CN114859175A

CN114859175A - Single-phase fault handling and island detection system and method

Info

Publication number: CN114859175A
Application number: CN202210509537.5A
Authority: CN
Inventors: 王宇波
Original assignee: Individual
Current assignee: Individual
Priority date: 2022-05-11
Filing date: 2022-05-11
Publication date: 2022-08-05

Abstract

The invention relates to a single-phase fault handling and island detection system and method, the method judges whether a single-phase fault occurs in a power grid, identifies the phase and type of the fault when the single-phase fault is judged to occur, and selects different arc extinguishing paths according to different single-phase fault types, thereby effectively realizing the handling of the single-phase fault of the power grid; meanwhile, according to the zero sequence admittance of each feeder line, specific lines and sections with single-phase faults are determined, then the faulty lines or sections are isolated, island detection is started, and therefore the single-phase fault handling technology and the island detection technology are fused together.

Description

Single-phase fault handling and island detection system and method

Technical Field

The invention relates to the technical field of intelligent power grids, in particular to a single-phase fault handling and island detection system and method.

Background

New energy (mainly photovoltaic and wind power) generation gradually replaces traditional energy and occupies a proportion or more than 50% in the future, and a large amount of new energy micro-grids are connected to a traditional large power grid. The traditional power system mainly takes thermal power as a main power, and has the remarkable characteristic that the power output is stable, the system is called as an inertial system in the industry, new energy is influenced by non-constant illumination and wind power, the output has the characteristic of intermittence, or the output power is unstable, and the integration of new and old power grids needs innovative technology to realize, so that the traditional power system is a hot research direction at home and abroad at present.

The single-phase fault handling and island identification technology is a key technology for the reliability and safety of power supply of a novel power system in two matters.

The Single Phase Fault (Single Phase Fault) accounts for more than 80% of the faults of the power distribution network, wherein the faults are mainly non-disconnection grounding faults, disconnection non-grounding faults are common, and the grounding faults on the side of a disconnection power supply and the grounding faults on the side of a disconnection load are solved.

The existing ground fault handling technology has several problems:

the reliability and the safety of power supply cannot be obtained at the same time;

the fault detection sensitivity is insufficient, and a large part of faults are in a detection blind area and cannot be identified;

failure type identification is not provided (non-disconnection ground fault, disconnection non-ground fault, disconnection power supply side ground fault, and disconnection load side ground fault): the method mainly comprises the following steps of mainly solving the non-disconnection ground fault, and also commonly solving the disconnection ungrounded fault, the disconnection power supply side ground fault and the disconnection load side ground fault;

the effect of eliminating grounding residual current (arc extinction) is poor, and the grounding point current is usually expressed as high-energy arc light, which is a direct cause of personal electric shock, firing in grassland forests and the like;

the reliability of fault line/section positioning is insufficient, and the prior art can basically meet the requirements of line selection and positioning for low-resistance ground faults; for high-resistance faults of more than 1000 ohms, the accuracy of line selection and positioning in the traditional technology is obviously reduced, and the problem of false alarm and misjudgment is frequent, which is also one of the international problems in the current industry.

Islanding or island Effect (island Effect) refers to an Islanding state in which when a large grid line carrying a new energy microgrid is disconnected from a bus for some reasons (such as line faults, overhaul and the like), one or more microgrids connected to the disconnected line do not trigger corresponding protection devices to act because the upstream microgrid cannot be detected to be in an off-grid state, and continue to operate independently with related loads.

The purpose of islanding detection is mainly to ensure the safety of grid equipment, user equipment and line maintenance personnel, because:

when the power of the microgrid is not matched with the power required by the load, the voltage and the frequency exceed the specified allowable range, and the electric equipment can be damaged;

when a circuit breaker of a micro-grid connected to a large power grid is not disconnected, the large power grid is still electrified, so that electric shock of maintenance personnel can be caused, and the life safety of line workers is seriously threatened;

the micro-grid continuously supplies power to the large power grid, so that the sensitivity of the relay protection equipment related to the line is reduced, and the normal action of the protection equipment is interfered.

In addition to normal maintenance, islanding is mainly related to faulty line removal, and post-fault islanding detection should be continued as a large grid fault, which is closely related to each other, since accurate positioning of the faulty line or section is a prerequisite for correct initiation of islanding detection.

The current island detection technical scheme cannot be obtained in technical reliability and application economy, so that the popularization and application range is limited, and the method has great elbow influence on large-scale development of new energy.

The existing islanding detection technology has the following objective problems probably:

the cost is high, and the application range is limited, such as the power carrier communication technology, and the equipment application cost is high;

the detection blind area is large, such as the technology of utilizing voltage, frequency, phase and harmonic content;

the method has negative influence on power grid equipment and power quality, such as the technical scheme of active interference injection.

In a word, the existing single-phase fault handling technology and the existing island detection technology completely belong to two categories, are mutually independent in technology, have high total application cost, and have obvious respective technical defects.

Disclosure of Invention

In view of this, an object of the present invention is to provide a single-phase fault handling and islanding detection system and method, so as to solve the problems that in the prior art, a single-phase fault handling technology and an islanding detection technology completely belong to two categories, are mutually independent in technology, and cannot achieve single-phase fault handling and islanding detection at the same time.

According to a first aspect of embodiments of the present invention, there is provided a single-phase fault handling and islanding detection system, comprising:

the active compensation device and the arc suppression coil are connected in parallel and are connected between the neutral point of the transformer and the ground;

the zero sequence current transformer is arranged on each feeder line and the feeder line connected with each distributed power generation unit, and the feeder lines are connected in parallel to the primary side of the transformer through buses;

and the control device is respectively connected with the active compensation device, the arc suppression coil, the zero sequence current transformer and the bus and is used for:

judging whether a single-phase fault occurs according to the amplitude and the phase of the zero-sequence voltage of the power grid;

identifying a fault phase and a single-phase fault type according to a phase deviation track of zero-sequence voltage of a power grid;

selecting different arc extinguishing paths according to the single-phase fault type;

calculating the zero sequence admittance of each feeder line according to the zero sequence voltage of the power grid and the zero sequence current of each feeder line;

determining specific lines and sections with single-phase faults according to the zero sequence admittance of each feeder line;

and isolating the fault line or section and starting island detection.

According to a second aspect of the embodiments of the present invention, there is provided a single-phase fault handling and islanding detection method, including:

and isolating the fault line or section and starting island detection.

The technical scheme provided by the embodiment of the invention can have the following beneficial effects:

the method has the advantages that the single-phase fault of the power grid is judged, the single-phase fault type is identified when the single-phase fault is judged to occur, and different arc extinguishing paths are selected according to different single-phase fault types, so that the single-phase fault of the power grid is effectively treated; meanwhile, according to the zero sequence admittance of each feeder line, a specific line and a section with a single-phase fault are determined, then the fault line or the section is isolated, and island detection is started, so that a single-phase fault disposal technology and an island detection technology are fused together.

It is to be understood that both the foregoing general description and the following detailed description are exemplary and explanatory only and are not restrictive of the invention, as claimed.

Drawings

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.

FIG. 1 is a circuit schematic diagram illustrating a single phase fault handling and islanding detection system in accordance with an exemplary embodiment;

FIG. 2 is a flow diagram illustrating a single phase fault handling and islanding detection method in accordance with an exemplary embodiment;

FIG. 3 is a diagram of a primary system network upon failure, shown in accordance with an exemplary embodiment;

FIG. 4 is an equivalent circuit diagram of FIG. 3, shown in accordance with an exemplary embodiment;

fig. 5 is a resonance plot of zero sequence voltage U0 shown in accordance with an exemplary embodiment;

FIG. 6 is an equivalent graph of FIG. 5 shown in accordance with an exemplary embodiment;

FIG. 7 illustrates an operational boundary of zero sequence voltage U0 according to an exemplary embodiment;

FIG. 8 illustrates a U0 phase offset trajectory at a non-disconnect ground fault in accordance with an exemplary embodiment;

FIG. 9 illustrates a U0 phase offset trajectory during a broken wire ungrounded fault in accordance with an exemplary embodiment;

FIG. 10 illustrates a U0 phase offset trace at a line break power supply side ground fault in accordance with an exemplary embodiment;

FIG. 11 illustrates a U0 phase offset trajectory at a break load side ground fault in accordance with an exemplary embodiment;

FIG. 12 is a U0 phase offset trace illustrating a line break power supply side ground fault with the system fully compensated in accordance with an exemplary embodiment;

FIG. 13 is a U0 phase offset trace illustrating a broken load side ground fault with the system fully compensated in accordance with an exemplary embodiment;

FIG. 14 is a schematic diagram illustrating arc extinction upon a forward fault, according to an exemplary embodiment;

FIG. 15 is a schematic diagram illustrating arc extinction upon a reverse fault, according to an exemplary embodiment;

FIG. 16 is a graph illustrating zero sequence admittance magnitude angle of a feed line as a function of transition resistance value in accordance with an exemplary embodiment;

FIG. 17 is a graph illustrating magnitude of zero sequence admittance of a feed line as a function of resistance of a transition resistor, according to an exemplary embodiment;

FIG. 18 is a diagram illustrating a zero sequence voltage phase jump identification islanding schematic in accordance with an exemplary embodiment;

FIG. 19 is an equivalent circuit showing a distributed generation unit DG upstream of a point of failure, prior to the removal of the faulted line, in accordance with an exemplary embodiment;

FIG. 20 is an equivalent circuit of a distributed generation unit DG downstream of the point of failure, prior to the removal of the faulted line, according to an exemplary embodiment;

fig. 21 illustrates an islanding equivalent system after a fault line is removed when a non-broken ground fault DG is upstream of a fault point in accordance with an exemplary embodiment;

fig. 22 is an island equivalent system after the fault line is cut when the non-broken ground fault DG is downstream of the fault point, according to an exemplary embodiment;

fig. 23 illustrates an islanding equivalent system after a fault line is cut off when a disconnection ungrounded fault DG is upstream of a fault point according to an exemplary embodiment;

fig. 24 illustrates an islanding equivalent system after a fault line is cut off when a disconnection ungrounded fault DG is located downstream of a fault point according to an exemplary embodiment;

fig. 25 illustrates an islanding equivalent system after a fault line is cut off when a fault DG on the side of a line break power source is upstream of a fault point according to an exemplary embodiment;

fig. 26 illustrates an islanding equivalent system after a fault line is cut off when a fault DG on the side of a line break power source is downstream of a fault point according to an exemplary embodiment;

fig. 27 is a diagram illustrating an islanding equivalent system after a fault line is removed when a broken load side ground fault DG is upstream of a fault point, in accordance with an exemplary embodiment;

fig. 28 is a diagram illustrating an islanding equivalent system after a fault line is removed when a disconnection load side grounding fault DG is located downstream of a fault point, according to an exemplary embodiment;

fig. 29 is a schematic diagram illustrating a DG side zero sequence voltage phase jump islanding detection according to an exemplary embodiment;

fig. 30 is a schematic diagram illustrating a DG side zero sequence voltage phase jump islanding detection according to another exemplary embodiment.

Detailed Description

Reference will now be made in detail to the exemplary embodiments, examples of which are illustrated in the accompanying drawings. When the following description refers to the accompanying drawings, like numbers in different drawings represent the same or similar elements unless otherwise indicated. The implementations described in the following exemplary examples do not represent all implementations consistent with the present invention. Rather, they are merely examples of apparatus and methods consistent with certain aspects of the invention, as detailed in the appended claims.

Example one

Fig. 1 is a circuit schematic diagram illustrating a single-phase fault handling and islanding detection system according to an exemplary embodiment, as shown in fig. 1, the system including:

the zero sequence current transformer is arranged on each feeder line and the feeder line hung and connected with each distributed power generation unit, and the feeder lines are connected in parallel to the primary side of the transformer through a bus;

and isolating the fault line or section and starting island detection.

It should be noted that, the technical solution provided by this embodiment is applicable to power grids of various voltage classes, including: high voltage transmission networks, medium voltage distribution networks (the main network responsible for new energy access), low voltage distribution networks. Practice proves that the technical scheme provided by the embodiment has the best effect when being suitable for a medium-voltage distribution network (6-66 kV). Therefore, the technical scheme provided by the embodiment is preferably suitable for a medium-voltage distribution network (6-66 kV).

Referring to fig. 1, in order to better understand the circuit structure of such a single-phase fault handling and islanding detection system provided by the present embodiment, the circuit structure is explained in detail as follows:

1. when the system works normally, the low-voltage side of a main transformer of the 110kV transformer substation is grounded through an active compensation device and an arc suppression coil which are connected in parallel; the transformer neutral point of the 10kV side of the distributed power generation unit (DG _1 and DG _2.. times. DG _ n in FIG. 2) is not grounded.

2. N (n >1) feeder lines are connected in parallel on the 10kV bus, and a main circuit breaker (CB 10 and CB20.. multidot.CBn 0 in fig. 2) and a zero-sequence current transformer (CT _1 and CT _2.. multidot.CT _ n in fig. 2) are arranged at an outlet of each feeder line and used for measuring zero-sequence current.

3. Each feeder is provided with a plurality of circuit breakers, and the feeder is divided into a plurality of sections, for example, a line between the circuit breakers CB11 and CB12 in fig. 2 belongs to one section, and a line between the circuit breakers CB12 and CB13 belongs to one section.

4. When each distributed power generation unit (for example, photovoltaic, wind power and the like) is hung on a feeder line, the distributed power generation unit is hung on the feeder line through one breaker, for example, DG _1 is hung on a first feeder line through a breaker CB11, and DG _2 is hung on a second feeder line through a breaker CB 21.

5. Measuring points (measuring point 1, measuring point 2.... measuring point n in fig. 1) in fig. 1 refer to zero-sequence voltage and zero-sequence current measuring positions of distributed power generation unit access points; the breaker is used for opening and closing the line (optional high-precision zero-sequence component measurement function); the arc suppression coil and the ungrounded coil refer to a transformer neutral point grounding mode; the active compensation device is an active inverter device for compensating residual current of the grounding point; the control device is used for collecting measurement data (zero sequence current measured by a zero sequence current transformer at each feeder line outlet, bus PT opening triangular voltage, three-phase voltage and arc suppression coil inductance current measurement values are collected to the control device in real time), and outputting an instruction after processing by a built-in algorithm; 1-3 are positions of the simulated line with faults; NO means tie switch (normally open).

6. Data measured by the measuring points (measuring point 1 and measuring point 2...... measuring point n in fig. 1) in fig. 1 are not directly communicated with the substation control device, because the communication involves potential problems such as increased cost, information safety and incapability of transmitting data after the communication equipment fails. The measuring point data is directly transmitted to the control device of the breaker CBn0 on site, and the judgment result is transmitted to a remote main station from the control device of the CBn 0.

The single-phase fault types that the control device can identify at least comprise: a non-disconnection ground fault, a disconnection non-ground fault, a disconnection power supply side ground fault, and a disconnection load side ground fault.

It should be noted that, in the technical solution provided in this embodiment, the islanding detection is placed after the single-phase fault handling, because:

the islanding effect occurs only when the line including the distributed DG is cut off under the condition that only the fault condition is considered, and therefore, it can be considered that the islanding detection procedure is started after the fault line or section isolation is completed in the fault handling process.

If a non-fault line is mistaken for a fault line and cut off, the distributed DG of the line exits from the large power grid after detecting the island effect, and in practical application, the condition needs to be avoided because the load power balance is influenced, and further, the voltage and the frequency exceed the set upper and lower limits, which may cause a large-area power failure accident of the system.

Therefore, islanding detection is actually a continuation of a fault handling process, and is closely related to the efficiency and effect of fault handling, and especially accurate fault line selection and positioning are prerequisites for accurate islanding detection.

It can be understood that, according to the technical scheme provided by this embodiment, by determining whether a single-phase fault occurs in the power grid, and identifying the phase of the fault and the type of the single-phase fault when it is determined that the single-phase fault occurs, different arc extinguishing paths are selected according to different single-phase fault types, thereby effectively achieving the disposal of the single-phase fault in the power grid; meanwhile, according to the zero sequence admittance of each feeder line, a specific line and a section with a single-phase fault are determined, then the fault line or the section is isolated, and island detection is started, so that a single-phase fault disposal technology and an island detection technology are fused together.

Example two

Fig. 2 is a flowchart illustrating a single-phase fault handling and islanding detection method according to an exemplary embodiment, which is applied to a control device provided in the system according to the first embodiment, as shown in fig. 2, and includes:

step S11, judging whether a single-phase fault occurs according to the amplitude and the phase of the zero-sequence voltage of the power grid;

step S12, identifying a fault phase and a single-phase fault type according to the phase deviation track of the zero-sequence voltage of the power grid;

step S13, selecting different arc extinguishing paths according to the single-phase fault type;

step S14, calculating the zero sequence admittance of each feeder line according to the zero sequence voltage of the power grid and the zero sequence current of each feeder line;

step S15, determining specific lines and sections with single-phase faults according to the zero sequence admittance of each feeder line;

and step S16, isolating the fault line or section and starting island detection.

It can be understood that, according to the technical scheme provided by this embodiment, by determining whether a single-phase fault occurs in the power grid, identifying the type of the single-phase fault when the single-phase fault is determined to occur, and selecting different arc extinguishing paths according to different single-phase fault types, the handling of the single-phase fault of the power grid is effectively realized; meanwhile, according to the zero sequence admittance of each feeder line, a specific line and a section with a single-phase fault are determined, then the fault line or the section is isolated, and island detection is started, so that a single-phase fault disposal technology and an island detection technology are fused together.

In specific practice, step S11 "determine whether a single-phase fault occurs according to the amplitude and the phase of the zero-sequence voltage of the power grid", there are various implementation manners, and one implementation manner may be:

acquiring insulation parameters to the ground of a system (comprising system asymmetry k, system damping rate d, system detuning degree v, system capacitance current Ic and resonance voltage Uen.max);

determining a fault threshold value according to the ground insulation parameters, wherein the fault threshold value is an operation boundary of the amplitude and the phase of the zero-sequence voltage of the power grid when the system operates normally;

measuring the amplitude and the phase of the zero-sequence voltage of the current power grid in real time;

if any feeder line is grounded or disconnected, the three-phase-to-ground asymmetry of the system is changed, and the amplitude or the phase of the zero-sequence voltage of the power grid exceeds the fault threshold value, the single-phase fault is judged to occur.

It should be noted that, during normal operation of the system, when the zero-sequence voltage variation of the power grid due to line variation or device switching exceeds a set value, the control device is triggered to update the insulation parameter of the measurement system and reset the threshold value until the system fails, so that the fault threshold value provided in this embodiment is a dynamic threshold value, and the threshold value does not need to be manually set or modified.

It is understood that the single-phase fault mentioned in the present embodiment may occur in any feeder of the single-phase fault handling and islanding detection system shown in fig. 1.

For any feeder, FIG. 3 is a primary system network diagram in case of failure, by combining K ₁ 、K ₂ 、 K ₃ The four types of single-phase faults previously described can be simulated. FIG. 4 is an equivalent circuit diagram corresponding to FIG. 3, again S ₁ 、S ₂ 、S ₃ Different combinations can simulate different system operation conditions.

In fig. 3, the meaning of each parameter is as follows:

tr-finger transformer

Neutral point on low-voltage side of N-finger transformer

L _P Finger arc suppression coil inductor

U ₀ Is the zero sequence voltage of the system

U _a1 、a ² U _a1 、aU _a1 Is a three-phase positive sequence voltage of the system, wherein a is a rotation factor 1 & lt 120 DEG;

A. b, C is the system three-phase voltage

Z ₁₂ For positive and negative sequence impedance of line

G _0a 、G _0b 、G _0c Conductance for line to ground leakage

B _ca 、B _cb 、B _cc For line to ground accommodation

Y _f For admittance of ground resistance

K ₁ 、K ₂ 、K ₃ Simulating a switch for a fault

In fig. 4, the meaning of each parameter is as follows:

B _LP is a neutral point induction

G _ns Equivalent conductance is connected in parallel to the neutral point

X _tr For equivalent leakage reactance of transformer

G ₀ Is the total conductance of the system to ground

B _LP For total accommodation of system to ground

S ₁ 、S ₂ 、S ₃ For simulating earthing switch

I _uf 、I _uc 、I _ud As a virtual current source

Y _uf 、Y _uc 、Y _ud For equivalent parallel admittance of corresponding virtual current source

In practical applications, the three phase-to-ground zero-sequence admittances are not completely equal due to the line arrangement when the system is in normal operation, so that a certain zero-sequence component always exists. Since the lines are accommodated much larger than the leakage conductance to ground, the three-phase asymmetry tends to depend on the three-phase capacitance, so the leakage resistance is negligible when calculating the asymmetry. Meanwhile, the series impedance of the circuit is smaller than the transition resistance, and the equivalent leakage reactance is far smaller than the arc suppression coil impedance, so that the series impedance can be ignored in the actual engineering.

K in FIG. 3 ₁ 、K ₂ Closure, K ₃ Disconnection means normal operation of the system, corresponding to S in fig. 4 ₁ 、S ₃ Breaking, S ₂ A closed condition. If the system fault state is defined, the boundary range of normal operation is necessarily determined, and it can be known from fig. 3 that the neutral point is grounded through the arc suppression coil during normal operation, and the normal operation is set to be in a moderate overcompensation mode, and the zero sequence current is the sum of the capacitance current to ground and the leakage active current.

According to kirchhoff's law:

only the positive sequence voltage (U) is considered in equation (1) _a1 、a ² U _a1 、aU _a1 Three-phase positive sequence voltage of the system) and zero sequence voltage U ₀ The negative sequence voltage is small and can be ignored during normal operation;

wherein: ya, Yb, Yc and Yn respectively refer to three-phase ground zero-sequence admittance and neutral point zero-sequence admittance;

u is obtained from the formula (1) ₀ Per unit value u ₀ The calculation formula of (2) is as follows:

after further conditioning, the resonance curve of U0 is obtained:

wherein the content of the first and second substances,

k is the system asymmetry:

d is the system damping rate:

v is the system detuning degree:

fig. 5 shows an image obtained from equation (3) and having the function u0 ═ f (v).

In fig. 5, assuming that the damping rate d is constant, when the system detuning degree v is 0, the maximum value u0.max is obtained; when v ± ∞, U0 is the minimum value of zero; it can be seen from the figure that each U0 corresponds to v values which are opposite to each other, and the function image of U0 obtained by combining formula (3) with v is shown in fig. 6 (the large circle in fig. 6 is transformed from the resonance curve in fig. 5, and the large circle in fig. 6 corresponds to the representation form of the resonance curve in fig. 5 under polar coordinates).

The vectors of U01 and U02 are obtained by changing neutral point parameters, the inductive currents IL1 and IL2 are obtained by measurement, and the system capacitance current Ic, the resonance voltage Uen.max, the system damping rate d, the current detuning degree v, the system asymmetry degree k and the phase angle thereof can be obtained by calculation according to the trigonometric function relation in figure 6.

In a specified coordinate system, a geometric triangle is established between the vector points U01 and U02 and the reference point n, the points U01 and U02 are positioned on a circumcircle of the triangle, the circle center is o, and the vector argument passing through the reference points n and o is phi ₀ . When the system detuning degree v changes from negative infinity to positive infinity, U0 will run along the circumscribed circle boundary, and the diameter passing through the center of the circle and the point n is U0.max, i.e. the harmonicAnd (5) vibrating voltage.

By establishing auxiliary lines, the system detuning degrees are mapped to the intersection points of the auxiliary lines one by one, and U01, U02, U0.max, Up and Uq correspond to v respectively ₁ 、v ₂ 、v ₀ 、v _p And v _q Also, U0i (i ═ 01, 02, max, p, q) is defined as a distance L1, L2, Lm, Lp, Lq; the distances from vi (i ═ 1, 2, p, q) to v0 are defined as Lv1, Lv2, Lv p, Lv q.

Therefore, the system ground insulation parameter can be calculated.

System capacitance current Ic:

the resonance voltage is uen.max (u0.max) and its phase angle

Degree of system detuning v:

system damping rate d:

system is notDegree of symmetry k and phase angle thereof

k＝U _en，max ·d

And the calculated Ic, uen.max, k, d, v can establish a current U0 running track circle in normal running as shown in FIG. 7.

It should be noted that the large circle in fig. 7 is a resonance curve of U0, and the small circle is an error fluctuation range in consideration of the measurement error of U0, and the error fluctuation range takes into consideration the amplitude and the phase angle of 360 degrees. The abscissa and ordinate in fig. 7 represent the component of U0 on the abscissa and ordinate, while the abscissa represents the starting point (line) at which the phase angle of U0 is 0.

Referring to fig. 7, under current parameter conditions, when U0 is always running within the measurement trigger threshold along the fault trigger threshold boundary, the system is in normal operation (U01 and U02); when the measurement trigger threshold is exceeded while the fault trigger threshold is crossed, the system is in a fault state (U03). In summary, when the amplitude and phase of U0 go beyond the great circle in fig. 7 together, it is determined that the system has a single-phase fault.

In specific practice, in step S12, "identify a single-phase fault type according to a phase offset trajectory of a zero-sequence voltage of a power grid", there are multiple implementation manners, where one implementation manner may be:

when the single-phase fault is judged to occur, acquiring a phase deviation track of the zero-sequence voltage of the power grid at the current moment;

searching a pre-stored corresponding relation table for the single-phase fault type corresponding to the phase offset track acquired at the current moment; the single-phase fault types include at least: a non-disconnection ground fault, a disconnection power source side ground fault, and a disconnection load side ground fault.

The corresponding relation table is obtained by the following method, including:

during the normal operation of the system, acquiring the ground insulation parameters of the system in near real time;

substituting the ground insulation parameters acquired in real time into prestored phasor functions for calculation to obtain phase deviation tracks of zero-sequence voltage of the power grid, wherein each phasor function corresponds to one single-phase fault type, and the single-phase fault types correspond to the phase deviation tracks one by one;

correspondingly storing the phase deviation track in the phasor function to establish a corresponding relation table of the phase deviation track and the single-phase fault type;

when the ground insulation parameters of the system are updated, the phase deviation track of the zero sequence voltage of the power grid is obtained through recalculation according to the updated insulation parameters;

and correspondingly storing the recalculated phase shift track data in the corresponding relation table.

In order to explain the correspondence relationship among the phasor function, the phase offset trajectory and the single-phase fault type, the following is specifically explained with reference to fig. 8 to 11:

1. non-broken line single phase earth fault

K in FIG. 3 ₁ 、K ₂ 、K ₃ The closing of the two phases indicates that the A phase of the system has a non-disconnection single-phase earth fault, corresponding to S in figure 4 ₁ 、S ₂ Closure, S ₃ And open condition. The equation is derived from kirchhoff's current law:

the expression of U0 at the time of failure is obtained from equation (4):

wherein:

wherein:

fig. 8 shows a functional image of u0 phasors when the non-disconnection fault obtained by equation (6) occurs in A, B, C three phases.

Fig. 8 is a U0 phase shift trace when a non-disconnection ground fault occurs in the system of the system. Line voltage U, for example overcompensation _AB As the reference phase, the phase interval of U0 is anticlockwise 150-240 degrees when A phase fails, the phase interval of U0 is anticlockwise 30-120 degrees when B phase fails, the phase interval of U0 is anticlockwise 270-360 degrees when C phase fails, and the phases are not overlapped with each other, so that the phase type and the fault type of the fault can be accurately identified. In actual operation, the arc suppression coil is usually set to be moderately overcompensated, and the closer the U0 phase interval is to full compensation, the narrower the U0 phase interval is, the higher the resolution is.

2. Disconnection and non-grounding fault

K in FIG. 3 ₁ 、K ₂ 、K ₃ All open indicates that the A phase has broken line and is not grounded, corresponding to S in FIG. 4 ₂ 、S ₃ Closure, S ₁ And open condition. The equation is derived from kirchhoff's current law:

the expression of U0 at this time is derived from equation (7):

wherein n is a real number, d is a power grid damping rate when the system is not in fault, and represents a ratio of the zero sequence admittance at the downstream of the line break point to the total zero sequence admittance of the line.

Fig. 9 shows a functional image of u0 phasors when the disconnection/ground fault occurs in A, B, C three phases, respectively, as obtained from equation (9).

Fig. 9 is a U0 phase shift trace when a disconnection-ground fault occurs. Taking overcompensation as an example, as the degree of compensation approaches full compensation, the phase interval of U0 is clockwise 150-60 degrees when the phase A is disconnected; when the phase B is disconnected, the phase interval of U0 is clockwise 30-300 degrees; when the C phase is disconnected, the U0 phase sections are clockwise 270-180 degrees and have no overlap with each other and the non-disconnection ground fault of the figure 8, so that the two types of faults are distinguished with high accuracy and reliability, and the fault phase can be identified.

3. Ground fault of broken line power supply side

K in FIG. 3 ₁ 、K ₃ Closure, K ₂ Disconnection indicates that disconnection power supply side ground fault occurs in phase A, corresponding to S in FIG. 4 ₁ 、S ₂ 、S ₃ All closed. The equation is also derived from kirchhoff's current law:

an expression of U0 is derived from equation (10):

wherein

d' is the grid damping rate after the system fault, and a functional image of u0 phasors is shown in fig. 10 when the open line power source side earth fault occurs in A, B, C three phases from equation (12).

Fig. 10 shows a U0 phase shift trajectory (v-100%) at the time of a ground fault on the line break power supply side. As the ground transition resistance increases from zero to infinity, its trajectory trend is more similar to a non-open ground fault (fig. 8), but the phase shifts are not exactly the same for the same fault phase and the same transition resistance conditions. Identifying such faults first requires confirming whether the line is broken, which is illustrated in detail in fig. 9. Because the ground fault of the broken line power supply side consists of two independent states, namely, the broken line state firstly and then the grounding state, the U0 phase can have obvious abrupt change due to the switching of the two states, namely, the U0 phase jumps from the broken line non-grounding interval to the non-broken line grounding interval within a short time after the fault, and the two states can be reliably identified due to the fact that the two states have no overlapped phase.

4. Load side earth fault of broken wire

K in FIG. 3 ₂ 、K ₃ Closure, K ₁ Disconnection indicates that disconnection load-side ground fault occurs in phase a, corresponding to S in fig. 4 ₁ 、S ₂ 、S ₃ When both are closed, the equation is obtained according to kirchhoff's current law:

an expression of U0 is derived from equation (13):

fig. 11 shows a functional image of u0 phasors when the open-line load-side ground fault occurs in A, B, C three phases, respectively, from equation (15).

Fig. 11 shows a U0 phase shift trajectory (v-100%) at the time of a disconnection load-side ground fault. As the transition resistance gradually increases from zero to infinity, the U0 phase starts coinciding with the fault phase primary voltage phase, rotating counterclockwise until coinciding with the open-circuit-to-ground fault U0 phase. However, the U0 phases of the phase fault in fig. 11 have a large overlap with each other (the center intersection of fig. 11 is marked with a ray, and the phases overlap as it passes through the trajectory curves of the two phases), which has an effect on the sensitivity of further identifying the type of fault and the phase class, and the system identifies the fault phase when the first state is disconnected, and may not be consistent with the fault phase identified by the first state due to the U0 phase overlap when the second state is grounded.

Fig. 10 and 11 are both the case of system-100% overcompensation, and in practical applications, the system is usually in moderate overcompensation, i.e., closer to 0% full compensation, so that the compensation degree of the arc suppression coil needs to be tuned during operation to be close to the full compensation state, and the situation that the phases of U0 are overlapped can be avoided, as shown in fig. 12 and 13.

Fig. 12 and 13 are U0 phase deviation traces of the disconnection power source side ground fault and the disconnection load side ground fault when the system is fully compensated, respectively. The offset of each phase U0 is 90 degrees, and the phases are not overlapped and mixed with each other, so that the fault type and fault phase identification sensitivity is excellent. In practical application, the detuning degree v in the system ground insulation parameter is kept between 0% and-10%, so that U0 phase aliasing can be avoided, the identification sensitivity can reach the optimal level, and the closer the detuning degree is to 0%, the higher the sensitivity is. The detection sensitivity is undoubtedly influenced when the crowbar coil is operated under-or overcompensated to a severe extent due to irregular operation.

Step S12 is to perform regulation and control by the active compensation device after completing the fault type and phase identification, to ensure safety of the ground point and prevent the human body from being electrically contacted and the vegetation from being ignited, and to eliminate the ground point current to zero by injecting a current in a large reverse direction such as a ground residual current from the neutral point, and the arc light is not reignited because the ground point voltage is always lower than the arc recovery voltage, and the risk of the human body from being electrically contacted and the vegetation from being ignited is greatly reduced.

In a specific practice, step S13 "select different arc extinguishing paths according to the single-phase fault type", there are multiple implementations, and one implementation may be:

the non-disconnection ground fault and the disconnection power supply side ground fault are defined as forward faults, and the disconnection non-ground fault and the disconnection load side ground fault are defined as reverse faults.

1. For the forward fault, the voltage of the fault phase after current compensation is injected from the neutral point is zero, the non-fault phase voltage respectively reaches the line voltage level, meanwhile, the zero-sequence voltage of the power grid and the positive-sequence voltage of the fault phase are in the same large reverse direction, and the residual current of the grounding point is close to zero after complete compensation.

From fig. 4, equation (4) and equation (10), it can be seen that the grounding residual current is related to the grounding transition (Y in equations (4) and (10)) _f The residual current of the grounding point is the fault phase voltage Ua'. times.Y _f ，Y _f The magnitude of U0 is affected, the magnitude of U0 affects the magnitude of the fault phase voltage Ua '(Ua' is equal to the vector sum of U0 and Ua 1), therefore, the ground residual current is necessarily related to the transition resistance), the target injection current is equal and opposite to the ground residual current, taking the phase a fault as an example, the neutral point injection current I _ inj is expressed as:

wherein:

is U _a1 A phase angle;

is an asymmetric amplitude angle;

the voltage of the A phase of the fault phase is zero after current compensation is injected from the neutral point, the voltage of the non-fault phase respectively reaches the level of the line voltage, meanwhile, the zero sequence voltage and the positive sequence voltage of the fault phase are in equal and opposite directions (as shown in figure 14), and the residual current of the grounding point is close to zero after complete compensation.

2. For a reverse fault, the fault phase voltage meets a first preset condition after current compensation is injected from a neutral point, the non-fault phase voltage meets a second preset condition, the zero-sequence voltage of a power grid meets a third preset condition, and the residual current of a load side grounding point is close to zero after complete compensation;

the first preset condition includes: the fault phase voltage reaches 1.5 times of the fault phase positive sequence voltage and the phases are consistent; the second preset condition includes: the magnitude of the non-fault phase voltage is 0.866 times of the positive sequence voltage of each non-fault phase voltage, 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 of the positive sequence voltage of the fault phase, and the phases are consistent.

From fig. 4, equation (7) and equation (13), it can be seen that the residual grounding current is related to the grounding transition, the target injection current is in the same direction as the residual grounding current, and the neutral point injection current I _ inj is expressed by taking the phase a fault as an example:

wherein:

the voltage of the fault phase A phase reaches 1.5 times of the positive sequence voltage after the current compensation is injected from the neutral point, the magnitude of the non-fault phase voltage is 0.866 times of the positive sequence voltage of each fault phase, the phases are reversed, the magnitude of the zero sequence voltage is 0.5 times of the positive sequence voltage of the fault phase, the phases are consistent (as shown in figure 15), and the residual current of the side connection site of the load is close to zero after the complete compensation.

In a specific practice, in step S14, "calculate the zero sequence admittance of each feeder line according to the zero sequence voltage of the power grid and the zero sequence current of each feeder line", there are various implementation manners, and one implementation manner may be:

during arc extinction, two groups of zero-sequence voltages and a measured value of the zero-sequence current of each feeder line under each group of zero-sequence voltages are obtained simultaneously in a mode that the current is injected into a neutral point step by step;

and after the zero sequence voltage of the power grid is regulated and controlled to reach a target value and the residual current of the grounding point is eliminated, calculating the zero sequence admittance of each feeder line according to the measured value.

The real-time measured zero-sequence voltages and zero-sequence currents shown in fig. 2 are collected in a control device, and two sets of zero-sequence voltages and measured values of the zero-sequence currents of the feeders are obtained simultaneously by injecting currents step by step from the neutral point during the arc-extinguishing procedure, and are denoted as I ₀₁ 、U ₀₁ And I ₀₂ 、U ₀₂ 。

For low-resistance faults, the zero sequence characteristic is obvious, and the zero sequence parameter can be measured by the measuring device under the condition of small error. When high-resistance faults occur and zero-sequence currents of all feeder lines are smaller than or close to measurement errors of the zero-sequence transformers, measured data are invalid values and cannot be used for further calculating line-to-ground parameters. Even if a high-precision measurement transformer is applied, unbalanced current caused by unbalanced impedance to ground of the line is still considered, so that the absolute measurement value of the zero-sequence current has a large error when the high-resistance fault occurs, and the fault line cannot be reliably judged only by the polarity of the zero-sequence current.

Because the grounding transition resistor is mainly represented as a resistance, the influence on the grounding resistance of the line is small when the resistance is high, and whether a fault occurs is difficult to judge from the amplitude of the zero sequence voltage. Because the zero sequence admittance value of the line to the ground is complex, namely in the form of a + bi, the conductance is set as a, and the accommodation is b, when a < < b, the module value mainly depends on b, therefore, the change of the conductance of the line is small when the high resistance fault occurs, and the zero sequence admittance value calculated by the method mainly depends on the accommodation; the argument is arg (b/a), b > > a when the line normally runs, although the influence on a after high resistance occurs is small, the fact that the argument is changed appreciably even if a is small can be found according to a y ═ actan (b/a) image, and therefore reliable basis is found by using the line selection and positioning method of the zero sequence admittance argument.

Fig. 16 shows that when the zero-sequence admittance argument of a certain line is 87.8 ° during normal operation, after a ground fault occurs, when the transition resistance is increased from 1 Ω to 12k Ω, the zero-sequence admittance argument gradually approaches the argument value during normal operation, and when the argument reaches 12k Ω, the argument still has a difference of about 3 ° from the argument value during normal operation, so that high-resistance fault line selection and positioning are realized with high feasibility.

Under the same condition as that in fig. 16, fig. 17 shows that when the transition resistance is increased from 1 Ω to 12k Ω, the zero-sequence admittance magnitude is rapidly reduced to near zero, and it can be known that the zero-sequence admittance magnitude cannot be used as a reliable basis to determine a faulty line.

After the regulated zero-sequence voltage reaches a target value and residual current of the grounding point is eliminated, the zero-sequence admittance value of each feeder line can be calculated according to the real-time measured zero-sequence component.

Wherein i denotes each of the feed lines 1 to n, U ₀₁ Zero sequence voltage, I, of the first measurement _{01_i} The zero sequence current measured by the ith feeder line for the first time is indicated; u shape ₀₂ Zero sequence voltage, I, of the second measurement _{02_i} Zero sequence current, i.e. U, measured for the second time on the ith feeder line ₀₁ 、I _{01_i} 、U ₀₂ 、I _{02_i} The method for injecting current step by the neutral point obtains two groups of zero-sequence voltages and zero-sequence current of each feeder line under each group of zero-sequence voltage.

In a specific practice, step S15 "determine a specific line and a section where a single-phase fault occurs according to the zero sequence admittance of each feeder line", there are various implementations, and one implementation may be:

comparing the zero sequence admittance of each feeder line with the zero sequence admittance of the same line when the system operates normally;

for any feeder line, if the argument of the zero sequence admittance exceeds the argument threshold, judging that the current feeder line is a fault line; if the argument of the zero sequence admittance is less than or equal to the argument threshold, determining that the current feeder line is a non-fault line;

for any section on any feeder line, if the argument of the upstream zero sequence admittance is different from that of the normal operation of the system and the argument of the downstream zero sequence admittance is the same as that of the normal operation of the system, determining that the current section is a fault section; otherwise, the current section is judged to be a non-fault section.

In specific practice, step S16 "isolate faulty line or segment, initiate islanding detection", there are various implementations, and one implementation may be:

when the preset condition is met, carrying out island detection by selecting a zero sequence voltage phase jump identification method; the preset conditions include: the amplitude of the zero-sequence voltage at the distributed power generation unit side is smaller than a first threshold, and the resistance value of a grounding transition resistor (in fig. 2, fault points 1, 2 and 3 are disconnection or grounding points, and a transition resistor exists when grounding is defaulted, and the value of the transition resistor is from zero to infinity) is larger than a second threshold;

and when the preset condition is not met, carrying out island detection by selecting a zero sequence admittance jump identification method.

It can be understood that, considering that the neutral point of the transformer on the high-voltage side of the microgrid is in an ungrounded mode, and meanwhile, assuming that the main transformer neutral point of the large power grid is grounded through an arc suppression coil, before and after the fault line is cut off, the grounding mode of the microgrid is changed from a resonance grounding mode to an ungrounded mode, because the neutral point ungrounded mode can be equivalent to zero inductance and extremely large resistance, the detuning degree v can be equivalent to 100%, the damping rate d of the system only depends on the ground conductance of the line, although the capacitance current of the island network is far smaller than that of the large power grid after the fault line is cut off, the capacitance current of the island network is always in a 100% under-compensation operation mode, and the large power grid system is normally set to be moderately over-compensated, it can be known that the phase of the U0 on the side of the microgrid after the fault line is cut off has a certain reverse jump due to the sudden change of the system compensation degree, and one or more microgrids on the non-fault line always remain in a resonance grounding mode, the DG access point U0 is almost unchanged or slightly changed, so that the island on the fault line can be identified by utilizing the change rule of the phase of the micro-grid side U0 without influencing the continuous normal operation of the micro-grid on the non-fault line.

The amplitude of the U0 phase jump depends on the magnitude of the transition resistance, and in a metallic ground fault, the U0 phase always makes 180 degrees or close to 180 degrees with the fault phase voltage no matter what the degree of system compensation is, in which case the sensitivity of identifying the phase reversal jump will be insufficient.

Therefore, the present embodiment provides two post-fault island detection methods to maximize the island detection sensitivity, and the two methods can be used simultaneously or separately under limited conditions. The method can meet the requirement only by utilizing the existing zero-sequence voltage and zero-sequence current measuring device on the line without adding new equipment, has incomparable advantages in the aspect of economy, has high technical reliability, and provides technical support for large-scale access of a novel power system to new energy.

1. The zero sequence voltage phase jump identification method specifically comprises the following steps:

and if the phase change rule of the zero sequence voltage at the side of any one distributed power generation unit is inverted before and after the fault line or section is isolated, judging that the distributed power generation unit operates in an island mode.

As can be seen from fig. 1, the 10kV access transformer neutral point on the DG side is in a non-grounded mode, and the main transformer of the large power grid is in an arc suppression coil grounded mode. When the system normally operates, the whole system is grounded for the arc suppression coil; when a fault occurs, after a fault line containing DG is cut off, the grounding mode is changed into a non-grounding mode. Before and after the grounding mode is switched, the change rule of the zero sequence voltage of the DG side measuring points presents completely opposite characteristics, for example, when the phase A has a grounding fault, the arc suppression coil is tuned to be in an overcompensation mode, and when the fault occurs, the zero sequence voltage of the whole system including all the DG measuring points is always in a region of-100% -0% overcompensation-A'; when a fault line is cut off, if a DG exists, an island operation mode is formed, the zero sequence voltage of a DG measuring point jumps to a region of 0% -100% under compensation-A, the non-fault line and a bus are not disconnected, the non-fault line and the bus still remain in an arc suppression coil grounding mode, and the region where the zero sequence voltage is located is unchanged.

Transition resistance R with ground fault _f From zero to infinity, the trend of the zero sequence voltage change of the main transformer side and the DG measuring point of the non-fault line is anticlockwise increased, namely anticlockwise increased from a phase angle of 150 degrees; the zero sequence voltage of the fault line DG measurement point decreases clockwise, i.e. from a phase angle of 150 degrees clockwise. It can be seen that the 150-degree phase angle is a constant boundary line of zero-sequence voltages in two different grounding modes, so that island identification is realized according to the jump of the DG-side zero-sequence voltage region。

Besides the non-disconnection grounding fault, the disconnection non-grounding fault, the disconnection load side grounding fault and the disconnection power supply side grounding fault are also suitable for the zero sequence voltage phase jump identification principle.

When the grounding transition resistance is smaller, the zero sequence voltage amplitude and the phase jump are smaller and hardly influenced by the switching of the grounding mode, and meanwhile, the zero sequence voltage phase identification sensitivity is obviously reduced by considering that certain errors exist in the measurement equipment, so the phase jump principle needs to ensure the sensitivity in a detection range by setting a limiting condition, if the zero sequence voltage amplitude is set to be smaller than 50-80% of positive sequence voltage, the phase jump principle is preferred, otherwise, a zero sequence admittance jump identification method is utilized.

2. The zero sequence admittance jump identification method specifically comprises the following steps:

and if the difference between the amplitude and the argument of the zero sequence admittance at the side of any distributed power generation unit is larger than a preset value before and after the fault line or section is isolated, judging that the distributed power generation unit operates in an island mode.

The zero sequence admittance measurement needs to consider the error of the line measurement device, and when the zero sequence voltage is smaller than 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 is reduced when the zero sequence voltage amplitude is close to the phase voltage, and for the zero sequence admittance, the measured value is closer to the actual value when the zero sequence voltage is larger.

Before the fault line is cut off, the zero sequence admittance measured by the DG side access point is a downstream line in the power flow direction, and after the fault line is cut off, the zero sequence admittance measured by the DG side changes due to the change of the working condition of the line, so that a feasible technical scheme is provided for identifying an island by using the difference of the zero sequence admittance measured by the DG side before and after the fault line is cut off.

Before the fault line is cut off, DG side measures two groups of stored zero sequence current and zero sequence voltage values, and uses formula (18) to calculate zero sequence admittance Y _{go_before tripping} 。

When the fault line is cut off, a group of zero sequence current and zero sequence voltage are measured in real time by the DG side and are marked as I _{03_g} 、 U _{03_g} The current zero sequence admittance calculation result is:

and if the difference of the amplitude values of the zero sequence admittances at the side of any distributed generation unit DG is larger than a first preset value before and after the fault line or the section is isolated, and the difference of the argument of the zero sequence admittances is larger than a second preset value, judging that the distributed generation unit DG operates in an island mode.

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

ΔY _g0 ＝Y _{g0_after trippiug} -Y _{g0_before tripping} (20)

Before the fault line is cut off, the DG may be positioned at the upstream of the fault point (see FIG. 19) or the DG may be positioned at the downstream of the fault point (see FIG. 20), and the DG measures the zero-sequence admittance as Y _{g0_before tripping} (ii) a When the DG enters an island operation mode after the fault line is cut off, the DG measures the zero sequence admittance as Y _{g0_after tripping} 。

The island identification method 1 and the island identification method 2 do not need to add new equipment or need to communicate between a main transformer station and a DG side, so that the method is relatively friendly in economy, the low-resistance and high-resistance fault conditions can be fully covered by comprehensively applying the two methods, the detection blind area is reduced to the maximum extent, the island identification reliability is improved, and meanwhile, the electric energy quality is not influenced.

In order to better understand the zero sequence admittance jump identification method provided by the embodiment, how to perform island detection when four single-phase fault types occur in the system is taken as an example, which is described in detail.

Referring to fig. 19 and 20, the meaning of each parameter in fig. 19 and 20 is as follows:

m represents the ratio of the length of DG from a fault point to the total length of a fault line

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

Ya, Yb and Yc represent total zero sequence admittance of three phases of fault line to ground respectively

1. Non-disconnection ground fault

1) When DG is upstream of the fault point

In FIG. 19, when K is ₁ 、K ₂ 、K ₃ When the phases are closed, the non-broken line grounding fault of the phase C is shown, and the zero sequence admittance measured at the DG side before the fault line is cut off is as follows:

Y _{g0_before tripping} ＝(m+n)·(Y _a +Y _b +Y _c ) (21)

fig. 21 shows an island equivalent system after the fault line is removed, and the DG side zero sequence admittance is measured as follows:

Y _{g0_after tripping} ＝Y _a +Y _b +Y _c +Y _f (22)

2) DG downstream of the point of failure

In FIG. 20, when K is ₁ 、K ₂ 、K ₃ When the phases are closed, the non-broken line grounding fault of the phase C is shown, and the zero sequence admittance measured at the DG side before the fault line is cut off is as follows:

Y _{g0_before tripping} ＝(n-m)·(Y _a +Y _b +Y _c ) (23)

fig. 22 shows an island equivalent system after the fault line is removed, and the DG side zero sequence admittance is measured as follows:

Y _{g0_after tripping} ＝Y _a +Y _b +Y _c +Y _f (24)

2. disconnection and non-grounding fault

1) DG upstream of the fault point

In FIG. 19, when K is ₁ 、K ₂ 、K ₃ When the C-phase is disconnected, the disconnection and non-grounding fault occurs, and the zero sequence admittance measured at the DG side before the fault line is cut is as follows:

Y _{g0_before tripping} ＝(m+n)·(Y _a +Y _b +Y _c ) (25)

fig. 23 shows an island equivalent system after the fault line is removed, and the DG side zero sequence admittance is measured as follows:

Y _{g0_after tripping} ＝Y _a +Y _b +Y _c (26)

2) DG downstream of the point of failure

In FIG. 20, when K is ₁ 、K ₂ 、K ₃ When the C-phase is disconnected, the disconnection and non-grounding fault occurs, and the zero sequence admittance measured at the DG side before the fault line is cut is as follows:

Y _{g0_before trpping} ＝(n-m)·(Y _a +Y _b )+N·Y _C (27)

fig. 24 shows an island equivalent system after the fault line is removed, and the DG side zero sequence admittance is measured as follows:

Y _{g0_after tripping} ＝Y _a +Y _b +n·Y _c (28)

3. ground fault of broken line power supply side

1) DG upstream of the point of failure

In FIG. 19, when K is ₁ 、K ₃ Closure, K ₂ And when the C-phase is disconnected, the line breaking power supply side earth fault occurs, and the zero sequence admittance measured at the DG side before the fault line is cut off is as follows:

Y _{g0_before tripping} ＝(m+n)·(Y _a +Y _b +Y _c )+Y _f (29)

fig. 25 shows an island equivalent system after the fault line is removed, and the DG side zero sequence admittance is measured as follows:

Y _{g0_after tripping} ＝Y _a +Y _b +Y _c +Y _f (30)

2) DG downstream of the point of failure

In FIG. 20, when K is ₁ 、K ₃ Closure, K ₂ And when the C-phase is disconnected, the disconnection power supply side earth fault occurs, and the DG side zero sequence admittance measured before the fault line is cut is as follows:

Y _{g0_befor tripping} ＝(n-m)·(Y _a +Y _b )+n·Y _c (31)

fig. 26 is an island equivalent system after a fault line is cut off, and a DG side measurement zero sequence admittance is as follows:

Y _{g0_after tripping} ＝Y _a +Y _b +n·Y _c (32)

4. load side earth fault of broken wire

1) DG upstream of the point of failure

In FIG. 19, when K is ₂ 、K ₃ Closure, K ₁ And when the C-phase is disconnected, the disconnection load side grounding fault occurs, and the DG side zero sequence admittance measured before the fault line is cut off is as follows:

Y _{g0_before tripping} ＝(m+n)·(Y _a +Y _b +Y _c )+Y _f ( ₃₃ )

fig. 27 is an island equivalent system after a fault line is cut off, and a DG side measurement zero sequence admittance is as follows:

Y _{g0_after tripping} ＝Y _a +Y _b +Y _c +Y _f (34)

2) DG downstream of the point of failure

In FIG. 20, when K is ₂ 、K ₃ Closure, K ₁ And when the C-phase is disconnected, the disconnection load side grounding fault occurs, and the DG side zero sequence admittance measured before the fault line is cut off is as follows:

Y _{g0_before tripping} ＝(n-m)·(Y _a +Y _b +Y _c )+Y _f (35)

fig. 28 is an island equivalent system after the fault line is cut off, and the DG side measurement zero sequence admittance is:

Y _{g0_after tripping} ＝Y _a +Y _b +n·Y _c +Y _f (36)

as can be seen from the equations (21) - (36), the DG measurements before and after the fault removal have different zero-sequence admittances, just as when the zero-sequence voltage and the zero-sequence current are in the accurate measurement range, the delta Y is calculated by using the real-time zero-sequence admittance difference identification principle _g0 When Δ Y is _g0 And if the current value is larger than the set threshold value, triggering an island alarm.

Fig. 29 is a schematic diagram of islanding detection of zero-sequence voltage phase jump at the DG side. During normal operation, the change of asymmetry of a three-phase line caused by the switching change of the line is limited, and zero-sequence voltage operation cannot cross a threshold in a range and can be generally set to be 15V; or the arc suppression coil is out of operation due to the fault, the zero sequence voltage can only be reduced and is far less than 15V because the absolute value of the detuning degree is increased to be close to 100%, in this case, the DG side always stays in the 15V threshold range (shown in the third part in fig. 29) even if the change of the zero sequence voltage is detected, and therefore the action is locked.

When the fault is removed, the DG on the non-fault line is always kept consistent with the zero sequence voltage of the main station bus, the voltage of the DG on the non-fault line is kept close to the phase voltage level in the operation process under the clamping of a neutral point compensation device, and the zero sequence voltage on the DG side on the fault line can be rapidly reduced to be below a 15V threshold value (shown as a phi in figure 29), so that the operation in an island mode is judged; in some cases, the amplitude value of the DG zero sequence voltage is not obvious, but the phase change alpha value exceeds a set value (shown in (ii) and (iv) of fig. 29), and the islanding can be determined as well.

However, when the metallic grounding or transition resistance is small, after the fault line is cut off, the amplitude and phase of the zero-sequence voltage on the DG side are changed to be smaller than the set threshold, and therefore the detection sensitivity is reduced. In this case, it needs to be further determined by matching with the DG side zero-sequence admittance, such as setting the zero-sequence admittance threshold value as a radius dY in fig. 30 _g0 The circle of (2) assumes that the DG measured zero-sequence admittance angle before the fault line is cut off is 85 degrees as the reference zero-sequence admittance angle. When Δ Y is _g0 ＞dY _g0 It is shown that the zero-sequence admittance of the DG side changes before and after the fault is removed, and particularly, when the metallic grounding fault occurs, the change of the zero-sequence admittance is most obvious (as shown in a region (i) in fig. 30), the change of the zero-sequence admittance angle is dozens of degrees, and the change of the zero-sequence admittance value is also dozens or hundreds of times, so that the problem of insufficient sensitivity of the zero-sequence voltage phase jump principle during the metallic grounding can be solved. When the areas (two) and (three) in fig. 30 have no transition resistance, the total length of the line is reduced and increased, and the situation often occurs when the broken line is in a fault of not grounding.

The zero sequence admittance jump principle is suitable for all working conditions that the zero sequence voltage is larger than 15V after the fault line is cut off, and is used as a dual basis for detecting the island together with the zero sequence voltage phase jump principle.

When the fault line is cut off, the neutral point compensation device will stop operating, if the fault line is directly stopped, the zero sequence voltage on the side of the DG on all the non-fault lines will be rapidly reduced to be within the 15V threshold range, and according to the above judging method, all the non-fault lines DG will mistakenly consider to be operating in the island mode, and then the connection with the large power grid is stopped, which is not allowed.

To solve this problem, the step exit method is creatively applied in fig. 29, and all DGs receiving the step exit signal consider the system to operate normally and do not act to exit.

After the fault line is cut off, the zero-sequence voltage of the non-fault line still runs at a level close to the phase voltage level, when the fault line is identified to be cut off, the neutral point compensation device is delayed to exit in two steps, the phase voltage is reduced from 100% to 75% in the first step, meanwhile, the phase is kept unchanged, and the duration is 5 s; and in the second step, the phase voltage is reduced from 75% to 50% while the phase is still unchanged for 3s, and then the operation is directly stopped, and because all on-grid DGs can measure the step-by-step stop signal, the DGs on the non-fault line can be ensured not to act and stop the operation even under the condition of no communication.

It is understood that the same or similar parts in the above embodiments may be mutually referred to, and the same or similar parts in other embodiments may be referred to for the content which is not described in detail in some embodiments.

It should be noted that the terms "first," "second," and the like in the description of the present invention are used for descriptive purposes only and are not to be construed as indicating or implying relative importance. Further, in the description of the present invention, the meaning of "a plurality" means at least two unless otherwise specified.

Any process or method descriptions in flow charts or otherwise described herein may be understood as representing modules, segments, or portions of code which include one or more executable instructions for implementing specific logical functions or steps of the process, and alternate implementations are included within the scope of the preferred embodiment of the present invention in which functions may be executed out of order from that shown or discussed, including substantially concurrently or in reverse order, depending on the functionality involved, as would be understood by those reasonably skilled in the art of the present invention.

It should be understood that portions of the present invention may be implemented in hardware, software, firmware, or a combination thereof. In the above embodiments, the various steps or methods may be implemented in software or firmware stored in memory and executed by a suitable instruction execution system. For example, if implemented in hardware, as in another embodiment, any one or combination of the following techniques, which are known in the art, may 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 an appropriate combinational logic gate circuit, a Programmable Gate Array (PGA), a Field Programmable Gate Array (FPGA), or the like.

It will be understood by those skilled in the art that all or part of the steps carried by the method for implementing the above embodiments may be implemented by hardware related to instructions of a program, which may be stored in a computer readable storage medium, and when the program is executed, the program includes one or a combination of the steps of the method embodiments.

In addition, functional units in the embodiments of the present invention may be integrated into one processing module, or each unit may exist alone physically, or two or more units are integrated into one module. The integrated module can be realized in a hardware mode, and can also be realized in a software functional module mode. The integrated module, if implemented in the form of a software functional module and sold or used as a separate product, may also be stored in a computer-readable storage medium.

The storage medium mentioned above may be a read-only memory, a magnetic or optical disk, etc.

In the description herein, references to the description of the term "one embodiment," "some embodiments," "an example," "a specific example," or "some examples," etc., mean that a particular feature, structure, material, or characteristic described in connection with the embodiment or example is included in at least one embodiment or example of the invention. In this specification, the schematic representations of the terms used above do not necessarily refer to the same embodiment or example. Furthermore, the particular features, structures, materials, or characteristics described may be combined in any suitable manner in any one or more embodiments or examples.

Although embodiments of the present invention have been shown and described above, it is understood that the above embodiments are exemplary and should not be construed as limiting the present invention and that variations, modifications, substitutions and alterations can be made by those of ordinary skill in the art without departing from the scope of the present invention.

Claims

1. A single-phase fault handling and islanding detection system, comprising:

and isolating the fault line or section and starting island detection.

2. A single-phase fault handling and islanding detection method for use in a control device provided in the system of claim 1, comprising:

judging whether a single-phase fault occurs or not according to the amplitude and the phase of the zero-sequence voltage of the power grid;

and isolating the fault line or section and starting island detection.

3. The method according to claim 2, wherein the determining whether the single-phase fault occurs according to the amplitude and the phase of the zero-sequence voltage of the power grid comprises:

acquiring a ground insulation parameter of a system;

4. The method according to claim 2, wherein the identifying the single-phase fault type according to the phase shift trajectory of the zero sequence voltage of the power grid comprises:

searching a pre-stored corresponding relation table for the single-phase fault type corresponding to the phase offset track obtained at the current moment; the single-phase fault types include at least: a non-disconnection ground fault, a disconnection power source side ground fault, and a disconnection load side ground fault.

5. The method according to claim 4, wherein the correspondence table is obtained by a method comprising:

when the ground insulation parameters of the system are updated, recalculating according to the updated ground insulation parameters to obtain a phase deviation track of the zero sequence voltage of the power grid;

6. The method of claim 4, wherein selecting different arc quenching paths according to the single-phase fault type comprises:

defining a non-disconnection grounding fault and a disconnection power supply side grounding fault as forward faults, and defining a disconnection non-grounding fault and a disconnection load side grounding fault as reverse faults;

for a forward fault, the voltage of a fault phase is zero after current compensation is injected from a neutral point, the voltage of a non-fault phase respectively reaches the level of a line voltage, meanwhile, the zero-sequence voltage of a power grid and the positive-sequence voltage of the fault phase are in large reversal directions, and the residual current of a grounding point is close to zero after complete compensation;

for a reverse fault, the fault phase voltage meets a first preset condition after current compensation is injected from a neutral point, the non-fault phase voltage meets a second preset condition, the zero-sequence voltage of a power grid meets a third preset condition, and the residual current of a load side grounding point is close to zero after complete compensation;

the first preset condition comprises the following steps: the fault phase voltage reaches 1.5 times of the fault phase positive sequence voltage and the phases are consistent; the second preset condition includes: the magnitude of the non-fault phase voltage is 0.866 times of the positive sequence voltage of each non-fault phase voltage, 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 of the positive sequence voltage of the fault phase, and the phases are consistent.

7. The method of claim 2, wherein calculating the zero sequence admittance of each feeder line according to the zero sequence voltage of the power grid and the zero sequence current of each feeder line comprises:

8. The method of claim 7, wherein the determining the specific line and section with the single-phase fault according to the zero sequence admittance of each feeder line comprises:

9. The method of claim 2, wherein isolating the faulty line or section, initiating islanding detection, comprises:

when the preset condition is met, carrying out island detection by selecting a zero sequence voltage phase jump identification method; the preset conditions include: the amplitude of the zero sequence voltage at the side of the distributed power generation unit is smaller than a first threshold value, and the resistance value of the grounding transition resistor is larger than a second threshold value;

10. The method of claim 9,

the zero sequence voltage phase jump identification method specifically comprises the following steps:

if the phase change rule of the zero sequence voltage at the side of any distributed power generation unit is reversed before and after the fault line or section is isolated, judging that the distributed power generation unit operates in an island mode;

and/or the presence of a gas in the gas,

the zero sequence admittance jump identification method specifically comprises the following steps:

and if the difference of the amplitude values of the zero sequence admittances at any distributed power generation unit side is larger than a first preset value before and after the fault line or the section is isolated, and the difference of the argument of the zero sequence admittances is larger than a second preset value, judging that the distributed power generation unit operates in an island mode.