Journal of Reliable Power - SEL

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11 m 2 1.5 1 0.5 0 3 4 5 6 7 8 9 10 11 Cycles Fig. 29. Directional Element Response With CT Tap Lower Than CTR Setting It is suspected that the CTR setting in the relay does not match the actual CT tap in the field. However, this is part of an ongoing investigation and, at the time of publication, root cause is yet to be determined. XI. DIRECTIONAL ELEMENT AFFECTS CARRIER EXTENSION In June 2006, a 161 kV line tripped incorrectly for a reverse AG fault. The line was protected by a DCB scheme. The ground directional element used the best choice logic described in Section IX. The element used ground current polarization first (I), followed by zero-sequence voltage polarization (V), and then by negative-sequence voltage polarization (Q). The event data from the misoperation are shown in Fig. 30. For a reverse fault, we expect the polarizing current (IP) and the terminal ground current (IG) to be 180 degrees out of phase. In the event data, however, IP and IG were in phase. A wiring error was found; the polarizing current CT was connected reverse polarity. This allowed the local breaker to trip. IA IB IC VA(kV) VB(kV) VC(kV) IP IG Digitals 1000 0 -1000 100 0 -100 5000 0 -5000 DSTRT Z3XT 50G3 32QR F32I 67G1T IA IB IC VA(kV) VB(kV) VC(kV) IP IG 2 3 4 5 6 7 8 Cycles Fig. 30. Directional Element Misoperation due to IP Wiring Mistake The remote breakers were allowed to trip because of the carrier-blocking signal dropout as the breaker was interrupting the fault. In Fig. 31, directional carrier blocking (DSTRT) was asserted due to a negative-sequence element (50Q3) and a negative-sequence directional element (R32Q). At the end of the event, the DSTRT element chattered then dropped out. This was because of the phase angle error introduced by arcing during interruption. Carrier blocking extension is enabled in this relay but requires Zone 3 elements to be asserted for 2 cycles; they were only asserted for 1.5 cycles. During the investigation, it was noted that the directional element processing order of IVQ was not typically used by this utility; an order setting of QV was more common. Would carrier extension have asserted if we had used the typical order In Fig. 31, the ground-polarized directional elements (F32I and 32GF) assert because of the directional logic order and wiring error. The phase angle of the faulted phase current varies wildly during the beginning of the fault because of the fault arcing and evolution. This delays the voltage-based directional elements but has little effect on the current-based directional element. Also in Fig. 31, negative-sequence directional elements (32QR and R32Q) asserted later in the fault. 32QR and R32Q supervise phase distance and negativesequence overcurrent elements. Their ground logic equivalent (R32QG) is controlled by best choice logic. R32QG did not assert because the IP-based element has priority, but the directional decision it would make would match that of 32QR and R32Q when enabled. From this, we realize that the order and best choice logic processing did not delay the R32QG element; the evolving fault did. IA IB IC VA(kV) VB(kV) VC(kV) Digitals 1000 0 -1000 100 0 -100 50Q3 50G3 NSTRT DSTRT Z3XT R32V F32V R32QG F32QG R32Q F32Q R32I F32I 32QE 32IE 32QGE 32VE 32GR 32GF 32QR IA IB IC VA(kV) VB(kV) VC(kV) 0.0 2.5 5.0 7.5 10.0 12.5 15.0 Cycles Fig. 31. Detailed Relay Response to Fault The evolving fault should delay a directional decision for all the relays. Remote relays additionally include a carrier coordination delay for tripping. How fast the directional element sent blocking is not the real issue in this fault; it is how fast we enable carrier extension. Setting the carrier extension pickup delay (Z3XPU) to a lower value, even zero, is recommended [13]. XII. COMPARING PRIMARY AND BACKUP METERING In November 2005, a 138 kV transmission line experienced an AG fault. The backup relay correctly saw the fault as forward and tripped by the directional ground overcurrent element (67G1). The primary relay, however, declared a reverse fault and did not operate. 62 | Journal of Reliable Power
12 The prefault data from the backup relay are shown in Fig. 32, and the prefault data from the primary relay are shown in Fig. 33. The phase voltages seen by the primary relay in the prefault state did not look normal or balanced, and a significant standing zero-sequence voltage was present. The backup relay, on the contrary, reported normal prefault voltages. 180 135 225 135 90 VC (kV) IB IA VB (kV) 270 90 IC 45 VA (kV) 0 315 45 The neutral bus of the primary relay three-phase voltage connections should have been connected at a terminal block to station ground; this wire was missing. The result was that the primary relay voltages were floating, and this distorted phaseto-neutral magnitudes, angles, and sequence components both before the fault and during the fault. The backup relay had properly terminated voltages and, therefore, its zero-sequence voltage polarized directional element performed correctly. The fault data collected from the backup relay are shown in Fig. 34. The zero-sequence current leads the zero-sequence voltage by about 120 degrees, as expected for a forward AG fault. Negative-sequence relationships are similar. The relay is set by the user to enable only zero-sequence quantities for directional decisions. However, the data show that the zerosequence directional element used (F32V) and the disabled negative-sequence directional element (F32Q) both made the correct directional decision. IA IB IC VA(kV) VB(kV) VC(kV) V0Ang I0Ang Digitals 10000 0 -10000 50 0 -50 100 0 -100 F32V F32Q 67G1 IA IB IC VA(kV) VB(kV) VC(kV) V0Ang I0Ang 0.0 2.5 5.0 7.5 10.0 12.5 15.0 Cycles Fig. 32. 180 225 Prefault Data From Backup Relay 135 180 225 135 180 270 90 VC (kV) IB (A) IC (A) IA (A) VB (kV) 270 90 V0 V1 0 315 45 VA (kV) 0 315 45 V1 0 Fig. 34. Fault Data From Backup Relay The fault data collected from the primary relay are shown in Fig. 35. The zero-sequence current leads the zero-sequence voltage by about 210 degrees, which causes the zero-sequence directional element misoperation. Negative-sequence relationships match those reported by the backup relay and are correct. The relay is set by the user to enable only zerosequence quantities for directional decisions. However, the data show that the disabled negative-sequence directional element (F32Q) made the correct directional decision. IA(A) IB(A) IC(A) VA(kV) VB(kV) VC(kV) V0Ang I0Ang 10000 0 -10000 100 0 -100 200 0 -200 IA(A) IB(A) IC(A) VA(kV) VB(kV) VC(kV) V0Ang I0Ang 225 270 315 Digitals 67G1 F32V F32Q TRIP IN105 Fig. 33. Prefault Data From Primary Relay Fig. 35. 0.0 2.5 5.0 7.5 10.0 12.5 15.0 Cycles Fault Data From Primary Relay Synchronized phasor measurement during commissioning is a useful tool for finding mistakes like these before they cause misoperations. When relays are connected to a common voltage or current source, automation systems can be easily designed to periodically retrieve metering data, compare them, and alarm when differences are discovered. Troubleshooting and repair can then be performed to fix problems before they are discovered by misoperations. Lessons Learned Analyzing Transmission Faults | 63
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$12.00 Journal of Reliable Power Vo
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Journal of Reliable Power Volume 1
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Capable of running protection calcu
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Both P and Q are two-input phase an
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TABLE 1: MHO ELEMENT POLARIZING CHO
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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 and 56: 2 II. COMMON ZONE TIMING In June 20
Page 57 and 58: 4 ment 67N2 after a 1-cycle carrier
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: 10 The phasors during the fault are
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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