JP-7857430-B2 - Method for detecting faults in transmission lines of a power transmission system

JP7857430B2JP 7857430 B2JP7857430 B2JP 7857430B2JP-7857430-B2

Inventors

ガイッチ，ゾラン

Assignees

ヒタチ・エナジー・リミテッド

Dates

Publication Date: 20260512
Application Date: 20230327
Priority Date: 20220428

Claims (16)

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, In the formula, S Cmp is the combined phase power, S1 is the positive phase power, S2 is the negative phase power, S0 is the zero phase power, k1 , k2 , and k0 are configurable non-negative weighting coefficients, and the determination is made using the delta value of the combined phase power (ΔS Cmp ) , 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 , Methods that include ...
The method according to claim 1, wherein determining the delta value (ΔS Cmp ) of the combined phase power includes determining the active power delta value (ΔP Cmp ) as the difference between the active power portion (P Cmp (present)) of the current combined phase power value and the active power portion (P Cmp (previous)) of the previous combined phase power value, and determining the reactive power delta value (ΔQ Cmp ) as the difference between the reactive power portion (Q Cmp (present)) of the current combined phase power value and the reactive power portion (Q Cmp (previous)) of the previous combined phase power value.
The method according to claim 2, comprising determining a first delta value (ΔS Cmp1 ) of the combined phase power at a first measurement point at the end of the protective line (114), which comprises determining a first active power delta value (ΔP Cmp1 ) and a first reactive power delta value (ΔQ Cmp1 ) at the first measurement point, wherein the criterion corresponds to the first active power delta value and the first reactive power delta value being positive and exceeding a predetermined threshold, and determining that a fault has been detected comprises determining that the fault has been detected in the forward direction from the first measurement point, wherein the forward direction is the direction from the first measurement point toward the protective line.
The method according to claim 3, further comprising determining a second delta value (ΔS Cmp2 ) 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, wherein the second delta value includes a second active power delta value (ΔP Cmp2 ) and a second reactive power delta value (ΔQ Cmp2 ) at the second measurement point, the criterion being 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 includes determining that the fault occurred between the first measurement point and the second measurement point.
The method according to any one of claims 1 to 4, wherein the protective line (114) comprises at least two ends, and the method includes determining the combined phase power value (S Cmp ) at each end of the protective line, and determining the differential phase power (S Diff ) as the sum of the combined phase powers at the ends, wherein the criterion corresponds to the value of the differential phase power exceeding a threshold.
The method according to any one of claims 1 to 4, wherein the protective line (114) comprises at least two ends, and the method includes determining the combined phase power value (S Cmp ) at each end of the protective line, and determining the differential phase power (S Diff ) as the difference between the sum of the combined phase powers at the ends and the power loss (S Loss ) along the transmission line (101), wherein the criterion corresponds to the value of the differential phase power exceeding a threshold.
The differential power is, The method according to claim 6, wherein S Loss is the power loss along the transmission line, P Loss is the active power loss along the transmission line, Q Loss is the reactive power loss along the transmission line, and n is the number of ends of the protective line.
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.
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.
Determining the delta phase power value means ΔS 1 @RP<ΔS 20 @RP The method according to claim 9, comprising determining an equation by which, ΔS 1 @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 of the combination of the negative-sequence power and the zero-sequence power at the destination.
The method according to claim 9, wherein determining the delta-phase power value at the destination includes utilizing a distance-related destination coefficient and a predetermined transmission line impedance, the method further includes recursively estimating a value of the destination coefficient such that the equation ΔQ1 @RP = ΔQ20 @RP is valid, where ΔQ1 @ RP is the reactive power portion of the delta-phase power value of the positive-sequence power at the destination , and ΔQ20 @RP is the reactive power portion of the delta-phase power value of the combination of the negative-sequence power at the destination and the zero-sequence power at the destination .
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.
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, S1 is the positive-sequence power, S2 is the negative-sequence power, S0 is the zero-sequence power, k1 , k2 , and k0 are non-negative configurable weighting coefficients, and the determination is made using the delta value of the combined phase power (ΔS Cmp ) , 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 )) . A fault detection system configured to determine that a fault has been detected on the protective line if it is determined that the above criteria are met.
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.
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.
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.

Description

Technical field This disclosure relates generally to power transmission systems, and more particularly to a method and system for detecting faults in protective lines constituting at least a portion of transmission lines in a power transmission system. Background: Power transmission systems, such as high-voltage (HV) or medium-voltage (MV) transmission systems, are at risk of large short-circuit faults, such as phase-to-phase or phase-to-phase faults. Such faults must be detected and corrected as quickly as possible. Therefore, transmission lines are monitored. Conventional solutions typically utilize current or impedance measurements. These have obvious drawbacks. For example, to identify the location of a fault along the transmission line, it may be necessary to transmit measurements between devices at different ends of the transmission line. Conventional methods place a very high demand for time synchronization of devices to produce correct results. Additionally, with respect to impedance measurements, they have drawbacks even for healthy phases, such as high-impedance faults, semaphore effects due to remote end supply, and impedance measurements. This is a block diagram of one embodiment of the fault detection system deployed within a transmission system.This is a flowchart of one embodiment of the fault detection method.This diagram shows the power status in a faulty transmission line. Detailed Description 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 in order 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 in the transmission line 101. Thus, 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. Note that the transmission line 101 or any portion thereof monitored by the IEDs 111-113 constitutes a protection line 114. As those skilled in the art will understand, the overall structure of the power transmission system shown in Figure 1 is merely one example among countless variations. In short, in addition to those described above, the power transmission system may be part of a grid or connected to a grid; the power sources may be multiple different types of power sources such as wind power plants, solar power plants, nuclear power plants, and transformers; and the loads may be multiple different types of loads such as production sites. The power transmission system may include multiple transmission lines, etc. These transmission lines may be HV AC lines or MV AC lines, and may extend between power sources, between power sources and loads, and thus constitute what are also called distribution lines, as recognized above. The length of the transmission lines can vary greatly, from a few kilometers, or even shorter, to several hundred kilometers. 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 determined based on the combined phase power S Cmp , which is determined based on the positive-sequence power S1 , the negative-sequence power S2 , and the zero-sequence power S0 , and at least one of at least one formula, which is determined based on at least two of the positive-sequence power S1 , the negative-sequence power S2 , and the zero-sequence power S0 . If the criterion is met, it is determined that a fault has been detected on the protective line 114 (box 203). The criteria may be based on at least one of the positive-sequence power S1 , negative-sequenc