Active power distribution network voltage sag inversion method based on two-dimensional feature joint solution

Abstract

The invention discloses an active power distribution network voltage sag inversion method based on two-dimensional characteristic joint solution. The method comprises the following steps: S1, establishing a voltage-controlled current source equivalent model of an inversion type distributed power supply based on low voltage ride through characteristics; s2, performing iterative calculation according to a fault network superposition principle to obtain fault current and voltage sag amplitudes of the power distribution network; s3, according to the fault current and the voltage sag amplitude obtained in the S2, the voltage sag duration is solved in combination with the action characteristics of the protection device, and two-dimensional characteristic joint solving of a sag event is achieved; and S4, based on the two-dimensional characteristics of the sag event, realizing multi-stage voltage sag inversion in combination with different inversion type distributed power supply off-network time sequences. According to the invention, a voltage sag amplitude-duration two-dimensional feature combined solution and multi-stage voltage sag inversion method is provided, the voltage sag evaluation accuracy of the power distribution network is improved, and a necessary model foundation is laid for follow-up event tracing, diagnosis and treatment.

Description

Technical Field

[0001] The present invention relates to the technical field of power quality, and in particular to a voltage sag inversion method for an active distribution network based on a joint solution of two-dimensional features. Background Art

[0002] The essence of a voltage sag is the voltage drop caused by a sudden large current drawn from the power grid flowing through the system impedance. Voltage sag inversion involves calculating the short-circuit current in the power grid to determine the two-dimensional characteristics of the busbars at different power nodes, namely, the voltage sag amplitude and duration. Currently, various methods have been used to inversely calculate voltage sag amplitude characteristics, including the critical distance method, the fault point method, analytical methods, virtual node methods, and Monte Carlo methods. The critical distance method estimates the voltage sag amplitude based on a voltage distributor model; the fault point method typically selects a certain number of possible fault points in the system, simulates these fault points under various fault conditions, and performs short-circuit calculations to assess the system's voltage sag level; the analytical method calculates the node fault residual voltage to obtain an assessment result; the virtual node method treats all fault points as newly added virtual nodes in the system to obtain the voltage sag characteristic quantity for a fixed PCC node; and the Monte Carlo method can utilize a small amount of system component failure probability information to calculate system voltage sag data for various fault types and multiple protection device parameters, thereby obtaining a system voltage sag probability indicator. However, although the above existing methods can calculate the amplitude characteristics of voltage sag, they all ignore the calculation of duration characteristics, resulting in that the inversion of voltage sag can only obtain amplitude information, resulting in information loss in the inversion results.

[0003] With the large-scale multi-point access of distributed power sources in the distribution network, the distribution characteristics of the fault current in the distribution network are affected by the distributed power generation units. On this basis, the voltage amplitude characteristics and duration characteristics perceived by different nodes in the distribution network are further affected. Existing research on voltage amplitude characteristics often regards the fault equivalent model of the power supply as a constant current source, ignoring the access of distributed power sources and the low voltage ride through (LVRT) requirements of grid-connected inverters. In addition, existing voltage sag assessment methods often only study the characteristic quantity of sag amplitude, assuming that the sag duration follows a probability distribution, ignoring the influence of short-circuit current on the duration and its correlation with the sag amplitude.

[0004] In summary, existing methods often treat the two-dimensional characteristics of voltage sag as independent and lack a joint calculation of them, resulting in a need to improve the accuracy of existing voltage sag inversion results. Furthermore, existing characterization methods are only applicable to "single-stage" voltage sag events. With the large-scale integration of distributed generation into active distribution networks, differences in their low voltage ride-through characteristics can cause some units to disconnect from the grid during a voltage sag, triggering changes in fault current and voltage distribution, ultimately leading to the sequential disconnection of multiple units and the generation of multi-stage voltage sag events. However, there is currently a lack of systematic feature calculation methods for these types of voltage sag events. Summary of the Invention

[0005] In order to solve the problems that the existing voltage sag inversion method does not jointly solve the voltage amplitude and duration, and is only applicable to single-stage voltage sag events, resulting in low voltage sag inversion accuracy, the present invention proposes an active distribution network voltage sag inversion method with a joint solution of two-dimensional features. The above problems are solved by jointly solving the two-dimensional features of voltage sag amplitude and duration and a multi-stage voltage sag inversion method.

[0006] The present application discloses a method for inverting voltage sag in an active distribution network based on a joint solution of two-dimensional features, comprising the following steps:

[0007] S1. Establish a voltage-controlled current source equivalent model of the inverter-type distributed power supply based on the low voltage ride-through characteristics;

[0008] S2. Iteratively calculate the fault current and voltage sag amplitude of the distribution network according to the fault network superposition principle;

[0009] S3. Based on the fault current and voltage sag amplitude obtained in S2, the voltage sag duration is solved in combination with the operating characteristics of the protection device to achieve a joint solution of the two-dimensional characteristics of the sag event;

[0010] S4. Based on the two-dimensional characteristics of the sag event and combined with the off-grid timing of different inverter-type distributed power sources, multi-stage voltage sag inversion is achieved.

[0011] Preferably, the low voltage ride-through characteristic satisfies:

[0012]

[0013] All quantities in the formula are per unit values. is the positive sequence active current, is the positive sequence reactive current, is the positive sequence voltage amplitude of the power grid after the voltage drop, K q is the reactive power compensation coefficient, I max is the maximum fault current value of the inverter type distributed power converter, i d0 It is the current value of the inverter distributed power supply before the fault.

[0014] Preferably, said S2 comprises the following steps:

[0015] Utilizing the principle of fault analysis superposition, the multi-inverter distributed generation fault network is decomposed into normal operating and fault component networks. The fault component network only receives short-circuit node current injection. Each inverter distributed generation injects short-circuit current into the normal network as a voltage-controlled current source, influencing the short-circuit node current through the normal network voltage. By iteratively calculating the initial current, normal positive and negative sequence node voltages, the short-circuit composite sequence network, the fault point current, the node voltage fault component, and the power reference value, a short-circuit current value that meets the accuracy requirements is obtained. This allows for the calculation of a high-precision sag amplitude.

[0016] S21, set the number of iterations to k, the initial number of iterations to k = 0, set the convergence threshold ε, and initialize the injection current of the inverter distributed power supply is the current value before the fault;

[0017] S22. Based on the symmetrical component method, the unbalanced system is converted into a positive sequence network, a negative sequence network, and a zero sequence network, and the node admittance matrix Y is constructed. The node voltage equation of the positive sequence network can be expressed as:

[0018] YU′=I; (4)

[0019] Among them, U′=[U′ 1 ,U′ 2 ,U′ 0 ] T Represents the sequence voltage vector in a normal network, I=[I 1 ,I 2 ,I 0 ] sequence current vector, superscript 1 represents a positive sequence, superscript 2 represents a negative sequence, and superscript 0 represents a zero sequence;

[0020] S23, calculating the sequence voltage vector U′ in the normal network by triangular decomposition method;

[0021] S24. Calculate the sequence current I at the fault point f :

[0022]

[0023] Among them, Z f is the sequence impedance matrix of the fault point, E is the voltage source at the fault point, U′ f is the sequence voltage of the normal network at the fault point;

[0024] S25, sequence current I based on fault point f Determine the sequence voltage in the fault component network:

[0025] ΔU=Z×(-I f ); (11)

[0026] Where Z is the sequence equivalent impedance matrix associated with the fault point f;

[0027] According to the superposition principle, the voltage amplitude of each node is calculated as follows:

[0028] U=U′+ΔU; (12)

[0029] According to the current iteration voltage U, the injection current of the inverter-type distributed power supply is updated through the low voltage ride-through control strategy

[0030] S26. Calculate the maximum absolute difference between the current iteration voltage and the previous iteration voltage:

[0031] ΔU max =max|U (k+1) -U (k) |; (13)

[0032] If ΔU max <ε, the iteration is terminated; otherwise, it returns to S22 and continues iterative calculation until a short-circuit current value that meets the accuracy requirement is obtained, and then the node voltage sag amplitude is obtained by formula (4).

[0033] Preferably, the S23 includes the following steps:

[0034] Decompose the admittance matrix Y into the product of the upper and lower triangular matrices, namely:

[0035] Y=LW; (5)

[0036] Where L is an upper triangular matrix and W is a lower triangular matrix;

[0037] Introducing the intermediate variable x, we have:

[0038] Lx=I; (6)

[0039] in,

[0040] After obtaining the intermediate variable x, perform reverse substitution to calculate the sequence voltage vector U′ in the normal network:

[0041] WU′=x; (7)

[0042] in,

[0043] Preferably, the action characteristics of the protection device include stage current protection and inverse time overcurrent protection.

[0044] Preferably, the steps for solving the voltage sag duration of the staged current protection are as follows:

[0045] The time when the sag event occurs is recorded as T initial .

[0046] The branch short-circuit current I is calculated using the following formula:

[0047] YU=I; (14)

[0048] Wherein, U is the node voltage when the short-circuit current value that meets the accuracy requirements is obtained;

[0049] Assume that the setting value of main protection current is I pp , the backup protection current setting value is I backup When I≥I pp When the main protection is in action, the fault is removed under normal circumstances, and the voltage sag duration D satisfies the relationship D=T pp -T initial When the main protection at one or both ends of the line fails to operate, the backup protection operates and the voltage sag duration D satisfies the relationship D=T backup -T initial , T backup The variable r is introduced. When the main protection is in normal operation, r=0; when the main protection at one or both ends of the line fails to operate and the backup protection operates, r=1. pp >I≥I backup When the main protection does not operate, the backup protection operates, and the voltage sag duration D satisfies the relationship D=T backup -T initial I backup When >I, it means that there is no fault point on this line and the fault occurs in other lines. In summary, the calculation formula for the voltage sag duration of the stage current protection is as follows:

[0050]

[0051] Among them, T pp The main protection triggering moment, T initial is the time when the voltage sag event occurs, T backup is the backup protection triggering moment, r is the introduced variable, I pp Main protection current setting value, I backup It is the backup protection current setting value.

[0052] Preferably, the steps for solving the voltage sag duration of the inverse time overcurrent protection are as follows:

[0053] The time when the sag event occurs is recorded as T initial .

[0054] The branch short-circuit current I is calculated using the formula YU=I.

[0055] Solution for voltage sag duration D: When I p When , the protection does not start;

[0056] When I>I p When , the voltage sag duration of the inverse time overcurrent protection is:

[0057] D=min(t,T backup -T initial ); (17)

[0058] Among them, t is the protection action time, T backup This is the backup protection triggering moment.

[0059] Preferably, said S4 comprises the following steps:

[0060] S41. Calculate and record the voltage U of the distributed power supply node that is not disconnected from the grid. IIDG , and the inverter type distributed power supply limit voltage U lim For comparison, if U IIDG lim , it is marked as a unit to be disconnected from the grid;

[0061] S42, record the node terminal voltage of the sth unit to be disconnected as U IIDG_s , and calculate the expected off-grid time T of the sth unit to be off-grid trip_s ;

[0062] S43, record the estimated off-grid time of all units to be off-grid in T trip and obtain the minimum expected offline time T by comparison trip_min ;

[0063] S44, the minimum expected offline time T trip_min The current of the corresponding unit and the affected forced trip unit is set to zero, and S42-S43 is repeated;

[0064] S45. Record the information of all affected forced trip units during the iteration process, as well as the voltage drop conditions and corresponding durations after the units trip at different stages, and output a multi-stage sag two-dimensional feature array C containing the voltage sag amplitude and duration. i :

[0065] C i ={(U1,D1),(U2,D2),…,(U k ,D k )}; (twenty two)

[0066] Among them, U k ​​is the voltage sag amplitude in the kth stage, D k is the duration of the voltage sag in the kth stage.

[0067] Preferably, the calculation formula for the inverter-type distributed power supply limit voltage is as follows:

[0068]

[0069] Among them, U max is the maximum voltage on the curve, U min is the minimum voltage on the curve, T max T is the longest time corresponding to the maximum voltage on the curve. min is the shortest time corresponding to the minimum voltage on the curve.

[0070] Preferably, the calculation formula for the expected off-grid time of the sth unit to be off-grid is as follows:

[0071]

[0072] Among them, U IIDG_s is the node terminal voltage of the sth unit to be disconnected from the grid.

[0073] Beneficial effects of the present invention:

[0074] 1. The present invention proposes for the first time a method for jointly solving the two-dimensional characteristics of voltage sag amplitude and duration, which solves the problem of decreased accuracy caused by the traditional method assuming that the two-dimensional features are independent of each other.

[0075] 2. The present invention proposes a multi-stage voltage sag inversion method, which solves the problem that the traditional method can only be applied to single-stage voltage sag events.

[0076] 3. This invention accurately reflects the impact of off-grid events on the power grid, improves the accuracy of distribution network voltage sag assessment, and lays the necessary model foundation for subsequent event tracing, diagnosis and management. BRIEF DESCRIPTION OF THE DRAWINGS

[0077] Figure 1 This is a flow chart of a method for inverting voltage sag in an active distribution network based on a joint solution of two-dimensional features according to an embodiment of the present invention.

[0078] Figure 2 FIG. 1 is a schematic diagram of a three-phase PV inverter connected to a power grid according to an embodiment of the present invention.

[0079] Figure 3 This is the IIDG equivalent model during a fault in an embodiment of the present invention.

[0080] Figure 4 1 is a schematic diagram of the LVRT curve of the IIDG and the IIDG off-grid timing during a fault according to an embodiment of the present invention. DETAILED DESCRIPTION

[0081] In order to make the objectives, technical solutions and advantages of this application more clear, the application is further described in detail below with reference to the accompanying drawings and examples.

[0082] The embodiment of the present invention discloses a method for inverting voltage sag in active distribution network based on joint solution of two-dimensional features, the specific process of which is as follows: Figure 1 As shown. The embodiments of the present invention propose for the first time a joint solution for the two-dimensional characteristics of voltage sag amplitude and duration, addressing the problem of decreased accuracy caused by traditional methods assuming that the two-dimensional features are independent of each other. Existing voltage sag assessment methods often only study the characteristic quantity of the sag amplitude, assuming that the sag duration follows a probability distribution, ignoring the coupled relationship between duration, voltage sag amplitude, and fault current. In fact, the duration of a voltage sag event is generally determined by the duration of the power system fault, which in turn depends on the operating time of the protection device and the operation time of the circuit breaker (i.e., the protection operation time). Since overcurrent protection is commonly used in distribution networks, the duration of the sag event is affected by the short-circuit current value. In addition, the connection of distributed power sources changes the fault current distribution characteristics, increasing the risk of the protection device not operating correctly, which in turn changes the duration of the fault. Existing methods often treat different voltage sag characteristics as independent, only studying a single characteristic, and lack a joint solution for the two-dimensional characteristics of the voltage sag event. As a result, the accuracy of existing voltage sag assessment results needs to be improved.

[0083] At the same time, the embodiment of the present invention also proposes a multi-stage voltage sag inversion method, which solves the problem that traditional methods can only be applied to single-stage voltage sag events. With the large-scale decentralized access of distributed power sources in the active distribution network, the low voltage ride-through capabilities of different units are different, and the grid connection point voltage is also different during faults. As a result, some units may be disconnected from the grid during the sag process, causing the sag event to evolve in multiple stages. However, traditional sag analysis methods do not take into account the changes in the grid connection status of new energy units, and the inversion results cannot reflect the actual system.

[0084] S1. A voltage-controlled current source equivalent model of an inverter-interfaced distributed generator (IIDG) is established based on the low voltage ride-through (LVRT) characteristics. During a fault, the IIDG outputs a fault current coupled to the grid connection point voltage according to the low voltage ride-through (LVRT) control strategy. The IIDG location is determined based on its actual system location, and the total number of IIDG nodes depends on the actual system. Faults are randomly generated, resulting in voltage sag events.

[0085] Inverter-type distributed power sources are connected to the grid through a grid-connected inverter. During normal operation, the inverter is configured to explicitly provide a specific amount of active power to the grid. Taking a photovoltaic (PV) system as an example, the basic diagram of connecting to the grid through a three-phase three-wire inverter is as follows: Figure 2 shown.

[0086] Figure 2 C in the figure represents the photovoltaic DC voltage stabilizing capacitor, U dc is the voltage across its two ends, R and L are the equivalent impedances of the line between the inverter and the grid; i(i a 、i b 、i c ) is the three-phase current, e(e a 、e b 、e c ) is the three-phase voltage on the grid side; dq / abc is the coordinate system transformation, which converts i and e from the three-phase coordinate system to the dq coordinate system, that is, i d 、i q 、e d 、e q ; P and Q are active and reactive power respectively.

[0087] During voltage drops, IIDGs must help support the terminal voltage to avoid disconnection. When the positive sequence voltage at the grid connection point drops below 90%, according to LVRT requirements, during the grid fault, the positive sequence active current is reduced according to the voltage drop amplitude. and reactive current Perform adaptive adjustments, namely:

[0088]

[0089] All quantities in the formula are per unit values. is the positive sequence voltage amplitude of the power grid after the voltage drop, K q is the reactive power compensation coefficient, I max is the maximum fault current value of the IIDGs converter, i d0 is the current value before the IIDGs fault. In order to issue the maximum allowable active power without overcurrent in the inverter, the active current command Take i d0 and The smaller value between .

[0090] Under asymmetrical fault conditions, the corresponding fault current reference value can be calculated as:

[0091]

[0092] Among them, p0 is the average active power, q0 is the average reactive power, p c2is the cosine component of the active power oscillation, p s2 The reference value of the positive and negative sequence components of the current can be calculated based on the goal of eliminating active power oscillation under asymmetrical faults. c2 and p s2 Should be set to 0. and e represents the grid-side voltage, i represents the grid-side current, the superscript + represents the positive sequence, the superscript - represents the negative sequence, the subscript d represents the component of the dq decomposition method on the d-axis, and the subscript q represents the component of the dq decomposition method on the q-axis. and The reference value can be generated according to the severity of the voltage sag and the inverter current limit.

[0093] Therefore, the positive sequence fault current and negative sequence fault current can be calculated as:

[0094]

[0095] in, is the positive sequence fault current, is the negative sequence fault current.

[0096] Since the IIDG fault current is coupled with the corresponding terminal voltage, the fault equivalent model of the IIDG must be configured as a voltage-controlled current source in the positive-sequence or negative-sequence network, such as Figure 3 As shown in Figure 2. U represents the voltage across IIDG, and I represents the output current of the current source.

[0097] S2. According to the fault network superposition principle, the fault current and voltage sag amplitude of the distribution network are obtained by iterative calculation.

[0098] Utilizing the principle of fault analysis superposition, the fault network of multiple inverter-type distributed generation (IIDGs) is decomposed into normal operating and fault component networks. The fault component network only receives short-circuit node current. Each IIDG, acting as a voltage-controlled current source, injects short-circuit current into the normal network, influencing the short-circuit node current through the normal network voltage. By iteratively calculating the initial current, normal positive and negative sequence node voltages, the short-circuit composite sequence network, the fault point current, the node voltage fault component, and the power reference value, a short-circuit current value meeting the accuracy requirements is obtained. This allows for the calculation of the sag amplitude with high precision.

[0099] The specific steps are as follows:

[0100] S21, set the number of iterations to k, the initial number of iterations to k = 0, set the convergence threshold ε (in this embodiment, 10 -6 ), initialize the injection current of the inverter-type distributed power supply is the current value before the fault.

[0101] S22. Based on the symmetrical component method, the unbalanced system is converted into a positive sequence network, a negative sequence network, and a zero sequence network. The node admittance matrix Y (including each sequence component) is constructed. The node voltage equation of the positive sequence network can be expressed as:

[0102] YU′=I; (4)

[0103] Among them, U′=[U′ 1 ,U′ 2 ,U′ 0 ] T Represents the sequence voltage vector in a normal network, I=[I 1 ,I 2 ,I 0 ] sequence current vector, superscript 1 represents a positive sequence, superscript 2 represents a negative sequence, and superscript 0 represents a zero sequence.

[0104] S23. Calculate the sequence voltage vector U′ in the normal network by using the triangular decomposition method.

[0105] Decompose the admittance matrix Y into the product of the upper and lower triangular matrices, namely:

[0106] Y=LW; (5)

[0107] Where L is an upper triangular matrix and W is a lower triangular matrix.

[0108] Introducing the intermediate variable x, we have:

[0109] Lx=I; (6)

[0110] in, The subscripts i and j are used to distinguish different elements in the matrix.

[0111] After obtaining the intermediate variable x, perform reverse substitution to calculate the sequence voltage vector U′ in the normal network:

[0112] WU′=x; (7)

[0113] in,

[0114] S24. Calculate the sequence current I at the fault point based on the fault boundary conditions and the Thevenin equivalent circuit. f :

[0115]

[0116] Among them, Z f is the sequence impedance matrix of the fault point, E is the voltage source at the fault point, U′ f is the sequence voltage of the normal network at the fault point.

[0117] The sequence equivalent impedance matrix z associated with the fault point f can be obtained as follows:

[0118]

[0119] Where Z i is the impedance matrix associated with node i, expressed as:

[0120]

[0121] The process of solving the matrix z is similar to the process of solving the expression of U′. Introduce the intermediate variable m to satisfy the following equation:

[0122]

[0123] Where,

[0124] After solving for the variable m, perform reverse substitution and solve the equivalent impedance matrix Z using the following formula:

[0125] WZ=m;

[0126] Where,

[0127] S25. Calculate the sequence current I at the fault point f After that, the sequence voltage in the fault component network can be determined as follows:

[0128] ΔU=Z×(-I f ); (11)

[0129] According to the superposition principle, the voltage amplitude of each node is calculated as follows:

[0130] U=U′+ΔU; (12)

[0131] According to the current iteration voltage U, the injection current of the inverter-type distributed power supply is updated through the low voltage ride-through control strategy

[0132] S26. Calculate the maximum absolute difference between the current iteration voltage and the previous iteration voltage:

[0133] ΔU max =max|U (k+1) -U (k) |; (13)

[0134] If ΔU max <ε, the iteration is terminated, otherwise it returns to S22 to continue the iteration, and the iterative calculation is performed until the accuracy requirement (ΔU max <ε) short-circuit current value (sequence current I f), and then the node voltage sag amplitude (sequence voltage vector U′ in a normal network) is obtained through equation (4).

[0135] S3: Voltage sag duration estimation method considering the impact of IIDG access. Based on the fault current and voltage sag amplitude obtained in S2, combined with the operating characteristics of the protection device, the voltage sag duration is solved, achieving a joint solution of the two-dimensional characteristics of the sag event.

[0136] In distribution networks, the duration of voltage sags is closely related to the operating characteristics of protective devices. Traditional voltage sag assessment methods typically assume a fixed protection operating time, ignoring the impact of the protective device's operating time characteristics on the sag duration, resulting in insufficient assessment accuracy. Common protections used in distribution networks include step-by-step current protection and inverse time overcurrent protection. The relationship between voltage sag duration and fault current varies depending on the operating time characteristics of each type of protection. Protective device operating characteristics include step-by-step current protection and inverse time overcurrent protection.

[0137] When solving the voltage sag duration of staged current protection, instantaneous current quick-break, time-limited current quick-break, and overcurrent protection are all protection devices that operate when the current exceeds the limit. In order to ensure that the fault is selectively removed, the above protections are often combined to form staged current protection. In practical applications, two-level protection is usually adopted, such as instantaneous current quick-break plus overcurrent protection, or time-limited current quick-break plus overcurrent protection. The instantaneous current quick-break or time-limited current quick-break that is triggered first is used as the main protection of the line, and the triggering time is recorded as T pp The time-limited overcurrent protection has the largest protection range because its setting current is the maximum load current. It acts as a backup protection when the main protection fails to operate. The triggering time is recorded as T backup .

[0138] The steps for calculating the voltage sag duration of the staged current protection are as follows:

[0139] The time when the sag event occurs is recorded as T initial .

[0140] The branch short-circuit current I is calculated using the following formula:

[0141] YU=I; (14)

[0142] Wherein, U is the node voltage when the short-circuit current value that meets the accuracy requirement is obtained.

[0143] Assume that the setting value of main protection current is I pp , the backup protection current setting value is I backup When I≥I pp When the main protection is in action, the fault is removed under normal circumstances, and the voltage sag duration D satisfies the relationship D=Tpp -T initial When the main protection at one or both ends of the line fails to operate, the backup protection operates and the voltage sag duration D satisfies the relationship D=T backup -T initial , T backup The variable r is introduced. When the main protection is in normal operation, r=0; when the main protection at one or both ends of the line fails to operate and the backup protection operates, r=1. pp >I≥I backup When the main protection does not operate, the backup protection operates, and the voltage sag duration D satisfies the relationship D=T backup -T initial I backup When >I, it means that there is no fault point on this line and the fault occurs in other lines. In summary, the calculation formula for the voltage sag duration of the stage current protection is as follows:

[0144]

[0145] When solving the voltage sag duration of the inverse time overcurrent protection, it is considered that the inverse time overcurrent protection of the distribution network has the characteristic of "short action time when the current is large and long action time when the current is small", and its action time is negatively correlated with the fault current. The action characteristics of the inverse time overcurrent protection are combined with the voltage sag duration to improve the evaluation accuracy.

[0146] According to the IEEE C37.112-2018 standard, the inverse time overcurrent protection action characteristic equation is:

[0147]

[0148] Among them, I p is the starting current setting value, which is 1.2×I rated , I rated is the rated current of the line, t is the protection action time, I is the fault current measurement value, TMS is the time multiplier, α is a constant, and in this embodiment, the value α=0.02.

[0149] The steps to solve the voltage sag duration of inverse time overcurrent protection are as follows:

[0150] The time when the sag event occurs is recorded as T initial .

[0151] The branch short-circuit current i is calculated using the formula YU=i.

[0152] Solution for voltage sag duration D: When i p When , the protection does not start;

[0153] When I>I​p When , the voltage sag duration of the inverse time overcurrent protection is:

[0154] D=min(t,T backup -T initial ); (17)

[0155] Among them, t is the protection action time, T backup This is the backup protection triggering moment.

[0156] S4. Based on the two-dimensional characteristics of the sag event and combined with the off-grid timing of different inverter-type distributed power sources, multi-stage voltage sag inversion is achieved.

[0157] like Figure 4 As shown in the figure, according to the LVRT characteristics of IIDG, different types of low voltage ride-through curve parameters are set. clear is the clearing time corresponding to the limit voltage.

[0158] Substitute the voltage sag duration D into the curve equation to calculate the limit voltage U of each IIDG lim Terminal voltage U IIDG lim It is marked as a unit to be disconnected from the grid.

[0159]

[0160] Among them, U max is the maximum voltage on the curve, U mim is the minimum voltage on the curve, T max T is the longest time corresponding to the maximum voltage on the curve. min is the shortest time corresponding to the minimum voltage on the curve.

[0161] The specific steps are as follows:

[0162] S41. Calculate and record the voltage U of the distributed power supply node that is not disconnected from the grid. IIDG , and the inverter type distributed power supply limit voltage U lim For comparison, if U IIDG lim , it is marked as a unit to be disconnected from the grid.

[0163] S42, record the node terminal voltage of the sth unit to be disconnected as U IIDG_s , and calculate the expected off-grid time T of the sth unit to be off-grid trip_s :

[0164]

[0165] S43, record the estimated off-grid time of all units to be off-grid in T trip :​​

[0166] T trip =[T trip_1 ,T trip_2 ,……,T trip_s ,……]; (20)

[0167] Compare and get the minimum expected offline time T trip_min ;

[0168] T trip_min =min(T trip ); (twenty one)

[0169] S44, the minimum expected offline time T trip_min The current of the corresponding unit and the affected forced trip unit is set to zero, and S42-S43 are repeated.

[0170] S45. Record the information of all affected forced trip units during the iteration process, as well as the voltage drop conditions and corresponding durations after the units trip at different stages, and output a multi-stage sag two-dimensional feature array C containing the voltage sag amplitude and duration. i :

[0171] C i ={(U1,D1),(U2,D2),…,(U k ,D k )}; (twenty two)

[0172] Among them, U k is the voltage sag amplitude in the kth stage, D k is the duration of the voltage sag in the kth stage.

[0173] In summary, based on the low voltage ride-through characteristics of distributed power sources, a voltage-controlled current source model of an inverter-type distributed power source is constructed, and a high-precision distribution network fault current is obtained by iterative calculation. While calculating the sag amplitude, the duration of the sag event is estimated in combination with the protective device action characteristic equation, thereby achieving a joint solution of the two-dimensional characteristics of the sag event. On this basis, by estimating the off-grid timing of different inverter-type distributed power sources, the off-grid sequence of the inverter-type distributed power sources and the voltage distribution of the power grid after off-grid are obtained, and then the multi-stage voltage sag characteristics are obtained, and multi-stage voltage sag inversion is achieved. The solution proposed in this application accurately reflects the impact of off-grid events on the power grid, improves the accuracy of distribution network voltage sag assessment, and lays the necessary model foundation for subsequent event tracing, diagnosis, and governance.

[0174] The basic principles, main features, and advantages of the present invention are shown and described above. Those skilled in the art should understand that the present invention is not limited to the above embodiments. The above embodiments and descriptions are merely illustrative of the principles of the present invention. Various changes and modifications may be made to the present invention without departing from the spirit and scope of the present invention. Such changes and modifications are intended to fall within the scope of the present invention. The scope of protection claimed in the present invention is defined by the appended claims and their equivalents.

Claims

1. A voltage sag inversion method for active distribution network based on two-dimensional feature joint solution, characterized in that: The following steps are involved: S1. Establish a voltage-controlled current source equivalent model of the inverter-type distributed power supply based on the low voltage ride-through characteristics; S2. Iteratively calculate the fault current and voltage sag amplitude of the distribution network according to the fault network superposition principle; S3. Based on the fault current and voltage sag amplitude obtained in S2, the voltage sag duration is solved in combination with the operating characteristics of the protection device to achieve a joint solution of the two-dimensional characteristics of the sag event; S4. Based on the two-dimensional characteristics of the sag event and combined with the off-grid timing of different inverter-type distributed power sources, multi-stage voltage sag inversion is achieved.

2. The method for inverting voltage sag in active distribution network based on joint solution of two-dimensional features according to claim 1 is characterized in that: The low voltage ride-through characteristics meet the following requirements: All quantities in the formula are per unit values. is the positive sequence active current, is the positive sequence reactive current, is the positive sequence voltage amplitude of the power grid after the voltage drop, K q is the reactive power compensation coefficient, I max is the maximum fault current value of the inverter type distributed power converter, i d0 It is the current value of the inverter distributed power supply before the fault.

3. The method for inverting voltage sag in active distribution network based on joint solution of two-dimensional features according to claim 2 is characterized in that: The S2 comprises the following steps: S21, set the number of iterations to k, the initial number of iterations to k = 0, set the convergence threshold ε, and initialize the injection current of the inverter distributed power supply is the current value before the fault; S22. Based on the symmetrical component method, the unbalanced system is converted into a positive sequence network, a negative sequence network, and a zero sequence network, and the node admittance matrix Y is constructed. The node voltage equation of the positive component network sequence can be expressed as: YU′=I; (4) Among them, U′=[U′ 1 ,U′ 2 ,U′ 0 ] T Represents the sequence voltage vector in a normal network, I=[I 1 ,I 2 ,I 0 ] sequence current vector, superscript 1 represents a positive sequence, superscript 2 represents a negative sequence, and superscript 0 represents a zero sequence; S23, calculating the sequence voltage vector U′ in the normal network by triangular decomposition method; S24. Calculate the sequence current I at the fault point f : Among them, Z f is the sequence impedance matrix of the fault point, E is the voltage source at the fault point, U′ f is the sequence voltage of the normal network at the fault point; S25, sequence current I based on fault point f Determine the sequence voltage in the fault component network: ΔU=Z×(-I f ); (11) Where Z is the sequence equivalent impedance matrix associated with the fault point f; According to the superposition principle, the voltage amplitude of each node is calculated as follows: U=U′+ΔU; (12) According to the current iteration voltage U, the injection current of the inverter-type distributed power supply is updated through the low voltage ride-through control strategy S26. Calculate the maximum absolute difference between the current iteration voltage and the previous iteration voltage: ΔU max =max|U (k+1) -U (k) |; (13) If ΔU max <ε, the iteration is terminated; otherwise, it returns to S22 and continues iterative calculation until a short-circuit current value that meets the accuracy requirement is obtained, and then the node voltage sag amplitude is obtained by formula (4).

4. The method for inverting voltage sag in active distribution network based on joint solution of two-dimensional features according to claim 3 is characterized in that: The S23 includes the following steps: Decompose the admittance matrix Y into the product of the upper and lower triangular matrices, namely: Y=LW; (5) Where L is an upper triangular matrix and W is a lower triangular matrix; Introducing the intermediate variable x, we have: Lx=I; (6) in, After obtaining the intermediate variable x, perform reverse substitution to calculate the sequence voltage vector U′ in the normal network: WU′=x; (7) in, 5. The method for inverting voltage sag in active distribution network based on joint solution of two-dimensional features according to claim 4 is characterized in that: The operating characteristics of the protection device include stage current protection and inverse time overcurrent protection.

6. The method for inverting voltage sag in active distribution network based on joint solution of two-dimensional features according to claim 5 is characterized in that: The voltage sag duration of the staged current protection is as follows: Among them, T pp The main protection triggering moment, T initial is the time when the voltage sag event occurs, T backup is the backup protection triggering moment, r is the introduced variable, I pp Main protection current setting value, I backup It is the backup protection current setting value.

7. The method for inverting voltage sag in active distribution network based on joint solution of two-dimensional features according to claim 6 is characterized in that: The voltage sag duration of the inverse time overcurrent protection is as follows: Let I p is the starting current setting value, when I p When , the protection does not start;​ When I>I p When , the voltage sag duration of the inverse time overcurrent protection is: D=min(t,T backup -T initial ); (17) Among them, t is the protection action time, T backup This is the backup protection triggering moment.

8. The method for inverting voltage sag in active distribution network based on joint solution of two-dimensional features according to claim 7 is characterized in that: The S4 comprises the following steps: S41. Calculate and record the voltage U of the distributed power supply node that is not disconnected from the grid. IIDG , and the inverter type distributed power supply limit voltage U lim For comparison, if U IIDG lim , it is marked as a unit to be disconnected from the grid;​ S42, record the node terminal voltage of the sth unit to be disconnected as U IIDG_s , and calculate the expected off-grid time T of the sth unit to be off-grid trip_s ; S43, record the estimated off-grid time of all units to be off-grid in T trip and obtain the minimum expected offline time T by comparison trip_min ; S44, the minimum expected offline time T trip_min The current of the corresponding unit and the affected forced trip unit is set to zero, and S42-S43 is repeated; S45. Record the information of all affected forced trip units during the iteration process, as well as the voltage drop conditions and corresponding durations after the units trip at different stages, and output a multi-stage sag two-dimensional feature array C containing the voltage sag amplitude and duration. i : C i ={(U1,D1),(U2,D2),…,(U k ,D k )}; (twenty two) Among them, U k is the voltage sag amplitude in the kth stage, D k is the duration of the voltage sag in the kth stage.

9. The method for inverting voltage sag in active distribution network based on joint solution of two-dimensional features according to claim 8, characterized in that: The calculation formula for the inverter type distributed power supply limit voltage is as follows: Among them, U max is the maximum voltage on the curve, U min is the minimum voltage on the curve, T max T is the longest time corresponding to the maximum voltage on the curve. min is the shortest time corresponding to the minimum voltage on the curve.

10. The method for inverting voltage sag in active distribution network based on joint solution of two-dimensional features according to claim 9, characterized in that: The calculation formula for the estimated off-grid time of the sth unit to be off-grid is as follows: Among them, U IIDG_s is the node terminal voltage of the sth unit to be disconnected from the grid.

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