POWER SYSTEM ANALYSIS TADP 641 SETTING OF OVERCURRENT RELAYS Juan Manuel Gers, PhD
Protection coordination principles Relay coordination is the process of selecting settings that will assure that the relays will operate in a reliable and selective way. In OC relays the coordination is based on the relay timecurrent characteristics of instantaneous and/or time delay units.
Protection coordination principles Instantaneous units should be set so they do not trip for fault levels equal or lower to those at busbars or elements protected by downstream instantaneous relays. Time delay units should be set to clear faults in a selective and reliable way, assuring the proper coverage of the thermal limits of the elements protected.
Typical System for Coordination Illustration Busbar 7 115 kv 9 TR1 Busbar 6 8 34.5 kv Busbar 4 7 6 Busbar 5 34.5 kv Busbar 3 34.5 kv 34.5 kv Busbar 2 34.5 kv 5 TR2 4 Busbar 1 13.2 kv 1 2 3
Criteria for Setting Instantaneous Units Instantaneous units are set by adjusting the pick up level current at which the relays operate. Most numerical relays now have the possibility of setting an operating time, allowing the relay to behave as a definite time unit.
Benefits of instantaneous units They reduce the operating time of the relays for severe system faults. t They avoid the loss of selectivity in a system consisting of relays with different characteristics. A
Criteria for setting instantaneous units i. Distribution lines Between 6 and 10 times the maximum circuit rating 50% of the maximum short circuit at the point of connection of the relay ii. iii. Lines between substations 125% to 150% of the short circuit current existing on the next substation Transformer units 125% to 150% of the short circuit current existing on the LV side The units at the LV side are overridden unless there is communication with the relays protecting the feeders.
Effects of fault current levels Effect of the source impedance on the short circuit level at a substation, and for a fault at point B down the line z S A Z R B Z R = impedance of protected element Z = source impedance S V V I SC(A) = S. 1 I SC(B) = S. 1 3 Z Z + Z S 3 S R
Effects of fault current levels Fault currents at F 1 and F 2 are almost the same F3 F2 F1
Coverage of instantaneous units z S A z AB B 50
Coverage of instantaneous units Definition of parameters: K I pickup i = Ks I end = Z Z source element I end = Z V I = + V s+ pickup Zab Zs X Zab X Z + Z - Z.K = Z K s ab s i ab i X K + 1 - K.K = K s s i i
Setting time delay relays Time delay units are set by selecting the time/curve characteristic that is defined by two parameters: TAP or PICK UP VALUE: A value that defines the pickup current of the relay. Current values are expressed as multiples of this value in the time/current characteristic curves. DIAL: Defines the time curve at which the relay operates for any TAP value. Higher DIAL values represent higher operating times.
Typical time/current characteristic CO-11 Westinghouse relay time/current characteristic
Coordination of OC time delay units Overcurrent inverse time relay curves associated with two breakers on the same feeder. t Coordination Time Interval R2 R1 CURRENT
Coordination Time Interval (CTI) A margin between two successive devices in the order of 0.2 to 0.4 seconds should be used to avoid losing selectivity due to one or more of the following reasons: The breaker opening time The overrun time after the fault has been cleared Variations in fault levels, deviations from the characteristic curves of the relays and errors in the current transformers
Criteria for setting the TAP For phase relays, the TAP or PICK UP VALUE is determined by: TAP = (OLF I nom ) CTR For ground fault relays, the TAP value is determined, with the maximum unbalance, typically around 20%: TAP = ((0.2) x I nom ) CTR
Criteria for setting the TAP The overload factor recommended is as follows: Motors = 1.05 HV Lines, transformers and generators = 1.25 to 1.5 Distribution feeders = 2.0
Criteria for setting the TAP For phase relays, three phase faults and maximum short time overload should be considered. For ground relays, line to ground faults and max 3I o should be considered.
Procedure for time delay setting A suggested procedure to coordinate OC time delay units: 1) Select the TAP value for all the relays 2) Determine the operating time t1 of the relay closest to the load with the lowest time dial and the fault level for which the instantaneous unit picks up. 3) Determine the operating time t 2a of the upstream relay substation with the expression t 2a = t 1 + t margin.
Procedure for time delay setting 4) Knowing t 2a, and having calculated the TAP value for relay 2, obtain the DIAL setting for relay 2. 5) Determine the operating time (t 2b ) of relay 2, but now use the fault level just before the operation of its instantaneous unit. 6) Continue with the sequence, starting from the third step.
Expression for time delay setting Operating time defined by IEC and ANSI/IEEE: t = k I I S * α β - 1 + L t = Relay operating time in seconds k = Time dial, or time multiplier setting I = Fault current level in seconds amps I S = Tap or pick up current selected L = Constant a = Slope constant b = Slope constant
Setting time delay on overcurrent relays IDMT Curve Description Standard a b L Moderately Inverse IEEE 0.02 0.0515 0.114 Very Inverse IEEE 2 19.61 0.491 Extremely Inverse IEEE 2 28.2 0.1217 Inverse US-CO8 2 5.95 0.18 Short Time Inverse US-CO2 0.02 0.02394 0.0169 Standard Inverse IEC 0.02 0.14 Very inverse IEC 1.0 13.5 Extremely inverse IEC 2.0 80.0 Long Time Inverse UK 1 120
Operating time (s) Operating time (s) Standards of Time/Current characteristics IEC/UK overcurrent relay curves IEEE/US overcurrent relay curves UK LTI IEC SI IEC VI IEC EI IEEE MI IEEE VI US C02 US C08 IEEE EI Current (Multiples of Is) Current (Multiples of Is)
Setting OC relays using software techniques 1. Locate the fault and obtain the current for setting the relays. 2. Identify the pairs of relays to be set, first determining which one is farther away from the source. 3. Verify that the requirement s thermal capabilities are protected and devices operate for minimum short circuit levels.
Coordination across Dy transformers Three phase fault I f E f -n = X 1 = I N I delta = I = N I primary = 3I 2 I delta 3 = I
Coordination across Dy transformers Phase-to-phase fault I f E 2X 3. E f -n = - f = f 2x = 3 2 I 3 N I delta = I = 2 N 2 I 1 2 I primary = 2I delta = I
Coordination across Dy transformers Phase-to-ground fault I f E = f -n X = I N I delta = I = N 1 I I primary = 3 2 I 3
Coordination across Dy transformers Summary of fault conditions Fault I primary I secondary Three phase I I Phase-to-phase I 3I/2 Phase-to-earth I 3I
Coordination across Dy transformers t 0.4 Sec 3 2 I f I f A
Thermal limits of copper conductors Thermal Plastic Insulation 75 C
TIME (seconds) Thermal capacity of transformers Category IV 10000 9000 8000 7000 6000 5000 4000 3000 2000 1000 900 800 700 600 500 400 300 THROUGH-FAULT PROTECTION CURVE FOR FAULTS WHICH WILL OCCUR FREQUENTLY OR INFREQUENTLY 200 100 90 80 70 60 50 40 30 20 10 98 CATEGORY IV TRANSFORMERS Above 10000 kva Single-Phase Above 30000 kva Three-Phase 7 6 5 4 3 2 1 0.9 0.8 0.7 0.6 0.5 0.4 0.3 12 10 8 7 6 5 4 K TRANSFORMER IMPEDANCE 0.2 0.1 1 2 3 4 5 6 7 8 9 10 20 30 40 50 2 3 4 5 6 7 8 9 10 20 30 40 50 TIMES NORMAL BASE CURRENT
Checking of energizing conditions It is important to check that the relay settings are not going to present problems when system elements are energized. In the case of transformers, the initial magnetization inrush current can be expressed as: where I Inrush = K I nom I nom = nominal transformer current K = 8, from 500 to 2,500 kva transformer capacity K = 10 above 2,500 kva transformer capacity The inrush point remains during 0.1 seconds.
Negative sequence OC protection 50/51Q are common features of the new multi-function relays. The 51Q settings should be checked for coordination with phase-only sensing devices such as fuses, reclosers, and ground relays. Sensitivity to phase-to-ground unbalances can be increased with the application of ground relays, which can be set more sensitively than phase relays because a balanced load has no ground current component (3I 0 ). 50Q elements can provide similar increased sensitivity to phase-to-phase faults because a balanced load has no negative sequence (I 2 ) current component.
Negative sequence OC protection To plot the negative sequence time current characteristics on the same plot for the phase and ground devices, it is required to multiply the 50/51Q pickup value by the respective multiplier. The multiplier is the ratio of phase current to negative sequence current for the fault type. Fault Type Multiplier Ph-Ph 1.732 Ph-Ph-G >1.732 Ph-G 3 Three-Phase Infinity
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