Post on 22-Jan-2020
1
DISTRIBUTION PROTECTION OVERVIEW
Kevin Damron & Beth Andrews
Avista Utilities
Presented
March 13th, 2017
At the 34th Annual
Hands-On Relay School
Washington State University
Pullman, Washington
2
Table of Contents
IEEE Device Designations …………………………………………….…….. 3
System Overview ………………………………………………………....… 4
Distribution (5-30MVA ) Transformer Protection damage curve …….…... 9
Relay Overcurrent Curves …………………………………………..……. 20
Symmetrical Components ……………………………………………..…….. 24
Distribution Fuse Protection ………………………………………….……. 39
Coordinating Time Intervals …………………………………………….… 43
Transformer Relay Settings using Electromechanical Relays ………….…… 52
Transformer Differential Protection ……………………………………….… 67
Smart Grid Challenges & Solutions……………………………………….… 70
Moscow 13.8kV Feeder Coordination Example ……………………………. 76
3
2 – Time delay relay.
27 – Undervoltage relay.
43 – Manual transfer or selective device.
We use these for cutting in and out
instantaneous overcurrent relays,
reclosing relays etc.
50 (or 50P) – Instantaneous overcurrent
phase relay.
50N (or 50G) – Instantaneous overcurrent
ground (or neutral) relay.
50Q – Instantaneous Negative Sequence
overcurrent relay.
51 (or 51P) – Time delay overcurrent phase
relay.
51N (or 51G) – Time delay overcurrent
ground (or neutral) relay.
51Q – Time delay Negative Sequence
overcurrent relay.
52 – AC circuit breaker.
IEEE Device Designations commonly used in Distribution Protection
Avista sometimes adds letters to these such as F for feeders, T for transformers, B for bus and BF for
breaker failure.
52/a – Circuit breaker auxiliary switch closed
when the breaker is closed.
52/b – Circuit breaker auxiliary switch closed
when the breaker is open.
59 – Overvoltage relay.
62 – Time Delay relay
63 – Sudden pressure relay.
79 – AC Reclosing relay.
81 – Frequency relay.
86 – Lock out relay which has several contacts.
Avista uses 86T for a transformer lockout,
86B for a bus lockout etc.
87 – Differential relay.
94 – Auxiliary tripping relay.
4
System Overview - Distribution Protection
Objective:
Protect people (company personnel and the public) and equipment by the proper
application of overcurrent protective devices.
Devices include:
Relays operating to trip (open) circuit breakers or circuit switchers, and/or fuses blowing
for the occurrence of electrical faults on the distribution system.
Design tools used:
1 – Transformer and conductor damage curves,
2 - Time-current coordination curves (TCC’s), fuse curves, and relay overcurrent
elements based on symmetrical components of fault current.
Documentation:
1 - One-line diagrams and Schematics with standardized device designations as defined
by the IEEE (Institute of Electrical and Electronics Engineers) – keeps everyone on the
same page in understanding how the system works.
2 - TCC’s
XFMR 12/16/20 MVA
115/13.8kV
115 kV SYSTEM
13.8 kV BUS
500A, 13.8 kVFDR #515
DELTA/WYE
LINE RECLOSER P584
3Ø = 5158SLG = 5346
3Ø = 3453SLG = 2762
PT-2BPT-2A
3Ø = 3699SLG = 3060
PT-3B PT-3A PT-4
#4 ACSR
1 PHASE#4 ACSR #4 ACSR
#4 ACSR
#2 ACSR#4 ACSR
2/0 ACSR#2 ACSR
3Ø = 1907SLG = 1492
3Ø = 322SLG = 271
3-250 KVAWYE/WYE
PT-865T
A-172
MOSCOW
1 PHASE#4 ACSR
3Ø = 558SLG = 463
PT-3C
PT-6BPT-6A
PT-6C
HIGH LEAD LOW
3Ø = 1210SLG = 877
PT-1
PT-5
PT-7
FUSE
556 ACSR
556 ACSR
13.8 kV FDR #512
500 A FDR
5
System Overview – Inside the
Substation Fence
Transformer
relays
Feeder relay
6
XFMR 12/16/20 MVA
115/13.8kV
115 kV SYSTEM
13.8 kV BUS
500A, 13.8 kVFDR #515
DELTA/WYE
LINE RECLOSER P584
3Ø = 5158SLG = 5346
3Ø = 3453SLG = 2762
PT-2BPT-2A
3Ø = 3699SLG = 3060
PT-3B PT-3A PT-4
#4 ACSR
1 PHASE#4 ACSR #4 ACSR
#4 ACSR
#2 ACSR#4 ACSR
2/0 ACSR#2 ACSR
3Ø = 1907SLG = 1492
3Ø = 322SLG = 271
3-250 KVAWYE/WYE
PT-865T
A-172
MOSCOW
1 PHASE#4 ACSR
3Ø = 558SLG = 463
PT-3C
PT-6BPT-6A
PT-6C
HIGH LEAD LOW
3Ø = 1210SLG = 877
PT-1
PT-5
PT-7
FUSE
556 ACSR
556 ACSR
13.8 kV FDR #512
500 A FDR
System Overview – Outside the
Substation Fence
Midline
recloser
relay
XFMR 12/16/20 MVA
115/13.8kV
115 kV SYSTEM
13.8 kV BUS
500A, 13.8 kVFDR #515
DELTA/WYE
LINE RECLOSER P584
3Ø = 5158SLG = 5346
3Ø = 3453SLG = 2762
PT-2BPT-2A
3Ø = 3699SLG = 3060
PT-3B PT-3A PT-4
#4 ACSR
1 PHASE#4 ACSR #4 ACSR
#4 ACSR
#2 ACSR#4 ACSR
2/0 ACSR#2 ACSR
3Ø = 1907SLG = 1492
3Ø = 322SLG = 271
3-250 KVAWYE/WYE
PT-865T
A-172
MOSCOW
1 PHASE#4 ACSR
3Ø = 558SLG = 463
PT-3C
PT-6BPT-6A
PT-6C
HIGH LEAD LOW
3Ø = 1210SLG = 877
PT-1
PT-5
PT-7
FUSE
556 ACSR
556 ACSR
13.8 kV FDR #512
500 A FDR
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
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TIME-CURRENT CURVES @ Voltage 13.8 kVHORS 2010 By JDH
For Idaho Rd Feeder 252 in Idaho Rd PHASE 1 2007base.olr No.
Comment At Sub: 3LG=5667A, SLG=5863A, L-L=4909A Date 11-25-2008
TRANSFORMER PROTECTION
STATION VCB 252 PROTECTION
MAXIMUM FEEDER FUSE
HI-SIDE CT'S
MIDLINE OCR
MAXIMUM MIDLINE FUSE
Fault I=5665.9 A
1
1. IDR A-777 51P 351 SEL-VI TD=1.200CTR=600/5 Pickup=2.A No inst. TP@5=0.3096sIa= 679.8A (5.7 sec A) T= 0.78s H=8.33
2
2. IDR 252 51P 351S SEL-EI TD=1.500CTR=800/5 Pickup=6.A No inst. TP@5=0.4072sIa= 5665.9A (35.4 sec A) T= 0.30s
3. IDR 252 50G 351S INST TD=1.000CTR=800/5 Pickup=3.A No inst. TP@5=0.048s3Io= 0.0A (0.0 sec A) T=9999s
4
4. 252 140T FUSE stn S&C Link140TTotal clear.Ia= 5665.9A T= 0.09s
5
5f
5. Phase unit of recloser MID LINE OCR Fast: ME-341-B Mult=0.2 Slow: ME-305-A Add=1000. Ia= 5665.9A T(Fast)= 0.03s
6
6. T FUSE S&C Link 50TMinimum melt.Ia= 5665.9A T= 0.01s
A
A. Conductor damage curve. k=0.06710 A=556000.0 cmilsConductor AACFEEDER 252 SMALLEST CONDUCTOR TO PROTECT
B
B. Transf. damage curve. 12.00 MVA. Category 3Base I=502.00 A. Z= 8.2 percent.IDAHO RD 12/16/20 MVA XFMR
FAULT DESCRIPTION:Bus Fault on: 0 IDR 252 13.8 kV 3LG
7
System Overview –Each device has at least one curve plotted with current and time values
on the Time Coordination Curve.
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
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10
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1000
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TIME-CURRENT CURVES @ Voltage 13.8 kVHORS 2010 By JDH
For Idaho Rd Feeder 252 in Idaho Rd PHASE 1 2007base.olr No.
Comment At Sub: 3LG=5667A, SLG=5863A, L-L=4909A Date 11-25-2008
TRANSFORMER PROTECTION
STATION VCB 252 PROTECTION
MAXIMUM FEEDER FUSE
HI-SIDE CT'S
MIDLINE OCR
MAXIMUM MIDLINE FUSE
Fault I=5665.9 A
1
1. IDR A-777 51P 351 SEL-VI TD=1.200CTR=600/5 Pickup=2.A No inst. TP@5=0.3096sIa= 679.8A (5.7 sec A) T= 0.78s H=8.33
2
2. IDR 252 51P 351S SEL-EI TD=1.500CTR=800/5 Pickup=6.A No inst. TP@5=0.4072sIa= 5665.9A (35.4 sec A) T= 0.30s
3. IDR 252 50G 351S INST TD=1.000CTR=800/5 Pickup=3.A No inst. TP@5=0.048s3Io= 0.0A (0.0 sec A) T=9999s
4
4. 252 140T FUSE stn S&C Link140TTotal clear.Ia= 5665.9A T= 0.09s
5
5f
5. Phase unit of recloser MID LINE OCR Fast: ME-341-B Mult=0.2 Slow: ME-305-A Add=1000. Ia= 5665.9A T(Fast)= 0.03s
6
6. T FUSE S&C Link 50TMinimum melt.Ia= 5665.9A T= 0.01s
A
A. Conductor damage curve. k=0.06710 A=556000.0 cmilsConductor AACFEEDER 252 SMALLEST CONDUCTOR TO PROTECT
B
B. Transf. damage curve. 12.00 MVA. Category 3Base I=502.00 A. Z= 8.2 percent.IDAHO RD 12/16/20 MVA XFMR
FAULT DESCRIPTION:Bus Fault on: 0 IDR 252 13.8 kV 3LG
8
System Overview –
Damage Curves:
- transformer
- conductor
So, what curve goes where?
What are the types of curves?
Protective Curves:
- relay
- fuse
Damage curves are at the top and to
the right of the TCC.
Protective curves lowest and to the
left on the TCC correspond to those
devices farther from the substation
where the fault current is less.
9
Transformer Protection - Damage Curve – ANSI/IEEE C57.109-1985
The main damage curve line shows only the thermal effect
from transformer through-fault currents. It is graphed
from data entered below (MVA, Base Amps, %Z ):10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
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T IME-CURRENT CURVES @ Voltage By
For No.
Comment Date
1
1. M15 P584 GND INST INST TD=1.000CTR=100 Pickup=3.A No inst. TP@5=0.048s
A
A. T ransf. damage curve. 12.00 MVA. Category 3Base I=502.00 A. Z= 8.2 percent.
The dog leg on the curve is added to allow for additional
thermal and mechanical damage from (typically more
than 5) through-faults over the life of a transformer
serving overhead feeders.
Dog leg curve - 10 times base current at 2 seconds.
Main curve - 25 times base current at 2 seconds.
Time at 50% of the maximum per-unit
through fault current = 8 seconds.
Avista has Category III size (5-30MVA) Distribution Transformers in service per the above standard.
10
Copper Conductor Damage Curves ACSR Conductor Damage Curves
(2/0 damage at 1500A @ 100sec.) (2/0 damage at 900A @ 100sec.)
Conductor Damage Curves
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
2
3
45
7
10
20
30
4050
70
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300
400500
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1000
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4050
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400500
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TIME-CURRENT CURVES @ Voltage 13.8 kV By DLH
For ACSR Conductor Damage Curves No.
Comment Date 12/13/05
1
1. M15-515 Phase INST INST TD=1.000CTR=160 Pickup=7.A No inst. TP@5=0.048s
A
A. Conductor damage curve. k=0.08620 A=355107.0 cmilsConductor ACSR336.4 ACSR
B
B. Conductor damage curve. k=0.08620 A=167800.0 cmilsConductor ACSR AWG Size 4/04/0 ACSR
C
C. Conductor damage curve. k=0.08620 A=105500.0 cmilsConductor ACSR AWG Size 2/02/0 ACSR
D
D. Conductor damage curve. k=0.08620 A=83690.0 cmilsConductor ACSR AWG Size 1/01/0 ACSR
E
E. Conductor damage curve. k=0.08620 A=52630.0 cmilsConductor ACSR AWG Size 2#2 ACSR
FF. Conductor damage curve. k=0.08620 A=33100.0 cmilsConductor ACSR AWG Size 4#4 ACSR
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
2
3
45
7
10
20
30
4050
70
100
200
300
400500
700
1000
2
3
45
7
10
20
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4050
70
100
200
300
400500
700
1000
.01
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.01
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1
TIME-CURRENT CURVES @ Voltage 13.8 kV By DLH
For Copper Conductor Damage Curves No.
Comment Date 12/13/05
1
1. M15-515 Phase INST INST TD=1.000CTR=160 Pickup=7.A No inst. TP@5=0.048s
A
A. Conductor damage curve. k=0.14040 A=105500.0 cmilsConductor Copper (bare) AWG Size 2/02/0 Copper
B
B. Conductor damage curve. k=0.14040 A=83690.0 cmilsConductor Copper (bare) AWG Size 1/01/0 Copper
C
C. Conductor damage curve. k=0.14040 A=52630.0 cmilsConductor Copper (bare) AWG Size 2#2 Copper
D
D. Conductor damage curve. k=0.14040 A=33100.0 cmilsConductor Copper (bare) AWG Size 4#4 Copper
EE. Conductor damage curve. k=0.14040 A=20820.0 cmilsConductor Copper (bare) AWG Size 6#6 Copper
11
Conductor Rating
556 730
336.4 530
4/0 340
2/0 270
1/0 230
#2 180
#4 140
ACSR
Ampacity Ratings
Conductor Rating
2/0 360
1/0 310
#2 230
#4 170
#6 120
Copper
Ampacity Ratings
Conductor Ampacities
Conductor at 25°C ambient taken from the Westinghouse Transmission & Distribution book.
12
Comparing a 140T fuse versus a
#4 ACSR Damage curve.
The 140T won’t protect the
conductor below about
550 amps where the curves cross.
Conductor Protection Graph
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
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TIME-CURRENT CURVES @ Voltage 13.8 kV#4 ACSR & 140T By Protection
For Aspen File: HORS M15 EXP.olr No.
Comment Date 3/06
1
1. Moscow 515 Kear 140T Kearney 140TTotal clear.
A
A. Conductor damage curve. k=0.08620 A=33100.0 cmilsConductor ACSR AWG Size 4
13
Transformer Protection using
115 kV Fuses
14
Transformer Protection using
115 kV Fuses
Used at smaller substations up to 7.5 MVA
transformer due to low cost of protection.
Other advantages are:
- Low maintenance
- Panel house & station battery not required
There are also several disadvantages to
using fuses however which are:
Low interrupting rating from 1,200A (for
some older models) up to 10,000A at 115 kV.
By contrast a circuit switcher can have a rating
of 25KAIC and our breakers have normally
40KAIC.
The fuses we generally use are rated to blow
within 5 minutes at twice their nameplate
rating. Thus, a 65 amp fuse will blow at 130
amps. This compromises the amount of
overload we can carry in an emergency and
still provide good sensitivity for faults.
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
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3
4
5
7
10
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30
40
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700
1000
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TIME-CURRENT CURVES @ Voltage 13.8 KVROK 451R2 By JDH
For ROK FDR 451, BUS FAULTS: 3LG=3580A, SLG=3782A, L-L=3100A No.
Comment ASPEN FILE: ROK NEW XFMR (2005 BASE).OLR Date 2-13-07
STATION TRANSFORMER PROTECTION
FEEDER VCR PROTECTION
MAXIMUM FEEDER FUSE
1
1. LAT RP4211 50N CO-11 INST TD=1.000CTR=500/5 Pickup=2.A No inst. TP@5=0.048s
2
2. SMD-2B 65E VERY SLOW 176-19-065Minimum melt. H=8.33
3
3. LAT RP4211 50P CO-11 INST TD=1.000CTR=500/5 Pickup=3.5A No inst. TP@5=0.048s
4
4. LAT RP4211 51P CO-11 CO-11 TD=2.000CTR=500/5 Pickup=3.A No inst. TP@5=0.5043s
5
5. LAT RP4211 51N CO-11 CO-11 TD=4.000CTR=500/5 Pickup=2.A No inst. TP@5=1.0192s
6
6. LAT RP4211 FUSE S&C Link 65TTotal clear.
A
A. Transf. damage curve. 7.50 MVA. Category 3Base I=313.78 A. Z= 7.3 percent.Rockford 13.8kV - ROCKFORD115 115.kV 1 T
15
The fuse time current characteristic (TCC) is fixed (although you can buy a standard, slow
or very slow speed ratio which are different inverse curves).
The sensitivity to detect lo-side SLG faults isn’t as good as using a relay on a circuit
switcher or breaker. This is because we use DELTA/WYE connected transformers so the
phase current on the 115 kV is reduced by the 3 as opposed to a three phase fault.
Some fuses can be damaged and then blow later at some high load point.
When only one 115 kV fuse blows, it subjects the customer to low distribution voltages.
For example the phase to neutral distribution voltages on two phases on the 13.8 kV become
50% of normal.
No indication of faulted zone (transformer, bus or feeder).
Transformer Protection using 115 kV Fuses - continued
A
B
C
a
b
c
1.0 PU
0.5 PU0.5 PU
16
Transformer Protection using a Circuit SwitcherShowing Avista’s present standard using Microprocessor relays.
13.8kV 115kV
17
Transformer Protection using a Circuit SwitcherShowing Avista’s old standard using Electromechanical relays.
18
Transformer Protection using a Circuit Switcher
Some advantages to this over fuses are:
Higher interrupting.
Relays can be set to operate faster
and with better sensitivity than
fuses.
Three phase operation.
Provide better coordination with
downstream devices.
Some disadvantages would be:
Higher cost.
Higher maintenance.
Requires a substation battery, panel
house and relaying.
Transformer requires CT’s.
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
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7
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1000
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.01
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1
TIME-CURRENT CURVES @ Voltage 13.8 kVIDR FEEDER 251 By JDH
For Idaho Rd Feeder 251 in Idaho Rd PHASE 1 2007base.olr No.
Comment At Sub: 3LG=5667A, SLG=5863A, L-L=4909A Date 11-25-2008
TRANSFORMER PROTECTION
STATION VCB 251 PROTECTION
MAXIMUM FEEDER FUSE
HI-SIDE CT'S
LO-SIDE CT'S
MINIMUM FAULT TO DETECT:3LG=2460A, SLG=1833A, L-L=2130A
1
1. IDR A-777 51P 351 SEL-VI TD=1.200CTR=600/5 Pickup=2.A No inst. TP@5=0.3096s H=8.33
2
2. IDR A-777 51G 351 SEL-VI TD=1.000CTR=600/5 Pickup=1.A No inst. TP@5=0.258s H=8.33
3
3. IDR A-777 51N 351 SEL-EI TD=5.700CTR=1200/5 Pickup=3.A No inst. TP@5=1.5473s
4
4. IDR A-777 51Q 351 SEL-EI TD=4.200CTR=600/5 Pickup=1.3A No inst. TP@5=1.1401s H=8.33
5
5. IDR A-777 51Q 587 W2 SEL-EI TD=4.300CTR=1200/5 Pickup=5.4A No inst. TP@5=1.1672s
6
6. IDR 251 50P 351S INST TD=1.000CTR=800/5 Pickup=7.A No inst. TP@5=0.048s
7
7. IDR 251 51P 351S SEL-EI TD=1.500CTR=800/5 Pickup=6.A No inst. TP@5=0.4072s
8
8. IDR 251 50G 351S INST TD=1.000CTR=800/5 Pickup=3.A No inst. TP@5=0.048s
9
9. IDR 251 51G 351S SEL-EI TD=3.900CTR=800/5 Pickup=3.A No inst. TP@5=1.0587s
10
10. IDR 251 51Q 351S SEL-EI TD=3.500CTR=800/5 Pickup=5.2A No inst. TP@5=0.9501s
11
11. 251 140T FUSE stn S&C Link140TTotal clear.
A
A. Conductor damage curve. k=0.08620 A=133100.0 cmilsConductor ACSR AWG Size 2/0FEEDER 251 SMALLEST CONDUCTOR TO PROTECT
B
B. Transf. damage curve. 12.00 MVA. Category 3Base I=502.00 A. Z= 8.2 percent.IDAHO RD 12/16/20 MVA XFMR
19
Transformer Protection using a Breaker
This is very similar to using a circuit switcher with a couple of advantages such as:
Higher interrupting – 40kAIC for the one shown below.
Somewhat faster tripping than a circuit switcher (3 cycles vs. 6 – 8 cycles).
Possibly less maintenance than a circuit switcher.
The CT’s would be located on the breaker so it would interrupt faults on the bus section up to
the transformer plus the transformer high side bushings.
20
SEL Various Relay Overcurrent Curves.
Extremely Inverse – steepest
Very Inverse
Inverse
Moderately Inverse
Short Time Inverse – least steep
The five curves shown here have the same
pickup settings , but different time dial
settings.
These are basically the same as various E-M
relays.
Avista uses mostly extremely inverse on
feeders to match the fuse curves.
Relay Overcurrent Curves
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
2
3
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5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
.01
.02
.03
.04
.05
.07
.1
.2
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1
.01
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.04
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.1
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1
TIME-CURRENT CURVES @ Voltage By
For No.
Comment Date
1
1. EXTREMELY INVERSE SEL-EI TD=15.000CTR=800/5 Pickup=6.A No inst. TP@5=4.0718s
2
2. INVERSE SEL-I TD=2.000CTR=800/5 Pickup=6.A No inst. TP@5=0.8558s
3
3. MODERATELY INVERSE SEL-2xx-MI TD=1.000CTR=800/5 Pickup=6.A No inst. TP@5=0.324s
4
4. SHORT TIME INVERSE SEL-STI TD=1.000CTR=800/5 Pickup=6.A No inst. TP@5=0.1072s
5 5. VERY INVERSE SEL-VI TD=6.000CTR=800/5 Pickup=6.A No inst. TP@5=1.5478s
21
Time dial
- at what time delay will the relay operate to
trip the breaker
- the larger time dial means more time delay
- also known as “lever” from the
electromechanical relay days
- Instantaneous elements have a “time dial”
of 1 and operate at 0.05 seconds.
- Instantaneous curves are shown as a flat
horizontal line starting at the left at the
pickup value and plotted at 0.05 seconds.
Relay Overcurrent Curves - Pickups & Time Dials
Pickup
- the current at which the relay will operate to trip the breaker.
- also known as “tap” from the electromechanical relay days
-expressed in terms of the ratio of the current transformer (CTR) that the relay is connected to,
- e.g., a relay with a CTR of 120 and a pickup (or tap) of 4 will operate to trip the breaker at 480
amps10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
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1000
.01
.02
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.04
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.07
.1
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1
.01
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1
TIME-CURRENT CURVES @ Voltage 13.8 kVIDR FEEDER 251 By JDH
For Idaho Rd Feeder 251 in Idaho Rd PHASE 1 2007base.olr No.
Comment At Sub: 3LG=5667A, SLG=5863A, L-L=4909A Date 11-25-2008
TRANSFORMER PROTECTION
STATION VCB 251 PROTECTION
MAXIMUM FEEDER FUSE
HI-SIDE CT'S
LO-SIDE CT'S
MINIMUM FAULT TO DETECT:3LG=2460A, SLG=1833A, L-L=2130A
1
1. IDR A-777 51P 351 SEL-VI TD=1.200CTR=600/5 Pickup=2.A No inst. TP@5=0.3096s H=8.33
2
2. IDR A-777 51G 351 SEL-VI TD=1.000CTR=600/5 Pickup=1.A No inst. TP@5=0.258s H=8.33
3
3. IDR A-777 51N 351 SEL-EI TD=5.700CTR=1200/5 Pickup=3.A No inst. TP@5=1.5473s
4
4. IDR A-777 51Q 351 SEL-EI TD=4.200CTR=600/5 Pickup=1.3A No inst. TP@5=1.1401s H=8.33
5
5. IDR A-777 51Q 587 W2 SEL-EI TD=4.300CTR=1200/5 Pickup=5.4A No inst. TP@5=1.1672s
6
6. IDR 251 50P 351S INST TD=1.000CTR=800/5 Pickup=7.A No inst. TP@5=0.048s
7
7. IDR 251 51P 351S SEL-EI TD=1.500CTR=800/5 Pickup=6.A No inst. TP@5=0.4072s
8
8. IDR 251 50G 351S INST TD=1.000CTR=800/5 Pickup=3.A No inst. TP@5=0.048s
9
9. IDR 251 51G 351S SEL-EI TD=3.900CTR=800/5 Pickup=3.A No inst. TP@5=1.0587s
10
10. IDR 251 51Q 351S SEL-EI TD=3.500CTR=800/5 Pickup=5.2A No inst. TP@5=0.9501s
11
11. 251 140T FUSE stn S&C Link140TTotal clear.
A
A. Conductor damage curve. k=0.08620 A=133100.0 cmilsConductor ACSR AWG Size 2/0FEEDER 251 SMALLEST CONDUCTOR TO PROTECT
B
B. Transf. damage curve. 12.00 MVA. Category 3Base I=502.00 A. Z= 8.2 percent.IDAHO RD 12/16/20 MVA XFMR
22
Same Time Dial = 9
Right curve picks up at 960 Amps
Left curve picks up at 320Amps
Relay Overcurrent Curves - Example of Different Pickup & Time Dial Settings
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
.01
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.04
.05
.07
.1
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1
.01
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.1
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1
TIME-CURRENT CURVES @ Voltage By
For No.
Comment Date
1
1. EXT INV 1 SEL-EI TD=15.000CTR=800/5 Pickup=6.A No inst. TP@5=4.0718s
2 2. ~EXT INV 1 SEL-EI TD=12.000CTR=800/5 Pickup=6.A No inst. TP@5=3.2574s
3
3. ~EXT INV 2 SEL-EI TD=9.000CTR=800/5 Pickup=6.A No inst. TP@5=2.4431s
4
4. ~EXT INV 3 SEL-EI TD=6.000CTR=800/5 Pickup=6.A No inst. TP@5=1.6287s
5
5. ~EXT INV 4 SEL-EI TD=2.000CTR=800/5 Pickup=6.A No inst. TP@5=0.5429s
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
.01
.02
.03
.04
.05
.07
.1
.2
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.7
1
.01
.02
.03
.04
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.07
.1
.2
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.7
1
TIME-CURRENT CURVES @ Voltage By
For No.
Comment Date
1
1. EXT INV 1 SEL-EI TD=9.000CTR=800/5 Pickup=6.A No inst. TP@5=2.4431s
2
2. ~EXT INV 1 SEL-EI TD=9.000CTR=800/5 Pickup=5.A No inst. TP@5=2.4431s
3
3. ~EXT INV 2 SEL-EI TD=9.000CTR=800/5 Pickup=4.A No inst. TP@5=2.4431s
4
4. ~EXT INV 3 SEL-EI TD=9.000CTR=800/5 Pickup=3.A No inst. TP@5=2.4431s
5
5. ~EXT INV 4 SEL-EI TD=9.000CTR=800/5 Pickup=2.A No inst. TP@5=2.4431s
Same Pickup = 960 Amps
Top curve Time Dial = 15
Bottom curve Time Dial = 2
23
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
TIME-CURRENT CURVES @ Voltage 13.8 kVINT 12F1 By JDH
For Indian Trail feeder 12F1 in INT 2007base.olr No.
Comment AT SUB: 3LG= 5719A, LL=4951A, SLG= 5880A Date 1-29-08
TRANSFORMER PROTECTION
STATION VCB 12F1 PROTECTION
1 1. INT A-742 51P 351 SEL-VI TD=10.000CTR=600/5 Pickup=0.8A No inst. TP@5=2.5797s H=8.33
2
2. INT 12F1 51P 351S SEL-VI TD=1.800CTR=800/5 Pickup=3.A No inst. TP@5=0.4643s
3
3. INT 12F1 51G 351S SEL-VI TD=0.900CTR=800/5 Pickup=3.A No inst. TP@5=0.2322s
4
4. INT 12F1 51Q 351S SEL-VI TD=0.500CTR=800/5 Pickup=3.A No inst. TP@5=0.129s
5 5. INT A-742 51G 351 SEL-VI TD=5.000CTR=600/5 Pickup=0.8A No inst. TP@5=1.2898s H=8.33
6
6. INT A-742 51Q 351 SEL-VI TD=3.000CTR=600/5 Pickup=0.8A No inst. TP@5=0.7739s H=8.33
A
A. Transf. damage curve. 12.00 MVA. Category 3Base I=502.00 A. Z= 8.4 percent.INDIAN TRAIL 12/16/20 MVA XFMR
B
B. Conductor damage curve. k=0.06710 A=556000.0 cmilsConductor AAC556 kCMil AAC
Microprocessor relays have different
types of curves based on the type of
fault current being measured:
51P – phase time overcurrent
51N or 51G – ground time overcurrent
51Q – negative sequence time overcurrent
Transformer relay curves
Feeder relay curves
51P – phase time overcurrent
51N or 51G – ground time overcurrent
51Q – negative sequence time overcurrent
This brings us to a brief discussion of:
24
Symmetrical Components
Symmetrical Components for Power Systems Engineering,
J. Lewis Blackburn,
There are three sets of independent components in a three-phase
system: positive, negative and zero for both current and voltage.
Positive sequence voltages (Figure 1) are supplied by generators
within the system and are always present. A second set of balanced
phasors are also equal in magnitude and displaced 120 degrees
apart, but display a counter-clockwise rotation sequence of A-C-B
(Figure 2), which represents a negative sequence. The final set of
balanced phasors is equal in magnitude and in phase with each
other, however since there is no rotation sequence (Figure 3) this is
known as a zero sequence.
25
Symmetrical Components
Three phase (3LG) fault - Positive sequence currents – for setting phase elements in relays. Phase -Phase (L-L) fault - Negative sequence currents – for setting negative sequence elements in relays.Single phase (1LG or SLG) fault - Zero sequence currents – for setting ground elements in relays.
Symmetrical Components Notation:
Positive Sequence current = I + = I1
Negative Sequence current = I - = I2
Zero Sequence current = I 0 = I0
Phase Current notation:
IA – High side Amps
Ia – Low side Amps
8.33= 115/13.8 = transformer Voltage (turns) ratioPhasor diagram from Fault-study Software.
Examples of three 13.8kV faults showing the current distribution through a Delta-Wye high-lead-low transformer bank :
26
Symmetrical Components – Positive Sequence, 3LG 13.8 kV Fault
You have only positive sequence voltage and current since the system is balanced.
A
B
C
a
b
c
RR
IA = 619 -88 Ia = 5158 -118
IB = 619 152 Ib = 5158 122
IC = 619 32 Ic = 5158 2
Phase current = Sequence current
That is; Ia = I+.
Phase currents and voltages for the 115kV side.
IA = Ia / 8.33 = 5158A / 8.33
IA = 619A
27
Symmetrical Components – Negative Sequence, L-L 13.8 kV Fault
115kV side sequence currents and voltages
13.8kV side sequence currents and voltages
A
B
C
a
b
c
RR
IA = 309 -28 Ia = 0 0
IB = 619 152 Ib = 4467 152
IC = 309 -28 Ic = 4467 -28
3LG 13.8kV fault = 5158A,
Ib=Ic=4467 A, 4467/5158 = 86.6%=3/2
IB3LG = IBLL = 619A
IA & IC = IB or Ia & Ic = Ib
I2 = the phase current/3 = 4467/3 = 2579
Digital relays 50Q/51Q elements set using 3I2.
3I2 = Ib x 3 = 4467 x 1.732 = 7737,
28
Symmetrical Components – Zero Sequence, 1LG 13.8 kV Fault
115kV side sequence currents and voltages
A
B
C
a
b
c
RR
3I0 is the sum of the 3 phase currents and since Ib & Ic
= 0, then 3I0 = Ia. This means the phase and ground
overcurrent relays on the feeder breaker see the same
amount of current.
5346/(8.33*3) = 370 amps. So the high side phase
current is the 3 less as compared to the 3Ø fault.
Digital relays ground elements set using 3I0.13.8kV side sequence currents and voltages
IA = 370 -118 Ia=3I0=5346 -118
IB = 0 0 Ib = 0 0
IC = 370 62 Ic = 0 0
Ia = 3Va/(Z1 + Z2 + Z0)
29
Symmetrical Components - Summary of 13.8 kV Faults
3LG – positive sequence current
SLG – zero sequence current
L-L – negative sequence current
IA = 619 Ia = 5158
IB = 619 Ib = 5158
IC = 619 Ic = 5158
5158 / 8.33 = 619 Ia = 5158 = I1
5346/(8.33x3) = 370 Ia = 5346 = 3I0
If you have a Delta-Wye transformer bank, and you know the voltage ratio and secondary phase
current values for 13.8kV 3LG (5158) and SLG (5346) faults, you can find the rest:
IA = 309 Ia = 0
IB = 619 Ib = 4467
IC = 309 Ic = 4467
5158 x 3/2 = 4467 Ib x 3 = 7737 = 3I2
4467/(8.33x 3) = 309
309 x 2 = 619
IA = 370 Ia=5346
IB = 0 Ib = 0
IC = 370 Ic = 0
30
Symmetrical Components - Summary of 13.8 kV Faults
You’ve heard of a Line-to-Line fault, how about an “Antler-to-Antler” fault?
31
Electromechanical Relays
used on Distribution Feeders
Avista’s standard distribution relay
package (until the mid-1990’s) included
the following:
3 phase 50/51 CO-11 relays,
1 reclosing relay
1 ground 50/51 CO-11 relay
.
32
Objectives:
- Protect the feeder conductor
- Detect as low a fault current as
possible (PU = 50% EOL fault amps)
- Other than 51P, set pickup and time
dial as low as possible and still have
minimum Coordinating Time Interval
(CTI) to next device. CTI is minimum
time between operation of adjacent
devices.
- Carry normal maximum load (phase
overcurrent only).
- Pickup the feeder in a cold load
condition ( 2 times maximum normal
load) or pickup ½ of the next feeder
load·
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
.01
.02
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.04
.05
.07
.1
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1
.01
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.04
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.1
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.7
1
TIME-CURRENT CURVES @ Voltage 13.8 KV By
For No.
Comment Date
TRANSFORMER PROTECTION
FEEDER VCB PROTECTION
MAXIMUM FEEDER FUSE
1
1. SMD-2B 65E VERY SLOW 176-19-065Minimum melt. H=8.33
2
2. LAT421 50P CO-9 INST TD=1.000CTR=600/5 Pickup=4.6A No inst. TP@5=0.048s
3
3. LAT421 51P CO-9 CO-9 TD=1.900CTR=600/5 Pickup=4.A No inst. TP@5=0.4618s
4
4. LAT421 50N CO-9 INST TD=1.000CTR=600/5 Pickup=3.A No inst. TP@5=0.048s
5
5. LAT421 51N CO-9 CO-9 TD=3.000CTR=600/5 Pickup=3.A No inst. TP@5=0.7228s
6
6. LAT421 FUSE S&C Link100TTotal clear.
A
A. Transf. damage curve. 7.50 MVA. Category 3Base I=313.78 A. Z= 6.9 percent.Latah Jct 13.8kV - LATAHJCT115 115.kV T
B
B. Conductor damage curve. k=0.08620 A=105500.0 cmilsConductor ACSR AWG Size 1/0
Electromechanical Relays
used on Distribution Feeders
33
13 kV BUS
MIN FAULT3LG = 2000 A1LG = 1000 A
FEEDER SETTINGS51P = 2000 / 2 = 1000 A51N = 1000 / 2 = 500 A
Electromechanical Relays
used on Distribution Feeders
Pickup setting criteria of 2/1 ratio of “end of line” fault duty / pickup
- ensures that the relay will “see” the fault and operate when needed.
34
13 kV BUS
FAULT at MIDLINE3LG = 2000 A1LG = 1000 A
FEEDER SETTINGS51P = 2000 / 2 = 1000 A51N = 1000 / 2 = 500 A
MIN FAULT at END OF LINE3LG = 1000 A1LG = 500 A
MIDLINE SETTINGS51P = 1000 / 2 = 500 A51N = 500 / 2 = 250 A
Electromechanical Relays
used on Distribution Feeders
35
Electromechanical Relays
used on Distribution Feeders
13 kV BUS
500A FEEDER SETTINGS51P = 960 A51N = 480 A
SECTION LOAD = 500 A
36
Electromechanical Relays
used on Distribution Feeders
13 kV BUS
500A FEEDER SETTINGS51P = 960 A51N = 480 A N.O.
SECTION LOAD = 250 A
SECTION LOAD = 500 A
SECTION LOAD = 250 A
37
Most overhead feeders also use reclosing capability to automatically re-energize the feeder
for temporary faults. Most distribution reclosing relays have the capability of providing up to three
or four recloses.
-- Avista uses either one fast or one fast and one time delayed reclose to lockout.
The reclosing relay also provides a reset time generally adjustable from about 10 seconds to
three minutes. This means if we run through the reclosing sequence and trip again within the reset
time, the reclosing relay will lockout and the breaker will have to be closed by manual means. The
time to reset from the lockout position is 3 to 6 seconds for EM reclosing relays.
-- Avista uses reset times ranging from 90 to 180 seconds.
Lockout only for faults within the protected zone. That is; won’t lockout for faults beyond
fuses, line reclosers etc.
Most distribution reclosing relays also have the capability of blocking instantaneous tripping.
-- Avista normally blocks the INST tripping after the first trip to provide for a Fuse Protecting
Scheme.
Electromechanical Relays
used on Distribution Feeders
Reclosing
38
13 kV BUS
RECLOSING SEQUENCE
Closed
Open
0.5" 12" LOCKOUT
RESET = 120"
(INST Blocked during Reset Time)
Electromechanical Relays
used on Distribution Feeders
Reclosing – Sequence shown for a permanent fault
39
Distribution Fusing – Fuse Protection/Saving Scheme
Fault on fused lateral on an overhead feeder:
- Station or midline 51 element back up fuse.
- Station or midline 50 element protects fuse.
During fault:
Trip and clear the fault at the station (or line
recloser) by the instantaneous trip before the fuse
is damaged for a lateral fault.
Reclose the breaker. That way if the fault were
temporary the feeder is completely re-energized
and back to normal.
During the reclose the reclosing relay has to
block the instantaneous trip from tripping again.
That way, if the fault still exists you force the
time delay trip and the fuse will blow before you
trip the feeder again thus isolating the fault and
re-energizing most of the customers.
Of course if the fault were on the main trunk
the breaker will trip to lockout.
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
.01
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1
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1
TIME-CURRENT CURVES @ Voltage 13.8 kVM15 515 51N to 140T By Protection
For Aspen File: HORS M15 EXP.olr No.
Comment Date 3/06
STATION FEEDER RELAYING
MAXIMUM FEEDER FUSE
1
1. M15 515 GND TIME CO-11 TD=4.000CTR=160 Pickup=3.A No inst. TP@5=1.0192s
2
2. Moscow 515 Kear 140T Kearney 140TTotal clear.
3
3. M15 50N CO-11 INST TD=1.000CTR=160 Pickup=3.A No inst. TP@5=0.048s
40
Shows the maximum fault current for which
S&C type T fuses can still be protected by a
recloser/breaker instantaneous trip for
temporary faults (minimum melt curve at 0.1
seconds):
6T – 120 amps
8T – 160 amps
10T – 225 amps
12T – 300 amps
15T – 390 amps
20T – 500 amps
25T – 640 amps
30T – 800 amps
40T – 1040 amps
50T – 1300 amps
65T – 1650 amps
80T – 2050 amps
100T – 2650 amps
140T – 3500 amps
200T – 5500 amps
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
TIME-CURRENT CURVES @ Voltage By
For No.
Comment Date
1
1. BR1 S&C 140T S&C Link140TMinimum melt.
2
2. ENDTAP S&C 40T S&C Link 40TMinimum melt.
3
3. M15 515 S&C 80T S&C Link 80TMinimum melt.
Distribution Fusing – Fuse Protection for Temporary Faults
41
NOTE: These values were taken from the S&C data bulletin 350-170 of March 28, 1988 based on no
preloading and then preloading of the source side fuse link. Preloading is defined as the source side
fuse carrying load amps equal to it’s rating prior to the fault. This means there was prior heating of
that fuse so it doesn’t take as long to blow for a given fault.10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
TIME-CURRENT CURVES @ Voltage By
For No.
Comment Date
1
1. T FUSE S&C Link100TMinimum melt.
2
2. 251 140T FUSE stn S&C Link140TTotal clear.
Distribution Fusing – Fuse to Fuse Coordination
42
Typical continuous and 8 hour emergency rating of the S&C T rated silver fuse links plus the 140T
and 200T.
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
T IME-CURRENT CURVES @ Voltage By
For No.
Comment Date
1
1. BR1 S&C 140T S&C Link140TMinimum melt.
Distribution Fusing – S&C T-Fuse Current Ratings
General Rule: Fuse Blows at 2X Rating in 5 Minutes
43
Typical Coordinating Time Intervals (CTI)
that Avista generally uses between protective
devices.
Other utilities may use different times.
DEVICES: CTI
(Sec.)
Relay – Fuse Total Clear 0.2
Relay – Series Trip Recloser 0.4
Relay – Relayed Line Recloser 0.3
Lo Side Xfmr Relay – Feeder Relay 0.4
Hi Side Xfmr Relay – Feeder Relay 0.4
Xfmr Fuse Min Melt – Feeder Relay 0.4
Coordinating Time Intervals
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
TIME-CURRENT CURVES @ Voltage 13.8 kVHORS 2010 By JDH
For Idaho Rd Feeder 252 in Idaho Rd PHASE 1 2007base.olr No.
Comment At Sub: 3LG=5667A, SLG=5863A, L-L=4909A Date 11-25-2008
TRANSFORMER PROTECTION
STATION VCB 252 PROTECTION
MAXIMUM FEEDER FUSE
HI-SIDE CT'S
MIDLINE OCR
MAXIMUM MIDLINE FUSE
Fault I=5665.9 A
1
1. IDR A-777 51P 351 SEL-VI TD=1.200CTR=600/5 Pickup=2.A No inst. TP@5=0.3096sIa= 679.8A (5.7 sec A) T= 0.78s H=8.33
2
2. IDR 252 51P 351S SEL-EI TD=1.500CTR=800/5 Pickup=6.A No inst. TP@5=0.4072sIa= 5665.9A (35.4 sec A) T= 0.30s
3. IDR 252 50G 351S INST TD=1.000CTR=800/5 Pickup=3.A No inst. TP@5=0.048s3Io= 0.0A (0.0 sec A) T=9999s
4
4. 252 140T FUSE stn S&C Link140TTotal clear.Ia= 5665.9A T= 0.09s
5
5f
5. Phase unit of recloser MID LINE OCR Fast: ME-341-B Mult=0.2 Slow: ME-305-A Add=1000. Ia= 5665.9A T(Fast)= 0.03s
6
6. T FUSE S&C Link 50TMinimum melt.Ia= 5665.9A T= 0.01s
A
A. Conductor damage curve. k=0.06710 A=556000.0 cmilsConductor AACFEEDER 252 SMALLEST CONDUCTOR TO PROTECT
B
B. Transf. damage curve. 12.00 MVA. Category 3Base I=502.00 A. Z= 8.2 percent.IDAHO RD 12/16/20 MVA XFMR
FAULT DESCRIPTION:Bus Fault on: 0 IDR 252 13.8 kV 3LG
44
Typical Coordinating Time Intervals (CTI)
that Avista generally uses between protective
devices.
Other utilities may use different times.
DEVICES: CTI
(Sec.)
Relay – Fuse Total Clear 0.2
Relay – Series Trip Recloser 0.4
Relay – Relayed Line Recloser 0.3
Lo Side Xfmr Relay – Feeder Relay 0.4
Hi Side Xfmr Relay – Feeder Relay 0.4
Xfmr Fuse Min Melt – Feeder Relay 0.4
Coordinating Time Intervals
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
TIME-CURRENT CURVES @ Voltage 13.8 kVHORS 2010 By JDH
For Idaho Rd Feeder 252 in Idaho Rd PHASE 1 2007base.olr No.
Comment At Sub: 3LG=5667A, SLG=5863A, L-L=4909A Date 11-25-2008
TRANSFORMER PROTECTION
STATION VCB 252 PROTECTION
MAXIMUM FEEDER FUSE
HI-SIDE CT'S
MIDLINE OCR
MAXIMUM MIDLINE FUSE
Fault I=5665.9 A
1
1. IDR A-777 51P 351 SEL-VI TD=1.200CTR=600/5 Pickup=2.A No inst. TP@5=0.3096sIa= 679.8A (5.7 sec A) T= 0.78s H=8.33
2
2. IDR 252 51P 351S SEL-EI TD=1.500CTR=800/5 Pickup=6.A No inst. TP@5=0.4072sIa= 5665.9A (35.4 sec A) T= 0.30s
3. IDR 252 50G 351S INST TD=1.000CTR=800/5 Pickup=3.A No inst. TP@5=0.048s3Io= 0.0A (0.0 sec A) T=9999s
4
4. 252 140T FUSE stn S&C Link140TTotal clear.Ia= 5665.9A T= 0.09s
5
5f
5. Phase unit of recloser MID LINE OCR Fast: ME-341-B Mult=0.2 Slow: ME-305-A Add=1000. Ia= 5665.9A T(Fast)= 0.03s
6
6. T FUSE S&C Link 50TMinimum melt.Ia= 5665.9A T= 0.01s
A
A. Conductor damage curve. k=0.06710 A=556000.0 cmilsConductor AACFEEDER 252 SMALLEST CONDUCTOR TO PROTECT
B
B. Transf. damage curve. 12.00 MVA. Category 3Base I=502.00 A. Z= 8.2 percent.IDAHO RD 12/16/20 MVA XFMR
FAULT DESCRIPTION:Bus Fault on: 0 IDR 252 13.8 kV 3LG
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
TIME-CURRENT CURVES @ Voltage 13.8 kVRAT 231 MID C390R By JDH
For Huetter feeder 142 (2008) Rat feeder 231 (2009+) Midline Recloser C390R No.
Comment Saved in: HUE142-RAT231 MID C390R 2007base.olr Date 2-25-08
HUETTER FDR 142 PROTECTION
RATHDRUM FDR 231 PROTECTION
HUE 142 MID C270R PROTECTION
MIDLINE 390R PROTECTION
CALLED "HUE 142 LINE" IN POWERBASE
RECLOSE IS 1SEC, 12SEC, LO, 120 SEC RESET
RECLOSE IS 1SEC, 12 SEC, LO, 180 SEC RESET
LARGEST DOWNSTREAM FUSE FROM 390R MIDLINE
1
1. C390R MID 51P CO-9 CO-9 TD=2.500
CTR=300/5 Pickup=5.A No inst. TP@5=0.6037s
2
2. C390R MID 50P CO-9 INST TD=1.000
CTR=300/5 Pickup=6.A No inst. TP@5=0.048s
3 3. C390R MID 50N CO-9 INST TD=1.000
CTR=300/5 Pickup=5.A No inst. TP@5=0.048s
4
4. C390R MID 51N CO-9 CO-9 TD=2.500
CTR=300/5 Pickup=5.A No inst. TP@5=0.6037s
5
5. HUE 142 50P 251 INST TD=1.000
CTR=160 Pickup=7.A No inst. TP@5=0.048s
6
6. HUE 142 51P 251 SEL-EI TD=1.500
CTR=160 Pickup=6.A No inst. TP@5=0.4072s
7
7. HUE ML C270R 50P INST TD=1.000
CTR=400/5 Pickup=8.1A No inst. TP@5=0.048s
8
8. HUE ML C270R 51P CO-11 TD=1.500
CTR=400/5 Pickup=7.A No inst. TP@5=0.3766s
9
9. HUE 142 50N 251 INST TD=1.000
CTR=160 Pickup=3.A No inst. TP@5=0.048s
10
10. HUE 142 51N 251 SEL-EI TD=4.000
CTR=160 Pickup=3.A No inst. TP@5=1.0858s
11
11. HUE 142 51Q 251 SEL-EI TD=4.000
CTR=160 Pickup=5.2A No inst. TP@5=1.0858s
12
12. HUE ML C270R 50N INST TD=1.000
CTR=400/5 Pickup=3.A No inst. TP@5=0.048s
13
13. HUE ML C270R 51N CO-11 TD=7.000
CTR=400/5 Pickup=3.A No inst. TP@5=1.8052s
14
14. RAT 231 50N CO-11 INST TD=1.000
CTR=800/5 Pickup=3.A No inst. TP@5=0.048s15
15. RAT 231 51N CO-11 CO-11 TD=5.000
CTR=800/5 Pickup=3.A No inst. TP@5=1.3192s
16
16. RAT 231 50P CO-11 INST TD=1.000
CTR=800/5 Pickup=7.A No inst. TP@5=0.048s
17
17. HUE 142 FUSE S&C Link 65T
Total clear.
18
18. RAT 231 FUSE S&C Link100T
Total clear.
19
19. RAT 231 51P CO-11 CO-11 TD=1.800
CTR=800/5 Pickup=6.A No inst. TP@5=0.4533s
A
A. Conductor damage curve. k=0.08620 A=133100.0 cmils
Conductor ACSR AWG Size 2/0
MIDLINE C390 FED FROM RAT 231 - MINIMUM CONDUCTOR TO PROTECT
B
B. Conductor damage curve. k=0.06710 A=556000.0 cmils
Conductor AAC
MIDLINE C390 FED FROM HUE 142 - MINIMUM CONDUCTOR TO PROTECT
45
Typical Coordinating Time Intervals (CTI)
that Avista generally uses between protective
devices.
Other utilities may use different times.
DEVICES: CTI
(Sec.)
Relay – Fuse Total Clear 0.2
Relay – Series Trip Recloser 0.4
Relay – Relayed Line Recloser 0.3
Lo Side Xfmr Relay – Feeder Relay 0.4
Hi Side Xfmr Relay – Feeder Relay 0.4
Xfmr Fuse Min Melt – Feeder Relay 0.4
Coordinating Time Intervals
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
TIME-CURRENT CURVES @ Voltage 13.8 kVIDR FEEDER 251 By JDH
For Idaho Rd Feeder 251 in Idaho Rd PHASE 1 2007base.olr No.
Comment At Sub: 3LG=5667A, SLG=5863A, L-L=4909A Date 11-25-2008
TRANSFORMER PROTECTION
STATION VCB 251 PROTECTION
MAXIMUM FEEDER FUSE
HI-SIDE CT'S
LO-SIDE CT'S
MINIMUM FAULT TO DETECT:3LG=2460A, SLG=1833A, L-L=2130A
1
1. IDR A-777 51P 351 SEL-VI TD=1.200CTR=600/5 Pickup=2.A No inst. TP@5=0.3096s H=8.33
2
2. IDR A-777 51G 351 SEL-VI TD=1.000CTR=600/5 Pickup=1.A No inst. TP@5=0.258s H=8.33
3
3. IDR A-777 51N 351 SEL-EI TD=5.700CTR=1200/5 Pickup=3.A No inst. TP@5=1.5473s
4
4. IDR A-777 51Q 351 SEL-EI TD=4.200CTR=600/5 Pickup=1.3A No inst. TP@5=1.1401s H=8.33
5
5. IDR A-777 51Q 587 W2 SEL-EI TD=4.300CTR=1200/5 Pickup=5.4A No inst. TP@5=1.1672s
6
6. IDR 251 50P 351S INST TD=1.000CTR=800/5 Pickup=7.A No inst. TP@5=0.048s
7
7. IDR 251 51P 351S SEL-EI TD=1.500CTR=800/5 Pickup=6.A No inst. TP@5=0.4072s
8
8. IDR 251 50G 351S INST TD=1.000CTR=800/5 Pickup=3.A No inst. TP@5=0.048s
9
9. IDR 251 51G 351S SEL-EI TD=3.900CTR=800/5 Pickup=3.A No inst. TP@5=1.0587s
10
10. IDR 251 51Q 351S SEL-EI TD=3.500CTR=800/5 Pickup=5.2A No inst. TP@5=0.9501s
11
11. 251 140T FUSE stn S&C Link140TTotal clear.
A
A. Conductor damage curve. k=0.08620 A=133100.0 cmilsConductor ACSR AWG Size 2/0FEEDER 251 SMALLEST CONDUCTOR TO PROTECT
B
B. Transf. damage curve. 12.00 MVA. Category 3Base I=502.00 A. Z= 8.2 percent.IDAHO RD 12/16/20 MVA XFMR
46
Typical Coordinating Time Intervals (CTI)
that Avista generally uses between protective
devices.
Other utilities may use different times.
DEVICES: CTI
(Sec.)
Relay – Fuse Total Clear 0.2
Relay – Series Trip Recloser 0.4
Relay – Relayed Line Recloser 0.3
Lo Side Xfmr Relay – Feeder Relay 0.4
Hi Side Xfmr Relay – Feeder Relay 0.4
Xfmr Fuse Min Melt – Feeder Relay 0.4
Coordinating Time Intervals
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
TIME-CURRENT CURVES @ Voltage 13.8 KV By
For No.
Comment Date
TRANSFORMER PROTECTION
FEEDER VCB PROTECTION
MAXIMUM FEEDER FUSE
1
1. SMD-2B 65E VERY SLOW 176-19-065Minimum melt. H=8.33
2
2. LAT421 50P CO-9 INST TD=1.000CTR=600/5 Pickup=4.6A No inst. TP@5=0.048s
3
3. LAT421 51P CO-9 CO-9 TD=1.900CTR=600/5 Pickup=4.A No inst. TP@5=0.4618s
4
4. LAT421 50N CO-9 INST TD=1.000CTR=600/5 Pickup=3.A No inst. TP@5=0.048s
5
5. LAT421 51N CO-9 CO-9 TD=3.000CTR=600/5 Pickup=3.A No inst. TP@5=0.7228s
6
6. LAT421 FUSE S&C Link100TTotal clear.
A
A. Transf. damage curve. 7.50 MVA. Category 3Base I=313.78 A. Z= 6.9 percent.Latah Jct 13.8kV - LATAHJCT115 115.kV T
B
B. Conductor damage curve. k=0.08620 A=105500.0 cmilsConductor ACSR AWG Size 1/0
47
Typical Coordinating Time Intervals (CTI)
that Avista generally uses between protective
devices.
Other utilities may use different times.
DEVICES: CTI
(Sec.)
Relay – Fuse Total Clear 0.2
Relay – Series Trip Recloser 0.4
Relay – Relayed Line Recloser 0.3
Lo Side Xfmr Relay – Feeder Relay 0.4
Hi Side Xfmr Relay – Feeder Relay 0.4
Xfmr Fuse Min Melt – Feeder Relay 0.4
Coordinating Time Intervals
48
Coordinating Time Intervals
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
2
3
45
7
10
20
30
4050
70
100
200
300
400500
700
1000
2
3
45
7
10
20
30
4050
70
100
200
300
400500
700
1000
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
TIME-CURRENT CURVES @ Voltage 13.8 kV By DLH
For M15 A-172 CS with fdr 515 with Kearney 140T Fuse No.
Comment Three Phase Fault Date 12/12/05
1
1. Moscow 515 Kear 140T Kearney 140TMinimum melt.I= 5158.1A T= 0.10s
2
2. M15-515 Phase Time CO-11 TD=1.500CTR=160 Pickup=6.A No inst. TP@5=0.3766sI= 5158.1A (32.2 sec A) T= 0.33s
3
3. M15 A-172 Phase CO- 9 TD=1.500CTR=120 Pickup=2.A Inst=1200A TP@5=0.3605sI= 619.0A (5.2 sec A) T= 1.03s H=8.33
FAULT DESCRIPTION:Close-In Fault on: 0 MoscowCity#2 13.8kV - 0 BUS1 TAP 13.8kV 1L 3LG
3LG Fault Coordination
Example:
Top – Ckt Swr w/ Phase E-M relay
----- 0.4 sec. ------
Middle - E-M Phase relay for a 500
Amp Feeder
----- 0.2 sec. ------
Bottom – 140T Feeder Fuse (Total
Clear)
49
Coordinating Time Intervals
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
2
3
45
7
10
20
30
4050
70
100
200
300
400500
700
1000
2
3
45
7
10
20
30
4050
70
100
200
300
400500
700
1000
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
TIME-CURRENT CURVES @ Voltage 13.8 kV By DLH
For Moscow CS with fdr 515 with 140T fuses No.
Comment Single Line to Ground Fault Date 12/12/05
1
1. Moscow 515 Kear 140T Kearney 140TMinimum melt.I= 5346.4A T= 0.09s
2
2. M15 515 GND TIME CO-11 TD=4.000CTR=160 Pickup=3.A No inst. TP@5=1.0192sI= 5346.5A (33.4 sec A) T= 0.29s
3
3. M15-515 Phase Time CO-11 TD=1.500CTR=160 Pickup=6.A No inst. TP@5=0.3766sI= 5346.4A (33.4 sec A) T= 0.31s
4 4. M15 A-172 GND TIME CO-11 TD=4.000CTR=240 Pickup=4.A No inst. TP@5=1.0192sI= 5346.5A (22.3 sec A) T= 0.83s
FAULT DESCRIPTION:Close-In Fault on: 0 MoscowCity#2 13.8kV - 0 BUS1 TAP 13.8kV 1L 1LG Type=A
SLG Fault Coordination
Example:
Top – Ckt Swr w/ E-M Phase relay
----- 0.4 sec. ------
Middle - E-M relays (Phase &
Ground) for a 500 Amp Feeder
----- 0.2 sec. ------
Bottom – 140T Feeder Fuse (Total
Clear)
50
Coordinating Time Intervals
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
2
3
45
7
10
20
30
4050
70
100
200
300
400500
700
1000
2
3
45
7
10
20
30
4050
70
100
200
300
400500
700
1000
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
TIME-CURRENT CURVES @ Voltage 13.8 kV By DLH
For Moscow CS A-172 with fdr 515 with 140T Fuse No.
Comment Line to Line Fault Date
1
1. Moscow 515 Kear 140T Kearney 140TMinimum melt.I= 4467.0A T= 0.12s
2
2. M15-515 Phase Time CO-11 TD=1.500CTR=160 Pickup=6.A No inst. TP@5=0.3766sI= 4467.0A (27.9 sec A) T= 0.43s
3
3. M15 A-172 Phase CO- 9 TD=1.500CTR=120 Pickup=2.A Inst=1200A TP@5=0.3605sI= 619.0A (5.2 sec A) T= 1.03s H=8.33
FAULT DESCRIPTION:Close-In Fault on: 0 MoscowCity#2 13.8kV - 0 BUS1 TAP 13.8kV 1L LL Type=B-C
L-L Fault Coordination
Example:
Top – Ckt Swr w/ E-M relay
----- 0.4 sec. ------
Middle - E-M (Phase) relay for a 500
Amp Feeder
----- 0.2 sec. ------
Bottom – 140T Feeder Fuse (Total
Clear)
51
The Final Product10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
2
3
4
5
7
10
20
30
40
50
70
100
200
300
400
500
700
1000
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
TIME-CURRENT CURVES @ Voltage 13.8 kVINT 12F2 & MID 466R By JDH
For Indian Trail feeder 12F2 and 12F2 Midline 466R in INT 2007base.olr No.
Comment AT SUB: 3LG= 5719A, LL=4951A, SLG= 5880A Date 1-29-08
TRANSFORMER PROTECTION
STATION VCB 12F2 PROTECTION
EAST BRANCH - FEEDER MAXIMUM FUSE
FAULT DUTY AT 140T - WHEN FED FROM NORTH (N.O. PT)
12F2 MIDLINE 466R PROTECTION
WEST OR NORTH BRANCH - FEEDER MAXIMUM FUSE
FAULT DUTY AT 150E; 3LG=2318, LL=2008, SLG=1684
3LG=1932, LL=1673, SLG=1388
FAULT DUTY AT 140T - WHEN FED FROM WEST MID 466R 3LG=2093, LL=1813, SLG=1520
9&15
11&4
1
1. INT A-742 51P 351 SEL-VI TD=1.200CTR=600/5 Pickup=2.A No inst. TP@5=0.3096s H=8.33
2
2. INT A-742 51G 351 SEL-VI TD=1.000CTR=600/5 Pickup=1.A No inst. TP@5=0.258s H=8.33
3
3. INT A-742 51N 351 SEL-EI TD=5.600CTR=1200/5 Pickup=3.A No inst. TP@5=1.5201s
4
4. INT A-742 51Q 351 SEL-EI TD=4.200CTR=600/5 Pickup=1.3A No inst. TP@5=1.1401s H=8.33
5
5. INT F2 150E FUSE SMU-20_150ETotal clear.
6
6. INT 12F2 50P 351S INST TD=1.000CTR=800/5 Pickup=7.A No inst. TP@5=0.048s
7
7. INT 12F2 51P 351S SEL-EI TD=1.500CTR=800/5 Pickup=6.A No inst. TP@5=0.4072s
8
8. INT 12F2 50G 351S INST TD=1.000CTR=800/5 Pickup=3.A No inst. TP@5=0.048s
9
9. INT 12F2 51G 351S SEL-EI TD=3.900CTR=800/5 Pickup=3.A No inst. TP@5=1.0587s
10
10. INT 12F2 51Q 351S SEL-EI TD=3.500CTR=800/5 Pickup=5.2A No inst. TP@5=0.9501s
11
11. INT A-742 51Q 587 W2 SEL-EI TD=4.300CTR=1200/5 Pickup=5.4A No inst. TP@5=1.1672s
12
12. F2 MID 466R 50P 351R INST TD=1.000CTR=500/1 Pickup=1.68A No inst. TP@5=0.048s
13
13. F2 MID 466R 51P 351R SEL-EI TD=2.300CTR=500/1 Pickup=1.44A No inst. TP@5=0.6243s
14
14. F2 MID 466R 50G 351R INST TD=1.000CTR=500/1 Pickup=0.89A No inst. TP@5=0.048s
15
15. F2 MID 466R 51G 351R SEL-EI TD=4.200CTR=500/1 Pickup=0.89A No inst. TP@5=1.1401s
16
16. F2 MID 466R 51Q 351R SEL-EI TD=3.800CTR=500/1 Pickup=1.54A No inst. TP@5=1.0315s
17
17. INT F2 140T FUSE stn S&C Link140TTotal clear.
A
A. Transf. damage curve. 12.00 MVA. Category 3Base I=502.00 A. Z= 8.4 percent.INDIAN TRAIL 12/16/20 MVA XFMR
B
B. Conductor damage curve. k=0.14040 A=52630.0 cmilsConductor Copper (bare) AWG Size 2NORTH BRANCH SMALLEST TRUNK CONDUCTOR
C
C. Conductor damage curve. k=0.04704 A=350000.0 cmilsCable XLPE 90C/250CEAST BRANCH SMALLEST TRUNK CONDUCTOR - 350 CN15
D
D. Conductor damage curve. k=0.08620 A=105500.0 cmilsConductor ACSR AWG Size 2/0WEST BRANCH SMALLEST TRUNK CONDUCTOR
An example of a completed 13.8kV
Feeder Coordination Study with 20
Time-Current Curves representing:
Instantaneous & Time-Delay Curves
for the:
- Transformer high side protection,
- Transformer low side protection,
- Station feeder breaker protection,
- Midline feeder breaker protection.
Two Fuses
Transformer Damage Curve
Three Conductor Damage Curves
52
Criteria (for outdoor bus arrangement, not switchgear)
Protect the Transformer from thermal damage
- Refer to Damage Curves
Backup feeder protection (as much as possible)
- Sensitivity is limited because load is higher
Coordinate with downstream devices (feeder relays)
Carry normal maximum load (phase only)
Pick up Cold Load after outages
Distribution Transformer Electromechanical Relays
53
Relays:
3 High Side Phase Overcurrent (with time and instantaneous elements)
1 Low Side Ground Overcurrent (with time and instantaneous elements)
Sudden Pressure Relay
Distribution Transformer
Electromechanical Relays - Setting Criteria
54
Distribution Transformer & Feeder Protection
with Microprocessor Relays
Advantages:
More precise TAP settings
More Relay Elements
Programmable Logic / Buttons
Lower burden to CT
Event Reports!!!!!!!!!
Communications
Coordinate with like elements
(faster)
More Settings
Microprocessor Relay
55
Distribution Transformer & Feeder Protection
with Microprocessor Relays
Elements We Set:
51P
50P
50P2 (FTB)
51G
50G (115kV)
51N (13.8kV)
50N1 (FTB)
FTB = Fast Trip Block (feeder relays must be Microprocessor)
56
Distribution Transformer & Feeder Protection
with Microprocessor Relays
Fast Trip Blocking
Fault
57
Distribution Transformer & Feeder Protection
with Microprocessor Relays
Fast Trip Blocking
Fault
Distribution Transformer
Relay Setting Criteria
Electromechanical Relays
51P Pickup (time overcurrent)
Don’t trip for load or cold load pickup (use
2.4 * highest MVA rating)
Ends up being higher than the feeder phase
element pickup
Example: 12/16/20 MVA unit would use
2.4*20*5 = 240 amps (1940A low side)
51P Time Lever (time dial)
Coordinate with feeder relays for
maximum fault (close in feeder fault)
CTI is 0.4 seconds
Worst coordination case: Ø-Ø on low side
(discrepancy due to delta/wye conn.)
Multiple feeder load can make the
transformer relay operate faster
50P Pickup (instantaneous overcurrent)
Must not trip for feeder faults set at
170% of low side bus fault
Accounts for DC offset
Microprocessor Relays
51P - Phase Time Overcurrent Pickup
Set to 240% of nameplate (same as EM
relay)
51P - Time Dial
Set to coordinate with feeder’s fastest
element for each fault
CTI is still 0.4 seconds
50P1 – Phase instantaneous #1 Pickup
Direct Trip
Set to 130% of max 13.8 kV fault (vs.
170% with EM relay)
50P2 – Phase instantaneous pickup for Fast Trip Block
scheme
Set above transformer inrush
4 Cycle time delay
Blocked if any feeder overcurrent elements are
picked up
58
Phase Overcurrent Settings – Current measured on 115kV side
Electromechanical Relays
51N – Ground Time Overcurrent Pickup
Set to same sensitivity as feeder
phase relay (in case the feeder ground
relay is failed)
This setting is higher than the feeder
ground, so we lose some sensitivity
for backup
51N - Time Lever (time dial)
Coordinate with feeder relays for
ground faults
CTI is 0.4 seconds
50N - Pickup (instantaneous overcurrent)
DO NOT USE!!!!
Microprocessor Relays
51N - Ground Time Overcurrent Pickup
Set slightly higher than feeder
ground pickup (about 1.3 times)
51N - Time Dial
Set to coordinate with feeder
ground
CTI is 0.4 seconds
50N1 – Ground Instantaneous for Fast Trip
Block
Set slightly above the feeder
ground instantaneous pickup
Time Delay by 4 cycles
Blocked if Feeder overcurrent
elements are picked up
59
Phase Overcurrent Settings – Current measured on 13.8kV side
Distribution Transformer
Relay Setting Criteria
60
Transformer Ground Overcurrent Settings - Current calculated from 115kV CTs
51G - Ground Time Overcurrent Pickup
Set very low (will not see low side ground faults due to transformer
connection). Usually 120 Amps.
51GTime Dial
Set very low
50G1 – Ground Instantaneous #1 Pickup
Set very low. Usually 120 Amps.
Distribution Transformer & Feeder Protection
with Microprocessor Relays
Symmetrical
Components!
61
Inrush – The current seen when
energizing a transformer.
Need to account for inrush when using
instantaneous elements (regular or FTB).
Inrush can be approximately 8 times the
nameplate of a transformer.
Note that the microprocessor relay only responds to the 60 HZ fundamental and that this
fundamental portion of inrush current is 60% of the total. So to calculate a setting, we could use
the 8 times rule of thumb along with the 60% value. For a 12/16/20 MVA transformer, the
expected inrush would be 8*12*5*0.6 = 288 amps. We set a little above this number (360 Amps).
Distribution Transformer & Feeder Protection
with Microprocessor Relays
62
Transformer inrush UNFILTERED
current. The peak current is about 1200
amps.
Transformer inrush FILTERED current
(filtered by digital filters to show
basically only 60 HZ).
Distribution Transformer & Feeder Protection
with Microprocessor Relays
63
Transformer inrush UNFILTERED
current. The peak current is about 1200
amps.
Distribution Transformer & Feeder Protection
with Microprocessor Relays
64
Distribution Transformer & Feeder Protection
with Microprocessor Relays
Microprocessor Feeder Relay
Overcurrent
Reclosing
Fast Trip Block Output
Breaker Failure Output
Elements We Set:
51P
50P
51G
50G
51Q
Distribution Transformer & Feeder Protection
with Microprocessor Relays
Feeder Phase Overcurrent Settings
51P - Phase Time Overcurrent Pickup
Set above load and cold load
(960 Amps for 500 Amp
feeder)
Same as EM pickup
51P - Time Dial
Same as EM relay (coordinate
with downstream protection
with CTI)
Select a curve
50P – Phase instantaneous Pickup
Set the same as the 51P pickup
(960 Amps)
Feeder Ground Overcurrent Settings
51G - Phase Time Overcurrent Pickup
Same as EM pickup which is
480 Amps
51G - Time Dial
Same as EM relay (coordinate
with downstream protection)
Select a curve
50G – Phase instantaneous Pickup
Set the same as the 51G
pickup
65
66
Feeder Ground Overcurrent Settings
51G - Phase Time Overcurrent Pickup
Same as EM pickup which is 480 Amps
51G Time Dial
Same as EM relay (coordinate with downstream protection)
Select a curve
50G – Phase instantaneous Pickup
Set the same as the 51G pickup
Distribution Transformer & Feeder Protection
with Microprocessor Relays
67
87R1
87OP
87R2
PRI I
PRI I
SEC I
SEC I
EXTERNAL FAULTTHE SECONDARY CURRENTS FLOW THROUGH BOTHRESTRAINT COILS IN THE SAME DIRECTION AND THENCIRCULATE BACK THROUGH THE CT'S. THEY DO NOTFLOW THROUGH THE OPERATE COIL
CURRENT FLOW THROUGH AN E/M 87 DIFFERENTIAL RELAY FOR AN INTERNAL AND EXTERNAL FAULT
BCT'S
BCT'S
CT POLARITY MARK
Transformer Differential Protection – External Fault
68
87R1
87OP
87R2
PRI I
PRI I
INTERNAL FAULTTHE SECONDARY CURRENTS FLOW THROUGH BOTHRESTRAINT COILS IN OPPOSITE DIRECTIONS, ADD AND THEN FLOW THROUGH THE OPERATE COIL ANDBACK TO THE RESPECTIVE CT'S
SEC I
SEC I
BCT'S
BCT'S
CT POLARITY MARK
Transformer Differential Protection – Internal Fault
69
The differential relay is connected to both the high and low side transformer BCT’s.
EM Differential Relay
Since the distribution transformer is connected delta – wye the transformer CT’s
have to be set wye – delta to compensate for the phase shift.
Transformer Differential Protection
BACK-TO-BACK MIDLINE RECLOSERS COORDINATION
*
Feeder Breaker
Feeder Breaker
Switch
MidlineRecloser
N.C.
70
BACK-TO-BACK MIDLINE RECLOSERS COORDINATION
*
Feeder Breaker
Feeder Breaker
SwitchMidlineRecloser N.O. Tie
MidlineRecloser
N.C.Fwd
Fwd
71
BACK-TO-BACK MIDLINE RECLOSERS COORDINATION
*
Feeder Breaker
Feeder Breaker
SwitchMidlineRecloser Closed Tie
MidlineRecloser
N.C.Fwd
Rev
*
72
BACK-TO-BACK MIDLINE RECLOSERS COORDINATION
*
Feeder Breaker
Feeder Breaker
SwitchMidlineRecloser Closed Tie
MidlineRecloser
T/R/T/R T/R/T-LO
Fwd
Rev
T = Trip
R = Reclose
LO = Lockout
73
RECLOSER/SWITCH FUNCTIONALITY
Substation
R
R R
R
R
FEEDER 1
FEEDER 2
FWD
FWD
FWD
N.O.
N.O.
Z01R
Z02R
Z03R
74
RECLOSER/SWITCH FUNCTIONALITY
Substation
R
R R
R
FEEDER 1
FEEDER 2
FWD
FWD
CLOSED
N.O.
Z01R
Z02R
Z03R
Now Z02R is a
switch 75
76
GRAB YOUR HANDOUT!
MOSCOW FEEDER 515 PROTECTION EXAMPLE
77
The Scenario
A hydraulic midline recloser on a 13.8kV feeder in Moscow, ID is
being replaced by a newer relayed recloser. The recloser is P584
on feeder 515.
The field engineer would like to replace the recloser in the existing
location.
Protection engineer must review the feeder protection and report
back to the field engineer.
NOTE: Avista designs for a “fuse saving” scheme with one
instantaneous trip. The field engineers decide if they want to
enable or disable the instantaneous tripping.
78
MOSCOW FEEDER 515 PROTECTION EXAMPLE
• Where do we start the protection design?
1) Gather Information:
• Feeder Rating (expected load)
• Protective devices (Breakers, line reclosers, fuses)
• Fault Duty (at each protective device)
• Conductors to be protected
• Project deadline (tomorrow?)
79
How do we proceed?
• At each coordination point– Loading
– Coordination• What will coordinate with the downstream device
• Are we above the fuse rating
– Conductor Protection• minimum conductor that can be protected by the feeder settings or
fuse
– Fault Detection• Can we detect the fault by our 2:1 margin
– Fuse Saving for Temporary faults• What can a fuse be protected up to?
80
Begin at the END
• POINT 8: This is a customers load and we are using 3-250 KVA
transformers to serve the load. The full load of this size of bank is 31.4
amps. The Avista transformer fusing standard says to use a 65T on this
transformer so that’s what we’ll choose.
81
FUSE - POINT 6B:
What we know:– 3Ø lateral feeding to a 65T at the end
– #4 ACSR conductor
Fuse Selection:– Loading – Assume the load is all downstream of point 8, so a 65T or higher will
still suffice.
– Conductor Protection - From Table 7 we see that #4 ACSR can be protected by a
100T or smaller fuse
– Fault Detection - Under the Relay Setting Criteria we want to detect the minimum
line end fault with a 2:1 margin. The SLG is 463 so we calculate the max fuse as
follows:
• 463/2 (2:1 margin) = 231 amps. “T” fuses blow at twice their rating so divide
by 2 again, with a result of 115. Fuse must be 100T or less.
– Coordination – From Table 2, we see that we need an 80T or larger to coordinate
with the downstream 65T fuse (at fault duties < 1400A w/preload)
– Fuse Saving - From Table 1 we see that an 80T fuse can be protected up to 2,050
amps for temporary faults and the 3Ø fault is 1,907 amps so we could choose an
80T or higher from that standpoint
82
Point 6B - So what fuse size should we use?
83
POINT 5 – Midline Recloser
• What we know:
– Conductor to protect: #4 ACSR (can carry 140A load)
– Max fuse to coordinate with = 100T (FUTURE per distribution engineer)
– Maximum load (per engineer) = 84A
• Settings Considerations:
– Loading: Cold load would be 84*2 = 168 A, but the conductor can carry 140A max. Size for some
load growth by setting at 2*conductor rating. 300 Amp phase pickup setting.
NOTE: we don’t design settings to protect for overload.
– Conductor Protection: From Table 7, Avista’s 300A feeder settings can protect down to #2 ACSR, so 300A pickup is still acceptable. Review curves to confirm.
– Fault Detection: detect the minimum fault with a 2:1 margin. Here the min fault is at point 6
1. The Ø-Ø fault at point 6 is 0.866*1907 = 1,651 so our margin to detect that fault would be 1651/300
= 5.5:1 so no problem with the 300 amps Ø PU from that standpoint (used Ø-Ø because it’s the
minimum multi phase fault)
2. The SLG at point 6 is 1,492 so we could set the ground up to 1492/2 = 745 amps and still detect the
fault. However, our criteria says to set as low as possible and still coordinate with the largest
downstream device and from above we’re trying to use a 100T. Based on curves, this is 300 amps
(same as phase, which is unusual).
– Coordination: Based on fault study, set the time dial to coordinate with a 100T fuse with 0.2 second
CTI.
– Fuse Saving: The fault duty at the recloser is 3453 3PH and 2762 1LG. An instantaneous trip will
protect the 80T fuse if the fault duty is less than 2050 Amps. Some fuse protection is compromised but
there is nothing we can do about it.
84
TRUNK FUSE - POINT 3C:
What we know:– #4 ACSR 3Ø trunk
– Load is 84 Amps
– Downstream protection is the midline recloser
Fuse Selection:– Loading – Assume the load is the same as at the midline recloser. We set that at
300A, and a 200T can carry 295 A continuous (Table 3).
– Conductor Protection - From Table 7 we see that #4 ACSR can be protected by a
100T or smaller fuse.
– Fault Detection - Under the Relay Setting Criteria we want to detect the minimum
line end fault with a 2:1 margin.
• SLG at midline is 2762 so even a 200T would provide enough sensitivity.
– Coordination – PROBLEM! We have coordinated the midline with
a 100T, so the upstream fuse must coordinate with that.
– Fuse Saving: As before, some fuse saving is compromised due to higher fault duty.
85
TRUNK FUSE Point 3C - Solutions?
86
TRUNK FUSE Point 3C - Solutions?
• Move Recloser
• Re-conductor
87
FEEDER BREAKER - POINT 1:
What we know:– This is a 500 amp feeder design. The load is 325 amps and cold load 650 per field engineer.
– Downstream protection is either the midline recloser or a 140T fuse.
Settings Considerations: Loading: A standard 500 amp feeder phase pickup setting of 960 A will carry all normal
load and pick up cold load. The ground pickup does not consider load and will be set at
480A.
Conductor Protection : The main trunk is 556 ACSR and from Table 7 a 500 amp feeder
setting of 960 A can protect 1/0 ACSR or higher. Laterals with smaller conductor must be
fused.
Fault Detection:
The Ø-Ø fault at point 5 is 0.866*3453 = 2990 so our margin to detect that fault would
be 2990/960 = 3.1:1
The SLG at point 5 is 2,762 so our margin to detect that fault is: 2762/480 = 5.7:1
Coordination: Use fault study to calculate settings to achieve 0.2 second CTI to fuses and
0.3 second CTI to the recloser.
Fuse Saving – We have decided that a 140T fuse is the maximum fuse we will use on the
feeder even though it can’t be saved by an instantaneous trip at the maximum fault duties.
88
Questions?