Fundamentals of Power System Protection_2012
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Transcript of Fundamentals of Power System Protection_2012
Page 1
Course SynopsisFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 1
Fundamental Principlesof
Power System Protection
Slide 1Slide 1
Barrie Moor
bmoor@powersystemprotection.com.auwww.powersystemprotection.com.au
Slide 2
Disclaimer
The material presented in this module is for Educational purposes only.This module contains a summary of information for the protection of various types of electrical equipment. Neither the author, nor anyone acting on his behalf, makes any warranty or representation, express or implied, as to the accuracy or completeness of the information contained herein, nor assumes any responsibility or liability for the use or consequences of the use of any of this information.The practical application of any of the material contained herein must be in accordance with legislative requirements and must give due regard to the individual circumstances.
Page 2
Course SynopsisFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 3
Course Synopsis
Fundamental Concepts of Protection DesignFault CalculationsOver Current & Earth Fault ProtectionVTs & CTsFundamentals of Distance ProtectionFundamentals of Protection SignallingFundamentals of High Impedance Differential ProtectionFundamentals of Transformer Biased Differential ProtectionFundamentals of Busbar Biased Differential ProtectionFundamentals of Feeder Differential ProtectionAuto ReclosingCapacitor Bank Protection
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Page 1
Fault CalculationsSequence Components
Fundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 1
Fundamental Principlesof
Power System Protection
Slide 1Slide 1
FAULT CALCULATIONS
An Introduction
Slide 2
Basic Calculations : 3 Phase Fault
ZS ZLVS VR IF
LS
SF ZZ
VI NL
+= −
LFR ZIVNL
•=−
Slide 3
Basic Calculations : Ph - Ph Fault
( )LS
SF ZZ2
VI LL
+•= −
= I3PH * √3 / 2
ZSVS
IF
ZL
Slide 4
Basic Calculations : Earth Fault
GLS
SF ZZZ
VI NL
++= −
ZSVS
IF
ZL
Multiple return paths
Slide 5
System Impedances and Fault Calculations
Transformers– Voltages reflected via turns ratio– Currents reflected inversely to turns ratio– Impedances reflected via (turns ratio)2
Slide 6
Per Unit Values
For those who think this is hard … you always operate in a per unit system !!1 Volt1 Ampere
A current of 1 Ampere flowing through a resistance of 1 Ohm produces a voltage drop of 1 Volt and an energy dissipation of …
SecondJoules
SecondElectrons18
ElectronJoules19 11025.6106.1 ⋅=⋅⋅⋅⋅⋅ −
= 1.6 x 10-19 Joules / Electron= 6.25 x 1018 Electrons / Second
Watt1 ⋅=
Page 2
Fault CalculationsSequence Components
Fundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 7
Per Unit Values
But I manufacture 100MVA 132/66kV Transformers, so these figures of 1 Volt and 1 Ampere don’t reflect how I work
100 MVA = 1 pu– On the 132kV side … 1 pu voltage = 132 kV– On the 132kV side … 1 pu current = 437.4 A– On the 132kV side … 1 pu impedance = 174.24 Ω
– On the 66kV side … 1 pu voltage = 66 kV– On the 66kV side … 1 pu current = 874.8 A– On the 66kV side … 1 pu impedance = 43.56 Ω
Slide 8
Per Unit Values and Transformers
100 MVA132kV 66kV
2Ω12Ω
• Transfer impedances to the HV side (via (turns))2
• Convert impedances to per unit on 100 MVA base
20Ω
132kV 66kV
0.1148 pu
132kV 66kVpu⋅= 1148.0
24.17420
( ) 20212 266
132 =⋅+
Slide 9
Per Unit Values and Transformers
100 MVA132kV 66kV
2Ω12Ω
• Transfer impedances to the LV side (via (turns))2
• Convert impedances to per unit on 100 MVA base
5Ω
132kV 66kV
0.1148 pu
132kV 66kVpu⋅= 1148.0
56.435
( ) 5122 213266 =⋅+
Slide 10
Per Unit Values
So, with the same base MVAAnd base voltage equal to system voltagePer Unit impedances remain the same across the transformer
132kV 66kV11kV
NB !!NB !!
Slide 11
Per Unit Values
So, with the same base MVAAnd base voltage equal to system voltagePer Unit impedances remain the same across the transformer
132kV 66kV11kV
NB !!NB !!
ZTOT = 0.1 puZTOT = 0.1 pu IFAULT = 10.0 puIFAULT = 10.0 puV = 1.0 puV = 1.0 pu
10pu@66kV = 8748A10pu@66kV = 8748A10pu@132kV = 4374A10pu@132kV = 4374A10pu@11kV = 52500A10pu@11kV = 52500A
Slide 12
Per Unit Quantities : Change of Base
Manufacturer base quantities most likely will not match the base values we wish to use.We must use a constant MVA base across the entire model.Base voltages must match system voltages.For example : Consider a generator step up transformer, with the manufacturer nominal values …
– 75 MVA– 11/145 kV– 12.5% impedance on rating
But for fault study simulations, we have chosen– 100MVA base– 132kV system nominal voltage
Page 3
Fault CalculationsSequence Components
Fundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 13
Per Unit Quantities : Change of Base
Transformer– 75MVA, 145kV, 12.5% impedance
Calculate base impedance– 1452 / 75 = 280.33 Ω
Convert transformer pu impedance to ohms– 280.33 * 12.5% = 35.04 Ω
System fault study– 100MVA, 132kV
Calculate base impedance– 1322 / 100 = 174.24 Ω
Hence, for our fault study simulation– 35.04 / 174.24 = 20.1%
Slide 14
Per Unit Quantities : Change of Base
2
NEW
OLD
OLD
NEWOLDNEW kV
kVMVAMVAZZ ⎟⎟
⎠
⎞⎜⎜⎝
⎛••=
2
NEW 132145
751005.12Z ⎟
⎠⎞
⎜⎝⎛••=
%1.20ZNEW =
Slide 15
Classical Fault Study
Pre-fault voltages set to 1/0°Pre-fault load currents ignoredTransformers on system voltage tap (eg. 132/66kV to match system voltages,even if transformer nominal tap is say 132/69kV)Shunt impedances ignored (Shunt capacitors, etc)Zero ohms fault resistanceGenerator Sub-transient reactance
– Assumes generator contribution to the fault remains at its maximum
This is adequate for setting of protection relays– Relay setting calculations will all be on the basis of the same fault
level data, and hence coordination is achieved– “C” factor of 1.1 usually applied in determining equipment ratings
Slide 16
Fundamental Principlesof
Power System Protection
Slide 16Slide 16
SEQUENCE COMPONENTS
An Introduction
Slide 17
Sequence Components
Positive Sequence– A B C– Equal in magnitude– 120 degrees apart
Negative Sequence– A C B– Equal in magnitude– 120 degrees apart
Zero Sequence– A B C– Equal in magnitude– In phase
V1
V2
V0
I1
I2
I0
Slide 19
Sequence Components
I1 I2 I0
I phase
IC
IB
IA
Page 4
Fault CalculationsSequence Components
Fundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 20
Sequence Components
210 IAIAIAIA ++=
210 IBIBIBIB ++=
01201a ∠=
210 ICICICIC ++=
⎥⎥⎥
⎦
⎤
⎢⎢⎢
⎣
⎡•⎥⎥⎥
⎦
⎤
⎢⎢⎢
⎣
⎡=
⎥⎥⎥
⎦
⎤
⎢⎢⎢
⎣
⎡
2
1
0
2
2
11
111
IAIAIA
aaaa
ICIBIA
212
0 IAaIAaIA ⋅+⋅+=
22
10 IAaIAaIA ⋅+⋅+=
Slide 21
Sequence Components
[ ]⎥⎥⎥
⎦
⎤
⎢⎢⎢
⎣
⎡•=
⎥⎥⎥
⎦
⎤
⎢⎢⎢
⎣
⎡
2
1
0
IAIAIA
AICIBIA
⎥⎥⎥
⎦
⎤
⎢⎢⎢
⎣
⎡•
⎥⎥⎥
⎦
⎤
⎢⎢⎢
⎣
⎡•=
⎥⎥⎥
⎦
⎤
⎢⎢⎢
⎣
⎡
ICIBIA
aa1aa1111
31
IAIAIA
2
2
2
1
0
⎥⎥⎥
⎦
⎤
⎢⎢⎢
⎣
⎡•
⎥⎥⎥
⎦
⎤
⎢⎢⎢
⎣
⎡=
⎥⎥⎥
⎦
⎤
⎢⎢⎢
⎣
⎡
2
1
0
2
2
IAIAIA
aa1aa1111
ICIBIA
[ ]⎥⎥⎥
⎦
⎤
⎢⎢⎢
⎣
⎡•=
⎥⎥⎥
⎦
⎤
⎢⎢⎢
⎣
⎡
ICIBIA
A1
IAIAIA
2
1
0
Slide 22
Sequence Networks
Source
RelayLocation
FaultLocation
Posi
tive
Sequ
ence
Net
wor
k
Z1s
Z1f
I1
Source
RelayLocation
FaultLocation
Neg
ativ
e Se
quen
ce N
etw
ork
Z2f
Z2s
I2
Source
RelayLocation
FaultLocation
Zero
Seq
uenc
e N
etw
ork
Z0f
Z0s
I0
V1 = 1 / 0º V2 = 0 V0 = 0
Slide 23
Sequence ComponentsThree phase conditions
Positive sequence only
– Three phase load– Three phase fault– No neutral (earth fault) current
Slide 24
In = 0
3 Phase Balanced Current
Balanced currents “sum to zero”– Positive sequence currents– Negative sequence currents– But zero sequence will sum to 3.Io In = 3.Io
Slide 25
Sequence Networks3 Phase Fault
Source
RelayLocation
FaultLocation
Posi
tive
Sequ
ence
Net
wor
k
Z1s
Z1f
I1
fZsZZ
ZVII
POS
POSFaultPhase
11
1__3
+=
==
Page 5
Fault CalculationsSequence Components
Fundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 26
Sequence ComponentsPhase – Phase fault
Positive and Negative sequence components only– And consider the special case where …
A phase equal in magnitude but opposite in phase
– B to C Phase to Phase fault
Slide 27
Sequence Networks (A phase)Phase – Phase fault
A phase– IA1 & IA2 antiphase
Sum to zeroB phase
– IB1 & IB2 at 60o
C phase– IC1 & IC2 at 60o
IB = - IC
Source
RelayLocation
FaultLocation
Posi
tive
Sequ
ence
Net
wor
k
Z1s
Z1f
I1
Source
RelayLocation
FaultLocation
Neg
ativ
e Se
quen
ce N
etw
ork
Z2f
Z2s
I2
21 II =
Slide 28
Sequence Networks (A phase)Phase – Phase fault
Source
RelayLocation
FaultLocation
Posi
tive
Sequ
ence
Net
wor
k
Z1s
Z1f
I1
Source
RelayLocation
FaultLocation
Neg
ativ
e Se
quen
ce N
etw
ork
Z2f
Z2s
I2
Since Z1 ~ Z2
|I1| = |I2| = 50% of 3 phase fault level
negpos ZZVII+
== 21
Slide 29
Sequence ComponentsPhase – Phase fault
|I1| = |I2| = 50% of 3 phase fault levelThus |IB| = |IC| = 86.6% of 3 phase fault level(because of 60o angles)
Slide 30
Phase to Phase Example
Source
RelayLocation
FaultLocation
Posi
tive
Sequ
ence
Net
wor
k
Z1s
Z1f
I1
Source
RelayLocation
FaultLocation
Neg
ativ
e Se
quen
ce N
etw
ork
Z2f
Z2s
I2
V2 = 0V1 = 1 / 0º
= 0.10 = 0.10
= 0.15= 0.15
I = 2.0
V1 = 0.5
V1 = 0.8 V2 = 0.2
V2 = 0.5
Slide 32
Sequence ComponentsEarth Fault
A phase positive sequencenegative sequencezero sequence
Equal in magnitude and phase
Page 6
Fault CalculationsSequence Components
Fundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 33
Sequence ComponentsEarth Fault
Slide 34
Sequence NetworksA Phase Earth Fault
Source
RelayLocation
FaultLocation
Posi
tive
Sequ
ence
Net
wor
k
Z1s
Z1f
I1
Source
RelayLocation
FaultLocation
Neg
ativ
e Se
quen
ce N
etw
ork
Z2f
Z2s
I2
Source
RelayLocation
FaultLocation
Zero
Seq
uenc
e N
etw
ork
Z0f
Z0s
I0
Slide 35
Sequence NetworksA Phase Earth Fault
PositiveSequence
FaultLocation
NegativeSequence
FaultLocation
ZeroSequence
FaultLocation
RelayLocation
ZS1
Zl
ZS2
Zl
I2I1RelayLocation
ZS0
Zl
I0RelayLocation
zeronegpos ZZZVIII
++=== 021
021 IIIIA ++=
0=IB
0=IC
03 II NEUT ∗=
Slide 36
Source
RelayLocation
FaultLocation
Posi
tive
Sequ
ence
Net
wor
k
Z1s
Z1f
I1
Source
RelayLocation
FaultLocation
Neg
ativ
e Se
quen
ce N
etw
ork
Z2f
Z2s
I2
Source
RelayLocation
FaultLocation
Zero
Seq
uenc
e N
etw
ork
Z0f
Z0s
I0
Phase to Ground Example
= 0.10 = 0.10
= 0.15= 0.15
= 0.15
= 0.35
I = 1.0 I = 1.0 I = 1.0
V1 = 1 / 0º V2 = 0
V0 = -0.15
V0 = -0.50
V2 = -0.10
V2 = -0.25
V0 = 0
V1 = 0.90
V1 = 0.75
Slide 37
Sequence NetworksResistive Earth Fault
Source
RelayLocation
FaultLocation
Posi
tive
Sequ
ence
Net
wor
k
Z1s
Z1f
I1
Source
RelayLocation
FaultLocation
Neg
ativ
e Se
quen
ce N
etw
ork
Z2f
Z2s
I2
Source
RelayLocation
FaultLocation
Zero
Seq
uenc
e N
etw
ork
Z0f
Z0s
I0
FaultResistance3 x R_fault3 x R_fault
Earth Fault current is 3 x IoHence, voltage drop across the fault resistance will be 3 x Io x R_faultBut the sequence model only has Io flowingSo, include 3 x R_fault in the model
Slide 38
Sequence ComponentsSummary
Positive Sequence– Balanced three phase load– Balanced three phase fault– No neutral (earth) current
Negative Sequence– Unbalanced load– Phase to phase fault– No neutral (earth) current
Zero Sequence– Earth fault– Neutral current = 3 . Io– Cannot flow into or out of a delta– Can circulate around (within) the delta
Io = 0
Io = 0
Io = 0
IoIoIo
3Io
Page 7
Fault CalculationsSequence Components
Fundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 39
Positive Sequence Network
LVZS
ZS HVZ1HL
HV
LV
Zfdr
Zfdr
Slide 40
Negative Sequence Network
ZS
ZS Z1HL
LV
HV
HV
LV
Zfdr
Zfdr
Slide 41
Zero Sequence Network
ZS
ZS Z1HL
LV
HV
HV
LV
Zfdr
Zfdr
Page 1
Over Current ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 1
Fundamental Principlesof
Power System Protection
Slide 1Slide 1
Over Current Protection
Overcurrent RelaysDirectional RelaysFuses & Fuse Contactors
Slide 2
Over Current Protection
Over Load Protection– Operation to the thermal capability of plant
Over Current Protection– Primarily for clearance of faults– Some measure of over load protection may be
provided
Slide 3
Discrimination by Time
Setting chosen to ensure CB nearest to the fault opens firstOften referred to as …“Independent Definite Time Delay Relay”Timing intervals selected to ensure upstream relays do not operate before CBs trip at fault locationDisadvantage …Longest fault clearing time occurs in section closest to the power source where fault level is the highest
Slide 4
Discrimination by Time
RELAY ‘A’ RELAY ‘B’ RELAY ‘C’
RELAY ‘C’
RELAY ‘B’
RELAY ‘A’
CURRENT
TIM
E
0.4 secs
0.4 secs
Slide 5
Discrimination by Current
Apply where fault current varies with fault location due to intermediate impedanceSet to operate at current values so that only relay nearest to fault trips its CBDifficulties– Same fault level at the end of one zone and the start
of the next– Fault levels vary with changing source impedance
(eg. As generators come on and go off line)
Slide 6
Discrimination by Current
RELAY ‘A’ RELAY ‘B’
Relay ‘A’ cannot distinguish between a fault here, for which it needs to operate
And a fault here for which it should not operate
Page 2
Over Current ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 7
Discrimination by Current
Significant difference between currents seen for Faults A & BSet HV OC to 1.3 x maximum through current for LV Fault
HV OC
FDR OC
FDR OC
FDR OC
FDR OC
A
B
Slide 8
Discrimination by Time & Current
Time and current coordination
RELAY ‘A’ RELAY ‘B’ RELAY ‘C’
RELAY ‘C’
RELAY ‘B’
RELAY ‘A’
CURRENT
TIM
E
ICmax IBmax IAmax
IAmax IBmax ICmax
Instantaneous element
Slide 10
Inverse Over Current Relays
Time of operation inversely proportional to fault current– Faster operating times at higher fault levels– Faster operating times for faults nearer to the source
Curves generally plotted in log - log or log(current) – linear(time) format
Slide 11
Discrimination withInverse Time Over Current Relays
Inverse time and current coordination
RELAY ‘A’ RELAY ‘B’ RELAY ‘C’
RELAY ‘C’
RELAY ‘B’RELAY ‘A’
CURRENT
TIM
E
ICmax IBmax IAmax
IAmax IBmax ICmax
Instantaneous element
Slide 12
Relay Curves to IEC 60255(BS142)
I = Actual relay currentRelay Settings
– TMS = Time Multiplier Setting– P = Plug (Current) pickup setting
Usual curve for transmission and distribution systems
1PI
TMS14.0TIME 02.0Inverse_dardtanS
−⎥⎦⎤
⎢⎣⎡
•=
Slide 13
Relay Curves to IEC 60255(BS142)
I = Actual relay currentRelay Settings
– TMS = Time Multiplier Setting– P = Plug (Current) pickup setting
Systems where the fault level decreases significantly between relaying points
1PI
TMS5.13TIME Inverse_Very
−⎥⎦⎤
⎢⎣⎡•
=
Page 3
Over Current ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 14
Relay Curves to IEC 60255(BS142)
I = Actual relay currentRelay Settings
– TMS = Time Multiplier Setting– P = Plug (Current) pickup setting
Grading with fuses
1PI
TMS80TIME 2Inverse_Extremely
−⎥⎦⎤
⎢⎣⎡
•=
Slide 15
Relay Curves to IEC 60255(BS142)
I = Actual relay currentRelay Settings
– TMS = Time Multiplier Setting– P = Plug (Current) pickup setting
Long time thermal protection– Motor & Generator Protection
1PI
TMS120TIME Inverse_Time_Long
−⎥⎦⎤
⎢⎣⎡•
=
Slide 16
Standard Characteristics to IEC 60255
Long Time (LTI)
Extremely Inverse (EI)
Very Inverse (VI)
Standard Inverse (SI)
Relay Characteristic
1ITMS14.0
02.0 −•
1ITMS5.13
−•
1ITMS80
2 −•
1ITMS120−•
100 1 .103 1 .1040.1
1
10
100
Standard InverseVery InverseEtremely InverseLong Time Inverse
IDMT Relay Grading Curves
Fault Current
Seco
nds
Slide 18
US Characteristics to IEC 60255
U5 Short Time Inverse
U4 Extremely Inverse *
U3 Very Inverse
U2 Inverse
U1 Moderately Inverse
Relay Characteristic
⎥⎦⎤
⎢⎣⎡
−+•
1M0104.00226.0TD 02.0
⎥⎦⎤
⎢⎣⎡
−+•
1M95.5180.0TD 2
⎥⎦⎤
⎢⎣⎡
−+•
1M88.30963.0TD 2
⎥⎦⎤
⎢⎣⎡
−+•
1M64.502434.0TD 2
⎥⎦⎤
⎢⎣⎡
−+•
1M00342.000262.0TD 02.0
TD = Time dial (TMS)M = Multiple of pick-up current
Slide 19
Electro Mechanical Relays
disc.
FLUX PRODUCED BY INPUT
TAPPEDCOIL Φ I
Φ- L
SHADING LOOP
FLUX PRODUCED BY INPUT CURRENT
DISC DISC
FLUX PRODUCED BY SHADING LOOP
Φk I
Φ L
(1-k)Φ I
Page 4
Over Current ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 20
Electro Mechanical RelaysConstruction
Current (Plug) Settings
Time multiplier (TMS) Settings (continuous adjustable)
Shaded Pole
Trip Contacts andFlag
Trip Contacts
Moving Contact
Slide 21
Electro Mechanical RelaysInverse Definite Minimum Time
Current sensitivity selected by “Plugs” on the magnetic circuit– Higher sensitivity selected via more turns – ie. Same Ampere Turns operating quantity …
more turns = less currentMagnetic circuit saturates at extreme over current
– Limits the minimum operating time– Typically around 20x plug setting– Hence IDMT performance : DM = definite minimum
Time coordination via Time Multiplier setting– Adjusted the starting point of the induction disk wrt the fixed trip
contact– Often called “Lever Setting”
disc.
100 1 .103 1 .1040.1
1
10
100Standard Inverse Relay Grading Curves
Fault Current
Seco
nds
Adjust TMS to achieve time coordination
And since we are usually interested in operating times of 3 seconds or less, we may get a better perception if we use a linear axis for time
100 1 .103 1 .104
0.5
1
1.5
2
2.5
3
3.5
4Standard Inverse Relay Grading Curves
Fault Current
Seco
nds
If we have sufficient
margin here
Then with the same characteristic, we tend to have greater margin at lower currents due to
divergence of the curves
Slide 24
IDMT Curves
Electromechanical relays– Must not pick up at < 1.00 pu current– Must pick up at > 1.30 pu current– May not have well defined characteristics between
1.3 and 2.0 pu currentElectromechanical relays tend to a definite minimum time at high currents, say > 20 x ISET– Due to saturation of their magnetic circuits
Microprocessor based relays will have a genuine definite minimum time.
OC OC
OC
OC
100 1 .103 1 .104
0.5
1
1.5
2
2.5
3
3.5
4IDMT Relay Grading Curves
Fault Current
Seco
nds
0.4 SecondsMargin
0.4 SecondsMargin
Page 5
Over Current ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 26
Instantaneous Element
Reduces tripping time at high fault levelsAllows a the discriminating curves behind the high set element to be lowered
– Grading of upstream relay now occurs at the instantaneous setting and not at maximum fault level
Minimises fault damage in both cases
Beware …Simple E/M instantaneous elements may have a substantial transient overreach on fault currents that include DC offset
OC OC
100 1 .103 1 .104
0.5
1
1.5
2
2.5
3
3.5
4IDMT Relay Grading Curves
Fault Current
Seco
nds
100 1 .103 1 .104
0.5
1
1.5
2
2.5
3
3.5
4IDMT Relay Grading Curves
Fault Current
Seco
nds
100 1 .103 1 .104
0.5
1
1.5
2
2.5
3
3.5
4IDMT Relay Grading Curves
Fault Current
Seco
nds Set Tx HV inst
element and now grade here
OC
OC
Slide 29
Relay Coordination Procedure
Start with selection of relay characteristic– As far as possible, use relays of the same characteristic
Choose current settings– Determine maximum load current limitations– Determine starting current requirements– As far as possible, select operating current of each upstream relay greater
than that of the successive downstream relayCoordinate relays via time multipliers to achieve appropriate grading margins
– Determine, under various system configurations, the values of short circuit current that will flow through each protective device
– Set relays to give minimum operating time at maximum fault currents– Check performance (discrimination) at lower fault levels
Plot and coordinate relay curves on log/log or log/linear format– Plot to a common current base (across transformers)
Earth faults are considered separately and require separate plots
Slide 30
Relay Current Pick-up Setting
Set above maximum load current– Allow for emergency loading conditions– Allow safety margin– Allow for relay reset ratio
Set below the current pickup level of the next “upstream” relayAllow for load pickup current
Slide 31
Load Pickup Current
Motor starting currentAuxiliary heatersTransformer magnetising inrushCapacitor charging currentLighting loads - 10s to 100s of msec– Filaments and electrodes heating– Arc lamps starting
Slide 32
Load Pickup Current
Hot load pickup– Short term loss of supply and subsequent load pickup
currents on return of supplyCold load pickup– Load pickup, but now with loss of diversity between
cyclic loadsVoltage recovery pickup– Pickup currents not as severe as for complete loss of
supply and subsequent hot load pickup– But more motors may still be on-line as under voltage
releases may not have disconnected them
Page 6
Over Current ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 33
Relay TMS Grading
Must provide for– CB tripping time (0.1 sec ??)– Relay timing errors– Relay overshoot– CT errors (10% ??)– Safety margin (10% ??)
A typical figure of 0.3 - 0.4 seconds is usually OK– 0.3 for numerical relays– 0.4 for electromechanical relays
Alternatively calculate a margin– Only necessary for slow tripping times (> 1.0 sec)
Slide 34
Relay TMS Grading
Slide 35
Relay TMS Grading
Hence for an E/M relay tripping in 0.5 seconds– t’ = (7.5 + 7.5 + 10)% x 0.5 + 0.1 + 0.05 + 0.1– t’ = 0.375 seconds
0.30.30.350.4Typical margin (s)
0.030.030.050.1Safety Margin (s)
0.020.020.030.05Overshoot Time (s)
5557.5Timing Error %
NumericalDigitalStaticElecto-Mechanical
Relay Technology
CT Errors
Slide 36
Grading of Parallel Elements
Worst case for grading is with only 1 transformer in serviceBut this will be an unusual operating conditionE/M & Electronic Relays
– Only a single relay setting is available– Hence, effectively no option but to set for the worst case,
namely 1 transformer case– And accept slower performance for system normal,
namely when both transformers are in serviceMicroprocessor based relays
– These relays have multiple setting groups– So, maybe set Group 1 for system normal : 2 transformers– And change to group 2 when one transformer is OOS
Automatically ??Via SCADA & operator intervention ??
OC OC
OC OC
OC
Slide 37
Grading of Parallel Elements
Maximum through fault level occurs when both transformers are in serviceBut the maximum individual transformer current flows when the 2nd transformer is OOSNeed to consider both conditions when grading relays
HV OC
HV OC Fdr_1 OC
3φ Fault Levels• 2 Tx IN : 16000A• 1 Tx IN : 12000A
3φ Fault Levels• 2 Tx IN : 10000A • 1 Tx IN : 7500A
33kV 11kV
20MVA
20MVA
300A FLC
800A FLC
Fdr_2 OCSI 400ATMS 0.2
Fdr1_TMS 0.28=Fdr1_TMS round Fdr1_TMS .003+ 2,( ):=Round Up
Fdr1_TMS 0.276=
Fdr1_TMS 1Fdr1_Tmin
Fdr1_TMS_1⋅:=Hence we can calculate the required TMS to achieve the required tripping time
Fdr1_TMS_1 2.971=This would result in a tripping time of
Fdr1_TMS_1 SI Fdr1_Plug 1.0, Imax,( ):=Assume TMS = 1.0
Fdr1_Tmin 0.821=Fdr1_Tmin Fdr2_Tmin 0.4+:=Required tripping time
ImaxFdr1_Plug
10=Fdr1_Plug 1000:=So select settings for Feeder 1
Fdr2_Tmin 0.421=Fdr2_Tmin SI Fdr2_Plug Fdr2_TMS, Imax,( ):=Tripping time at maximum fault level
Fdr2_TMS 0.2:=
ImaxFdr2_Plug
25=Fdr2_Plug 400:=Given data for Feeder 2
Imax 10000:=Grade Fdr_1 OC over Fdr_2 OC at the maximum through fault level of 10kASet Fdr_1 OC above maximum feeder load of 800Aand check against maximum fault level of 10kA
SI P TMS, I,( )0.14 TMS⋅
IP
⎛⎜⎝
⎞⎠
0.021−
:=Relay Characteristic
Page 7
Over Current ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Feeder 1 Relay_2n SI Fdr2_Plug Fdr2_TMS, I2n,( ):= SI Fdr2_Plug Fdr2_TMS, Imax,( ) 0.421=
Feeder 2 Relay_1n SI Fdr1_Plug Fdr1_TMS, I1n,( ):= SI Fdr1_Plug Fdr1_TMS, Imax,( ) 0.832= ∆_T 0.411=
100 1 .103 1 .104 1 .1050
0.2
0.4
0.6
0.8
1
1.2
1.4
1.6
1.8
2
2.2
2.4
2.6
2.8
3
Fdr 2 OCFdr 1 OC
Tx OC Grading (11kV Base Currents)
Tx_HV_TMS 0.36=Tx_HV_TMS round Tx_HV_TMS .003+ 2,( ):=Round up
Tx_HV_TMS 0.355=
Tx_HV_TMS 1Tx_HV_Tmin
Tx_HV_TMS_1⋅:=Hence we can calculate the required TMS to achieve the required tripping time
Tx_HV_TMS_1 3.297=This would result in a tripping time of
Tx_HV_TMS_1 SI Tx_HV_Plug 1.0, Imax,( ):=Assume TMS = 1.0
Tx_HV_Tmin 1.169=Tx_HV_Tmin Fdr1_Tmin 0.4+:=Transformer HV OC
Fdr1_Tmin 0.769=Fdr1_Tmin SI Fdr1_Plug Fdr1_TMS, Imax,( ):=Fdr Tripping time at maximum fault level
Tx_HV_Plug 1500=
Tx_HV_Plug 3 Tx_HV_Plug⋅:=Allow for 33/11kV ratio
Tx_HV_Plug 500:=Set130 %⋅ FLC_33kV⋅ 455=FLC_33kV 350=FLC_33kV20000000
3 33000⋅:=
Imax 12000:=
Grade Transformer HV OC under the maximum current condition, namely with one transformer OOS
Feeder 1 Relay_1n SI Fdr1_Plug Fdr1_TMS, I1n,( ):= SI Fdr1_Plug Fdr1_TMS, Imax,( ) 0.769=
Tx HV Relay_3n SI Tx_HV_Plug Tx_HV_TMS, I3n,( ):= SI Tx_HV_Plug Tx_HV_TMS, Imax,( ) 1.187= ∆_T 0.418=
100 1 .103 1 .104 1 .1050
0.2
0.4
0.6
0.8
1
1.2
1.4
1.6
1.8
2
2.2
2.4
2.6
2.8
3
Fdr 2 OCFdr 1 OCTx HV OC
Tx OC Grading (11kV Base Currents)
Slide 42
Resetting of Over Current Relays
Electromechanical relays tend to have a slow reset of their operating mechanism
– eg. For the disk to rotate back to the “stops”Other relays may have
– Disk simulation resetting– Instantaneous resetting
This becomes important in auto-reclosing schemes– E/M relays may not have fully reset before re-application of
a fault via autoreclose– They will thus be partially integrated to the trip and will
require less and less time to reach a trip on each successive reclosure
Slide 43
Sequential Operation of Over Current Relays
As CBs trip, fault current magnitudes and flows will changeWe need to integrate how far each relay progresses towards tripping in each stage
– To determine total tripping times– To ensure relays that should not trip, remain stable
Relay 1 operating time must have a suitable margin above the total of Relay 2 and the subsequent Relay 3 operations
Relay 3Relay 2
Relay 1
Slide 44
Fundamental Principlesof
Power System Protection
Slide 44Slide 44
DirectionalOver Currentand Earth FaultProtection
Page 8
Over Current ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 45
Directional Over Current Relays
Extra discrimination may be achieved by making the response of the relay directional when current can flow in both directionsAchieved via voltage (polarising) connections to the relayDigital and numeric relay achieve phase displacements via softwareEM & Static relays require suitable connection of input quantities to the relay
Slide 46
Directional Over Current RelaysApplication to Parallel Feeders
Apply directional relays at the feeder receiving ends– Typically set to 50% of FLC, TMS = 0.1– Grade below non-directional relays at the source end– Ensure DOC relay thermal rating is OK
OC OC
OCOC
Fdr 1
Fdr 2BA
Slide 49
Earth Fault Protection
Implement more sensitive protection responding only to residual current of the systemLow settings are permissible and beneficial
– Earth faults are the most frequent– Earth faults may be limited by earth fault resistance– Earth faults may be limited by neutral earth impedance
Typical settings 20 - 40% x FLCTime grade in the same manner as for phase OC relaysBeware of the burden that electromechanical relays may place on CTs at low current settings
– Although burden does decrease at very high currents with saturation of the relay’s magnetic circuits
Slide 50
Earth Fault Protection
EF Prot
EF Prot
OC
OC
OC
EF Prot
OC
OC
Not suitable for 2:1:1 Current applications(Transformer HV
current in the case of Star/Delta or Delta/Star through phase/phase
faults)
Slide 51
Directional Earth Fault Protection
Voltage Quantity required to polarise relayUse the system residual voltage– This is the vector sum of all three phase voltages– This is thus three times the zero sequence voltage
This voltage will be zero for balanced system voltages– Normal Load conditions– Three phase events– 2 phase events not involving earth
Slide 52
Directional Earth Fault Protection
3 . V0 is obtained from a VT with the secondary connected in a broken deltaPrimary star point of VT must be earthedAnd to provide the path for zero sequence flux …VT must be …– 5 limb core type– 3 x 1 phase units
Va
VbVc
3.Vo
Page 9
Over Current ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 53
Fundamental Principlesof
Power System Protection
Slide 53Slide 53
FusesandFuse Contactors
Slide 54
Fuses
Performance effectively follows I2t law– Pre Arcing time– Arc time
Fuse – Fuse grading requires that the total I2t of the smaller fuse be less than the pre-arcing I2t of the larger fuse
Slide 55
FuseBullrush Curves
Discrimination between fuse links is achieved when the total I2t of the minor fuse link does not exceed the pre-arcing I2t of the major fuse linkBut note that this applies only for high speed operation where there is no heat dissipation …ie. I2t adiabatic performanceAs a starting point, a current rating ratio between fuses of 1.6 - 2 is probably OK (but this depends on the specific fuse design)
100
160
200
250
Fuse Rating
403532 50 63 1 25
80
minimumpre-arcingI2t
maximumtotal I2t
Slide 56
Expulsion Fuses
Used where expulsion gases cause no problem such as in overhead circuits and equipmentSpecial materials (fiber, melamine, boric acid, liquids such as oil or carbon tetrachloride ) located in close proximity to fuse element and arc rapidly create gasesThese produce a high pressure turbulent medium surrounding the arcExpulsion process deionises gases them as well as removing them from ‘arc area‘In inductive circuits, transient recovery voltage (TRV) will be maximum at current zero.
Slide 57
Fuses & TRV Performance
0 0.002 0.004 0.006 0.008 0.01 0.012 0.014 0.016 0.018 0.02 0.022 0.0242
1.5
1
0.5
0
0.5
1
1.5
2
Circuit VoltageFuse VoltageCurrent
0 0.002 0.004 0.006 0.008 0.01 0.012 0.014 0.016 0.018 0.02 0.022 0.0242
1.5
1
0.5
0
0.5
1
1.5
2
Circuit VoltageFuse VoltageCurrent
0 0.002 0.004 0.006 0.008 0.01 0.012 0.014 0.016 0.018 0.02 0.022 0.0242
1.5
1
0.5
0
0.5
1
1.5
2
Circuit VoltageFuse VoltageCurrent
0 0.002 0.004 0.006 0.008 0.01 0.012 0.014 0.016 0.018 0.02 0.022 0.0242
1.5
1
0.5
0
0.5
1
1.5
2
Circuit VoltageFuse VoltageCurrent
0 0.002 0.004 0.006 0.008 0.01 0.012 0.014 0.016 0.018 0.02 0.022 0.0242
1.5
1
0.5
0
0.5
1
1.5
2
Circuit VoltageFuse VoltageCurrent
Current lags Voltage by 90
deg
System Voltage
Current interrupted at
natural current zero
TRV across blown fuse
element
Fuse Voltage
Slide 58
Current Limiting Fuses (HRC Fuses)
Fuse is designed to insert a large resistance– Hence, prospective level of fault current is reduced– And zero crossing of the current and voltage will be
reasonably in phase – TRV significantly reducedFuse element is completely surrounded with filler material, typically silica sand
– Arc energy melts the sand, thus inserting the required high resistance
But this design may have difficulty interrupting low level overloads.Overcome by …
– M Effect designs– Spring assisted designs
Page 10
Over Current ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 59
Current Limiting Fuses
Tin for “M Effect” low overload fuse performanceSee later
Slide 60
Current Limiting Fuses
Slide 61
Current Limiting FusesM Effect for low level overloads
M Effect : A.W. Metcalf - 1939
Slide 62
Current Limiting Fuses
Slide 63
Grading Relays with Fuses
Extremely Inverse curve follows a similar I2t characteristicRelay current setting should be approximately 3 times the fuse ratingGrading margin of not less than 0.4 seconds recommended
Or …
EI P TMS, I,( )80 TMS⋅
IP
⎛⎜⎝
⎞⎠
21−
:=
15.04.0' +⋅≥ tT
Slide 64
Grading Relays with Fuses
First relay upstream of the fuse should be set to EI characteristicNow to coordinate further upstream relays …– Option 1 : Also select EI characteristics– Option 2 : Check also for the possibility of setting
The next relay to a VI characteristicAnd subsequent further upstream relays to SI characteristics
Page 11
Over Current ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 65
Fuse Contactors
High fault level applications eg …– 40kA fault level– Contactor rated to only 10kA– Fuse operates for all faults above say 7 kA– Contactor and associated protection relay operate for
lower fault levels– Warning … the fuse may also have a minimum
breaking capacity and the contactor must be set to operate above this point
Slide 66
100 1 .103 1 .104 1 .1050.01
0.1
1
10
100
FuseRelay / ContactorFuse
Fuse Contactors
10kA Contactor operates for faults
below 7kA
Fuse operates for faults above 7kA
Fuse operation below 2kA is not
permissible
Page 1
Voltage TransformersCurrent Transformers
Fundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 1
Fundamental Principlesof
Power System Protection
Slide 1Slide 1
VOLTAGE andCURRENTTRANSFORMERS
Slide 2
DIST
Basic Concepts of Distance Protection
Measure V/IIf this falls below some preset value, a fault is detected and relay operates
faultZ=I
V
Zfault
Slide 3
Fundamental Principlesof
Power System Protection
Slide 3Slide 3
VOLTAGETRANSFORMERS
Specification to AS60044.1
Slide 4
Specification of VTsAS1243 (Superseded by AS60044)
555P
222P
111P
Phase displacement (crad)
Percentage voltage ratio errorProtection Class
1 crad = 34.4 mins1 crad = 34.4 mins
Slide 5
AS60044 : Specification of VTs
Percentage voltagePercentage voltage
2402402404806.06.06.012.06P
1201201202403.03.03.06.03P
FV10052FV10052
Phase displacement(minutes)
Ratio error(percent)
Protection Class
Slide 6
AS60044 : Specification of VTs
Protection VTs to operate between– V = 0.05 pu– V = Voltage Factor : FV pu
8 h1.9
Phase – earth in isolated neutral system
Continuous1.230 s1.9
Phase – earth in non- effectively earthed neutral system w e/f tripping
Continuous1.230 s1.5
Phase – earth in effectively earthed neutral system
Continuous1.2SystemRated TimeRated Voltage Factor
Page 2
Voltage TransformersCurrent Transformers
Fundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 7
AS60044 : Specification of VTs
Voltage Error– KN = rated transformation ratio– UP = actual primary voltage– US = actual secondary voltage
Phase displacement– Primary and secondary voltage phase difference– Said to be positive when the secondary voltage leads
the primary
100%__ •⋅−
=P
SNP
UUKUErrorVoltage
Slide 8
Fundamental Principlesof
Power System Protection
Slide 8Slide 8
VOLTAGETRANSFORMERS
Transient Performance
Slide 9
VT Fundamentals
Magnetic VTs– HV systems
Capacitor VTs– EHV systems
Requirements of VT plus Relay– In Zone Faults– Out of Zone Faults– Switching
Slide 10
Magnetic Voltage Transformer Energisation & De-energisation
Minimal problems with magnetic VT transient performance– Transient effects typically short term
Energisation– Flux Doubling depending on POW switching– OK since VT’s are designed to operate at low flux densities
(also minimises errors in normal operation)De-energisation
– Flux cannot immediately decay to zeroPrimary Fault
– Collapse of voltage on fault occurrence– Recovery of voltage on fault clearance
Slide 11
Capacitor Voltage Transformer
Use a voltage divider principle to reduce system HV voltage to a lower levelAnd then use a lower ratio transformer to …– provide final step down ratio to protection relay– provide galvanic isolation
Voltage divider implemented via capacitorsLoading effects eliminated via series tuning choke
Slide 12
V
RL . VRH + RL
RL
RH
N:1
ZL
Resistive losses – heating effectsPerformance varies with load burden
Voltage Divider Principles
Voltage across RH varies with current supplied to VT burden, ZL
Page 3
Voltage TransformersCurrent Transformers
Fundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 13
Thevenin Equivalent Circuit
RL.RHRL+RH
RL.VRL+RH
ZL
Equivalent to resistors in parallel !! Intermediate VT voltage
source reduces as burden current increases => errors !!
Slide 15
V
CH
CL ZL
N:1X
Resistive losses – nilPerformance at 50Hz does not vary with load burden
CH . VCH + CL
Capacitor Voltage Transformers : CVTs
Slide 16
CVT Thevenin Equivalent Circuit
CH+CL
ZLCH.VCH+CL
X
Equivalent to capacitors in parallel !!
• Capacitive divider and series tuning choke with identical impedance at 50Hz.
• Impedances cancel.
Slide 17
CVT Thevenin Equivalent Circuit
CH+CL
ZLCH.VCH+CL
X
• Capacitive divider and series tuning choke with identical impedance at 50Hz.
• Impedances cancel.• CVT loading effects eliminated
CH.VCH+CL
Slide 19
CVT Transient Performance
Resonances– Low frequency transient response between …
Intermediate VT magnetising branchThevenin equivalent of main capacitors
– High frequency transient response between …Tuning chokeCapacitance of intermediate VT
Slide 20
CVT Transient Performance
Resonant effects minimised via simple resistive damping
CH+CL
ZLCH.VCH+CL
N2ZL
High Frequency
Low Frequency
RP XP XS RS
XM RM CM
X
Page 4
Voltage TransformersCurrent Transformers
Fundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 21
CVTs and Distance Relay Performance
Distance Relay Reach Measurement– Accuracy at Zone reach
Distance Relay Directionality– Immunity to tripping on reverse faults
Distance Relay Problems– Spurious operation on transients
Eg. On simple de-energisation of feeder
Modern Relays– May have special facilities to provide for CVTs
Slide 22
Fundamental Principlesof
Power System Protection
Slide 22Slide 22
CURRENTTRANSFORMERS
Specification to AS60044.1andComparison with AS1675
Slide 23
Specification of CTsAS1675 (Superseded by AS60044.1)
Class P CTs– Equivalent to IEC P Class CTs
General purpose protection CT– Not usually used in HV systems– Not usually used in high speed
differential systems– Suitable for slower speed systems
where perhaps a few cycles of distorted output will not seriously affect relay performance (eg IDMT & Def Time relays)
Not generally intended for applications requiring good transient performanceTurns compensation is permissible
10 P 60 F15
Composite error % at accuracy limit current
Composite error % at accuracy limit current
Secondary ref voltage
at ALF
Secondary ref voltage
at ALF
Accuracy limit factorAccuracy limit factor
Slide 24
Specification of CTsAS1675 (Superseded by AS60044.1)
Class P CTsComposite Error
– RMS value of the errors in the instantaneous values of the actual secondary current expressed as a percentage of the nominal secondary current
– (ie. Basically the CT error, but via instantaneous values to allow for both magnitude and phase errors) .. See next slide !!
Secondary reference voltage– RMS value of the secondary terminal voltage on which the
performance of the CT is basedAccuracy limit factor
– Factor (applied to the rated primary current) for the accuracy limit of the CT
– ie. Factor (applied to the rated primary current) for which the CT will comply with the requirements for composite error
– If not specified … F20 is assumed
Slide 25
Specification of CTsAS1675 (Superseded by AS60044.1)
Class P CTsComposite Error
KN = Rated transformation ratioIP = RMS value of primary currentiP = instantaneous value of primary currentiS = instantaneous value of secondary currentT = duration of 1 cycle
( )∫ ⋅−⋅⋅⋅=T
PSNP
C dtiiKTI
E0
21100
Square of sum of squares to compute the RMS value of the
difference between the instantaneous values of the nominal and actual currents
Slide 26
Specification of CTsAS1675 comparison with AS60044.1
To convert P Class specification to IEC Specification
– AS1675 Class P CT 100/5 5 P 60 F 20
– IEC Class P CT 100/5 15 VA Cl 5 P 20
Composite Error
Composite Error
Page 5
Voltage TransformersCurrent Transformers
Fundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 27
Specification of CTsAS1675 comparison with AS60044.1
To convert P Class specification to IEC Specification
– AS1675 Class P CT100/5 5 P 60 F 20
– IEC Class P CT100/5 15 VA Cl 5 P 20
Accuracy Limit Factor
Accuracy Limit Factor
Slide 28
Specification of CTsAS1675 comparison with AS60044.1
To convert P Class specification to IEC Specification
– AS1675 Class P CT100/5 5 P 60 F 20
– IEC Class P CT100/5 15 VA Cl 5 P 20
Terminal Voltage Specified
at FAULT Current
Connected Burden Specified
at LOAD Current
Slide 30
CT Assignment : Class P CTs
What is the maximum fault level (Primary Amps) where the CT performance is guaranteed?
A Current transformer, for general purpose use in an application NOT requiring good transient performance has been specified, as per AS60044.1 as …
200/1 5VA Class 5 P20
CTpri x ALF = 200 x 20 = 4000A
Slide 31
CT Assignment : Class P CTs
At this fault level, what is the maximum secondary burden [ie. leads plus relay(s)] in OHMS that the CT can supply.
A Current transformer, for general purpose use in an application NOT requiring good transient performance has been specified, as per AS60044.1 as …
200/1 5VA Class 5 P20
Rated Burden = VA x 1 x 1 = 5 x 1 x 1 = 5 OhmsA A 1 1
Slide 32
CT Assignment : Class P CTs
What will the CT terminal voltage be under this condition
A Current transformer, for general purpose use in an application NOT requiring good transient performance has been specified, as per AS60044.1 as …
200/1 5VA Class 5 P20
Vct = I x R = (Isec x ALF) x R = (1 x 20) x 5 = 100V
Page 6
Voltage TransformersCurrent Transformers
Fundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 33
CT Assignment : Class P CTs
What is the equivalent (ie. old) AS1675 specification for this CT
A Current transformer, for general purpose use in an application NOT requiring good transient performance has been specified, as per AS60044.1 as …
200/1 5VA Class 5 P20
200/1 5P 100 F20
Slide 34
CT Assignment : Class P CTs
Is this CT adequate to supply the connected burden of 6 ohms at this site specific fault level of 3kA.
At fault levels below ALF, we can confirm operation provided rated terminal voltage is not exceeded
It turns out that at the particular substation where this CT is installed, the maximum fault level is actually only 3kA.The connected burden of leads and relay is however 6 ohms.
200/1 5VA Class 5 P20
Vct = I x R = 3000 x 6 = 15 x 6 = 90V … OK !!200
Slide 35
CT Assignment : Class P CTs
Comment on the suitability of using this CT at the 3kA fault location, but now with a connected burden of 7 ohms.
At fault levels above ALF, or if rated terminal voltage is exceeded, we also need to know CT internal resistance to confirm suitability.
Now, tests on the CT reveal that it has an internal resistance of 1 ohm.
200/1 5VA Class 5 P20
Vknee = Vterm + Ialf x Rct = 100 + 20 x 1 = 120V
Vreq = I x Rtot = 15 x (7 + 1) = 15 x 8 = 120V … OK
Slide 42
Class PX CTs : AS60044.1
Class PL CTs under AS1675Applications requiring good transient performance
– High accuracy high speed schemes
General– Jointless core wound from
continuous strip– Turns for each section of the
winding to be uniformly distributed
– Turns compensation not permissible
0.1 PX 200 R5
Magnetising current at knee point voltage
Magnetising current at knee point voltage
CT knee point voltage
CT knee point voltage
CT internal resistance
CT internal resistance
10% increase in voltage requires a 50% increase in magnetising current
Slide 43
CTs with multiple tappings
Because the Class PX CT has a uniformly wound secondary winding, it may be possible to utilise intermediate ratiosFor CT with n terminals, ½.n.(n-1) ratios may be available
– CT specified as 2400/2000/800/1– May also provide 400/1200/1600/1
Beware of simple interpolation between ratios … but in general
– Resistance α Ratio (number of turns)– Voltage α Ratio (number of turns)– Magnetising current α 1/Ratio (inverse of turns)
Recommended to confirm performance of intermediate ratios with the manufacturerCT continuous rating
– Rating of primary conductor– Rating of secondary : perhaps 2 x In
2400
2000
800
1200/1
Slide 44
Fundamental Principlesof
Power System Protection
Slide 44Slide 44
CURRENTTRANSFORMERS
Transient Performance
Page 7
Voltage TransformersCurrent Transformers
Fundamental Principles ofPower System Protection
May 2012© Barrie Moor
Basic CT Requirement : No Transients
( )V ICT
R R RKNEEFAULT
RATIOCT LEADS RELAY= ⋅ + +
Ifault
Isec
Rct RleadsVk Rrelay
v t( ) Vm sin ω t⋅( )⋅:= E Ldidt⋅:=
i t( ) Im sin ω t⋅π2
−⎛⎜⎝
⎞⎠
⋅:=
0 0.01 0.02 0.03 0.04 0.05 0.06 0.07 0.08 0.09 0.14
3
2
1
0
1
2
3
4Fault Current : Inductive Power System
Seconds
v t( )
i t( )
t
Current lags voltage by 90ºCurrent cannot changeinstantaneously
v t( ) Vm sin ω t⋅( )⋅:= E Ldidt⋅:=
Fault_Point 0.025= i t( ) if t Fault_Point< 0, Im sin ω t⋅π2
−⎛⎜⎝
⎞⎠
⋅,⎛⎜⎝
⎞⎠
:=
0 0.01 0.02 0.03 0.04 0.05 0.06 0.07 0.08 0.09 0.14
3
2
1
0
1
2
3
4Fault Current : Inductive Power System
Seconds
v t( )
i t( )
t
OKI = 0 at fault inceptionI lags V by 90 deg
v t( ) Vm sin ω t⋅( )⋅:= E Ldidt⋅:=
Fault_Point 0.020= i t( ) if t Fault_Point< 0, Im sin ω t⋅π2
−⎛⎜⎝
⎞⎠
⋅,⎛⎜⎝
⎞⎠
:=
0 0.01 0.02 0.03 0.04 0.05 0.06 0.07 0.08 0.09 0.14
3
2
1
0
1
2
3
4Fault Current : Inductive Power System
Seconds
v t( )
i t( )
t
NOT OKI is not 0 at fault inception
v t( ) Vm sin ω t⋅( )⋅:= E Ldidt⋅:=
Fault_Point 0.020= i t( ) if t Fault_Point<( ) 0, Im sin ω t⋅π2
−⎛⎜⎝
⎞⎠
⋅ DC_Offset+,⎡⎢⎣
⎤⎥⎦
:=
0 0.01 0.02 0.03 0.04 0.05 0.06 0.07 0.08 0.09 0.14
3
2
1
0
1
2
3
4Fault Current : Inductive Power System
Seconds
v t( )
i t( )
t
DC_Offset 100% Im⋅=
NOW OKI = 0 at fault inceptionI lags V by 90 degBut now there is DC offset
v t( ) Vm sin ω t⋅( )⋅:= E Ldidt⋅:=
Fault_Point 0.030= i t( ) if t Fault_Point< 0, Im sin ω t⋅π2
−⎛⎜⎝
⎞⎠
⋅,⎛⎜⎝
⎞⎠
:=
0 0.01 0.02 0.03 0.04 0.05 0.06 0.07 0.08 0.09 0.14
3
2
1
0
1
2
3
4Fault Current : Inductive Power System
Seconds
v t( )
i t( )
t
NOT OKI is not 0 at fault inception
Page 8
Voltage TransformersCurrent Transformers
Fundamental Principles ofPower System Protection
May 2012© Barrie Moor
v t( ) Vm sin ω t⋅( )⋅:= E Ldidt⋅:=
Fault_Point 0.030= i t( ) if t Fault_Point<( ) 0, Im sin ω t⋅π2
−⎛⎜⎝
⎞⎠
⋅ DC_Offset+,⎡⎢⎣
⎤⎥⎦
:=
0 0.01 0.02 0.03 0.04 0.05 0.06 0.07 0.08 0.09 0.14
3
2
1
0
1
2
3
4Fault Current : Inductive Power System
Seconds
v t( )
i t( )
t
DC_Offset 100− % Im⋅=
NOW OKI = 0 at fault inceptionI lags V by 90 degBut now there is DC offset
Slide 56
DC Offset in the fault current waveform
Faults occurring away from voltage peak will result in DC offset in the fault current waveformUp to 100% DC offset is possibleDC offset may be positive or negativeBut the power system is not purely inductive, so the DC offset will not continue but will decay exponentially
Primary Transient Fault Current
System Parameters R 1 L .1 =LR
0.1 sec =.ω L 31.416
=φ 88.177 deg =.ω L
R31.416
θ φ .90 deg =θ 1.823 deg
2
1
0
1
2
0 0.02 0.04 0.06 0.08 0.1 0.12 0.14 0.16 0.18 0.2
AC ComponentDC Component
SECONDS
Primary Transient Fault Current
System Parameters R 1 L .03 =LR
0.03 sec =.ω L 9.425
=φ 83.943 deg =.ω L
R9.425
θ φ .90 deg =θ 6.057 deg
2
1
0
1
2
0 0.02 0.04 0.06 0.08 0.1 0.12 0.14 0.16 0.18 0.2
AC ComponentDC Component
SECONDS
Primary Transient Fault Current
System Parameters R 1 L .01 =LR
0.01 sec =.ω L 3.142
=φ 72.343 deg =.ω L
R3.142
θ φ .90 deg =θ 17.657 deg
2
1
0
1
2
0 0.02 0.04 0.06 0.08 0.1 0.12 0.14 0.16 0.18 0.2
AC ComponentDC Component
SECONDS
Slide 60
DC Offset in the fault current waveform
DC component of the fault current will magnetise the CT coreIf the CT core becomes fully magnetised (ie. above its knee point) it cannot transform the primary current to a proportional secondary quantity.
Page 9
Voltage TransformersCurrent Transformers
Fundamental Principles ofPower System Protection
May 2012© Barrie Moor
⎥⎥⎦
⎤
⎢⎢⎣
⎡+⋅=+
systempower
systempowerACDCAC R
XpeakPEAK
_
_)( 1φφ
5
0
5
10
15
20
25
30
35
0 0.1 0.2 0.3 0.4 0.5
AC FluxDC FluxTotla Flux
CT Flux (times AC component)
Seconds
Total Flux : AC Component plus DC ComponentTotal Flux : AC Component plus DC Component
AC FluxDC FluxTotal Flux
B
H
V
Imag
CT terminal voltage is low based on E = N dφ/dtie Simply enough to drive current through the connected burdenBut in specifying a high flux capability we, by default, have a high voltage capabilityThe high knee point is required because of the flux, not the voltage requirements
Slide 63
⎥⎦⎤
⎢⎣⎡ +⋅=+ 1
11)( RX
peakPEAK ACDCAC φφ
CT Specification to provide forTotal Flux : AC & DC Components
For purely sinusoidal quantities, the VT voltage and flux requirements are directly related
So, we can effectively specify the AC & DC flux requirements by specifying the proportional AC sinusoidal voltage requirements
NV⋅
=ω
φ maxmax
Slide 64
V V XRKNEE ACpeak peak
= ⋅ +⎡⎣⎢
⎤⎦⎥
1 11
V V XRKNEE ACrms rms
= ⋅ +⎡⎣⎢
⎤⎦⎥
1 11
( )V ICT
R R RKNEEFAULT
RATIOCT LEADS RELAY= ⋅ + +
To provide for the AC Component only
( )V ICT
XR
R R RKNEEFAULT
RATIOCT LEADS RELAY= ⋅ +⎡
⎣⎢⎤⎦⎥⋅ + +1
To provide for the AC & DC Components
⎥⎦⎤
⎢⎣⎡ +⋅=+ 1
11)( RX
peakPEAK ACDCAC φφ
Specify CT Voltage requirement to provide for the AC & DC Flux requirements
5
0
5
10
15
20
25
30
35
0 0.1 0.2 0.3 0.4 0.5
AC FluxDC FluxTotla Flux
CT Flux (times AC component)
Seconds
( )V ICT
XR
R R RKNEEFAULT
RATIOCT LEADS RELAY= ⋅ +⎡
⎣⎢⎤⎦⎥⋅ + +1
AC FluxDC FluxTotal Flux
Slide 66
CT Transient Performance
CT must cope with exponentially decaying DC component of fault currentNormal practice is to allow transient factor of (1 + X/R)– At Relaying Point– Or at Zone 1 Reach Point
Beyond the scope of our discussion– CT saturation, after relay operation, may be acceptable– Modern microprocessor based relay algorithms may
accommodate some CT saturation
Page 10
Voltage TransformersCurrent Transformers
Fundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 67
CT Assignment : Class PX CTs
A distance relay is employed on a simple radial 132kV system, with source and feeder impedances as per sketchAll figures are on 100 MVA base.System operates at nominal voltage – ie. Source voltage = 1 /0ºDistance relay Zone 1 will be set to 85% of the outgoing feeder
ZS = 0.05 /85º Zfdr = 0.10 /75º
132kVDistance Prot
Slide 68
CT Assignment : Class PX CTs
Calculate the relay current (in Amps) for a 3φ fault occurring just in front of it, namely, at the relaying point.Calculate the fault current (in Amps) for a 3φ fault occurring at the proposed 85% zone 1 reach point.
ZS = 0.05 /85º Zfdr = 0.10 /75º
132kVDistance Prot
Slide 69
Ibase100 MVA⋅
132 kV⋅ 3⋅:= Ibase 437.387= Zs rect 0.05 85 deg⋅,( ):=
Zfdr rect 0.10 75 deg⋅,( ):=
Ztot Zs:=
Ifault1
Ztot:= Ifault 1.743 19.924i−= Ifault 20=
arg Ifault( ) 85− deg=
XR tan arg Ifault( )−( ):= XR 11.43=
Ifault Ifault Ibase⋅:= Ifault 8748=
3φ Fault at Relaying Point
Slide 70
Ibase100 MVA⋅
132 kV⋅ 3⋅:= Ibase 437.387= Zs rect 0.05 85 deg⋅,( ):=
Zfdr rect 0.10 75 deg⋅,( ):=
Ztot Zs 85 %⋅ Zfdr⋅+:=
Ifault1
Ztot:= Ifault 1.457 7.29i−= Ifault 7.434=
arg Ifault( ) 78.701− deg=
XR tan arg Ifault( )−( ):= XR 5.005=
Ifault Ifault Ibase⋅:= Ifault 3251=
3φ Fault at Zone 1 85% Reach Point
Slide 71
CT Assignment : Class PX CTs
Lead resistance is 2 ohms (loop total)Connected relay burden is 1 ohmFor the fault at the relaying point, check and comment on the transient performance of the CT.For the fault at the proposed Zone 1 reach point, check and comment on the transient performance of the CT.
ZS = 0.05 /85º Zfdr = 0.10 /75º
132kVDistance Prot
VT = 132000/110 voltsCT = 600/1 0.1 PX 600 R 5VT = 132000/110 voltsCT = 600/1 0.1 PX 600 R 5
3251AX/R=5
8748AX/R=11
Slide 72
CT Performance : 0.1 PX 600 R53φ Fault at Relaying Point
Ztot Zs:=
Ifault1
Ztot:= Ifault 1.743 19.924i−= Ifault 20=
arg Ifault( ) 85− deg=
XR tan arg Ifault( )−( ):= XR 11.43=
Ifault Ifault Ibase⋅:= Ifault 8748=
Half of lead loop resistance for 3φ fault
CT 600V knee point is INADEQUATE
CT6001
:= IrelayIfaultCT
:= Irelay 14.58=
Rct 5:=Leads 2:=Relay 1:=
Vk Irelay 1 XR+( )⋅ Rct 0.5 Leads⋅+ Relay+( )⋅:= Vk 1269=
Page 11
Voltage TransformersCurrent Transformers
Fundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 73
CT Performance : 0.1 PX 600 R53φ Fault at Zone 1 85% Reach Point
Ztot Zs 85 %⋅ Zfdr⋅+:=
Ifault1
Ztot:= Ifault 1.457 7.29i−= Ifault 7.434=
arg Ifault( ) 78.701− deg=
XR tan arg Ifault( )−( ):= XR 5.005=
Ifault Ifault Ibase⋅:= Ifault 3251=
Half of lead loop resistance for 3φ fault
CT 600V knee point is ADEQUATE
CT6001
:= IrelayIfaultCT
:= Irelay 5.419=
Rct 5:=Leads 2:=Relay 1:=
Vk Irelay 1 XR+( )⋅ Rct 0.5 Leads⋅+ Relay+( )⋅:= Vk 228=
Slide 74
Transient Performance Equation Aspects
How to determine X/R of power system?– Current angle from fault study simulation
Transient performance for close-in faults?– High fault level & high X/R
Transient performance for Zone 1 faults?– Lower fault level & lower X/R due to fdr impedance.
Transient performance for 3 phase faults?– No neutral return current in CT secondary wiring
Transient performance for 1 phase faults– Neutral return current in CT secondary wiring
Page 1
Distance ProtectionFundamentals of Performance
Fundamental Principles ofPower System Protection
October 2010© Barrie Moor
Slide 1
Fundamental Principlesof
Power System Protection
Slide 1Slide 1
DISTANCEPROTECTION
Fundamentals of Performance
VI= +Z Zline loadHealthy Conditions:-
Zs I
V
Z line
Z load
VI= Z faultFault Conditions:-
Zs
V
I
Z fault
Z line
Z load
Slide 4
DIST
TIME
DISTANCE RELAY TIME DISCRIMINATION
LOCATION
ZONE 3
ZONE 2
LOCATION
ZONE 1
DIST
DIST
TIME
ZONE 1
ZONE 2
ZONE 2
ZONE 3
ZONE 1
ZONE 3
Distance Relay Zones
Slide 5
Distance Relay : Basic Scheme
Basic Scheme
ZONE 2MEASURER
ZONE 2TIMEDELAY
ZONE 3MEASURER
ZONE 3TIMEDELAY
ZONE 1MEASURER
>1 TRIP
Slide 6
DIST DIST DIST DISTK L M
Zone 1 Zone 1
Zone 2 Zone 2
Zone 3
Time and Reach Coordinationof Distance Relays
TimeCoordination
TimeCoordination
ReachCoordination
ReachCoordination
Page 2
Distance ProtectionFundamentals of Performance
Fundamental Principles ofPower System Protection
October 2010© Barrie Moor
Slide 7
ZONE 2
NON-SWITCHED DISTANCE RELAY OPERATION
A-B
ZONE 2TIMER
TRIP
ZONE 1C-EA-E B-E A-B B-C C-A A-E B-E C-E B-C
ZONE 3TIMER
A-EB-C C-AZONE 3
B-E C-E A-B C-A
Non Switched Distance Relay
Slide 8
ZONE REACHSWITCHING NETWORK
ZONE 2TIMER
TRIP
B-CA-E B-EZONE 1C-E A-B C-A
ZONE 3
ZONE 3TIMER
A-E C-EB-E C-AB-CA-B
Zone Switched Distance Relay
Fdr
Z1
Z3
Z1/2
Slide 9
ZONE 2TIMER
INCREASEIMPEDANCE
SETTINGTO
ZONE 2 REACH
VOLTAGE&
CURRENTSWITCHINGNETWORK
C
VOLTS
N
TRIP
CURRENT
MEASURER
VOLTS
N
CURRENT
BA
CBA
E
STARTERS
A B C
INCREASEIMPEDANCE
SETTINGTO
ZONE 3 REACH
ZONE 3TIMER
STARTERTIMER
Fully Switched Distance Relay
Slide 15
Primary & Secondary Impedances
Vsecondary = Vprimary / VTratio
Isecondary = Iprimary / CTratio
ratio
ratio
primary
primary
ondarysec
ondarysec
VTCT
IV
IV
•=
ratio
ratioprimaryondarysec VT
CTZZ •=
Slide 16
Simple Distance Relay Comparator
So, firstly, provide a ZSEC replica impedance within the relay to establish the relay’s zone of operation
– A real element of resistive and inductive components in an electromechanical relay
– An algorithm in a microprocessor based relayAnd measure VSEC from the VTAnd measure ISEC from the CTThe actual fault impedance will be given by VSEC / ISEC
If VSEC / ISEC < ZREPLICA, fault is in the zone and relay tripsIf VSEC / ISEC > ZREPLICA, fault is out of zone and relay restrainsBut, how can we easily perform the V / I calculation and comparison with Z
Slide 17
Simple Distance Relay Comparator
Pass CT secondary current (“I”) thru relay replica impedance “Z”– This develops a relay internal, or “replica” voltage “IZ”– So, the R / X diagram has become a IR / IX voltage diagram, with
“I” simply being a constant of proportionality (Note: I at 0º)
R
X ZV
I
II
I
V
Page 3
Distance ProtectionFundamentals of Performance
Fundamental Principles ofPower System Protection
October 2010© Barrie Moor
Slide 18
Operating & Restraining QuantitiesSimple Distance Relay Comparator
Hence, simply compare magnitudes of V and I*Zr– Trip if V < I*Zr– Stable if V > I*Zr
Restraining Quantity : VOperating Quantity : I*Zr
And even though this is a voltage diagram where we compare V and IZ,the IR & IX axes are usually labelled simply as “R” & “X”, since “I” is just a constant of proportionality
VI ZR≤Trip Condition
IR
IZr
X
V
RZIV ×≤Alternatively …
I
I
Slide 19
SimpleBeam BalanceComparator
OperateQuantity
RestrainQuantity
Restrain = VOperate = I * Zr
Simple Amplitude Comparator
Slide 20
Distance Relay Operation
Distance relay does not …– Store Current I– Store Voltage V– Compute ratio V/I– Determine this to be impedance to the fault– Check to see if this impedance is less than some preset value– Trip or not trip accordingly
Distance relay simply …– Trips if the operating quantity lies inside the trip zone– Restrains if the operating quantity lies outside the trip zone– Operates in a simple “GO” / “NO GO” mode
Slide 21
Distance Relay Does :-
Trip if impedance falls inside a specified domain in the impedance plain
– Inside = Trip– Outside = No trip– On the edge = Maybe !!
V
Marginal
TripV
R
V
No Trip
I.Zr
X
Slide 22
Mho Circle Comparator
Consider the quantities– S1 = I.Zr - V– S2 = V
And set the operating criteria to be the angle between these quantities, not their magnitudeSelect 90º as the criteriaRemember that the diameter of a circle always subtends 90º at the circumferenceWe have thus established a circular characteristic, with diameter of : I.Zr
R
X
I.Zr
S2 = V
S1 = IZ - V
Slide 23
Induction Cup Comparator
I2
I1
Induction Cup Angle Comparator
Direction of rotation depends on the phase
angle between S1 & S2, either to open or close
the trip contacts
S1
S2
Page 4
Distance ProtectionFundamentals of Performance
Fundamental Principles ofPower System Protection
October 2010© Barrie Moor
Slide 24
Phase Angle Comparators
Characteristics easily implementedPronounced operation, especially at the relay characteristic anglePolarising is available– Healthy Phase Cross Polarising– Memory Polarising– Positive Sequence Polarising
Slide 25
Cross Polarising S I Zr VS V12= ⋅ −=
A
BC
k.Vbc /+90 deg
Contract for Reverse Fault
X
R
Expand for Forward Fault
S2 = Va + k.Vbc /+90 degS2 = Va + k.Vbc /+90 deg
Slide 26
Close-in Faults : MHO
Close-in faults are difficult to detect– For unbalanced faults, augment
S2 with some healthy phase voltage
– Modern microprocessor based relays will most likely use the positive sequence voltage.(ref slide 39)
– For 3 phase faults, augment S2 with some pre-fault memory voltage
– For 3 phase SOTF events, special SOTF logic is required
X
R
VSVZrIS
=−⋅=
21
Slide 27
R
X
Typical Mho Zones of Protection
Slide 28
R
X
Quadrilateral Characteristic
Slide 29
LOADR
XExport WattsImport Watts
Lagging pf
Leading pfLagging pf
Leading pf
Three Phase Load Limits
Page 5
Distance ProtectionFundamentals of Performance
Fundamental Principles ofPower System Protection
October 2010© Barrie Moor
Slide 30
3 Phase Load Limits
Remember to allow for emergency conditions– eg. A single feeder carrying the load normally shared by 2
feedersExcept for the impedance circle characteristic, load transfer will vary for …
– export and import conditions – and with power factor.
Allow a safety margin– And ensure the system operators are aware that the safety
margin has been includedAnd be aware that some relays have a different characteristic under 3 phase conditions
– This applies especially to old fully switched distance relays
Slide 31
R
QUADRILATERAL
X
Z1
Z2Feeder
Z3
Tall, narrow quadrilateral for long feeders : Good load transfer performance
Quadrilateral Characteristics
Slide 32
QUADRILATERAL
Feeder
X
R
Z2Z1
Z3
Short, wide quadrilateral for short feeders : Good
fault resistance coverage
Quadrilateral Characteristics
Slide 33
Load Encroachment Characteristic
Export Load near to unity pfImport Load near to unity pfCalculate impedance that corresponds to max loadLimit characteristics for export load (3 phase only)Import characteristic is OK in this example
Slide 34
Fundamental Principlesof
Power System Protection
Slide 34Slide 34
DISTANCEPROTECTION
Comparator Connections
Slide 35
Relaying Quantities
What Voltage will we apply to the relayWhat Current will we apply to the relay3 phase faults2 phase faults2 phase to earth faults1 phase to earth faults
Page 6
Distance ProtectionFundamentals of Performance
Fundamental Principles ofPower System Protection
October 2010© Barrie Moor
ZVIL =φ
φ
This could be used for detection of three phase faults.However, [except by default in the Earth Fault Comparator connection (see later)] it is not !
Vb
IcVc
Zl
Ib
IaVa
Zl
ZlVI
Z
ZV
I
ZVI
BC
BL
L
L
= ⋅
=⋅
=
2
2φφ
φ
φφ
φφ
. . . (1)
. . . (2)
First equation is not used, except for starters in older style switched distance relays.The Second equation is usedThis correctly detects three phase faults also.
ZlIcVc
Ia = 0
IbVb
Va
Zl
Zl
Iφφ = Ib – IcBut Ib = – Ic⇒ Iφφ = Ib – Ic = 2 Ib = 2 Iφ
Slide 38
φφ
φφ
IV
Z =BA
BA
IIVV
−−
= A
BC
AB
Phase – Phase Comparatorand 3 Phase Performance
Hence this φ-φ comparator also correctly detects 3 phase faults
A
A
IV
=
°∠⋅⋅°∠⋅⋅
=303303
A
A
IV
Slide 39
Source
RelayLocation
FaultLocation
Posi
tive
Sequ
ence
Net
wor
k
Z1s
Z1f
I1
Source
RelayLocation
FaultLocation
Neg
ativ
e Se
quen
ce N
etw
ork
Z2f
Z2s
I2
Source
RelayLocation
FaultLocation
Zero
Seq
uenc
e N
etw
ork
Z0f
Z0s
I0
Phase to Ground Example
= 0.10 = 0.10
= 0.15= 0.15
= 0.15
= 0.35
I = 1.0 I = 1.0 I = 1.0
V1 = 1 / 0º V2 = 0
V0 = -0.15
V0 = -0.50
V2 = -0.10
V2 = -0.25
V0 = 0
V1 = 0.90
V1 = 0.75
Source
RelayLocation
FaultLocation
Posi
tive
Sequ
ence
Net
wor
k
Z1s
Z1f
I1
Source
RelayLocation
FaultLocation
Neg
ativ
e Se
quen
ce N
etw
ork
Z2f
Z2s
I2
Source
RelayLocation
FaultLocation
Zero
Seq
uenc
e N
etw
ork
Z0f
Z0s
I0
At the relay location– Vph = 0.65 pu– Iph = 3 pu– Therefore …
= 0.10 = 0.10
= 0.15= 0.15
= 0.15
= 0.35
I = 1.0 I = 1.0 I = 1.0
V1 = 1 / 0º V2 = 0
V0 = -0.15
V0 = -0.50
V2 = -0.10
V2 = -0.25
V0 = 0
V1 = 0.90
V1 = 0.75
217.0365.0
IV
PH
PH ==
Wrong !?
⎟⎟⎠
⎞⎜⎜⎝
⎛⋅−
⋅⋅⋅+⋅=1
10101 3
3ZZZZIZIV φφ
PositiveSequence
FaultLocation
NegativeSequence
FaultLocation
ZeroSequence
FaultLocation
I1RelayLocation
ZS1
Z1
ZS2
I2RelayLocation
Z2
ZS0
I0RelayLocation
Z0
002211 ZIZIZIV ⋅+⋅+⋅=φ
( ) 00121 ZIZIIV ⋅+⋅+=φ
( ) 10001021 ZIZIZIIIV ⋅−⋅+⋅++=φ
( ) ⎟⎟⎠
⎞⎜⎜⎝
⎛⋅⋅−⋅+⋅=33
1
11001 Z
ZZZIZIV φφ
( ) 100 Z3 ⋅⋅⋅+= IKIV φφ
⎟⎟⎠
⎞⎜⎜⎝
⎛⋅−
=1
100 3
where......ZZZK
001 3 IKI
VZ
⋅⋅+=
φ
φ
How will this measure for a 3 phase fault ?
Residual Compensation for Earth Faults
Residually Compensated Phase Current
Phase Voltage
Page 7
Distance ProtectionFundamentals of Performance
Fundamental Principles ofPower System Protection
October 2010© Barrie Moor
Source
RelayLocation
FaultLocation
Posi
tive
Sequ
ence
Net
wor
k
Z1s
Z1f
I1
Source
RelayLocation
FaultLocation
Neg
ativ
e Se
quen
ce N
etw
ork
Z2f
Z2s
I2
Source
RelayLocation
FaultLocation
Zero
Seq
uenc
e N
etw
ork
Z0f
Z0s
I0
At the relay location– Vph = 0.65 pu– Iph = 3 pu– Residual Compensation …
– Therefore …
= 0.10 = 0.10
= 0.15= 0.15
= 0.15
= 0.35
I = 1.0 I = 1.0 I = 1.0
V1 = 1 / 0º V2 = 0
V0 = -0.15
V0 = -0.50
V2 = -0.10
V2 = -0.25
V0 = 0
V1 = 0.90
V1 = 0.75
150.014444.033
65.00I0K3I
VPH
PH =••+
=••+
Correct !!
4444.015.03
15.035.01Z31Z0Z0K =
•−
=•−
=
Slide 44
Distance Relay Comparator Connections
ZONE 2
NON-SWITCHED DISTANCE RELAY OPERATION
A-B
ZONE 2TIMER
TRIP
ZONE 1C-EA-E B-E A-B B-C C-A A-E B-E C-E B-C
ZONE 3TIMER
A-EB-C C-AZONE 3
B-E C-E A-B C-A
001 3 IKI
VZ
⋅⋅+=
φ
φ
φφ
φφ
IV
Z =1
Page 1
Protection SignallingFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 1
Fundamental Principlesof
Power System Protection
Slide 1Slide 1
DISTANCE PROTECTION
Protection Signalling
Slide 2
Distance Relay Zone Discrimination
DIST
TIME
DISTANCE RELAY TIME DISCRIMINATION
LOCATION
ZONE 3
ZONE 2
LOCATION
ZONE 1
DIST
DIST
TIME
ZONE 1
ZONE 2
ZONE 2
ZONE 3
ZONE 1
ZONE 3
Slide 3
AEMC Requirements(Australian Energy Market Commission)
National Electricity Rules : NER– Automatic Access Standards– To maintain system stability– To not constrain inter or intra regional power flows
Maximum Fault Clearance Times (milliseconds)
System Voltage kV Faulted End Remote End Breaker Fail
≥400kV 80 100 175
≥250kV to < 400kV 100 120 250
>100kV to < 250kV 120 220 430
≤ 100kV As necessary to prevent plant damage and meet stability requirements
Slide 5
Protection Signalling
AnalogueDigitalCommunications Bearers– Microwave– Fibre Optics (OPGW & ADSS)– Radio– Cable Carrier– Power Line Carrier– External Communications Network
Slide 6
Protection Signalling Equipment
External stand alone equipment– Duplex operation– Single signal– Multiple signals– Maintenance aspects
Built into protection relays– Duplex operation– Multiple signals– Maintenance aspects
Slide 7
Protection Signalling Schemes
Permissive Intertripping– Under Reaching– Over Reaching
Blocking IntertrippingDirect IntertrippingSeries Intertripping
Page 2
Protection SignallingFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 8
Fundamental Principlesof
Power System Protection
Slide 8Slide 8
PROTECTIONSIGNALLING
Permissive Intertripping
Slide 9
Permissive Intertripping
Applies primarily to non-switched distance relaysRemote end relay has a dedicated Zone 2 measurer– Zone 2 measurer has detected the fault but has to wait
for expiration of Zone 2 timer before tripping – Signal sent to ‘permit’ that measurer to trip in fast time
Two schemes in use …– Permissive ‘Underreaching’ ... PIT signal from Zone 1
(will not signal for faults beyond feeder end)– Permissive ‘Overreaching’ … PIT signal from Zone 2
(may signal for faults beyond feeder end)
Slide 10
Non-Switched Distance Relay
ZONE 2
NON-SWITCHED DISTANCE RELAY OPERATION
A-B
ZONE 2TIMER
TRIP
ZONE 1C-EA-E B-E A-B B-C C-A A-E B-E C-E B-C
ZONE 3TIMER
A-EB-C C-AZONE 3
B-E C-E A-B C-A
At the feeder remote end, one of these Zone 2 elements will have detected the fault, but has to wait for expiration of Zone 2 timer before tripping is allowed
Slide 11
PIR
ZONE 3MEASURER
ZONE 3TIMEDELAY
&
ZONE 2MEASURER
ZONE 1MEASURER
ZONE 2TIMEDELAY >1
PIS
TRIP
Permissive Underreaching
Slide 12
Permissive Underreaching
PUTT : Permissive Underreaching Transfer TripPermissive signal sent via the Zone 1 “underreaching” elementSimply implemented– No concerns since a signal is only sent when the fault
is actually on the protected feeder
Slide 13
ZONE 1MEASURER
ZONE 3MEASURER
ZONE 3TIMEDELAY
ZONE 2MEASURER
PIR &
ZONE 2TIMEDELAY
>1
PIS
TRIP
Permissive Overreaching
Page 3
Protection SignallingFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 14
Permissive Overreaching
POTT : Permissive Overreaching Transfer TripPermissive signal sent via the Zone 2 “overreaching”elementNot simply implemented– Concerns exist since a signal may be sent when the
fault is beyond the protected feeder
Slide 15
Fundamental Principlesof
Power System Protection
Slide 15Slide 15
PROTECTIONSIGNALLING
Blocking Intertripping
Slide 16
Blocking Signalling
Local end relay has Zone 2 set to trip in fast time.Remote end relay sends a signal to inhibit this fast Zone 2 trip.
Signal sent from B to 'Block'the fast Zone 2 of relay A
DISTA
TIME
ZONE 1
Reverse looking Blocking Zone
LOCATION
FAST ZONE 2
B
NORMAL ZONE 2
ZONE 3
Slide 17
>1ZONE 1MEASURER
ZONE 3TIMEDELAY
REVERSELOOKINGZONE 4
ZONE 3MEASURER
ZONE 2TIMEDELAY
ZONE 2SHORTTIMEDELAY
BR
ZONE 2MEASURER
&
BS
TRIP
Distance Relay Blocking Scheme
Slide 18
Blocking Signalling Considerations
Blocking delay timer coordination - Fast Z2 coordination delay setting must allow time for receipt of blocking signalFor security, 2 signals are sent– Different signalling paths
Guard fail scheme provides security in the case of communication system failure
Slide 19
BLK B
SYSTEM B
BLK A
SYSTEM A
Feeder 'Y' Protection
BS B
SYSTEM BSignalling Equipment
BS B
BS A
SYSTEM ASignalling Equipment
BS B
BS APOSBS A
Blocking Send
Page 4
Protection SignallingFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 20
BLK B
SYSTEM B
BLK A
SYSTEM A
SYSTEM BSignalling Equipment
BR B
GFB B
SYSTEM ASignalling Equipment
BR B
POSGFBGFA
BR A
BR A
GFB A BR B
BR A
Feeder 'Y' ProtectionPOS
DISTPROT
'Y'
OR
AND
≥1
&
≥1
BR_A
BR_B
GF_A
GF_B
InhibitFastZone 2
Blocking Receive & Guard Fail Logic
Slide 21
Fundamental Principlesof
Power System Protection
Slide 21Slide 21
PROTECTIONSIGNALLING
Direct IntertrippingSeries Intertripping
Slide 22
Direct Intertrip
Trips remote CB directlyUsed where security not paramountSingle DIT for back-up protection applications(eg. CB fail protection)Duplicate DIT for primary protection applications(eg. Line end transformer protection)– ‘X’ uses one signalling path– ‘Y’ uses a separate signalling path
Slide 23
CB FailProt DIS DIR
DIT for CB Fail Event
Slide 24
TransfProt Y DIS
TransfProt X
TransfProt Y
TransfProt X
DIS
DIS
DIS
DIR
DIR
DIR
DIR
Duplicate Direct Intertripping
Slide 25
Series Intertrip
Trips remote CB directlySecurity paramount– Increased security over direct intertripping– Reduced reliability compared with direct intertripping
Single SIT for back-up protection applications(eg. CB fail protection)– Two signals over separate paths
Duplicate SIT for primary protection applications(eg. Line end transformer protection)– ‘X’ uses two signals over one signalling path– ‘Y’ uses two signals over a second signalling path
Page 5
Protection SignallingFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 26
CB FailProt SIS SIR
Series Intertripping
Slide 27
SYSTEM B
SIT B
SIT A
SYSTEM A
Intertrip Cubicle
SIS A&BPOS
SYSTEM BSignalling Equipment
SIS B
SIS B
SYSTEM ASignalling Equipment
SIS A
SIS A
Series Intertrip Send
Slide 28
SYSTEM B
SIT B
SIT A
SYSTEM A
SYSTEM BSignalling Equipment
SIR B
SIR B
SYSTEM ASignalling Equipment
SIR A
SIR A
SIR A&B
Intertrip CubiclePOS
Series Intertrip Receive
Slide 29
TransfProt X
TransfProt Y
SIS
SIS
SIR
SIR
Duplicate Series Intertripping
Slide 30
SYSTEM B
SIT B1SIT B2
SYSTEM A
SIT A1SIT A2
SIS A2
POS
'Y' Intertrip Cubicle
SIS B
'X' Intertrip Cubicle
SYSTEM BSignalling Equipment
SIS B2
SIS B2
SIS B1
SYSTEM ASignalling Equipment
SIS A2
SIS B1
SIS APOS
SIS A1
SIS A1
Duplicate Series Intertrip Send
Slide 31
SYSTEM B
SIT B1SIT B2
SYSTEM A
SIT A1SIT A2
SIR B1
SYSTEM BSignalling Equipment
SIR B1
SIR B2
SIR B2
SYSTEM ASignalling Equipment
SIR A2
SIR A2
POS
SIR B
'Y' Intertrip Cubicle
SIR A
SIR A1
SIR A1'X' Intertrip Cubicle
POS
Duplicate Series Intertrip Receive
Page 6
Protection SignallingFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 32
Fundamental Principlesof
Power System Protection
Slide 32Slide 32
PROTECTIONSIGNALLING
Power Line Carrier
Slide 33
Power Line Carrier
HF signal sent over the transmission lineCoupling Equipment & Line traps– To allow signal injecting– To limit signal distribution
Slide 34
V
CH
CL ZL
N:1X
CH . VCH + CL
CVT’s & PLC Signal Injection
Inject HF Signal
Line Trap
Slide 35
CVT’s & PLC Signal Reception
XN:1
ZLCH + CL
CL CH . V
V
CHLine Trap
Receive HF Signal
Slide 36
Power Line Carrier
Low Power– Cannot be guaranteed to signal through a fault
OK for Blocking SchemesProbably OK for DIT & SIT schemes Some concerns for permissive schemes
– Low Power Permissive schemes do seem to work in any case – Quiescent Scheme
Low power under normal circumstances (guard tone)High Power to guarantee signalling through faults
Page 1
High Impedance Differential ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 1
Fundamental Principlesof
Power System Protection
Slide 1Slide 1
HIGH IMPEDANCE DIFFERENTIAL PROTECTION
Busbar ProtectionandGalvanically Connected Plant
Slide 2
SIMPLE !!
!Bus Zone Protection Requirements
Dependability– Must trip for all ‘in-zone’ faults
Discrimination– Must not trip for any ‘out-of-zone’ faults
Security– Against all sources of mal-tripping
Speed of operation– As quickly as possible
Dependability & Security
RELAY
Internal FaultSlide 4
CT Connections & Polarity
S2
P2
S1
P1
I1
I2
P2
S2
P1
I1 S1
I2
RELAY
Internal Fault
RELAY
External Fault
Page 2
High Impedance Differential ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 8
3 Phase CT Connections
CT MARSHALLING
HZ RELAY
Slide 9
Current Mismatch
CT Manufacturing VariationsInequality of CT BurdensCT Saturation– Highest Fault Current on CT exposed to through fault– Worst possible mismatch is
Total saturation of the CT on the faulted plantAll other CTs transform perfectly
Slide 10
15000A 5000A
RELAY
5000A
External Fault
5000A
External Fault & CT Saturation
RELAY
External Fault
Rlead
Rlead
Rct High Impedance
Relay
CT Saturates :Magnetising branch
impedance becomes zero
( )LEADSCTFAULTRELAY RRIV +⋅=
Slide 12
Setting Voltage and Margins
Fault current comprises …– AC Component– DC Component
Hence, employ a DC Stabilised Relay– No additional margin on the setting is required
And considering 0% / 100% CT saturation case– This in an unrealistically extreme case– 100% safety margin is automatically built in
So, no additional safety margin on setting is required
RELAY
Internal Fault
High Impedance
Relay
RELAYKNEE V2V ⋅≥
CTs will saturate under internal fault conditions.But relay operation is assured provided absolutely all
CTs meet the requirement …
Page 3
High Impedance Differential ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 14
CT Selection
All CTs to be the same ratioAll CTs to have Vk ≥ 2.Vsetting
– This is an absolute “MUST”– Preferably Vk ≥ 5.Vsetting
Need to know– Knee Point voltage– CT Resistance
Class Requirements– Not critical– But easiest to specify class “PX” CTs
CTs will almost certainly saturate under in-zone fault conditions– Not suitable for connection to other protection relays
0.1 PX 200 R5
Magnetising current at knee point voltage
Magnetising current at knee point voltage
CT knee point voltage
CT knee point voltage
CT internal resistance
CT internal resistance
Slide 15
Current Operated Schemes
Voltage operatedCurrent operated, incl stabilising resistorTypical current settings
– as low as possible, but– > 20% of plant rating– < 30% of fault current
20% setting is usually OK– Assuming the CT has
been selected to match plant rating
V = I.R = 0.2 x (200 + 10) = 42 volts
Relay0.2A
10 ohms
200 ohms
Slide 16
Summary
Ensure Stability under through faults
Ensure Operation for genuine ‘in-zone’ faults
Beware of short cut methods
– Do not simply set …
RELAYKNEE V2V ⋅≥
2VV KNEE
RELAY =
( )LEADSCTFAULTRELAY RRIV +⋅=
Preferably 5 times to optimise relay performance, but 2 is the absolute minimum to ensure
reliable relay operation
Preferably 5 times to optimise relay performance, but 2 is the absolute minimum to ensure
reliable relay operation
Slide 17
Fundamental Principlesof
Power System Protection
Slide 17Slide 17
HIGH IMPEDANCE DIFFERENTIAL PROTECTION
Application to other Plant
Slide 18
HZ Prot’n Application to Plant
Requires Galvanic ConnectionAll CT ratios the sameCan Apply To …– Busbars– Transformers– Generators & Motors– Capacitors– Reactors
Slide 19
DIFF
Auto Transformers
All CT ratios to be the same
This CT will carry maximum current and hence dictates ALL CT ratios
But this CT is internal and may have a single fixed ratio.Thus, must be specified correctly at time of purchase !!
Page 4
High Impedance Differential ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 20
REF
Restricted Earth Fault Protection
CT terminals “away” from protected object are connected
CT terminals “near” to protected object are connected
Slide 21
DIFFDIFF
A
DIFF
B C
Reactors – Earthed Neutral
Slide 22
DIFFDIFF
A
DIFF
B C
Reactors – Floating Neutral
“Floating” neutral bus is also protected
Page 1
Transformers andSequence Components
Fundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 1
Fundamental Principlesof
Power System Protection
Slide 1Slide 1
TRANSFORMERSandSEQUENCE COMPONENTS
DIFFERENTIAL PROTECTIONREQUIREMENTS
Slide 2
Transformer Current Flows
Star / Star Transformer : LV Earth Fault– Current flows in corresponding HV winding– Appears as EF on the HV system also
I1, I2 & I0I1, I2 & I0I1, I2 & I0I1, I2 & I0
Slide 4
Transformer Current Flows
Star / Star Transformer : LV Earth Fault– But, suppose we don’t have an upstream power system earth– However, consider the effect of adding a delta connected tertiary winding– HV line current flows in a 2:1:1 ratio– No I0 on the HV system as there is no path for neutral current flow
I1, I2I1, I2
I0I0
I1, I2 & I0I1, I2 & I0
So where did the I0 go ??So where did the I0 go ??
Slide 5
Transformer Current Flows
Star / Star Transformer : LV Earth Fault– Retain the delta connected tertiary winding– But, let’s reinstate the generator earth– Power system and delta winding zero sequence current flow
distributions will depend on their relative Z0 impedances
I1, I2 & I0I1, I2 & I0I1, I2, I0I1, I2, I0
I0I0
Slide 6
Transformers, Sequence Componentsand Differential Protection
Star/Star transformers, with a delta tertiary winding:– Will have a mismatch between zero sequence current flows
on the HV & the LV windings– It is thus necessary to exclude zero sequence current from
the differential relay protection algorithmsStar/Star transformers, without a delta tertiary winding:
– May still have a mismatch between zero sequence current flows on the HV & the LV windings
The transformer tank can act as a low quality “tertiary delta winding”
– It is thus still necessary to exclude zero sequence current from the differential relay protection algorithms
Slide 7
Transformer Current Flows
Delta / Star Transformer : LV Earth Fault– Current in corresponding HV winding only– Appears as phase to phase fault from the perspective
of the HV system
I1 & I2 onlyI1 & I2 only
So where did the I0 go ??So where did the I0 go ??
I1, I2 & I0I1, I2 & I0
Page 2
Transformers andSequence Components
Fundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 8
Transformer Current Flows
Delta / Star Transformer : LV phase to phase fault– Current in 2 LV windings – Current in 2 HV windings– Appears as 2:1:1 fault on the HV system
I1 & I2I1 & I2I1 & I2I1 & I2
Slide 9
Transformer Current Flows
Star / Delta Transformer : LV phase to phase fault– Current in all 3 LV windings – Current in all 3 HV windings– Appears as 2:1:1 fault on the HV system
I1 & I2I1 & I2I1 & I2I1 & I2
Slide 11
Sequence ComponentsTransformer LV ph-ph fault
30 deg
Consider B-C fault on the LV of either of …– Star Delta transformer– Delta Star transformer
30 deg phase shift– Positive seq components– Negative seq components
… will shift + 30 deg… will shift - 30 deg
Slide 12
Sequence ComponentsTransformer LV ph-ph fault
LV phase to phase fault– A phase I1 & I2 cancel– B & C phase I1 & I2 are 60o apart
HV distribution is 1 : 2 : 1– I1 & I2 are shifted ±30o across the transformer– On two of the HV phases, I1 & I2 are now 120o apart– On one of the HV phases, I1 & I2 are now exactly in phase !!
30 deg
LVHV
Slide 13
Transformers, Sequence Componentsand Differential Protection
Compensate for the transformer phase shiftExclude zero sequence current from the differential relay protection scheme– Zero sequence current can flow into and out of
earthed star windings– Zero sequence current cannot flow into or out of delta
windings– Zero sequence current can circulate around delta
windings (said to be “trapped” in the delta)
Page 1
Transformer ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 1
Fundamental Principlesof
Power System Protection
Slide 1Slide 1
TRANSFORMER PROTECTION
Slide 3
Types of Fault
Phase-ground faults - from winding to core or winding to tankPhase-phase faults - between windings Interturn faults - between single turns or adjacent layers of the same winding (Buchholz)Arcing contactsLocal hotspots caused by shorted laminations Low level internal partial discharges (moisture ingress or design problems)Bushing faults (internal to the tank)Tapchanger faults (often housed in a separate tank)Terminal faults (external to the tank, but inside the transformer zone)
Slide 4
Buchholz Protection
Two floats in the relay:– Upper float
detects accumulation of gasdetects loss of oilIncipient faults
– Partial discharge– Winding & core overheating– Bad contacts and joints
May alarm only or may be set to trip– Lower float
detects surge in oil < 100msalthough it does take a finite time for pressure waves to initiate Buchholz tripping
To Conservator
Gas Sample
Trip
Alarm
BUCHHOLZ RELAY
Float
To Tank
Float
Slide 5
Pressure Relief Device – (Qualitrol)
Spring assisted pressure relief devicesRelieves pressure impulses due to massive internal fault conditions. Helps prevent the tank bursting or splittingRelay contacts are also connected to trip the transformer.
Since pressure waves travel with a finite velocity, they may rupture the tank locally before the pressure wave has reached the pressure relief device, if it is some distance away. Severalunits may therefore be required on larger transformers.
Slide 6
Basic Transformer Protection
Fuses– Transformers without CBs– Perhaps to a few MVA
Overcurrent & Earth Fault Protection– Transformers with CBs– Perhaps 5 - 50MVA
Differential Protection– Transformers > 10MVA
FastCan be sensitiveMay detect terminal faults also
Slide 7
Fundamental Principlesof
Power System Protection
Slide 7Slide 7
TRANSFORMER PROTECTION
Biased Differential Protection
Page 2
Transformer ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 8
Differential Protection
DifferentialRelay
DifferentialRelay
P1
S1
P1
S1
Slide 9
Differential Protection
DifferentialRelay
P1
S1
P2
S2
SIDE OF CT AWAY FROM PROTECTED PLANT CONNECTS
TO RELAY
CURRENT FLOWS INTO PLANT
CURRENT FLOWS OUT OF PLANT
CURRENT FLOWS INTO RELAY
CURRENT FLOWS OUT OF RELAY
SIDE OF CT AWAY FROM PROTECTED PLANT CONNECTS
TO RELAY
TRIPELEMENT
IT IS NOT THE P1/S1 OR P2/S2 ORIENTATIONS THAT ARE
IMPORTANT, BUT THE PREFERENCE FOR THE
“AWAY” SIDES OF THE CTs TO CONNECT TO THE RELAY
Slide 10
Differential Protection of Transformers
132/66kV
100/1 200/1100A 200A
1A 1A
BIAS orRESTRAINTELEMENT
BIAS orRESTRAINTELEMENT
TRIPPING ELEMENT DETECTS ONLY THE
MIS-MATCH CURRENT
TRIPELEMENT
Slide 11
Transformer Differential Mismatch
Transformer turns ratio & tap changingInrush on energisation (2nd harmonic)Over excitation (5th harmonic)CT MismatchSome CT Saturation on through faults Transformer phase shiftsEarth fault (neutral … zero sequence) currents
Slide 12
Inrush Current on Energisation of Transformer
TRIPELEMENT
Slide 13
Second Harmonic on Inrush
Transformer inrush current on energization.– Inrush current produces a current from the energizing
side only, appearing as an internal fault. – Inrush current magnitude can be as great as a through
3 phase fault.– This current is characterized by the appearance of
second harmonics, so additional restraint can be based on this 2nd harmonic “signature”
– Relay setting below the 2nd harmonic level is required(Ratio of 2nd harmonic to fundamental)
Page 3
Transformer ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 14
Transformer Inrush Current
2
0
2
4
6
8
10
12
0 0.05 0.1 0.15 0.2 0.25 0.3 0.35 0.4 0.45 0.5
Transformer Inrush Current
Current
Seconds
Second Harmonic on inrush
Slide 15
Fifth Harmonic on over excitation
Overfluxing, caused by too high a voltage, or too low a frequency. – Increased magnetising current– This is characterized by third & fifth harmonics. – Fifth harmonic restraint to retrain tripping of the differential
element– Typically no user calculations or settings are required
Sustained overfluxing may damage the transformer– Time delayed V/f tripping function (long time)– Especially applicable to generator transformers
Frequency can be anywhere from zero to nominal during run-up and run down
– Not so necessary for transmission or distribution applicationsFrequency will not deviate significantly from nominal
Slide 16
Unbalance Currents
Mismatched CTs– CTs do not exactly compensate for transformer turns
ratio– Transformer turns ratio changes with tap changing– Implement a “biasing” restraint system
Magnetizing current in the CTs, especially as some saturation due to DC fault current sets in. – The amount of bias is increased under heavy through
fault conditions to compensate for possible CT saturation
Slide 17
Bias Differential Protection
Allow for Transformer turns ratioAllow for Transformer phase shiftsEliminate Zero Sequence currents from the relaying system
OperatingWinding
P1S1
Bias Windings
P1S1
Slide 19
Fundamental Principlesof
Power System Protection
Slide 19Slide 19
TRANSFORMER PROTECTION
CONTINUED
Slide 20
CT Connections and Ratios
Star/Delta and Delta/Star transformers have a 30 degree phase shiftCompensate with CTs connected opposite to the transformer connections. ie:
– Star connected CTs on the delta side of the transformer– Delta connected CTs on the star side of the transformer
Phase shift compensatedZero sequence currents flowing in the transformer star windings prevented from entering the relaying systemBut how do we get the correct delta connection for our CTs ???
Page 4
Transformer ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 21
Determination of CT Connection
Diff Prot
Yd11D11D11
CT Primary is star connectedCT secondary is D11 connectedOverall connection is thus YD11
Slide 22
Determination of CT Connection
Dy11D1D1
Diff ProtCT Primary is star connectedCT secondary is D1 connectedOverall connection is thus YD1
Slide 23
Star/Delta and Delta/Star TransformersCT Connection Summary
Transformer HV is STAR connected– HV CTs are delta connected– HV CTs EQUAL to the transformer phase shift– LV CTs in star
Transformer LV is STAR connected– LV CTs delta connected– LV CTs OPPOSITE to the transformer phase shift– HV CTs in star
Slide 24
CT Connection Summary
Compensates for the phase shift across a star-delta transformer.– The correct vector group must be chosen for the CTs
to ensure that through currents balance.Prevents any zero sequence currents flowing in the star winding from entering the relay– Since they are not present in the line on the delta side.
And for Star / Star transformers ??– It is still necessary to eliminate Io from the relaying
system– Connect CTs delta / delta– Or use the D12 / D12 feature of microprocessor relays
Slide 25
A phase output is at "11 o'clock"
A phase "S1" connects to B phase "S2"B phase "S1" connects to C phase "S2"C phase "S1" connects to A phase "S2"
D11
S2
A
S1
S1C
S2
S1
S2B
C
B
A
CT YD11 Connections
D11D11
Slide 26
A phase output is at "1 o'clock"
A phase "S2" connects to B phase "S1"B phase "S2" connects to C phase "S1"C phase "S2" connects to A phase "S1"
A phase output is at "11 o'clock"
A phase "S1" connects to B phase "S2"B phase "S1" connects to C phase "S2"C phase "S1" connects to A phase "S2"
D11
S2
A
S1
S1C
S2
S1
S2B
D1
C
B
A
S2B
S2
S1
S1
A
S1CS2
C
B
A
CT YD1 Connections
D1D1
Page 5
Transformer ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
A B
Bias Windings
P1 P2
S1 S2
A1 A2
OperatingWindingsC
a2 a1P1P2
S2 S1
Notice that the connections for the Delta windings are the same !!
“Away” side of CTs connected to relay.Hence, transformer current “in” or “out”corresponds to relay current “in” or “out”.
“Away” side of CTs connected to relay.Hence, transformer current “in” or “out”corresponds to relay current “in” or “out”
Slide 28
Transformer Current Flows
There must be a path for the current to flowThere must be an Ampere Turns balanceIf there is current flowing in one winding– There must be current in the coupled winding
If there is no current flowing in one winding– There can be no current in the coupled winding
A B
Bias Windings
P1 P2
S1 S2
A1 A2
OperatingWindingsC
a2 a1P1P2
S2 S1
External Phase – Earth Fault
Protection Scheme remains balanced– HV 0:1:1 (HV looks like a phase – phase fault)– LV 0:0:1 (LV is actually a single phase fault)
A B
Bias Windings
P1 P2
S1 S2
A1 A2
OperatingWindingsC
a2 a1P1P2
S2 S1
External Phase – Phase Fault
Protection Scheme remains balanced – HV 1:2:1 (HV has a 2:1:1 current distribution)– LV 0:1:1 (LV is actually a phase – phase fault)
Slide 31
Delta CTs and Ratio Selection
CT ratios must allow for the fact that current flowing into the relay from the delta connected CTs is √3 times the CT secondary currentHence, a standard 1A CT will result in relay current of √3 times the CT secondary currentThus, CTs with ratios such as 1000/0.577 are, for this reason, quite common.
1 / 0
1 / -120
1 / -
240
= 1.732 /-30
1 / 0 – 1/-240
Slide 32
Delta CTs and Ratio Selection
Ia - Ic = 1.732 /-30
CT ratios must allow for the fact that current flowing into the relay from the delta connected CTs is √3 times the CT secondary currentHence, a standard 1A CT will result in relay current of √3 times the CT secondary currentThus, CTs with ratios such as 1000/0.577 are, for this reason, quite common.
1 / 0 – 1/-240
Page 6
Transformer ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 33
Modern Microprocessor Relays
All CTs connected in StarRelay has to “process” phase shiftsRelay has to “remove” neutral current
P1
P1
P1
S1
S1
S1
S1
S1
S1
P1
P1
P1
Slide 34
Modern Microprocessor Relays
P1
P1
P1
S1
S1
S1
S1
S1
S1
P1
P1
P1
ICIAIARELAY −=
IAIBIBRELAY −=
IBICICRELAY −=
⎥⎥⎥
⎦
⎤
⎢⎢⎢
⎣
⎡•
⎥⎥⎥
⎦
⎤
⎢⎢⎢
⎣
⎡
−−
−•=
⎥⎥⎥
⎦
⎤
⎢⎢⎢
⎣
⎡
ICIBIA
110011101
31
ICIBIA
RELAY
RELAY
RELAY
⎥⎥⎥
⎦
⎤
⎢⎢⎢
⎣
⎡•
⎥⎥⎥
⎦
⎤
⎢⎢⎢
⎣
⎡
−−
−•=
⎥⎥⎥
⎦
⎤
⎢⎢⎢
⎣
⎡
ICIBIA
110011101
31
ICIBIA
RELAY
RELAY
RELAY
IArelay
IBrelay
ICrelay
⎛⎜⎜⎜⎜⎝
⎞⎟⎟
⎠
1
3
1
1−
0
0
1
1−
1−
0
1
⎛⎜⎜⎝
⎞
⎠⋅
IA
IB
IC
⎛⎜⎜⎝
⎞
⎠:=
relay
D1
D11IArelay
IBrelay
ICrelay
⎛⎜⎜⎜⎜⎝
⎞⎟⎟
⎠
1
3
1
0
1−
1−
1
0
0
1−
1
⎛⎜⎜⎝
⎞
⎠⋅
IA
IB
IC
⎛⎜⎜⎝
⎞
⎠:=
relay
A phase output is at "1 o'clock"
A phase "S2" connects to B phase "S1"B phase "S2" connects to C phase "S1"C phase "S2" connects to A phase "S1"
A phase output is at "11 o'clock"
A phase "S1" connects to B phase "S2"B phase "S1" connects to C phase "S2"C phase "S1" connects to A phase "S2"
D11
S2
A
S1
S1C
S2
S1
S2B
D1
C
B
A
S2B
S2
S1
S1
A
S1CS2
C
B
A
Modern Microprocessor RelaysSlide 36
Modern Microprocessor Relays
All CTs can now be connected in Star– Relay internal processing adjusts for phase angle – Relay internal processing rejects zero sequence
componentsCT ratios mismatches can also now be accommodated– Internal processing within relay then adjusts CT
current to match transformer turns ratio– CTs can be fine tuned to match middle tap position– Allows for more sensitive relay settings
Slide 37
CT Phase and Ratio Adjustment
Dyn120MVA 33/11kV
1500/1400/1
DifferentialElement
350A 1050A
0.7A
-300
0.875A
00
00
1A
00
1A
Transformer Microprocessor Differential Protection Relay
• Magnitudes normalised to transformer FLC• Phase angles compensated• Zero sequence current eliminated
Yy0Software CT
x 1.143Software CT
x 1.429
Yd11
00 -300
TAP POSITION
Software CT Ratio
Adjustment
Transformer Bias Differential Protection
0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5 5.5 60
0.5
1
1.5
2
2.5
3
3.5
4
15% Differential Setting25% Differential Setting35% Differential Setting
Differential Current
Diff I1 I2+:=
Bias Current BiasI1 I2+
2:=
OPERATEOPERATE
Transformer Internal Fault
Protection Trips
Transformer Internal Fault
Protection Trips
Through Fault withCT Saturation
Through Fault withCT Saturation
Through FaultMismatch due to CT Ratios &Transformer Tap Changing
Through FaultMismatch due to CT Ratios &Transformer Tap Changing
RESTRAINRESTRAIN
Page 1
Low Impedance Busbar Differential ProtectionFundamental Principles of Power System Protection
May 2012© Barrie Moor
Slide 2
Fundamental Principlesof
Power System Protection
Slide 2Slide 2
LOW IMPEDANCEBUSBAR DIFFERENTIAL PROTECTION
Slide 3
Low Impedance Busbar Prot’n
Utilises Bias Restraint– 1 x 3 phase input for every item of plant
Often applied as a retrofitExpensiveAre not simple schemes
Slide 4
Basic Types
Central Unit– GE B30– SEL 487B– REB 670 & RED 521– Areva P746
Bay units with connection to central unit– Areva P740– ABB REB500
Slide 5
Special Features
Mismatched CTs– Applicable where CT ratios vary– Applicable where CT classes vary
Poor quality CTs– Increased operating current pickup– Reduced knee point for increase in bias– Increased bias slope– CT saturation algorithms
Slide 7
LZ Busbar Bias Differential Characteristic
Bias Current
OperatingCurrent
Through Fault
Internal Fault
Reduced knee point for
increase in bias
Increased bias slope
TRIPZONE
Increased operating
current pickup
Slide 8
CT Saturationand Through Fault Performance
Bias Current
OperatingCurrent
Through Fault
Internal Fault
TRIPZONE
CTSaturation
CTSaturation
Monitor the “locus” and use thisto detect CT saturation and restrain the
relay under through fault conditions
Monitor the “locus” and use thisto detect CT saturation and restrain the
relay under through fault conditions
Page 2
Low Impedance Busbar Differential ProtectionFundamental Principles of Power System Protection
May 2012© Barrie Moor
Slide 9
Special Features
CT problems accommodated– Mis-matched CTs– Poor quality CTs
Provide for multiple bus zones– One relay covers (say) up to 6 zones– Do not need separate CTs where zones overlap– Do not need separate CTs for Master & Check Zones
Allow for dynamic switching of bus zones– Requires Isolator status (a & b) inputs
Provide CB Fail and CB Fail Bus Trip Facilities
Slide 10
Multiple Bus Zones
Feeder and coupler CTs for BZ1 scheme
Feeder and coupler CTs for BZ2 scheme
Feeder CTs for overall check zone
Slide 12
Dynamic Switching of Bus Zones
Two separate BZ schemes
Checkzone
Slide 13
Dynamic Switching of Bus Zones
Diameter closed.Single BZ scheme for entire substation
Checkzone
Slide 14
Dynamic Switching of Bus Zones
Bus 2 disconnector now open.BZ schemes reconfigured OK.
Checkzone
Slide 15
Bus Zone CB Fail Protection
CB Fail for a bus zone fault– Fault on bus– CB Failure detected by BZ relay inbuilt CBF feature– BZ relay initiates tripping of remote CB(s)
Remote end CBs for plant connected to busNext bus for coupler or section CB failure
Page 3
Low Impedance Busbar Differential ProtectionFundamental Principles of Power System Protection
May 2012© Barrie Moor
Slide 16
CB Fail Protection & CBF Bus Tripping
CB Fail for a plant fault (eg feeder fault)– Plant protection detects fault and initiates tripping of its
CB(s)– Plant protection also initiates BZ relay inbuilt CBF feature
(via opto input)– CB Failure detected by BZ relay inbuilt CBF feature– BZ relay “knows” what bus the plant is connected to– BZ relay “knows” what other plant is connected to that bus– BZ relay initiates CBF Bus Trip of required CBs
Especially important for switched busbars– BZ relay is the only system that “knows” the busbar
topology !!
Page 1
Feeder Differential ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 1
Fundamental Principlesof
Power System Protection
Slide 1Slide 1
FEEDERDIFFERENTIAL PROTECTION
Pilot Wire Protection
Slide 2
Pilot Wire RelayingLimitations and Requirements
Pilot Length– Pilot Cost– Pilot Wire Resistance
Must not exceed relay design limitationsBut, add separate (padding) resistors to bring the pilots to the relay manufacturer’s design value (say 1000 ohms)
– Pilot Wire CapacitanceMay disable relay operation : circulating current schemeMay unstabilise relay operation : opposed voltage scheme
Relays at each feeder end tripping local CBs for– Strong infeed– Weak infeed– Zero infeed
Two Elements– Operating element - trips relay on mismatch– Bias element - restrains relay on through current
Slide 3
Circulating Current Scheme
Through current results in relay current circulating between line end relays
R R
OO
Slide 4
Circulating Current Scheme
Through current results in relay current circulating between line end relaysFeeder fault current results in current flowing in the relay operating elementsAnd the effect of Pilot capacitance ??
– Desensitises or even disables the relay operating elements
R R
OO
Slide 6
Opposed Voltage Scheme
Through current results in relay current circulating between line end relaysPilot wires crossed to create an opposed voltage schemeAnd reconfigure the operating and restraining elementsAnd the effect of Pilot capacitance ??
– Disables relay restraint : may trip on through faults
R R
OO
limited to relay restraint elements
R
O
R
O
Slide 7
Opposed Voltage Scheme
Feeder fault current results in current flowing in the relay operating elements
R R
OO R
O
R
O
Page 2
Feeder Differential ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 8
Summation Transformer
Allows comparison of composite quantityMust trip for all internal faultsMust be stable for all external faultsVarious sensitivities ..... OK
Slide 9
Summation Transformer
FAULT RELATIVETYPE PICK-UP
A-B 0.8AB-C 1.0AC-A 0.44AA-B-C 0.51AA-N 0.19AB-N 0.25AC-N 0.33A
SUMMATION TRANSFORMER
C
N
3
B
A
1
1.25
This arrangement ensures correct operation under 2:1:1 current distributions
Slide 10
Complete Scheme
PADDINGRESISTOR
SUMMATIONTRANSFORMER
PILOT WIRES
PADDINGRESISTOR
SUMMATIONTRANSFORMER
PILO
T WIR
ER
ELAY
TAPPEDPILOT ISOLATIONTRANSFORMER
TAPPEDPILOT ISOLATIONTRANSFORMER
STABILISINGRESISTOR
STABILISINGRESISTOR
PILO
T W
IRE
RE
LAY
Just a few ohms to improve stability under heavy through fault conditions
Tapped pilot isolation transformers R α Turns2
Padding resistance at each end to bring total pilot resistance to the relay specification requirements
Slide 11
Fundamental Principlesof
Power System Protection
Slide 11Slide 11
FEEDERDIFFERENTIAL PROTECTION
Digital Current Differential Protection
Slide 12
Digital Current Differential Schemes
Digital CommunicationsIndividual measurements per phaseChannel delay automatically compensatedData security checks– CRC & Parity bits
12
12.2 π1
i1
i2i3
i4
i5
i6i7
i8
( )
( )
IN
n t i
IN
i i n t i
S nn
N
CN
nn
N
= ⋅ ⋅ ⋅ ⋅⎡
⎣⎢⎤
⎦⎥
= ⋅ + + ⋅ ⋅ ⋅⎡
⎣⎢⎤
⎦⎥
=
−
=
−
∑
∑
2
22 2
1
1
0
1
1
sin
cos
ω
ω
∆
∆
Page 3
Feeder Differential ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 14
In-Phase & Quadrature Components
Slide 15
Current Differential Data Synchronisation
How can the local and remote end data samples by synchronisedGPSPing Pong Topology– Asynchronous Samples – Synchronised Samples
tA5tA*
tA6
tA4
tA1tB3
tp2
td
Current Vectors
Current VectorstA1
tA3
tB3*
tA2
td
tp1
RELAYA
tA1
tB6
tB5
tB4
tB3
tB*tB2
tB1
RELAYB
( )2
1*21 tdTAtAtptp −−==
Relay ping-pong system determines that it needs a sample at tB3, whereas samples exist at tA3 and tA4 … choose the closest.
Slide 18
Data alignment for non-synchronised schemes
Remote relay
samples
Localrelay
samples
Adjust the non-synchronised samples via
relay computation
algorithm
Adjust the non-synchronised samples via
relay computation
algorithm
Slide 19
Current Differential Data Synchronisation
Ping Pong Topology– Asynchronous Samples
Relay selects nearest available and uses the Ping Pong to adjust the non-synchronised samples via its computation algorithm
– Synchronised SamplesPing Pong system aligns the samples which can then be compared directly
– Both systems require equal send and receive times (paths) GPS Synchronisation
– Truly Synchronised Samples (time tagged)– Send and receive times (paths) do NOT have to match– Ping Pong Back-up
IS1
IS2
k1
k2
TRIPTRIP
( )ZYXBIAS
ZYXDIFF
III5.0I
IIII
++•=
++=
IS1=0.2 puIS1=0.2 pu
IS2=2.0 puIS2=2.0 pu
k1=30%k1=30%
k2=100%k2=100%
NO TRIPNO TRIP
Through Load or
Fault Event
Through Load or
Fault Event
Feeder Fault Event
Feeder Fault Event
BIAS CURRENT
IX IY
IZ
X
Z
Y
DIF
FER
ENTI
AL
CU
RR
ENT
Page 4
Feeder Differential ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 21
Alpha Plane Representation
Some relays now use the ratio of remote to local end feeder currents to define their characteristicThis will ideally be -1 under through load and through fault conditions
Slide 22
Alpha Plane Representation Ziegler : Numerical Differential Protection
RestrainRestrainTripTrip
Increasing Bias SlopeIncreasing Bias Slope “Conventional” Differential vs Restraint characteristics can also be represented on the alpha plane
TripTrip
RestrainRestrain
Slide 23
Alpha PlaneRestrain Zone Requirements
“Restrain Zone” must, as a minimum, be adjusted to provide for magnitude and angular deviation for …– Line charging current– CT saturation
Slide 24
Alpha PlaneBalance : Restrain & Trip Zone Requirements
Relay trip region needs to expand to accommodate angle variation under in-zone fault conditions. Similarly, the restrain zone needs to expand to ensure stability under through load and fault conditions.That is, allow for variations and simultaneously increase both zones to achieve the optimum.
Slide 25
Alpha PlaneSEL311L Recommendation
Trip Zone to ensure correct tripping for all in-zone faultsRestrain Zone to ensure stability for all external load and fault conditions195° recommended
– SEL advises that this allows 35°of margin for other sources of error
Slide 26
Current Differential Signalling
2 ended schemes – single comms3 ended schemes – dual commsDaisy chained schemes
Page 5
Feeder Differential ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 27
2 Ended Scheme – Single Comms
DIFF
DIFF
Slide 28
3 Ended Scheme – Dual Comms
DIFF
DIFF
DIFF
Slide 30
Daisy Chain Scheme : >3 Ended
Schemes covering up to 6 ended tee feeders are available
DIFF
DIFF
DIFF
A
B
C
IA
IA + IB
IC + ID
IB + IC + ID
DIFF
IA + IB + IC
ID
D
Slide 31
Daisy Chain Scheme : with Redundancy
DIFF
DIFF
DIFF
A
B
C
IA
IA + IB
IC + ID
IB + IC + ID
DIFF
IA + IB + IC
ID
Close the Daisy Chain– Redundant path is normally idle– Redundant path becomes active
when any other link is broken
D
Page 1
Auto ReclosingFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 1
Fundamental Principlesof
Power System Protection
Slide 1Slide 1
AUTO RECLOSING
EHV SystemsHV SystemsDistribution Systems
Slide 2
Application of Auto Reclosing
Most faults are single phaseMost faults are transientHence, an automatic reclosure is often provided to restore faulted feeders to service– To improve transient and voltage stability of the
system– To restore the system to normal levels of security– To restore supply to customers
Slide 3
Safety Aspects of Auto Reclosing
Auto Reclosing is usually blocked or inhibited for …Cases where the following plant may be affected– Cables– Transformers
Cases where the initial protection operation may have involved backup for …– CB Fail Event– Blind Spot Event– Failure of a remote protection scheme
Slide 4
Auto Reclosing Sequence
Initiate by protection operationCB Auto Recloses after Dead Time
– With checks to ensure the CB was actually previously closed
– With checks to ensure the fault was actually on the feeder and that protection operation is not a back-up function
Scheme resets after Reclaim TimeScheme lockouts
– Transmission schemes typically lockout upon occurrence of a 2nd fault within reclaim time
– Distribution schemes may allow multiple reclosures
Slide 5
Auto Reclosing Initiate Signal
Usually for high speed tripping only– Feeder differential protection– Distance relay Zone 1 protection– Distance relay Fast Zone 2 protection
Usually not for slow speed tripping– eg. Distance relay Slow Zone 2 protection
Usually not for tripping for remote faultsAllow for trip signal resetting– May need to extend the relay trip signal
Slide 6
Blocking of Auto Reclosing
Transformer or Shunt Reactor fault– eg. On receipt of DIT or SIT from remote end
CBF or Blind Spot faultsFollowing manual close of CBAR Check systems– Dead line check to prevent the master end reclose
onto a back-energised system– Live line check to only allow the slave end reclose
onto a healthy feeder– Sync check at the slave end to prevent re-connection
between systems that are now out of synchronism
Page 2
Auto ReclosingFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 7
Auto Reclosing Dead Time
Time delay between operation of protection and initiation of CB close - has to provide for …– Fault clearance (local and remote end clearance)– Dissipation of ionised air– Effects of parallel feeders, parallel phases (SPAR) &
couplingInductiveCapacitive
– Resetting of protection relay
Slide 8
Auto Reclosing Dead Time
Beware of AR effects on nearby power stations– AR onto multiphase fault should be avoided until
oscillations of the generator shaft have subsided, perhaps:
5 seconds for double phase to ground faults10 seconds for three phase faults
Slide 9
Auto Reclosing Reclaim Time
To prevent multiple reclosures onto permanent faultsTime delay following autoreclosure during which another fault is considered to be re-occurrence of the original fault– Not to be set too short as reoccurring faults may not
be properly identified– Not to be set too long as totally independent faults
may be incorrectly identified as reoccurrence of the original fault
To ensure the CB capability for Trip - Close - Trip sequences is not be compromised
Slide 10
EHV Auto Reclosing
Weakly interconnected systems– System stability is of prime concern
Strongly interconnected systems– Return of system security is of concern
SPAR and/or TPAR– SPAR for 1 phase faults– TPAR for 2 and 3 phase faults– Perhaps with different dead times
Typically only single shot– Failed reclose attempts will have a serious effect on system
stabilityTrip all 3 poles and lockout if AR is unsuccessful
Slide 11
Fundamental Principlesof
Power System Protection
Slide 11Slide 11
Single Pole Auto Reclosing(SPAR)
Slide 12
Single Pole Auto Reclosing (SPAR)
Advantages– In-service phases maintain system synchronism– In-service phases improve system “robustness”– Less system disturbance on reclose
Requires phase selective circuitry– Tripping, Closing and CB Fail
CB Pole discrepancy– Breaker must accept the single pole open operation
during SPAR
Page 3
Auto ReclosingFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 13
Single Pole Auto Reclosing (SPAR)
Dead Time – May need to be increased over TPAR time
(Due to coupling effects, particularly capacitive coupling)
Weakly interconnected systems : “2 phasing”scenarios– Reasonably short dead time may be required
Strongly interconnected systems– Longer dead times may be acceptable
Slide 14
Single Pole Auto Reclosing (SPAR)
Minimal affect on power stationsBut beware of possible cross country faults on double circuit feeders– Each feeder experiences a single phase fault– But the system, and nearby power stations, are
subjected to a double phase to ground fault
Slide 15
Single Pole Auto Reclosing (SPAR)
No requirement for sync check– System synchronism is ensured by the remaining
2 in-service phases Typically, no live line check implemented either– Single phase faults do not pose a significant risk to
system stability or to nearby plant– Common practice is to not implement such check
facilities. – Both ends simply reclose and both will be subject to
the effects of a permanent fault and will then trip (all 3 phases) and lock-out
Slide 16
SPAR & Transformer Ended Feeders
Single pole tripping of transformer ended feeders must not occur– The open phase remains magnetically coupled– 100% voltage is likely on the open phase– Fault is sustained for the complete dead time– Disastrous consequences for the transformer and for system
stabilityFlux from B & C phases continues to energise A phase
A phase fault current continuesWhoops !!
Slide 17
Fundamental Principlesof
Power System Protection
Slide 17Slide 17
Three Pole Auto Reclosing(TPAR)
Slide 18
Three Pole Auto Reclosing (TPAR)
EHV Systems– SPAR often implemented for single phase faults– TPAR implemented for multi-phase faults
Master/Slave system always implemented
HV Systems– SPAR rarely implemented for single phase faults– TPAR usually implemented for all fault types
Master/Slave system usually implemented
Distribution Systems– TPAR implemented for all fault types
System is usually radial
Page 4
Auto ReclosingFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 19
Three Pole Auto Reclosing (TPAR)Live Line Check
Simple Voltage check to implement a Master/Slave system– Master end recloses after the dead time– Slave end only recloses if the feeder is healthy– Prevents multiple reclosures onto permanent faults
Master end must have a secure source of supply– Hence, usually the “stronger” end
But near to Power Stations, the remote end may be selected as Master– Minimising the power station effects of reclosure onto
permanent faults
Slide 20
Three Pole Auto Reclosing (TPAR)Synchronism (Sync) Check
Strongly Interconnected Systems– Feeder tripping is unlikely to split the system– Synchronism is maintained– Sync Check is not needed– Dead times can be longer
Weakly interconnected systems– Feeder tripping may split the system– Synchronism may be lost– Sync check is needed– Dead times need to be shorter
Slide 21
Three Pole Auto Reclosing (TPAR)Synchronism (Sync) Check
Sync Check may allow reclosure for:– LLLB : Live Line, Live Bus, in synchronism– LLDB : Live Line, Dead Bus– DLLB : Dead Line, Live Bus– DLDB : Dead Line, Dead Bus
Sync Check monitors both sides of the CB for:– Frequency– Voltage– Phase angle– Rate of change of frequency (df/dt)
(To ensure the systems are not drifting at an unacceptable rate)
Slide 22
Fundamental Principlesof
Power System Protection
Slide 22Slide 22
Distribution SystemAuto Reclosing
Slide 23
Distribution System Auto Reclosing
Longer fault clearance times– Fault damage (eg. arc burning) can cause a transient fault to
become permanentLonger fault clearance times
– Slow clearance can allow a semi-permanent fault to burn clearConnected load
– Industrial CustomersDead times must allow expensive, complex or dangerous processes to become fully disconnected before restoring supply
– Domestic CustomersSimple loss of supply is of prime importanceAutoreclose delay is chosen to optimise protection performance, minimise fault damage, and to automatically return supply to as many customers as possible
Slide 24
Distribution System Auto ReclosingHigh Speed Tripping
High speed tripping results in minimal fault damage and minimises the possibility of transient faults becoming permanentBut protection discrimination is lost
– Downstream faults may result in the rapid and non-selective tripping of upstream circuit breakers
– Auto reclose returns supply to all customersMultiple reclosures are usually implemented
– High speed tripping is inhibited after reclosure– On reclosure, permanent faults will be tripped by time
coordinated schemes, ensuring discrimination – After reclosure, permanent faults then result in tripping of
only the faulted portion of the system
Page 5
Auto ReclosingFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 25
Distribution System Auto ReclosingSemi-Permanent Faults
Slower protection operations allow for semi-permanent faults to be burnt away– Perhaps due to contact with a tree
High speed tripping on the initial event– System disturbances minimised– Transient faults cleared and system restored
Slower time graded tripping after reclosure– Slower, coordinated tripping clears just the faulted
portion of the system– Slower tripping allows for semi-permanent faults to be
burnt away– May involve multiple reclosures
Slide 26
Distribution System Auto Reclosing Sectionalisers
Applies to radial distribution systemsFeeder fault is cleared at the source end CB (Recloser) Sectionaliser
– Cannot clear fault current– But counts the number of recloses– And sectionalises the feeder during the open dead time
CB(Recloser)
Sectionaliser Sectionaliser
N = 2N = 3
Slide 27
Distribution System Auto Reclosing Sectionalisers
Fault occurs … N = 1– CB Trips– No action by sectionalisers
Auto RecloseFault re-occurs … N = 2
– CB Trips– N = 2, so sectionaliser opens during the AR dead time
Auto recloseSystem restored, but with faulted section isolated
Sectionaliser Sectionaliser
N = 2N = 3
CB(Recloser)
Slide 28
Fundamental Principlesof
Power System Protection
Slide 28Slide 28
Auto ReclosingandSafety
Slide 29
Auto Reclosing and Safety
In autoreclosing fails, manual closing will be delayed to ensure public safetyAutoreclosing should be turned off in times of power system maintenanceAutoreclosing should not be initiated for faults not likely to be transient
Slide 30
Auto Reclosing and SafetySEF Protection
Distribution system sensitive earth fault protection– Detects very low level earth faults– These pose a significant danger to the public– These are rarely transient events– Faults to trees, fences, even to dry roads– Long time clearance : 10 or more seconds
Auto Reclose Reclaim time must be set longer than SEF protection timesSEF protection trips should inhibit or block any subsequent auto reclosing sequences.
Page 6
Auto ReclosingFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 31
Auto Reclosing and Fire Considerations(Victoria Black Saturday)
Of special relevance to distribution and SWER systemsLonger fault clearances increase the likelihood of fire ignition.High speed autoreclosure also increases the likelihood of fire ignition
– The initial event may not cause fire ignition, but it predisposes dry forest fuel to ignition on subsequent events (reclosure)
– Probability of fire ignition is perhaps 3 times greater on reclosure than on the initial event
Slide 32
Auto Reclosing and Fire Considerations(Victoria Black Saturday)
In times of fire risk:– Protection operations need to be high speed– Second shot, slow protection tripping should be avoided– Autoreclosing dead times should be extended (30 secs or
more)– Autoreclosing should be turned off
Periods of extreme fire riskLocations with extreme consequences
Page 1
Capacitor Bank ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 1
Fundamental Principlesof
Power System Protection
Slide 1Slide 1
CAPACITOR BANK PROTECTION
Slide 2
Capacitor Bank Protection
Overcurrent & Earthfault protection– IDMT– INST
Differential protection– Eg. For HV & EHV applications– HZ or LZ biased schemes
Balance protectionOver Voltage protection
Slide 3
Capacitor Bank Ratings
Maximum continuous operation at 110% Voltage– But the system typically operates 1.05pu voltage or
higher– Thus typically specify capacitor bank to provide for this– Eg. A 20MVar 33kV bank would be specified and
purchased as 24MVar at 36kVMaximum continuous operation at 130% Current– (Extra component on current is to allow for harmonics)
Cfreq21Zc ⋅⋅π⋅
=
Slide 4
In-Rush Current
Add these sinusoidal quantities– Steady state (load) current– Inrush from the system– Inrush from adjacent banks
This is a worst case solutionAs an absolute worst case approach, use this current in determining IDMT O/C relay TMS Settings
( ) ( )2RMS_ADJt2
RMS_SYSt2
LRMS_TOT IeIeII 21 ⋅+⋅+= ⋅α−⋅α−
Slide 5
In-Rush Current - Adjacent Banks
Series Reactor(s) installed to limit inrush current– May be installed at line potential– May be installed at neutral potential, one per phase, above the star
pointApply to (n-1) banks to limit inrush from adjacent banksApply to all banks to limit inrush from the system
– Also limits outrush to system faultsInrush current may also be limited by POW switching
Slide 6
In-Rush Current
Effect of inrush on protection may be eliminated by using stabilised relays (ie. not sensitive to higher frequency components)– IDMT OC Protection
Probably no problems in any caseTypically set to 150%, 0.1 – 0.2 TMS
– High set (Inst) OC ProtectionShould be stabilisedAnd even then, 1 or 2 cycle time delay may be necessary
Page 2
Capacitor Bank ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 7
Earth Fault Protection
Un-Earthed Capacitor Banks (non-effectively earthed systems)– With no earth connection, phase currents balance and residual
current on inrush is thus small.– Sensitive and fast IDMT EF protection can be applied.
Earthed Capacitor Banks (effectively earthed systems)– EF tripping on in-rush and also on out-rush is likely.– EF protection maybe disabled in such circumstances.– Stabilised EF protection can be simply set above load current.– Setting less than 2% of terminal EF levels not recommended.– Beware of setting electromechanical IDMT relays excessively
sensitive as the large relay burden can cause CT saturation under heavy terminal fault events.
No timing issues, so TMS of 0.1 may be appropriate.
Slide 8
Differential Protection
Slide 9
Differential Protection
Slide 14
Internally Fused Can
Failed element has negligible effect– Failure mode of a capacitor element is for it to short circuit– Associated fuse blows– Only a small part of capacitor is lost– Adjacent elements
Small current increaseSmall voltage increase
– Requires at least 8 elementsin parallel
Applicable to larger cansDischarge resistor
– Reduce can voltage to 50Vwithin 5 minutes
Slide 15
Externally Fused Can
Failed element shorts the parallel elements– Whole row is shorted and is effectively OOS
Can impedance reducesCan current increases
With further failures, external fuse operatesTypically for lower kVar cans
– Few elements in parallel– Many elements in series
Cap bank made up of series and parallel cans– Parallel cans allow bank to remain in
service with one can out (fuse blown).Discharge resistor
– Reduce to 50V within 5 minutes
Slide 16
Fuseless Can
Failed element shorts the parallel elements– Whole row is shorted and is effectively OOS
Can impedance reducesCan current increases
Typically for lower kVar cans– Few elements in parallel– Many elements in series
HV Capacitor bank– Cans in series, none in parallel
LV Capacitor bank– Cans in parallel, few (or none) in series
Discharge resistor– Reduce to 50V within 5 minutes
Page 3
Capacitor Bank ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 17
Balance Protection
Unbalance detected by simple neutral displacement voltage measurementBut this will also be sensitive to system voltage unbalances
– Steady state– During faults
Monitor 3 phase terminal volts also to compensate for any system voltage unbalanceTime delay to allow system faults to clear Voltage
Displacement
Slide 18
CurrentBalance
Balance Protection
Cans positioned at commissioning for minimum neutral unbalance current flowMonitor unbalance neutral currentUnaffected by system unbalances
Slide 19
CurrentBalance
Balance Protection
Note that these two schemes give different results– Unearthed system neutral voltages are locked together, and
will change with unbalance– Earthed system neutral simply remain locked at earth
potential
Slide 20
Bala
nce
A
Bala
nce
Bala
n ce
B C
Balance ProtectionPhase Segregated Scheme
Slide 21
Internally FusedCapacitor Can
1 CapacitorCan
One Phase of a36kV, 24MVAr Capacitor Bank
BalanceProtection
Capacitor Bank Constructionand Failure Mode
Slide 22
Internally FusedCapacitor Can
1 CapacitorCan
One Phase of a36kV, 24MVAr Capacitor Bank
BalanceProtection
Balance ProtectionPrinciples
When initially commissioned, zero current flows via balance protectionOn failure of one element in one can, a small current is now detected
– The parallel elements in that can also now have a small over voltage condition
– Hence, all other things being equal, the most likely subsequent failure is another element in the same row in the same can
– Unbalance current subsequently increases and is detected
Page 4
Capacitor Bank ProtectionFundamental Principles ofPower System Protection
May 2012© Barrie Moor
Slide 23
Balance ProtectionPrinciples
Trip before 10% overvoltage on the parallel cans – small time delay
– Typically about 50% of elements failedAlarm at half this value – small time delay
– Typically about 25% of elements failedUnbalance current is very small … maybe <1A primary
– CT ratio typically 1 / 1A– CT does not need a protection class specification, in fact a
measurement class CT should probably be specified
Internally FusedCapacitor Can
1 CapacitorCan
One Phase of a36kV, 24MVAr Capacitor Bank
BalanceProtection
Slide 24
Over Voltage Protection
To trip the bank if the continuous voltage capability (110%) is exceededTo protect the system from over voltage due to the capacitor banksCoordinate with any nearby generator under excitation protection
– Trip capacitors to reduce system voltage before any generator protections may operate
Staged tripping recommended – To prevent wide spread capacitor tripping and hence
prevent a subsequent under voltage event from occurring– eg. Where more than one bank is installed at a substation– eg. Where banks are installed a nearby substations