PROTECTIVE RELAY MISOPERATIONS AND ANALYSIS BY STEVE TURNER, Beckwith Electric Company, Inc. This paper provides detailed technical analysis of two relay misoperations and demonstrates how to prevent them from occurring. Case 1: An unwanted breaker failure operation tripped for a large offline generator during high load, resulting in an outage in the adjoining downtown area of a large city. Case 2: A transformer differential trip protecting the generator step-up transformer at a process plant occurred due to sympathetic inrush when a large nearby GSU was energized via the interconnecting high-voltage transmission line, resulting in an extended outage. Each individual analysis ends with a conclusion stating why the relay misoperated and providing a recommendation on the best practice for the particular application. CASE 1: UNWANTED BREAKER FAILURE OPERATION LARGE GENERATOR TRIPPED DURING HIGH-LOAD PERIOD During a period of high load, a breaker failure trip for a large offline generator located in the downtown area of a large city resulted in an outage. Figure 1 shows the system topology at the time of the trip. Note that the generator is connected to Figure 1: System Operating Conditions the transmission grid via a high-voltage breaker. The links connecting the generator to the GSU were open as well as the high-side breaker. The lowside winding of the GSU drew excitation current since it was energized via the auxiliary station service. Original Breaker Failure Scheme Logic Figure 2 shows the original logic used for this breaker failure protection scheme. Figure 2: Breaker Failure Logic NETAWORLD 43
Original Protection Settings Figure 3 shows the original relay settings for this breaker failure scheme. Fault Current Signals Figure 4 shows the oscillography captured by the relay at the time of the trip. Figure 5 shows the current phasors measured by the protective relay when the breaker failure occurred. Figure 3: Breaker Failure Settings Figure 4: Fault Event Oscillography Figure 5: Fault Current Phasors 44 WINTER 2016
Case 1 Conclusion The breaker failure trip occurred because I C was above the current detector pickup setting and input 4 (BFI) was asserted. Original Protection Settings Figure 8 shows the original settings for the transformer differential protection. The breaker failure function may be used for a unit breaker rather than a generator breaker. It is limited in that no fault detector is associated with the unit breaker. Output contact operation would occur if any of the initiate contacts close, and the 52b contact indicated a closed breaker after the set time delay. The corresponding logic is shown in Figure 6. Figure 8: 87T Settings Figure 6: Fault Current Phasors CASE 2: TRANSFORMER DIFFERENTIAL TRIP DUE TO SYMPATHETIC INRUSH The transformer differential relay protecting the step-up transformer at a processing plant tripped when a nearby large GSU at a power plant was energized from the high side. The trip was due to sympathetic inrush current flowing through the step-up transformer (Figure 7). Fault Current Signals Figure 9 shows the oscillography captured by the relay at the time of the trip. Note that current input IAW1 is almost completely offset, and there is some distortion in other current inputs as well. Figure 7: System Operating Conditions (Arrows Indicate Direction of Inrush Current) Figure 9: Fault Event Oscillography (Raw Waveforms) NETAWORLD 45
Harmonic Restraint Calculations Figure 10 shows the second harmonic content of the current inputs at the time of the trip. The second harmonic differential current present when the trip occurred was as follows: A-Phase = 17 percent B-Phase = 13 percent C-Phase = 13 percent If the ratio is greater than the restraint setting, then the transformer differential protection is blocked (Figure 12). Figure 12: Even Harmonic Restraint Logic The original second harmonic restraint setting was 20 percent for the electro-mechanical transformer differential relay. The customer used the same setting for the multi-function numerical relay that replaced the original electro-mechanical relay. Figure 10 showed that a setting of 20 percent was not sensitive enough to detect the sympathetic inrush current flowing through the step-up transformer. Figure 10: Fault Event Oscillography (Second Harmonic Content) The ratio of harmonic to fundamental differential current used to restrain the transformer differential protection is calculated as follows (Figure 11): Case 2 Conclusion For several decades, electro-mechanical relays had a fixed harmonic inhibit level of 20 percent. This worked well for a period of time until transformer manufacturers began making better transformers that used less material and were designed with smaller tolerances. Therefore, modern laminated-steel-core transformers will not reliably produce 20 percent second harmonic current during inrush. Based upon this particular event, an 11 percent setting for the second harmonic restraint would be the most reliable. Note that the multi-function numerical relay in this application actually uses the root mean square (RMS) of the second and fourth harmonic differential current, but that still was not enough to restrain the protection. Figure 11: Even Harmonic Restraint Equation 46 WINTER 2016
FINAL CONCLUSION The technical analysis of these two relay misoperations, along with examples of how to use the data recorded by a relay during these types of conditions, should help you understand why each misoperation occurred and how to implement best practices for each particular application. Knowing that the first misoperation was due to an incorrect relay setting, while the second was due to an incorrect application, should clarify the need for careful attention during the design and initial work stages. Steve Turner, an IEEE Senior Member, is a Senior Applications Engineer at Beckwith Electric Company. His previous experience includes work as an application engineer with GEC Alstom and as an application engineer in the international market for SEL, focusing on transmission line protection applications. Steve worked for Duke Energy (formerly Progress Energy), where he developed a patent for double-ended fault location on overhead transmission lines. He has a BSEE and MSEE from Virginia Tech. Steve has presented at numerous conferences, including Georgia Tech Protective Relay Conference, Western Protective Relay Conference, Energy Council of the Northeast, and Doble User Groups, as well as various international conferences.