Line Protection.pdf

Protection Coordination
Serge Beauzile
Chair IEEE FWCS
Ch i P & E S i t
Chair Power & Energy Society
serge.beauzile@ieee.org
June 10 2014
June, 10, 2014
8:30 -12:30
Florida Electric Cooperatives Association
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
– Distance Protection
– Pilot Protection Schemes
– Current Differential Protection
Current Differential Protection
2
IEEE/ FECA Protection Coordination June 2014 Serge Beauzile

Art & Science of System Protection
• Not an exact science, coordination
schemes will vary based on:
schemes will vary based on:
– Company Philosophy
Company Philosophy
– Protection engineer preference
– System requirements
3

C di ti D i
Coordinating Devices
Basic concept: All protective devices are able to
Basic concept: All protective devices are able to
detect a fault do so at the same instant.
If h d i th t d f lt t d
If each device that sensed a fault operated
simultaneously, large portions of the system
would be de-energized every time a fault needed
g y
to be cleared. This is unacceptable.
A properly designed scheme will incorporate time
A properly designed scheme will incorporate time
delays into the protection system, allowing
certain devices to operate before others.
4

C di ti D i
Timing of device operation is verified using time
Timing of device operation is verified using time-
current characteristics or TCCs – device
response curves plotted on log-log graph paper.
Devices have inverse TCCs. They operate quickly for
large magnitude overcurrents, and more slowly
g g , y
for lower-magnitude overcurrents.
Operating time is plotted on the vertical axis and
Operating time is plotted on the vertical axis, and
current magnitude is plotted on the horizontal
scale.
5

C di ti D i
100
Four different TCCs
h th
10
are shown on the
left. Device “D” is
the fastest to
1
Time
in
Seconds
operate, and device
“A” is the slowest.
25
0.1
A
B
C
D
For a given current
value, the operating
ti b f d
.25 sec 10,000
1000
10
100
0.01
100,000
D
time can be found.
3 kA
Current in Amperes
6

g
In this example,
A l l
100
Device A is clearly
faster than Device B
for low (400-700 A)
10
Uncertain
Coordination
( )
fault currents.
Device B is clearly
Time
in
Seconds
1
Device B is clearly
faster for high
(>1000 A) fault
t b t i th
0.1
A
currents, but in the
700-1000 A region,
timing is uncertain.
100
10
0.01
100,000
10,000
1000
B
g
1
Current in Amperes
7

Expulsion Fuse to Expulsion Fuse
100
Minimum Melt
10
Average Melt + tolerance
1
Time
in
Seconds
Total Clear
0.1
Average Melt + tolerance
+ arcing time
Curves are developed at 25ºC
100
10
1000
00,000
0,000
0.01
Curves are developed at 25ºC
With no preloading
10
1
Current in Amperes
8

100
In this example, the red
10
TCCs represent the
downstream (protecting)
fuse, and the blue TCCs
1
Time
in
Seconds
represent the upstream
(protected) fuse.
0.1
The protected fuse
should not be damaged
by a fault in the
100
10
1000
,000
,000
0.01
y
protecting fuse’s zone of
protection.
1
100,
10,
Current in Amperes
9

100
Four factors need to be
10
considered:
1. Tolerances.
1
Time
in
Seconds
2. Ambient
temperature.
0.1
p
3. Preloading effects.
100
10
1000
0,000
0,000
0.01
4. Predamage effects.
1
100
10
Current in Amperes
10

100
Consideration of these
10
four factors can be
quite involved.
1
Time
in
Seconds
Practically, the “75%
Method” can be used:
the maximum clearing
0.1
g
time of the protecting
link shall be no more
than 75% of the
100
10
1000
,000
,000
0.01
minimum melting time
of the protected link.
1
100
10
Current in Amperes
11

100
Minimum melting time of
10
protected link at 5 kA is
0.3 seconds.
1
Time
in
Seconds
Total clearing time of the
protecting link at 5 kA is
0.22 seconds.
0.1
0.22 < 0.3 × 75% = 0.225,
so coordination is
100
10
1000
0,000
0,000
0.01
assured for current
magnitudes ≤ 5 kA.
100
10
Current in Amperes
12

Utility Distribution Feeders
y
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
separated from the rest of the feeder.
Segments are delineated by reclosers, fuses,
sectionalizers or switches
sectionalizers or switches.
Two primary concerns: number of customers per
d l
segment and time to isolate segment.
13

y
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 can also be adversely impacted, and
y y p
construction cost will increase.
A ti i t t b ht t d t i th
An optimum point must be sought to determine the
best segment size.
14

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.
coordination due changes in the load.
It is impossible to predict everything, so versatility is
the key.
15

Coordination Goal
1. Maximum Sensitivity.
2. Maximum Speed.
3. Maximum Security.
4. Maximum Selectivity.
16

Basic Coordination Strategy
gy
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
current of all instantaneous
overcurrent devices, based
on short-circuit studies.
4 D t i i i
4. Determine remaining
overcurrent device
characteristics starting
from the load and moving to
g
the source.
17

18

19

20

21

22

Fuse Peak Load Capability
IEEE/ FECA Protection Coordination June 2014 Serge Beauzile 23

24

25

26

27

28

Fuse Blow Vs. Fuse Save
Fuse Blow Vs. Fuse Save
• Fuse Blow
– Eliminates Instantaneous trip of the breaker or recloser
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
Minimizes momentary interruptions and increases SAIDI.
Improves power quality but decreases reliability.
• Fuse Save
• 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.
29

Fuse Blow
FUSE is BLOWN
Lateral experiences
Lateral experiences
sustained interruption
30

Fuse Blow
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
31

Fuse Save
Entire Feeder trips
Momentary occurs
FUSE is SAVED
FUSE is SAVED
32

Fuse Save
Fuse Save
– Minimize customer interruption time
Reduce SAIDI
– Reduce SAIDI
– Increase MAIFI
– May not work in high short circuit areas
– May not work in high short circuit areas
– Work well in most areas
– Not suitable for certain industrial
Not suitable for certain industrial
customers that cannot tolerate immediate
reclosing
– Works best for residential and small
commercial customers
33

Both (Fuse Save & Fuse Blow)
( )
• Many utilities use both schemes for a variety of
reasons
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 rural and Fuse Blow on urban
– Fuse Save on stormy days and Fuse Blow on nice
days.
F S i it d F Bl
– Fuse Save on some circuits and Fuse Blow on
others depending on customer desires
34

Fast Bus Trip
IEEE/ FECA Protection Coordination June 2014 Serge Beauzile 35

SEL-351S
SEL 351S
Protection and Breaker Control
Relay
Relay
36

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
37

SEL-351S
Protection Features:
P f t l t 18 diff t t ti f ti
Performs at least 18 different protection functions.
=
38

SEL-351S
Protection Features:
B U d lt (27)
Bus Undervoltage (27)
Phase Overvoltage (59P)
G d O lt (59G)
Ground Overvoltage (59G)
Sequence Overvoltage (59Q)
O f (81O)
Overfrequency (81O)
Underfrequency (81U)
39

Modern Microprocessor Relay
Protection Features (continued):
Ph Di ti l O t (67P)
Phase Directional Overcurrent (67P)
Ground Directional Overcurrent (67G)
S Di ti l O t (67Q)
Sequence Directional Overcurrent (67Q)
Instantaneous Phase Overcurrent (50P)
I t t G d O t (50G)
Instantaneous Ground Overcurrent (50G)
Instantaneous Sequence Overcurrent
(50Q)
(50Q)
40

SEL-351S
Protection Features (continued):
Ti Ph O t (51P)
Time Phase Overcurrent (51P)
Time Ground Overcurrent (51G)
Ti S O t (51Q)
Time Sequence Overcurrent (51Q)
Directional Neutral Overcurrent (67N)
I t t N t l O t (50N)
Instantaneous Neutral Overcurrent (50N)
Time Neutral Overcurrent (51N)
41

SEL-351S
Breaker Control Features:
S h i Ch k (25)
Synchronism Check (25)
Automatic Circuit Reclosing (79)
TRIP/CLOSE Pushbuttons
Enable/Disable Reclosing
Enable/Disable Reclosing
Enable/Disable Supervisory Control
42

SEL-351S
Other Features:
E t R ti d R di
Event Reporting and Recording
Breaker Wear Monitor
St ti B tt M it
Station Battery Monitor
High-Accuracy Metering
F lt L t
Fault Locator
43

SEL-351S
44

• Advantages of microprocessor relays
• Advantages of microprocessor relays
ƒ Extremely flexible
ƒ Have many different elements (UF, UV, Directionality, etc…)
ƒ One relay can protect on zone of protection
One relay can protect on zone of protection
ƒ Inexpensive and require much less maintenance
ƒ Alarm if they fails and don’t need calibration
ƒ Provide fault information
ƒ Provide oscillography and SER data
ƒ Can provide analog data to SCADA
• Disadvantages of microprocessor relays
ƒ Can be very complex to program due to given flexibility
R i t i i t R l T h i i
ƒ Require more training to Relay Technicians
ƒ Require more training to Relay Engineers
45

Relays
Relays
• Basic relay settings:
ƒ Phase overcurrent elements must be set above maximum
ƒ Phase overcurrent elements must be set above maximum
possible loads
ƒ Ground overcurrent elements must be set above maximum
anticipated unbalanced loads
p
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 attempts
g p
ƒ WORK mode – HOT LINE TAG
ƒ COLD mode
46

Relay Curves
Relay Curves
100
10
1
S
e
c
o
n
d
Moderately Inverse
Inverse
Very Inverse
0.1
d
s
Very Inverse
Extremely Inverse
0.01
0.1 1 10 100
Multiple of Pick Up
Multiple of Pick Up
47

Very Inverse Curve Time Dial
100
0.29s
In this example
10
p
Multiple of Pickup = 3.
TD = 0 5 Time = 0 3s
1
SECONDS
TD=0.5
TD=2
TD=6
TD = 0.5 Time = 0.3s
TD = 2 Time = 1.1s
TD = 6 Time = 3.4s
TD = 15 Time = 7.0s
0.1
TD 6
TD=15
0.01
0.1 1 10 100
Multiples Of Pick Up
48

100
0.29s In this example,
Pi k 600 A
10
Pickup = 600 A.
Fault Current = 1800 A.
TD = 0.5 Time = 0.29s
1
SECONDS
TD=0.5
TD=2
TD=6
T 0.5 Time 0. 9s
TD = 2 Time = 1.16s
TD = 6 Time = 3.48s
TD = 15 Time = 8.72s
0.1
TD 6
TD=15
Pickup = 900 A.
Fault Current = 1800 A.
0.01
0.1 1 10 100
TD = 0.5 Time = 0.69s
TD = 2 Time = 2.78s
TD = 6 Time = 8.33s
TD = 15 Time = 20 8s
Multiples Of Pick Up TD = 15 Time = 20.8s
49

Pickup Current of Delayed Ground OC Devices
p y
Source Side Load Side
Single Phase to Ground Fault
Primary
Backup
IMU<IPU<I MIN Fault
g
IMU = Maximum Unbalance
50

Pickup Current of Delayed Phase OC Devices
p y
Source Side Load Side
IML<IPU<Imin Ø‐Ø Fault Phase to Phase Fault
IML = Maximum Load
51

Typical Pickup Setting
TB > TR + CTI CTI = Coordination Time Interval (Typically 0.2-0.5sec)
Recloser Ct ratio 600:1 Breaker Ct ratio 240:1
IPU = 1 A IPU = 3.75 A
IPU Primary= 600 A IPU Primary= 900 A
52

53

Trip Logic
TR OC + PB9 + 51P1T + 51G1T * (LT6 + LT7) + (50P3 + 50G3) * LT7 + (50P2 + 50G2) * SH1
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 (960 AMPS PRIMARY)
50G2P 1.6 (960 AMPS PRIMARY)
INSTANTANEOUS ENABLED ONLY DURING WORK/HOT LINE TAG
50P3P = 1.35 (810 AMPS PRIMARY)
50G3P = 0 50 (300 AMPS PRIMARY) NORMAL UNBALANCE GROUND CURRENT ~20 TO 30 AMPS
50G3P = 0.50 (300 AMPS PRIMARY) – NORMAL UNBALANCE GROUND CURRENT ~20 TO 30 AMPS
54

55

56

57

SEL-351S
History Summary (HIS Command)
Sample output:
58

SEL-351S
Sequence of Events Recording (SER)
Sequence of Events Recording (SER)
59

SEL-351S
Metering Data (MET Command)
Sample output - Metering Data (MET):
60

SEL-351S
Sample output - Metering Demand (MET D):
61

SEL-351S
Sample output - Metering Energy (MET E):
62

SEL-351S
Sample output - Metering Max/Min (MET M):
63

Differential Relays
Protection of a Delta‐Wye Transformer
I
I I
I I
A
B
a
b
Ia
52
52
Ib
Ia‐Ib Ia
Ia
Ia‐Ib
Ib‐Ic
Ia‐Ib
Ib‐Ic
Ia
B
C
b
c
52
52
Ic
Ib‐Ic
Ic‐Ia
Ib
Ic
Ib
Ic
Ic‐Ia
Ic‐Ia
Ib
Ic
Ia‐Ib
Ia‐Ib
R R
OP
OP
Ia‐Ib
I I
Ic‐Ia
Ib‐Ic
R
R
R
R
OP
OP Ic‐Ia
Ib‐Ic
Ib‐Ic
Ic‐Ia
Power System Protection -64- Ralph Fehr, Ph.D., P.E. – October 28, 2013
R R

Distance Relays
y
Protection Features
– Four zones of distance protection
– Pilot schemes
– Phase/Neutral/Ground TOCs
Phase/Neutral/Ground IOCs
– Phase/Neutral/Ground IOCs

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

Distance Relays
Control Features
Control Features
B k F il ( h / t l )
– Breaker Failure (phase/neutral amps)
– Synchrocheck
– Autoreclosing

Distance Relays
Metering Features
Metering Features
F lt L t
− Fault Locator
− Oscillography
− Event Recorder
− Data Logger
− Phasors / true RMS / active, reactive
and apparent power, power factor
and apparent power, power factor

Distance Relays
Zones of Protection Zone 2
X
Line Impedance (Line A)
Zone 1
Zone 2
1
2
3
Line Impedance (Line A)
Zone 2
Z 3
1
2
3
1
Line A
A1 A2
Zone 1
Zone 3 3
4
1
2
Bus 1 Bus 2
Normal Load
Distance Relay
at Bus 1
R
Zone 1 – fastest (80% of line)
2 Normal Load
to protect Line A
Zone 3
Zone 2 – slower (120% of line)
Zone 3 –(backwards Use in Pilot
Protection for current
4
Reversal logic)

Zone 3
Zone 2 Zone 2
Zone of Protection
∆t
Zone 1 Zone 1
Zone 2
∆t
∆t
∆t
1 2 4
3
Zone 1
Zone 1 Zone 1
Zone 3
Zone 2
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.
Z 2 O h th t li d T i ll 1 2 Z
Zone 2: Over reaches the remote line end Typically 1.2 Z1L
with definite time delay.
Zone 3: Over reaches the longest adjacent line
i h d fi i i d l h Z 2
with definite time delay greater than Zone2.
70

Unconventional Zone 2 & Zone 3 Settings
Zone 2
Zone 1
Zone 2
∆t
Long Line Short Line
Be Mindful when Applying General Rules
71

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 PTR = 600:1
CTR 1200:5 or 240:1 PTR 600:1
72

Distance Relay Coordination Exercise
Circuit 2 & Circuit 5 Impedances Circuit 3 & Circuit 6 Impedances
Z1 = 35.11 83.97˚ Ω primary
Z0 = 111.58 81.46˚ Ω primary
Z1 = 17.56 83.72˚ 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
73

Distance Relay Coordination Exercise
Zone 1 Reach = 0.8 * (35.11 83.97˚) Ω primary Zone 1 Reach = 28.09 83.97˚) Ω primary
Z 2 R h 1 2 * (35 11 83 97˚) Ω i Z 2 R h 42 13 83 97˚) Ω i
Zone 2 Reach = 1.2 * (35.11 83.97˚) Ω primary
Check Zone 2 reach does not overreach = Circuit 2 Impedance + (Zone 1 of Circuit 3) or (Zone 1of Circuit 6).
General rule = protected Circuit Impedance + Zone 1 of the Shortest Circuit past the protected circuit.
Zone 2 Reach = 42.13 83.97˚) Ω primary
p p p p
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 = 52.55 83.35˚) Ω primary
Zone 4 Reach = (35.11 83.97˚) + (17.56 83.72˚) ( Ω primary)
74

Primary / Secondary Impedance
Relay Input
75

Relay Input
Zone 1 Reach = 28.09 Ω x 240 = 11.24 Ω secondary
600
600
600
76

Overcurrent Supervision Setting Criteria
1) Find the lowest Ø – Ø fault seen by relay 3
for a remote end bus (4 10 5 11)
Set above (maximum load) and 60% of min fault.
Zone 1 Phase Fault detector:
for a remote end bus (4, 10, 5, 11).
Zone 2 Phase Fault detector:
Set above (maximum load) and 60% of min fault.
1) Find the lowest Ø – Ø fault seen by relay 3
for a remote end bus (6, 12).
( , )
Zone 4 Fault detector same as Zone 2
Repeat same process for Ground Fault detector.
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
I L
Apparent Impedance = ( IL x ZL) + (IR x ZR)
IL
Apparent Impedance = 4Ω
78

Thank You
Thank You
79

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