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8/12/2019 Feeder Protection Fundamentals
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Relion. Thinking beyond the box.
Designed to seamlessly consolidate functions, Relion relays aresmarter, more flexible and more adaptable. Easy to integrate andwith an extensive function library, the Relion family of protectionand control delivers advanced functionality and improved
performance.
This webinar brought to you by the Relion® product family Advanced protection and control IEDs from ABB
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ABB is pleased to provide you with technical information regarding
protective relays. The material included is not intended to be a complete
presentation of all potential problems and solutions related to this topic.
The content is generic and may not be applicable for circumstances or
equipment at any specific facility. By participating in ABB's web-based
Protective Relay School, you agree that ABB is providing this information
to you on an informational basis only and makes no warranties,
representations or guarantees as to the efficacy or commercial utility of
the information for any specific application or purpose, and ABB is not
responsible for any action taken in reliance on the information contained
herein. ABB consultants and service representatives are available to
study specific operations and make recommendations on improving
safety, efficiency and profitability. Contact an ABB sales representative
for further information.
ABB Protective Relay School Webinar Series
Disclaimer
October 29, 2013
l Slide 2
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Feeder Protection FundamentalsTim ErwinOctober 29, 2013
ABB Pro tective Relay School Webinar Ser ies
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Topics
System Overview
Why is feeder protection necessary
The Protection team
Fuses
Breakers/reclosers
Relays
CT’s
Characteristics of protective devices
● Fuses
● Circuit breakers, relays and reclosers
Principles of feeder coordination
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15 kV
62%
25 kV
20%
35 kV
12%
5 kV
6%
Distribution System Voltage Class
Trend to larger nominal voltage class
Increasing load density
Lower cost of higher voltageequipment
Percent of Distribution Systems at
the Nominal voltage Class
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WHY IS FEEDER PROTECTIONNECESSARY?
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City Lights
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Lightning
© ABB GroupOctober 29, 2013 | Slide 8
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Blackout
© ABB GroupOctober 29, 2013 | Slide 9
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Transmission Line Tower Flashover
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Transformer Failure
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Generator Failure
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Overhead Distribution Feeder Faults
Temporary (non-persistent) – 85%
● Lightning causing flashover
● Wind blowing tree branches into line(s)
Permanent (persistent) – 15%
● Broken insulator
● Fallen tree
● Automobile accident involving utility pole
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Feeder Circuit
Breaker in protective zone
Breakers controlled by protective relays
Reclosers
Sectionalizers
Lateral Tapped Fuses
Transformer Primary Rural – primary fuses
Urban – breaker or circuit switch
B R
Relay
Fuse
Recloser Sectionalizer
Relay
Typical Distribution Substation Feeder Circuit
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Function of
● Substation transformersize (source impedance)
● Distribution voltage
● Fault location
10kA - majority
10-20kA - moderatenumber
20kA - few
TransformerSecondary
End ofLine
Fault Current Vs. Distance to Fault onthe Feeder
Fault Current Levels
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Protection to be applied based on exposure
Higher voltage feeders tend to be longer with moreexposure to faults
Apply downline devices . . . reclosers, fuses, based
typically on 3 to 5 MVA of load per segment
Application
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Feeder protection consists
of a team of coordinated devices: Fuses
Breakers/Reclosers
• Relay(s)
• The sensors
– PTs – CTs
– Etc.
The interconnection
The Protection Team
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Distribution Protection
Required characteristics of protective devices are:
Sensitivity – responsive to fault conditions
Reliability - operate when required (dependability) andno-operation when not required (security)
Selectivity –isolate minimum amount of system andinterrupt service to fewest customers
Speed – minimize system and apparatus damage
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Reliability
DEPENDABILITY SECURITY
The certainty ofcorrect operationin response tosystem trouble.
The ability of thesystem to avoid
undesiredoperations with or
without faults.
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Reliability
DEPENDABILITY SECURITY
The certainty of operation
in response to systemtrouble
The ability of the system
to avoid misoperationwith or without faults
Main 2
Main1
Main 1
Main2
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“Zone Protection” Generator
Transformer
Bus
Transmission Lines
Motors
General Relaying Philosophy
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Zones of Protection
Station A
Station B
Station C
Station D
G
G
G
M
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Zones of Protection
Station A
Station B
Station C
Station D
G
G
G
M
Generator
Protection
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Zones of Protection
Station A
Station B
Station C
Station D
G
G
G
M
Transformer
Protection
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Zones of Protection
Station A
Station B
Station C
Station D
G
G
G
M
Bus
Protection
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Zones of Protection
Station A
Station B
Station C
Station D
G
G
G
M
Line
Protection
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Zones of Protection
Station A
Station B
Station C
Station D
G
G
G
M
Motor/Feeder
Protection
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Distribution Fuses
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Typical Distribution Substation Feeder Circuit:Fuses
B R
Relay
Fuse
Recloser Sectionalizer
Relay
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Continuous current rating
Interruption rating
Curve characteristics
Minimum melt
Total clearing
Distribution Fuses
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Fuse Characteristic
Amperes
10
0.1
T i m e i n S e c
o n d s
1.0
10
100
1000
100 1000 10000
Minimum Melt(Response Time)
Total Clearing(Interruption Time)
Arc Clearing
Fuse melting time(damage)
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K link
T link (slower clearingat high current)
Common low currentclearing time based onfuse rating
300 sec <=100 A rating
600 sec > 100 Arating
Distribution Fuses - Expulsion
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Distribution Fuses – Current Limiting
General purpose
Rated maximum interruptingdown to current that causesmelting in one hour
Melting - 150% to 200%
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Distribution Fuses – Current Limiting
Backup
Rated maximum interruptingdown to rated minimuminterrupting
Requires application withexpulsion fuse for low current
protection
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Fuse Coordination - Rule of Thumb
Amperes
10
0.1
T i m e i n S e c
o n d s
1.0
10
100
1000
100 1000 10000
Minimum Melt(Response Time)
Total Clearing(Interruption Time)
Upstream
Downstream
Maximum clearing time of
downstream fuse should beless than 75% of minimummelt time of upstream fuse(device)
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Line terminal
MountingBracket
PorcelainHousing
HousingDoorFuse Tube
Mounted InsideHousing Door
Enclosed Open Link
Line terminal
Line terminal
Silicon/PolymerSupport
FuseHolder
MountingBracket
Fused Cutout
Arc Arrester
Open LinkFuse Link
Line terminal
Line terminal
SpringContacts
Silicon/PolymerSupport
MountingBracket
Fused Cutouts
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Typical Distribution Substation Feeder Circuit:Breakers and Reclosers
B R
Relay
Fuse
Recloser Sectionalizer
Relay
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Distribution Circuit Breaker / Recloser
Interruption medium
Oil
Vacuum under oil
Vacuum
Operating mechanism Electromechanical (spring charging)
Magnetic actuator
Fault sensing and control
Electromechanical Solid state
Microprocessor
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Operating Mechanisms: ESV (spring charge) vs. OVR
Spring charged mechanism
Over 300 total parts Many moving parts
2000 Operation
Three phase operation only
Magnetic actuator
One moving part No maintenance
10,000 Operation
Single and three phase
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Oil Reclosers vs. Solid Dielectric
Oil
Lower interrupting ratings
Clearing time / coordination can varydepending on temperature andcondition of oil
Reclosing must be delayed on older
units without vacuum bottles to allow forout gassing
2000 Operations or less
Requires 5 – 7 year maintenanceschedule
Magnetic Actuation, Solid
Dielectric High fault interrupting capability
High load current rating
One size fits all amp rating(interchangeability)
Low maintenance costs Environmentally friendly
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Medium Voltage Vacuum Breakers
15kV/27kVBreaker
● Single Bottle design● 15kV & 27kV
● Stored Energy or magnetic
Mechanism
38 KV Breaker
● 38kV
● Two bottle per phase design
● Stored Energy or Magnetic
Mechanism
Vacuum Interruption Definite purpose rated – ANSI C37.06 – 2000
Table 2A
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MV Breaker Ratings
Type V two bottle design allows for back-to-back capacitor
switching up to 1200 A
Type X R-MAG Type R R-MAG Type V
Voltage , kV 15 15 27 27 38
Continuous
Current, A
600 / 1200 /
2000 / 3000
600 / 1200 /
2000 / 30001200 / 2000 1200 / 2000 1200 / 2000
Interrupting, kA 12 - 25 12 - 25 12 - 20 12 - 25 25 - 40
BIL 110 110 125 - 150 125 - 150 150 - 200
BIL (Basic Impulse Level): Impulse withstand voltage
A i R l
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Automatic Recloser
Improve reliability of service
Pole-top mounting - eliminates need to buildsubstation
Three-phase unit can replace breaker in substationfor lower current ratings
Three Phase
Single Phase
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Breakers and Reclosers provide the physical interruption
Both require a protective relay to signal when to operate
© ABB Group
October 29, 2013 | Slide 46
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Distribution Circuit Protective Relays
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WHAT ISRELAYING
R l
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Relays
Relays are electromechanical, solid-state (static) or
microprocessor-based (digital/numerical) devices that are
used throughout the power system to detect abnormal and
unsafe conditions and take corrective action
© ABB Group
October 29, 2013 | Slide 49
Cl ifi ti f R l D fi d i IEEE C37 90
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Classification of Relays - Defined in IEEE C37.90
Classification by Function Protective - Detects intolerable conditions and defective apparatus. Monitoring - Verify conditions in the protection and/or power
system.
Reclosing - Establish closing sequences for a circuit breakerfollowing a protective relay trip.
Regulating - Operates to maintain operating parameters within adefined region.
Auxiliary - Operates in response to other [relay] actions to provideadditional functionality
Synchronizing - Assures that proper conditions exist forinterconnecting two sections of the power system.
Cl ifi ti f R l
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Classification of Relays
Classification by Input
Current (Generator, Motor, Transformer, Feeder)
Voltage (Generator, Motor, Transformer, Feeder)
Power (Generator, Motor, Transformer, Feeder)
Frequency (Generator, Motor, Feeder)
Temperature (Generator, Motor, Transformer) Pressure (Transformer)
Flow (Generator, Motor, Transformer, Feeder)
Vibration (Generator, Motor)
Cl ifi ti f R l
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Classification of Relays
Classification by Performance Characteristics
Overcurrent
Over/under voltage
Distance
Directional Inverse time, definite time
Ground/phase
High or slow speed
Current differential
Phase comparison Directional comparison
Classification of Relays
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Classification of Relays
Classification by Technology Electromechanical Solid state (Static)
Microprocessor-based (Digital/Numerical)
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© ABB GroupOctober 29, 2013 | Slide 54
Relay Input Sources
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Typical Distribution Substation Feeder Circuit
B R
Relay
Fuse
Recloser Sectionalizer
Relay
Purpose
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Provide input signal (replica of power systemvoltage and current) to Relays
Reduce level - suitable for relays (typically 120V and69V depending on line-line or line to neutralconnection)
Provide isolation
Purpose
Types
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Voltage transformation
Electromagnetic voltage transformer
Coupling capacitance voltage transformer
Optical voltage transformer
Current transformation
Electromagnetic current transformer
Optical current transformer
Rogowski coil
Types
Voltage (potential) Transformer (VT/PT)
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Do not differ materially from constant-potentialpower transformers except
Power rating is small
Designed for minimum ratio & phase angle error
Voltage (potential) Transformer (VT/PT)
Current Transformer Basics
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Current or series transformer primary connected inseries with the line
Ratio of transformation is approximately inverseratio of turns. i.e 2000/5
Differs from constant-potential transformer Primary current is determined entirely by the
load on the system and not by its ownsecondary load
Current Transformer Basics
Current Transformer Basics
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© ABB GroupOctober 29, 2013 | Slide 60
Secondary winding should never be open-circuited
Flux in the core, instead of being the difference ofthe primary & secondary ampere-turns, will now bedue to the total primary ampere-turns acting alone
This causes a large increase in flux, producing
excessive core loss & heating, as well as highvoltage across the secondary terminals
VCD= VS= IL(ZL+ Zlead + ZB)VCD= VS= IL(ZL+ Zlead + ∞)Where Z
B
is the load presented tothe CT by the relay.
Current Transformer Basics
Steady State Performance of CT
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© ABB GroupOctober 29, 2013 | Slide 61
ANSI accuracy classes
Class C indicates that the leakage flux is
negligible and the excitation characteristic can
be used directly to determine performance. The
Ct ratio error can thus be calculated. It isassumed that the burden and excitation
currents are in phase and that the secondary
winding is distributed uniformly.
Steady State Performance of CT
Steady State Performance of CT
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© ABB GroupOctober 29, 2013 | Slide 62
ANSI accuracy classes
Steady State Performance of CT
D C Saturation of a CT
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D.C. Saturation of a CT
© ABB GroupOctober 29, 2013 | Slide 63
Saturation of a CT may occur as a result of any oneor combination of:
Off-set fault currents (dc component)
Residual flux in the core
D C Saturation Effect in Current
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© ABB GroupOctober 29, 2013 | Slide 64
D.C. Saturation Effect in Current
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Over Current Relay Characteristics
© ABB Group
October 29, 2013 | Slide 65
Recloser or Breaker Relay Characteristic
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Recloser or Breaker Relay Characteristic
Amperes
100
0.1
T i m e i n S e
c o n d s
1.0
10
100
1000
1000 10000
Response Time
Breaker / RecloserInterruption Time
Contact openingand arc clearing
Overcurrent Current Device Characteristics
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Overcurrent Current Device Characteristics
Current in Secondary Amperes
0.1
0.1
T i m e i n S e
c o n d s
1
10
0.001
100
10 1000
51
1 100
ANSI Numbers
50 - Instantaneous Overcurrent (Nointended delay)
Recloser –Fast Curve
51 - Inverse-time OvercurrentRecloser – Slow curve
50
M1 PU
Time Overcurrent Curves
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Time Overcurrent Curves
Current in Multiples of Pickup
DefiniteTime
5
0.2
T i m e i n S e
c o n d s
0.4
0.6
0.8
1.0
10 15 20
ModeratelyInverse
Inverse
Very
Inverse
Extremely
Inverse
Time Overcurrent Curve – Time Dial
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Time Overcurrent Curve Time Dial
Recloser Curves
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Recloser Curves
Variety of recloser curves are offered tomatch existing practices, fuses, conductorannealing, etc.
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Distribution Feeder Ground Protection
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Distribution Feeder Ground Protection
Pickup commonly based on one of the following
% Above estimated normal load unbalance % Above estimated load unbalance due to switching
% Of the phase overcurrent pickup
% Of the feeder emergency load rating
% Of the feeder normal load rating
Permissible Unbalance
Not above 25% of load current is typical rule-of-thumb, but some allow up to50%
Pickup setting of ground element to be 2 - 4 times the permissible unbalance
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Principles of Feeder Coordination
P i i l f F d C di ti
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Principles of Feeder Coordination
Fault Current Vs. Distance to
Fault on the Feeder
Principles of Feeder Coordination
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p
If2 If1
T i m e
CurrentIf2If1
T1
T2
51 – Inverse time-overcurrent characteristic
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Principles of Feeder Coordination
If3 If2If1
T i m e
CurrentIf3If2If1
Relay
Recloser Fuse
Fuse
MinimumMelt
RecloserRelay
CTI - Coordination Time Interval(typical - 0.35 sec)
CTI
CTI
P2
P3
TotalClearing
InterruptTime
Response
Time
P1
Breaker
© ABB Group
October 29, 2013 | Slide 76
Principles of Feeder Coordination
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p
Upstream
Source-side
Protected
Backup
B
Downstream
Load-side
Protecting
Down-line
Local(where you are)
LOADSOURCE
Coordination Terminology
R
© ABB Group
October 29, 2013 | Slide 77
Principles of Feeder Coordination
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p
T i m e
CurrentIf1M
1. Determine critical fault current
locations and values of mostdown stream device, and plot• Maximum – If1M
Min Zs, at device• Minimum – If1m
Max Zs, end of segment
MIN MAX
If1m
If2M If2M If1M
H R
If1MLOAD LOAD
If1mIf2m
© ABB Group
October 29, 2013 | Slide 78
Principles of Feeder Coordination
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p
T i m e
CurrentIf1M
IRpu1. Determine critical fault current
locations and values, and plot.2. Set the pickup of the most
downstream device as sensitiveas possible(0.5*If1m > IRpu > 2*LOAD )
MIN MAX
If1m
If2M If2M If1M
H R
If1MLOAD LOAD
If1mIf2m
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p
T i m e
CurrentIf1M
IRpu1. Determine critical fault current
locations and values, and plot.2. Set most downstream device as
sensitive as possible.3. Plot operating times of Relay R
based on characteristic of deviceselected.
T2
T1
MIN MAX
If1m
If2M If2M If1M
H R
If1MLOAD LOAD
If1mIf2m
Principles of Feeder Coordination
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p
T i m e
CurrentIf1M
IRpu
T2
T1
MIN MAX
If1m
CTI
1. Determine critical fault currentlocations and values, and plot.
2. Set most downstream deviceas sensitive as possible.Plot operating times of Relay R.
3. Add Coordination Time Interval(CTI).
If2M If2M If1M
H R
If1MLOAD LOAD
If1mIf2m
Principles of Feeder Coordination
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p
T i m e
CurrentIf1M
IRpu
T2
T1
MIN MAX
If1m
CTI
Coordination Time Interval
CTI is the minimum time interval added to the
local device (relay/breaker, fuse) that permitscoordination with the next remote upstreamdevice. Coordination is achieved where theremote device will not [normally] operate forfaults downstream of the local device, but willoperate for all faults between the two.
If2M If2M If1M
H R
If1MLOAD LOAD
If1mIf2m
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T i m e
CurrentIf1M
IRpu
T2
T1
MIN MAX
If1m
CTI
Coordination Time Interval
Factors that influence CTI are:• Breaker fault interruption time of upstreamdevice
• Relay dropout (over-travel) time ofupstream device [momentum]
• Safety margin to account for setting, tap,
CT and operating time errors• 0.35 seconds typical
If2M If2M If1M
H R
If1MLOAD LOAD
If1mIf2m
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T i m e
CurrentIf1M
IRpu
T2
T1
MIN
MAX
MIN
MAX
If1mIf2MIf2m
4. Add CTI.
5. Determine critical fault currentlocations for device H, and plot•Maximum – If2M
Min Zs, at device•Minimum – If2m
Max Zs, end of segment.6. Plot operating times for H.
If2M If2M If1M
H R
If1MLOAD LOAD
If1mIf2m
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T i m e
If1M
IRpu
T2
T1
MIN
MAX
MIN
MAX
If1m
IHpu
If2MIf2m
4. Add CTI.
5. Determine critical fault currentlocations for device H, and plot.6. Plot operating times of Relay H.7. Select pickup settings for Relay H
(IHpu ) to operate for minimumfault and not operate onmaximum load.(0.5*If2m > IHpu > 2* Load or
compromise)
If2M If2M If1M
H R
If1MLOAD LOAD
If1mIf2m
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T i m e
CurrentIf1M
IRpu
T2
T1
MIN
MAX
MIN
MAX
If1m
IHpu
If2MIf2m
4. Add CTI.
5. Determine critical fault currentlocations for device H.6. Plot operating times of Relay H.7. Select pickup settings for Relay H.8. Select time dial for Relay H so
curve passes through or above allCTI points.
If2M If2M If1M
H R
If1MLOAD LOAD
If1mIf2m
© ABB Group
October 29, 2013 | Slide 86
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T i m e
CurrentIf1M
IRpu
MIN
MAX
MIN
MAX
IHpu
If2M
Relay at H is comparatively slow
in the defined region of I > If1M
If2M If2M If1M
H R
If1MLOAD LOAD
If1mIf2m
© ABB Group
October 29, 2013 | Slide 87
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T i m e
CurrentIf1M
IRpu
T2
T1
MIN
MAX
MIN
MAX
IHpu
Relay at H is comparatively slow
in the defined region Apply Instantaneous at H at value
greater than 1.25*If1M
IH50pu
If2M If2M If1M
H R
If1MLOAD LOAD
If1mIf2m
Fuse Coordination - Rule of Thumb
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Amperes
10
0.1
T i m e i n S e
c o n d s
1.0
10
100
1000
100 1000 10000
Minimum Melt
(Response Time)
Total Clearing
(Interruption Time)
UpstreamDownstream
Maximum clearing time ofdownstream fuse should be less than75% of minimum melt time of
upstream fuse.
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Amperes
10
0.1
T i m e i n S e
c o n d s
1.0
10
100
1000
100 1000 10000
Minimum Melt
(Response Time)
UpstreamRecloser
DownstreamFuse
Maximum clearing time of downstreamfuse should be 75% of the 51characteristic of the upstreamrecloser/relay for desirablecoordination. It may be necessary,
however, to to set the CTI down to aslow as 5 cycles to achieve completefeeder coordination.
Fuse - TC
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Most utilities require complete coordination between phase time-overcurrentelements down through customer owned protective devices
Those who allow miscoordination only permit it at high current levels where theresult is likely to be simultaneous fuse blowing and feeder tripping
Typical Feeder Coordination
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Typical Feeder Coordination
BR
Relay
Recloser
Fuse
115 kV - 13.2/7.62
kV Grd Y
15/20/25 MVAZ = 8% @ 15 MVA
125E 100T
100T 65T
I3Ph
= 7850
I1Ph
= 7950
I3Ph = 1100
I1Ph
= 950
I3Ph
= 6300
I1Ph
= 6000
I3Ph
= 2300
I1Ph
= 950
X
X
X
X
Feeder Coordination Example
Typical Feeder Coordination
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Time-Current Curves drawn based on the 13.2kv system currents
Assumptions Maximum load through recloser = 230A
Maximum load at feeder breaker = 330A
65T and 100T fuses used at lateral taps
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With 230A maximum load, select 560A phase pickup setting for the recloser(240%)
for both phase time and instantaneous units
Select 280A pickup for ground overcurrent element (50% of phase pickup)
for both ground time and instantaneous units
Select ground time-curve of recloser to coordinate with the 100T fuse
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Assuming 400:5 ct ratio for the substation relays, 330A max load = 4.125Asecondary
Select 9A tap for phase relays = 720A pickup
Select 4A tap for ground relay = 320A pickup
Select ground relay time-dial to coordinate with recloser ground curve. Selectphase relay time dial to coordinate with recloser phase curve
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Phase overcurrent relay curve must also coordinate with transformer primaryside fuses and transformer frequent-fault capability
Primary side fuse must protect transformer per transformer infrequent-faultcapability curve
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Typical Feeder Coordination
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Transformer fuse is theslowest (C&D)
OC Relay and Recloserslow curves faster than65T and 100T Fuses(3,4,5 & 6)
Typical Feeder Coordination
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Typical Feeder Coordination
© ABB GroupOctober 29, 2013 | Slide 99
•Recloser fast curves faster than 65T and 100T Fuses
•Recloser is operating in a “fuse save” mode:
•Fast curve (1&2) will open recloser before downstream fuses open
•This will allow a transient fault on a fused tap tobe cleared before blowing the fuse
•After a pre-determined number of operations,usually one or two, the fast curves are blockedand the recloser allows the fuse to blow if thefault is in the fuse’s zone of protection.
•If the fault is on the feeder the recloser willoperate again, typically going to lockout afterone or two more operations.
•Each recloser operation will have a longer opentime to allow the fault to clear
•This reduces the outage time on the taps fortransient faults, saving the fuse and not havingto dispatch a crew to replace the fuse.
Typical Feeder Coordination
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The breaker is operating in a fuse blowing mode:
• If the fault is on the tap above the recloserthe 100T fuse will open before the breaker
•This reduces the number of customersaffected by the outage to only those on thetap.
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