Zero sequence overcurrent protection checking method based on power grid primary simulation platform

Abstract

The application discloses a zero sequence overcurrent protection checking method based on a power grid primary simulation platform, and comprises the following steps: obtaining power flow information and grid frame parameters of a regional power grid through a dispatching automation system, and establishing a power grid primary simulation platform; S2, calculating system equivalent impedance at a bus corresponding to a fault point in a small mode through the power grid primary simulation platform; S3, obtaining zero sequence currents of relevant fault points according to the system equivalent impedance at the bus corresponding to the fault point and a power grid operation mode; S4, calculating zero sequence overcurrent II section setting values and zero sequence overcurrent III section setting values according to the zero sequence currents of the relevant fault points; and S5, calling the zero sequence overcurrent II section setting values and the zero sequence overcurrent III section setting values in an actual protection device, and comparing the zero sequence overcurrent II section setting values and the zero sequence overcurrent III section setting values obtained through calculation, so as to complete zero sequence overcurrent protection checking. According to the method, the system equivalent impedance is calculated by considering generator and load fluctuation, and the accuracy of zero sequence overcurrent protection checking and the reliability of relay protection device operation are improved.

Description

Technical Field

[0001] This application relates to the field of power system simulation technology, and in particular to a zero-sequence overcurrent protection verification method based on a primary power grid simulation platform. Background Technology

[0002] Existing zero-sequence overcurrent protection verification methods rely on manual calculation of the system's equivalent impedance and the calculation of the zero-sequence current at the fault point based on specific power grid operating conditions. This approach is labor-intensive, error-prone, and the calculation results are highly dependent on the power grid's operating conditions, resulting in significant calculation errors. This invention utilizes a dispatch automation system to establish a primary power grid simulation platform. The model data is derived from actual power grid parameters, and by calculating the fluctuating bus voltage and current, it obtains the system impedance closest to the real power grid, improving the accuracy of the zero-sequence fault current. Simultaneously, using an expert database model, the settings for stages II and III of the zero-sequence overcurrent protection are obtained and compared with the settings in the actual protection device, further improving accuracy and ensuring the safe and stable operation of the power grid. Summary of the Invention

[0003] To address the aforementioned shortcomings in existing technologies, this invention provides a zero-sequence overcurrent protection verification method based on a primary power grid simulation platform. This method solves the problems of large workload, error-proneness, and significant calculation errors in traditional power grids that rely on manual methods to calculate equivalent impedance.

[0004] To achieve the aforementioned objectives, the technical solution adopted by this invention is: a zero-sequence overcurrent protection verification method based on a power grid primary simulation platform, comprising:

[0005] S1. The dispatch automation system obtains regional power grid flow information and grid parameters, and establishes a primary power grid simulation platform;

[0006] S2. Calculate the equivalent impedance of the system at the bus corresponding to the fault point under small-mode conditions using a power grid primary simulation platform;

[0007] S3. Based on the equivalent impedance of the system at the bus corresponding to the fault point and the power grid operation mode, obtain the zero-sequence current at the relevant fault point;

[0008] S4. Calculate the zero-sequence overcurrent stage II and zero-sequence overcurrent stage III settings based on the zero-sequence current at the relevant fault points.

[0009] S5. Retrieve the zero-sequence overcurrent stage II and zero-sequence overcurrent stage III settings from the actual protection device, and compare them with the calculated zero-sequence overcurrent stage II and zero-sequence overcurrent stage III settings to complete the zero-sequence overcurrent protection verification.

[0010] Furthermore: S1 contains regional power grid flow information and grid parameters including the power generation of the regional power system, load power, power output of 500kV substations, line parameters, and transformer parameters.

[0011] Furthermore: S2 includes:

[0012] S201, Dispatch automation system, obtains the output power of each generator and the load power of each node corresponding to the minimum annual power grid load;

[0013] S202. Based on the output power of each generator and the load power of each node corresponding to the minimum annual grid load, obtain the normal distribution samples of each generator and the normal distribution samples of each node load power at the minimum annual grid load.

[0014] S203. Substitute the normal distribution samples of each generator and the normal distribution samples of each node load power when the annual grid is at its minimum load into the grid primary simulation platform;

[0015] S204. Using the primary power grid simulation platform and the Monte Carlo probabilistic power flow calculation method, obtain the bus voltage sample set and load current sample set corresponding to the fault point under normal distribution.

[0016] S205. Based on the bus voltage sample set and load current sample set corresponding to the fault point under normal distribution, calculate the equivalent impedance of the system at the bus corresponding to the fault point under the small mode.

[0017] Furthermore: S3 includes:

[0018] S301. Generate a short-circuit current calculation sequence network diagram based on the equivalent impedance of the system at the bus corresponding to the fault point and the power grid operation mode.

[0019] S302. Based on the short-circuit current calculation sequence network diagram and the characteristics of the single-phase grounding fault network at the end of the line, calculate the zero-sequence current value during single-phase grounding.

[0020] S303. Based on the short-circuit current calculation sequence network diagram and the characteristics of the fault network when two phases are grounded at the end of the line, calculate the zero-sequence current value when two phases are grounded at the end of the line.

[0021] S304. Take the smaller of the zero-sequence current value when a single phase is grounded and the zero-sequence current value when two phases are grounded at the end of the line as the zero-sequence current at the fault point.

[0022] Furthermore: In S4, there are three methods for calculating the zero-sequence overcurrent stage II setting:

[0023] Method 1: Calculate the zero-sequence overcurrent stage II setting based on the zero-sequence current at the relevant fault point, and on the premise of ensuring sufficient sensitivity when there is a fault at the end of this line;

[0024] Method 2: Calculate the zero-sequence overcurrent stage II setting value based on the coordination relationship between this line and adjacent lines;

[0025] Method 3: Calculate the zero-sequence overcurrent stage II setting value based on the 220kV transformer on the opposite side of the line.

[0026] Furthermore: In S4, the zero-sequence overcurrent stage II setting also includes the zero-sequence overcurrent stage II time setting, which is used to coordinate with the zero-sequence overcurrent stage II setting of adjacent lines.

[0027] Furthermore: In S4, the method for calculating the zero-sequence overcurrent stage III setting includes:

[0028] S411. Calculate the zero-sequence current of the relevant fault point, and on the premise of ensuring sufficient sensitivity when there is a fault at the end of the line.

[0029] S412. Based on the constraints of the zero-sequence III-stage current and the zero-sequence current flowing through the 220kV side of the transformer during a ground fault, calculate the zero-sequence overcurrent III-stage setting.

[0030] S413. Convert the zero-sequence III-stage current and the zero-sequence overcurrent III-stage current into named values, and divide them by the zero-sequence current transformer ratio to obtain the zero-sequence overcurrent III-stage setting value.

[0031] Furthermore, in S4, the zero-sequence overcurrent stage III setting also includes the zero-sequence overcurrent stage III time setting, which is used to ensure the selectivity of the zero-sequence overcurrent protection during a fault.

[0032] The beneficial effects of this invention are as follows:

[0033] A primary simulation platform for the power grid was established using a dispatch automation system. The model data was derived from actual power grid parameters, and the system impedance, which is closest to that of the real power grid, was calculated by using fluctuating bus voltage and current, thus improving the accuracy of zero-sequence fault current. At the same time, the settings for the second and third stages of zero-sequence overcurrent protection were obtained by using an expert database model and compared with the settings in the actual protection device, thereby improving accuracy and ensuring the safe and stable operation of the power grid. Attached Figure Description

[0034] Figure 1 The flowchart shows the zero-sequence overcurrent protection verification method based on a power grid primary simulation platform. Detailed Implementation

[0035] The specific embodiments of the present invention are described below to enable those skilled in the art to understand the present invention. However, it should be understood that the present invention is not limited to the scope of the specific embodiments. For those skilled in the art, various changes are obvious as long as they are within the spirit and scope of the present invention as defined and determined by the appended claims. All inventions utilizing the concept of the present invention are protected.

[0036] like Figure 1 As shown, in one embodiment of the present invention, a zero-sequence overcurrent protection verification method based on a power grid primary simulation platform is provided, comprising:

[0037] S1. The dispatch automation system obtains regional power grid flow information and grid parameters, and establishes a primary power grid simulation platform;

[0038] S2. Calculate the equivalent impedance of the system at the bus corresponding to the fault point under small-mode conditions using a power grid primary simulation platform;

[0039] S3. Based on the equivalent impedance of the system at the bus corresponding to the fault point and the power grid operation mode, obtain the zero-sequence current at the relevant fault point;

[0040] S4. Calculate the zero-sequence overcurrent stage II and zero-sequence overcurrent stage III settings based on the zero-sequence current at the relevant fault points.

[0041] S5. Retrieve the zero-sequence overcurrent stage II and zero-sequence overcurrent stage III settings from the actual protection device, and compare them with the calculated zero-sequence overcurrent stage II and zero-sequence overcurrent stage III settings to complete the zero-sequence overcurrent protection verification.

[0042] Specifically, the power flow information and grid parameters in S1 include the generator power, load power, 500kV substation grid connection power, line parameters, and transformer parameters of the regional power system.

[0043] S1 includes:

[0044] S11. Obtain power flow information of a certain region's power grid through the power system dispatch automation system, and obtain the generator power, load power and 500kV substation power supply of the region's power system.

[0045] S12. Obtain the grid parameters of a certain region's power grid through the power system dispatch automation system, and obtain the impedance parameters of all generators, line impedance parameters, and transformer short-circuit impedance parameters of the regional power system.

[0046] S13. Establish a primary simulation platform for the power grid based on the generator power, load power, grid connection power of 500kV substations, and the impedance parameters of all generators, line impedance parameters, and transformer short-circuit impedance parameters of the regional power system.

[0047] Specifically, S2 includes:

[0048] S201, Dispatch automation system, obtains the output power of each generator and the load power of each node corresponding to the minimum annual power grid load;

[0049] S202. Based on the output power of each generator and the load power of each node corresponding to the annual minimum grid load, obtain the normal distribution sample P of each generator at the annual minimum grid load. G (P i ) and the normal distribution sample L(d) of load power at each node i );

[0050] S203. Substitute the normal distribution samples of each generator and the normal distribution samples of each node load power when the annual grid is at its minimum load into the grid primary simulation platform;

[0051] S204. Using the primary power grid simulation platform and the Monte Carlo probabilistic power flow calculation method, we obtain the bus voltage sample set U and the load current sample set I corresponding to the fault point under the normal distribution.

[0052] S205. Based on the bus voltage sample set and load current sample set corresponding to the fault point under normal distribution, calculate the equivalent system impedance Z at the bus corresponding to the fault point under the small mode. S-ym Its expression is:

[0053]

[0054] Where E is the system voltage at the fault point, I is the load current at the 220kV fault point during normal operation, U is the bus voltage at the fault point, and Z is the load current at the fault point. S-ym This represents the equivalent impedance of the system at the bus corresponding to the fault point under the small-mode condition.

[0055] Optionally, after S205, Z S-ym Convert named values ​​to per-unit values.

[0056] Specifically, S3 includes:

[0057] S301. Generate a short-circuit current calculation sequence network diagram based on the equivalent impedance of the system at the bus corresponding to the fault point and the power grid operation mode.

[0058] The short-circuit current calculation sequence network diagram includes positive sequence network, negative sequence network and zero sequence network;

[0059] The positive-sequence network includes the system equivalent impedance, transformer and line positive-sequence impedances, and the positive-sequence composite impedance X. 1∑ =X S-by +X T1 +X L1 The negative-sequence network includes the negative-sequence impedances of transformers and lines, and its negative-sequence combined impedance X 2∑ =X S-by +X T2 +X L2 The zero-sequence network includes the zero-sequence impedance of the transformer and the line, and its zero-sequence combined impedance X 0∑ =XT0 +X L0 ;

[0060] Among them, X S-by For Z S-ym The corresponding system impedance, X T1 X is the positive sequence impedance of the transformer. L1 X is the positive sequence impedance from the fault point to the busbar; T2 X is the negative sequence impedance of the transformer. L2 The negative sequence impedance from the fault point to the busbar; X T0 X is the zero-sequence impedance of the transformer. L0 The zero-sequence impedance from the fault point to the busbar;

[0061] S302. Based on the short-circuit current calculation sequence network diagram and the characteristics of the single-phase ground fault network at the end of the line (i.e., the positive sequence, negative sequence, and zero sequence networks are connected in series), calculate the zero-sequence current value 3I0 during a single-phase ground fault. Its expression is:

[0062]

[0063] S303. Based on the short-circuit current calculation sequence network diagram and the characteristics of the fault network when two phases are grounded at the end of the line (i.e., the negative sequence and zero sequence networks are connected in parallel and then connected to the positive sequence network), calculate the zero sequence current value 3I0′ when two phases are grounded at the end of the line. Its expression is:

[0064]

[0065] S304. Take the smaller of the zero-sequence current value when a single-phase ground fault occurs and the zero-sequence current value when a two-phase ground fault occurs at the end of the line. 0min =min(3I0,3I0′), which is the zero-sequence current at the fault point.

[0066] Specifically, according to the setting calculation principle, in S4, there are three methods for calculating the zero-sequence overcurrent stage II setting:

[0067] Method 1: Calculate the zero-sequence overcurrent stage II setting based on the zero-sequence current at the relevant fault point, and on the premise of ensuring sufficient sensitivity when there is a fault at the end of this line;

[0068] Its expression is:

[0069] I ∏ =3I 0min / K sen

[0070] Among them, I 0min This represents the zero-sequence current value when a fault occurs at the end of the line under the small-mode condition, via K. sen This refers to the sensitivity when a fault occurs at the end of the line.

[0071] To improve the sensitivity of zero-sequence overcurrent protection, it is necessary to determine the minimum fault zero-sequence current. Furthermore, the fault type and operating mode will cause variations in the magnitude of the zero-sequence current; therefore, it is necessary to obtain the minimum zero-sequence current I. 0min .

[0072] Method 2: Based on the coordination relationship between this line and adjacent lines in the zero-sequence overcurrent stage II, calculate the setting value of the zero-sequence overcurrent stage II. The expression is as follows:

[0073] I Π =K k K F I' DZ ∏

[0074] Among them, K k K is the reliability coefficient. F I′ is the maximum branch coefficient. DZ∏ Set the value for the zero-sequence II segment of the adjacent line;

[0075] Method 3: If there is a 220kV transformer on the opposite side of the line, the zero-sequence current I flowing through the line can be obtained through a ground fault on the 220kV side of the transformer. 0T The expression for calculating the zero-sequence segment II current is as follows:

[0076] I ∏ =K k ′·I 0T

[0077] Among them, K k ′ is the reliability coefficient, I 0T This refers to the zero-sequence current flowing through the line due to a ground fault on the 220kV side of the transformer.

[0078] Optionally, the calculated zero-sequence overcurrent stage II setting is converted into a nominal value and divided by the zero-sequence CT ratio to obtain the zero-sequence overcurrent stage II reference setting I. DZII Specifically, it includes:

[0079] S4001. Convert the calculated zero-sequence overcurrent stage II setting value into a named value to obtain the named value I of the zero-sequence stage II current. II ;

[0080] in, V B For the corresponding level of reference voltage, S B Base capacity;

[0081] S4002, Zero-sequence II-stage current nominal value divided by zero-sequence current transformer ratio n CT The reference setting value I for the zero-sequence overcurrent stage II is obtained. DZII .

[0082] Specifically, in S4, the zero-sequence overcurrent stage II setting also includes a zero-sequence overcurrent stage II time setting. The zero-sequence overcurrent stage II time setting is used to coordinate with the zero-sequence overcurrent stage II setting of adjacent lines, and its expression is:

[0083] t ∏ =t lin∏ +Δt

[0084] Among them, t ∏ For zero-sequence overcurrent II, time period t lin∏ The zero-sequence overcurrent stage II setting is used for adjacent lines, and Δt is the time interval.

[0085] Specifically, according to the setting calculation principles, the method for calculating the zero-sequence overcurrent stage III setting in S4 includes:

[0086] S411. Based on the zero-sequence current at the relevant fault point, and on the premise of ensuring sufficient sensitivity when a fault occurs at the end of this line, calculate the per-unit value I of the zero-sequence III segment current. III Its expression is:

[0087] I III =3I 0min / K s ′ en

[0088] S412. Based on the constraints of the zero-sequence III-stage current and the zero-sequence current flowing through the 220kV side of the transformer during a ground fault, calculate the zero-sequence overcurrent III-stage setting.

[0089] In this embodiment, the constraint on the zero-sequence III segment current is that the primary value of the zero-sequence current does not exceed 300A;

[0090] S413. Convert the zero-sequence stage III current and the zero-sequence overcurrent stage III current into named values, and divide them by the zero-sequence current transformer ratio to obtain the zero-sequence overcurrent stage III setting value.

[0091] Specifically, S413 includes:

[0092] S4131. Multiply the per-unit value of the zero-sequence III segment current by the current reference value of the corresponding voltage level to obtain the nominal value of the zero-sequence III segment current, the expression of which is:

[0093] I III =I III-by ·I B

[0094] Among them, I III-by I is the per-unit value of the zero-sequence III segment current. III The zero-sequence III segment current has a named value;

[0095] S4132. Divide the nominal value of the zero-sequence III-stage current by the zero-sequence current transformer ratio n. CT The zero-sequence overcurrent stage III setting value I is obtained. DZIII .

[0096] Specifically, in S4, the zero-sequence overcurrent stage III setting also includes the zero-sequence overcurrent stage III time setting. The zero-sequence overcurrent stage III time setting is used to ensure the selectivity of the zero-sequence overcurrent protection during a fault, and specifically includes:

[0097] To prevent faults from escalating to the main transformer protection, the zero-sequence overcurrent III time setting t is limited. III It should be less than 2.2 seconds;

[0098] To ensure selectivity during faults, the zero-sequence overcurrent III-stage time setting t of this line is... III =t linII +Δt;

[0099] Among them, t linII Set the time value for the second stage of zero-sequence overcurrent in adjacent lines.

[0100] In step S5, dedicated software is used to retrieve the settings of the zero-sequence overcurrent stage II and zero-sequence overcurrent stage III in the actual protection device and compare them with the settings in steps 4 and 5. If the settings obtained in steps 4 and 5 are within the preset range, the system considers the settings of the zero-sequence overcurrent stage II and III to be correct; otherwise, they are judged to be incorrect and require manual confirmation.

[0101] The above embodiments are only used to illustrate the technical solutions of this application, and are not intended to limit them. Although this application has been described in detail with reference to the foregoing embodiments, those skilled in the art should understand that modifications can still be made to the technical solutions described in the foregoing embodiments, or equivalent substitutions can be made to some of the technical features. Such modifications or substitutions do not cause the essence of the corresponding technical solutions to deviate from the spirit and scope of the technical solutions of the embodiments of this application.

Claims

1. A method for verifying zero-sequence overcurrent protection based on a primary power grid simulation platform, characterized in that, include: S1. The dispatch automation system obtains regional power grid flow information and grid parameters, and establishes a primary power grid simulation platform; S2. Using a primary power grid simulation platform, calculate the equivalent impedance of the system at the bus corresponding to the fault point under the small-mode condition, including: S201, Dispatch automation system, obtains the output power of each generator and the load power of each node corresponding to the minimum annual power grid load; S202. Based on the output power of each generator and the load power of each node corresponding to the minimum annual grid load, obtain the normal distribution samples of each generator and the normal distribution samples of each node load power at the minimum annual grid load. S203. Substitute the normal distribution samples of each generator and the normal distribution samples of each node load power when the annual grid is at its minimum load into the grid primary simulation platform; S204. Using the primary power grid simulation platform and the Monte Carlo probabilistic power flow calculation method, obtain the bus voltage sample set and load current sample set corresponding to the fault point under normal distribution. S205. Based on the bus voltage sample set and load current sample set corresponding to the fault point under normal distribution, calculate the equivalent impedance of the system at the bus corresponding to the fault point under small mode. S3. Based on the equivalent impedance of the system at the bus corresponding to the fault point and the power grid operation mode, obtain the relevant zero-sequence current at the fault point, including: S301. Generate a short-circuit current calculation sequence network diagram based on the equivalent impedance of the system at the bus corresponding to the fault point and the power grid operation mode. S302. Based on the short-circuit current calculation sequence network diagram and the characteristics of the single-phase grounding fault network at the end of the line, calculate the zero-sequence current value during single-phase grounding. S303. Based on the short-circuit current calculation sequence network diagram and the characteristics of the fault network when two phases are grounded at the end of the line, calculate the zero-sequence current value when two phases are grounded at the end of the line. S304. Take the smaller of the zero-sequence current value when a single phase is grounded and the zero-sequence current value when two phases are grounded at the end of the line as the zero-sequence current at the fault point. S4. Calculate the zero-sequence overcurrent based on the zero-sequence current at the relevant fault point. Segment setpoint and zero-sequence overcurrent Segment fixed value; Calculate zero-sequence overcurrent There are three methods for setting segment values: Method 1: Calculate the zero-sequence overcurrent based on the zero-sequence current at the relevant fault point, while ensuring sufficient sensitivity in the event of a fault at the end of the line. Segment fixed value; Method 2: Based on the zero-sequence overcurrent of this line and adjacent lines The coordination relationship of segments, calculating zero-sequence overcurrent. Segment fixed value; Method 3: Calculate the zero-sequence overcurrent based on the 220kV transformer on the opposite side of the line. Segment fixed value; Calculate zero-sequence overcurrent Methods for setting segment values ​​include: Based on the zero-sequence current at the relevant fault point, and under the premise of ensuring sufficient sensitivity when there is a fault at the end of the line, calculate the zero-sequence current. III Per-unit value of segment current; According to zero order Constraints and verification of segment current, calculation of zero-sequence current flowing through the 220kV side of the transformer during a ground fault. III Per-unit value of segment current; Zero sequence III Multiplying the per-unit value of the segment current by the current reference value of the corresponding voltage level yields the zero-sequence current. The segment current has a nominal value, and its expression is: in, Zero order Per-unit value of segment current Zero order The segment current has a nominal value; Zero sequence The nominal value of the current segment divided by the zero-sequence current transformer ratio Zero-order overcurrent is obtained Segment value ; S5. Retrieve the zero-sequence overcurrent from the actual protection device. Segment and zero-sequence overcurrent The segment value is set and compared with the calculated zero-sequence overcurrent. Segment setpoint and zero-sequence overcurrent The segment setting value is compared to complete the zero-sequence overcurrent protection verification.

2. The zero-sequence overcurrent protection verification method based on a primary power grid simulation platform according to claim 1, characterized in that, S1 contains regional power grid flow information and grid parameters, including generator power, load power, 500kV substation grid connection power, line parameters, and transformer parameters.

3. The zero-sequence overcurrent protection verification method based on a primary power grid simulation platform according to claim 1, characterized in that, In S4, zero-sequence overcurrent The segment setting also includes zero-sequence overcurrent. Time-limited fixed value, zero-sequence overcurrent The time-limited setting is used to coordinate with the zero-sequence overcurrent of adjacent lines. Segment fixed value.

4. The zero-sequence overcurrent protection verification method based on a primary power grid simulation platform according to claim 1, characterized in that, In S4, zero-sequence overcurrent The segment setting also includes zero-sequence overcurrent. Time-limited fixed value, zero-sequence overcurrent The time-limited setting is used to ensure the selectivity of zero-sequence overcurrent protection during faults.

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