Method for detecting faults in transmission lines of a power transmission system

Abstract

A method for detecting a fault in a protection line constituting at least a portion of a transmission line in a power transmission system, the transmission line having at least one phase, the method comprising: determining positive, negative and zero-phase powers of the powers in the protection line, respectively positive, negative and zero-phase, and determining whether a criterion is met, the criterion being an expression of the combined phase powers according to: S Cmp = k1 * S1 - ( k2 * S2 + k0 * S0 ), where S Cmp is a composite phase power, S1 is a positive-sequence power, S2 is a negative-sequence power, S0 is a zero-sequence power, and k1, k2, and k0 are configurable non-negative weighting coefficients; and determining that a fault is detected on the protected line if it is determined that the -criterion is met. The method further comprises determining a delta value (ΔS Cmp ) to the current composite phase power value (S Cmp (present)) and the previous composite phase power value (S Cmp (previous)). The difference is determined as the difference between the active power portions and the difference between the reactive power portions.

Description

Technical Field

[0001] Technical Field The present disclosure generally relates to a power transmission system, and more particularly to a method and system for detecting a fault in a protection line that forms at least a part of a transmission line in a power transmission system.

Background Art

[0002] Background In a power transmission system such as a high voltage (HV) or medium voltage (MV) power transmission system, there is a risk of, for example, a large short circuit fault between phase and ground or between phases. Such faults must be detected and corrected as soon as possible. Therefore, the transmission line is monitored. Conventional solutions typically utilize measured values of current or impedance. They have obvious drawbacks. For example, in order to identify the location of a fault along a transmission line, it may be necessary to transmit measured values between devices at different ends of the transmission line. Conventional methods have very high requirements for the time synchronization of devices in order to generate correct results. Additionally, with regard to impedance measurement, they have drawbacks even for healthy phases, such as for high impedance faults, the semaphore effect due to remote end supply, impedance measurement, etc.

Summary of the Invention

Problems to be Solved by the Invention

[0003] Summary In view of the above, a concern of the present disclosure lies in how to reduce the drawbacks of the prior art.

Means for Solving the Problems

[0004] To better address this concern, in its first aspect, the present disclosure provides a method for detecting a fault in a protection line that forms at least a part of a transmission line within a power transmission system, the transmission line having at least one phase. The method is as follows. The task involves determining the positive-sequence power, negative-sequence power, and zero-sequence power of the power in the protective line, and determining whether the criteria are met, the criteria being based on the following formula for combined phase power:

[0005]

number

[0006] The method includes determining that SCmp is the combined phase power, S1 is the positive-sequence power, S2 is the negative-sequence power, S0 is the zero-sequence power, and k1, k2, and k0 are configurable non-negative weighting coefficients, and determining that a fault has been detected on the protected line if the criteria are met. The method further includes determining the delta value of the combined phase power as the difference between the current combined phase power value and the previous combined phase power value.

[0007] By using the delta value of the combined phase power, a simpler method for detecting different fault indicators becomes available, and some requirements may be relaxed.

[0008] The operation for determining the delta value of the combined phase power may include determining the active power delta value as the difference between the active power portion of the current combined phase power value and the active power portion of the previous combined phase power value, and determining the reactive power delta value as the difference between the reactive power portion of the current combined phase power value and the reactive power portion of the previous combined phase power value.

[0009] The method may further include determining a first delta value of the combined phase power at a first measurement point at the end of the protective line, which includes determining a first active power delta value and a first reactive power delta value at the first measurement point. The criterion is that the first active power delta value and the first reactive power delta value are positive and exceed a predetermined threshold. Determining that the above fault has been detected includes determining that the fault has been detected in the forward direction from the first measurement point, where forward direction is the direction from the first measurement point toward the protective line. In other words, forward direction refers to the direction outward from the measurement point along the protective line. The procedure for determining in which direction along the transmission line the fault has occurred is called transient directionality. Under steady-state conditions, the active power delta value and reactive power delta value are typically 0, which facilitates the setting of appropriate thresholds. This makes fault detection rapid and reliable.

[0010] The method may further include determining a second delta value of the combined phase power at a second measurement point at another end of the protective line, at a certain distance from the first measurement point, and the combined phase power ΔS Cmp2 The second delta value includes the second active power delta value and the second reactive power delta value. The criterion is that the first active power delta value, the second active power delta value, and the first reactive power delta value and the second reactive power delta value are all positive and exceed the threshold. Determining that the above fault has been detected on the protective line includes determining that the fault occurred between the first measurement point and the second measurement point. This allows for a directional comparison, thereby determining whether or not the fault occurred on the protective line between the measurement points, thus eliminating the need for transmission line characteristics such as line impedance.

[0011] In situations where the protective line has at least two ends, the method may include determining the combined phase power value at each end of the protective line and determining the differential phase power as the sum of the combined phase powers at the ends. The criterion is that the differential phase power exceeds a threshold. This results in differential protection that relaxes the synchronization requirements between the ends compared to conventional methods based on measuring the current / impedance of the transmission line, due to the use of combined phase power which can be considered time-invariant in this respect.

[0012] In a situation where the protective line has at least two ends, the method may include determining the combined phase power value at each end of the protective line and determining the differential phase power as the difference between the sum of the combined phase powers at the ends of the protective line and the power loss along the transmission line, wherein the criterion corresponds to the differential phase power value exceeding a threshold.

[0013] By taking power loss into account, the decision is better suited to longer transmission lines. Furthermore, the differential phase power can be determined according to the following:

[0014]

number

[0015] This method involves determining the phase power value at a destination point located along a transmission line at a certain distance from a measurement point, the measurement point being located at the end of the protective line; determining the phase power value; and determining the delta power value at the destination point using the phase power value at the destination point, where each delta phase power value is the difference between the current phase power value and the previous phase power value; and determining the delta power value. The criterion is based on the delta phase value. Determining that the above fault has been detected includes determining that the fault occurred between the measurement point and the destination point. This provides distance protection that does not require actual measurement of the impedance of the transmission line.

[0016] The delta power value may include the delta power value of the positive-sequence power at the destination, and the delta power value of the combination of the negative-sequence power and the zero-sequence power at the destination.

[0017] Determining the delta phase power value mentioned above may involve determining the formula according to the following:

[0018]

number

[0019] In the formula, ΔS1@RP is the delta-phase power value of the positive-sequence power at the destination, and ΔS 20 @RP is the delta phase power value, which is the combination of the negative phase power and the zero phase power at the destination.

[0020] This method may further include determining a first voltage phasor and a first current phasor of different phases at a measurement point; determining a second current phasor at the destination point using the first current phasor; determining a second voltage phasor at the destination point using the first voltage phasor, the first current phasor, the line impedance of the transmission line, and a destination coefficient related to the distance; determining the phase power value at the destination point using the second voltage phasor and the second current phasor; and determining the delta phase power value at the destination point using the phase power value at the destination point.

[0021] Determining that the above-mentioned fault occurred between the measurement point and the destination point may include determining that the fault is an asymmetric fault.

[0022] The power transmission system may be a three-phase system, but this method is also applicable to power transmission systems with more or fewer phases than three.

[0023] Determining the delta phase power value at the above destination can include using a distance-related reach coefficient and a predetermined transmission line impedance. This method is given by ΔQ1@RP=ΔQ 20 The equation by @RP can further include recursively estimating the value of the attainment coefficient for which the equation is valid, where ΔQ1@RP is the reactive power portion of the positive-sequence delta-phase power, and ΔQ 20 @RP is the reactive power portion of the delta power value in the above combination. Furthermore, since the above formula is only valid at the fault point, the location of the fault is also determined.

[0024] In another embodiment, a fault detection system for a power transmission system comprising a transmission line is provided, wherein the transmission line comprises a protective line constituting at least a portion of the transmission line, and the transmission line has at least one phase. The fault detection system comprises intelligent electronic devices (111, 112, 113) connectable to the transmission line and configured to detect faults on the protective line, the intelligent electronic devices configured to do the following:

[0025] - Determine the positive-sequence power, negative-sequence power, and zero-sequence power of the power in the protective line, respectively.

[0026] - Determine whether the criteria are met. The criteria are based on the following formula for combined phase power.

[0027]

number

[0028] In the formula, S Cmp is the combined phase power, S1 is the positive-sequence power, S2 is the negative-sequence power, S0 is the zero-sequence power, and k1, k2, and k0 are non-negative configurable weighting coefficients.

[0029] -If the criteria are determined to be met, it is determined that a fault has been detected on the protected line. The intelligent electronic device is further configured to determine the delta value of the combined phase power as the difference between the current combined phase power value and the previous combined phase power value, which includes determining the active power delta value as the difference between the active power portion of the current combined phase power value and the active power portion of the previous combined phase power value, and determining the reactive power delta value as the difference between the reactive power portion of the current combined phase power value and the reactive power portion of the previous combined phase power value.

[0030] This fault detection system offers advantages corresponding to the methods described above. The intelligent electronic device can be connected to the transmission line at a measurement point located at the end of the protective line. The intelligent electronic device can be configured to determine the phase power value at a destination point located along the transmission line at a certain distance from the measurement point, and to determine the delta phase power value at the destination point by using the phase power value at the destination point. Each delta phase power value is the difference between the current phase power value and the previous phase power value. The basis is the delta phase value. Determining that a fault has been detected includes determining that the fault occurred between the measurement point and the destination point.

[0031] The delta power value may include the delta power value of the positive-sequence power at the destination, and the delta power value of the combination of the negative-sequence power and the zero-sequence power at the destination.

[0032] In another embodiment, a computer program product is provided which, when downloaded to an intelligent electronic device, contains instructions causing the intelligent electronic device to perform the method described above. The computer program product can be implemented as a computer program stored on a computer-readable medium such as a portable memory device or other carrier containing code for instructions, a server, a hard disk, or downloadable computer program code, as will be understood by those skilled in the art. For the purposes of this application, it should be noted that the term "power transmission system" refers to any suitable power transmission system, such as alternating current (AC) and alternating / direct current (AC / DC) transmission systems. The term "transmission line" refers to any suitable AC transmission line, such as HVAC transmission lines, MVAC transmission lines (also called distribution lines), long-distance and short-distance transmission lines. The term "protected line" refers to a portion of a transmission line that is monitored for faults. The term "forward direction" refers to a reference direction from the measurement point toward the protected line.

[0033] Brief explanation of the drawing Hereinafter, exemplary embodiments will be described in more detail with reference to the attached drawings. [Brief explanation of the drawing]

[0034] [Figure 1] This is a block diagram of one embodiment of the fault detection system deployed within a transmission system. [Figure 2] This is a flowchart of one embodiment of the fault detection method. [Figure 3] This diagram shows the power status in a faulty transmission line. [Modes for carrying out the invention]

[0035] Detailed explanation Figure 1 shows the most common example of a power transmission system 100 comprising a transmission line 101 having one or more phases, for example three phases, and at least two ends. In the illustrated example, there are three ends, one of which is shown as an alternative to a two-end transmission line. Electrical devices 102, 103, and 104 are connected to each of the transmission lines 101. Electrical devices 102-104 may be power sources or electrical loads. The transmission line 101 is provided with one or more switching devices 105, 106, 107, 108, 109, and 110 that allow the circuit to be opened to limit the flow of current in the power transmission system 100. The fault detection system of the power transmission system 100 comprises one or more intelligent electrical devices (IEDs) 111, 112, and 113. Each IED 111-113 is typically connected to the transmission line 101, either directly or via some other device at its end, and is configured to monitor electrical activity in the transmission line 101, for example, by measuring current and voltage within the transmission line 101. Therefore, for the purposes of this disclosure, the portion of the transmission line 101 to which the IEDs 111-113 are connected is referred to as the measurement point. Furthermore, the IEDs 111-113 are configured to detect faults in the transmission line 101 and to switch one or more of the switching devices 105-110. It should be noted that the transmission line 101 or any portion thereof monitored by the IEDs 111-113 constitutes a protection line 114.

[0036] As will be understood by those skilled in the art, the overall structure of the power transmission system shown in Figure 1 is merely one example among countless variations. Briefly, in addition to what has been described above, the power transmission system may be part of a grid or connected to a grid, the power sources may be several different types of power sources such as wind power plants, solar power plants, nuclear power plants, and transformers, and the loads may be several different types of loads such as production sites. The power transmission system may include several transmission lines, etc. The transmission lines may be HV AC lines or MV AC lines and may extend between power sources, between power sources and loads, etc., and thus may constitute what is also called a distribution line, as recognized above. The length of the transmission lines can vary greatly, from a few kilometers, or even shorter, to several hundred kilometers.

[0037] According to an exemplary embodiment of the method for detecting faults in the protective line 114, the method includes the operations shown in the flowchart of Figure 2. In box 201, the phase powers of the transmission line 101 are determined. That is, the positive-sequence power S1, the negative-sequence power S2, and the zero-sequence power S0 of the power in the transmission line 101 are determined. The method further includes determining in box 202 whether a criterion is met. The criterion is the combined phase power S2, which is determined based on the positive-sequence power S1, the negative-sequence power S2, and the zero-sequence power S0. Cmp Furthermore, it is determined based on at least one of at least one formulas which are determined based on at least two of the positive-sequence power S1, negative-sequence power S2, and zero-sequence power S0. If the criteria are met, it is determined that a fault has been detected on the protective line 114 (box 203).

[0038] The criterion may be based on at least one of the positive-sequence power S1, negative-sequence power S2, and zero-sequence power S0, as well as an additional formula determined based on a threshold.

[0039] The standard can be based on the following formula for combined phase power.

[0040]

Number

[0041] In the formula, S Cmp is the composite phase power, S1 is the positive phase power, S2 is the negative phase power, S0 is the zero phase power, and k1, k2, and k0 are non - negative weighting factors that can be set.

[0042] Determining a criterion based on the composite phase power S Cmp and / or an equation based on at least two of the phase powers includes different possible alternatives such as using one or more of the phase powers in the determination, using the resulting composite phase powers in different manners, determining instantaneous values, determining delta values, predicting future values, judging values against thresholds, etc. This will become clear from the following examples and will be detailed in the following examples.

[0043] For clarity, an example of a method for determining phase power for a three - phase transmission line is shown here. IEDs 111 - 113 are configured to measure the phase current and phase voltage signals of three phases. The reference direction Ref is determined to point to the other end of the transmission line 101 outward from the end to which IEDs 111 - 113 are connected. To clearly identify phases and phase components, the following nomenclature is used throughout this application.

[0044] 1. The phase quantities are indicated by indices A, B, and C (e.g., I A , I B and I C ). [[ID=;32]]<000027;0> 2. The phasors are indexed by indices <0, 1, 2> for the positive, negative, and zero phase components respectively (e.g., I1, I2, and I0).

[0046] 3. All values given in the examples are presented per unit or in a percentage system.

[0047] The fundamental frequency phasors of three phase voltage and current signals are to be derived. The signals are sampled and a full-cycle discrete Fourier transform (DFT) filter, or any other suitable type of filtering, may be applied. The phase components phasors of the current and voltage are then calculated for the current signal using a well-known determinant, as shown below. The voltage phasors are calculated similarly.

[0048]

number

[0049] The letter "a" represents the complex operator, and a = e i*120° =e j*120° Therefore, i=j=√(-1). Thus, the positive, negative, and zero-sequence current phasors I1, I2, and I0 all have phase current I A , I B , I C It is determined by different combinations of these factors.

[0050] Next, the complex-value phase powers S1, S2, and S0 are calculated using the following well-known formulas.

[0051]

number

[0052] During the ceremony, `` <c>This indicates that the current phasor values ​​should be complex conjugated before the multiplication is performed, where P is the active power and Q is the reactive power.

[0053] Once the phase power is determined, the combined phase power is calculated according to the following formula.

[0054]

number

[0055] In the formula, S Cmp is the combined phase power, S1 is the positive-sequence power, S2 is the negative-sequence power, S0 is the zero-sequence power, and k1, k2, and k0 are non-negative configurable weighting coefficients.

[0056] This equation for combined phase power can be expanded as follows:

[0057]

number

[0058] As mentioned above, the weighting coefficients k1, k2, and k0 are non-negative and configurable. For the sake of simplicity in this explanation, for the purposes of the following discussion, all weighting coefficients are chosen to be 1.0, i.e., k1=k2=k0=1.0. However, the weighting coefficients can be given other values ​​to enhance the influence of certain phase power components on the sum of the combined phase powers.

[0059] Negative and zero-sequence powers S2 and S0 actually flow in the opposite direction to the positive-sequence power S1, so the combined phase power S Cmp The formula has a negative sign. As a result, when they are added together, they become positive-sequence power, increasing the sensitivity of this method.

[0060] Furthermore, combined phase power S Cmp The formula is useful for detecting different types of faults in the transmission line 101, as will become clear below.

[0061] The method for detecting faults in protective lines within a power transmission system, as disclosed herein, stems from novel discoveries based on prior knowledge of how power is distributed within a transmission line in the presence of a short circuit, as shown in Figure 3. The scenario shown is an ideal case where there is no fault resistance at the fault point and the transmission system is unloaded before the fault occurs. However, some of the basic principles shown in Figure 3 are generally valid. The relationship between phase powers at the fault point (FP) can be expressed as follows:

[0062]

number

[0063] In other words, this can be expressed and understood as the positive-sequence power at the fault point FP being equal to the sum of the negative-sequence power and the zero-sequence power, but with the opposite sign. In a physical sense, the negative sign means that the negative-sequence power and zero-sequence power reflect back from the fault point and flow from the fault point towards the power source 301, which is shown on the left side of Figure 3. This is even true for a symmetrical three-phase fault, but at the fault point FP and throughout the transmission system, the zero and negative-sequence powers S0, S2 are equal to 0.

[0064] Therefore, as shown in Figure 3, it should be noted that the following relationship is always valid even at any point T between the power supply 201 and the fault point FP where the IED is connected.

[0065]

number

[0066] Here, it should be noted that in order to obtain sufficiently appropriate results, the weighting coefficients k must all be equal to 1. In actual power transmission systems 100, the following is almost always valid.

[0067] 1. The transmission line is loaded before the fault and supplies some power to the load. 2. Faults are supplied from both sides of the protective line, or from all sides in the case of a multi-terminal transmission line.

[0068] 3. Some fault resistance (variable or constant) exists at the point of fault. Therefore, the above equation can be generalized to be valid under all operating conditions of the protective line. Based on the superposition theorem of electrical circuits, the following general equation can be written for the phase power at the point of fault.

[0069]

number

[0070] During the ceremony, ΔS1@FP is the change in positive-sequence power at the fault point FP caused by the fault. Determining the delta value eliminates the influence of the load before the fault occurred. The delta value of a phase power is the difference between the current phase power value and the previous phase power value. For example, the delta value of a phase power may be calculated by the time difference between two transmission system cycles.

[0071] ΔS2@FP is the change in negative phase power at the fault point FP due to the fault. Note that before the fault, the negative phase power is typically 0, i.e., non-existent. However, by using its delta value, it is possible to eliminate any asymmetric or nonlinear loads that exist before the fault.

[0072] ΔS0@FP is the change in zero-sequence power at the fault point caused by the fault. Note that zero-sequence power is typically 0, i.e., non-existent, before the fault. However, by using its delta value, it is possible to eliminate any asymmetric or nonlinear loads prior to the fault.

[0073] P RF This is the active power consumed by the fault point itself, i.e., the power supplied to the fault resistance or electric arc at the fault point. Note that this quantity cannot be measured directly. Neither can be easily estimated. However, this active power is consumed for almost all actual faults in a power transmission system. In other words, this can be expressed and understood as the change in positive-sequence power S1 at the fault point being supplied to the fault resistance, i.e., consumed primarily as active power by the fault point / resistance itself, and partially reflected back as negative-sequence and zero-sequence powers S2, S0. This is even true for symmetrical three-phase faults, although at the fault point and throughout the power transmission system, the negative and zero-sequence powers S2, S0 are equal to 0.

[0074] As explained above, the flow of positive-sequence power S1, or its delta value ΔS1, is in the opposite direction to the flow of negative and zero-sequence powers S2 and S0 in the entire transmission system, or their delta values ​​ΔS2 and ΔS0. Consequently, the combined phase power is defined as the difference between them as described above, i.e.,

[0075]

number

[0076] As a result, all phase power values ​​are summed up to form an actual combined sum. This can be considered as using all three phase powers S1, S2, and S0 in the same direction. This results in a larger sum than if the phase power values ​​were added with their independent signs, and consequently, comparisons made by such values ​​become more sensitive. Furthermore, such combined phase power values ​​will have a more or less constant value across the entire protective line, if losses along the protective line are ignored.

[0077] As a result, the relative locations of IED111-113 to the fault point FP become less important compared to a situation where each of the three phase components and their respective powers are used individually for protection purposes.

[0078] Furthermore, at any point T between the power source and the fault point, any point T may be the location to which the IED is connected, and the following relationship is always valid.

[0079]

number

[0080] The use of this relationship between the delta values ​​of phase powers is illustrated below. According to this embodiment of the method, the comparative value is determined by the combined phase power S according to the following formula. Cmp The delta value ΔS Cmp This may include determining it as the difference between the current combined phase power value and the previous combined phase power value.

[0081]

number

[0082] Therefore, the delta value ΔS of the combined phase power Cmp The determination is based on the active power delta value ΔP Cmp The current combined phase power value S Cmp (present) Active power portion P Cmp (present) and the previous combined phase power value S Cmp (previous) Active power portion P Cmp The reactive power delta value ΔQ is determined as the difference between (previous) and (previous). Cmp The current combined phase power value S Cmp (present) Reactive power portion Q Cmp (present) and the previous combined phase power value S Cmp (previous) Reactive power portion Q Cmp This includes determining the difference between the current value and the previous value. The time difference between the current value and the previous value may be, for example, two cycles of the power transmission system 100, where the cycles are related to the fundamental frequency.

[0083] Delta value ΔS of combined phase power Cmp This is useful for several different ways of determining faults on the protective track 114.

[0084] According to an embodiment of this method, for example, when the first IED 111 is connected to the transmission line 101, the first delta value ΔS of the combined phase power at the first measurement point at the end of the protective line 114 is measured. Cmp1 This may include determining ΔS Cmp1 The determination is based on the first active power delta value ΔP at the first measurement point. Cmp1 and the first reactive power delta value ΔQ Cmp1 This may include determining the first active power delta value ΔP. Cmp1 and the first reactive power delta value ΔQ Cmp1 The value is positive and corresponds to exceeding a predetermined threshold. The predetermined threshold may be, for example, 5%, or any other appropriate value. Furthermore, it is determined that a fault has been detected in the forward direction from the first measurement point, where the forward direction is the direction toward the protective line from the first measurement point, i.e., the reference direction Ref1 of the first IED111.

[0085] According to this embodiment of the method, the second delta value ΔS of the combined phase power at a second measurement point at another end of the protective line 114 located at a distance from the first measurement point is obtained. Cmp2 This may further include determining the second measurement point, which may be the portion of the transmission line 101 to which the second IED 112 is connected. The second delta value ΔS of the combined phase power Cmp2 This is the second active power delta value ΔP Cmp2 and the second reactive power delta value ΔQ Cmp2 This includes the first active power delta value ΔP. Cmp1 and the second active power delta value ΔP Cmp2 Furthermore, the first reactive power delta value ΔQ Cmp1 and the second reactive power delta value ΔQ Cmp2 All of these conditions are positive and correspond to exceeding the threshold. The forward direction from the first measurement point, for example, the reference direction Ref1 of the first IED111, is the direction toward the second measurement point. The forward direction from the second measurement point, for example, the reference direction Ref2 of the second IED112, is also the direction toward the protective line, which means it is the direction toward the first measurement point. As a result of satisfying the criterion, the first active power delta value ΔP is obtained. Cmp1 and the second active power delta value ΔP Cmp2 Furthermore, the first reactive power delta value ΔQ Cmp1 and the second reactive power delta value ΔQ Cmp2 If all of the values ​​are positive and exceed a threshold, a fault is determined to have occurred between the first and second measurement points. The result of their operation may be called a direction comparison, which is a method for determining that a fault has occurred on the protective line 114 extending between the first IED 111 and the second IED 112. Thus, it is concluded that the detected fault is somewhere on the protective line, and the first IED 111 and / or the second IED 112 can control one or more of the switching devices 105-110 to interrupt the current in the protective line. As understood, communication between IEDs 111 and 112 is necessary to ensure correct fault detection. However, the communication may be limited to transmitting a binary number indicating the direction or whether the direction is forward or not. If the fault detection system has two or more IEDs 111-113, fault detection may be performed on one, some or all of the IEDs 111-113. Each IED111-113 that determines whether a fault has occurred receives a binary value from the other IED111-113. The use of phase power as described above allows for the detection of all types of faults. However, it may not be possible to determine the phase in which the fault occurred. This direction comparison method does not require any data about the protection line itself; for example, positive and / or zero-sequence line impedance is not required as a setting parameter.

[0086] According to this embodiment of the method, the combined phase power value S at each end of the protective line 114 is Cmp To determine the difference phase power S Diff At least, the combined phase power S at the end. Cmp This may include determining it as the sum of the difference phase powers S. Diff This corresponds to exceeding a threshold. This method is called differential fault detection or differential protection. For example, if there are three ends on the protection line 114, as in one of the options shown in Figure 1, the combined phase power value S Cmp This is determined by all three IEDs 111-113, and their sum is determined by each of the IEDs 111-113 that receive the combined phase power value from the other two IEDs. For an ideal line, i.e., a line with no P loss and Q loss, if there are no faults on the transmission line 101, the combined phase value S from IEDs 111-113 is Cmp The sum of these is zero. By setting a threshold slightly away from zero, such as 5%, and comparing the recalculated sum as a percentage of the nominal total value to the threshold, it can be concluded that a fault has occurred on transmission line 101 if the threshold is exceeded. The determination of the differential phase power can be expressed mathematically as follows:

[0087]

number

[0088] Alternatively, the delta value of the differential phase power may be used, namely, as follows:

[0089]

number

[0090] In this differential fault detection method, similar to the directional comparison described above, the time invariance of complex power values ​​is utilized to relax the time synchronization requirements for communication between IEDs. In other words, since phase power is used, and the combined phase power under normal conditions changes very little compared to the current and changes slowly, the synchronization timing requirements can be relaxed compared to the timing requirements of conventional methods that are directly based on current measurements. As an example, the time synchronization requirement may be around 1 to 3 milliseconds for power measurement in a 50 Hz power transmission system. This should be compared to conventional techniques using current-based differential fault detection that require time synchronization of about 1 microsecond. As a result, the time synchronization requirements are significantly relaxed in the case of power-based differential fault detection. At the same time, two actual quantities, namely P, Cmp and Q Cmp Since only the data is transferred between IED111 and 113, the data bandwidth required for communication is also significantly reduced. Additionally, these two quantities remain nearly constant under steady-state conditions, which can be used to further reduce the required communication bandwidth.

[0091] However, it should be noted that in reality, there are P and Q power losses along the transmission line 101, which have a significant impact, at least on longer transmission lines. Therefore, for longer transmission lines 101, the differential phase power S Diff The formula for determining can be modified to include power losses on the transmission line 101 according to the following:

[0092]

number

[0093] During the ceremony, P Loss This is the active power loss along the transmission line 101. It is R1*|I1| 2 It can be estimated that...

[0094] Q Loss This is the reactive power loss along transmission line 101. It is X1*|I1| 2 -B1*|U1| 2 It can be estimated that...

[0095] R1 is the positive-sequence resistance of the transmission line 101. X1 is the positive-sequence reactance of the transmission line 101.

[0096] B1 is the positive-sequence susceptance of the transmission line 101. Delta difference phase power ΔS Diff In an alternative method of determination, in the case of an internal fault, i.e., a fault on the protective line, the power change at all ends of the transmission line 101 will be positive, indicating an internal fault regardless of power loss as described above, and therefore power loss can be ignored.

[0097] A further example of fault detection in transmission line 101 is called distance fault detection or distance protection. The purpose of distance protection is to detect whether a fault is on the protected line based solely on local measurements. This can be done by defining one or more distance protection zones. For example, two protection zones may be defined, with a first protection zone covering 80% of the protected line 114 and a second protection zone covering 120% of the protected line 114. The location of the distal end of the protected line 114 relative to the locations of IED 111-113, i.e., the location of 80% or 120% of the protected line, which could be substantially the entire length of transmission line 101, is indicated as the destination RP. Several transmission line characteristics are taken into consideration in order to implement distance protection. These include the line positive-sequence impedance Z 1L and zero-sequence impedance Z of the transmission line 0L This includes, but is not limited to, the following: If parallel transmission lines exist (not shown in the diagram), the zero-sequence impedance between the lines Z ML These may also be used. Based on these characteristics, the selected protection zone represented by a reach coefficient r which is 0.8 in the case of 80% and 1.2 in the case of 120%, and the phase current phasor and phase voltage phasor measured at the IED location, i.e., the measurement point, it is possible to determine the phase power at the set reach point RP. In other words, the reach coefficient r is related to the distance from the measurement point, i.e., where IEDs 111-113 are connected to the transmission line 101, to the reach point RP.

[0098] Therefore, according to an embodiment of this method, the method may include determining the phase power values ​​S1, S2, and S0 at a destination point RP located along the transmission line 101 at a certain distance from the measurement point, and thus from IED111-113, and determining the delta phase power values ​​ΔS1, ΔS2, and ΔS0 at the destination point RP by using the phase power values ​​at the destination point. Based on the delta phase power values, it is possible to determine whether a fault has occurred between the measurement point and the destination point. This method determines the combined phase power S Cmp Still based on the above defined formula, but with the individual coefficients of the formula used instead of the combined phase power itself, they are determined relative to the destination, and are shown as @RP.

[0099] For example, the delta phase power value is the delta phase power value ΔS1@RP of the positive-sequence power at the destination, and the delta phase power value ΔS of the combination of the negative-sequence power and the zero-sequence power at the destination. 20 It can include @RP. Then, the comparison value can be defined as follows:

[0100]

number

[0101] Therefore, when the criterion is met, that is, when the delta value of the positive-sequence power at the destination ΔS1@RP is equal to the delta value ΔS of the combination of the negative-sequence power and the zero-sequence power at the destination. 20 When it is smaller than @RP, a fault is detected, where the fault is located between the measurement point, i.e., IED111~113, and the destination point RP. For example, the combination could be the whole part of the equation valid for the destination point, which includes negative and zero-sequence powers, i.e., the negative sum of those powers, i.e., S 20 @RP = -(S2@RP + S0@RP) is possible.

[0102] The delta value of the phase power is determined at the measurement point, for example, at the first IED111, where the first voltage phasors and first current phasors of different phases, indicated here as U1@IED, U2@IED, U0@IED, I1@IED, I2@IED, and I0@IED, are determined, and by using the first current phasors, the second current phasors at the destination points, indicated here as I1@RP, I2@RP, and I0@RP are determined, along with the first voltage phasors, the first current phasors, and the line impedance Z of the transmission line 101. 1L , Z 0L By using the attainment coefficient r, the second voltage phasors at the attainment points, indicated here as U1@RP, U2@RP, and U0@RP, are determined; by using the second voltage phasors and the second current phasors, the phase power values ​​at the attainment points are determined; and by using the phase power values ​​at the attainment points, the delta phase power values ​​at the attainment points are determined.

[0103] A more detailed example of the calculations performed to enable the detection of distance faults is as follows: First, the current phasor and voltage phasor at the destination RP are determined as follows:

[0104]

number

[0105] This example is simplified, in particular, in that the shunt capacitance of transmission line 101 / protection line 114 is not taken into consideration. However, this is not absolutely necessary to detect faults within the set protection zone. Furthermore, it should be noted that other more complex methods can be used to estimate the phase voltage and current components at the destination, for example, by taking parallel capacitance into consideration and using a 2-port equivalent network, telegrapher's equations, etc. Once the current and voltage phase phasors are known at the set destination RP, the following phase powers at destination RP can be calculated.

[0106]

number

[0107] As described above, the combined phase power S at the destination 20 Note that @RP is the negative sum of S2@RP and S0@RP. Finally, delta value S1@RP and delta value S 20 @RP will also be calculated. For example, this can be done by subtracting the value from two transmission system cycles ago from the currently calculated value, i.e., the term "previous" in the following formula corresponds to "the value from two cycles ago".

[0108]

number

[0109] Furthermore, it should be noted that if the fault point is within the set distance protection zone, the above calculation will exceed the actual fault point FP. As a result, the delta value ΔS1 of the positive-sequence power is equal to the delta value ΔS of the combination of negative-sequence power and zero-sequence power. 20 It becomes smaller than this. Note that such a relationship between these two delta powers is not physically possible at any point in an actual transmission system, but is due to the calculation assuming that the actual fault point is located between the measurement point where the above calculation is performed and the set destination RP.

[0110] Distance fault detection based on the delta value of phase power can be performed as follows:

[0111]

number

[0112] Because this is a complex expression, it can be separated into two real number expressions as shown below.

[0113]

number

[0114] Therefore, ΔP1@RP, ΔP 20 @RP+P RF ΔQ1@RP, and ΔQ 20 @RP is used as a comparison value, and they are compared in pairs. The criterion that must be met to determine that a fault has been detected is that both of these equations are satisfied. The first equation is: Fault resistance P RF It has an unknown term for the active power consumed by the fault. Therefore, if fault resistance is present, it is more difficult to satisfy it for an actual fault. This is a known problem with distance fault detection where larger fault resistance values ​​can affect fault determination. The second equation for reactive power is easier to use and offers clear advantages over conventional impedance-based distance protection. As shown in this equation, fault resistance has no effect on the reactive power portion of this equation.

[0115] It should be noted that the two equations above are valid only for all types of asymmetric faults. In the case of a symmetric three-phase fault, there is no negative or zero-sequence power in the system. For such a three-phase fault, these two equations can be modified as follows:

[0116]

number

[0117] By ignoring the fault resistance for a three-phase fault in the first of the two equations above, the safety of the decision is increased because the conclusion that a fault has occurred, even though the trip condition, i.e., the condition for switching switching devices 105-110, is already met for some small positive values ​​of ΔP1@RP, is delayed slightly until ΔP1@RP becomes negative.

[0118] The transient directionality described above can be used to confirm that the fault is in the forward direction. Therefore, the following applies to a three-phase fault.

[0119]

number

[0120] Because phase power is used, this distance protection works for all types of faults in a three-phase system (i.e., non-phase-isolated). However, its main advantage is its operating speed. Here again, the second equation is typically first satisfied for most practical faults, which are due to the presence of fault resistance (i.e., active power consumption) at the fault point.

[0121] As a further exemplary embodiment, the relation ΔQ1@RP=ΔQ can be used. 20 Since @RP is only valid at the point of failure, the relation ΔQ1@RP = ΔQ 20 Faults can be localized by recursively determining the value of the reach coefficient r of the set line impedance for which @RP is enabled. More specifically, determining the delta phase power value at the above reach point involves the reach coefficient r related to distance and a given transmission line impedance, e.g., Z 1L and Z 0L This may include utilizing the above determination of the voltage phasor including the reach coefficient r, so ΔQ1@RP = ΔQ 20 It may be possible to recursively estimate the value of the attainment coefficient r for which the formula by @RP is valid. ΔQ1@RP is the reactive power portion of the positive-sequence delta-phase power, and ΔQ 20 @RP represents the reactive power portion of the delta power value of the combination.

[0122] Although this disclosure has been illustrated and described in detail in the drawings and the foregoing description, such illustrations and descriptions should be considered illustrative or exemplary and not limiting.

[0123] While the features and elements are described above in specific combinations, each feature or element may be used alone without other features and elements, or in various combinations with or without other features and elements.

[0124] Other modifications to the disclosed embodiments can be understood and implemented by those skilled in the art in the practice of the claimed invention, based on the study of the drawings, disclosures, and the appended claims. In the claims, the word “comprising” does not exclude other elements or steps, and the indefinite article “a” or “an” does not exclude the plural. A single processor or other unit may perform the functions of several items enumerated in the claims. The mere fact that certain features are enumerated in mutually different dependent claims does not imply that combinations of these features cannot be used advantageously. No reference numeral in the claims should be construed as limiting in scope.< / c>

Claims

1. A method for detecting a fault in a protective line constituting at least a portion of a transmission line in a power transmission system, wherein the transmission line has at least one phase, and the method is - Determining the positive-sequence power, negative-sequence power, and zero-sequence power of the power in the aforementioned protective line, - Determining whether or not the criteria are met, the criteria being the formula for the combined phase power as follows: S Cmp =k 1 *S 1 -(k 2 *S 2 +k 0 *S 0 ) It is defined by, where S Cmp is the synthetic phase power, S １ is the positive phase power, S ２ is the negative phase power, S ０ is the zero phase power, k １ , k ２ , k ０ is a configurable non - negative weighting factor, using the delta value of the synthetic phase power (ΔS Cmp) determined as the difference between the current synthetic phase power value (S Cmp (present)) and the previous synthetic phase power value (S Cmp (previous)) for determination, - If it is determined that the above criteria are met, it is determined that a fault has been detected on the protective line, Methods that include...

2. The delta value (ΔS) of the combined phase power Cmp Determining the above means the active power delta value (ΔP Cmp ) is the active power portion (P Cmp (present)) and the active power portion of the aforementioned combined phase power value (P Cmp (previous)) is determined as the difference between and the reactive power delta value (ΔQ Cmp ) is the reactive power portion (Q) of the current combined phase power value. Cmp (present)) and the reactive power portion (Q) of the aforementioned combined phase power value Cmp The method according to claim 1, comprising determining as the difference between (previous) and (previous).

3. The first delta value (ΔS) of the combined phase power at the first measurement point at the end of the protective line (114) Cmp１ This includes determining the first active power delta value (ΔP) at the first measurement point. Cmp１ ) and the first reactive power delta value (ΔQ Cmp１ The method of claim 2, comprising determining a first active power delta value and a first reactive power delta value that are positive and exceed a predetermined threshold, and determining that a fault has been detected comprising determining that the fault has been detected in the forward direction from the first measurement point, the forward direction being the direction from the first measurement point toward the protective line.

4. The second delta value (ΔS) of the combined phase power at a second measurement point at another end of the protective line, at a certain distance from the first measurement point. Cmp２ The method further includes determining the second delta value, which is the second active power delta value (ΔP) at the second measurement point. Cmp２ ) and the second reactive power delta value (ΔQ Cmp２ The method according to claim 3, wherein the criterion is that the first active power delta value and the second active power delta value and the first reactive power delta value and the second reactive power delta value are all positive and exceed the threshold, and determining that the fault has been detected on the protective line means determining that the fault occurred between the first measurement point and the second measurement point.

5. The protective line (114) comprises at least two ends, and the method comprises the combined phase power value (S) at each end of the protective line. Cmp ) and the determination of the differential phase power (S Diff The method according to any one of claims 1 to 4, comprising determining the sum of the combined phase powers at the end, wherein the criterion corresponds to the value of the differential phase power exceeding a threshold.

6. The protective line (114) comprises at least two ends, and the method comprises the combined phase power value (S) at each end of the protective line. Cmp ) and the determination of the differential phase power (S Diff ) is calculated as the sum of the combined phase powers at the end and the power loss along the transmission line (101) (S Loss The method according to any one of claims 1 to 4, comprising determining the difference between the following, wherein the criterion corresponds to the value of the differential phase power exceeding a threshold.

7. The differential power is, [Math 1] S Loss P is the power loss along the transmission line, Loss Q is the effective power loss along the transmission line, Loss The method according to claim 6, wherein n is the reactive power loss along the transmission line and n is the number of ends of the protective line.

8. The method according to claim 1, comprising determining a phase power value at a destination located along the transmission line at a certain distance from a measurement point, wherein the measurement point is located at the end of the protective line; determining a phase power value; and determining a delta phase power value at the destination by using the phase power value at the destination, wherein each delta phase power value is the difference between the current phase power value and the previous phase power value; and determining that the fault has been detected, based on the delta phase power value, comprising determining that the fault occurred between the measurement point and the destination.

9. The method according to claim 8, wherein the delta-phase power value includes the delta-phase power value of the positive-sequence power at the destination and the delta-phase power value of the combination of the negative-sequence power at the destination and the zero-sequence power at the destination.

10. Determining the delta phase power value means ΔS 1 @RP<ΔS 20 @RP This includes determining the formula by which ΔS １ @RP is the delta-phase power value of the positive-sequence power at the aforementioned point, and ΔS ２０ The method according to claim 9, wherein @RP is the delta-phase power value of the combination of the negative-phase power at the destination and the zero-phase power at the destination.

11. Determining the delta phase power value at the aforementioned destination includes utilizing a distance-related destination coefficient and a predetermined transmission line impedance, wherein the method is ΔQ １ @RP=ΔQ ２０ This further includes recursively estimating the value of the attainment coefficient for which the formula by @RP is valid, and ΔQ １ @RP is the reactive power portion of the delta-phase power value of the positive-sequence power at the aforementioned point, and ΔQ ２０ The method according to claim 9, wherein @RP is the reactive power portion of the delta-phase power value of the combination of the negative-phase power and the zero-phase power at the destination.

12. The method according to claim 8, comprising: determining a first voltage phasor and a first current phasor of different phases at the measurement point; determining a second current phasor at the destination point by using the first current phasor; determining a second voltage phasor at the destination point by using the first voltage phasor, the first current phasor, the line impedance of the transmission line, and a destination coefficient related to the distance; determining the phase power value at the destination point by using the second voltage phasor and the second current phasor; and determining the delta phase power value at the destination point by using the phase power value at the destination point.

13. A fault detection system for a power transmission system (100) comprising a transmission line (101), wherein the transmission line comprises a protective line constituting at least a portion of the transmission line, the transmission line has at least one phase, and the fault detection system comprises intelligent electronic devices (111, 112, 113) connectable to the transmission line and configured to detect faults on the protective line, wherein the intelligent electronic devices - Determining the positive-sequence power, negative-sequence power, and zero-sequence power of the power in the aforementioned protective line, - Determining whether or not the criteria are met, the criteria being the formula for the combined phase power as follows: S Cmp =k 1 *S 1 -(k 2 *S 2 +k 0 *S 0 ) It is defined by, In the formula, S Cmp is the combined phase power, S １ is the positive-sequence power, and S ２ This is the negative phase power, and S ０ k is the zero-sequence power, １ , k ２ , k ０ This is a non-negative configurable weighting coefficient, and the determination is made using the delta value (ΔS Cmp) of the combined phase power, which is determined as the difference between the current combined phase power value (S Cmp (present)) and the previous combined phase power value (S Cmp (previous)). - If it is determined that the above criteria are met, it is determined that a fault has been detected on the protective line. A fault detection system configured to perform the following actions.

14. The fault detection system according to claim 13, wherein the intelligent electronic devices (111, 112, 113) are connectable to the transmission line at a measurement point located at the end of the protective line, the intelligent electronic devices are configured to determine a phase power value at a destination point located along the transmission line at a certain distance from the measurement point, and to determine a delta phase power value at the destination point by using the phase power value at the destination point, each delta phase power value being the difference between the current phase power value and the previous phase power value, the criterion is based on the delta phase power value, and the determination that a fault has been detected includes determining that the fault occurred between the measurement point and the destination point.

15. The fault detection system according to claim 14, wherein the delta-phase power value includes the delta-phase power value of the positive-sequence power at the destination and the delta-phase power value of a combination of the negative-sequence power at the destination and the zero-sequence power at the destination.

16. A computer program that includes instructions to cause an intelligent electronic device, which can be connected to a transmission line of a power transmission system, to perform the method according to claim 1 when downloaded to the intelligent electronic device.

Images