Digital Differential Protection G. Ziegler
Differential Protection Symposium
Belo Horizonte, 7 to 9 Nov. 2005
No.: 1
Differential Protection: Discussion Subjects Ø
Mode of operation
Ø
Measuring technique
Ø
Current transformers
Ø
Communications
Ø
Generator and motor differential protection
Ø
Transformer differential protection
Ø
Line differential protection
Ø
Busbar differential protection
Differential Protection Symposium
Belo Horizonte, 7 to 9 Nov. 2005
No.: 2
Digital Differential Protection Principles and Application Gerhard Ziegler
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 1
Contents Pages Mode of operation
3 - 27
Measuring technique
28 - 45
Current transformers
46 - 86
Communications
87 - 115
Generator and motor differential protection
116 - 122
Transformer differential protection
123 - 178
Line differential protection
179 - 216
Busbar differential protection
217 - 247
7UT6 product features
248 - 264
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 2
Digital Differential Protection Mode of operation Gerhard Ziegler
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 3
Comparison protection - Principles Absolute selectivity by using communications IA
IB B
A
Exchange of YES / NO signals (fault forward / reverse)
protection range reverse
forward
Relay
forward
communication
reverse
• Current comparison | ∆I |
Relay
Sampled values Phasors Binary decisions
t
•Directional comparison
IA
IB
•comparison of momentary values or phasors B
• | ∆I | = | IA - IB | > limiting value
A Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 4
Protection Criterion “current difference“ (differential protection) n Kirchhoff‘s law: II1 + I2 + I3 + ... InI= Idiff = 0;
Current difference indicates fault
n Security by through-current dependent restraint
|I1|+|I2|+ ... |In| = IRes
protection object
n Characteristic:
Idiff Trip Ires n Absolute zone selectivity (limits: CT locations)
No “back-up“ for external faults n Differential protection: for generators, motors, transformers, lines and busbars
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 5
Current differential protection: Basic principle
I1 i1
I2 Protection object
i2 ∆I>
∆I=I1 + I2 =0
external fault or load
Differential Protection Symposium
I1
I2
Protection object
i1
i2 i1
∆I>
∆I=I1 + I2
i2
internal fault
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 6
Differential protection: Connection circuit Traditional technique
Digital technique
L1
L1
L2 L3
L2 L3
∆I
∆I
∆I
Galvanically connected circuits must only be earthed once!
Different CT ratios need to be adapted by auxiliary CTs!
Differential Protection Symposium
∆I
CT circuits of digital relays are segregated and must each be earthed !
Digital relays have integrated numerical ratio adaptation !
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 7
Generator and transformer differential protection
L1 L2 L3
L1 L2 L3
∆I
∆I
∆I
Differential Protection Symposium
Yd5
Matching transformer
Belo Horizonte November 2005
∆I
∆I
∆I
G. Ziegler, 10/2005
page 8
Transformer differential protection
Yd5 L1 L2 L3
Matching transformer
Differential Protection Symposium
∆I
∆I
∆I
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 9
Current transformer: Principle, transformation ratio, polarity
i1
i2
i1 w1
u1 i2
1 Φ
u2
i1 ⋅ w1 = i2 ⋅ w2
Function principle i1
u2
u1 u 2 = w1 w2
2
w2
u1
Polarity marks
P1
P2
i2 i1
u1
i2
u2 S1 Equivalent electrical circuit
Differential Protection Symposium
S2
Designation of CT terminals according to IEC 60044-1
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 10
Busbar differential protection Digital protection 7SS52
Analog protection 7SS10/11/13 7SS600 with digital measuring relay (∆I)
∆I Central Unit 2
4
3
Optic fibres
0
∆I
BU
BU
BU
BU
0
G
M Grid infeed
BU: bay unit
G
Load
Differential Protection Symposium
M Grid infeed
Belo Horizonte November 2005
Load
G. Ziegler, 10/2005
page 11
Line differential protection
50/60 Hz current comparison through wire connection I1
Phasor with digital communication via OF, microwave or pilot wires I1
I2 I2
∆I
DI
∆I
∆I
∆I
I1
I2
dedicated O.F. up to about 35 km Other services
PCM MUX
PCM MUX
Other services
O.F. or Microwave
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 12
Two wire (pilot wire) line differential protection Voltage comparison principle I2
I1
Grid
G ∆I
RS
U1
∆U
∆I
U2
RS
3
3
∆I
Differential Protection Symposium
∆I
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 13
False differential currents during load or external faults
I∆ / In te
ri st ic
4
ac
∆IGF = total false current
re
la
y
ch
ar
3 2
∆IWF = CT false current ∆IAF = Inaccurate adaptation (CT ratios, tap changer)
1
∆IWF = Transformer magnetising current
1
10
Differential Protection Symposium
15
ID / In
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 14
Percentage differential relay
A = I1− I2 operate stabilise
B S = I1+ I2
I1 Basicpick-up value (B) I2 I1+ I2
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 15
Differential protection: analog measuring circuit Rectifier bridge comparator with moving coil relay
I2
I1 protection object
i1
Fault characteristic (single side infeed)
i2
ΔI =
W2
W1 W3
k1 ⋅ I Re s
k1 ⋅ I Re s
I1 − I 2
Relay characteristic
W1
k 2 ⋅ I Op
= k1 ⋅ (I 1 − I 2 ) k1 =
I1 + I 2 > k ⋅ I1 − I 2
W4
w1 w2
Differential Protection Symposium
k=
k2 ⋅ I Op
Σ I = I1 + I 2
= k2 ⋅ (I1 + I 2 ) k2 =
w3 w4
k1 k2
with digital relays: ΣI = I1 + I 2
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 16
Multi-end differential protection: Analog measuring principle
1
n
2
Iop = I1 + I 2 + .... + I n = Σ I
Differential Protection Symposium
k ⋅ I Re s
I Op
I Res = I1 + I 2 + .... + I n = Σ I
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 17
Optimised relay characteristic
G R 2000A
Ideal fault characteristic
∆Ι
IOp = I1 − I 2
internal fault
300A
F
Load RL
IOp = 2000 A
relay characteristic
IS = 2600 A
I F1
I F2
G
G
CT saturation
∆Ι I Res = I1 + I 2
Healthy protection object
δ I Op = 2 ⋅ I F ⋅ cos
Differential Protection Symposium
I Re s = 2 ⋅ I F
δ 2
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 18
Digital differential protection: Relay characteristic IOp Positive current polarity k2 ∆I
k1
Id > IR0
I Op = ΣI = I1 + I 2
Settings:
I Res = Σ I = I1 + I 2
• slope k1
IRes
• Pick-up value Id >
• slope k2 with footing point IR0
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 19
∆I / ΣI und I1 / I2 diagram ΔI = I1 + I 2
I1 Internal faults IS0 1+ k + ⋅B 2 2⋅k
k [% / 100 ] slope
B
IS0
IS0 1− k ⋅B + 2 2⋅k
Σ I = I1 + I 2
(
1
I1 + I 2 > k I1 + I 2 − I S 0
2
I1 + I 2 > B
Differential Protection Symposium
)
IS0 2
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 20
I2
Polar diagram of differential protection I1 + I 2 > k ⋅ I1 − I 2
β-Plane (remote/local current)
I 1+ 2 1+β I1 > k or >k I2 1- β 1− I1
I Im 2 I1
I β= 2 I1
I2 Protection object ∆Ι
I with β = 2 I1 −
I1
1+ k 1− k
+1
-1 (k=0,5)
−
1− k 1+ k
I Re 2 I1
Restraint area
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 21
Polar diagram of digital differential protection: Basic pick-up value B > 0
90
I 2 jϕ e I1
120
I1 + I 2 > k ⋅ ( I1 + I 2 ) + B or I2 > k ⋅ 1 + 1+ I1
I2 I1
B + I 1
60
ϕ
150
30
180
0 5
210
10
330
300
240 270 B/I1= 0,3
a1(Φ): k=0,3 a2(Φ): k=0,6 a3(Φ): k=0,8
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 22
Mixing transformer of composed current differential protection
IL1
IL2
IL3 IL1
Composed current during symmetrical 3-ph fault or load
IM
2
IL3
7SD503: IM = 100 mA 7SS600: IM = 100 mA 7SD502: IM = 20 mA
1
IE 3 Mixing transformer
IM =
IL3
1 ⋅ 3 ⋅ I Ph −3 w
2 ·IL1
IL3
IL1
I M = 2 ⋅ I L1 + 1 ⋅ I L3 + 3 ⋅ I E IL3
IL2
Differential Protection Symposium
= 5 ⋅ I L1 + 3 ⋅ I L2 + 4 ⋅ I L3 ⇒ composed current (vector sum) Belo Horizonte November 2005
G. Ziegler, 10/2005
page 23
Mixing transformer: Pickup sensitivity of standard connection (IM= 2IL1+IL3+3IE )
Fault type
Per unit composed current related to 3-phase symmetrical current
Composed current
L1-E
IML1-E = 5 IL1
IL2 = IL3 = 0
IML1-E / IM = 5 / √ 3 = 2.9
L2-E
IML2-E = 3 IL2
IL1 = IL3 = 0
IML2-E / IM = 3 / √3 = 1.73
L3-E
IML3-E = 4 IL3
IL1 = IL2 = 0
IML3-E / IM = 4 / √3 = 2.3
L1-L2
IML12 = 5 I L1 + 3 I L2
IL3 = 0
IML12 / IM = 2 / √3 = 1.15
L2-L3
IML23 = 3 I L2 + 4 I L3
IL1 = 0
IML23 / IM = 1 / √3 = 0.58
L1-L3
IML13 = 5 I L1 + 4 I L3
IL2 = 0
IML13 / IM = 1 / √3 = 0.58
L1-L2-L3
IML123 = 5 IL1 + 3IL2 + 4IL3
|IL1| = |I L2| = |I L3|
IML123 / IM = √3 / √3 = 1
Differential Protection Symposium
Belo Horizonte November 2005
Highest sensitivity
G. Ziegler, 10/2005
page 24
Composed current differential protection Behaviour during cross country fault (isolated/compensated network) ∆I
A
B L1 L2 L3
IF
L1 internal und L3 external: IM-A= 5⋅IF - 4⋅IF = 1⋅IF und IM-B= + 4⋅IF ∆I = |IM-A + IM-B| = 5IF und ΣI = |IM-A| + |IM-B| = 5⋅IF ∆I/ΣI = 5/5 = 1.0
Tripping
L2 internal, L3 external IM-A= - 1⋅IF und IM-B= + 4⋅IF ∆I = |IM-A + IM-B| = 3 ⋅IF und ΣI = |IM-A| + |IM-B| = 5⋅IF ∆I/ΣI = 3/5 = 0.6
Tripping if k-setting < 0.6
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 25
Composed current differential protection Through current stabilisation with unsymmetrical earthing conditions
2
1
3
3
2
IM2=2·IL1 + 1·IL3+ 3 ·IE =2·IF + 1 ·IF+ 3·3IF = +12 ·IF
IM1=2·IL1 + 1·IL3 + 3 ·IE =2 ·(–IF) + 1 ·(–IF) + 3·0= –3·IF IOp=| IM1 + IM2 | = 9 ·IF IRes=|IM1| +|IM2| = 15 ·IF
1
k=9/15 = 0.6
IOp
Fault L2-E
k=0.5
Faults in other phases: Fault L1-E: IOp = (3+12) ·IF = 15 ·IF, IRes= (3+12) ·IF = 15 ·IF,
k=1
Fault L3-E: IOp = (0+12) ·IF = 12 ·IF, IRes= (0+12) ·IF = 12 ·IF,
k=1
Differential Protection Symposium
IRes Belo Horizonte November 2005
G. Ziegler, 10/2005
page 26
High impedance differential protection: Principle Behaviour during external fault with CT saturation
with ideal current transformers
ISC
RCT
RCT
ISC
ISC
ISC
UR
ECT −1 = (RL + RCT ) ⋅ iSC
ECT −1 = 2 ⋅ (RL + RCT ) ⋅ iSC
UR = 0 ECT −2 = (RL + RCT ) ⋅ iSC
Differential Protection Symposium
U R = (RL + RCT ) ⋅ iSC
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 27
High impedance differential protection: Calculation example (busbar protection)
Given:
n = 8 feeders rCT = 600/1 A UKN = 500 V RCT = 4 Ohm ImR = 30 mA (at relay pick-up value)
Pick-up sensitivity:
(
600 ⋅ (0.02 + 0.05 + 8 ⋅ 0.03) 1
I F − min = 186 A ⋅ (31% )
Differential Protection Symposium
RR = 10 kOhm Ivar = 50 mA (at relay pick-up value)
Stability:
I F −min = rCT ⋅ I R − pick −up + IVar + n ⋅ I mR
I F − min =
RL= 3 Ohm (max.) IR-pick-up.= 20 mA (fixed value)
)
I F −through − max < rCT ⋅
I F −throuh − max
9 10
0
1
6
trip
7 8
restrain
9
0 10
18O = 1 ms (50 Hz) = 0.67 ms (60 Hz)
ΣI
IA
IB
∆I
∆I
Operating quantity :
∆I = I A + I B
Restraining quantity : ΣI = I A + I B Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 35
Discrete Fourier-Transformation (Principle) sin 2π ⋅i n 0 1 2 . .
i( k −n+i )
.
Correlate: Multiply samples and add for one cycle n
Correlate IS(k)
i k-n
I (k) = I S(k) + j ⋅ I C(k) k
Correlate IC(k)
I (k )
j
IC(k)
cos 2π ⋅i n
Differential Protection Symposium
Belo Horizonte November 2005
ϕ IS(k)
G. Ziegler, 10/2005
page 36
Discrete Fourier-Transformation (calculation formulae) i 0
i1 i2 i 3 iN ∆t
N
I = 2 ∑ sin(ω ⋅n⋅ Δt )⋅in S N n=1
N
i i N-1 I = 2 O + N + ∑ cos(ω ⋅n ⋅ Δt)⋅in C N 2 2 n=1
N-1
0 1 2 3 .... n
0 1 2 3 ...
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 37
Orthogonal components of a current phasor dependent on the position of the data window Data window
Φ = ωt IS =
Φ 1 ⋅ ∫ I (ω ⋅ t ) ⋅ sin ωt ⋅ dt 2π Φ −360
IC =
Φ 1 ⋅ ∫ I (ω ⋅ t ) ⋅ cos ωt ⋅ dt 2π Φ −360
I Φ = I S + j ⋅ IC I0 = 1+ j ⋅ 0 I
O
O
O
I30 3 1 = + j⋅ I 2 2 O
I 60 1 3 = + j⋅ I 2 2 O
jIC
I IS
ωt t=0
I90 = 0 + j ⋅1 I O
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 38
Transfer function of a one cycle Fourier-filter Hrel 1,0 0,75 0,5 0,25 0 0
1
Differential Protection Symposium
2
3
4
5
6
f/fn
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 39
Digital protection Fast current phasor estimation N
k-N
i(t)
k
Data window i(t) = A ⋅ sin( ωt ) +
Task: Method:
Delta =
t − B ⋅ cos( ωt) - e τ + C ⋅ cos( ωt)
Estimation of the coefficients A, B, C on basis of measured currents and voltages Gauß‘s Minimization of error squares: Delta = quality value k = sampling number k N = length of data window 2 ∑ i(n ⋅ ∆T) - f (n) MIN n = variable n=k-N ∆T = sampling interval sampled values
(
)
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 40
Differential protection with phasors (principle) A
∆I
B
IAC , IAS IBC , IBS
∆I
∆I
trip
∆I>
restraint
j·IAS
ΣI Operating quantity :
∆I = I A + I B
Restrainin g quantity : Σ I = I A + I B
IBC IAC j·IBS
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 41
Digital line differential protection Synchronisation of phasors (ping-pong time alignment) A
tA1 tA2
∆I
∆I
curre n phas t o rs
α ...
tPT1
tAR
tA5
tA1
tPT2 tV tB3 tA1
tBR
tB2
α=
tB3 nt curre . . . rs ph aso
Differential Protection Symposium
t B3 - t A3 ⋅ 360 ° TP
tB4
Signal transmission time: t PT1 = t PT2 = Sampling instant:
IB( tB3 )
tB1 tD
tA3 tA4
IB( tA3 )
B
1 (t A1 - t AR - t D ) 2
t B3 = t A3 - t PT2
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 42
Split path data transmission Impact of unsymmetrical propagation time I1
I2
∆I
∆I
180o ∆T[ms ]⋅ α 10ms ∆I = I ⋅ sin = I ⋅ sin 2 2
α I2 I1
Example: Transmit channel time 3 ms Receive channel time 4.2 ms → time difference ∆ = 1.2 ms
180o 1.2ms ⋅ 10ms = I ⋅ 0.19 ∆I = I ⋅ sin 2
∆I α/2
∆I = 19%!
To keep the false differential current below about 2 to 5%, the propagation time difference should not exceed about 0.1 to 0.25 ms! Otherwise: → more insensitive relay setting → or GPS synchronisation Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 43
Synchronisation of Differential relays via GPS Line end 1
Line end 2
GPS-Antenna RS232
GPS-Antenna GPS
RS232
UH
DC GPS-Empfänger supply DCF-SIM A B LWL LWL IRIG-B 24V
GPS
GPS-Empfänger Hopf DC supply DCF-SIM A B LWL LWL IRIG-B 24V
IRIG-B Telegram Sec. impulse (highly accurate)
LWL K1
LWL
BE2
K2
IRIG-B Telegram Sec. impulse (highly accurate)
LWL
K2
K1
7XV5654 Sync-Trans. K1 X1 K2 K2
LWL
BE2
K2
K2
7XV5654 Sync-Trans. K1 X1 K2 K2
+ - 24V + 1 3 8 4
+ - 24V + 1 3 8 4
Y-cable 7XV5105
1 3 8 4
RUN
7SD52
SIEMENS
ERR OR
L1 402,1A L2 402,1A L3 402,1A E 00.0A
to max.
Differential Protection Symposium
SIEMENS
ERR OR
L1 402,1A L2 402,1A L3 402,1A E 00.0A
7SD52
6
V4
SIPROTEC RUN
Max450.1A Max450.1A Max450.1A
Anr. L1 Anr. L2 Anr. L3 Anr. Erde Automat
1 3 8 4
V4
SIPROTEC
RUN
Max450.1A Max450.1A Max450.1A
Anr. L1 Anr. L2 Anr. L3 Anr. Erde Automat
1
1 3 8 4
V4
SIPROTEC
L1 402,1A L2 402,1A L3 402,1A E 00.0A
Y-cable 7XV5105
1 3 8 4
V4 SIEMENS
UH
SIEMENS
ERR OR
SIPROTEC
RUN
Max450.1A Max450.1A Max450.1A
L1 402,1A L2 402,1A L3 402,1A E 00.0A
Anr. L1 Anr. L2 Anr. L3 Anr. Erde Automat
ERR OR Max450.1A Max450.1A Max450.1A
Anr. L1 Anr. L2 Anr. L3 Anr. Erde Automat
1
t0 max.
Belo Horizonte November 2005
6
G. Ziegler, 10/2005
page 44
Devices for GPS time synchronisation n GPS receiver with 2 optical outputs (7XV5664-0AA00). Output for IRIB-B telegram and output for second/ minute pulse n Galvanic separation between the receiver and the tranceiver 7XV5654 n Optic/electric signal conversion in the tranceiver n Distribution of the electrical signals via Y-bus cable to port A of the relays (telegram) n Electronic contact for the minute pulse in case of synchronisation through binary input with battery voltage
Differential Protection Symposium
Outdoor antenna FG4490G10 for GPS
GPS receiver 7XV5664 Tranceiver 7XV5654 Belo Horizonte November 2005
G. Ziegler, 10/2005
page 45
Additional components for SICAM SAS GPS-System
• • • •
Differential Protection Symposium
24 satellites move in a height of 20 000km on 6 different paths Transmission frequency 1,57542GHz For a continuous time reception min. 4 satellites is necessary High accuracy : 1 usec
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 46
Operating characteristic of digital differential relays
I∆ =|I1+ I2|
I1
I2
b%
∆I
I∆>
a%
I∑ b
Differential Protection Symposium
I∑ = |I1|+ |I2|
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 47
Differential protection CT saturation with internal and external faults ∆I Protection object
I2
I1 Internal fault
External fault
I1 I2 Σ I= |I1| + |I2| ∆I=|I1 +I2| t=0
t=10
Differential Protection Symposium
t=20 ms
t=0
t=10
t=20 ms
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 48
Saturation detector:
Locus of ∆I/ΣI for external faults without and with CT saturation
i Op( n ) = i1( n ) + i 2( n ) 6' 7'
saturation
3'
re s
i 2( n )
in tra
n
8'
External fault
5' 4' with CT
i1( n )
e rat e op
i1( n ) + i 2( n )
9'
0 10
External fault (ideal CTs)
1
2
3
4 5
9
8
7
6
i Re s ( n ) = i1(n ) + i 2( n )
Differential Protection Symposium
i1(n ) + i 2( n )
n=0
n=10
Belo Horizonte November 2005
n=20
G. Ziegler, 10/2005
page 49
Differential current caused by transient CT saturation (ext. fault) with operating and restraint current of busbar protection 7SS5 I1 100
50
I2
0
50
IRes.= |I1| + |I2|
IOp=|I1 +I2|
Differential current appears only every second half wave!
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 50
Tripping logic of digital busbar protection 7SS600/7SS5 with saturation detector (simplified) di Re s > k s [A / ms] dt
i Op > iset i Op > k ⋅ i Re s
A N D
A N D
A N D
3 ms A N D
Transient blocking
Differential Protection Symposium
1-out-of-1
2 150 ms
Saturation detected
3 ms
Trip
n=2
Adaptive restraint
A N D
O R
Trip
2-out-of-2 Trip
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 51
Transformer differential protection 7UT6: Saturation detection and automatic increase stabilisation
Internal faults
Trip
Restrain
Area of add-on restraint
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 52
Transient CT saturation causes false differential currents
IF
IF
+I1
+I2
87
I1
IF
I2
+∆I
∆I
Wave shape similar to transformer inrush current ?
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 53
Adaptive restraint against CT errors (7SD52/61) Detection of CT saturation (wave shape analysis)
CT Error approximation (no-saturation)
Error %
Load range
Fault range
fL
fF 10%
ALF‘/ALFN • IN-CT
Differential Protection Symposium
ALF’ •IN-CT
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 54
Adaptive 87 restraint (7SD52/61) considers current CT- errors IDiff
I1
Trip Area
Trip level With saturation Block-Area
IDiff> 0 0 Current summation:
Trip level Without saturation
I2
External Fault
I2
I1
Max. error (ε) without saturation
IDiff = │I1+ I2│
Max. error (ε) with saturation.
IRest
Max. error summation: IRestraint = ΣIError = IDiff> + εCT1 ·I1 + fSat· εCT2 ·I2
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 55
External fault Increase of stabilisation after detection of saturation Begin of saturation ∆Ι
(K1:iE = -K1:iL1)
Increase of restraint
I∆
IRestraint
ΣΙ Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 56
Fast charge comparison supplement speeds up phasor based line differential protection (7SD52/61) Q2
Q1
iL1/kA 20 10 0 -10
-0,02
-0,01
-0,00
0,01
0,02
0,03
0,04
0,05
0,06
0,07
0,08
-0,02
-0,01
-0,00
0,01
0,02
0,03
0,04
0,05
0,06
0,07
0,08
-0,02
-0,01
-0,00
0,01
0,02
0,03
0,04
0,05
0,06
0,07
0,08
t/s
-0,02
-0,01
-0,00
0,01
0,02
0,03
0,04
0,05
0,06
0,07
0,08
t/s
t/s
-20 -30 -40
iL2/kA 20 10 0 -10
Q3
t/s
-20 -30 -40
iL3/kA 20 10 0 -10 -20 -30
Diff G-AUS
Q 1/4 cycle
1 cycle data windows for phasor comparison •Synchronized with fault inception ¼ cycle data windows of fast charge comparison
Differential Protection Symposium
•Released by Idiff >>
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 57
Generator, Motor and Transformer protection: Adaptive algorithms to upgrade relay stability and dependability with CT saturation (7UT6) Measured value processing i1L i2L
Side 1 Side 2
Sampled momentary values iRes = | i1 | + | i2 | iOp = i1 + i2
Mean values IRes = Mean(iRes) Fundamental wave IOp = RMS(iDiff)60Hz
87 algorithm Operating characteristic IOp
IDiff>
IRes.
Motor start DC component
&
Trip IOp>
Saturation detector
For security:
Harmonic Analysis: -2nd Harmon. Blocking -Cross Blocking
Adaptive restraint
IOp IDiff> >
For dependability: Fast tripping using sampled momentary values ensures fast operation with very high currents before extreme CT saturation occurs!
Differential Protection Symposium
iOp
≥1
Trip IOp>>
IDiff>>>
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 58
Current Transformers for Differential Relaying Requirements and Dimensioning Gerhard Ziegler
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 46
Equivalent current transformer circuit I2′ = I1 ⋅ I1
jX1 R1
N1 N2
Im
P1 N1
P2
jX2
N2 U2
Ideal transformer
R2
I2 S1
Zm
Zb
S2
X1 = Primary leakage reactance R1 = Primary winding resistance X2 = Secondary leakage reactance Z0 = Magnetising impedance R2 = Secondary winding resistance Zb = Secondary load Note:
Normally the leakage fluxes X 1 and X2 can be neglected
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 47
Current transformer: Phase displacement (δ) and current ratio error (ε) w1 . I1 w 2
w1:w2 j·X2
R2 U2
I2
I1
ZB
ε
I2 δ
I‘1=
w1 ·I w2 1
Im
I2
Em
I1 Em
R2
U2
RB
Xm
Differential Protection Symposium
Im
Im
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 48
Dimensioning of CTs for differential protection Pi = I sec .2 × R CT
CT classes to IEC 60044-1: 5P or 10P Specification:
300/1 A
5P10, 30 VA RCT ≤ 5 Ohm Rated burden (nominal power) PN
Ratio In -Prim / In -Sek. 5% accuracy at I= n x In Actual accuracy limit factor in operation is higher as the CT is normally under-burdened : Operating ALF: ALF‘
Accuracy limit factor ALF Dimension criterium:
P + PN ALF ' = ALF × i Pi + PB
I ALF ' ≥ SC − max × KTF In
KTF (over-dimensioning factor) considers the single sided CT over-magnetising due to the d.c. component in short circuit current I SC. KTF values required in practice depend on relay type and design. Recommendations are provided by manufacturers (see Application Guide) Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 49
Current transformer, Standard for steady-state performance
IEC 60044-1 specifies the following classes:
Accuracy class
Current error at nominal current (In)
5P
±1%
10P
± 5%
Differential Protection Symposium
Angle error δ at rated current In
Total error at n x In (rated accuracy limit)
± 60 minutes
5% 10 %
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 50
Current transformers, Standard for transient performance IEC 60044-6 specifies four classes:
Class
Error at rated current Ratio error
TPX (closed iron core)
TPY with anti-remanence air-gap
TPZ linear core
TPS closed iron core
Maximum error at rated accuracy limit
Remanence
Angle error
± 0,5 %
± 30 min
εˆ ≤ 10 %
± 1,0 %
± 30 min
εˆ ≤ 10 %
± 1,0 %
± 180 ± 18 min
εˆ ≤ 10% (a.c. current only)
Special version for high impedance protection (Knee point voltage, internal secondary resistance)
Differential Protection Symposium
Belo Horizonte November 2005
no limit < 10 %
negligible
No limit
G. Ziegler, 10/2005
page 51
Definition of the CT knee-point voltage (BS and IEC)
British Standard BS3938: Class X
U2 10 %
or IEC 60044-1 Amendment 2000/07: Class PX
UKN 50 %
Specify: Knee point voltage Secondary resistance RCT Im
I U KN ≥ K TF ⋅ (R CT + R B − connected ) ⋅ SC − max . I n − CT Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 52
CT specification according to ANSI C57.13
w1 I‘1= w ·I1 2
I2
Im
Em
ANSI C57.13 specifies:
RCT RB
U2
• Secondary terminal voltage U2 at 20 times rated current (20x5=100 A) and rated burden • Error > ALF‘ > (I>>set / In) Belo Horizonte November 2005
G. Ziegler, 10/2005
page 68
Coordination of CTs and digital relays Summary ü Digital relays use intelligent algorithms and are therefore highly tolerant against CT saturation. ü In particular differential relays allow short time to saturation of ¼ cycle and below. ü Determination of transient dimensioning factors for short time to saturation must consider the real flux course after fault inception. ü With time to saturation < 10 ms, the critical point on wave of fault inception is not close to voltage zero-crossing (fully offset current), but varies and is closer to voltage maximum (a.c. current). ü CT dimensioning is normally based on relay specific Ktd factors provided by manufacturers ü In practice, fully offset s.c. current has been assumed while remanence has been widely neglected for CT dimensioning. ü A new dimensioning factor is discussed in CIGRE WG B5.02, composed of more probable transient and remanence factors. Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 69
CT dimensioning for differential protection (1) 1. Calculation of fault currents 110/20 kV F1 40 MVA 110 kV, 3 GVA uT=12%
F2
OH-line: l = 8 km, zL‘= 0,4 Ω/km
F3
Net 300/1A
7SD61
7UT61
Impedances related to 20 kV:
Impedances related to 110 kV:
Transf. :
∆ IL
∆ IL
∆ IT
Net :
200/1A
200/1A
1200/1A
F4
U N 2 kV 2 110 2 ZN = = = 4.03 Ω S SC ' ' [MVA ] 3000
Net :
U N 2 kV 2 uT [% ] 110 2 12 % ZT = ⋅ = ⋅ = 36.3 Ω PN -T [MVA ] 100 40 100
Transf. :
U N 2 kV 2 20 2 ZN = = = 0.13 Ω SSC ' ' [MVA ] 3000 U N 2 kV 2 uT [% ] 20 2 12 % ZT= ⋅ = ⋅ = 1.2 Ω PN - T [MVA ] 100 40 100
Line : Z L = l[km ] ⋅ z L ' [Ω/km ] = 8 ⋅ 0,4 = 3,2 Ω
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 70
CT dimensioning for differential protection (2)
F1
I F1 =
1.1 ⋅ U N / 3 1.1 ⋅ 110kV/ 3 = = 17.3 kA ZN 4.03 Ω
F2
I F2 =
1.1 ⋅ U N / 3 1,1 ⋅ 110kV/ 3 = = 1.73 kA Z N + ZT 4.03 Ω + 36.3 Ω
F3 I F3 = F4
I F4 =
1.1 ⋅ U N / 3 1.1 ⋅ 20kV/ 3 = = 9.55 kA Z N + ZT 0.13Ω + 1.2Ω
1.1 ⋅ U N / 3 1,1 ⋅ 20kV/ 3 = = 2.8 kA Z N + Z T + Z L 0.13Ω + 1.2Ω + 3.2Ω
Dimensioning of the 110 kV CTs for the transformer differential protection: Manufacturer recommends for relay 7UT61:
1) Saturation free time ≥ 4ms for internal faults 2) Over-dimensioning factor KTF ≥ 1,2 for through flowing currents (external faults)
The saturation free time of 3 ms corresponds to KTF≥ 0,75 See diagram, page 59 Criterion 1) therefore reads:
I 17300 ALF' ≥ K TF ⋅ F1 = 0,75 ⋅ = 43 IN 300
For criterion 2) we get: I 1730 ALF' ≥ K TF ⋅ F2 = 1,2 ⋅ =7 IN 300
The 110 kV CTs must be dimensioned according to criterion 1).
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 71
CT dimensioning for differential protection (3) We try to use a CT type: 300/1, 10 VA, 5P?, internal burden 2 VA.
ALF ≥
Pi + Poperation 2 + 2.5 ⋅ ALF ' = ⋅ 43 = 16.1 (Connected burden estimated to about 2.5 VA) Pi + Prated 2 + 10
Chosen, with a security margin : 300 /1 A, 5P20, 10 VA, R2≤ 2 Ohm (Pi ≤ 2VA) Specification of the CTs at the 20 kV side of the transformer: It is good relaying practice to choose the same dimensioning as for the CTs on the 110 kV side: 1200/1, 10 VA, 5P20, R2≤ 2 Ohm (Pi ≤ 2VA) Dimensioning of the 20 kV CTs for line protection: For relay 7SD61, it is required: The saturation free time of 3 ms corresponds to KTF≥ 0.5 See diagram, page 59 Criterion 1‘) therefore reads: I 9550 ALF' ≥ K TF ⋅ F3 = 0.5 ⋅ = 24 IN 200
1‘) Saturation free time ≥ 3ms for internal faults 2‘) Over-dimensioning factor KTF ≥ 1.2 for through flowing currents (external faults)
For criterion 2‘) we get:
I 2800 ALF' ≥ KTF ⋅ F4 = 1.2 ⋅ = 16 .8 IN 200
The 20 kV line CTs must be dimensioned according to criterion 1‘).
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 72
CT dimensioning for differential protection (4)
For the 20 kV line we have considered the CT type: 200/5 A, 5 VA, 5P?, internal burden ca. 1 VA
Pi + Poperation 1+1 ⋅ ALF ' = ⋅ 24 = 8 ALF ≥ Pi + Prated 1+ 5
(Connected burden about 1 VA)
Specification of line CTs: We choose the next higher standard accuracy limit factor ALF=10 : Herewith, we can specify: CT Type TPX, 200/5 A, 5 VA, 5P10, R2≤ 0.04 Ohm ( Pi≤ 1 VA)
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 73
Interposing CTs, Basic versions
w1
i1
separate winding connection
i2
i1
w2
wa
i2
wb
i1 -i2
Relay
i2 =
w1 ⋅ i1 w2
auto-transformer connection Relay
i2 =
wb ⋅ i1 wa + wb
No galvanic separation!
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 74
Interposing CTs, Example
1A W1= 21 turns
600/1 A
1A
600/1 A
Differential Protection Symposium
1,5 A W2= 14 turns
1A
Wa=16 turns
0,5 A
Wb=32 turns
RB
1,5 A
RB
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 75
Interposing CTs in Y-∆-connection
Yd5
-I1c
I1a
I2a-c
I1b
I2b-a I2c-b
I1c
w1
I2a
I1a
-I1b
I2c
I1b I1c
w1 = w2
w2 I1 =
Differential Protection Symposium
150O
I2b I2b
I2c
-I1a I2a
o 1 w ⋅ I 2 ⋅ 2 ⋅ e j ⋅( n⋅30 ) w1 3
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 76
False operation during external fault of transformer differential protection without zero-sequence current filter
L1 L2 L3
∆I
Differential Protection Symposium
∆ I
∆I
∆I>0 without delta winding!
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 77
Zero-sequence current filter
I1a
I3a
I2a
I1b
I3b
I2b
I1c
I3c
I2c
I 1a ⋅ w1 + I 2a ⋅ ww2 + I 3a ⋅ w3 = 0 I 1b ⋅ w1 + I 2b ⋅ ww2 + I 3b ⋅ w3 = 0 I 1c ⋅ w1 + I 2c ⋅ ww2 + I 3c ⋅ w3 = 0 I 3a = I 3b = I 3c I 2a + I 2b + I 2c = 0
Differential Protection Symposium
Relay
I w I +I +I I 3a = I 3b = I 3c = 1 ⋅ 1a 1b 1c = E w3 3 3 I +I +I w I 2a = 1 I 1a − 1a 1b 1c w2 3 I 1a + I 1b + I 1c w1 I 2b = I − 3 w2 1b I +I +I w I 2c = 1 I 1c − 1a 1b 1c 3 w2 Belo Horizonte November 2005
G. Ziegler, 10/2005
page 78
Biasing of transformer differential protection during external earth fault with zero-sequence current filter (closed delta winding)
L1 L2 L3
With delta winding: ∆I=0 !
Differential Protection Symposium
∆I
∆ I
∆I
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 79
Current matching with interposing CTs (1) Calculation example 110 kV ±16% L1
75 / 1 A
Yd5
6.3 kV
53.9A
915A
1200 / 5 A
L2 L3 0.719A
3.81A
∆I
3,81 = 2,20 3
Differential Protection Symposium
∆I
∆I
In-Relay = 5A
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 80
Current matching with interposing CTs (2) Calculation example Current transformation ratio: We take through flowing rated current as reference: : 110kV-side: Mean current value of upper and lower tap changer position:
I1 =
10,000kVA = 45.2A 3 ⋅ (110kV + 16%
6 kV-side:
I2 =
10,000kVA = 62.5A 3 ⋅ (110kV − 16%
I1' =
I1− mean =
45.2 + 62.5 = 53.9A 2
10.000kVA = 915A 3 ⋅ 6.3kV
The corresponding secondary currents are:
i1 = 53 . 9 ⋅
1 = 0 . 719 A 75
and
i 2 = 915 ⋅
5 = 3.813 1200
. The current in the star connected winding of the interposing transformer is The current in the delta connected winding is:
i.1
i2 / 3 .
The ratio of the interposing CT must be :
w1 i 2 / 3 3.813 / 3 2.202 = = = = 3.06 w2 i1 0.719 0.719
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 81
Link selectable interposing CT 4AM5170-7AA
P1
S1
i2
A B C DE
1 0,013
2
F G H I
7
0,025 0,08
S2
P2
i1
K L
M N O P Q
16
1
2
7
16
Windings
0,75
0,013
0,025
0,08
0,75
R in Ohm
2
4
14
32
2
4
14
32
U-max. in V
5
5
5
1
5
5
5
1
Rated current in A
w1 i2 / 3 3,813 / 3 2, 202 = = = = 3.06 w2 i1 0,719 0,719
chosen :
w1 16 + 16 + 2 34 = = = 3,09 w 2 7 + 2 + 1 + 1 11 Connection and links as shown.
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 82
Designation of transformer or CT vector groups (1) Clock-wise notation according to IEC 60076-1
11
12 0
1
0
2
10 9
3 8
4 7 6
4 8
0
6
0
6
4
1 0
4
1 0
8
2
8
2
5 9 1 (13)
5
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 83
Designation of transformer or CT vector groups (2) Clock-wise notation according to IEC 60076-1, examples
I
II
III
12
I
II
12
III
I
I
III II
III II
HS
I I
II
III
NS
II
12
III
11 12 I III II
I III II I
II
III
Dyn11
12 II
III I 5
Yny0d5
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 84
Frequently used vector groups (IEC 60076-1)
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 85
Finding the vector group by using the clock principle
Proceed in the following steps: 1. Starting on the high voltage winding, the phase connection terminals are numbered with 0, 4, 8 (always 4 x 30 O= 120O phase shift). 2. The opposite end of each winding is labelled with a number incremented by +6 relative to the phase connection (6x 30 O =180O). 3. The secondary windings are numbered the same. In this context it is assumed that the polarity of the windings is the same in the diagram. (If in doubt, polarity marks may also be applied.) 4. The phase connection is labelled with the average value of the corresponding terminal designations belonging to the winding terminals connected to this phase terminal, e.g. (6+4)/2= 5 5. The difference between the high and low voltage side terminal numbers of same phases corresponds each with the vector group number, being Yd5 in this case.
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 86
Checking the connections of transformer differential protection using the clock-wise notation method
Yd5 L1 L2 L3
6
0
10 4 2
0
6
0
6
5
4
10
4
10
9
5 11
8
2
8
2
1
9
3
1
7
8
6
12
6
12 11
10
4 8
10
4 3
2
8 7
2
Yd5
Differential Protection Symposium
∆I
∆I
∆I
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 87
Current distribution in Y-∆-transformer circuits for different external fault types
3
1
3
G
G
G
3 1
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 88
Checking the connections of transformer differential protection using the arrow method (two-phase fault)
Yd5
1
3
L1
3
L2 L3 3 3
= 3
3
∆I
∆I
Differential Protection Symposium
∆I
3
Dy5
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 89
Checking the connections of transformer differential protection using the arrow method (single-phase earth fault)
Yd5
1
L1 L2 L3
∆I
∆I
Differential Protection Symposium
∆I
3
Dy5
3
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 90
Digital Differential Protection Communications Gerhard Ziegler
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005 page 87
Comparison protection Absolute selectivity by using communication
IA
A
IB
B
• Directial comparison distance protection Exchange of YES/NO signals (e.g. fault forward / reverse) • Current comparison (phasors) differential protection
Protection Relay
Communication samples, phasors, binary signals
| ∆I |
Protection Relay
IA
IB
| ∆I | = | IA - IB | > Ipick-up
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005 page 88
Signal transmission channels for differential relaying Pilot wires - AC (50/60 Hz), voice frequency and digital communication (128 - kbit/s) - for short distances (< about 20 km) - influenced by earth short-circuit currents! Optical fibres - wide-band communication (n · 64 kbit/s) - digital signal transmission (PCM) - up to about 150 km without repeater stations - noise proof Digital microwave channels 2 - 10 GHz - wide-band communication (n · 64 kbit/s) - digital signal transmission (PCM) - up to about 50 km (sight connection) - dependent on weather conditions (fading) Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005 page 89
Analog pilot wire differential relaying
3
3
87L
87L
• Pilot wires are normally operated insulated form earth • Voltage limiters (glow dischargers) connected to earth , as used with telephone lines, are not allowed!
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005 page 90
Relay-to-Relay pilot wires communication New technology on existing (copper-) pilots Traditional:
Composed current measurement Comparison of analogue values
Modern:
E
O
O
E
Phase segregated measurement
Digital data transmission 64 kbps bi-directional 4 value digital code (2B1Q) Amplitude and phase modulation Spectrum mid frequency: 80 kHz
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005 page 91
Wire pilot cables Longitudinal voltage induced by earth currents Relay B
Relay A
G IF
Φ E
F1
E/2 F2
Differential Protection Symposium
A) Symmetrical coupling along the pilot cable
E/2
F2
F1
E
Belo Horizonte November 2005
B) Unsymmetrical Coupling along the pilot cable
G. Ziegler, 10/2005 page 92
Disturbance voltage caused by rise in station potential
RG STP STP
E Ω = I SC − G ⋅ R G
PGA RGP Legend: RG STP PGA RGP E
station grounding resistance station potential potential gradient area remote ground potential station potential rise against remote ground (ohmic coupled disturbance voltage )
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005 page 93
HV insulated protection pilot cable (example) core diameter
pilot resistance Core Loop
pilot capacitance
mm
Ω/km
Ω/km
nF/km
1,4 0,8
11,9 ---
--73,2
--60
test voltage (r.m.s. value) triple pair pair to core- coretriple to core core shield core pair to triple core kV kV kV kV kV 2,5 8 8 8 2 2 2
Symmetry: better 10–3 (60 db) at 800/1000 Hz better 10–4 (80 db) at 50/60 Hz (Uq 2 Mbit/s
Differential Protection Symposium
Clock Belo Horizonte November 2005
G. Ziegler, 10/2005 page 107
Communication through transmission networks
M U X
A User / Source
Modem Network node circuit / packet switching trunk
Modem
Station user terminal point
M U X
line Transmission path
B loop
Differential Protection Symposium
User / Destination
Belo Horizonte November 2005
G. Ziegler, 10/2005 page 108
Structure of a modern data communication network
622 Gbit/s
ØNetworks are plesiochronous (PDH), synchronous (SDH) or asynchronous (ATM) ØData terminal devices (e.g. relays) are synchronised through the network ØRings guarantee redundance. ØData of different services (e.g. telephone and protection are commonly transmitted (time multiplexed) ØProtection relays must be adapted to the given network conditions (e.g. changing propagation time due to path witching.
622 Gbit/s
POTS: Plain Old Telephone Services ISDN: Integrated Services Digital Network STM-n: Synchronous Transport Module level n SMA: Synchronous Module Access ATM: Asynchronous Transmission Mode ISP: Internet Service Provider
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005 page 109
Comparison of Switching Methods Circuit Switching
Packet switching
The physically assigned channel is established before and disconnected after communication
Data stream is segmented to packets
POT (Plain old telephony), ISDN Digital networks on basis of PCM with plesiochronous digital hierarchy (PDH) Reliable and fast transmission possible when connection is established. Circuit establishment requires a free channel from A to B Connection occupies channel also when no data is exchanged Deterministic data transmission (fixed data transmission time per channel)
Differential Protection Symposium
Transmission runs connection-oriented or connection-less Synchronous digital hierarchy (SDH), ATM Backbone Cannel not occupied during whole connection time Channels can be used quasi-simultaneously Data transmission by principle time is random. SDH and ATM can provide virtual circuitswitched channels. However, split path signal routing may however result in unsymmetrical signal transmission times.
Belo Horizonte November 2005
G. Ziegler, 10/2005 page 110
SDH network: Split path routing
Node F
Node E
Node D
Standby path
Node A tP2‘ Node B Relay End 1
Differential Protection Symposium
tP1
Node C
tP1‘
tP2 Healthy path
Relay End 2
Belo Horizonte November 2005
G. Ziegler, 10/2005 page 111
Digital Transport Systems: Bundling of channels PCM 7680
PDH Hierarchy
PCM 1920
Plesiochronous (almost synchronous) PCM 480 PCM 120 PCM 30
M U X
M U X
M U X
M U X
M U X
565 Mbit/s
140 Mbit/s
32 Mbit/s
8 Mbit/s
2 Mbit/s
64 kbit/s
SDH Hierarchy Synchronous SMT-1 155 Mbit/s
SMT-4 622 Mbit/s
1
SMT-16 2.5 Gbit/s 1 2
1 2
2 3
3
3 4
Differential Protection Symposium
SMT-64 10 Gbit/s 1
4
4 Belo Horizonte November 2005
G. Ziegler, 10/2005 page 112
PDH (Plesiochronous Digital Hierarchy)
Multiplexing structure: ØBase rate 64 kbit/s (digital equivalent of analogue telephone channel) ØEquipments may generate slightly different bit rates due to independent internal clocks ØBit stuffing is used to bring individual signals up to the same rate prior to multiplexing (Dummy bits are inserted at the sending side and removed at the receiving side) ØIntermediate inserting and extracting of individual channels is not possible, but the full multiplexing range has always to be run through. Hierarchical level 0 1 2 3 4
Europe 64 kbit/s 2‘048 Mbit/s 8‘448 Mbit/s 34‘368 Mbit/s 139‘264 Mbit/s
Differential Protection Symposium
USA 56 kbit/s 1‘544 Mbit/s 6‘312 Mbit/s 44‘736 Mbit/s 139‘264 Mbit/s
Belo Horizonte November 2005
G. Ziegler, 10/2005 page 113
SDH (Synchronous Digital Hierarchy) Multiplexing structure Ø SONET (Synchronous Optical Network) first appeared in USA (1985) Ø ITU-T (formerly CCITT) issued B-ISDN as world wide standard (1988) Ø All multiplexing functions operate synchronously using clocks derived from a common source Ø Designed to carry also future ATM SDH STM level STM-1 STM-4 SZM-16 STM-64
Aggregate Rate 155,520 Mbit/s 622,080 Mbit/s 2‘488,320 Mbit/s 9‘953,280 Mbit/s
Differential Protection Symposium
SONET OC level
STS level
Aggregate Rate
OC-1 OC-3 OC-12 OC-48 OC-192
STS-1 STS-3 STS-12 STS-48 STS-192
51,840 Mbit/s 155,520 Mbit/s 622,080 Mbit/s 2‘488,320 Mbit/s 9‘953,280 Mbit/s
Belo Horizonte November 2005
G. Ziegler, 10/2005 page 114
ATM (Asynchronous Transfer Mode) and Broadband B-ISDN Features of ATM: Ø Synchronisation individually per packet
Voice Audio
Fax
Data
Video
Ø Packets carry each complete address of destination so that each can be separately delivered (Datagrams, here called Cells) Ø Information stream is segmented into cells that are 53 octets long Ø ATM sets up a virtual switched connection and sends data along a switched path from source to destination
ISDN
Ø Requirements on bandwidth, bounded delay and delay variation can be set by the user ØSingle cells can be inserted or removed at the nodes, as required Ø The predominant use is for net backbones
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005 page 115
TDM over optical fiber
Hicom
FO MUX >2 Mbit/s L1-L2 21,3 KA 73,6 kW
I O
Optic fibres in the core of earth wires
x 64 kbit/s
V
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005 page 116
Bit error rate (of data channels) Bit error rate:
p=
number of faulty bits total number of sent bits
Typical bit error rates of public services: Telephone circuits ca. 10 -5 Digital data networks (Germany) ca. 10 -6 to 10-7 Coaxial cables (LAN) ca. 10 -9 Fiber optic communication ca. 10 -12 Utility conditions (CIGRE SC34 Report 2001): Fiber optic communication ca. 10 -6 Data networks (PDH, SDH, ATM) ca. 10-6 Microwave ca. 10 -3 Requirements acc. to CIGRE report: Protection and control in general: < 10-6 Function guaranteed up to < 10 -3 however downgraded (reduced operating speed) Line differential protection < 10 -6 and < 10-5 during power system faults
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005 page 117
Error detection methods: Cyclic redundancy check 01111110 Flag
01111110 Address
Control
I(x)
Data field
Check field
Flag
I(x) + R(x) Receiver
Sender
Division by G(x)
R(x) = CRC
error free data block
CRC 16: G(x) = X16 + X15 + X2 + 1 binary: 1 1000 0000 0000 0101 Reduction of the block failure rate by the factor > 10 -5 against the bit failure rate! (CRC 32: > 10-10)
Differential Protection Symposium
Division by G(x)
R(x) = 0
faulty data block
Belo Horizonte November 2005
G. Ziegler, 10/2005 page 118
Data integrity (line differential protection 7SD52/61)
Received data
Block failure rate P = 10-5
Error detection e.g. CRC = 32
Residual data
Block failure rate R = 10-15
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005 page 119
Residual error rate
Residual error rate:
R=
number of not detected faulty telegrams (data blocks) total number of sent telegrams (data blocks)
Practical range of protection and control systems: Time between 2 not detected errors:
T=
R < 10 -10 to 10-15
n v⋅R
n= length of telegram (data block) v= transmission speed in bit/s
Example: Telegrams of n =200 bit are continuously transmitted at 64 kbit/s. R
T
10-7
20 hours
10-10
2.3 years
10-15
230000 years
typical application cyclic transmission (metering)
remote control and protection
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005 page 120
Protection of a short line lines Differential relay using direct digital relay-to-relay communication
A
B
D 7SA6
D 7SA6
Communication via direct relay-relay connection Fibre type
optical wave length
maximum attenuation
permissible distance
Multi-mode 62.5/125 µm
820 nm
16 dB
ca. 3.5 km
Monomode 9/ 125 µm
1300 nm
29 dB
ca. 60 km
9/ 125 µm
1500 nm
29 dB
ca. 100 km
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005 page 121
Line differential relaying using digital communication A
B
D 7SD52
D 7SD52 D 7SD52
Chain topology or redundant ring topology
typical Adaptive add-on stabilisation Settable time difference to consider given data transmission asymmetry
l Adaptive topology recognition Automatic recognition of connections and remote end devices Automatic re-routing from ring to chain topology if one data connection fails In case of multi-terminal protection, remaining relay system continues operation if one line end is switched off and the relay is logged out for maintenance
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005 page 123
Individual time references by synchro-phasors Definition of a synchrosynchro-phasor: phasor: SynchroSynchro-phasors, phasors, are phasors, phasors, which are measured at different network locations by independent devices and referred to a common time basis
Time reference iB
iA
Ort : A
Ort : B IM
IA
relay A
RE
IB relay B
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005 page 124
Phasor synchronisation between line ends
A
tA1 tA2
∆I
∆I
curre n phas t o rs
tAR
tA5
B
α ...
tA1
tPT1
tB2
tBR
α=
tB3
tPT2 ...
tV tB3 tA1
nt curre rs ph aso
Signal transmission time: Sampling instant:
Differential Protection Symposium
IB( tB3 )
tB1 tD
tA3 tA4
IB( tA3 )
t B3 - t A3 ⋅ 360 ° TP
tB4
t PT1 = t PT2 =
1 (t A1 - t AR - t D ) 2
t B3 = t AR - tTP2 Belo Horizonte November 2005
G. Ziegler, 10/2005 page 125
Specification of data channel for line differential protection based on Cigre Report: Protection using Telecommunication *)
Data rate
64 kbit/s (min.)
Channel delay time:
< 5 ms
Channel delay time unsymmetry:
< 0.2 ms
Bit error rate normal:
< 10 -6
during power system fault Availability:
< 10-5 *) > 99.99 %
*) Report of WG34/35.11, Brochure REF. 192, Cigre Central Office, Paris, 2001, *) It is suggested that for a BER of less than 10-6 the dependability shall not suffer a noticeable deterioration . For a BER of 10-6 to 10-3 the teleprotection may still able to perform its function although a loss in dependability is to be expected.
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005 page 126
Digital Protection of Generators and Motors Gerhard Ziegler
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
Seite 116
Generator differential protection
a a c
S
S S A
IA/In 3 2
S S A
1 S A
Connection circuit
Differential Protection Symposium
1
2
3
4
5
6
IS/In
Operating characteristic
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Seite 117
Generator HI differential protection
a b c
A
Differential Protection Symposium
A
A
Belo Horizonte November 2005
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Seite 118
Transverse differential protection
a
b
c
S
S S
S S
A
Differential Protection Symposium
A
S A
Belo Horizonte November 2005
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Seite 119
HI earth current differential protection
L1 L2 L3
∆IE>
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
Seite 120
Earth current differential protection for generators
L1 L2 L3
U0>
∆IE> Tripping
Differential Protection Symposium
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G. Ziegler, 10/2005
Seite 121
Motor starting current
20
IRush /IN
TRush
15
Tst 10
Ist/IN
5 0 5
0
50
100
150
200
250
300
tst (ms)
Differential Protection Symposium
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Seite 122
Transformer Differential Protection Gerhard Ziegler
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 123
Transformer: Function principle and equivalent circuits I1
w1
w2
I2
U1
Xσ1
R1
Φ
U2 Φ σ1
Φ σ2
U1
I1
I ⋅ w + I ⋅ w = I µ ⋅ w1 1 1 2 2
I µ
K OB 4 ⋅ K OB − 1
10
20
t
20
1
or
k>
1 4 ⋅ K TF − K 2 TF
KOB= CT over-burdening factor KTF= 1/KOB = CT over-dimensioning factor
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 240
Digital busbar protection 7SS5, Measuring technique External fault, fault current with DC offset I1
I2
2 2
I1
IOp= |I1+I2| 0
20
40
1
60
0
20
0
20
40
60
40
60
40
60
2
I2 0
20
40
60
k·IRes =k·(|I1|+|I2|)
1
2
t
2
IRes=|I1|+|I2|
1
∆I=IOp - IRes
1
0
20
1 0
20
40
Differential Protection Symposium
60
2
Belo Horizonte November 2005
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page 241
Digital busbar protection 7SS5, Measuring technique Internal fault, fault current with DC offset I1
I2 3 2 1
2
IOp= |I1+I2|
I1
0
20
40
60
40
60
1 0
I2
20
40
2
t
2
k·IRes =k·(|I1|+|I2|) 0
20
t
2 3
60
40
1 0
60
20
1 t
2 2 2
∆I=IOp - IRes
IRes=|I1|+|I2| 0
20
40
60
0.75 0.5 0
40
60
1.75 3
Differential Protection Symposium
20
Tripping!
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 242
CT dimensioning for busbar protection 7SS5, Example (1)
25 ⋅ 106 I N −T = = 1440A 10 ⋅103 ⋅ 3
110kV SSC‘‘= 4 GVA 110/10 kV 25 MVA uT= 14% TT= 60 ms
G
1500/1
2MW
600/1 300/1
150/1
5MW
10 kV 10 MVA Xd‘‘= 15% TG= 100 ms
300/1
300/1
ISt= 6·IN Xd‘‘= 17% TM= 35 ms
M
M
5MW
5MW
Differential Protection Symposium
I N −G =
10 ⋅10 6 = 577A 3 10 ⋅ 10 ⋅ 3
5 ⋅10 6 ΣI N − M -HV = 2 ⋅ = 577A 3 10 ⋅ 10 ⋅ 3
IF−T =
1.1 ⋅ 1440 = 11.3 kA 0.14
IF−G =
1.1 ⋅ 577 = 4.2 kA 0.15
ΣI F − M =
Belo Horizonte November 2005
1.1 ⋅ 577 = 3.7 kA 0.17
G. Ziegler, 10/2005
page 243
CT dimensioning for busbar protection 7SS5 and 7SS6, Example (2) As worst case, the CT 150/1 A in bay 1 is considered. Total fault current with a fault at the transformer HV terminals:
ΣI F = I F − T + I F − G + ΣI F − M = 11,3 + 4,2 + 3,7 = 19,2 kA Equivalent time constant:
I ⋅ T + I F − G ⋅ TG + ΣI F − M ⋅ TM 11.3 ⋅ 60 + 4.2 ⋅ 100 + 3.7 ⋅ 35 TEquiv. = F − T T = = 64 ms I F − T + I F − G + ΣI F − M 11.3 + 4.2 + 3.7 We consider a CT type 5P?, 30 VA, internal burden Pi= 15% (4.5 VA): Connected burden Pa= 1 VA CT over-dimensioning factor for 3ms saturation free time: KTF ca. 0.45 Corresponding to an overburdening factor of kOB= 1/KTF = 2.2 Checking of the k-setting (Stability with symmetrical fault currents):
ALF ' =
ΣI F I N − CT
⋅ K TF =
19 .200 ⋅ 0 . 45 = 58 150
k>
k OB 4 ⋅ kOB − 1
ALF =
=
2,2 = 0 .5 (chosen: k=0.6) 4 ⋅ (2 .2 − 1)
Pa + Pi 1 + 4.5 ⋅ ALF ' = ⋅ 58 = 9.3 PN + Pi 30 + 4.5
We finally choose: CT 5P10, 150/1, 30 VA, R2≤ 4.5 Ohm
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 244
Transient performance of iron closed CT cores (type TPX) Over-dimensioning factor KTF for short time to saturation
1.5
1.5
KTF
1.4
TM
1.3
KTF
1.4 1.2
1.2
5 ms
1.1
1.1
1
1
0.9
0.9
0.8
4 ms
0.7 0.5
0.5
3 ms
0.3
0.2
0.2
0.1
0.1 10 20 30 40 50 60 70 80 90 100
3 ms
0.4
0.3
0
4 ms
0.7 0.6
0.4
5 ms
0.8
0.6
0
TM
1.3
0
0
1
2
3
4
6
7
8
9
10
TN
TN
Differential Protection Symposium
5
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page 245
High impedance busbar protection
RCT
RCT
RCT
RCT
RCT: Resistance of CT secondary winding
RL
RL
RL
RL
RL: Connection cable resistance RRV: Relay series resistance RRS: Relay shunt resistance
RRS
Varistor IV
IS
RRV ∆I
Differential Protection Symposium
IR
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 246
HI busbar protection, calculation example RL= 3 Ohm (max.) IR=20 mA (fixed value) RRV = 10 kOhm RRS = 250 Ohm Iv = 50 mA (at relay pick-up voltage)
Given: :n = 8 feeders rCT = 600/1 A UKN = 500 V RCT = 4 Ohm ImR = 30 mA (at relay pick-up voltage)
Primary pick-up current: I F − min = rCT ⋅ (I R + IS + I V + n ⋅ I mR I F − min =
Stability with external faults:
)
I F − through − max < rCT ⋅
600 ⋅ (0.02 + 0.89 + 0.05 + 8 ⋅ 0.03 ) 1
I F − min = 666A ⋅ (111%I N − CT )
Differential Protection Symposium
I F − through − max
, t
50N/51N
Ground overcurrent (IE, t)
50G/51G
Hand reset trip
86
Unbalanced current I2>, t
46
Trip circuit supervision
74TC
Thermal overload IEC 60255-8
49
Therm. OL IEC 60354 (hot spot)
49
Differential Protection Symposium
ANSI No.
Binary inputs for tripping commands
Belo Horizonte November 2005
G. Ziegler, 5/2005
page 251
7UT6: Application
(1) ∆
∆I ∆I Shunt Reactor
G
Three winding transformer
Two winding transformer
∆I
Generator / Motor
Differential Protection Symposium
∆I
∆I
Transformer bank (1-1/2-LS)
∆I
∆I
Busbars
Belo Horizonte November 2005
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page 252
7UT6: Application Generation Unit protection (overall differential)
Y ∆
(2)
HI restricted earth fault protection
7UT6xx 7UT635
G 3~
Differential Protection Symposium
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G. Ziegler, 5/2005
page 253
7UT6: selectable: I0-correction or restricted earth fault protection YN
yn0
d5
R S T
49 (1)
49 (2)
50 51
∆ITE
∆IT 7UT613
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 5/2005
page 254
7UT6: operating characteristic
Idiff >>
7 Locus of internal faults
6
I Op In
45° 5
S
operate
e2 p lo restrain
4
*)
3 2
Idiff >
1
e1 p o l S
0 0
2
supplementary restraint
4
6
8
10
12
14
16
IRes
*) Slope of add on characteristic:
In
7UT6 à as slope 1 (7UT5 à ½ of slope 1)
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 5/2005
page 255
7UT6: Effect of supplementary restraint in case of CT saturation
Restrain 45°
Trip
Area of add-on restraint
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 5/2005
page 256
Differential protection functions IDiff> and IDiff>> Sampled momentary values
Measuring value processing i1L
iRes = |i1|+ |i2|
Side 1
i2L
iOp = i1 + i2
Side 2
Average value IStab = iRest Fundamental wave: IDiff = Eff(iDiff)50Hz
Operating characteristic, Saturation detector IDiff IDiff>
IStab
&
Trip IDiff>
≥1
Trip IDiff>>
Motor start, DCcomonent Harmonic Analysis: -2nd Harmon. Blocking -Cross Blocking
iRes IRes
IDiff
IDiff IDiff>>
I / InO
I / InO
iDiff
ms
iDiff 2·IDiff>> ms
Fast tripping using sampled momentary values ensures dependable operation in case of extreme CT saturation!
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 5/2005
page 257
7SA6: Temperature monitoring
RS485 Interface
7XV5662-(x)AD10
7XV5662-(x)AD10
Two thermo-devices can be connected to the serial service interface (RS485) Monitoring of up to 12 measuring points (6 per thermo-device) - each with two pick-up levels Display of the measured temperatures - directly at the thermo-device (which can also be used stand alone) - at the relay One input is reserved for hot spot monitoring (measurement of oil temperature) Thermistors: Pt100, Ni100 or Ni120
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 5/2005
page 258
7UT6: Temperature monitoring with hot spot calculation (1) Example: Natural cooling Θ h = Θ O + H gr ⋅ k Y
Θh= hot spot temperature Θh= oil temperature Hgr=hot-spot-to-oil temperature gradient k= load factor I/In Y= winding exponent
Aging rate: Oil Temp.
HV LV
Aging at Θh V= = 2(Θ h −98)/6 Aging at 98°C
98O is reference for the aging of Cellulose insulation
Mean value of aging during a fixed time interval: T
2 1 L= ⋅ ∫ V ⋅ dt T2 − T1 T1
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 5/2005
page 259
7UT6: Temperature monitoring with hot spot calculation (1) Example: Natural cooling
Θ h = Θ o + H gr ⋅ k Y ≈ 73 + 23 ⋅1.151.6 = 102°C
(L)
V = 2(Θ h −98)/6 = 2(102−98)/6 ≈ 1.6 108°C
k, V, L
98°C 102°C 73°C
Θh Hot spot temp. Θo oil temp. (from thermodevice)
[°C]
Θh Θo
1.6
k (I/In)
V (relative aging) L (mean value of V)
1.15
t
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 5/2005
page 260
7UT6: Commissioning und service tool
(1)
WEB-Technology Access to WEB Browser Help system in the INTRANET / INTERNET http://www.siprotec.com
Relay homepage address of : http://141.141.255.160 IP-address can be set with program DIGSI 4 at the front or service interface of the relay
1. Serial connection Directy or with modem to standard DIAL-UP network 2. HTM L page view at IP-address of the relay http://141.141.255.160
Differential Protection Symposium
WEB server in relay firmware Server sends HTML pages and JAVA code to WEB Browser via DIAL-UP connection
Belo Horizonte November 2005
G. Ziegler, 5/2005
page 261
7UT6: Commissioning and service tool
(2)
Current phasors of all terminals can be displayed
Transformer YNd11d11, 110/11/11kV, 38.1MVA, IL2S2à wrong polarity
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 5/2005
page 262
7UT6: Commissioning and service tool (3) Operating/restraint position can be displayed
Transformer YNd11d11, 110/11/11kV, 38.1MVA, IL2S2à wrong Polarität
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 5/2005
page 263
Power Transmission and Distribution
Differential Protection (7UT)
Determination of the Transformer Vector Group
Transformer with Vector Group Yy0
7UT612
80 MVA Yy0 2500A/1A
20 kV
110 kV 500A/1A
PTD PA13 N. M Tests 7UT 05/03 No. 2
Method of Vector Group Determination (ExampleYy0) IL1,S2
Side 2:
Side 1:
2L1 1L1
IL1,S1
2L2
1L2 2L3 1L3
IL1,S2 = IL1
UL1,S1
UL1,S2
IL1,S1
UL3,S2
UL2,S2
UL3,S1
UL2,S1
0° Vector group is
Yy0 PTD PA13 N. M Tests 7UT 05/03 No. 3
Transformer Protection
7UT612
80 MVA Yd11 2500A/1A
20 kV
110 kV 500A/1A
PTD PA13 N. M Tests 7UT 05/03 No. 4
Method of Vector Group Determination (ExampleYd11) IL1,S2
Side 2:
Side 1:
2L1
IL1,S1
2L2
1L1 1L2
2L3 1L3
IL1,S2 = IL1 - IL2
IL1,S1
UL1,S1
UL1,S2
UL2,S2 UL3,S1
UL2,S1
UL3,S2
Vector group is Y d 11
330° (n * 30°)
PTD PA13 N. M Tests 7UT 05/03 No. 5
Definitions in SIPROTEC 4 Relays
Vector definition to a node is positive The shown vectors or phase angles are transformed in this positive definition The phase angle is displayed mathematics positive. The reference phase is always phase L1 on side 1 How to see the vector group Yd11? Original
Siprotec 4 (Browser)
Phase angles Side 1: 0° (reference phase) Side 2: 210° Please subtract 180°, than you get 30° (360° - 30° = 330°) PTD PA13 N. M Tests 7UT 05/03 No. 6
Web Tool (Browser) Vector group YNd11
PTD PA13 N. M Tests 7UT 05/03 No. 7
Vector Group Determination via Fault Record IL1;Side 2 lags 150° or leads 210°
Star point is towards the protected object
IL1;Side 1
Way 1: IL1 Side: 150° + 180° = 330°
Way 2: IL1 Side: 210° - 180° = 30° leads 30° or lags 330°
Phase shift is according the vector group definition 330° → 11 * 30° PTD PA13 N. M Tests 7UT 05/03 No. 8
Digital Transformer Differential Protection
I0-correction + vector group adaptation
Differential Protection Symposium
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 1
Transformer differential protection with I0-correction External fault L3
L1 L2 L2
L3
L1
Yd5
3
3
3
L1 L2 L3
1 3
1:3
Vector group adaptation
3
1
I0-correction
Differential Protection Symposium
1
2
3
2
∆
∆
∆
3
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 2
Transformer differential protection with I0-correction Internal fault L3
L1 L2 L2
L3
L1
Yd5
3
3
3
L1 L2 L3
1 3
1:3
1
I0-correction
Differential Protection Symposium
Vector group adaptation
1
1
3
2
∆
∆
∆
3
Belo Horizonte November 2005
G. Ziegler, 10/2005
page 3
Power Transmission and Distribution
Differential Protection (7UT)
Determination of the Transformer Vector Group
Transformer with Vector Group Yy0
7UT612
80 MVA Yy0 2500A/1A
20 kV
110 kV 500A/1A
PTD PA13 N. M Tests 7UT 05/03 No. 2
Method of Vector Group Determination (ExampleYy0) IL1,S2
Side 2:
Side 1:
2L1 1L1
IL1,S1
2L2
1L2 2L3 1L3
IL1,S2 = IL1
UL1,S1
UL1,S2
IL1,S1
UL3,S2
UL2,S2
UL3,S1
UL2,S1
0° Vector group is
Yy0 PTD PA13 N. M Tests 7UT 05/03 No. 3
Transformer Protection
7UT612
80 MVA Yd11 2500A/1A
20 kV
110 kV 500A/1A
PTD PA13 N. M Tests 7UT 05/03 No. 4
Method of Vector Group Determination (ExampleYd11) IL1,S2
Side 2:
Side 1:
2L1
IL1,S1
2L2
1L1 1L2
2L3 1L3
IL1,S2 = IL1 - IL2
IL1,S1
UL1,S1
UL1,S2
UL2,S2 UL3,S1
UL2,S1
UL3,S2
Vector group is Y d 11
330° (n * 30°)
PTD PA13 N. M Tests 7UT 05/03 No. 5
Definitions in SIPROTEC 4 Relays
Vector definition to a node is positive The shown vectors or phase angles are transformed in this positive definition The phase angle is displayed mathematics positive. The reference phase is always phase L1 on side 1 How to see the vector group Yd11? Original
Siprotec 4 (Browser)
Phase angles Side 1: 0° (reference phase) Side 2: 210° Please subtract 180°, than you get 30° (360° - 30° = 330°) PTD PA13 N. M Tests 7UT 05/03 No. 6
Web Tool (Browser) Vector group YNd11
PTD PA13 N. M Tests 7UT 05/03 No. 7
Vector Group Determination via Fault Record IL1;Side 2 lags 150° or leads 210°
Star point is towards the protected object
IL1;Side 1
Way 1: IL1 Side: 150° + 180° = 330°
Way 2: IL1 Side: 210° - 180° = 30° leads 30° or lags 330°
Phase shift is according the vector group definition 330° → 11 * 30° PTD PA13 N. M Tests 7UT 05/03 No. 8
