Protection Coordination
Serge Beauzile
Chair IEEE FWCS
Ch i Power
Chair
P
&E
Energy S
Society
i t
serge.beauzile@ieee.org
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
IEEE/ FECA Protection Coordination
June 2014
Serge Beauzile
2
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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June 2014
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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
June 2014
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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.
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June 2014
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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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June 2014
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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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June 2014
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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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June 2014
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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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June 2014
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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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June 2014
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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
IEEE/ FECA Protection Coordination
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
IEEE/ FECA Protection Coordination
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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June 2014
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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.
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June 2014
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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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June 2014
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Coordination Goal
IEEE/ FECA Protection Coordination
1.
Maximum Sensitivity.
2.
Maximum Speed.
3.
Maximum Security.
4.
Maximum Selectivity.
June 2014
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Basic Coordination Strategy
gy
IEEE/ FECA Protection Coordination
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
June 2014
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Fuse Blow
FUSE is BLOWN
Lateral experiences
sustained interruption
30
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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June 2014
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Fuse Save
Entire Feeder trips
Momentary occurs
FUSE is SAVED
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June 2014
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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
June 2014
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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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June 2014
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Fast Bus Trip
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June 2014
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SEL-351S
SEL
351S
Protection and Breaker Control
Relay
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June 2014
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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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June 2014
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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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June 2014
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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)
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June 2014
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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)
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June 2014
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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)
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June 2014
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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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June 2014
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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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June 2014
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SEL-351S
Protection and Breaker Control Relay
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June 2014
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• Advantages of microprocessor relays
ƒ
ƒ
ƒ
ƒ
ƒ
ƒ
ƒ
ƒ
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
ƒ Can be very complex to program due to given flexibility
ƒ Require
R
i more training
t i i to
t Relay
R l T
Technicians
h i i
ƒ Require more training to Relay Engineers
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June 2014
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Relays
• Basic relay settings:
ƒ Phase overcurrent elements must be set above maximum
possible loads
ƒ Ground overcurrent elements must be set above maximum
anticipated
p
unbalanced loads
ƒ Must be coordinated with downstream protective devices
ƒ Under Frequency elements must be set according to the
predetermined set point
• TAGGING
ƒ NORMAL mode – 2 reclosing
g attempts
p
ƒ WORK mode – HOT LINE TAG
ƒ COLD mode
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June 2014
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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
IEEE/ FECA Protection Coordination
100
June 2014
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47
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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June 2014
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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
IEEE/ FECA Protection Coordination
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<IPU<I MIN Fault
IMU = Maximum Unbalance
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June 2014
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Pickup
p Current of Delayed
y Phase OC Devices
Source Side
IML<IPU<Imin Ø‐Ø Fault
Load Side
Phase to Phase Fault
IML = Maximum Load
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June 2014
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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
IEEE/ FECA Protection Coordination
Breaker Ct ratio 240:1
IPU = 3.75 A
IPU Primary= 900 A
June 2014
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June 2014
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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
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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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June 2014
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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
-67-
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
-68-
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
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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
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PTR = 600:1
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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
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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
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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
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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
June 2014
Serge Beauzile
77
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
IEEE/ FECA Protection Coordination
Apparent Impedance = 4Ω
June 2014
Serge Beauzile
78
Thank You
IEEE/ FECA Protection Coordination
June 2014
Serge Beauzile
79