Relaying 101
The abridged edition
Too Much to Cover• Power system theory review
– Phasor domain representation of sinusoidal waveforms
– 1-phase and 3-phase power– Symmetrical components
• Zones of protection• Relaying principals
– Over-current– Differential– Distance
Page 3
Power system theory review• Phasor domain representation of sinusoidal waveforms
– Vectors: multi-dimensional, static
N
ESt Paul
Duluth
Page 4
Power system theory review• Phasor domain representation of sinusoidal waveforms
– Phasors: multi-dimensional, time-variant, rotate at constant angular velocity (ω=2πf)
– Projection onto the Re axis plots as cos(ωt+θ)– Projection onto the Im axis plots as sin(ωt+θ)– m*cos(ωt+θ) => M@ θ => re + jim
• where M=m/√2 (RMS value)• j operator = 90 degree phase shift
– Useful for showing lead/lag relationships• M leads N by (θ+φ)
Im
Re
ωM(ω)
θre
im
N(ω)
φ
Page 5
Power system theory review• 1-phase power
– Ohms law:• V=I*Z (time or phasor domain)• S=V*I*=p+jq (V and I are phasors, S is a vector)• S=V*(V/Z)* ; |S|=|V2/Z|• S=I*I*/Z ; |S|=|I2Z|
– Power factor• pf = p/S = cos(θ) for pure sinusoids• Leading/lagging (current relative to the voltage)
Ppage 6
Power system theory review• Balanced 3-phase power
– Phase quantities are equal magnitude and 120o
displaced– |AB| = √3*|A|
A
B
C
AB
CA
BC
AB=A-B
-B
Page 7
Power system theory review• 3-phase power
– Ohms law:• VPN=IP*ZPN
• S1P=VPN*IP*
• S3P=SA+SB+SC
• For balanced systems: S3P = 3*S1P
|S3P|=|VPP2/ZPN|
|ZPN|=|VPP2/S3P|=|VPN
2/S1P||IP|=|S3P/(√3*VPP)|
Page 8
I’ll try to keep this simple.Hopefully, most of it will be correct!
Power system theory review• Symmetrical components
– Mathematical trick for unbalanced systems• Superposition theorem• Break original system into 3 balanced sub-systems
– Positive sequence (phase rotation same as original)– Negative sequence (phase rotation opposite of original)– Zero sequence (no phase rotation)
• Perform balanced analysis on each sub-system and then add the results to get the total
Page 10
Power system theory review• Symmetrical components
– Definition: VA=VA1+VA2+V0
+ VB=VB1+VB2+V0
VC=VC1+VC2+V0
VA+VB+VC= 3V0
IA=IA1+IA2+I0
+ IB=IB1+IB2+I0
IC=IC1+IC2+I0
IA+IB+IC= 3I0
Page 11
Power system theory review• Symmetrical components
Page 12
C1 A1
B1
A2
C2
B2
A0=B0=C0=0
Positive seq (ABC)
Negative seq (ACB)
Zero seq
A
A=A1+A2+0
ω ωω
Power system theory review• Symmetrical components
Page 13
C1 A1
B1
A2
C2
B2
A0=B0=C0
Positive seq (ABC)
Negative seq (ACB)
Zero seq
B
A
B=B1+B2+0
Power system theory review• Symmetrical components
Page 14
C1 A1
B1
A2
C2
B2
A0=B0=C0=0
Positive seq (ABC)
Negative seq (ACB)
Zero seq
A
B
C
C=C1+C2+0
Power system theory review• Symmetrical components
Page 15
C1 A1
B1
A2
C2
B2
A0=B0=C0=0
Positive seq (ABC)
Negative seq (ACB)
Zero seq
A
B
C
Phase system rotation is ABC
ω
Power system theory review• Symmetrical components
– Physical meaning (intuition)• Positive sequence is “normal” balanced system• Zero sequence is “ground current”• Negative sequence creates reverse rotating fields in motors
and generators– Slip frequence = 2*f– Rotor is cutting many lines of force– Induces heating in the rotor
• Phase-phase unbalances/faults create negative sequence• Phasae-ground unbalances/faults create zero sequence
Page 16
Relaying: An addiction that is hard to break!
Zones of Protection• Goals of protective systems
– Detect and isolate all faults (reliability)– Never mis-operate (security)– Isolate the minimum amount of equipment– Time is of the essence– Some protection systems operate to prevent a fault (ex:
overload)• Requires selectivity
– Each protection device is assigned a zone of protection
Page 18
Zones of Protection
Page 19
52 52
52
52
T-Line Bus
Bus
Trans
Radial Fdr
52 52
Radial Fdr
Radial Fdr
• Highly selective• Over-lapping• Back-up “blurs” the zone boundaries
52
What breakers are tripped for each zone?
Relaying principals• Over-current relaying
– Instantaneous (50)• Definite time
– Time (51)– Phase – Neutral/Ground (zero sequence)– Directional (67)
Page 20
CHOICES, CHOICES, CHOISES.....
Page 22
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
2
3
45
7
10
20
30
4050
70
100
200
300400500
700
1000
2
3
45
7
10
20
30
4050
70
100
200
300400500
700
1000
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
TIME-CURRENT CURVES @ Voltage 13.8 kV By TWE
For Instantaneous Over-current relay Characteristic No. M2008
Comment Date 11/6/2008
1
1. 50 Instant. RelayCTR=400/5 Inst.=5000A
No Operate
Operate
No intentional delay
Instantaneous over-current element (50)
Is this really instantaneous?
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
2
3
45
7
10
20
30
4050
70
100
200
300400500
700
1000
2
3
45
7
10
20
30
4050
70
100
200
300400500
700
1000
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
TIME-CURRENT CURVES @ Voltage 13.8 kV By TWE
For Definite Time Over-Current Relay Characteristic No. M2008
Comment Date 11/6/2008
1
1. 50 Instant. RelayCTR=400/5 Inst.=5000A
Page 23
No Operate
Operate
0.5 Second intentional delay
Instantaneous over-current element with definite time delay (50)
Page 24
Time over-current element (51)
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
2
3
45
7
10
20
30
4050
70
100
200
300400500
700
1000
2
3
45
7
10
20
30
4050
70
100
200
300400500
700
1000
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
TIME-CURRENT CURVES @ Voltage 13.8 kV By TWE
For Time Over-current Relay Characteristics No. M2008
Comment Date 11/6/2008
1
1. 51 (Extreemly Inv) UR-IEEE-EI TD=2.000CTR=400/5 Pickup=5.A No inst. TP@2=19.043s
2
2. 51 (Very Inv) UR-IEEE-VI TD=2.000CTR=400/5 Pickup=5.A No inst. TP@2=14.055s
3
3. 51 (Moderatly Inv) UR-IEEE-MI TD=2.000CTR=400/5 Pickup=5.A No inst. TP@2=7.6065s
Why do we use this inverse time characteristic?
Page 25
Combined instantaneous and time over-current element (50/51)
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
2
3
45
7
10
20
30
4050
70
100
200
300400500
700
1000
2
3
45
7
10
20
30
4050
70
100
200
300400500
700
1000
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
TIME-CURRENT CURVES @ Voltage 13.8 kV By TWE
For Time Over-Current Relay With Instantaneous Characteristic No. M2008
Comment Date 11/6/2008
1
1. 50/51 UR-IEEE-EI TD=2.000CTR=400/5 Pickup=5.A Inst=5000A TP@2=19.043s
Page 26
Phase (50/51P) and Neutral (50/51N) over-current elements(composite coordination)
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7
10 2 3 4 5 7 100 2 3 4 5 7 1000 2 3 4 5 7 10000 2 3 4 5 7CURRENT (A)
SECONDS
2
3
45
7
10
20
30
4050
70
100
200
300400500
700
1000
2
3
45
7
10
20
30
4050
70
100
200
300400500
700
1000
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
.01
.02
.03
.04
.05
.07
.1
.2
.3
.4
.5
.7
1
TIME-CURRENT CURVES @ Voltage 13.8 kV By TWE
For Phase and Ground Over-current Relay Characteristics No. M2008
Comment Date 11/6/2008
1
1. 50/51P UR-IEEE-EI TD=2.000CTR=400/5 Pickup=5.A Inst=5000A TP@2=19.043s
2
2. 50/51G UR-IEEE-MI TD=12.000CTR=400/5 Pickup=2.A Inst=5000A TP@2=45.639s
Full Load
Why can the neutral pick-up be set less than full load?
Time coordination is achieved through selection of curve shapes, pick-ups and time delays.
Relaying Principals
Page 27
52 52T-Line 1
Bus
52 52
52 52
T-Line 2
T-Line 3
67
• Directional Relay (67)– Compares angle between operating and polarizing
quantities• Operating = line current• Polarizing = something stationary
– Healthy phase-phase voltage– Sequence voltage– Sequence current
Relaying principals• Bus differential relay (87B)
– Kirchhoff's current lawI1 + I2 = I3
Page 28
52
Bus
52
52
87B
I1
I3
I2
Relaying principals• Bus differential relay (87B)
– CT error will cause operating current• Poor quality CTs• CT saturation due to very high fault currents
– Use percentage slope characteristics for security• Operate on difference current• Restrain operation with through-load current• Minimum operating current = Irest * Slope
– Minimum pick-up to avoid “divide by zero” issues– Directional element and CT saturation detection add security– Will not operate for faults outside the zone of protection
• No coordination required
Page 29
Page 30
Bus differential relay slope characteristic
Minimum Pick-up = 0.1 pu
TRIP Region
Slop
e1=25
%
Slop
e2=80
%
TRIP
NOTRIP
Relaying principals• Transformer differential relay (87T)
– Same principal as bus except SIN = SOUT• Account for turns ratio and phase shifts
– Includes additional restraint• 2nd harmonic for in-rush• 5th harmonic for over-excitation
– May include:• directional element • CT saturation detection
Page 31
52
87T
SIN
SOUT
Relaying principals• Line differential relay (87L)
– Same principal as bus: IS = IR• Account for CT ratio differences
– Uses magnitude and angle of differential and restraint
– May include differential for line termination transformer
– Requires high bandwidth communication channel
• Fiber• Digital microwave• Digital radio
Page 32
IS
IR
52
Line
52
87L
87L
Conn Chan
Relay Engineers get used to the abuse,Given enough time...
Relaying principals• Distance relay (21)
– AKA: Impedance– Measures the complex impedance to the fault
• Z=V/I• Operates “instantaneously” if Z is within the
characteristic– Offset MHO– Quadrilateral
Page 34
21
52 52T-Line 1
21
Page 35
line21
R
jXDesired reach @ line angle
Offset MHO Characteristic
Most fault impedances are on or near the line angle
Operating Voltage = V-I*ZRPolarizing Voltage = V
Page 36
line21
R
jXDesired reach @ line angle
Quadrilateral Characteristic
Most fault impedances are on or near the line angle
Relaying principals• Distance relay (21)
– Uses pre-fault memory voltage for directional control on zero-voltage faults
– Phase• Phase-phase element• 3-Phase element• Phase or sequence component based
– Ground• Measures positive sequence impedance• Uses a K0 scaling factor to approximate zero sequence
impedance
Page 37
Relaying principals• Distance relay (21)
• Typically applied using stepped zones– Zone 1 (21-1) under-reaching: ZR=85% of ZL Instantaneous– Zone 2 (21-2 ) over-reaching: ZR=125% of ZL Time delayed to
coordinate with remote zone 1 elements
Page 38
21-1
52 52T-Line 1
21-1
21-2 21-2
Relaying principals• Pilot schemes (communication assisted)
– Permissive over-reaching transfer trip (POTT)• Send permission to remote end(s) if 21-2 operates• Local instantaneous trip if 21-2 operates while receiving
permission from remote end(s)
Page 39
21-2
52 52T-Line 1
21-1Trip zone
Relaying principals
Page 40
21-R
52 52T-Line 1
21-R
21-2 21-2
• Pilot schemes (communication assisted)– Directional comparison blocking (DCB)
• Send block to remote end(s) if 21-R operates• Local instantaneous trip if 21-2 operates while not receiving
block from remote end(s)
Trip zone
Relaying principals• Pilot schemes (communication assisted)
– Direct under-reaching transfer trip (DUTT)• Local instantaneous trip if 21-1 operates• Send direct transfer trip to remote end(s) if 21-1 operates
Page 41
21-1
52 52T-Line 1
21-1
Trip zone
Lots More to Talk About• Generator protection• Motor protection• Capacitor bank protection and control• Reactor protection• Over-voltage coordination• IEC-61850••
Page 42
Save it for Relaying 102, 103, ......
It’s finally over! Time to grab a beer.
Page 44
Thanks for Your Time!
Any Questions?