A single-phase fault handling and island detection system and method

Abstract

The present invention relates to a single-phase fault handling and islanding detection system and method. The method determines whether a single-phase fault occurs in a power grid, and identifies the fault phase and fault type when a single-phase fault is determined to have occurred. Different arc extinguishing paths are selected according to different single-phase fault types, thereby effectively handling the single-phase fault in the power grid. At the same time, the specific line and section where the single-phase fault occurs are determined based on the zero-sequence admittance of each feeder, and the faulty line or section is then isolated, and islanding detection is initiated, thereby integrating the single-phase fault handling technology and the islanding detection technology. Through a set of solutions, the problems of single-phase fault handling and islanding detection are simultaneously solved, providing an effective solution to the long-standing problems of single-phase fault protection and islanding detection in the power grid.

Description

Technical Field

[0001] The present invention relates to the technical field of smart grids, and in particular to a single-phase fault handling and islanding detection system and method. Background Art

[0002] Under the dual carbon goals of "carbon peak and carbon neutrality," renewable energy (primarily photovoltaic and wind power) will gradually replace traditional energy sources and potentially account for over 50% of the total power generation in the future. This will necessitate the integration of a large number of renewable energy microgrids into the traditional power grid. Traditional power systems, primarily based on thermal power, are characterized by stable power output, known in the industry as inertial systems. However, renewable energy sources, affected by the fluctuations of sunlight and wind power, exhibit intermittent or unstable output. Integrating these two power grids requires innovative technologies, a hot research topic both domestically and internationally.

[0003] Among them, single-phase fault handling and island identification technology are two key technologies related to the power supply reliability and safety of new power systems.

[0004] Single-phase faults account for over 80% of distribution network faults, with non-disconnected grounding faults being the most common. Other common faults include disconnected non-grounding faults, disconnected power supply side grounding faults, and disconnected load side grounding faults. Solving the single-phase fault problem significantly reduces the risk of large-scale power outages. It also addresses urgent practical needs such as grassland and forest fires and personal electric shock accidents. The former affects power supply reliability, while the latter affects power supply safety.

[0005] There are several problems with existing ground fault handling technologies:

[0006] Power supply reliability and safety cannot be achieved at the same time;

[0007] The fault detection sensitivity is insufficient, and a large number of faults are in the detection blind zone and cannot be identified;

[0008] No fault type identification (non-disconnection grounding fault, disconnection non-grounding fault, disconnection power supply side grounding fault and disconnection load side grounding fault): The main fault type is non-disconnection grounding fault, and other common faults include disconnection non-grounding fault, disconnection power supply side grounding fault and disconnection load side grounding fault;

[0009] The effect of eliminating the grounding residual current (arc extinguishing) is poor. The grounding point current usually manifests as high-energy arc light, which is the direct cause of electric shock to people and fires in grasslands and forests.

[0010] The reliability of fault line / section positioning is insufficient. For low-resistance grounding faults, existing technologies can basically meet the line selection and positioning requirements. For high-resistance faults above 1000 ohms, the accuracy of line selection and positioning of traditional technologies is significantly reduced, and false alarms and misjudgments occur frequently. This is also one of the international challenges in the current industry.

[0011] Islanding effect refers to the situation when a large power grid line carrying a new energy microgrid is disconnected from the busbar for some reason (such as line failure or maintenance). One or more microgrids connected to the disconnected line cannot detect that the upstream is off-grid and therefore fail to trigger the corresponding protection device action, resulting in an island state where the microgrids continue to operate independently with the related loads.

[0012] The purpose of islanding detection is to ensure the safety of power grid equipment, user equipment, and line maintenance personnel. This is because:

[0013] When the microgrid power does not match the load demand power, the voltage and frequency will exceed the prescribed allowable range, and the power equipment may be damaged;

[0014] When the circuit breaker connecting the microgrid to the main grid is not disconnected, the main grid line is still energized, which may cause electric shock to maintenance personnel and pose a serious threat to the life safety of line workers;

[0015] The continuous supply of power to the large power grid by the microgrid will cause the sensitivity of line-related relay protection equipment to decrease, interfering with the normal operation of the protection equipment.

[0016] In addition to normal maintenance, the islanding effect is mainly related to the removal of the faulty line. Post-fault islanding detection should be regarded as a continuation of the large power grid fault. The two are closely related, because the accurate positioning of the faulty line or section is the prerequisite for correctly starting islanding detection.

[0017] The current island detection technology solution cannot achieve both technical reliability and application economy, which limits its scope of promotion and application, and has a great hindering impact on the large-scale development of new energy.

[0018] The objective problems existing in existing island detection technology are roughly as follows:

[0019] The cost is high and the scope of application is limited. For example, the equipment application cost of power carrier communication technology is high;

[0020] Large detection blind spots, such as technologies utilizing voltage, frequency, phase, and harmonic content;

[0021] Technical solutions that have negative impacts on grid equipment and power quality, such as active interference injection.

[0022] In short, the existing single-phase fault handling technology and island detection technology belong to two completely different categories. They are technically independent of each other, have high total application costs, and each has obvious technical defects. Summary of the Invention

[0023] In view of this, the purpose of the present invention is to provide a single-phase fault handling and island detection system and method to solve the problem in the existing technology that single-phase fault handling technology and island detection technology belong to two completely different categories, are technically independent of each other, and cannot simultaneously achieve single-phase fault handling and island detection.

[0024] According to a first aspect of an embodiment of the present invention, a single-phase fault handling and islanding detection system is provided, comprising:

[0025] The parallel active compensation device and arc suppression coil are connected between the neutral point of the transformer and the ground;

[0026] A zero-sequence current transformer is provided on each feeder and the feeder to which each distributed generation unit is connected, wherein the feeder is connected in parallel to the primary side of the transformer via a busbar;

[0027] The control device is connected to the active compensation device, arc suppression coil, zero-sequence current transformer and busbar respectively, and is used to:

[0028] Determine whether a single-phase fault has occurred based on the amplitude and phase of the grid zero-sequence voltage;

[0029] According to the phase shift trajectory of the grid zero-sequence voltage, the fault phase and single-phase fault type are identified;

[0030] Selecting different arc extinguishing paths according to the single-phase fault type;

[0031] Calculate the zero-sequence admittance of each feeder based on the zero-sequence voltage of the grid and the zero-sequence current of each feeder;

[0032] According to the zero-sequence admittance of each feeder, the specific line and section where the single-phase fault occurs are determined;

[0033] Isolate the faulty line or section and start islanding detection.

[0034] According to a second aspect of an embodiment of the present invention, a single-phase fault handling and islanding detection method is provided, comprising:

[0035] Determine whether a single-phase fault has occurred based on the amplitude and phase of the grid zero-sequence voltage;

[0036] According to the phase shift trajectory of the grid zero-sequence voltage, the fault phase and single-phase fault type are identified;

[0037] Selecting different arc extinguishing paths according to the single-phase fault type;

[0038] Calculate the zero-sequence admittance of each feeder based on the zero-sequence voltage of the grid and the zero-sequence current of each feeder;

[0039] According to the zero-sequence admittance of each feeder, the specific line and section where the single-phase fault occurs are determined;

[0040] Isolate the faulty line or section and start islanding detection.

[0041] The technical solutions provided by the embodiments of the present invention may have the following beneficial effects:

[0042] By judging whether a single-phase fault has occurred in the power grid and identifying the type of single-phase fault when it is determined to have occurred, different arc extinguishing paths are selected according to different single-phase fault types, thereby effectively handling the single-phase fault in the power grid; at the same time, based on the zero-sequence admittance of each feeder, the specific line and section where the single-phase fault has occurred is determined, and then the faulty line or section is isolated, and island detection is started, thereby integrating the single-phase fault handling technology and the island detection technology together, and solving the problems of single-phase fault handling and island detection at the same time through a set of solutions, and users are expected to have a good experience and high satisfaction.

[0043] It is to be understood that the foregoing general description and the following detailed description are exemplary and explanatory only and are not restrictive of the invention. BRIEF DESCRIPTION OF THE DRAWINGS

[0044] The accompanying drawings, which are incorporated in and constitute a part of this specification, illustrate embodiments consistent with the invention and, together with the description, serve to explain the principles of the invention.

[0045] Figure 1 is a circuit schematic diagram of a single-phase fault handling and islanding detection system according to an exemplary embodiment;

[0046] Figure 2 is a flow chart showing a method for single-phase fault handling and islanding detection according to an exemplary embodiment;

[0047] Figure 3 is a primary system network diagram when a fault occurs according to an exemplary embodiment;

[0048] Figure 4 According to an exemplary embodiment Figure 3 Equivalent circuit diagram of

[0049] Figure 5 is a resonance curve diagram of a zero-sequence voltage U0 according to an exemplary embodiment;

[0050] Figure 6 According to an exemplary embodiment Figure 5 Equivalent curve diagram of ;

[0051] Figure 7 is an operating boundary of the zero-sequence voltage U0 according to an exemplary embodiment;

[0052] Figure 8 is a U0 phase offset trajectory in the case of a non-disconnected ground fault according to an exemplary embodiment;

[0053] Figure 9 1 is a U0 phase offset trajectory when a line is disconnected and not grounded according to an exemplary embodiment;

[0054] Figure 10 1 is a U0 phase offset trajectory when a ground fault occurs on the disconnected power supply side according to an exemplary embodiment;

[0055] Figure 11 1 is a U0 phase shift trajectory when a load-side ground fault occurs according to an exemplary embodiment;

[0056] Figure 12 1 is a U0 phase offset trajectory of a ground fault on the disconnected power supply side when the system is fully compensated according to an exemplary embodiment;

[0057] Figure 13 is a U0 phase shift trajectory of a load-side ground fault when the system is fully compensated according to an exemplary embodiment;

[0058] Figure 14 is a schematic diagram showing arc extinguishing during a forward fault according to an exemplary embodiment;

[0059] Figure 15 is a schematic diagram of arc extinguishing during a reverse fault according to an exemplary embodiment;

[0060] Figure 16 is a graph showing a change in the zero-sequence admittance amplitude of a feeder as a function of the resistance value of a transition resistor according to an exemplary embodiment;

[0061] Figure 17 is a graph showing a change in the zero-sequence admittance amplitude of a feeder as a function of the resistance of a transition resistor according to an exemplary embodiment;

[0062] Figure 18 1 is a schematic diagram showing a zero-sequence voltage phase jump and islanding identification principle according to an exemplary embodiment;

[0063] Figure 19 1 is an equivalent circuit of a distributed generation unit DG located upstream of a fault point before a fault line is removed according to an exemplary embodiment;

[0064] Figure 201 is an equivalent circuit of a distributed generation unit DG located downstream of a fault point before the fault line is removed according to an exemplary embodiment;

[0065] Figure 21 This is an island equivalent system after the fault line is removed when the DG with a non-disconnected ground fault is located upstream of the fault point according to an exemplary embodiment;

[0066] Figure 22 It is an island equivalent system after the fault line is removed when the DG with a non-disconnected ground fault is located downstream of the fault point according to an exemplary embodiment;

[0067] Figure 23 It is an island equivalent system after the fault line is removed when the DG of a disconnected and ungrounded fault is located upstream of the fault point according to an exemplary embodiment;

[0068] Figure 24 It is an island equivalent system after the fault line is removed when the DG of a disconnected and ungrounded fault is located downstream of the fault point according to an exemplary embodiment;

[0069] Figure 25 It is an island equivalent system after the fault line is removed when the ground fault DG on the side of the disconnected power supply is located upstream of the fault point according to an exemplary embodiment;

[0070] Figure 26 It is an island equivalent system after the fault line is removed when the ground fault DG on the side of the disconnected power supply is located downstream of the fault point according to an exemplary embodiment;

[0071] Figure 27 It is an island equivalent system after the fault line is removed when the DG on the side of the disconnected load is located upstream of the fault point according to an exemplary embodiment;

[0072] Figure 28 It is an island equivalent system after the fault line is removed when the DG on the load side of the disconnected line is located downstream of the fault point according to an exemplary embodiment;

[0073] Figure 29 1 is a schematic diagram showing a DG side zero-sequence voltage phasor jump islanding detection principle according to an exemplary embodiment;

[0074] Figure 30 2 is a schematic diagram showing a principle of zero-sequence admittance transition islanding detection on the DG side according to another exemplary embodiment. DETAILED DESCRIPTION

[0075] Exemplary embodiments will be described in detail herein, examples of which are illustrated in the accompanying drawings. In the following description, when referring to the drawings, like numbers in different figures represent like or similar elements unless otherwise indicated. The embodiments described in the following exemplary embodiments are not intended to represent all possible embodiments consistent with the present invention. Rather, they are merely examples of apparatus and methods consistent with certain aspects of the present invention, as detailed in the appended claims.

[0076] Example 1

[0077] Figure 1 FIG. 1 is a circuit diagram of a single-phase fault handling and islanding detection system according to an exemplary embodiment. Figure 1 As shown, the system includes:

[0078] The parallel active compensation device and arc suppression coil are connected between the neutral point of the transformer and the ground;

[0079] A zero-sequence current transformer is provided on each feeder and the feeder to which each distributed power generation unit is connected, and the feeder is connected in parallel to the primary side of the transformer through a busbar;

[0080] The control device is connected to the active compensation device, arc suppression coil, zero-sequence current transformer and busbar respectively, and is used to:

[0081] Determine whether a single-phase fault has occurred based on the amplitude and phase of the grid zero-sequence voltage;

[0082] According to the phase shift trajectory of the grid zero-sequence voltage, the fault phase and single-phase fault type are identified;

[0083] Selecting different arc extinguishing paths according to the single-phase fault type;

[0084] Calculate the zero-sequence admittance of each feeder based on the zero-sequence voltage of the grid and the zero-sequence current of each feeder;

[0085] According to the zero-sequence admittance of each feeder, the specific line and section where the single-phase fault occurs are determined;

[0086] Isolate the faulty line or section and start islanding detection.

[0087] It should be noted that the technical solution provided in this embodiment is applicable to power grids of various voltage levels, including high-voltage transmission networks, medium-voltage distribution networks (the primary network for new energy access), and low-voltage distribution networks. Practice has proven that the technical solution provided in this embodiment is most effective when applied to medium-voltage distribution networks (6-66 kV). Therefore, the technical solution provided in this embodiment is preferably applicable to medium-voltage distribution networks (6-66 kV).

[0088] See also Figure 1To better understand the circuit structure of the single-phase fault handling and islanding detection system provided in this embodiment, the circuit structure is explained in detail as follows:

[0089] 1. When the system is working normally, the low voltage side of the main transformer of the 110kV substation is grounded through the parallel active compensation device and arc suppression coil; the distributed generation unit ( Figure 2 The neutral point of the 10kV side transformer (DG_1, DG_2...DG_n) is not grounded.

[0090] 2. There are n (n>1) feeders connected in parallel on the 10kV busbar, and a main circuit breaker is configured at the outlet of each feeder ( Figure 2 CB10, CB20....CBn0) and zero sequence current transformer ( Figure 2 CT_1, CT_2.....CT_n in the CT_1 are used to measure zero-sequence current).

[0091] 3. Multiple circuit breakers are installed on each feeder to divide the feeder into multiple sections, for example, Figure 2 The line between circuit breakers CB11 and CB12 belongs to one section, the line between circuit breakers CB12 and CB13 belongs to one section... the line between circuit breakers CB21 and CB22 belongs to one section... and so on.

[0092] 4. When each distributed generation unit (e.g., photovoltaic, wind power, etc.) is connected to a feeder, it is connected to the feeder through a circuit breaker. For example, DG_1 is connected to the first feeder through circuit breaker CB11, DG_2 is connected to the second feeder through circuit breaker CB21... DG_n is connected to the nth feeder through circuit breaker CBn3.

[0093] 5. Figure 1 Middle measuring point ( Figure 1 Measurement points 1, 2, ..., n) refer to the zero-sequence voltage and current measurement locations at the access points of distributed generation units; circuit breakers are used to open and close lines (with optional high-precision zero-sequence component measurement); arc suppression coil and ungrounded refer to the neutral point grounding methods of the transformer; the active compensation device is an active inverter device that compensates for the residual current at the grounding point; the control device collects measurement data (the zero-sequence current measured by the zero-sequence current transformer at each feeder outlet, the bus PT open-delta voltage, the three-phase voltage, and the arc suppression coil inductance current measurement values ​​are all collected in real time to the control device), and the built-in algorithm processes and outputs instructions; 1 to 3 are the locations where faults occur in the simulated lines; NO refers to the tie switch (normally open).

[0094] 6. Figure 1 Middle measuring point ( Figure 1The data measured at measurement points 1, 2, ..., and n is not directly communicated to the substation control unit because of potential issues such as increased costs, information security, and data transmission failures due to communication equipment failures. Instead, the data from these measurement points is transmitted directly to the control unit of circuit breaker CBn0, which then sends the judgment result to the remote master station.

[0095] The single-phase fault types that can be identified by the control device include at least: non-disconnected grounding fault, disconnected non-grounding fault, disconnected power supply side grounding fault, and disconnected load side grounding fault.

[0096] It should be noted that the technical solution provided in this embodiment places islanding detection after single-phase fault handling because:

[0097] When only considering the fault condition, the islanding effect will only occur when the line containing distributed DG is cut off. Therefore, it can be considered that the islanding detection procedure is started after the fault handling process completes the isolation of the faulty line or section.

[0098] If a non-faulty line is mistakenly identified as a faulty line and removed, the distributed DG on that line will detect the islanding effect and exit the main power grid. In practical applications, this situation needs to be avoided because it will affect the load power balance, which may cause the voltage and frequency to exceed the set upper and lower limits, resulting in a large-scale power outage in the system.

[0099] Therefore, island detection is actually a continuation of the fault handling process and is closely related to the efficiency and effectiveness of fault handling. In particular, accurate fault line selection and positioning are prerequisites for precise island detection.

[0100] It can be understood that the technical solution provided in this embodiment determines whether a single-phase fault has occurred in the power grid, and identifies the fault phase and single-phase fault type when a single-phase fault is determined to have occurred. Different arc extinguishing paths are selected according to different single-phase fault types, thereby effectively achieving the handling of single-phase faults in the power grid; at the same time, based on the zero-sequence admittance of each feeder, the specific line and section where the single-phase fault has occurred are determined, and then the faulty line or section is isolated, and island detection is started, thereby integrating the single-phase fault handling technology and the island detection technology together, and solving the problems of single-phase fault handling and island detection at the same time through a set of solutions, and users are expected to have a good experience and high satisfaction.

[0101] Example 2

[0102] Figure 2 1 is a flow chart showing a method for handling a single-phase fault and detecting an island according to an exemplary embodiment. The method is applied to a control device, and the control device is provided in the system described in the first embodiment. Figure 2 As shown, the method includes:

[0103] Step S11: judging whether a single-phase fault occurs based on the amplitude and phase of the zero-sequence voltage of the power grid;

[0104] Step S12: Identify the fault phase and single-phase fault type based on the phase shift trajectory of the grid zero-sequence voltage;

[0105] Step S13: selecting different arc extinguishing paths according to the single-phase fault type;

[0106] Step S14: Calculate the zero-sequence admittance of each feeder based on the zero-sequence voltage of the grid and the zero-sequence current of each feeder;

[0107] Step S15: Determine the specific line and section where the single-phase fault occurs based on the zero-sequence admittance of each feeder;

[0108] Step S16: Isolate the faulty line or section and start islanding detection.

[0109] It should be noted that the technical solution provided in this embodiment is applicable to power grids of various voltage levels, including high-voltage transmission networks, medium-voltage distribution networks (the primary network for new energy access), and low-voltage distribution networks. Practice has proven that the technical solution provided in this embodiment is most effective when applied to medium-voltage distribution networks (6-66 kV). Therefore, the technical solution provided in this embodiment is preferably applicable to medium-voltage distribution networks (6-66 kV).

[0110] It can be understood that the technical solution provided in this embodiment determines whether a single-phase fault has occurred in the power grid, and identifies the single-phase fault type when a single-phase fault is determined to have occurred. Different arc extinguishing paths are selected according to different single-phase fault types, thereby effectively achieving the handling of single-phase faults in the power grid; at the same time, based on the zero-sequence admittance of each feeder, the specific line and section where the single-phase fault has occurred is determined, and then the faulty line or section is isolated, and island detection is started, thereby integrating the single-phase fault handling technology and the island detection technology together, and solving the problems of single-phase fault handling and island detection at the same time through a set of solutions, and users are expected to have a good experience and high satisfaction.

[0111] In practice, step S11 of "determining whether a single-phase fault occurs according to the amplitude and phase of the grid zero-sequence voltage" can be implemented in a variety of ways, one of which can be:

[0112] Obtain the system's ground insulation parameters (including: system asymmetry k, system damping rate d, system detuning degree v, system capacitive current Ic, and resonant voltage Uen.max);

[0113] Determining a fault threshold according to the ground insulation parameter, wherein the fault threshold is an operating boundary of the amplitude and phase of the grid zero-sequence voltage when the system is operating normally;

[0114] Real-time measurement of the amplitude and phase of the current grid zero-sequence voltage;

[0115] If any feeder is grounded or disconnected, causing the asymmetry of the three phases to the ground of the system to change, and the amplitude or phase of the zero sequence voltage of the power grid exceeds the fault threshold, it is determined that a single-phase fault has occurred.

[0116] It should be noted that during normal system operation, if the zero-sequence voltage of the power grid changes by more than the set value due to line changes or equipment switching, the control device will be triggered to update the insulation parameters of the measurement system and reset the threshold until the system fails. Therefore, the fault threshold provided in this embodiment is a dynamic threshold, which does not need to be manually set or modified. Compared with the technical solution of using a fixed empirical threshold in the prior art (based on human experience, for safety reasons, the threshold is often set larger, generally 20-30% of the phase voltage, so its measurement blind spot is large), the technical solution provided in this embodiment can set the threshold more accurately, and the fault perception and judgment are more sensitive and more accurate.

[0117] It is understandable that the single-phase fault mentioned in this embodiment may occur in Figure 1 In any feeder of the single-phase fault handling and islanding detection system shown.

[0118] For any feeder, Figure 3 This is a primary system network diagram when a fault occurs. By combining K1, K2, and K3, the four types of single-phase faults mentioned above can be simulated. Figure 4 To correspond Figure 3 The equivalent circuit diagram of S1, S2 and S3 can simulate different system operating conditions.

[0119] Figure 3 The meaning of each parameter is as follows:

[0120] Tr refers to transformer

[0121] N refers to the neutral point on the low-voltage side of the transformer

[0122] L P Refers to the arc suppression coil inductance

[0123] U0 is the system zero sequence voltage

[0124] U a1 、a 2 U a1 、aU a1 is the system three-phase positive sequence voltage, where a is the rotation factor 1∠120°;

[0125] A, B, C are the three-phase voltages of the system

[0126] Z 12 is the positive and negative sequence impedance of the line

[0127] G 0a , G 0b , G 0c Line-to-ground leakage conductance

[0128] B ca 、B cb 、B cc To accommodate the line to ground

[0129] Y f is the admittance of the ground resistance

[0130] K1, K2, K3 are fault simulation switches

[0131] Figure 4 The meaning of each parameter is as follows:

[0132] B LP Neutral point sensing

[0133] G ns is the neutral point parallel equivalent conductance

[0134] X tr is the transformer equivalent leakage reactance

[0135] G0 is the total conductance of the system to ground

[0136] B LP The total ground capacity of the system

[0137] S1, S2, S3 are analog ground switches

[0138] I uf , I uc , I ud A virtual current source

[0139] Y uf 、Y uc 、Y ud is the equivalent parallel admittance of the corresponding virtual current source

[0140] In practical applications, the three-phase zero-sequence admittance to ground is not completely equal during normal system operation due to line layout, so a certain zero-sequence component always exists. Because the line-to-ground conductance is much greater than the leakage conductance to ground, three-phase asymmetry often depends on the three-phase capacitance. Therefore, leakage resistance can be ignored when calculating asymmetry. Furthermore, the line series impedance is smaller than the transition resistance, and the equivalent leakage reactance is much smaller than the arc suppression coil impedance. Therefore, both can be ignored in practical projects.

[0141] Figure 3 K1 and K2 are closed and K3 is open, indicating that the system is operating normally. Figure 4 In the case of S1 and S3 being disconnected and S2 being closed, if the system fault state is to be defined, the boundary range of normal operation must be determined. Figure 3 It can be seen from the figure that during normal operation, the neutral point is grounded through the arc suppression coil. The normal mode is set to moderate overcompensation mode, and the zero-sequence current is the sum of the ground capacitance current and the leakage active current.

[0142] According to Kirchhoff's law:

[0143]

[0144] In formula (1), only the positive sequence voltage (U a1 、a 2 U a1 、aU a1 is the system three-phase positive sequence voltage) and zero sequence voltage U0. The negative sequence voltage is small during normal operation and can be ignored.

[0145] Among them: Ya, Yb, Yc and Yn refer to the three-phase zero-sequence admittance to ground and the neutral point zero-sequence admittance respectively;

[0146] From formula (1), the calculation formula of the per-unit value u0 of U0 is:

[0147]

[0148] After further arrangement, the resonance curve of U0 is obtained:

[0149]

[0150] in,

[0151] k is the system asymmetry:

[0152] d is the system damping rate:

[0153] v is the system detuning degree:

[0154] The image of the function u0=f(v) is obtained from formula (3) as follows Figure 5 shown.

[0155] Figure 5 Assuming that the damping rate d is constant, when the system detuning degree v = 0, the maximum value U0.max is obtained; when v = ±∞, U0 is the minimum value zero; it can be seen from the figure that each U0 corresponds to an opposite v value. Combining formula (3), the function graph of U0 with respect to v is obtained as follows Figure 6 As shown ( Figure 6 The great circle in Figure 5 The resonance curve in the transformation is Figure 6 The great circle in is equivalent to Figure 5 The resonance curve in polar coordinates).

[0156] By changing the neutral point parameters, the U01 and U02 vectors are obtained, and the inductor currents IL1 and IL2 are measured at the same time. Figure 6 The trigonometric function relationship can be used to calculate the system capacitance current Ic, resonant voltage Uen.max, system damping rate d and current detuning degree v, system asymmetry k and its phase angle.

[0157] In the specified coordinate system, the vector points U01 and U02 form a geometric triangle with the reference point n. Points U01 and U02 lie on the circumcircle of the triangle, centered at o. The vector magnitude angle between n and o is φ0. As the system detuning degree v varies from negative infinity to positive infinity, U0 will follow the boundary of the circumcircle. The diameter passing through the center of the circle and point n is U0.max, the resonant voltage.

[0158] By establishing auxiliary lines, the system detuning degrees are mapped to the intersection points of the auxiliary lines one by one. U01, U02, U0.max, Up and Uq correspond to v1, v2, v0, v respectively. p and v q At the same time, the distance from U0i (i=01, 02, max, p, q) to n is defined as L1, L2, Lm, Lp, Lq; the distance from vi (i=1, 2, p, q) to v0 is defined as Lv1, Lv2, Lvp, Lvq.

[0159] From this, the system's ground insulation parameters can be calculated.

[0160] System capacitance current Ic:

[0161]

[0162] The resonant voltage is Uen.max (U0.max) and its phase angle

[0163]

[0164]

[0165] System detuning degree v:

[0166]

[0167] System damping rate d:

[0168]

[0169]

[0170] System asymmetry k and its phase angle

[0171] k=U en.max ·d

[0172]

[0173] The calculated Ic, Uen.max, k, d, and v can be used to establish the current U0 trajectory during normal operation. Figure 7 shown.

[0174] It should be noted that Figure 7 The large circle in the figure is the resonance curve of U0, and the small circle is the error fluctuation range after considering the U0 measurement error. The error fluctuation range takes into account the amplitude and 360-degree phase angle. Figure 7 The horizontal and vertical coordinates represent the components of U0 on the horizontal and vertical coordinates, and the horizontal axis is the starting point (line) where the phase angle of U0 is 0.

[0175] See also Figure 7 Under the current parameter conditions, when U0 always runs along the fault trigger threshold boundary within the measurement trigger threshold, it means that the system is in normal operation (U01 and U02); when it exceeds the measurement trigger threshold and crosses the fault trigger threshold at the same time, the system is in fault state (U03). In short, when the amplitude and phase of U0 both exceed Figure 7 The large circle in the figure indicates that a single-phase fault has occurred in the system.

[0176] In practice, step S12 of "identifying the single-phase fault type according to the phase offset trajectory of the grid zero-sequence voltage" can be implemented in a variety of ways, one of which can be:

[0177] When a single-phase fault is determined to have occurred, the phase offset trajectory of the zero-sequence voltage of the power grid at the current moment is obtained;

[0178] Search the pre-stored correspondence table for the single-phase fault type corresponding to the phase offset trajectory obtained at the current moment; the single-phase fault types include at least: non-disconnected grounding fault, disconnected non-grounding fault, disconnected power supply side grounding fault and disconnected load side grounding fault.

[0179] The corresponding relationship table is obtained by the following method, including:

[0180] During normal system operation, the system's ground insulation parameters are obtained in near real time;

[0181] Substitute the real-time ground insulation parameters into the pre-stored phasor function for calculation to obtain the phase offset trajectory of the grid zero-sequence voltage. Each phasor function corresponds to a single-phase fault type, and the single-phase fault type corresponds to the phase offset trajectory one by one.

[0182] The phase offset trajectory is stored correspondingly under the phasor function to establish a corresponding relationship table between the phase offset trajectory and the single-phase fault type;

[0183] When the system's insulation parameters to ground are updated, the phase shift trajectory of the grid zero-sequence voltage is recalculated based on the updated insulation parameters;

[0184] The recalculated phase offset trajectory data is stored in the corresponding relationship table.

[0185] In order to illustrate the corresponding relationship between phasor function, phase offset trajectory and single-phase fault type, we now combine Figures 8 to 11 The specific explanations are as follows:

[0186] 1. Non-disconnected single-phase grounding fault

[0187] Figure 3 In the figure, K1, K2 and K3 are all closed, indicating that a non-disconnected single-phase grounding fault occurs in phase A of the system. Figure 4 In the case where S1 and S2 are closed and S3 is open, the equation is obtained according to Kirchhoff's current law:

[0188]

[0189] The expression of U0 during fault is obtained from formula (4):

[0190]

[0191]

[0192] in:

[0193] in:

[0194] When the non-disconnection fault obtained by formula (6) occurs in phases A, B, and C respectively, the function graph of the u0 phase is as follows: Figure 8 shown.

[0195] Figure 8 The U0 phase deviation trajectory is shown in Figure 1 when a non-disconnected ground fault occurs in the system. Taking overcompensation as an example, the line voltage U AB As a benchmark reference phase, the U0 phase interval for a Phase A fault is 150° to 240° counterclockwise, for a Phase B fault it is 30° to 120° counterclockwise, and for a Phase C fault it is 270° to 360° counterclockwise. These phases do not overlap, allowing accurate identification of the fault phase and type. In actual operation, arc suppression coils are typically placed at a moderately overcompensated position. The closer the U0 phase interval is to full compensation, the narrower it is, resulting in higher identification accuracy.

[0196] 2. Broken line and ungrounded fault

[0197] Figure 3 K1, K2 and K3 are disconnected, indicating that phase A has a disconnection and no grounding fault. Figure 4 In the case where S2 and S3 are closed and S1 is open, the equation is obtained according to Kirchhoff's current law:

[0198]

[0199] The expression of U0 at this time is obtained from formula (7):

[0200]

[0201]

[0202] Where n is a real number, d is the grid damping rate when the system is not faulty, and represents the ratio of the zero-sequence admittance downstream of the line break point to the total zero-sequence admittance of the line.

[0203] From formula (9), we can get the function graph of u0 phase when the disconnection fault occurs in phases A, B, and C respectively. Figure 9 shown.

[0204] Figure 9 This is the U0 phase deviation trajectory when a disconnection and ungrounded fault occurs. Taking overcompensation as an example, as the compensation degree approaches full compensation, when phase A is disconnected, the U0 phase interval is 150° to 60° clockwise; when phase B is disconnected, the U0 phase interval is 30° to 300° clockwise; when phase C is disconnected, the U0 phase interval is 270° to 180° clockwise, with no overlap and no overlap. Figure 8 There is no overlap in the case of non-broken ground faults, so the two types of faults can be distinguished with high accuracy and reliability, and the faulty phase can be identified at the same time.

[0205] 3. Ground fault on the disconnected power supply side

[0206] Figure 3 K1 and K3 are closed and K2 is open, indicating that a ground fault occurs on the power supply side of phase A. Figure 4 The situation when S1, S2, and S3 are all closed. According to Kirchhoff's current law, we can get the equation:

[0207]

[0208] The expression of U0 is obtained from formula (10):

[0209]

[0210]

[0211] in

[0212] d′ is the damping rate of the power grid after the system fault. According to formula (12), when the ground fault on the disconnected power supply side occurs in phases A, B, and C respectively, the function image of the u0 phase is as follows: Figure 10 shown.

[0213] Figure 10 This is the U0 phase deviation trajectory when the power supply side is grounded (v = -100%). As the ground transition resistance increases from zero to infinity, its trajectory trend is the same as that of the non-disconnected ground fault ( Figure 8 ) is similar, but the phase shift is not completely consistent under the same fault phase and the same transition resistance conditions. To identify this type of fault, you first need to confirm whether the line is broken. Figure 9 Because a ground fault on the power supply side of a power outage consists of two independent states—the first being the power outage and the second being the grounded state—the U0 phase undergoes a significant abrupt change due to the switching between the two states. Specifically, within a short period of time after the fault, the phase changes from the power outage-ungrounded state to the non-power outage-grounded state. Since the two states do not overlap, they can be reliably identified.

[0214] 4. Ground fault on the load side of the disconnected line

[0215] Figure 3 In the figure, K2 and K3 are closed and K1 is open, indicating that a ground fault occurs on the load side of phase A. Figure 4 When S1, S2, and S3 are all closed, the equation is obtained according to Kirchhoff's current law:

[0216]

[0217] The expression of U0 is obtained from formula (13):

[0218]

[0219]

[0220] From formula (15), we can get that when the ground fault on the disconnected load side occurs in phases A, B, and C respectively, the function image of the u0 phase is as follows: Figure 11 shown.

[0221] Figure 11 This is the U0 phase deviation trajectory when the load side of the disconnected line is grounded (v = -100%). As the transition resistance gradually increases from zero to infinity, the U0 phase starts to coincide with the original voltage phase of the fault phase, and rotates counterclockwise until it coincides with the U0 phase of the disconnected line ungrounded fault. Figure 11 The faults in each phase U0 overlap with each other to a large extent ( Figure 11Draw a ray at the center intersection of , and when it passes through the trajectory curves of the two phases, the phases overlap). This affects the sensitivity of further identifying the fault type and phase difference. When a line break occurs in the first state, the system identifies the fault phase. When grounding occurs in the second state, the fault phase may be inconsistent with the fault phase identified in the first state due to the overlap of the U0 phase.

[0222] Figure 10 and Figure 11 All of these are for the case where the system is -100% overcompensated. In actual applications, the system is usually moderately overcompensated, that is, closer to 0% full compensation. Therefore, during operation, it is necessary to tune the compensation level of the arc suppression coil to be close to the full compensation state to avoid the occurrence of U0 phase overlap. Figure 12 and Figure 13 shown.

[0223] Figure 12 and Figure 13 The following are the U0 phase offset trajectories for ground faults on the disconnected power source side and on the disconnected load side, respectively, when the system is fully compensated. The U0 offset for each phase is 90 degrees, with no overlap or confusion, resulting in excellent fault type and phase identification sensitivity. In practical applications, maintaining the system detuning degree v within the ground insulation parameter range of 0% to -10% can prevent U0 phase aliasing and achieve optimal identification sensitivity. The closer the detuning degree is to 0%, the higher the sensitivity. When arc suppression coils are severely under-compensated or over-compensated due to improper operation, identification sensitivity will undoubtedly be affected.

[0224] After completing the fault type and phase identification in step S12, in order to ensure the safety of the grounding point and prevent electric shock to people and vegetation fire, the active compensation device performs regulation and control. The grounding point current is eliminated to zero by injecting a large reverse current such as the grounding residual current from the neutral point. Since the grounding point voltage is always lower than the arc recovery voltage, the arc will not reignite, and the risk of electric shock to people and vegetation ignition is greatly reduced.

[0225] In specific practice, step S13 "selecting different arc extinguishing paths according to the single-phase fault type" can be implemented in multiple ways, one of which can be:

[0226] The non-disconnected line grounding fault and the disconnected line power supply side grounding fault are defined as forward faults, and the disconnected line non-grounding fault and the disconnected line load side grounding fault are defined as reverse faults.

[0227] 1. For a forward fault, the voltage of the fault phase is zero after compensation by the neutral point injection current, and the voltage of the non-fault phase reaches the line voltage level. At the same time, the zero-sequence voltage of the grid and the positive-sequence voltage of the fault phase are in the same large opposite direction, and the residual current at the grounding point is close to zero after being fully compensated.

[0228] Depend on Figure 4, Equation (4) and Equation (10), it can be seen that the grounding residual current is related to the grounding transition (Y in Equation (4) and Equation (10) f It is the admittance representation of the transition resistance. The residual current at the grounding point is the fault phase voltage Ua'*Y f , Y f The size of U0 will affect the size of U0, and the size of U0 will affect the fault phase voltage Ua' (Ua' is equal to the vector sum of U0 and Ua1). Therefore, the ground residual current must be related to the transition resistance). The target injection current is in the opposite direction of the ground residual current. Taking the A phase fault as an example, the expression of the neutral point injection current I_inj is:

[0229]

[0230] in:

[0231] For U a1 Phase angle;

[0232] is the argument of asymmetry;

[0233]

[0234] After the neutral point current injection compensation, the fault phase A voltage is zero, and the non-fault phase voltage reaches the line voltage level. At the same time, the zero sequence voltage and the positive sequence voltage of the fault phase are in the same magnitude and opposite direction (such as Figure 14 ), the residual current at the grounding point is close to zero after being fully compensated.

[0235] 2. For reverse faults, after compensation by neutral point injection current, the fault phase voltage meets the first preset condition, the non-fault phase voltage meets the second preset condition, the grid zero-sequence voltage meets the third preset condition, and the residual current at the load-side grounding point is close to zero after being fully compensated;

[0236] The first preset condition includes: the fault phase voltage reaches 1.5 times the positive sequence voltage of the fault phase and the phases are consistent; the second preset condition includes: the non-fault phase voltage is 0.866 times the respective positive sequence voltages and the phases are opposite to each other; the third preset condition includes: the zero sequence voltage of the power grid is 0.5 times the positive sequence voltage of the fault phase and the phases are consistent.

[0237] Depend on Figure 4 , Equation (7) and Equation (13), it can be seen that the grounding residual current is related to the grounding transition, and the target injection current is in the opposite direction of the grounding residual current. Taking the A phase fault as an example, the neutral point injection current I_inj is expressed as:

[0238]

[0239] in:

[0240]

[0241] After the neutral point injection current compensation, the voltage of the fault phase A reaches 1.5 times the positive sequence voltage, the voltage of the non-fault phase is 0.866 times the positive sequence voltage of each phase, and the phase is reversed, and the zero sequence voltage is 0.5 times the positive sequence voltage of the fault phase and the phase is consistent (such as Figure 15 ), the residual current at the load side grounding point is close to zero after being fully compensated.

[0242] In practice, step S14 of "calculating the zero-sequence admittance of each feeder according to the zero-sequence voltage of the power grid and the zero-sequence current of each feeder" can be implemented in multiple ways, one of which can be:

[0243] When the arc is extinguished, two sets of zero-sequence voltages and the measured values ​​of the zero-sequence current of each feeder under each set of zero-sequence voltages are obtained simultaneously by injecting current step by step from the neutral point.

[0244] After the zero-sequence voltage of the power grid is regulated to reach a target value and residual current at the grounding point is eliminated, the zero-sequence admittance of each feeder is calculated based on the measured value.

[0245] Figure 2 The zero-sequence voltage and zero-sequence current measured in real time are collected in the control device. When the arc extinguishing program is executed, two sets of zero-sequence voltage and zero-sequence current measurement values ​​of each feeder are obtained simultaneously by injecting current step by step from the neutral point, which are recorded as I 01 、U 01 and I 02 、U 02 .

[0246] For low-resistance faults, the zero-sequence characteristic is more pronounced, facilitating the measurement of zero-sequence parameters with minimal error. However, in the event of a high-resistance fault, if the zero-sequence current of each feeder is less than or close to the zero-sequence transformer measurement error, the measured data becomes invalid and cannot be used to further calculate line-to-ground parameters. Even with the use of high-precision measuring transformers, the unbalanced current caused by the line's inherent impedance imbalance to ground must still be considered. Therefore, the absolute measurement of the zero-sequence current will have significant error in high-resistance faults, making it impossible to reliably determine the faulty line based solely on the polarity of the zero-sequence current.

[0247] Since the grounding transition resistance mainly exhibits resistive characteristics and has little impact on the total line-to-ground impedance when the resistance value is high, it is difficult to determine whether a fault has occurred from the magnitude of the zero-sequence voltage. Since the zero-sequence admittance value of the line to the ground is a complex number, in the form of a + bi, assuming the conductance is a and the susceptance is b, when a << b, its modulus value mainly depends on b. Therefore, when a high-resistance fault occurs, the change in the line conductance is small, and the calculated zero-sequence admittance value mainly depends on the susceptance; the argument is arg(b / a). When the line is operating normally, b >> a. Although the impact on a after a high-resistance fault occurs is small, it can be found from the y = actan(b / a) graph that even a small change in a will cause a significant change in the argument. Therefore, a reliable basis has been found for the method of selecting and locating the line using the zero-sequence admittance argument.

[0248] Figure 16 It is shown that when a certain line is operating normally, the zero-sequence admittance argument is 87.8°. After a grounding fault occurs, when the transition resistance increases from 1 Ω to 12 kΩ, the zero-sequence admittance argument gradually approaches the argument value under normal conditions. When it reaches 12 kΩ, there is still a difference of about 3° between the argument and the normal value. Therefore, it is highly feasible to use this to achieve the selection and location of high-resistance faults.

[0249] And Figure 16 Under the same operating conditions, Figure 17 It is shown that when the transition resistance increases from 1 Ω to 12 kΩ, the zero-sequence admittance magnitude rapidly drops close to zero. It can be seen that the zero-sequence admittance magnitude cannot be used as a reliable basis to judge the faulty line.

[0250] After regulating the zero-sequence voltage to the target value to eliminate the residual current at the grounding point, the zero-sequence admittance values of each feeder can be calculated from the previously measured zero-sequence components. <00​​​​​​​​​​​​​​​​​​​​​​​​​Compare the zero-sequence admittance of each feeder with the zero-sequence admittance of the same line during normal system operation;

[0255] For any feeder, if the zero-sequence admittance's argument exceeds the argument threshold, the current feeder is determined to be a fault line; if the zero-sequence admittance's argument is less than or equal to the argument threshold, the current feeder is determined to be a non-fault line.

[0256] For any section on any feeder, if the amplitude of the upstream zero-sequence admittance is different from that during normal system operation, while the amplitude of the downstream zero-sequence admittance is the same as that during normal system operation, the current section is determined to be a fault section; otherwise, the current section is determined to be a non-fault section.

[0257] In practice, step S16 "isolating the faulty line or section and starting island detection" can be implemented in a variety of ways, one of which can be:

[0258] When the preset conditions are met, the zero-sequence voltage phase jump identification method is selected for island detection; the preset conditions include: the amplitude of the zero-sequence voltage on the distributed generation unit side is less than the first threshold, and the ground transition resistance ( Figure 2 Fault points 1, 2, and 3 are disconnected or grounded. By default, when there is a ground fault, there is a transition resistance, and its value ranges from zero to infinity. When the resistance value is greater than the second threshold;

[0259] When the preset conditions are not met, the zero-sequence admittance jump identification method is used for islanding detection.

[0260] It is understandable that, considering the ungrounded neutral point of the microgrid's high-voltage transformer and assuming the neutral point of the main transformer in the main grid is grounded via an arc suppression coil, the microgrid's grounding method will change from resonant grounding to ungrounding before and after the fault line is cleared. Since the ungrounded neutral point is equivalent to zero inductance and extremely large resistance, the detuning degree v can be considered equivalent to 100%, and the system damping rate d depends only on the line-to-ground conductance. Although the capacitive current of the island network is much smaller than that of the main grid after the fault line is cleared, it remains in a 100% undercompensated operating mode, while the main grid is typically set to moderate overcompensation. It can be seen that after the fault is cleared, the U0 phase on the microgrid side will undergo a certain reverse jump due to the sudden change in the system compensation degree. Since one or more microgrids on the non-fault line always maintain resonant grounding, the DG access point U0 remains almost unchanged or changes only slightly. Therefore, the change pattern of the U0 phase on the microgrid side can be used to identify islands on the fault line without affecting the continued normal operation of the microgrid on the non-fault line.

[0261] The amplitude of the U0 phase jump depends on the size of the transition resistance. In the case of a metallic ground fault, regardless of the system compensation degree, the U0 phase is always 180 degrees or close to 180 degrees with the fault phase voltage. In this case, the identification sensitivity of the phase reverse jump will be insufficient.

[0262] Therefore, this embodiment provides two post-fault islanding detection methods to maximize islanding detection sensitivity. These two methods can be used simultaneously or separately under certain conditions. This method requires no new equipment and can simply utilize existing zero-sequence voltage and current measurement devices on the line. This method offers unparalleled economic advantages and high technical reliability, providing technical support for the large-scale integration of renewable energy into new power systems.

[0263] 1. Zero-sequence voltage phase jump identification method, specifically:

[0264] If the phase change pattern of the zero-sequence voltage on any distributed generation unit side is reversed before and after the fault line or section is isolated, it is determined that the distributed generation unit is operating in island mode.

[0265] Depend on Figure 1 It can be seen that the neutral point of the 10kV transformer on the DG side is ungrounded, while the main transformer of the large power grid is grounded with an arc suppression coil. During normal operation, the entire system is grounded with an arc suppression coil; when a fault occurs, the fault line containing the DG is disconnected and the grounding method is changed to ungrounded. Before and after the grounding method change, the zero-sequence voltage variation pattern of the measurement point on the DG side will show completely opposite characteristics. Figure 18 Taking the ground fault of phase A as an example, since the arc suppression coil is tuned to the overcompensation mode, the zero-sequence voltage of the entire system, including all DG measuring points, will always be in the "-100% to 0% overcompensation-A" range when the fault occurs; when the fault line is removed, if there is a DG, an island operation mode will be formed. At this time, the zero-sequence voltage of the DG measuring point will jump to the "0% to 100% undercompensation-A" range. The non-fault line is not disconnected from the busbar and still maintains the arc suppression coil grounding mode, and its zero-sequence voltage range remains unchanged.

[0266] With the ground fault transition resistance R f From zero to infinity, the zero-sequence voltage at the main transformer side and the DG measurement point on the non-fault line increases counterclockwise, starting from a phase angle of 150 degrees (with the Uab line voltage as the reference). The zero-sequence voltage at the DG measurement point on the fault line decreases clockwise, starting from a phase angle of 150 degrees. This indicates that the 150-degree phase angle is the constant dividing line between the zero-sequence voltages under the two different grounding schemes. Therefore, islanding can be identified based on the regional jumps in the zero-sequence voltage on the DG side.

[0267] In addition to non-disconnected grounding faults, disconnected non-grounding faults, disconnected load-side grounding faults and disconnected power supply-side grounding faults are also applicable to the zero-sequence voltage phase jump identification principle.

[0268] When the grounding transition resistance is small, the zero-sequence voltage amplitude and phase jump are both small and are almost unaffected by the grounding mode conversion. At the same time, considering that there are certain errors in the measuring equipment, the sensitivity of zero-sequence voltage phase recognition will be significantly reduced. Therefore, the phase jump principle needs to ensure the sensitivity within the detection range by setting restriction conditions. For example, when the zero-sequence voltage amplitude is set to be less than 50% to 80% of the positive-sequence voltage, the phase jump principle takes precedence. Otherwise, the zero-sequence admittance jump identification method is used.

[0269] 2. Zero-sequence admittance jump identification method, specifically:

[0270] If the difference in the amplitude and angle of zero-sequence admittance on any distributed generation unit side before and after the fault line or section is isolated is greater than a preset value, it is determined that the distributed generation unit is operating in island mode.

[0271] Zero-sequence admittance measurement requires consideration of the errors of the line measurement device. When the zero-sequence voltage is below or close to the error range, the measured value cannot be effectively used. In the zero-sequence voltage phase jump identification method, the identification sensitivity decreases when the zero-sequence voltage amplitude approaches the phase voltage. However, for zero-sequence admittance, the larger the zero-sequence voltage, the closer the measured value is to the actual value.

[0272] Before the fault line is removed, the zero-sequence admittance measured at the DG access point is that of the downstream line in the direction of power flow. However, after the fault line is removed, the zero-sequence admittance measured on the DG side changes due to changes in line operating conditions. Therefore, using the difference in zero-sequence admittance measured on the DG side before and after the fault line is removed provides a feasible technical solution for identifying islands.

[0273] Before the fault line is removed, the two sets of zero-sequence current and zero-sequence voltage values ​​are measured and saved on the DG side. The zero-sequence admittance Y is calculated using formula (18): go_beforetripping .

[0274] After the fault line is removed, a set of zero-sequence current and zero-sequence voltage are measured in real time on the DG side, denoted as I 03_g 、U 03_g , the current zero-sequence admittance calculation result is:

[0275]

[0276] If the difference in the amplitude of the zero-sequence admittance on the DG side of any distributed generation unit before and after the fault line or section is isolated is greater than a first preset value, and the difference in the argument of the zero-sequence admittance is greater than a second preset value, it is determined that the distributed generation unit DG is operating in island mode.

[0277] It should be noted that the first preset value and the second preset value are set according to user needs, or according to experimental data, or according to historical experience values.

[0278] ΔYg0 =Y g0_after tripping -Y g0_before tripping (20)

[0279] Before the fault line is removed, the DG may be located upstream of the fault point (see Figure 19 ) or the DG may be downstream of the fault point (see Figure 20 ), DG measured zero sequence admittance is Y g0_beforetripping ; When the fault line is removed, the DG enters the island operation mode, and the zero-sequence admittance measured by the DG is Y g0_aftertripping .

[0280] Island identification methods 1 and 2 do not require new equipment or communication between the main substation and the DG side, making them more economical. The combined application of the two methods can fully cover low-resistance and high-resistance fault conditions, minimize detection blind spots, and improve the reliability of island identification without any impact on power quality.

[0281] In order to better understand the zero-sequence admittance jump identification method provided by this embodiment, a detailed description is now given by taking how to perform islanding detection when four types of single-phase faults occur in the system as an example.

[0282] See also Figure 19 and Figure 20 , Figure 19 and Figure 20 The meanings of the parameters are as follows:

[0283] m represents the ratio of the distance between the DG and the fault point to the total length of the fault line.

[0284] n represents the ratio of the length downstream of the fault point to the total length of the fault line

[0285] Ya, Yb, and Yc represent the total zero-sequence admittance of the three phases of the fault line to ground.

[0286] 1. Non-disconnection grounding fault

[0287] 1) When the DG is upstream of the fault point

[0288] Figure 19 In the example, when K1, K2, and K3 are all closed, it indicates that a non-disconnected ground fault has occurred on phase C. The zero-sequence admittance measured on the DG side before the fault line is removed is:

[0289] Y g0_before tripping =(m+n)·(Y a +Y b +Y c ) (twenty one)

[0290] Figure 21 This is the island equivalent system after the fault line is removed. The zero-sequence admittance measured on the DG side is:

[0291] Y g0_after tripping =Y a +Y b +Y c +Y f (twenty two)

[0292] 2) DG is downstream of the fault point

[0293] Figure 20 In the example, when K1, K2, and K3 are all closed, it indicates that a non-disconnected ground fault has occurred on phase C. The zero-sequence admittance measured on the DG side before the fault line is removed is:

[0294] Y g0_before tripping =(nm)·(Y a +Y b +Y c ) (twenty three)

[0295] Figure 22 This is the island equivalent system after the fault line is removed. The zero-sequence admittance measured on the DG side is:

[0296] Y g0_after tripping =Y a +Y b +Y c +Y f (twenty four) 2. Broken line and ungrounded fault

[0297] 1) The DG is upstream of the fault point

[0298] Figure 19 In the example, when K1, K2, and K3 are all disconnected, it indicates that a disconnected and ungrounded fault has occurred on phase C. The zero-sequence admittance measured on the DG side before the fault line is removed is:

[0299] Y g0_bejore tripping =(m+n)·(Y a +Y b +Y c ) (25)

[0300] Figure 23 This is the island equivalent system after the fault line is removed. The zero-sequence admittance measured on the DG side is:

[0301] Y g0_after tripping =Y a +Y b +Y c (26)

[0302] 2) DG is downstream of the fault point

[0303] Figure 20In the example, when K1, K2, and K3 are all disconnected, it indicates that a disconnected and ungrounded fault has occurred on phase C. The zero-sequence admittance measured on the DG side before the fault line is removed is:

[0304] Y g0_before tripping =(nm)·(Y a +Y b )+n·Y c (27)

[0305] Figure 24 This is the island equivalent system after the fault line is removed. The zero-sequence admittance measured on the DG side is:

[0306] Y g0_after tripping =Y a +Y b +n·Y c (28)

[0307] 3. Ground fault on the disconnected power supply side

[0308] 1) The DG is upstream of the fault point

[0309] Figure 19 In the example, when K1 and K3 are closed and K2 is open, it indicates that a ground fault has occurred on the power supply side of phase C. The zero-sequence admittance measured on the DG side before the fault line is removed is:

[0310] Y g0_before tripping =(m+n)·(Y a +Y b +Y c )+Y f (29)

[0311] Figure 25 This is the island equivalent system after the fault line is removed. The zero-sequence admittance measured on the DG side is:

[0312] Y g0_aftertripping =Y a +Y b +Y c +Y f (30)

[0313] 2) DG is downstream of the fault point

[0314] Figure 20 In the example, when K1 and K3 are closed and K2 is open, it indicates that a ground fault has occurred on the power supply side of phase C. The zero-sequence admittance measured on the DG side before the fault line is removed is:

[0315] Y g0_before tripping =(nm)·(Y a +Y b )+n·Y c (31)

[0316] Figure 26 This is the island equivalent system after the fault line is removed. The zero-sequence admittance measured on the DG side is:

[0317] Y g0_after tripping =Y a +Y b +n·Y c (32)

[0318] 4. Ground fault on the load side of the disconnected line

[0319] 1) The DG is upstream of the fault point

[0320] Figure 19 In the example, when K2 and K3 are closed and K1 is open, it indicates that a load-side grounding fault has occurred on phase C. The zero-sequence admittance measured on the DG side before the fault line is removed is:

[0321] Y g0_before tripping =(m+n)·(Y a +Y b +Y c )+Y f (33)

[0322] Figure 27 This is the island equivalent system after the fault line is removed. The zero-sequence admittance measured on the DG side is:

[0323] Y g0_after tripping =Y a +Y b +Y c +Y f (34)

[0324] 2) DG is downstream of the fault point

[0325] Figure 20 In the example, when K2 and K3 are closed and K1 is open, it indicates that a load-side grounding fault has occurred on phase C. The zero-sequence admittance measured on the DG side before the fault line is removed is:

[0326] Y g0_before tripping =(nm)·(Y a +Y b +Y c )+Y f (35)

[0327] Figure 28 This is the island equivalent system after the fault line is removed. The zero-sequence admittance measured on the DG side is:

[0328] Y g0_after tripping =Y a +Y b +n·Y c +Y f (36)

[0329] From equations (21) to (36), it can be seen that the zero-sequence admittance measured by DG is different before and after fault removal. As mentioned above, when the zero-sequence voltage and zero-sequence current are within the accurate measurement range, the real-time zero-sequence admittance differential identification principle is used to calculate ΔY g0 , when ΔY g0 If the value is greater than the set threshold, an island alarm will be triggered.

[0330] Figure 29 This is the principle diagram of the DG side zero-sequence voltage phase jump island detection. During normal operation, the asymmetry of the three-phase line caused by line switching changes is limited, and the zero-sequence voltage operates within the threshold range and does not cross the threshold, which can usually be set to 15V. Or if the arc suppression coil fails and stops operating, the absolute value of the detuning degree increases to nearly 100%, and the zero-sequence voltage can only decrease, far less than 15V. In this case, even if the DG side detects a zero-sequence voltage change, it remains within the 15V threshold range ( Figure 29 As shown in ③), the action is therefore locked.

[0331] After the fault is cleared, the DG on the non-fault line always keeps consistent with the zero-sequence voltage of the master busbar and is always in operation close to the phase voltage level under the clamping of the neutral point compensation device. However, the zero-sequence voltage on the DG side of the fault line may drop rapidly to below the 15V threshold ( Figure 29 In some cases, the DG zero-sequence voltage amplitude does not change significantly, but the phase change α value exceeds the set value ( Figure 29 (As shown in ② and ④), isolated islands can also be determined.

[0332] However, when the metallic grounding or transition resistance is small, after the fault line is removed, the zero-sequence voltage amplitude and phase change on the DG side are less than the set threshold, which will lead to a decrease in detection sensitivity. In this case, it is necessary to further judge with the zero-sequence admittance on the DG side, such as Figure 30 The zero-sequence admittance threshold is set to a radius of dY g0 It is assumed that the zero-sequence admittance angle measured by DG before the fault line is removed is 85 degrees as the reference zero-sequence admittance angle. g0 >dY g0 This indicates that the zero-sequence admittance on the DG side changes before and after the fault is cleared. In particular, the change in zero-sequence admittance is most obvious when there is a metallic ground fault (e.g. Figure 30 In the middle area ①), the zero-sequence admittance angle changes by dozens of degrees, and the zero-sequence admittance value also changes by dozens or hundreds of times, which can make up for the problem of insufficient sensitivity of the zero-sequence voltage phase jump principle when metallic grounding is used. Figure 30 When there is no transition resistance in the middle areas ② and ③, the total line length decreases and increases, which often occurs when there is a broken line and no grounding fault.

[0333] The zero-sequence admittance jump principle is applicable to all working conditions where the zero-sequence voltage is greater than 15V after the fault line is removed, and serves as a dual basis for island detection together with the zero-sequence voltage phase jump principle.

[0334] When the faulty line is cleared, the neutral point compensation device will shut down. If it shuts down directly, the zero-sequence voltage on the DG side of all non-faulty lines will quickly drop to within the 15V threshold range. According to the above judgment method, all DGs on non-faulty lines will be mistakenly believed to be operating in island mode and will subsequently disconnect from the main power grid. This is not allowed.

[0335] To solve this problem, Figure 29 The system creatively applies the step-by-step exit method. All DGs that receive the step-by-step exit signal believe that the system is operating normally and exit without taking any action.

[0336] After the fault line is removed, the zero-sequence voltage of the non-fault line still operates at a level close to the phase voltage. When it is recognized that the fault line has been removed, the neutral point compensation device will exit with a two-step delay. The first step is to reduce the phase voltage from 100% to 75% while the phase remains unchanged, lasting for 5 seconds; the second step is to reduce the phase voltage from 75% to 50% while the phase remains unchanged, lasting for 3 seconds, and then directly exit operation. Since all DGs on the grid can measure the step-by-step exit signal, it can be ensured that the DGs on the non-fault line will not exit operation even in the absence of communication.

[0337] It can be understood that the same or similar parts of the above embodiments can be referenced to each other, and the contents not described in detail in some embodiments can refer to the same or similar contents in other embodiments.

[0338] It should be noted that, in the description of the present invention, the terms "first", "second", etc. are used for descriptive purposes only and should not be understood as indicating or implying relative importance. In addition, in the description of the present invention, unless otherwise specified, the meaning of "plurality" is at least two.

[0339] Any process or method description in a flowchart or otherwise described herein may be understood to represent a module, segment or portion of code comprising one or more executable instructions for implementing the steps of a specific logical function or process, and the scope of the preferred embodiments of the present invention includes alternative implementations in which functions may be performed out of the order shown or discussed, including performing functions in a substantially simultaneous manner or in the reverse order depending on the functions involved, which should be understood by those skilled in the art to which the embodiments of the present invention pertain.

[0340] It should be understood that various parts of the present invention can be implemented using hardware, software, firmware, or a combination thereof. In the above-described embodiments, multiple steps or methods can be implemented using software or firmware stored in a memory and executed by a suitable instruction execution system. For example, if implemented using hardware, as in another embodiment, any one of the following technologies known in the art or a combination thereof can be used: a discrete logic circuit having a logic gate circuit for implementing a logic function on a data signal, an application-specific integrated circuit having a suitable combination of logic gate circuits, a programmable gate array (PGA), a field programmable gate array (FPGA), etc.

[0341] Those skilled in the art will understand that all or part of the steps in the method of the above embodiment can be completed by instructing related hardware through a program, and the program can be stored in a computer-readable storage medium. When the program is executed, it includes one or a combination of the steps of the method embodiment.

[0342] In addition, the functional units in the various embodiments of the present invention may be integrated into a single processing module, or each unit may exist physically separately, or two or more units may be integrated into a single module. The aforementioned integrated modules may be implemented in the form of hardware or in the form of software functional modules. If the integrated modules are implemented in the form of software functional modules and sold or used as independent products, they may also be stored in a computer-readable storage medium.

[0343] The storage medium mentioned above can be a read-only memory, a magnetic disk or an optical disk, etc.

[0344] Throughout this specification, reference to terms such as "one embodiment," "some embodiments," "examples," "specific examples," or "some examples" means that a specific feature, structure, material, or characteristic described in conjunction with that embodiment or example is included in at least one embodiment or example of the present invention. In this specification, schematic representations of the above terms do not necessarily refer to the same embodiment or example. Furthermore, the specific features, structures, materials, or characteristics described may be combined in any suitable manner in any one or more embodiments or examples.

[0345] Although embodiments of the present invention have been shown and described above, it is understood that the above embodiments are exemplary and are not to be construed as limitations of the present invention and that those skilled in the art may change, modify, replace and vary the above embodiments within the scope of the present invention.

Claims

1. A single-phase fault handling and islanding detection system, characterized in that: include: The parallel active compensation device and arc suppression coil are connected between the neutral point of the transformer and the ground; A zero-sequence current transformer is provided on each feeder and the feeder to which each distributed generation unit is connected, wherein the feeder is connected in parallel to the primary side of the transformer via a busbar; The control device is connected to the active compensation device, arc suppression coil, zero-sequence current transformer and busbar respectively, and is used to: Determine whether a single-phase fault has occurred based on the amplitude and phase of the grid zero-sequence voltage; According to the phase shift trajectory of the grid zero-sequence voltage, the fault phase and single-phase fault type are identified; Selecting different arc extinguishing paths according to the single-phase fault type; Calculate the zero-sequence admittance of each feeder based on the zero-sequence voltage of the grid and the zero-sequence current of each feeder; According to the zero-sequence admittance of each feeder, the specific line and section where the single-phase fault occurs are determined; Isolate the faulty line or section and initiate islanding detection, specifically for: When the preset conditions are met, the zero-sequence voltage phase jump identification method is selected for islanding detection; the preset conditions include: the amplitude of the zero-sequence voltage on the distributed generation unit side is less than the first threshold, and the resistance value of the ground transition resistor is greater than the second threshold; When the preset conditions are not met, the zero-sequence admittance jump identification method is used for islanding detection.

2. A single-phase fault handling and islanding detection method, applied to a control device, wherein the control device is provided in the system according to claim 1, characterized in that: include: Determine whether a single-phase fault has occurred based on the amplitude and phase of the grid zero-sequence voltage; According to the phase shift trajectory of the grid zero-sequence voltage, the fault phase and single-phase fault type are identified; Selecting different arc extinguishing paths according to the single-phase fault type; Calculate the zero-sequence admittance of each feeder based on the zero-sequence voltage of the grid and the zero-sequence current of each feeder; According to the zero-sequence admittance of each feeder, the specific line and section where the single-phase fault occurs are determined; Isolate the faulty line or section and initiate islanding detection, including: When the preset conditions are met, the zero-sequence voltage phase jump identification method is selected for islanding detection; the preset conditions include: the amplitude of the zero-sequence voltage on the distributed generation unit side is less than the first threshold, and the resistance value of the ground transition resistor is greater than the second threshold; When the preset conditions are not met, the zero-sequence admittance jump identification method is used for islanding detection.

3. The method according to claim 2, characterized in that The determining whether a single-phase fault occurs based on the amplitude and phase of the zero-sequence voltage of the power grid includes: Obtain the system's ground insulation parameters; Determining a fault threshold according to the ground insulation parameter, wherein the fault threshold is an operating boundary of the amplitude and phase of the grid zero-sequence voltage when the system is operating normally; Real-time measurement of the amplitude and phase of the current grid zero-sequence voltage; If any feeder is grounded or disconnected, causing the asymmetry of the three phases to the ground of the system to change, and the amplitude or phase of the zero sequence voltage of the power grid exceeds the fault threshold, it is determined that a single-phase fault has occurred.

4. The method according to claim 2, characterized in that The method of identifying the type of single-phase fault according to the phase offset trajectory of the grid zero-sequence voltage includes: When a single-phase fault is determined to have occurred, the phase offset trajectory of the zero-sequence voltage of the power grid at the current moment is obtained; Search the pre-stored correspondence table for the single-phase fault type corresponding to the phase offset trajectory obtained at the current moment; the single-phase fault types include at least: non-disconnected grounding fault, disconnected non-grounding fault, disconnected power supply side grounding fault and disconnected load side grounding fault.

5. The method according to claim 4, characterized in that The corresponding relationship table is obtained by the following method, including: During normal system operation, the system's ground insulation parameters are obtained in near real time; Substitute the real-time ground insulation parameters into the pre-stored phasor function for calculation to obtain the phase offset trajectory of the grid zero-sequence voltage. Each phasor function corresponds to a single-phase fault type, and the single-phase fault type corresponds to the phase offset trajectory one by one. The phase offset trajectory is stored correspondingly under the phasor function to establish a corresponding relationship table between the phase offset trajectory and the single-phase fault type; When the system's ground insulation parameters are updated, the phase shift trajectory of the grid zero-sequence voltage is recalculated based on the updated ground insulation parameters; The recalculated phase offset trajectory data is stored in the corresponding relationship table.

6. The method according to claim 4, characterized in that The selecting different arc extinguishing paths according to the single-phase fault type includes: The non-disconnected line grounding fault and the disconnected line power supply side grounding fault are defined as forward faults, and the disconnected line non-grounding fault and the disconnected line load side grounding fault are defined as reverse faults; For a forward fault, the voltage of the fault phase is zero after compensation by the neutral point injection current, and the voltage of the non-fault phase reaches the line voltage level. At the same time, the zero-sequence voltage of the grid and the positive-sequence voltage of the fault phase are in the same magnitude and opposite direction, and the residual current at the grounding point is close to zero after being fully compensated. For reverse faults, after compensation by neutral point injection current, the fault phase voltage meets the first preset condition, the non-fault phase voltage meets the second preset condition, the grid zero-sequence voltage meets the third preset condition, and the residual current at the load-side grounding point is close to zero after being fully compensated; The first preset condition includes: the fault phase voltage reaches 1.5 times the positive sequence voltage of the fault phase and the phases are consistent; the second preset condition includes: the non-fault phase voltage is 0.866 times the respective positive sequence voltages and the phases are opposite to each other; the third preset condition includes: the zero sequence voltage of the power grid is 0.5 times the positive sequence voltage of the fault phase and the phases are consistent.

7. The method according to claim 2, characterized in that Calculating the zero-sequence admittance of each feeder based on the zero-sequence voltage of the power grid and the zero-sequence current of each feeder includes: When the arc is extinguished, two sets of zero-sequence voltages and the measured values ​​of the zero-sequence current of each feeder under each set of zero-sequence voltages are obtained simultaneously by injecting current step by step from the neutral point. After the zero-sequence voltage of the power grid is regulated to reach a target value and residual current at the grounding point is eliminated, the zero-sequence admittance of each feeder is calculated based on the measured value.

8. The method according to claim 7, characterized in that Determining the specific line and section where the single-phase fault occurs based on the zero-sequence admittance of each feeder includes: Compare the zero-sequence admittance of each feeder with the zero-sequence admittance of the same line during normal system operation; For any feeder, if the zero-sequence admittance's argument exceeds the argument threshold, the current feeder is determined to be a fault line; if the zero-sequence admittance's argument is less than or equal to the argument threshold, the current feeder is determined to be a non-fault line. For any section on any feeder, if the amplitude of the upstream zero-sequence admittance is different from that during normal system operation, while the amplitude of the downstream zero-sequence admittance is the same as that during normal system operation, the current section is determined to be a fault section; otherwise, the current section is determined to be a non-fault section.

9. The method according to claim 2, characterized in that The zero-sequence voltage phase jump identification method is specifically as follows: If the phase change pattern of the zero-sequence voltage on any distributed generation unit side is reversed before and after the fault line or section is isolated, the distributed generation unit is determined to be operating in island mode; and / or, The zero-sequence admittance jump identification method is specifically as follows: If the difference in the amplitude of the zero-sequence admittance on any distributed generation unit side before and after the fault line or section is isolated is greater than a first preset value, and the difference in the argument of the zero-sequence admittance is greater than a second preset value, it is determined that the distributed generation unit is operating in island mode.

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