Fault Detection in Power Transmission Systems

Abstract

The present subject matter describes fault detection during power oscillations in an electric power transmission system. Voltage measurements and current measurements are obtained for each phase at the terminals of the electric power transmission system. Based on the obtained measurements, for each sampled value of the voltage and current, a value of the change in impedance angle for each relative-to-ground loop and each relative-to-phase loop is calculated, wherein the value of the change in impedance angle is the difference between the impedance angles of two samples separated by a predetermined interval. In addition, for each relative-to-ground loop and each relative-to-phase loop, an average value of the change in impedance angle is calculated based on a predetermined number of values ​​of the change in impedance angle. The calculated average value is compared with a threshold value for the change in impedance angle, and based on the comparison, a fault in one or more of the relative-to-ground loop or the relative-to-phase loop is detected and the fault is classified.

Description

Technical Field

[0001] The present subject matter generally relates to fault detection in power transmission lines. In particular, the present subject matter relates to fault detection during power oscillations in power transmission systems. Background Art

[0002] The power transmission system is a large and complex network that includes transmission lines with many electrical components, such as generators, transformers, relays, etc. The power transmission system is often subject to system disturbances, such as due to transmission line faults, switching operations in heavily loaded power transmission lines, changes in load magnitude and direction, etc. In general, a fault can be defined as an abnormal condition of an electrical system that causes an interruption of the normal current flow. This current deviation from the flow results in a change in voltage and / or current flow, which interrupts the power transmission. System disturbances occurring in the transmission system can result in power oscillations.

[0003] Power oscillations are a phenomenon whereby the rotor angles of generator sets accelerate or decelerate relative to each other, resulting in changes in the three-phase power flow. In particular, inter-area oscillations can result in large power fluctuations between two areas of the power system connected via a tie line.

[0004] Relay tripping during power oscillation phenomena is undesirable, and therefore they are typically locked during power oscillations. Therefore, a fault occurring during a power oscillation may not be detected during the lockout period, which may result in a system blackout. BRIEF DESCRIPTION OF THE DRAWINGS

[0005] The features, aspects and advantages of the present subject matter will be better understood with respect to the following description and accompanying drawings.The use of the same reference numerals in different figures indicates similar or identical features and components.

[0006] 1( a ), 1( b ), 1( c ) and 1( d ) illustrate in a first example the monitoring of incremental current in a power transmission line for fault detection based on methods known in the art.

[0007] 2(a), 2(b), 2(c) and 2(d) illustrate in a second example monitoring incremental current in a power transmission line for fault detection based on methods known in the art.

[0008] Figure 3 A block diagram of a dual-source equivalent power grid according to an embodiment of the present subject matter is illustrated.

[0009] Figure 4 A two-terminal system with a device for fault detection during power oscillations according to an embodiment of the present subject matter is illustrated.

[0010] Figure 5 A method for fault detection during power oscillations in a power transmission system according to one embodiment of the present subject matter is illustrated.

[0011] 6(a), 6(b) and 6(c) illustrate fault detection according to an example implementation of the present subject matter.

[0012] 7(a), 7(b) and 7(c) illustrate fault detection according to another example implementation of the present subject matter. Summary of the invention

[0013] Embodiments of the present invention provide a method for fault detection during power oscillations in a power transmission system, an apparatus for fault detection, and a computer-readable storage medium for fault detection.

[0014] According to a first aspect, a method for fault detection during power oscillation in a power transmission system is provided. The method includes obtaining voltage measurements and current measurements for each phase at a terminal of the power transmission system. The voltage measurements and the current measurements are obtained using one or more measurement equipment associated with the terminal of the power transmission system. The voltage measurements and the current measurements include sampled values ​​of voltage and current obtained at the terminal. Based on each sampled value of the voltage and current, a value of a change in the impedance angle of each relative-to-ground loop and each relative-to-phase loop is calculated, wherein the value of the change in the impedance angle is the difference between the impedance angles of two samples separated by a predetermined interval. In addition, for each relative-to-ground loop and each relative-to-phase loop, an average value of the change in the impedance angle is calculated for a predetermined number of values ​​of the change in the impedance angle. The average value calculated for each relative-to-ground loop and each relative-to-phase loop is compared with a threshold value of the change in the impedance angle, and based on the comparison, a fault in one or more of the relative-to-ground loop or the relative-to-phase loop is detected. The threshold value may be in the range of 1 degree to 3 degrees. When the average value of the change in the impedance angle is within the threshold range, a fault in one or more of the phase-to-ground loop or the phase-to-phase loop is detected.

[0015] According to a second aspect, an intelligent electronic device (IED) for detecting faults in a power transmission line is provided. The IED comprises a processor and a fault detection module executable by the processor. The fault detection module is configured to obtain voltage measurements and current measurements from each phase at a terminal of the power transmission system. The voltage measurements and the current measurements are obtained using one or more measurement equipment associated with the terminal of the power transmission system. The voltage measurements and the current measurements include sampled values ​​of voltage and current obtained at the terminal. The fault detection module is configured to: for each sampled value of the voltage and current, calculate a value of a change in the impedance angle of each relative-to-ground loop and each relative-to-phase loop. The change in the impedance angle is the difference between the impedance angles of two samples and the two samples are separated by a predetermined interval. In addition, the fault detection module is configured to: for each relative-to-ground loop and each relative-to-phase loop, calculate an average value of the change in the impedance angle for a predetermined number of values ​​of the change in the impedance angle. The average value calculated for each relative-to-ground loop and each relative-to-phase loop is compared with a threshold value of the change in the impedance angle. Based on the comparison, a fault in one or more of the relative-to-ground loop or the relative-to-phase loop is detected. The threshold value may be in the range of 1 degree to 3 degrees. When the average value of the change in impedance angle is within the threshold value range, a fault in one or more of the relative-to-ground loop or the relative-to-phase loop is detected.

[0016] According to a third aspect, a non-transitory computer-readable medium contains program instructions that, when executed, cause an intelligent electronic device (IED) to detect a fault in a power transmission line. The program instructions include instructions to: obtain voltage measurements and current measurements from each phase at a terminal of the power transmission system. The voltage measurements and the current measurements are obtained using one or more measurement equipment associated with the terminal of the power transmission system. The voltage measurements and the current measurements include sampled values ​​of voltage and current obtained at the terminal. The program instructions also include instructions to: for each sampled value of the voltage and current, calculate a value of a change in impedance angle for each relative ground loop and each relative phase loop. The change in impedance angle is the difference between the impedance angles of two samples and the two samples are separated by a predetermined interval. In addition, the program instructions include instructions to: for each relative ground loop and each relative phase loop, calculate an average value of the change in impedance angle for a predetermined number of values ​​of the change in impedance angle. The average value calculated for each relative ground loop and each relative phase loop is compared with a threshold value for the change in impedance angle. The threshold value may be in the range of 1 degree to 3 degrees. When the average value of the change in impedance angle is within the threshold range, a fault in one or more of the phase-to-ground loop or the phase-to-phase loop is detected. DETAILED DESCRIPTION

[0017] The present subject matter relates to fault detection in power transmission lines. The following describes fault detection related to power oscillations, in particular detecting faults at or near the oscillation center voltage. However, the subject matter is not limited to fault detection in power oscillations.

[0018] Power oscillations are generally classified into stable power oscillations and unstable power oscillations. Stable power oscillations occur when the generators do not slip poles or lose synchronization and the system reaches an acceptable operating state. However, unstable power oscillations may cause slippage between poles of the generators, resulting in severe fluctuations in voltage, current and power.

[0019] During the power oscillation period, the distance relay will usually be locked and cannot operate to prevent malfunction because the impedance locus may enter the operating area of ​​the distance measurement zone. If a fault occurs during the lock period of the distance relay during the power oscillation, the fault will remain undetected. Undetected faults put pressure on power system components, such as transformers, generators, etc. The pressure on power system components in turn affects the stability of the power system. In order to avoid widespread interference, the distance relay should only be allowed to operate for short-circuit faults during power oscillations, and remain unlocked when no fault occurs during power oscillations. This is called power oscillation unlocking. When faults occurring during power oscillations cannot be detected, they may cause equipment or system failures and in the worst case may cause power outages.

[0020] In addition to fault detection, fault classification must also be performed to be able to identify the fault type. Generally, faults can be classified into four types of faults, namely line-to-ground fault Ag, line-to-line fault AB, double line-to-ground fault BC-g, and three-phase fault ABC-g, where A, B, and C are the three phases of the power transmission line.

[0021] In one technique, for fault detection and classification during power oscillations, i.e., during the power oscillation unlocking period, differential currents are used. However, these differential or incremental currents are not available in all power system conditions, such as faults near the oscillation center voltage, systems with high source impedance, inverter-based systems (renewable energy sources), during high impedance faults, etc. Therefore, during such power system conditions, fault detection and classification may be performed unreliably.

[0022] FIG. 1(a), FIG. 1(b), FIG. 1(c) and FIG. 1(d) illustrate in a first example the monitoring of incremental current in a power transmission line for fault detection based on methods known in the art. In the first case, the predefined threshold current is set to a value of 1 kA. The predefined threshold is set to detect a fault based on a comparison of the incremental current value with a set threshold.

[0023] The example of Figures 1(a)-1(d) considers that a fault may have occurred on the transmission line at a distance of 20% of the protected line. The source line impedance ratio (SIR) of the two sources is considered to be 0.1:1, where SIR is the ratio of source impedance to line impedance. The fault inception angle is 60 degrees. In addition, the slip frequency is considered to be 0.5 Hz and the time to fault inception is considered to be 3 seconds. Based on these parameters, a delta current based fault detection analysis is performed.

[0024] FIG. 1( a) depicts an incremental current flow analysis for fault detection and classification in a power transmission system. The current measured in phase A is represented by 102, the current measured in phase B is represented by 104, and the current measured in phase C is represented by 106. As can be observed from the figure, the current 102 measured in phase A shows an incremental rise in its value after a period of 3 seconds. The current 104 measured in phase B and the current 106 measured in phase C do not show any incremental rise in current value at the same time. The incremental value of the current measurement results is observed only in phase A after the fault starts. Therefore, the faulty phase is identified by comparing the incremental value of the current 102 measured in phase A with a predefined threshold set to 1 kA. Because the faulty phase is identified as phase A, the fault is classified as a line-to-ground fault Ag.

[0025] FIG. 1( b) depicts an incremental current flow analysis for fault detection and classification in a power transmission system, wherein it can be observed from the figure that the current 102 measured in phase A and the current 104 measured in phase B show incremental values ​​after a period of 3 seconds. The current 106 measured in phase C does not show any incremental current value at the same time. Incremental values ​​of current measurements are observed only in phase A and phase B after the fault starts. Therefore, the faulty phases are identified by comparing the incremental values ​​of the current 102 measured in phase A and the current 104 measured in phase B with a predefined threshold value set to 1 kA. Since the faulty phases are identified as phase A and phase B and based on the magnitude of the currents in these identified phases, the fault is classified as a line-to-line fault AB.

[0026] FIG. 1( c ) depicts an incremental current flow analysis for fault detection and classification in a power transmission system, wherein it can be observed from the figure that the current 104 measured in phase B and the current 106 measured in phase C show incremental values ​​after a period of 3 seconds. While the currents in phase B and in phase C show incremental changes, the current 102 measured in phase A does not show any incremental current value at the same time. After the fault starts, incremental current measurements are observed only in phase B and phase C of the transmission line. Therefore, the faulty phases are identified by comparing the incremental values ​​of the current 104 measured in phase B and the current 106 measured in phase C with a predefined threshold value set to 1 kA. Since the faulty phases are identified as phase B and phase C and based on the magnitude of the currents in the identified phases, the fault is classified as a double line-to-ground fault BC-g.

[0027] FIG. 1( d) depicts an incremental current flow analysis for fault detection and classification in a power transmission system, wherein it can be observed from the figure that the current 102 measured in phase A, the current 104 measured in phase B, and the current 106 measured in phase C show incremental values ​​after a period of 3 seconds. After the fault begins, incremental current measurements are observed in all three phases of the transmission line, such as phase A 102, phase B 104, and phase C 106. Thus, the faulty phases are identified by comparing the incremental values ​​of the currents 102, 104, 106 measured in phase A, phase B, and phase C with a predefined threshold value set to 1 kA. Since the faulty phases are identified as phase A, phase B, and phase C and based on the magnitude of the currents in the identified phases, the fault is classified as a three-phase to ground fault ABC-g.

[0028] FIG. 2(a), FIG. 2(b), FIG. 2(c) and FIG. 2(d) illustrate in a second example the monitoring of incremental current in a power transmission line for fault detection based on methods known in the art. In the second example, similar to the first example, a predefined threshold current is set to 1 kA for fault detection and classification. The predefined threshold is set to be compared with the incremental current value observed when a fault occurs.

[0029] In the example shown in Figures 2(a)-2(d), a fault is simulated at a distance of 80% of the protected line during an oscillation of the oscillation center voltage at 5 Hz. In this case, a fault has been simulated at an oscillation center voltage with a high slip frequency of 5 Hz for fault detection and classification based on incremental current monitoring under adverse conditions. The source-line impedance ratio (SIR) of the two sources is considered to be 5:2 in the second case, where the fault resistance is 10 ohms. In addition, the time to the start of the fault is set to 1.3 seconds. Based on these parameters, an incremental current-based fault detection analysis is performed.

[0030] FIG2( a) depicts an incremental current flow analysis for fault detection and classification in a power transmission system. The current measured in phase A is represented by waveform 202, the current measured in phase B is represented by waveform 204, and the current measured in phase C is represented by waveform 206. As can be observed from the figure, the current 202 measured in phase A shows an incremental value after a time of 1.3 seconds. While the current measured at A shows an incremental change, the current 204 measured in phase B and the current 206 measured in phase C do not show any incremental current values ​​at the same time. After the fault begins, incremental current measurements are observed only in phase A. In order to identify the faulty phase, the incremental value of the current 102 measured in phase A is compared with a predefined threshold set to 1 kA. However, because the incremental current is less than the threshold, the fault is not detected and cannot be classified.

[0031] FIG2( b) depicts an incremental current flow analysis for fault detection and classification in a power transmission system, wherein it can be observed from the figure that the current 202 measured in phase A and the current 204 measured in phase B show incremental values ​​after a time of 1.3 seconds. While the current measured at phase A and the current measured at phase B show incremental changes, the current 206 measured in phase C does not show any incremental current value at the same time. After the fault starts, incremental current measurements are observed only in phase A and phase B. In order to identify the faulty phase, the incremental values ​​of the current 202 measured in phase A and the current 206 measured in phase B are compared with a predefined threshold value set to 1 kA. However, because the incremental rise in current is less than the threshold, the fault is not detected and cannot be classified.

[0032] FIG2(c) depicts an incremental current flow analysis for fault detection and classification in a power transmission system, wherein as can be observed from the figure, the current 204 measured in phase B and the current 206 measured in phase C show an incremental rise in their values ​​after a time of 1.3 seconds. While the current measured at phase B and the current measured at phase C show incremental changes, the current 202 measured in phase A does not show any incremental current value at the same time. After the fault begins, incremental current measurements are observed only in phase B and phase C of the transmission line. In order to identify the faulty phase, the incremental values ​​of the current 204 measured in phase B and the current 206 measured in phase C are compared with a predefined threshold value set to 1 kA. However, because the incremental current is less than the threshold, the fault is not detected and cannot be classified.

[0033] FIG2(d) depicts an incremental current flow analysis for fault detection and classification in a power transmission system. As can be observed from the figure, the current 202 measured in phase A, the current 204 measured in phase B, and the current 206 measured in phase C show incremental values ​​after a period of 1.3 seconds. After the fault begins, incremental current measurements are observed in all three phases of the transmission line (phase A 202, phase B 204, and phase C 206). In order to identify the faulty phase, the incremental values ​​of the current 202 measured in phase A, the current 204 measured in phase B, and the current 206 measured in phase C are compared with a predefined threshold value set to 1 kA. However, because the incremental rise in current is less than the threshold value, the fault is not detected and cannot be classified.

[0034] It can be seen from the first and second examples discussed above with reference to Figures 1(a)-1(d) and Figures 2(a)-2(d) that for the situation described in Figures 2(a)-2(d), the incremental rise in current is not above the threshold. The incremental amount depends on various factors, such as the SIR of the system, the location of the fault, the fault start angle and the fault impedance. Considering the specific example of a line-to-ground fault - an Ag fault - it is observed from the two examples discussed above that the maximum incremental amount of current measured in the first example is 50kA, which is greater than the threshold of 1kA, and the maximum incremental amount of current measured in the second example is 0.5kA, which is less than the threshold of 1kA. Therefore, the occurrence of the fault in the first example can be detected, while the occurrence of the fault in the second example cannot be detected.

[0035] Therefore, using the comparison of the incremental amount of current measured in any one phase of the transmission line with a predefined threshold to identify the faulty phase is not reliable in all situations. In addition, the threshold depends on parameters such as fault onset, location of the fault and fault resistance, and the fault at the crest or center of the oscillation of the voltage. Therefore, there is a need to develop a current threshold-free fault detection and classification method for faults during power oscillations.

[0036] The present subject matter provides accurate single-ended fault detection and classification using local measurements on protected lines, particularly during power oscillations in power transmission systems. The fault detection and classification is based on changes in impedance angles, also known as delta impedance angles. An example method includes measuring three phase voltages and currents to obtain voltage measurements and current measurements at one terminal or one end of a transmission line. The voltage measurements and current measurements are obtained from a measuring device in the form of a voltage signal and a current signal, respectively. The signals are sampled according to a configured sampling frequency to obtain sampled values ​​of the voltage and current. Sampled values ​​may be obtained for each instant in a measurement cycle. For example, a measurement cycle may have 20 milliseconds (50 Hz frequency), and multiple samples may be obtained at each millisecond at a sampling frequency of 1 kHz. The amplitude and angle of the voltage and current are calculated from the sampled values. For each of the obtained sampled values, the change in the impedance angle of each relative ground loop and each relative phase loop is calculated with reference to another sample separated by a predetermined interval from the sample under consideration. In addition, for each phase-to-ground loop and each phase-to-phase loop, an average value is calculated for a predetermined number of values ​​of the change in impedance angle. The calculated average value is compared with a threshold value, and based on the comparison, a fault is detected in the corresponding loop and the fault is classified. For example, the threshold value may be a threshold range, and when the average value is within the threshold range, a fault may be detected, and the fault may be classified according to the loop in which the fault is detected.

[0037] The above and other features, aspects and advantages of the present subject matter will be better explained with respect to the following description and drawings. Whenever possible, the same reference numerals are used in the drawings and the following description to refer to the same or similar parts. Although several examples are described, modifications, adaptations and other implementations are possible.

[0038] Figure 3 A block diagram of a dual-source equivalent power grid 300 according to an embodiment of the present subject matter is illustrated. The dual-source equivalent power grid 300 includes a power transmission line 312 connected between two terminal bus M 301 and bus N 302. Two power sources, namely source 303 and source 304, supply power to bus M 301 and bus N 302, respectively. In one example, source 303 and source 304 can be power generators, such as synchronous power generators. The power grid 300 can transmit electric power at high voltages such as in the range of several thousand volts and over long distances such as tens or hundreds of kilometers.

[0039] The subject technology may be implemented with one or more devices associated with a power transmission line. The devices may include current transformers, voltage transformers, circuit breakers, and intelligent electronic devices (IEDs). Figure 3 , IED A 308 is associated with bus M 301, also referred to as a first terminal, and IED B 310 is associated with bus N 302, also referred to as a second terminal. The voltage transformer at each terminal is depicted as VT, and the current transformer at each terminal is depicted as CT. The IEDs may be configured to detect power oscillations in the power transmission line, and subsequently detect faults during the power oscillations, using techniques known in the art.

[0040] In one example, the steps of the method of the subject matter can be performed by one or more modules. The modules can be implemented as instructions executable by one or more processors. In some examples, the method can be performed by an IED, while in other examples, the method can be performed by a server that receives voltage measurements and current measurements from the IED. For example, in an example where an IED (such as IED 308 and IED 310) performs the method, the modules are performed by processors of IED 308 and IED 310. In other examples where a server performs the method, the modules can be performed by a processor of the server. If the method is partially implemented by an IED and partially implemented by a server, the modules (depending on the steps) will be distributed in the IED and the server accordingly.

[0041] In one example, IED A 308 and IED B 310 may have a Figure 3320-1 and 320-2. The IED 308 and IED 310 may be configured to receive input measurement signals from various measurement equipment connected to the transmission line 312, such as current transformers, voltage transformers, Rogowski coils or other measurement sensors. The IED 308 and IED 310 may process the measurement results obtained with the help of the processor 320-1 and the processor 320-2, respectively. The processor 320-1 and the processor 320-2 may be individually referred to as the processor 320. The processor 320 may be implemented as a dedicated processor, a shared processor or a plurality of separate processors, some of which may be shared. The IED 308 and IED 310 may each include a memory 326-1 and a memory 326-2, respectively, which are communicatively connected to the corresponding processor 320. The memories 326-1 and 326-2 may be individually referred to as the memory 326. Among other capabilities, the processor 320 may retrieve and execute computer-readable instructions stored in the memory 326. In one example, the memory 326-1 and the memory 326-2 may store the fault detection module 322-1 and the fault detection module 322-2, respectively. The fault detection module 322-1 and the fault detection module 322-2 may be individually referred to as the fault detection module 322. In other examples, the fault detection module 322 may be external to the memory 326. The memory 326 may include any non-transitory computer-readable medium, including, for example, volatile memory, such as RAM, or non-volatile memory, such as EPROM, flash memory, etc.

[0042] In one example, upon detecting a power oscillation in a transmission line, a method for detecting a fault that may occur during a power oscillation may be performed by the IED. For discussion, a method for fault detection is described with reference to an IED 308 implemented at a terminal M 301. However, as can be appreciated, a similar method will be performed by an IED 310 at a terminal N. In order to detect a fault, a processor 320 of the IED 308 may fetch instructions to execute a fault detection module 322 to calculate a voltage phasor and a current phasor based on the measured voltage and current at the terminal M 301. In one example, the voltage phasor and the current phasor may be calculated based on an average value of sampled values ​​of the measured voltage and current. The calculated voltage phasor and current phasor may be used to calculate an impedance angle. The change in the impedance angle may be calculated for many samples to calculate an average value of the change in the impedance angle. Based on the average value of the change in the impedance angle, a fault may be detected in the transmission line 312. In one example, upon detecting a fault, the fault detection module 322 may enable a line protection function for the corresponding loop. In one example, the fault detection module 322 can enable a distance protection function for the corresponding loop, which is usually locked during power oscillations. For example, the IED 308 can be configured to release a phase in which a fault on the transmission line can be detected for distance protection. The distance protection function can be performed using techniques known in the art.

[0043] In addition, the IED 308 and the IED 310 may include an output interface 324-1 and an output interface 324-2, respectively, to communicate the results obtained from the fault detection module 322, for example, to a server. The output interface 324-1 and the output interface 324-2 may be individually referred to as output interfaces 324. In one embodiment, when the method is implemented at the server, the IED 308 may communicate the current measurement results and the voltage measurement results to the server through the output interface 324. The output interface 324 may include a variety of computer-readable instruction-based interfaces and hardware interfaces that allow interaction with other communication devices, storage devices, and computing devices, such as network entities, network servers, databases, and external repositories, and peripheral devices. In one example, the fault detection parameters, current measurement results, voltage measurement results, etc. can be viewed on a display connected to the output interface 324 or integrated with the IED 308 and the IED 310.

[0044] Figure 4 A two-terminal system having a device for fault detection during power oscillations according to an example embodiment of the present subject matter is illustrated. The two-terminal test system 400 may include two sources E SM 402 and E SN 404. In one example, two sources ESM 402 and E SN 404 may be a synchronous power generator connected to two buses M 406 and N 408, respectively. Bus M 406 is alternatively referred to as a first terminal M 406, and bus N 408 is alternatively referred to as a second terminal N 408. In one example, there may be two transmission lines: line 1 411 and line 2 412, which may be connected between the two terminals M 406 and N 408.

[0045] It should be understood that the two-terminal test system 400 for fault detection may include a plurality of additional components or devices for monitoring, sensing and controlling various parameters that may be associated with the transmission line but are not shown for the sake of brevity. For example, components such as circuit breakers, sensors, current transformers, voltage transformers, loads connected to the transmission line, shunt reactors, intelligent electronic devices IEDs, protection relays, etc. may be connected to the transmission line.

[0046] exist Figure 4 In one example shown in FIG. 4 , a two-terminal test system 400 includes a pair of circuit breakers CB1 410-1 and CB3 410-3 connected to terminals M on line 2 and line 1, respectively. Similarly, circuit breaker CB2 410-2 and circuit breaker CB4 410-4 are connected to terminals N on line 2 and line 1, respectively. Circuit breakers CB are electrical switches for connecting or disconnecting the flow of current in power transmission lines. They are typically configured to operate automatically or manually based on signals from IEDs or other protection devices. Circuit breakers are used to protect high-voltage power transmission lines from current overload conditions that may occur during faults. They cut off the flow of current in the event of the fault, which protects the transmission line and components connected to the transmission line from further damage, and when the fault is cleared, the circuit breaker can be configured to resume normal operation.

[0047] IED 414 and IED 416 are respectively arranged at terminal M and terminal N of transmission line 411. IED 414 and IED 416 can be similar to IED 308 and IED 310 discussed above. It should be understood that transmission line 412 can also be connected to an IED at each terminal. In one example, IED 414 and IED 416 can include a fault detection module 420-1 and a fault detection module 420-2, respectively. Fault detection module 420-1 and fault detection module 420-2 can be individually referred to as fault detection module 420. For ease of discussion, as an example, the following description is provided using IED 414. However, it should be understood that IED 416 will also operate in a similar manner.

[0048] When the IED 414 detects a power oscillation, the fault detection module 420 may be triggered by the IED 414. The fault detection module 420 obtains voltage measurements and current measurements for each phase at the corresponding terminals of the power transmission system. As explained above, the voltage measurements and current measurements may be obtained using one or more measurement equipment associated with the terminals of the power transmission system, such as current transformers and voltage transformers. The voltage measurements and current measurements include sampled values ​​of voltage and current obtained at the terminals.

[0049] The fault detection module 420 pre-processes the measured three phase voltage signals and three phase current signals. The pre-processing of the measured voltage signals and current signals includes calculating the relative ground voltage amplitude and current amplitude and the relative phase voltage amplitude and current amplitude and their phase angles, also known as voltage phasors and current phasors, for each phase or measurement loop. The voltage phasors and current phasors of each relative ground loop and each relative phase loop can be calculated based on the full cycle discrete Fourier transform of the voltage measurement results and the current measurement results. The voltage measurement results and the current measurement results include sampled values ​​of voltage and current obtained from the voltage phasors and the current phasors and are stored in the memory of the IED 414. The number of samples N depends on the sampling frequency and the sampling interval. For example, if a 50Hz signal is sampled at a rate of 1kHz, there may be 20 samples per basic power cycle. These sampled values ​​of voltage and current are stored in a buffer in the memory and are used for fault detection when the IED A 414 detects a power oscillation.

[0050] During power oscillations, there may be a continuous change in the three-phase power flow. As an example, this may be due to a relative advance or delay of the rotor angle of the generator connected in the two-terminal system 400. Such a change may be due to a fault or it may be a typical power oscillation change. Upon detecting a power oscillation, a method of detecting a fault may be triggered by the IED 414 and performed by the fault detection module 420.

[0051] The fault detection module 420 calculates a value of a change in the impedance angle of each phase-to-ground loop and each phase-to-phase loop, wherein the value of the change in the impedance angle is a difference between impedance angles of two samples separated by a predetermined interval.

[0052] Equation 1 provides a calculation of the value of the change in impedance angle of the phase-to-ground loop and the phase-to-phase loop, which is alternatively referred to as the differential impedance angle:

[0053] dθ Lx (k) = θ Lx (k)-θ Lx (kN) (1)

[0054] in,

[0055] θ Lx is the impedance angle of loop x,

[0056] dθ Lx is the change in impedance angle of the kth sample of loop x,

[0057] θ Lx (k) is the calculated impedance angle of the kth sample of loop x,

[0058] N is the number of samples per measurement cycle, where a measurement cycle includes a predetermined number of samples based on the sampling frequency, and

[0059] x represents a phase-to-ground loop or a phase-to-phase loop.

[0060] Here, x can take values ​​of 1, 2, 3, 12, 23, and 31. In one example, when x is equal to 1, the value of the change in the impedance angle of the phase A relative to the ground loop is calculated. When x is equal to 2, the value of the change in the impedance angle of the phase B relative to the ground loop is calculated. When x is equal to 3, the value of the change in the impedance angle of the phase C relative to the ground loop is calculated. Similarly, when x is equal to 12, the value of the change in the impedance angle of the phase AB relative to the phase loop is calculated. When x is equal to 23, the value of the change in the impedance angle of the phase BC relative to the phase loop is calculated, and when x is equal to 31, the value of the change in the impedance angle of the phase CA relative to the phase loop is calculated.

[0061] As discussed, for each sampled value of the voltage and current values, the value of the change in impedance angle for each phase-to-ground loop and each phase-to-phase loop may be calculated. The value of the change in impedance angle is the difference in impedance angle between two samples separated by a predetermined interval. In one example, the value of the change in impedance angle may be calculated for phase A for the 21st sample which is the current sample, and where the total number of samples N=20. The value of the change in impedance angle may be calculated using Equation 1, where substituting the values ​​of N and k into Equation 1, we obtain:

[0062] dθ Lx (21) = θ Lx (21)-θ Lx (1) (1)

[0063] Therefore, the value of the change in impedance for the 21st sample will be the difference between the impedance angle obtained for the 21st sample and the impedance angle obtained for the first sample. Once the value of the change in impedance angle is calculated, for each phase-to-ground loop and each phase-to-phase loop, an average value of the change in impedance angle is calculated for a predetermined number of values ​​of the change in impedance angle.

[0064] A predetermined number of impedance angle change values ​​may be used to calculate the average value. For example, five impedance angle change values, such as dθLx (21), dθ Lx (22), dθ Lx (23), dθ Lx (24) and dθ Lx The values ​​of (25) can be averaged. In one embodiment, the average value is calculated by applying a moving window average filter to calculate the values ​​of the change in impedance angle of the samples, where the predetermined number of values ​​of the change in impedance angle is the size of the moving window. In one example, the size of the moving window can be equal to the number of samples in one measurement cycle. The moving average of the values ​​of the change in impedance angle can be calculated as shown in Equation 2:

[0065]

[0066] Where Dθ Lx is the average value of the change in impedance angle, dθ Lx (q) is the value of the change in impedance angle at the qth sample, q takes values ​​of k-N+1, where k is the current sample and N is the total number of samples per cycle. It should be understood that in other examples, different values ​​of N may be used. Using an average, particularly a moving average, helps smooth out the calculated value of the change in impedance angle.

[0067] The average value of the change of the impedance angle calculated for each relative-to-ground loop and each relative-to-phase loop is compared with a threshold value of the change of the impedance angle. The threshold value can be set by a user, such as an expert. In one example, the threshold value is a range, wherein the range is 1 degree to 3 degrees. The average value of the change of the impedance angle is compared with the threshold range. Therefore, it can be determined whether the moving average value is within the range. In one example, when the average value of the change of the impedance angle is within the threshold range of the change of the impedance angle, a fault is detected in one or more of the relative-to-ground loop or the relative-to-phase loop. According to the loops in which the moving average value of the change of the impedance angle is within the range, the fault can be further classified as a relative-to-ground fault or a relative-to-phase fault. When the value of the moving average value of the change of the impedance angle is not within the threshold range, no fault is detected.

[0068] The mean value calculated at each step (ie for each sample) is iteratively compared with the threshold range until a fault is detected or until all mean values ​​corresponding to samples obtained during the duration of the power oscillation have been compared.

[0069] In addition, when a fault is detected, the distance protection function of the IED 414, which is usually locked during power oscillations, may be triggered. The distance protection function releases the corresponding distance measurement loop when a fault in one or more of the phase-to-earth loop or the phase-to-phase loop is detected to determine the distance between the terminal M 406 and the starting point of the fault.

[0070] Therefore, the present subject matter provides an efficient fault detection technique based on the value of the change of the impedance angle, so that faults can be detected, especially during power oscillations. During power oscillations, the impedance angle changes linearly, and when a fault occurs, the impedance angle does not change significantly (almost constant), especially when the fault is close to the oscillation center voltage. Therefore, in order to detect these faults, the value of the change of the impedance angle is utilized. In addition, the two-terminal system 400 not only detects faults in power oscillations, but also detects faults that may occur at or near the oscillation center voltage, making the two-terminal system 400 very efficient. Such an oscillation center voltage is the voltage of a dual-source equivalent system-when the voltage value is zero or close to zero, for example, when the rotor angles of the two systems are 180 degrees apart.

[0071] Figure 5 A method for fault detection during power oscillations in a power transmission line according to one embodiment of the present subject matter is illustrated. The order in which the method 500 is described is not intended to be construed as a limitation, and some of the described method blocks may be performed in a different order to implement the method 500 or an alternative method. Furthermore, the method 500 may be implemented in any suitable hardware, computer readable instructions, firmware, or a combination thereof. For discussion, reference is made to Figure 3-Figure 4 Method 500 is described with reference to the embodiment illustrated in FIG.

[0072] In method 500, at box 502, voltage measurements and current measurements are obtained for each phase at a terminal of a power transmission system. The voltage measurements and current measurements are obtained using one or more measurement equipment associated with the terminal of the power transmission system. The voltage measurements and current measurements include sampled values ​​of voltage and current obtained at the terminal. In an example, the voltage measurements can be obtained for each phase at the terminal of the power transmission system by a voltage transformer or a potential transformer, and the current measurements can be obtained for each phase at the terminal of the power transmission system by a current transformer. In an example, the current transformer and the voltage transformer can be operably connected to an intelligent electronic device IED at a terminal M and a terminal N. Figure 4In the example of , terminal M is shown by 406 and terminal N is shown by 408. The three-phase voltage measurements and current measurements measured at terminals M and N of the transmission line can be fed to IED 414 and IED 416, respectively. Voltage phasors and current phasors are calculated based on the current measurements and voltage measurements monitored on line 1411. In one example, the voltage phasors and current phasors are calculated using a full cycle discrete Fourier transform (DFT).

[0073] At block 504, for each sampled value of the voltage and current, a value of a change in impedance angle of each phase-to-ground loop and each phase-to-phase loop is calculated. The value of the change in impedance angle is the difference in impedance angle of two samples separated by a predetermined interval. The predetermined interval between the two samples used to determine the value of the change in impedance angle is the duration of one measurement cycle, wherein one measurement cycle includes a predetermined number of samples based on a sampling frequency.

[0074] At block 506, for each phase-to-ground loop and each phase-to-phase loop, an average value of the change in impedance angle is calculated for a predetermined number of values ​​of the change in impedance angle. The predetermined number of values ​​may take any positive integer value starting from one. In one example, the predetermined number of values ​​for calculating the average value of the change in impedance angle may be 5. The average value may be calculated by applying a moving window average filter to calculate the values ​​of the change in impedance angle of the samples, wherein the predetermined number of values ​​of the change in impedance angle is the size of the moving window.

[0075] At block 508, the average of the change in impedance angle calculated for each phase-to-ground loop and each phase-to-phase loop is compared with a threshold range of the change in impedance angle. In one example, the threshold is in the range of 1 degree to 3 degrees. When it is determined that the moving average is within the threshold range, the occurrence of a fault is detected.

[0076] At box 510, based on the comparison at box 508, a fault is detected and further classified as a fault in one or more of the phase-to-earth loop or the phase-to-phase loop. In one example, the fault detected in one or more of the phase-to-earth loop or the phase-to-phase loop based on the comparison may be at the oscillation center voltage. When the value of the moving average is within the threshold range, the fault is detected and classified as a phase-to-earth fault, a phase-to-phase fault, or a double phase-to-earth fault. Upon detecting the occurrence of a fault, the IED is configured to release the corresponding loop for distance protection when a fault in one or more of the phase-to-earth loop or the phase-to-phase loop is detected to measure the distance from the terminal of the power transmission system to the fault, wherein the distance is the distance between the terminal M or the terminal N to the starting point of the fault.

[0077] 6(a), 6(b) and 6(c) illustrate fault detection according to an example implementation of the present subject matter.

[0078] For example Figure 3 The 500 kV single circuit system shown tests the technique of fault detection and classification based on the changed value of the impedance angle. The three-phase voltage and three-phase voltage current measured at the terminal M and the terminal N are fed to the IED 308 at the terminal M and the IED 310 at the terminal N. Different fault scenarios for different types of faults, different fault resistance values, source-line impedance ratios, fault locations, slip frequencies, and fault locations of oscillation periods are created and tested.

[0079] A first scenario was tested and compared for two techniques for fault detection. The first technique for fault detection is based on the presence of differential current - a method known in the art. The second technique for fault detection is based on values ​​based on changes in impedance angle according to the present subject matter. The following parameters were used to simulate fault detection for the first and second techniques, simulating and testing a phase-to-ground fault on phase A with a fault distance of 50 km and a fault start time of 1.08 seconds on line 1.

[0080] FIG6(a) depicts three-phase voltage signals 602, 604 and 606 of phases A, B and C and current signals 608, 610, 612 and 614 of phases A, B, C and neutral, respectively, measured at IED A at terminal M. FIG6(b) depicts three-phase current signals 616, 618 and 620 at the beginning of a fault. The graph shows the results obtained from the first technique for fault detection, and it is observed that low differential currents below the current threshold of the three-phase currents have been detected at the beginning of the fault. Therefore, the phase-to-ground fault on phase A is not detected. However, FIG6(c) depicts release signals 622, 624 and 626 for distance measurement for fault detection by the change of the impedance angle of the present subject, respectively, in phases A, B and C. Upon detection of a phase-to-ground fault in phase A, the output obtained by the technique of change of the impedance angle according to the present subject produces a release signal 622 of the distance to be measured at 1.235 seconds.

[0081] 7(a), 7(b) and 7(c) illustrate fault detection according to another example implementation of the present subject matter.

[0082] The second scenario was tested and compared for two techniques for fault detection. The first technique for fault detection is based on the presence of differential current - a method known in the art. The second technique for fault detection is based on the value of the change of the impedance angle according to the present subject matter. The following parameters were used to simulate fault detection for the first and second techniques, simulating and testing a phase-to-phase to ground fault on phase AB with a fault distance of 50 km and a fault start time of 1.08 seconds on line 1.

[0083] FIG. 7( a) depicts three-phase voltage signals 702, 704 and 706 of phases A, B and C and current signals 708, 710, 712 and 714 of phases A, B, C and neutral, respectively, measured at IED A at terminal M. FIG. 7( b) depicts three-phase current signals 716, 718 and 720 at fault onset. The graph shows the results obtained according to the first technique for fault detection, and it is observed that a low differential current has been measured for the faulty phase. Since there is no observed differential current above the threshold during fault onset in the graph as depicted in FIG. 7( b), a relative phase-to-ground fault on phase AB is not detected. However, FIG. 7( c) depicts release signals 722, 724 and 726 for distance measurement for fault detection by change of impedance angle of the present subject matter, respectively, in phases A, B and C. Upon detection of a relative phase-to-ground fault in phase A and phase B, the output obtained by the technique of variation of impedance angle according to the present subject matter generates release signals 722 and 724 for the distance to be measured at 1.235 s.

[0084] Thus, the present subject matter provides an accurate single-ended method for detecting and classifying faults based on the value of the change in impedance angle that occurs during power oscillations. The method also detects and classifies faults occurring at the center voltage of the oscillation when minimal or no change is observed in the differential current. The method also detects and classifies faults occurring at the center voltage of the oscillation by using a method such as Figure 4 The invention provides a reliable phase selection by taking the average value of the change of the impedance angle in question. The reliable phase selection ensures the release of the corresponding loop for the distance protection locked during the power oscillation. When the faulty loop is identified, the distance protection is executed by the distance protection relay or IED to cope with the fault situation in the power oscillation. Therefore, the method and device of the present subject matter can be used to reliably perform fault detection and classification during power oscillation.

Claims

1. A method for fault detection during power oscillations in a power transmission system, the method comprising: obtaining voltage measurements and current measurements for each phase at a terminal of the power transmission system, wherein the voltage measurements and the current measurements are obtained using one or more measurement equipment associated with the terminal of the power transmission system, wherein the voltage measurements and the current measurements include sampled values ​​of voltage and current obtained at the terminal; For each sampled value of the voltage and current, calculating a value of a change in the impedance angle of each phase-to-ground loop and each phase-to-phase loop, wherein the value of the change in the impedance angle is a difference between the impedance angles of two samples separated by a predetermined interval; for each phase-to-ground loop and each phase-to-phase loop, calculating an average value of the change in impedance angle for a predetermined number of values ​​of the change in impedance angle; comparing the average value calculated for each phase-to-ground loop and each phase-to-phase loop with a threshold value for a change in impedance angle; as well as Based on the comparison, a fault in one or more of the phase-to-ground loop or the phase-to-phase loop is detected.

2. The method according to claim 1, wherein the method comprises: When a fault in one or more of the phase-to-ground loop or the phase-to-phase loop is detected, the corresponding loop is released for distance protection.

3. The method of claim 1, wherein the predetermined interval is the duration of one measurement cycle, wherein one measurement cycle includes a predetermined number of samples based on a sampling frequency.

4. The method of claim 1 , wherein calculating the average value comprises: A moving window average filter is applied to calculate values ​​of change of impedance angle for the samples, wherein the predetermined number of values ​​of change of impedance angle is the size of the moving window. The method according to claim 4 , wherein the size of the moving window is equal to the number of samples in one measurement cycle. The method of claim 1 , wherein the threshold is a range. The method of claim 6 , wherein the range is 1 degree to 3 degrees.

8. The method according to claim 1, comprising: The detected fault is classified as a phase-to-ground fault, a phase-to-phase fault, or a double phase-to-ground fault based on the loop in which the fault is detected.

9. The method according to claim 1, wherein the method comprises: Voltage phasors and current phasors are calculated for each phase-to-ground loop and each phase-to-phase loop, respectively, based on full-cycle discrete Fourier transforms of the voltage measurements and the current measurements.

10. The method according to claim 1, comprising: A fault in one or more of the phase-to-ground loop or the phase-to-phase loop at the oscillation center voltage is detected.

11. An intelligent electronic device (IED) for detecting faults during power oscillations in a power transmission line, the IED comprising: processor; as well as A fault detection module, the fault detection module being executable by the processor to: obtaining voltage measurements and current measurements from each phase at a terminal of the power transmission system, wherein the voltage measurements and the current measurements are obtained using one or more measurement equipment associated with the terminal of the power transmission system, wherein the voltage measurements and the current measurements include sampled values ​​of voltage and current obtained at the terminal; For each sampled value of the voltage and current, calculating a value of a change in the impedance angle of each phase-to-ground loop and each phase-to-phase loop, wherein the value of the change in the impedance angle is a difference between the impedance angles of two samples separated by a predetermined interval; for each phase-to-ground loop and each phase-to-phase loop, calculating an average value of the change in impedance angle for a predetermined number of values ​​of the change in impedance angle; comparing the average value calculated for each phase-to-ground loop and each phase-to-phase loop with a threshold value for a change in impedance angle; as well as Based on the comparison, a fault in one or more of the phase-to-ground loop or the phase-to-phase loop is detected.

12. The device according to claim 11, wherein the device is configured to release the corresponding loop for distance protection when a fault in one or more of the phase-to-ground loop or the phase-to-phase loop is detected.

13. The apparatus of claim 11, wherein the predetermined interval is the duration of one measurement cycle, wherein one measurement cycle includes a predetermined number of samples based on a sampling frequency.

14. The device according to claim 11, wherein: To calculate the average value, the fault detection module is configured to apply a moving window average filter to calculate values ​​of changes in impedance angle for samples, wherein the predetermined number of values ​​of changes in impedance angle is the size of the moving window.

15. The apparatus of claim 14, wherein the size of the moving window is equal to the number of samples in one measurement cycle.

16. The apparatus of claim 11, wherein the threshold is a range.

17. The apparatus of claim 16, wherein the range is 1 degree to 3 degrees.

18. The apparatus of claim 11, wherein the fault detection module is configured to classify the detected fault as a phase-to-ground fault, a phase-to-phase fault, or a double phase-to-ground fault based on the loop in which the fault is detected.

19. A non-transitory computer readable medium containing program instructions that, when executed, cause an intelligent electronic device (IED) to detect a fault during a power oscillation in a power transmission line, wherein the program instructions include instructions to: obtaining voltage measurements and current measurements from each phase at a terminal of the power transmission system, wherein the voltage measurements and the current measurements are obtained using one or more measurement equipment associated with the terminal of the power transmission system, wherein the voltage measurements and the current measurements include sampled values ​​of the values ​​of voltage and current obtained at the terminal; For each sampled value of the voltage and current, calculating a value of a change in the impedance angle of each phase-to-ground loop and each phase-to-phase loop, wherein the value of the change in the impedance angle is a difference between the impedance angles of two samples separated by a predetermined interval; for each phase-to-ground loop and each phase-to-phase loop, calculating an average value of the change in impedance angle for a predetermined number of values ​​of the change in impedance angle; comparing the average value calculated for each phase-to-ground loop and each phase-to-phase loop with a threshold value for change in impedance angle, wherein the threshold value is in the range of 1 degree to 3 degrees; as well as When the average value of the change in impedance angle is within the threshold, a fault in one or more of the phase-to-ground loop or the phase-to-phase loop is detected.

20. The non-transitory computer readable medium of claim 19, wherein the program instructions include instructions to classify a detected fault as a phase-to-ground fault, a phase-to-phase fault, or a dual-phase-to-ground fault based on the loop in which the fault is detected.

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