the output power of the network ports includes: the power input from the power distribution line to the substation, the output load power of each distribution transformer, and the power output from the tie gate to other lines. Summary of the Invention

[0005] To achieve online calculation of theoretical line losses in power distribution lines, this invention proposes a data-driven method and system for calculating theoretical line losses in power distribution lines, based on the collected measurement data from the line side, transformer side, and tie-off point side.

[0006] This invention is achieved through the following technical solution: A data-driven method for calculating theoretical line losses in power distribution lines, comprising the following steps:

[0007] Step 1: Obtain measurement data from the line side, distribution transformer side, and tie gate side;

[0008] Step 2: Perform data preprocessing on the line-side measurement data, distribution transformer-side measurement data, and tie-gate-side measurement data;

[0009] Preprocessing of line-side measurement data: Analyze each line of line-side measurement data, delete missing data, abnormal voltage and current data, and determine that the data in the line where the data was collected is not included in the theoretical line loss calculation. At the same time, determine whether the line-side voltage data is collected by three-phase metering or two-phase metering.

[0010] The preprocessing method for measurement data on the connecting gate side is the same as that for measurement data on the line side.

[0011] Preprocessing of distribution transformer side measurement data: Analyze each row of distribution transformer side measurement data, delete missed data, abnormal voltage and current data, and determine that the row of data with the data acquisition time should not be included in the theoretical line loss calculation;

[0012] Step 3: Calculation of apparent power, average voltage, and average current data:

[0013] Step 4: Calculation of rated no-load and load losses of distribution transformers: Determine the rated no-load loss and rated load loss of distribution transformers based on the transformer connection group, design serial number, and capacity; Multiply the calculated apparent power of the distribution transformer by the rated load loss and divide by the rated capacity of the distribution transformer, then take the absolute value to obtain the corresponding load loss.

[0014] Step 5: Calculate the transformer gear position;

[0015] Step 6: Calculate branch loss: Calculate branch loss for the distribution variable measurement data at each data acquisition time, and find the average line voltage value at the same time.

[0016] Step 7: Calculate the theoretical line loss of the power distribution line at each data collection time point.

[0017] Specifically, the preprocessing method for line-side measurement data is as follows:

[0018] ① Delete any row record where the A-phase line voltage, C-phase line voltage, A-phase line current, C-phase line current, or multiplier field is empty;

[0019] ② Add a field for line voltage metering method attribute. If the line voltage of phase A is not greater than 75 and is greater than 35, and the absolute value of the difference between the maximum value of the three-phase line voltage and the minimum value of the three-phase line voltage is less than 1, then the line voltage metering method is 2, indicating high-voltage three-phase metering method; if the line voltage of phase A is not greater than 150 and is greater than 75, and the absolute value of the difference between the line voltage of phase A and the C-phase line voltage is less than 1, then the line voltage metering method is 3, indicating high-voltage two-phase metering method; if the line voltage of phase A is not greater than 300 and is greater than 150, and the absolute value of the difference between the maximum value of the three-phase line voltage and the minimum value of the three-phase line voltage is less than 30, then the line voltage metering method is 1, indicating low-voltage metering method. If these rules are not met, delete the record and do not include it in the theoretical line loss calculation.

[0020] Specifically, the preprocessing method for distribution transformer side measurement data is as follows:

[0021] ① Collect power supply assessment data and electricity sales settlement measurement data for the transformer substation; delete all other data related to office electricity consumption and low-voltage photovoltaic power.

[0022] ② Delete any row containing empty values ​​for phase A voltage, phase C voltage, phase A current, phase C current, current transformer ratio, and voltage transformer ratio of any distribution transformer.

[0023] ③ Add a field for transformer voltage metering method attribute. If the transformer A phase voltage is not greater than 75 and is greater than 35, and the absolute value of the difference between the maximum value of the transformer A, B, and C phase voltages and the minimum value of the transformer three-phase voltages is less than 1, then the transformer voltage metering attribute is 2, indicating high-voltage three-phase metering method. If the transformer A phase voltage is not greater than 150 and is greater than 75, and the absolute value of the difference between the transformer A phase voltage and the C phase voltage is less than 1, then the transformer voltage metering attribute is 3, indicating high-voltage two-phase metering method. If the transformer A phase voltage is not greater than 300 and is greater than 150, and the absolute value of the difference between the maximum value of the transformer A, B, and C phase voltages and the minimum value of the transformer three-phase voltages is less than 30, then the transformer voltage metering attribute is 1, indicating low-voltage three-phase metering method. If these rules are not met, delete the record and do not include it in the theoretical line loss calculation.

[0024] Step three specifically involves:

[0025] (I) Calculation of line-side measurement data:

[0026] ① If the line voltage metering method is 3, then the line apparent power at the corresponding data acquisition time is obtained by multiplying the corresponding A and C phase line voltages by their respective A and C phase currents, multiplying by 1.732 / 2, and then multiplying by the multiplier. At the same time, the average line voltage of A and C phases is calculated to obtain the line average voltage value.

[0027] ② If the line voltage metering method is 2, then the line apparent power at the corresponding data acquisition time is obtained by multiplying the corresponding A, B, and C phase line voltages by their respective A, B, and C phase currents and then multiplying by the multiplier. At the same time, the average value of the three-phase line voltage is calculated and multiplied by 1.732 to obtain the average line voltage value.

[0028] (II) Calculation of Measurement Data on Distribution Transformer Side:

[0029] ① If the transformer voltage metering method is 3, then the apparent power of the transformer at the corresponding data acquisition time is obtained by multiplying the corresponding transformer phase A and C voltages by their respective transformer phase A and C currents, multiplying by 1.732 / 2, and then multiplying by the multiplier. The average value of the transformer phase A and C voltages is calculated to obtain the transformer average voltage value. The average value of the transformer phase A and C currents is calculated to obtain the transformer average current value.

[0030] ② If the transformer voltage metering method is 2, then the apparent power of the transformer at the corresponding data acquisition time is obtained by multiplying the corresponding phase A, B, and C voltages of the transformer by their respective phase A, B, and C currents, and then multiplying by a factor. The average value of the three-phase voltages of transformer A, B, and C is calculated and multiplied by 1.732 to obtain the average transformer voltage value. The average value of the three-phase currents of transformer A, B, and C is calculated to obtain the average transformer current value.

[0031] ③ If the distribution transformer voltage metering method is 1, then the apparent power of the distribution transformer at the corresponding data acquisition time is obtained by multiplying the voltage of phases A, B, and C of the distribution transformer by their respective currents, then multiplying by the current transformer ratio, and then multiplying by the voltage transformer ratio. Simultaneously, the average value of the three-phase voltages of distribution transformers A, B, and C is calculated to obtain the average voltage value of the distribution transformer. The average value of the three-phase currents of distribution transformers A, B, and C is calculated to obtain the average current value of the distribution transformer.

[0032] Specifically, calculate the transformer gear:

[0033] Step 1: Distribution transformer side measurement data with distribution transformer voltage metering mode 1 under the same data acquisition time; Step 2: Delete rows with negative line apparent power, and extract the 5 rows of data with the lowest line apparent power each day; Step 3: Match the data acquisition time of the distribution transformer side measurement data obtained in Step 1 to the line side measurement data processed in Step 2, group by day, average the average voltage value of each distribution transformer and the average voltage value of the line, to obtain the daily average voltage value of each public and private transformer, and the daily average voltage value of the line. Then, divide the daily average voltage value of the line voltage by the daily average voltage value of the distribution transformer to obtain the preliminary transformer ratio.

[0034] Step 4: Based on the initial voltage range of the public and private transformers each day, compare it with the distribution transformer voltage ratio list. Set all values ​​less than -0.1 to 100 to obtain the distribution transformer voltage ratio difference list. At the same time, take the voltage ratio in the distribution transformer voltage ratio list corresponding to the minimum value in the distribution transformer voltage ratio difference list as the final voltage ratio of that distribution transformer for that day.

[0035] Specifically, calculate the branch loss:

[0036] ① If the distribution transformer voltage metering method is 2, subtract the average line voltage value from the average distribution transformer voltage value, multiply by the average distribution transformer current value, multiply by the current transformer ratio, and then multiply by the voltage transformer ratio to obtain the branch line loss value for that data acquisition time.

[0037] ② If the distribution transformer voltage metering method is 3, subtract the average line voltage value from the average distribution transformer voltage value, multiply by the average distribution transformer current value, multiply by the current transformer ratio, and then multiply by the voltage transformer ratio to obtain the branch line loss value for that data acquisition time.

[0038] ③ If the distribution transformer voltage metering method is 1, take the average distribution transformer voltage, multiply it by the final transformation ratio of the distribution transformer on that day, take the average distribution transformer current value, divide it by the final transformation ratio of the distribution transformer on that day, subtract the average line voltage value from the average distribution transformer voltage value, multiply it by the average distribution transformer current value, multiply it by the current transformer transformation ratio, and then multiply it by the voltage transformer transformation ratio to obtain the branch line loss value at that data acquisition time.

[0039] Step seven is as follows: Taking the line as a unit, calculate the cumulative no-load loss and cumulative load loss of the transformers connected to the transformers with voltage metering mode 1 at the same data acquisition time, calculate the cumulative line loss of all transformer branches, calculate the cumulative value of transformer apparent power less than 0, and subtract the cumulative value of transformer apparent power less than 0 from the line apparent power to obtain the line input power; add the cumulative no-load loss to the cumulative load loss and the cumulative branch line loss, and then divide by the line input power to obtain the theoretical line loss value for that data acquisition time.

[0040] The line-side measurement data comes from the electricity metering system and includes: A-phase line voltage, B-phase line voltage, C-phase line voltage, A-phase line current, B-phase line current, C-phase line current, data acquisition time, power factor readings at 96 points, multiplier, line name, line number, and metering point number.

[0041] The measurement data on the distribution transformer side comes from the electricity consumption data acquisition system. The measurement data on the distribution transformer side includes: distribution transformer A-phase voltage, distribution transformer B-phase voltage, distribution transformer C-phase voltage, distribution transformer A-phase current, distribution transformer B-phase current, distribution transformer C-phase current, data acquisition time, 96-point power factor, current transformer ratio, voltage transformer ratio, transformer area name, transformer area number, metering point number, metering method, metering point purpose, and capacity.

[0042] The measurement data at the connection point comes from the power distribution automation system or the power consumption data acquisition system. The measurement data at the connection point includes: phase A voltage, phase B voltage, phase C voltage, phase A current, phase B current, phase C current, data acquisition time, power factor readings at 96 points, multiplier, line name, line number, and metering point number.

[0043] The present invention provides a computer-readable medium having computer instructions stored thereon, which, when executed by a processor, implement the data-driven method for calculating theoretical line losses of power distribution lines.

[0044] This invention provides a data-driven distribution line theoretical line loss calculation system, comprising: one or more processors; a memory for storing one or more programs; when the one or more programs are executed by the one or more processors, the one or more processors implement the data-driven distribution line theoretical line loss calculation method.

[0045] The beneficial effects of this invention are:

[0046] (1) This invention does not consider network topology and conductor parameters, improves the theoretical line loss calculation rate of distribution lines, automatically calculates the transformer ratio of the distribution area, and does not require on-site verification of transformer taps.

[0047] (2) This invention can quickly determine the proportion of no-load, load and branch loss, as well as the list of high-loss transformers and the list of high-loss branch lines, and implement precise management.

[0048] (3) This invention can quickly determine the impact of load on line loss in each section of the line, as well as the impact of small hydropower and photovoltaic distributed power sources on line loss.

[0049] (4) Based on the existing measurement data in the power distribution network, the present invention does not require additional acquisition devices. The theoretical line loss of the power distribution line can be calculated online through an executable program, which can meet the needs of large-scale promotion and application. Detailed Implementation

[0050] A data-driven method for calculating theoretical line losses in power distribution lines, comprising the following steps:

[0051] Step 1: Obtain measurement data from the line side, distribution transformer side, and tie gate side;

[0052] The line-side measurement data comes from the electricity metering system and includes: A-phase line voltage, B-phase line voltage, C-phase line voltage, A-phase line current, B-phase line current, C-phase line current, data acquisition time, power factor readings at 96 points, multiplier, line name, line number, and metering point number.

[0053] The measurement data on the distribution transformer side comes from the electricity consumption data acquisition system. The measurement data on the distribution transformer side includes: distribution transformer A-phase voltage, distribution transformer B-phase voltage, distribution transformer C-phase voltage, distribution transformer A-phase current, distribution transformer B-phase current, distribution transformer C-phase current, data acquisition time, 96-point power factor, current transformer ratio, voltage transformer ratio, transformer area name, transformer area number, metering point number, metering method, metering point purpose, and capacity.

[0054] The measurement data at the connection point comes from the power distribution automation system or the power consumption data acquisition system. The measurement data at the connection point includes: phase A voltage, phase B voltage, phase C voltage, phase A current, phase B current, phase C current, data acquisition time, power factor readings at 96 points, multiplier, line name, line number, and metering point number.

[0055] Step 2: Perform data preprocessing on the line-side measurement data, distribution transformer-side measurement data, and tie-gate-side measurement data;

[0056] Each row of measurement data on the line side is analyzed, and missing data, abnormal voltage and current data are deleted. The row of data with the data collection time is determined to be excluded from the theoretical line loss calculation. At the same time, it is determined whether the voltage data collection method on the line side is the three-phase metering method or the two-phase metering method.

[0057] ① Delete any row record where the fields for A-phase line voltage, C-phase line voltage, A-phase line current, C-phase line current, and multiplier are empty.

[0058] ② Add a field for line voltage metering method attribute. If the line voltage of phase A is not greater than 75 and is greater than 35, and the absolute value of the difference between the maximum value of the three-phase line voltage and the minimum value of the three-phase line voltage is less than 1, then the line voltage metering method is 2, indicating high-voltage three-phase metering method; if the line voltage of phase A is not greater than 150 and is greater than 75, and the absolute value of the difference between the line voltage of phase A and the C-phase line voltage is less than 1, then the line voltage metering method is 3, indicating high-voltage two-phase metering method; if the line voltage of phase A is not greater than 300 and is greater than 150, and the absolute value of the difference between the maximum value of the three-phase line voltage and the minimum value of the three-phase line voltage is less than 30, then the line voltage metering method is 1, indicating low-voltage metering method. If these rules are not met, delete the record and do not include it in the theoretical line loss calculation.

[0059] The preprocessing method for measurement data on the connection point side is the same as that for measurement data on the line side.

[0060] Each row of measurement data from the distribution transformer side is analyzed, and missing, abnormal voltage, and abnormal current data are deleted. The row containing the data collection time is determined and is not included in the theoretical line loss calculation.

[0061] ① Collect the power supply assessment data of the transformer substation and the settlement measurement data of the electricity sales side, and delete all other data involving office electricity consumption and low-voltage photovoltaic power.

[0062] ② Delete any row containing empty values ​​for phase A voltage, phase C voltage, phase A current, phase C current, current transformer ratio, and voltage transformer ratio of any transformer.

[0063] ③ Add a field for transformer voltage metering method attribute. If the transformer A phase voltage is not greater than 75 and is greater than 35, and the absolute value of the difference between the maximum value of the transformer A, B, and C phase voltages and the minimum value of the transformer three-phase voltages is less than 1, then the transformer voltage metering attribute is 2, indicating high-voltage three-phase metering method. If the transformer A phase voltage is not greater than 150 and is greater than 75, and the absolute value of the difference between the transformer A phase voltage and the C phase voltage is less than 1, then the transformer voltage metering attribute is 3, indicating high-voltage two-phase metering method. If the transformer A phase voltage is not greater than 300 and is greater than 150, and the absolute value of the difference between the maximum value of the transformer A, B, and C phase voltages and the minimum value of the transformer three-phase voltages is less than 30, then the transformer voltage metering attribute is 1, indicating low-voltage three-phase metering method. If these rules are not met, delete the record and do not include it in the theoretical line loss calculation.

[0064] Step 3: Calculation of apparent power, average voltage, and average current data:

[0065] (I) Calculation of line-side measurement data:

[0066] ① If the line voltage metering method is 3, then the line apparent power at the corresponding data acquisition time is obtained by multiplying the corresponding A and C phase line voltages by their respective A and C phase currents, multiplying by 1.732 / 2, and then multiplying by the multiplier. At the same time, the average line voltage of A and C phases is calculated to obtain the line average voltage value.

[0067] ② If the line voltage metering method is 2, then the line apparent power at the corresponding data acquisition time is obtained by multiplying the corresponding A, B, and C phase line voltages by their respective A, B, and C phase currents and then multiplying by the multiplier. At the same time, the average value of the three-phase line voltage is calculated and multiplied by 1.732 to obtain the average line voltage value.

[0068] (II) Calculation of Measurement Data on Distribution Transformer Side:

[0069] ① If the transformer voltage metering method is 3, then the apparent power of the transformer at the corresponding data acquisition time is obtained by multiplying the corresponding transformer phase A and C voltages by their respective transformer phase A and C currents, multiplying by 1.732 / 2, and then multiplying by the multiplier. The average value of the transformer phase A and C voltages is calculated to obtain the transformer average voltage value. The average value of the transformer phase A and C currents is calculated to obtain the transformer average current value.

[0070] ② If the transformer voltage metering method is 2, then the apparent power of the transformer at the corresponding data acquisition time is obtained by multiplying the corresponding phase A, B, and C voltages of the transformer by their respective phase A, B, and C currents, and then multiplying by a factor. The average value of the three-phase voltages of transformer A, B, and C is calculated and multiplied by 1.732 to obtain the average transformer voltage value. The average value of the three-phase currents of transformer A, B, and C is calculated to obtain the average transformer current value.

[0071] ③ If the distribution transformer voltage metering method is 1, then the apparent power of the distribution transformer at the corresponding data acquisition time is obtained by multiplying the voltage of phases A, B, and C of the distribution transformer by their respective currents, then multiplying by the current transformer ratio, and then multiplying by the voltage transformer ratio. Simultaneously, the average value of the three-phase voltages of distribution transformers A, B, and C is calculated to obtain the average voltage value of the distribution transformer. The average value of the three-phase currents of distribution transformers A, B, and C is calculated to obtain the average current value of the distribution transformer.

[0072] Step 4: Calculation of Rated No-Load and Load Losses of Distribution Transformers: Determine the rated no-load loss and rated load loss of the distribution transformer based on the transformer connection group, design serial number, and capacity. The load loss is obtained by multiplying the calculated apparent power of the distribution transformer by the rated load loss, dividing by the rated capacity of the distribution transformer, and then taking the absolute value.

[0073] Step 5: Calculate the transformer gear position:

[0074] Step 1: Distribution transformer side measurement data with distribution transformer voltage metering mode 1 under the same data acquisition time; Step 2: Delete rows with negative line apparent power, and extract the 5 rows of data with the lowest line apparent power each day; Step 3: Match the data acquisition time of the distribution transformer side measurement data obtained in Step 1 to the line side measurement data processed in Step 2, group by day, average the average voltage value of each distribution transformer and the average voltage value of the line, to obtain the daily average voltage value of each public and private transformer, and the daily average voltage value of the line. Then, divide the daily average voltage value of the line voltage by the daily average voltage value of the distribution transformer to obtain the preliminary transformer ratio.

[0075] Step 4: Based on the initial daily voltage levels of public and private transformers, compare them with the distribution transformer voltage ratio list [23.75, 24.375, 25, 25.625, 26.25]. Set all values ​​less than -0.1 to 100 to obtain the distribution transformer voltage ratio difference list. At the same time, take the voltage ratio in the distribution transformer voltage ratio list corresponding to the minimum value in the distribution transformer voltage ratio difference list as the final voltage ratio of that distribution transformer for that day.

[0076] Step 6: Calculate branch loss:

[0077] Calculate branch losses from the distribution variable measurement data at each data acquisition time, and find the average line voltage value at the same time.

[0078] ① If the distribution transformer voltage metering method is 2, subtract the average line voltage value from the average distribution transformer voltage value, multiply by the average distribution transformer current value, multiply by the current transformer ratio, and then multiply by the voltage transformer ratio to obtain the branch line loss value for that data acquisition time.

[0079] ② If the distribution transformer voltage metering method is 3, subtract the average line voltage value from the average distribution transformer voltage value, multiply by the average distribution transformer current value, multiply by the current transformer ratio, and then multiply by the voltage transformer ratio to obtain the branch line loss value for that data acquisition time.

[0080] ③ If the distribution transformer voltage metering method is 1, take the average distribution transformer voltage, multiply it by the final transformation ratio of the distribution transformer on that day, take the average distribution transformer current value, divide it by the final transformation ratio of the distribution transformer on that day, subtract the average line voltage value from the average distribution transformer voltage value, multiply it by the average distribution transformer current value, multiply it by the current transformer transformation ratio, and then multiply it by the voltage transformer transformation ratio to obtain the branch line loss value at that data acquisition time.

[0081] Step 7: Calculate the theoretical line loss of the power distribution line at each data acquisition time point:

[0082] Using the line as a unit, calculate the cumulative no-load loss and cumulative load loss of the transformers connected to the transformer with voltage metering mode 1 at the same data acquisition time. Calculate the cumulative line loss of all transformer branches and the cumulative value of transformer apparent power less than 0. Subtract the cumulative value of transformer apparent power less than 0 from the line apparent power to obtain the line input power. Add the cumulative no-load loss to the cumulative load loss and the cumulative branch line loss, and then divide by the line input power to obtain the theoretical line loss value for that data acquisition time.

[0083] Taking the calculation of the theoretical line loss of the XX power distribution line from June 6, 2023 to June 15, 2023 as an example, the daily theoretical line loss value of the power distribution line is obtained, as shown in Table 1.

[0084]

[0085] Table 1 Theoretical line loss calculation

[0086] This embodiment provides a computer-readable medium storing computer instructions that, when executed by a processor, implement the data-driven method for calculating theoretical line losses of power distribution lines.

[0087] This embodiment provides a data-driven distribution line theoretical line loss calculation system, including: one or more processors; a memory for storing one or more programs; when the one or more programs are executed by the one or more processors, the one or more processors implement the data-driven distribution line theoretical line loss calculation method.

[0088] The above description is merely an application example of the present invention and does not limit the patent scope of the present invention. Any equivalent structural or procedural transformations made using the content of the present invention, or direct or indirect applications in other related technical fields, are similarly included within the patent protection scope of the present invention.

Claims

1. A data-driven method for calculating theoretical line losses in power distribution lines, characterized in that, The steps are as follows: Step 1: Obtain measurement data from the line side, distribution transformer side, and connecting gate side; Step 2: Perform data preprocessing on the line-side measurement data, distribution transformer-side measurement data, and tie-gate-side measurement data; Preprocessing of line-side measurement data: Analyze each line of line-side measurement data, delete missing data, abnormal voltage and current data, and determine that the data in the line where the data was collected is not included in the theoretical line loss calculation. At the same time, determine whether the line-side voltage data is collected by three-phase metering or two-phase metering. The preprocessing method for measurement data on the connecting gate side is the same as that for measurement data on the line side. Preprocessing of distribution transformer side measurement data: Analyze each row of distribution transformer side measurement data, delete missed data, abnormal voltage and current data, and determine that the row of data with the data acquisition time should not be included in the theoretical line loss calculation; Step 3: Calculation of apparent power, average voltage, and average current data: Step 4: Calculation of rated no-load and load losses of distribution transformers: Determine the rated no-load loss and rated load loss of distribution transformers based on the transformer connection group, design serial number, and capacity; Multiply the calculated apparent power of the distribution transformer by the rated load loss and divide by the rated capacity of the distribution transformer, then take the absolute value to obtain the corresponding load loss. Step 5: Calculate the transformer gear position; Step 6: Calculate branch loss: Calculate branch loss for the distribution variable measurement data at each data acquisition time, and find the average line voltage value at the same time. Step 7: Calculate the theoretical line loss of the power distribution line at each data acquisition time point; The preprocessing method for line-side measurement data is as follows: ① Delete any row record where the A-phase line voltage, C-phase line voltage, A-phase line current, C-phase line current, or multiplier field is empty; ② Add a field for line voltage metering method attribute. If the voltage of phase A is not greater than 75 and is greater than 35, and the absolute value of the difference between the maximum value of the three-phase line voltage and the minimum value of the three-phase line voltage is less than 1, then the line voltage metering method is 2, indicating high-voltage three-phase metering method; if the voltage of phase A is not greater than 150 and is greater than 75, and the absolute value of the difference between the voltage of phase A and the voltage of phase C is less than 1, then the line voltage metering method is 3, indicating high-voltage two-phase metering method; if the voltage of phase A is not greater than 300 and is greater than 150, and the absolute value of the difference between the maximum value of the three-phase line voltage and the minimum value of the three-phase line voltage is less than 30, then the line voltage metering method is 1, indicating low-voltage metering method. If these rules are not met, delete the record and do not include it in the theoretical line loss calculation. The steps for calculating the transformer gear are as follows: Step ①: Measurement data of the distribution transformer side with distribution transformer voltage metering mode 1 under the same data acquisition time; Step 2: Delete the rows with negative line apparent power, and extract the 5 rows with the lowest line apparent power for each day; Step 3: Match the data acquisition time of the distribution transformer side measurement data obtained in Step 1 to the line side measurement data processed in Step 2. Group the average voltage value of each distribution transformer and the average voltage value of the line by day to obtain the average voltage value of each public and private transformer on the same day and the average voltage value of the line. Then divide the average voltage value of the line by the average voltage value of the distribution transformer to obtain the preliminary transformer ratio. Step 4: Based on the initial voltage range of the public and private transformers each day, compare it with the distribution transformer voltage ratio list. Set all values ​​less than -0.1 to 100 to obtain the distribution transformer voltage ratio difference list. At the same time, take the voltage ratio in the distribution transformer voltage ratio list corresponding to the minimum value in the distribution transformer voltage ratio difference list as the final voltage ratio of that distribution transformer for that day.

2. The data-driven method for calculating theoretical line losses of power distribution lines according to claim 1, characterized in that, The preprocessing method for distribution transformer side measurement data is as follows: ① Collect power supply assessment data and electricity sales settlement measurement data for the transformer substation; delete all other data related to office electricity consumption and low-voltage photovoltaic power. ② Delete any row containing empty values ​​for phase A voltage, phase C voltage, phase A current, phase C current, CT, and PT of any distribution transformer. ③ Add a field for transformer voltage metering method attribute. If the transformer A phase voltage is not greater than 75 and is greater than 35, and the absolute value of the difference between the maximum value of the transformer A, B, and C phase voltages and the minimum value of the transformer three-phase voltages is less than 1, then the transformer voltage metering attribute is 2, indicating high-voltage three-phase metering method. If the transformer A phase voltage is not greater than 150 and is greater than 75, and the absolute value of the difference between the transformer A phase voltage and the C phase voltage is less than 1, then the transformer voltage metering attribute is 3, indicating high-voltage two-phase metering method. If the transformer A phase voltage is not greater than 300 and is greater than 150, and the absolute value of the difference between the maximum value of the transformer A, B, and C phase voltages and the minimum value of the transformer three-phase voltages is less than 30, then the transformer voltage metering attribute is 1, indicating low-voltage three-phase metering method. If these rules are not met, delete the record and do not include it in the theoretical line loss calculation.

3. The data-driven method for calculating theoretical line losses in power distribution lines according to claim 2, characterized in that, Step three specifically involves: (a) Calculation of line-side measurement data: ① If the line voltage metering method is 3, then the line apparent power at the corresponding data acquisition time is obtained by multiplying the corresponding A and C phase line voltages by their respective A and C line currents, multiplying by 1.732 / 2, and then multiplying by the multiplier. At the same time, the average line voltage of A and C phases is calculated to obtain the average line voltage value. ② If the line voltage metering method is 2, then the line apparent power at the corresponding data acquisition time is obtained by multiplying the corresponding A, B, and C phase line voltages by their respective A, B, and C phase currents and then multiplying by the multiplier. At the same time, the average value of the three-phase line voltage is calculated and multiplied by 1.732 to obtain the average line voltage value. (II) Calculation of measurement data on the distribution transformer side: ① If the distribution transformer voltage metering method is 3, then the apparent power of the distribution transformer at the corresponding data acquisition time is obtained by multiplying the corresponding A and C phase voltages of the distribution transformer with their respective A and C currents, multiplying by 1.732 / 2, and then multiplying by the multiplier; the average value of the A and C phase voltages of the distribution transformer is calculated to obtain the average voltage value of the distribution transformer. Calculate the average current of phases A and C of the distribution transformer to obtain the average current value of the distribution transformer; ② If the transformer voltage metering method is 2, then the apparent power of the transformer at the corresponding data acquisition time is obtained by multiplying the voltage of phases A, B, and C of the transformer with the current of phases A, B, and C of the transformer respectively, and then multiplying by the multiplier; the average value of the three-phase voltages of transformers A, B, and C is calculated and then multiplied by 1.732 to obtain the average voltage value of the transformer. Calculate the average value of the three-phase currents A, B, and C of the distribution transformer to obtain the average current value of the distribution transformer. ③ If the distribution transformer voltage metering method is 1, then the apparent power of the distribution transformer at the corresponding data acquisition time is obtained by multiplying the voltage of phases A, B, and C of the distribution transformer by their respective currents, multiplying the sum by the current transformer ratio, and then multiplying by the voltage transformer ratio; at the same time, the average value of the three-phase voltages of distribution transformers A, B, and C is calculated to obtain the average voltage value of the distribution transformer; the average value of the three-phase currents of distribution transformers A, B, and C is calculated to obtain the average current value of the distribution transformer.

4. The data-driven method for calculating theoretical line losses of power distribution lines according to claim 3, characterized in that, Calculate branch loss: ① If the distribution transformer voltage metering method is 2, subtract the average line voltage value from the average distribution transformer voltage value, multiply by the average distribution transformer current value, multiply by the current transformer ratio, and then multiply by the voltage transformer ratio to obtain the branch line loss value for that data acquisition time. ② If the distribution transformer voltage metering method is 3, subtract the average line voltage value from the average distribution transformer voltage value, multiply by the average distribution transformer current value, multiply by the current transformer ratio, and then multiply by the voltage transformer ratio to obtain the branch line loss value for that data acquisition time. ③ If the distribution transformer voltage metering method is 1, take the average distribution transformer voltage, multiply it by the final transformation ratio of the distribution transformer on that day, take the average distribution transformer current value, divide it by the final transformation ratio of the distribution transformer on that day, subtract the average line voltage value from the average distribution transformer voltage value, multiply it by the average distribution transformer current value, multiply it by the current transformer transformation ratio, and then multiply it by the voltage transformer transformation ratio to obtain the branch line loss value at that data acquisition time.

5. The data-driven method for calculating theoretical line losses of power distribution lines according to claim 4, characterized in that, Step seven is as follows: Taking the line as a unit, calculate the cumulative no-load loss and cumulative load loss of the transformers connected to the transformers with voltage metering mode 1 at the same data acquisition time, calculate the cumulative line loss of all transformer branches, calculate the cumulative value of transformer apparent power less than 0, and subtract the cumulative value of transformer apparent power less than 0 from the line apparent power to obtain the line input power; add the cumulative no-load loss to the cumulative load loss and the cumulative branch line loss, and then divide by the line input power to obtain the theoretical line loss value for that data acquisition time.

6. The data-driven method for calculating theoretical line losses of power distribution lines according to claim 1, characterized in that, The line-side measurement data comes from the electricity metering system and includes: A-phase line voltage, B-phase line voltage, C-phase line voltage, A-phase line current, B-phase line current, C-phase line current, data acquisition time, power factor readings at 96 points, multiplier, line name, line number, and metering point number. The measurement data on the distribution transformer side comes from the electricity consumption data acquisition system. The measurement data on the distribution transformer side includes: distribution transformer A-phase voltage, distribution transformer B-phase voltage, distribution transformer C-phase voltage, distribution transformer A-phase current, distribution transformer B-phase current, distribution transformer C-phase current, data acquisition time, power factor readings at 96 points, current transformer ratio, voltage transformer ratio, transformer substation name, transformer substation number, metering point number, metering method, metering point purpose, and capacity. The measurement data at the connection point comes from the power distribution automation system or the power consumption data acquisition system. The measurement data at the connection point includes: phase A voltage, phase B voltage, phase C voltage, phase A current, phase B current, phase C current, data acquisition time, power factor readings at 96 points, multiplier, line name, line number, and metering point number.

7. A computer-readable medium having stored thereon computer instructions that, when executed by a processor, implement the data-driven method for calculating theoretical line losses of power distribution lines as described in any one of claims 1-6.

8. A data-driven system for calculating theoretical line losses in power distribution lines, comprising: One or more processors; Memory, used to store one or more programs; When the one or more programs are executed by the one or more processors, the one or more processors implement the data-driven method for calculating theoretical line losses of power distribution lines as described in any one of claims 1-6.

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