Protection Coordination Serge Beauzile Chair IEEE FWCS Ch i Power Chair P &E Energy S Society i t
[email protected] June, 10, June 10 2014 8:30 -12:30 Florida Electric Cooperatives Association Clearwater, Florida
Seminar Objective • Distribution Circuit Protection – Fuse to Fuse Coordination – Recloser to Fuse Coordination – Breaker to Recloser Coordination
• Transmission Line Protection – Distance Protection – Pilot Protection Schemes – Current Differential Protection
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Art & Science of System Protection • Not an exact science, coordination schemes will vary based on: – Company Philosophy – Protection engineer preference – System requirements
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C Coordinating di ti D Devices i Basic concept: All protective devices are able to detect a fault do so at the same instant. If each h device d i that th t sensed d a fault f lt operated t d simultaneously, large portions of the system g every y time a fault needed would be de-energized to be cleared. This is unacceptable. A properly designed scheme will incorporate time delays into the protection system, allowing certain devices to operate before others. IEEE/ FECA Protection Coordination
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C Coordinating di ti D Devices i Timing of device operation is verified using timetime current characteristics or TCCs – device response curves plotted on log-log graph paper. Devices have inverse TCCs. They operate quickly for g magnitude g overcurrents,, and more slowly y large for lower-magnitude overcurrents. Operating time is plotted on the vertical axis, axis and current magnitude is plotted on the horizontal scale. IEEE/ FECA Protection Coordination
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C Coordinating di ti D Devices i Four different TCCs are shown h on the th left. Device “D” is the fastest to operate, and device “A” is the slowest.
100
1
.25 25 sec
A
0.1
For a given current value, the operating ti time can be b found. f d
B C D
3 kA
100,000
1000
100
10
0.01 10,000
Time in Seconds
10
Current in Amperes
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Coordinating g Devices In this example, Device A is clearly l l faster than Device B for low ((400-700 A)) fault currents.
100
Uncertain Coordination
1
0.1 A
B
100,000 1
10,000
1000
100
0.01 10
Time in Seconds
10
Device B is clearly faster for high (>1000 A) fault currents, t but b t iin the th 700-1000 A region, g is uncertain. timing
Current in Amperes
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Coordinating Devices Expulsion Fuse to Expulsion Fuse 100
Minimum Melt Average Melt + tolerance
Time in Seconds
10
Total Clear
1
Average Melt + tolerance + arcing time
0.1
Curves are developed at 25ºC With no preloading 10 00,000
10,000
1000
100
10
0.01
Current in Amperes
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Coordinating Devices Expulsion Fuse to Expulsion Fuse 100
In this example, the red TCCs represent the downstream (protecting) fuse, and the blue TCCs represent the upstream (protected) fuse.
1
The protected fuse should not be damaged by y a fault in the protecting fuse’s zone of protection.
0.1
100,,000
10,,000
1000 1
100
0.01 10
Time in Seconds
10
Current in Amperes
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Coordinating Devices Expulsion Fuse to Expulsion Fuse 100
Four factors need to be considered: 10
2. Ambient temperature. p
1
3. Preloading effects.
0.1
4. Predamage effects. 100 0,000
10 0,000
1000 1
100
0.01 10
Time in Seconds
1. Tolerances.
Current in Amperes
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Coordinating Devices Expulsion Fuse to Expulsion Fuse 100
Consideration of these four factors can be quite involved. Practically, the “75% Method” can be used: the maximum clearing g time of the protecting link shall be no more than 75% of the minimum melting time of the protected link.
1
0.1
Current in Amperes
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100,000
10,000
1000 1
100
0.01 10
Time in Seconds
10
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Coordinating Devices Expulsion Fuse to Expulsion Fuse 100
Minimum melting time of protected link at 5 kA is 0.3 seconds. Total clearing time of the protecting link at 5 kA is 0.22 seconds.
1
0.22 < 0.3 × 75% = 0.225, so coordination is assured for current magnitudes ≤ 5 kA.
0.1
Current in Amperes
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100 0,000
10 0,000
1000
100
0.01 10
Time in Seconds
10
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Utility y Distribution Feeders Multiple Feeder Segments Segments are defined as sectionalizable pieces of a feeder that can be automatically or manually separated from the rest of the feeder. feeder Segments are delineated by reclosers, fuses, sectionalizers or switches. switches Two primary concerns: number of customers per segment and d time to isolate l segment.
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Utility y Distribution Feeders Number of Customers per Segment The number of customers per segment has a major impact on reliability indices. As the number of segments per feeder increases, reliability y can also be adversely y impacted, p and construction cost will increase. A optimum An ti point i t mustt b be sought ht tto d determine t i th the best segment size. IEEE/ FECA Protection Coordination
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Utility Distribution Feeders Present and Future Load Requirements Even the best load forecasts are full of errors. You must continuously monitor your fuse coordination due changes in the load. It is impossible to predict everything, so versatility is the key.
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Coordination Goal
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1.
Maximum Sensitivity.
2.
Maximum Speed.
3.
Maximum Security.
4.
Maximum Selectivity.
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Basic Coordination Strategy gy
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1.
Establish a coordination pairs.
2.
Determine maximum load of each segment and the pickup of all delayed overcurrent devices.
3.
Determine the pickup current of all instantaneous overcurrent devices, based on short-circuit studies.
4 4.
Determine D t i remaining i i overcurrent device characteristics starting g to from the load and moving the source.
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Fuse Peak Load Capability
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Fuse Blow Vs. Fuse Save • Fuse Blow – Eliminates Instantaneous trip of the breaker or recloser (1st) by having the fuse blow for all permanent and temporary faults. – Minimizes momentary interruptions and increases SAIDI. SAIDI Improves power quality but decreases reliability.
• Fuse Save – Minimizes customer interruption time by attempting to open the breaker or recloser faster than it takes to melt the fuse. fuse – This saves the fuse and allows a simple momentary interruption. IEEE/ FECA Protection Coordination
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Fuse Blow
FUSE is BLOWN
Lateral experiences sustained interruption
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Fuse Blow – Used primarily to minimize momentary interruptions (reduces MAIFI) – Increases interruption duration (SAIDI) – Very successful in high short circuit areas – More suitable for industrial type customers having very sensitive loads
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Fuse Save Entire Feeder trips Momentary occurs
FUSE is SAVED IEEE/ FECA Protection Coordination
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Fuse Save – – – – – –
Minimize customer interruption time Reduce SAIDI Increase MAIFI May not work in high short circuit areas Work well in most areas Not suitable for certain industrial customers that cannot tolerate immediate reclosing – Works best for residential and small commercial customers IEEE/ FECA Protection Coordination
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Both ((Fuse Save & Fuse Blow)) • Many utilities use both schemes for a variety of reasons – Fuse Blow for high short circuit current areas and Fuse Save where it will work. – Fuse Save on overhead and Fuse Blow on underground taps. – Fuse Save on rural and Fuse Blow on urban – Fuse Save on stormy days and Fuse Blow on nice days. – Fuse F Save S on some circuits i it and d Fuse F Blow Bl on others depending on customer desires
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Fast Bus Trip
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SEL-351S SEL 351S Protection and Breaker Control Relay
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Modern Microprocessor Relay Protection and Breaker Control Relay
Extremely versatile, many applications Most commonly used on distribution feeders Communicates with EMS system (DNP 3.0 Protocol) Key element of “Substation Integration” Provides many “traditional” features Provides new capabilities
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SEL-351S Protection and Breaker Control Relay Protection Features: P f Performs att lleastt 18 different diff t protection t ti functions. f ti
=
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SEL-351S Protection and Breaker Control Relay Protection Features: B U Bus Undervoltage d lt (27) Phase Overvoltage (59P) G Ground d Overvoltage O lt (59G) Sequence Overvoltage (59Q) O Overfrequency f (81O) Underfrequency (81U) IEEE/ FECA Protection Coordination
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Modern Microprocessor Relay Protection and Breaker Control Relay Protection Features (continued): Ph Phase Di Directional ti l Overcurrent O t (67P) Ground Directional Overcurrent (67G) S Sequence Di Directional ti l Overcurrent O t (67Q) Instantaneous Phase Overcurrent (50P) I t t Instantaneous Ground G d Overcurrent O t (50G) Instantaneous Sequence Overcurrent (50Q) IEEE/ FECA Protection Coordination
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SEL-351S Protection and Breaker Control Relay Protection Features (continued): Ti Time Ph Phase Overcurrent O t (51P) Time Ground Overcurrent (51G) Ti Time S Sequence Overcurrent O t (51Q) Directional Neutral Overcurrent (67N) I t t Instantaneous N t l Overcurrent Neutral O t (50N) Time Neutral Overcurrent (51N) IEEE/ FECA Protection Coordination
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SEL-351S Protection and Breaker Control Relay Breaker Control Features: S Synchronism h i Ch Check k (25) Automatic Circuit Reclosing (79) TRIP/CLOSE Pushbuttons Enable/Disable Reclosing Enable/Disable Supervisory Control
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SEL-351S Protection and Breaker Control Relay Other Features: E Event t Reporting R ti and dR Recording di Breaker Wear Monitor St ti Battery Station B tt M Monitor it High-Accuracy Metering F lt Locator Fault L t
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SEL-351S Protection and Breaker Control Relay
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• Advantages of microprocessor relays
Extremely flexible Have many different elements (UF, UV, Directionality, etc…) One relay can protect on zone of protection Inexpensive and require much less maintenance Alarm if they fails and don’t need calibration Provide fault information Provide oscillography and SER data Can provide analog data to SCADA
• Disadvantages of microprocessor relays Can be very complex to program due to given flexibility Require R i more training t i i to t Relay R l T Technicians h i i Require more training to Relay Engineers
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Relays • Basic relay settings: Phase overcurrent elements must be set above maximum possible loads Ground overcurrent elements must be set above maximum anticipated p unbalanced loads Must be coordinated with downstream protective devices Under Frequency elements must be set according to the predetermined set point
• TAGGING NORMAL mode – 2 reclosing g attempts p WORK mode – HOT LINE TAG COLD mode
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Relay Curves 100
10
S e c o n d s
Moderately Inverse
1
Inverse Very Inverse Extremely Inverse
0.1
0.01 0.1
1 10 Multiple of Pick Up
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100
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Very Inverse Curve Time Dial 0.29s
100
In this example p Multiple of Pickup = 3.
SECONDS
10
TD=0.5
1
TD=2 TD=6 TD 6
TD = 0.5 05 TD = 2 TD = 6 TD = 15
Time = 0.3s 0 3s Time = 1.1s Time = 3.4s Time = 7.0s
TD=15 0.1
0.01 0.1
1 10 Multiples Of Pick Up
100
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Very Inverse Curve Time Dial 0.29s
In this example,
100
Pickup Pi k = 600 A A. Fault Current = 1800 A.
SECONDS
10
TD=0.5
1
TD=2
T = 0.5 TD TD = 2 TD = 6 TD = 15
Time = 0.29s 0. 9s Time = 1.16s Time = 3.48s Time = 8.72s
TD=6 TD 6 TD=15 0.1
0.01 0.1
1 10 Multiples Of Pick Up
100
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Pickup = 900 A. Fault Current = 1800 A. TD = 0.5 TD = 2 TD = 6 TD = 15 June 2014
Time = 0.69s Time = 2.78s Time = 8.33s Time = 20.8s 20 8s
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Pickup p Current of Delayed y Ground OC Devices Source Side
Backup
Load Side
Primary Single g Phase to Ground Fault
IMU
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Pickup p Current of Delayed y Phase OC Devices Source Side
IML
Load Side
Phase to Phase Fault
IML = Maximum Load
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Typical Pickup Setting
TB > TR + CTI
CTI = Coordination Time Interval (Typically 0.2-0.5sec)
Recloser Ct ratio 600:1 IPU = 1 A IPU Primary= 600 A
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Breaker Ct ratio 240:1 IPU = 3.75 A IPU Primary= 900 A
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Trip Logic TR
= OC + PB9 + 51P1T + 51G1T * (LT6 + LT7) + (50P3 + 50G3) * LT7 + (50P2 + 50G2) * SH1
OC: OPEN COMMAND (SCADA TRIP) PB9: FRONT PUSH BUTTON 51P1T: PHASE TIME OC ELEMENT 51G1T: GROUND TIME OC ELEMENT LT6: TAGGING IS IN NORMAL MODE LT7: TAGGING IS IN WORK MODE 50P2/50P3: PHASE INSTANTANEOUS OC ELEMENT 50G2/50G3: GROUND INSTANTANEOUS OC ELEMENT SH1: RECLOSING SHOT #1 (FIRST RECLOSE ATTEMPT) CTR = 600.0 INSTANTANEOUS ENABLED ONLY AFTER FIRST RECLOSE ATTEMPT 50P2P = 2.5 (1500 AMPS PRIMARY) 50G2P = 1.6 1 6 (960 AMPS PRIMARY) INSTANTANEOUS ENABLED ONLY DURING WORK/HOT LINE TAG 50P3P = 1.35 (810 AMPS PRIMARY) 50G3P = 0 0.50 50 (300 AMPS PRIMARY) – NORMAL UNBALANCE GROUND CURRENT ~20 TO 30 AMPS IEEE/ FECA Protection Coordination
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SEL-351S History Summary (HIS Command) Sample output:
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SEL-351S Sequence of Events Recording (SER)
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SEL-351S Metering Data (MET Command) Sample output - Metering Data (MET):
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SEL-351S Metering Data (MET Command) Sample output - Metering Demand (MET D):
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SEL-351S Metering Data (MET Command) Sample output - Metering Energy (MET E):
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SEL-351S Metering Data (MET Command) Sample output - Metering Max/Min (MET M):
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Differential Relays Protection of a Delta‐Wye Transformer
Ia‐IIb A B C
Ib‐Ic Ic‐Ia
Ia‐IIb
Ia‐Ib Ib‐Ic
Ib‐Ic
52 Ic‐Ia
Ia Ib Ic
Ic‐Ia
Ia
Ia Ia I b
52
Ib
Ib I c
Ic
a b c
Ic Ia‐Ib
Ia‐Ib Ib‐Ic Ic‐Ia
Power System Protection
R
OP R
Ia‐Ib
R
OP R
Ib‐Ic Ib‐IIc
R
OP R
Ic‐Ia
-64-
Ic‐Ia
Ralph Fehr, Ph.D., P.E. – October 28, 2013
Distance Relays y Protection Features
– Four zones of distance protection – Pilot schemes – Phase/Neutral/Ground TOCs – Phase/Neutral/Ground IOCs Phase/Neutral/Ground IOCs Power System Protection
-65-
Ralph Fehr, Ph.D., P.E. – October 28, 2013
Distance Relays y Protection Features ‐ continued – Negative sequence TOC – Negative sequence IOC – Phase directional OCs – Neutral directional OC – Negative sequence directional OC – Phase under‐ and overvoltage – Power swing blocking – Out of step tripping Power System Protection
-66-
Ralph Fehr, Ph.D., P.E. – October 28, 2013
Distance Relays Control Features Control Features – Breaker Failure (phase/neutral amps) B k F il ( h / t l ) – Synchrocheck – Autoreclosing
Power System Protection
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Ralph Fehr, Ph.D., P.E. – October 28, 2013
Distance Relays Metering Features Metering Features − Fault Locator F lt L t − Oscillography − Event Recorder − Data Logger − Phasors / true RMS / active, reactive and apparent power, power factor and apparent power, power factor
Power System Protection
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Ralph Fehr, Ph.D., P.E. – October 28, 2013
Distance Relays Zones of Protection
Zone 2 Zone 2
X 3
Zone 1 2 1
Line Impedance (Line A) Line Impedance (Line A) Zone 2
1
A1 Z Zone 3 3
Bus 1
Zone 3
Power System Protection
Bus 2
Normal Load Normal Load R Distance Relay at Bus 1 to protect Line A
4
A2 3
4
Zone 1 2
Line A
Zone 1 – fastest (80% of line) Zone 2 – slower (120% of line) Zone 3 –(backwards Use in Pilot Protection for current Reversal logic) -69-
Ralph Fehr, Ph.D., P.E. – October 28, 2013
Zone of Protection Zone 2 Zone 1 1
∆t 2
∆t
∆t
Zone 2
Zone 1 4
3
Zone 1 Zone 2
Zone 3
Zone 1
Zone 2
Zone 3 Zone 1: Under reaches the remote line end Typically 0.7 Z1L to 0.9 Z1L With no intentional time delay. Zone 2: Z 2 Over O reaches h the th remote t line li end d Typically T i ll 1.2 1 2 Z1L with definite time delay. Zone 3: Over reaches the longest adjacent line with i h definite d fi i time i d delay l greater than h Z Zone2. 2 IEEE/ FECA Protection Coordination
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Unconventional Zone 2 & Zone 3 Settings
Zone 2 Zone 1
Long Line
∆t
Short Line
Be Mindful when Applying General Rules
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Step Distance Relay Coordination Exercise
Setting the relay at breaker 3 protecting Circuit 2. Set the Zones of Protection. The maximum expected load is about 600A. CTR = 1200:5 or 240:1 IEEE/ FECA Protection Coordination
PTR = 600:1 June 2014
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Distance Relay Coordination Exercise
Circuit 2 & Circuit 5 Impedances
Circuit 3 & Circuit 6 Impedances
Z1 = 35.11 83.97˚ Ω primary
Z1 = 17.56 83.72˚ Ω primary
Z0 = 111.58 81.46˚ Ω primary
Z0 = 53.89 81.56˚ Ω primary
Circuit 1& Circuit 4 Impedances Z1 = 35.21 83.72˚ Ω primary Z0 = 187.80 81.56˚ Ω primary IEEE/ FECA Protection Coordination
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Distance Relay Coordination Exercise
Zone 1 Reach = 0.8 * (35.11 83.97˚) Ω primary Z Zone 2R Reach h=1 1.2 2 * (35.11 35 11 83.97˚) 83 97˚) Ω primary i
Zone 1 Reach = 28.09 83.97˚) Ω primary Z Zone 2R Reach h = 42.13 42 13 83.97˚) 83 97˚) Ω primary i
Check Zone 2 reach does not overreach = Circuit 2 Impedance + (Zone 1 of Circuit 3) or (Zone 1of Circuit 6). General rule = p protected Circuit Impedance p + Zone 1 of the Shortest Circuit p past the p protected circuit.
Check for Zone 2 Overreach = 35.11. + (0.8 * 17.56) = 49.16 Ω primary Zone 2 Reach = 42.13 < 49.16 no overreach Zone 4 Reach = (35.11 83.97˚) + (17.56 83.72˚) ( Ω primary) Zone 4 Reach = 52.55 83.35˚) Ω primary IEEE/ FECA Protection Coordination
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Primary / Secondary Impedance Relay Input
75
Relay Input
Zone 1 Reach = 28.09 Ω x 240 = 11.24 Ω secondary 600 Zone 2 Reach = 42.43 Ω x 240 = 16.97 Ω secondary 600 Zone 4 Reach = 28.09 Ω x 240 = 21.02 Ω secondary 600 IEEE/ FECA Protection Coordination
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Overcurrent Supervision Setting Criteria
Zone 1 Phase Fault detector: 1) Find the lowest Ø – Ø fault seen by relay 3 for a remote end bus (4 (4, 10 10, 5 5, 11) 11).
Set above (maximum load) and 60% of min fault.
Zone 2 Phase Fault detector: 1) Find the lowest Ø – Ø fault seen by relay 3 for a remote end bus ((6,, 12). )
Set above (maximum load) and 60% of min fault.
Zone 4 Fault detector same as Zone 2 Repeat same process for Ground Fault detector. IEEE/ FECA Protection Coordination
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Current Infeed IL =0.5 A ZL =2 Ω
IR =1 A ZR =1 Ω
IT =0.5 A ZT =1 Ω
Actual Impedance from L to the Fault is 3Ω
Apparent Impedance = EL IL Apparent Impedance = ( IL x ZL) + (IR x ZR) IL
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Apparent Impedance = 4Ω
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Thank You IEEE/ FECA Protection Coordination
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