- Case study
- Open Access
Relay performance verification using fault event records
© The Author(s) 2018
- Received: 1 February 2018
- Accepted: 31 May 2018
- Published: 16 July 2018
Event reports recorded by intelligent electronic devices (IEDs) such as digital relays and fault recorders during disturbances depict the status and system parameters of the power system. Incorrect relay settings and unknown system parameters can lead to relay misoperation but information regarding these are available by performing a comprehensive analysis of fault records. Hence, it is necessary to regularly make a comprehensive assessment of the functioning of the relay to ensure reliable operation.
The objective of this paper is to demonstrate various aspects of evaluating relay performance and verifying circuit parameters which are used in relay settings using field data in two case studies.
Discussion and Evaluation
While scrutinizing the relay’s operation, this paper also presents key insights on verifying circuit parameters using the same relay event records.
The lessons learned from the case studies presented in this paper will equip a protection engineer to inspect the operation of a relay during a transmission line fault, help gain a better understanding of the fault event and take possible actions to prevent future occurrence of similar events.
- Event report
- Fault analysis
Relays are vital devices present in any power system. They protect various components in the power system from catastrophic damage during faults. They help in maintaining safe and reliable operation of the entire system. A recent study analyzing protection system misoperations was performed by North Electric Reliability Corporation (NERC) and they identified various causes for relay misoperations . All these emphasize the need to make comprehensive assessment of relay operation and its performance regularly.
Event reporting is a very useful feature in intelligent electronic devices (IEDs) such as digital relays and fault recorders. Event reports contain voltage and current waveforms which depict the fault characteristics at the time of occurrence. They are traditionally used for fault analysis such as fault classification and identifying the fault location but contain much more additional information which can be used to improve the power system reliability.
System operators usually have detailed circuit models of transmission and distribution networks in CAPE , OpenDSS , and other power system software . The circuit model is useful for conducting short-circuit studies, determining protective relay settings, and choosing the maximum rating of circuit breakers and other power system equipment. Incorrect short-circuit model parameters can lead to erroneous relay settings and relay misoperations, an example of which is described in . As a result, it is essential that the circuit parameters are accurately known and the system model is continually updated to reflect any system additions, repairs, or modifications.
Several authors in the past have attempted to glean additional information from fault records [6–10]. Using event reports, authors in [11, 12] have estimated the zero-sequence line impedance of a two-terminal line. Similarly, the authors of  have calculated the Thevenin impedance of the system upstream from the measured location using event reports. The authors of  have further explored in detail about deriving zero-sequence line impedance using data from both the terminals of a two-terminal line as well as using data from only one end of the line. These highlight the presence of plethora of information in an event report and the need for comprehensive analysis of event reports.
Based on the above background, the objective of this paper is to use relay event reports to comprehensively evaluate the relay performance and circuit parameters which are used in relay settings instead of just one or two parameters such as those presented in [8–13]. The contribution of this paper lies in demonstrating the above by analyzing two case studies in detail. The following applications of IED data for above purpose are presented in this paper: (a) relay and circuit breaker performance evaluation, (b) event reconstruction, (c) zero-sequence line impedance validation, (d) detection of incorrect power system equipment installation, (e) fault resistance and root-cause identification, and (f) circuit model verification. It presents the theory of potential applications of IED data to improve power system reliability. Each section consists of description of the fault incident, the current and voltage waveforms associated with it followed by the analysis.
2 Case study 1: B-G fault verifies relay performance, validates the zero-sequence line impedance, and authenticates the system model
397,500 26/7 ACSR
3/8 A HSS
In the following subsections, the waveform data is used to reconstruct the sequence of events, estimate the fault location, estimate the fault resistance, validate the zero-sequence line impedance, and verify the accuracy of the system model and demonstrate what we can learn from these about the relay performance and operation.
2.1 System protection description
where t is the relay trip time in seconds, M is a multiple of pickup and is calculated as the ratio of the fault current to the pickup setting, and TD is the time dial setting. When 51P times out, 51T asserts and causes the relay to initiate a trip.
During a ground fault, if the relay detects a ground current greater than 560.40 A primary, element 67G1T asserts and the relay trips instantaneously. When the ground current is greater than 288 A primary but less than 560.40 A primary, the ground time-overcurrent pickup element, 51G, asserts and starts timing on the U3 curve. Once 51G times out, 51GT asserts and trips the relay. It is important to note that 67P1T and 67G1T are disabled for shot 1 as specified by the trip equation in Fig. 4. Logical operator ‘!’ indicates a NOT function, operator ‘*’ indicates a AND function, operator ‘/’ indicates a rising edge trigger, and SH1 = 1 when the relay is at shot = 1. In other words, during shot 1, the relay will trip only for 51PT and 51GT elements.
2.2 Event report trigger criteria
The digital relay records an event report under two conditions: (a) when the TR equations asserts and the relay trips or (b) when the ER equation asserts. The ER equation consists of the phase and ground time-overcurrent elements, 51P and 51G, as shown in Fig. 4. When either of 51P or 51G or the TR equation is asserted, the ER equation asserts and the digital relay records an event report.
2.3 Event reconstruction
When 79OI1 times out, the circuit breaker closes back into the circuit at 12:44:38.885 hours as shown by Event 3 in Fig. 5b, and the shot counter increases to 1. The fault, however, is still present in the circuit and the relay measures a phase and ground current of 2860 A and 2811 A, respectively. Since the operation of the 67P1T and 67G1T elements are suspended in shot 1, the ground time-overcurrent element picks up at 12:44:38.893 hours and starts timing on the U3 curve. The phase time-overcurrent element also picks up at 12:44:38.897 hours and triggers this event. According to (1), the operating time of the phase and ground time-overcurrent elements are 0.316 and 0.203 secs, respectively. As a result, 51GT asserts before 51P has a chance to time out and issues a trip signal to the circuit breaker. Because the relay records only 16 cycles of waveform data, the opening of the circuit breaker is not shown.
By the time the relay starts recording Event 2 at 12:59:41.476 hours, the circuit breaker has already closed back into the circuit. The fault has cleared and the phase B current has returned back to normal load current levels as shown in Fig. 5c. The relay has also reset itself since the fault was absent from the transmission network for more than 900 cycles. Unfortunately, the fault reappears on phase B at 12:59:41.526 hours. Element 67G1T asserts immediately and trips the circuit breaker. The relay starts timing on the first open interval, 79OI1.
When 79OI1 times out, the circuit breaker closes back into the circuit, and the shot counter increases to 1. The fault, however, persists, and the relay measures a phase and a ground current of 3380 A and 3340 A, respectively. Since the operation of the 67P1T and 67G1T elements are suspended for shot 1, both the phase and the ground time-overcurrent elements pick up at 12:59:41.995 h and start timing on the U3 curve. The more sensitive ground time-overcurrent, 51GT, times out before its phase counterpart, 51PT, and trips the circuit breaker at 12:59:42.186 h. No other event reports were provided. Therefore, it is not clear whether this shot of the relay removed the fault or whether the relay eventually locked out to isolate the permanent fault.
2.4 Relay performance assessment
In the previous subsections, we have reviewed the relay settings, understood its expected behaviors and reconstructed the sequence of events. This subsection aims to assess the performance of the relay and to determine whether relay operating times are within set time limits. The approach for this is by comparing the expected time of operation with the actual relay operating time. When calculating the expected operating time of the relay, the functional specifications of the relay must be taken into consideration.
2.4.1 Assessment of Trip Time during the Shot 1 in Event 3
The relay has a pickup accuracy of ± 3% of setting ± 0.05 A. Therefore, for a pickup setting of 2.40 A secondary, the pickup accuracy equals ± 0.122 A. This means that when the actual fault current is 23.425 A secondary, 51G can assert when the current is between 23.303 A and 23.547 A secondary (23.425 ±0.122 A).
Suppose the relay picks up at 23.303 A secondary (M = 9.71). Using (1), the operating time of the relay is 0.2040 secs. As per Fig. 6, 51P has a curve timing accuracy of ± 4% of the operating time and ± 1.5 cycle. For an operate time of 0.2040 secs, the curve timing accuracy equals 0.0331 secs (4% ×0.2040 + 0.025 secs). Therefore, the relay is expected to operate within 0.1709 and 0.2372 secs (t1 = 0.2040 ±0.0331 secs).
Alternatively, suppose the relay picks up when the fault current is 23.547 A secondary (M = 9.81). From (1), the operating time of the relay is solved to be 0.2028 secs. The curve timing accuracy for this operate time is calculated to be 0.0331 secs (4% ×0.2028 + 0.025 secs). Therefore, the relay will operate within 0.1697 and 0.236 secs (t2 = 0.2028 ±0.0331 secs).
The final time window, tfinal, that accounts for both pickup and curve timing accuracy can be calculated as Min (t2) < tfinal < Max (t1) or 0.1697 < tfinal <0.2372 secs. Therefore,the relay is expected to operate within 0.1697 and 0.2372 secs. From Fig. 5b, 51GP asserts at 12:44:38.897 hours while 51GT asserts at 12:44:39.072 hours. Therefore, the actual operating time of 0.175 secs falls within the expected window of operation and hence, the relay performs as expected.
2.4.2 Assessment of trip time during the shot 1 in event 1
During shot 1 in Event 1, the relay measures a ground fault current magnitude of 3340 A primary (3340/CTR = 27.83 A secondary). Following the procedure outlined in Subsection 2.4.1, the relay is expected to operate within 0.1528 and 0.2184 secs. From Fig. 5d, 51GP asserts at 12:59:41.995 hours while 51GT asserts at 12:59:42.186 hours. Therefore, the actual operating time of 0.191 secs lies within the expected window of operation and hence, the relay performs as expected.
2.5 Fault location
Case study 1: Location estimates from one-ended methods
Estimated Location (mi)
2.6 Fault resistance estimation
Case study 1: Estimated values of fault resistance
Fault resistance (Ω)
2.7 Thevenin Impedance estimation
Case study 1: Actual vs. estimated positive- and negative-sequence Thevenin impedances
2.82 + j17.90
3.62 + j17.35
2.91 + j18.03
2.94 + j17.09
1.90 + j18.36
3.18 + j16.84
4.12 + j17.31
3.13 + j17.08
1.43 + j18.77
3.71 + j17.11
Case study 1: Actual vs. estimated zero-sequence Thevenin impedance
Zero-sequence Thevenin Impedance (Ω)
5.29 + j30.72
4.88 + j29.75
5.20 + j29.59
5.17 + j29.70
5.89 + j29.78
2.8 Zero-sequence line impedance validation
Case study 1: Actual vs. estimated zero-sequence line impedance
Zero-sequence line Impedance (Ω)
From Table 6, it can be concluded that the estimated zero-sequence line impedance matched well with that computed using Carson’s equations at an earth resistivity value of 100 Ωm. This helps in verifying the zero-sequence line impedance setting of the relay as they play an important role in distance and directional protection.
2.9 Short-circuit model verification
Short-circuit current in CAPE vs. actual measurements from the relay
Fault current (kA)
2.10 Lessons Learned
Successful analysis of this event verified the performance of the relay. In addition, the event report was used to validate the zero-sequence line impedance setting in the relay. Furthermore, the fault record was used to estimate the fault resistance and Thevenin impedance which helped to gain further knowledge about the fault as well as assist in short circuit model verification. Calculating the fault location and simulating fault scenarios similar to those in the event reports verified that there were no errors in settings of the instrument transformers, the input contacts were working fine and the circuit model is representative of the actual transmission network. The reason why several methods have been presented to verify various relay settings and relay operation is because it may not be possible to implement all of the above verification steps in every fault scenario.
3 Case study 2: Lightning strike on a 161-kV transmission line reveals incorrect CT polarity and missing phase CT
3.1 Fault location
Location estimates from one-ended methods
Estimated location (mi)
Because the sampling rate of the DFRs at Station 1 and Station 2 are not equal, the unsynchronized two-ended method  was chosen to estimate the fault location. The missing phase A current at Station 1 did not allow for the calculation of sequence components. However, since the event is a balanced three-phase fault, it was possible to use phase components instead of symmetrical components. The reverse polarity of the CT at Station 2 was also taken into account. The fault location estimated by this method was 5.71 miles from Station 1 which is close to the actual fault location. Since fixing the reverse polarity of the CT at Station 2 got us a fault location estimate close to the actual fault location, it verifies that it was the source of error for negative fault location initially.
3.2 Thevenin Impedance estimation
Estimated positive-sequence source impedances
Source Impedance (Ω)
0.46 + j3.66
2.25 + j11.38
3.3 Lessons learned
Analysis of fault data can reveal incorrect setup of power system equipment or incorrect field wiring that was missed during field commissioning tests. Results of the analysis can be used to take corrective action and avoid future misoperations. For example, this event shows that the CT at Station 2 was installed with an incorrect polarity. As a result, the direction of the current was reversed and can affect the reliability and performance of directional relays. Furthermore, the phase A current measurement at Station 1 was missing. It is possible that the phase CT has not been connected to the DFR and can result in loss of valuable information. The fault was observed to have encountered the least resistance path to the ground, which coincides with the root cause of the fault. Finally, Station 2 was learned to be electrically weaker than Station 1.
Relay and Circuit Breaker Performance Evaluation
IEDs record what they “see” during a fault and those records can be used to assess the performance of relays and circuit breakers. For example, Case study 1 confirmed that the relay performed as expected during that fault event. If the protective relay had operated slower than expected during the fault, the utility can carefully monitor the future trip operations of this relay to ensure that the relay is not out of tolerance.
Validating the Zero-sequence Line Impedance
Single line-to-ground or double line-to-ground fault events can be used to validate the zero-sequence impedance of the transmission line as shown in Case study 1.
Estimating the Fault Resistance
Fault data captured at one or both ends of the line can be used to estimate the fault resistance. Interpretation of this value is useful in determining the root cause of the fault. Knowing the fault resistance value also plays a significant role while verifying the accuracy of the short-circuit model as demonstrated in Case study 1.
Estimating the Thevenin Impedances
Estimating the Thevenin impedance during a fault helps in validating the short-circuit model and can also provides valuable feedback about the state of the transmission network upstream from the monitoring location.
Estimating the Fault Location
Apart from being able to accurately locate the fault so as to quickly clear it, a lot more information about the relay can be derived from estimating the fault location using different methods such as identifying errors in instrument transformer connections and settings, and verifying that the system parameters have been accurately programmed into the relay as shown in Case study 1. Since fault location uses a lot of parameters in its calculation, it helps verify all the factors and variables which influence it.
Verifying the accuracy of the system short-circuit model used for simulation studies
Event reports help not only in confirming the accuracy of the short-circuit model but by comparing simulated short-circuit currents and relay measured currents it can help locate errors in input contacts and connections as well as identify errors in instrument transformer settings in the relay. Furthermore, it can help validate all the circuit parameters that have been programmed into the relay.
Detecting incorrect installation of power system equipment
Analysis of fault data can reveal incorrect setup of power system equipment or incorrect field wiring that was missed during field commissioning tests. Results of the analysis can be used to take corrective action and avoid future misoperations. For example, Case study 2 detects a CT with incorrect polarity and a digital fault recorder with a missing measurement channel.
Amongst the numerous parameters that can be calculated from relay event reports, estimation of some of these parameters can be automated and used instantly whereas the estimation of other parameters requires them to be done offline with manual procedures to obtain maximum benefits.
Relay and circuit breaker performance evaluation can be automated and performed every time a fault has occurred. This can serve as a continuous supervision of the relay and circuit breaker operation. Most digital relays have fault location algorithms embedded in them which can approximate the fault location as soon as it records an event report.
Though the process of estimating the fault resistance can be automated, it is not commonly implemented in a digital relay. It requires the attention of a protection engineer (PE) to estimate the fault resistance and interpret it. Similarly, the process of estimating the Thevenin impedance, zero-sequence line impedance and other short-circuit model parameters requires a PE to be able to study the system, validate the calculated values and make use of them. Likewise, detecting incorrect installation of power system equipment also requires the skills of a PE.
SD had performed the analysis using relay event reports. SNA assisted in performing the analysis and drafting the manuscript. SS was the technical advisor and supervised the analysis and submission of the manuscript. All authors read and approved the manuscript.
The authors declare that they have no competing interests.
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