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3 reasserts, the relay advances to lockout (79LO). The root cause can be found in the relay operation and user settings [1]. A programmable logic equation (79RI) defines the conditions that initiate reclose. 79RI is set equal to the rising edge of 67G1 plus a number of other conditions logically ORed together. Once 79RI asserts, the relay enters its cycle state (79CY) and begins to time to reclose. However, the reclose timer is interrupted when 79RI reasserts. The relay immediately assumes something has gone awry, such as a flashover during a breaker opening, and the relay immediately goes to lockout (79LO) to prevent further trouble. just after the fault transitioned from AG to BG; therefore, we are suspicious that the relay used corrupt data for its fault location estimate. A fault location algorithm MathCad simulation is shown in Fig. 7. We can see the fault location error during the fault type change, but before and after that transition the location estimate is consistent. m 12 9 6 Single-Line-to-Ground Faults (BG) IA IB IC 2500 0 -2500 IA IB IC IGMag VA(kV) VB(kV) VC(kV) 5.25 cycles 3 0 7 7.5 8 8.5 9 9.5 10 10.5 11 11.5 12 12.5 13 Cycles IGMag VA(kV) VB(kV) VC(kV) Digitals 2000 1000 0 25 0 -25 FSB FSA 52A 79LO 79CY 79RS 67G1T 51G TRIP 5.0 7.5 10.0 12.5 15.0 17.5 Cycles Fig. 6. Reclosing Interrupted by Evolving Fault To prevent this from happening in the future, reclosing must not be reinitiated before reclose open-interval timing is complete and the breaker has been reclosed. Use the trip element to initiate reclose. Relays have a minimum trip duration time, so trip outputs remain asserted throughout evolving faults. It is also common to stall open-interval timing while the trip condition is still present. Additionally, there are likely conditions included in the trip logic for which we do not want to reclose. These conditions can be specified in a programmable drive-to-lockout equation (79DTL). Such conditions may include remote or manual OPEN commands, relay trips for three-phase faults, or time-delayed trips. An interesting breaker problem is also evident by the data in Fig. 6. Notice that the breaker status contact (52A) changes state shortly after the main breaker interrupts current. This is consistent with breaker operations in the previous two examples. However, we see that while the main breaker contacts remain open, the breaker auxiliary status contact bounces closed after 0.75 cycles and remains closed for 3.5 cycles before opening again. Bouncy auxiliary contacts can cause reclosing failures. If 52A asserts before the relay calls for a close, relay logic assumes a manual or remote CLOSE command asserted. The auxiliary contacts of this breaker need maintenance to prevent future problems. The relay reported a fault location of 3.22 miles and a BG fault type. The contiguous fault data are roughly from Cycle 8 to 13, which was the window of time the triggering element 51G was asserted. The midpoint of that data corresponds to Fig. 7. MathCad Fault Location Estimates for AG and BG Fault Types The relay fault location algorithm selected data just prior to Cycle 10.5, where the B-phase current is still increasing to its maximum value. Therefore, its estimate is slightly further away from the local terminal because of the lower current magnitude used. The actual fault location is closer to 3.0 miles. IV. COMMUNICATIONS PROBLEM In June 2007, a fault occurred beyond the remote terminal of a 115 kV line protected by a DCB scheme. DCB schemes use a high-speed on/off carrier signal to block high-speed tripping at the remote terminal for out-of-section faults. Therefore, we expected the remote terminal to send a blocking signal to the local relay to prevent it from tripping at a high speed. The event data recorded from the local relay are shown in Fig. 8. The received blocking signal was wired to a programmable input on the relay (IN5) and appears to have been asserted at the time of the trip. IA IB IC IRMag VA VB VC Digitals 100 0 -100 75 50 25 0 50 0 -50 Fig. 8. IA IB IC IRMag VA VB VC OUT 1&2 B IN 5&6 5 5 67N 2 -1 0 1 2 3 4 5 6 7 8 9 10 11 Cycles Four Samples-per-Cycle Data From a DCB Scheme Trip The relay is set so that overreaching phase and ground elements are allowed to trip after a one-cycle carrier coordination delay if no block is received. However, the relay tripped by overreaching ground directional overcurrent ele- 54 | Journal of Reliable Power
4 ment 67N2 after a 1-cycle carrier coordination delay. Apparently, a blocking signal was being received. Higher resolution data from the same relay for the same event are shown in Fig. 9. The better resolution illuminates a 0.25-cycle carrier hole that allowed the local relay to trip. IA IB IC IRMag VA VB VC Digitals 100 0 -100 75 50 25 0 50 0 -50 Fig. 9. BTX OUT1 IN5 67N2T 67N2 IA IB IC IRMag VA VB VC .25 cycles -1 0 1 2 3 4 5 6 7 8 9 10 11 Cycles Sixteen Samples-per-Cycle Raw Data From a DCB Scheme Trip The received blocking input must remain asserted to block the forward-looking elements after the coordination timer expires. If the blocking signal drops out momentarily because of noise or other channel-related problems, the local relay will trip for out-of-section faults. Relays include an extension timer to delay the control input dropout assigned to receive the blocking signal. The output of this timer (BTX) ensures unwanted tripping does not occur during momentary lapses of the blocking signal (carrier holes). A typical setting is 0.5 to 1.5 cycles. One drawback of using the block trip (BT) extension timer is that tripping would be delayed anytime the BT input is asserted. This can cause unnecessary delays for internal faults in applications using a nondirectional carrier start. That is, the BT input asserts momentarily when nondirectional elements assert then deasserts when the forward elements detect the fault. BTX would remain asserted and delay tripping until the extension timer expired. To avoid this delay, use programmable logic in the relay to extend the blocking signal (see Fig. 10). IN10x 1.0 cyc Set pickup to longer than remote carrier assertion Fig. 10. 1 cyc Set dropout to longer than expected carrier hole time BT 0 cyc BTXD Set BTXD to zero (0) BT Extension for Nondirectional Carrier Start Applications In this logic, we extend the BT only if the carrier has been initially picked up longer than the remote carrier assertion. The typical BT extension timer setting can then be set equal to 0 cycles [4]. BTX V. SENSITIVITY MISCOORDINATION In January 2001, two parallel 138 kV lines connecting a utility to a petrochemical plant tripped for an out-of-section fault. The simultaneous outages left the plant’s local generation and load electrically isolated from the utility. Both lines use identical permissive overreaching transfer trip (POTT) schemes with identical relay types at local and remote terminals. A simplified system one-line diagram with fault location is shown in Fig. 11. The tie line that is in parallel with Line 3–4 and other infeeds to the petrochemical plant and utility bus are not shown. The utility is designated 1, and the petrochemical plant is designated 2. The actual fault location was behind the utility terminal (reverse to Terminal 1 and forward to Terminal 2). 2 – Petrochem 1 – Utility Fig. 11. 1 2 3 4 5 6 Zone 3 Zone 2 Zone 2 Zone 3 Simplified One-line Diagram of System With Relay Sensitivities Event data from both ends of one tie line are shown simultaneously in Fig. 12. The event data match the designations above, i.e., the utility data are designated 1, and the petrochemical plant data are designated 2. 1_IA 1_IRMag 2_IA 2_IRMag 2_VA 1_VA Digitals 1000 500 0 -500 1000 500 0 -500 50 0 -50 Fig. 12. 1_IA 1_IRMag 2_IA 2_IRMag 2_VA 1_VA .054167 sec 2_OUT 3&4 3 3 B 2_OUT 1&2 2_67N 1 2_32 Q 1_OUT 3&4 3 3 1_OUT 1&2 2 2 1_IN 1&2 1 1_67N 1_32 q 34.725 34.750 34.775 34.800 34.825 34.850 34.875 34.900 34.925 Event Time (Sec) 05:05:34.856396 Utility and Plant Relay Data for Fault Terminal 2 responds to the forward AG fault by asserting its forward directional element (2_32Q) and its overreaching forward directional ground overcurrent element (2_67N2). The digital trace in Fig. 12 is identified with a 2_67N1, which is correct. Settings for the level one (67N1) and level two (67N2) ground elements are set to the same value, and the relay reports the assertion of the nearest zone. Terminal 2 keys a permission-to-trip (PTT) signal to the remote utility relay (2_OUT3). Lessons Learned Analyzing Transmission Faults | 55
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$12.00 Journal of Reliable Power Vo
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Journal of Reliable Power Volume 1
Page 5 and 6: Capable of running protection calcu
Page 7 and 8: Both P and Q are two-input phase an
Page 9 and 10: TABLE 1: MHO ELEMENT POLARIZING CHO
Page 11 and 12: For an Aφ-ground fault on the syst
Page 13 and 14: The most onerous 3φ fault is one w
Page 15 and 16: If the angle is near +120°, then t
Page 17 and 18: Impedance-Based Fault Location Expe
Page 19 and 20: A. Simple Reactance Method From Fig
Page 21 and 22: Figure 9 shows a screen capture of
Page 23 and 24: The relay then performs “torque
Page 25 and 26: IX. LAB TEST SETUP Several line fau
Page 27 and 28: APPENDIX The following are the rela
Page 29 and 30: The following shows the analog math
Page 31 and 32: Digital Communications for Power Sy
Page 33 and 34: increasing security by a factor of
Page 35 and 36: The receiver amplifier is the major
Page 37 and 38: Noise from faults or other sources
Page 39 and 40: 80 60 40 20 R F 100 3 3 S 2 5 6 4 1
Page 41 and 42: 15. A POTT scheme implemented over
Page 43 and 44: Transmission Line Protection System
Page 45 and 46: One-Cycle Directional Element Figur
Page 47 and 48: element misoperation. Shunt reactor
Page 49 and 50: • SW2 is in Position 1 when there
Page 51 and 52: Complete reclosing relay supervisio
Page 53 and 54: IX. BIOGRAPHIES Armando Guzmán, P.
Page 55: 2 II. COMMON ZONE TIMING In June 20
Page 59 and 60: 6 VI. ZONE 1 OVERREACH DUE TO CVT I
Page 61 and 62: 8 1_VA 1_VB 1_VC 2_VA 2_VB 2_VC 3_V
Page 63 and 64: 10 The phasors during the fault are
Page 65 and 66: 12 The prefault data from the backu
Page 67 and 68: 1 Adaptive Phase and Ground Quadril
Page 69 and 70: 3 C. Short Line Applications A shor
Page 71 and 72: 5 II. QUADRILATERAL DISTANCE ELEMEN
Page 73 and 74: 7 For the purpose of implementing t
Page 75 and 76: 9 The three-phase fault detection e
Page 77 and 78: 11 Zone 1 distance elements should
Page 79 and 80: 13 Fig. 24 shows the apparent resis
Page 81 and 82: 15 B. Adaptive Resistance Element F
Page 83 and 84: 17 Fig. 34 and Fig. 35 illustrate t
Page 85 and 86: Line Protection Bibliography Issue
Page 87 and 88: Hou, Daqing, and Jeff Roberts. “C
Page 90: ©2010 Schweitzer Engineering Labor
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