Digital Differential Protection g Ziegler

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


Belo Horizonte, 7 to 9 Nov. 2005

No.: 2

Digital Differential Protection Principles and Application Gerhard Ziegler


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


123 - 178


179 - 216

Busbar differential protection

217 - 247

7UT6 product features

248 - 264



G. Ziegler, 10/2005

page 2

Digital Differential Protection Mode of operation Gerhard Ziegler



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


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



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


I1

I2

Protection object

i1

i2 i1

∆I>

∆I=I1 + I2

i2

internal fault


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!


∆I

CT circuits of digital relays are segregated and must each be earthed !

Digital relays have integrated numerical ratio adaptation !


G. Ziegler, 10/2005

page 7

Generator and transformer differential protection

L1 L2 L3

L1 L2 L3

∆I

∆I

∆I


Yd5

Matching transformer


∆I

∆I

∆I

G. Ziegler, 10/2005

page 8


Yd5 L1 L2 L3

Matching transformer


∆I

∆I

∆I


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


S2

Designation of CT terminals according to IEC 60044-1


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


M Grid infeed


Load

G. Ziegler, 10/2005

page 11


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



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


∆I


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


15

ID / In


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



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


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


G. Ziegler, 10/2005

page 16

Multi-end differential protection: Analog measuring principle

1

n

2

Iop = I1 + I 2 + .... + I n = Σ I


k ⋅ I Re s

I Op

I Res = I1 + I 2 + .... + I n = Σ I


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


I Re s = 2 ⋅ I F

δ 2


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



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


)

IS0 2


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



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



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


= 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



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



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


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


U R = (RL + RCT ) ⋅ iSC


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% )


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 <

RR ⋅ I R − pick −up RL + RSW

600 10,000 ⋅ ⋅ 0.02 1 3+4

I F −through − max < 17kA = 28 ⋅ I n Belo Horizonte November 2005

G. Ziegler, 10/2005

page 28

Digital Differential Protection Measuring Technique Gerhard Ziegler



G. Ziegler, 10/2005

page 28

Merz and Price differential protection Patent dated 1904

a: feeder, b: generator, c: substation, d: primary winding of CT, e: secondary winding of CT, f: earth or return conductor, g: pilot wire, h: relay windings, i: circuit breakers, k,l: movable and fixed relay contacts, m: circuit, n: battery, o: electromagnetic device with armature p.



G. Ziegler, 10/2005

page 29

Electro-mechanical differential protection based on induction relay I2

I1 Schutzobjekt

i1


∆i

i2


G. Ziegler, 10/2005

page 30

Electro-mechanical differential protection Rectifier bridge comparator with moving coil relay I1

Protection object

i1

I Re s

ΔI = I

Op

−I

i2

IOp

∆I

I Re s = k ⋅ (I 1 − I 2 )

I2

I Op = I 1 + I 2

+ Re s


N

S


G. Ziegler, 10/2005

page 31

Differential protection Analog static measuring circuit

I1

I2

Protection object

i1

I Re s = k ⋅ (I 1 − I 2 )

i2 I Re s ⋅ R S

RS V1 RS

I Op = I 1 + I 2

V3 V2

I Op ⋅ R S

URef



G. Ziegler, 10/2005

page 32

Digital differential protection Measuring value acquisition and processing

0.67 ms (18 degr. el.)

MI

1.2 kHz clock

Filter

1 IL1 IL2 IL3 IE UL1 UL2 UL3 UE a.s.o.

Processor system

S&H

CPU A D

RAM

MUX

ROM

n



G. Ziegler, 10/2005

page 33

Digital protection: Measurement based on momentary values

I=

IRMS 0

I

n

∆Tsamp. corresponds to ∆ϕ ( 60Hz: 0.67 ms = 18O el.)

I= n −1 cos ( ⋅ ∆ϕ ) 2 Iˆ I RMS = 2

Iˆ =


when n sampled values exceed the pick-up limit I= f ∆ϕ = ω ⋅ ∆Tsamp. = N ⋅ 360O fA


G. Ziegler, 10/2005

page 34

Digital differential protection: Measurement based on momentary values 4 3

∆I

5

5

6

2

4 7

3 2

8

1

∆I>

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


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



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 ...



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



G. Ziegler, 10/2005

page 38

Transfer function of a one cycle Fourier-filter Hrel 1,0 0,75 0,5 0,25 0 0

1


2

3

4

5

6

f/fn


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

(

)



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



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


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


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


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.


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



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


L1 402,1A L2 402,1A L3 402,1A E 00.0A


ERR OR Max450.1A Max450.1A Max450.1A


1

t0 max.


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


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

• • • •


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


G. Ziegler, 10/2005

page 46

Operating characteristic of digital differential relays

I∆ =|I1+ I2|

I1

I2

b%

∆I

I∆>

a%

I∑ b


I∑ = |I1|+ |I2|


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


t=20 ms

t=0

t=10

t=20 ms


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 )


i1(n ) + i 2( n )

n=0

n=10


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!



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


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


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



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 ?



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


ALF’ •IN-CT


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



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


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


•Released by Idiff >>


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!


iOp

≥1

Trip IOp>>

IDiff>>>


G. Ziegler, 10/2005

page 58

Current Transformers for Differential Relaying Requirements and Dimensioning Gerhard Ziegler



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



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


Im

Im


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


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%


Angle error δ at rated current In

Total error at n x In (rated accuracy limit)

± 60 minutes

5% 10 %


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)



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


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 <10% Example: 800/5 A, C400 (RB= 4 Ω)

U2, Em

Resulting magnetising voltage:

E al ≈ (U ANSI + 20 ⋅ 5 ⋅ R CT )

= (20 ⋅ 5 ⋅ Z B − rated + 20 ⋅ 5 ⋅ R CT )

Im Differential Protection Symposium


G. Ziegler, 10/2005

page 53

Current transformer saturation

Steady-state saturation with a.c. current

Transient saturation with offset current



G. Ziegler, 10/2005

page 54

CT saturation Currents and magnetising IP

t

φ saturation flux

t

IS

t



G. Ziegler, 10/2005

page 55

Transient CT saturation due to DC component

ISC

Short circuit current

DC flux non-saturated ΦS

Φ

Im


AC flux

Magnetising current


G. Ziegler, 10/2005

page 56

Course of CT-flux during off-set short-circuit current

ΙP primary current d.c. component

i p (t) =

Φ

Total flux

t ωTp Ts - t Φ max Tp K td (t) = = (e - e Ts ) + 1 ˆ Φ Tp - Ts a.c.

Ktd(t) transient d.c. flux

 − cos( ωt)   

t ωTp Ts - t Φ = (e Tp - e Ts ) - sin ωt ˆ Φ a.c. Tp - Ts

t Tp

- t 2 ⋅ I p ⋅  e Tp  

Φ max ˆ Φ a.c.

a.c. flux

ˆ a.c. Φ


t

K td − max = 1 + ωTp = 1 +


Xp Rp

G. Ziegler, 10/2005

page 57

Theoretical CT over-dimensioning factor KTF KTF

∞ (KTF ≈1+ωTN)

60 5000

Closed iron core

50 1000 40

TS

 T N  TS − TN KTF = 1+ ωTS   TS 

TS [ms] 500

30 250 20 100

Linear core

10 TN = network time constant (short-circuit time constant) 50

100

150

200

TN [ms] TS = CT secondary time constant



G. Ziegler, 10/2005

page 58

CT with closed iron core, Over-dimensioning factor KTF‘ for specified time to saturation (tM) 20

tM → ∞

tM

15

2.5 cycles

K‘td

2.0 cycles 10

1.5 cycles

8

1.0 cycles

 −tTM  Ktd' = 1+ ωTp ⋅ 1− e p     

5

0.5 cycles

0

20

40

60

80

100

Tp (ms)



G. Ziegler, 10/2005

page 59

Transient dimensioning factor K’’td for short time to saturation tM

t  − M  T K td − Envelop = 1 + ωTp ⋅ 1 − e p  

15

t  − M  ' K 'td (Θ, t M ) = ω ⋅ Tp ⋅ cos θ ⋅ 1 − e Tp  

    

   + sin Θ − sin (ωt M + Θ )  

3

15

2.5

Ktd( 0 , tM) 10

Ktd( 80 , tM)

2 1.5

Ktd( 90 , tM) Ktd_Envelop( tM)

5

1 0.5

0

0

0 0

20

40

60 tM


80

100 100

0

0 0

1

2

3

4


5 6 tM

7

8

9 10 10

G. Ziegler, 10/2005

page 60

CT over-dimensioning factor KTF (tM,TN) in the case of short time to saturation (tM)

KTF

4

tM

Θ (tM,TN)

10 ms

3.5

(el. degree)

180 160 140

3 8 ms

2.5

120 100

2 6 ms

1.5

tM 10 ms 8 ms 6 ms 4 ms 2 ms

80 60

1

4 ms

0.5

40 20

2 ms

0

0

20

40

60

80

100

0

0

20

40

80

100

TN in ms

TN in ms


60


G. Ziegler, 10/2005

page 61

Current transformer Magnetising and de-magnetising ΙP

B t

B

BMax BR

BMax BR Ιm t



Ιm

G. Ziegler, 10/2005

page 62

Current transformer Course of flux in the case of non-successful auto-reclosure B

t F1 = duration of 1st fault

Bmax

t DT dead time t F2 =duration of 2nd fault

t tF1

tDT

tF2

tF1  tDT + tF2  tF2  tF1 tF2  − − − − − Bmax  ω ⋅ TN ⋅TS   ω ⋅ TN ⋅ TS  TS = 1 + (e TN − e TS )  ⋅ e (e TN − e T S )  + 1 + TN − TS TN − T S Bˆ ~        



G. Ziegler, 10/2005

page 63

Current transformer Magnetising curve and point of remanence I

II

III

B up to about 80%

< 10% negligible

H = im ⋅ w I: closed iron core (TPX) II: core with anti-remanence air-gaps (TPY) III: Linearised core (TPZ)



G. Ziegler, 10/2005

page 64

Current transformers TPX und TPY Course of the flux with non-successful auto-reclosure

BR

BR tF1

tDT


tF2

closed iron core (TPX)

core with antiremanence air-gaps (TPY)

t


G. Ziegler, 10/2005

page 65

Current transformer with linear core (TPZ), Course of the flux with non-successful auto-reclosure ΙP

t

ΙS B

Ιm t tF1


tDT

tF2


t

G. Ziegler, 10/2005

page 66

Dimensioning of CTs for protection application Rated CT burden: PN Internal CT burden: Pi=Ri ⋅ I2N2

Pi + P N Ri + RN ALF' = ALF ⋅ = n⋅ Pi + PB Ri + RB

Actually connected burden :

P + PB Ri + RB = ALF'⋅ ALF = ALF' ⋅ i Pi + PN Ri + RN

I with ALF ' ≥ K OD ⋅ SC IN

with:

Theory:

No saturation for the specified time tM:

K OD ≥ KTF ⋅ K Re m K Re m = 1 +

% remanence 100


RB=RL+RR= total burden resistance RL= resistance of connecting cable RR= relay burden resistance

No saturation during total fault duration:

Where KOD is the total over-dimensioning factor:

Practice:

K OD = KTF

PB= RB ⋅ I2N2

BMax XN = 1 + ω TN = 1 + RN Bˆ ~ tM tM   − − ω ⋅ T N ⋅ TS (e T N − e T S  K ' 'TF = 1 + TN − TS    

K' TF =

Remanence only considered in extra high voltage systems (EHV) KTF-values acc. to relay manufacturers‘ guides


G. Ziegler, 10/2005

page 67

Practical CT dimensioning using dimensioning factors Ktd (required minimum time to saturation) IEC 60044-1 and 60044-6

ANSI C57.13

300/5 A, 5P20, VA (Rb= 1.0 Ω), Rct= 0.15 Ω

300/5 A, C100 (Rb= 1 Ω)

E al ≈ (U ANSI + 20 ⋅ 5 ⋅ Rct )

= (20 ⋅ 5 ⋅ Z b − rated + 20 ⋅ 5 ⋅ Rct )

ALF' ≥ K SSC ⋅ K td ALF' =

R ct + R b − rated ⋅ ALF R ct + R b − connected

20 ≥ K td ⋅

I R + R b − connected ALF ≥ K td ⋅ F − max ⋅ ct I pn R ct + R b − rated

Transient dim. factor: Ktd

BS 3839 (IEC: 60044-1 addendum)

I E al = F − max ⋅ K td ⋅ (R ct + R b − con. ) ⋅ Isn − CT I pn U KN ≈ (0.8...0.85) ⋅ E al


I F − max R ct + R b − connected ⋅ I pn R ct + R b − rated

No saturation:

1+X/R =1+ω·Tp

Differential relays:

1 (87BB: 0.5)

Distance relays:

2 to 4 close-in faults 5 to 10 zone end

faults O/C relays: I>> 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


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



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).



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‘).



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)



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!



G. Ziegler, 10/2005

page 74

Interposing CTs, Example

1A W1= 21 turns

600/1 A

1A

600/1 A


1,5 A W2= 14 turns

1A

Wa=16 turns

0,5 A

Wb=32 turns

RB

1,5 A

RB


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 =


150O

I2b I2b

I2c

-I1a I2a

o 1 w ⋅ I 2 ⋅ 2 ⋅ e j ⋅( n⋅30 ) w1 3


G. Ziegler, 10/2005

page 76

False operation during external fault of transformer differential protection without zero-sequence current filter

L1 L2 L3

∆I


∆ I

∆I

∆I>0 without delta winding!


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


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 !


∆I

∆ I

∆I


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


∆I

∆I

In-Relay = 5A


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



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.



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



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



G. Ziegler, 10/2005

page 84

Frequently used vector groups (IEC 60076-1)



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.



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


∆I

∆I

∆I


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



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


∆I

3

Dy5


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


∆I

3

Dy5

3


G. Ziegler, 10/2005

page 90

Digital Differential Protection Communications Gerhard Ziegler



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




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



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!




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




Wire pilot cables Longitudinal voltage induced by earth currents Relay B

Relay A

G IF

Φ E

F1

E/2 F2


A) Symmetrical coupling along the pilot cable

E/2

F2

F1

E


B) Unsymmetrical Coupling along the pilot cable


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 )




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 <10–4·Ul)




American practice Neutralising reactor to compensate potential rise at the station Gas tube Relay neutralising reactor Relay potential gradient potential at insulating transformer and relay Voltage profile at the neutralising reactor


potential of the pilot wires


potential of the remote earth


Optic fibre (OF) Cable




Optic fibers and connectors Multi-mode fiber (IEC 793-2) Type 62.5 / 125 µm for 850 and 1300 nm Cladding

Mono-mode fiber (IEC 793-2) Type 10/125 µm for 1300 and 1550 nm ST connector

Core

Coating

62,5 µm 125 µm 250 µm

Refractive index

LC connector


10 µm 125 µm 250 µm



Optic fibres: Principle of light wave propagation r

n2 n1 rL n

A) Graded index fibre

AA

AE γA

t

EingangsInput impulse

Output impulse

impuls

Refractive index profile

r

B) Mono-mode fibre

Geometric design

Wave propagation

n2 n1 r L

AE

AA

n t

t EingangsInput impulse impuls



Output impulse


Optic attenuation of a mono-mode fibre

10,0 5,0

Attenuation (dB/km)

Infrared absorption

1,0

Rayleigh dispersion 0,85

0,1 0,8

1,3 1,0

1,2

1,55 1,4

1,6

1,8

Wave length (µm)




Optic fibre connections: Coarse planning rules Optic component:

Attenuation:

Mono-mode fibre at 1300 nm

αOFC = 0.45 dB/km

at 1550 nm

αOFC = 0.30 dB/km

at 850 nm

αOFC = 2,5 to 3,5 dB/km

at 1300 nm

αOFC = 0.7 to 1.0 dB/km

Gradient fibre

αSPL = 0.1 dB

Per splice Per connector

Reserve

FSMA

αCON = 1.0 dB

FC

αCON = 0.5 dB αRES = 0.1 to 0.4 dB/km

Total attenuation of the OF cable system:

αTOT = l ⋅ αOFC + n ⋅ αSPL + 2 ⋅ αCON + l ⋅ αRES Differential Protection Symposium



Optic Fibre signal transmission system: Calculation example Task:

Optic fibre signal transmission device 7VR500 Estimation of maximum reach

Given:

Device data:

Seached:

Maximum distance that can be bridged

Solution:

The cable length is: l=x⋅2 km The number of splices is: n=x-1 The admissible system attenuation: −14− (−46)=32 dB Therefore: dB dB 32dB = x ⋅ 2km ⋅ 0,45 + ( x − 1) ⋅ 0,1dB + 2 ⋅ 0,5dB + x ⋅ 2km ⋅ 0,2 km km

Sending power of laser diode: αS= –14 dB Minimum reception power: αE= -46 dB Optic wave length: 1300 nm The optic fibre cable is shipped in sections of each 2 km. For reserve, 0.2 dB/km have been chosen.

we get:

x=22 and l=44 km




Radio (Micro-wave) Signalling

repeater station

terminal station

radiolink

terminal station

• Line-of-sight path (up to about 50 km without repeater) • 150 MHz to 20 GHz, n times 4 kHz channels analog and n times 64 (56) kbit/s digital (PCM) • Advantage: Independent of line short-circuit and switching disturbances • Disadvantage: Fading and reflections during bad weather conditions Additional pilot links necessary to sending/receiver stations




Digital communication

u Wide-band communication via optic fibre or digital microwave u n times 64 (56) kbit/s channels u pulse code modulation (PCM) u transmission via dedicated channels or communication network u access through time division multiplexers u interface standard for synchronous data transmission: CCITT G.703 or X.21 (wired connection) u interface standard for asynchronous data transmission: V.24/V.28 to CCITT or RS485 to EIA (wired connection)




Function sequence of message transmission Sending side

Message Digital coding Segmentation into information blocks

wide band transmission

Error control Parallel-to-serial conversion

modulation block synchronisation


coding base band transmission



Structure of a remote control telegram

Start

Control

Start sign

Kind of telegram

Block limit

Transmission cause

Identification

Information

Error check

Address

User data

Checking

Origin

Measuring values

Check bits

Destination

Telegram length

Status

etc.

Commands

End

End sign

etc.

Information field Block length Transmitted frame




Digital communication Synchronous transmission mode • all bits follow a fixed time frame • synchronism between sending and receiving station. (separate clocking line or signal codes with clock regain) • block (frame) synchronising by opening and closing flags • suitable for high data rates • used protocol: HDLC (high-level data link control) • cyclic redundancy check (CRC) or frame check sequence (FCS) by 16 or 32 added check-bits (probability of non-detected telegram block errors: 10–5 (CRC-16) or 10–10 (CRC-32)) • used for high speed teleprotection

HDLC telegram frame format to ISO 3309:

Opening Flag

Address Field

Control Field

01111110

8 or more bits

8 or 16 bits


Information Field any length


Frame Check FCS

Closing Flag

16 or 32 bits

01111110


Multiplexing Frequency Multiplexing f1 f2 Coded voice tones 300 to 4000 Hz

FC +f1+f2

M U X

Carrier frequency, FC e.g. 100 kHz with PLC

M U X

f1 f2

FC

Time Divison Multiplexing (TDM) 125 µs M U X

64 kbit/s channels

Clock

M U X

> 2 Mbit/s


Clock Belo Horizonte November 2005


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


User / Destination



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




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)


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.



SDH network: Split path routing

Node F

Node E

Node D

Standby path

Node A tP2‘ Node B Relay End 1


tP1

Node C

tP1‘

tP2 Healthy path

Relay End 2



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


SMT-64 10 Gbit/s 1

4

4 Belo Horizonte November 2005


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


USA 56 kbit/s 1‘544 Mbit/s 6‘312 Mbit/s 44‘736 Mbit/s 139‘264 Mbit/s



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


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



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




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




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




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)


Division by G(x)

R(x) = 0

faulty data block



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




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




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




Line differential relaying using digital communication A

B

D 7SD52

D 7SD52 D 7SD52

Chain topology or redundant ring topology

typical <1.5 km multimode fibre 62.5/ 9/ 125 µm

C

O

Communication network

E

X21 or G703.1


O

E

Communication converter

X21 or G703.1



Differential protection with communication through data net l Microsecond exact time keeping in the relays Each relay has its individual time keeping n Sent and received telegrams get microsecond accurate time stamps n

l Special relay properties for network communication Measurement of propagation times and automatic correction 0 - 30 ms Detection of channel switching in the network Unique address for each relay (1 - 65525) to detect signal misdirection (channel cross-over of loop-back) Measurement of channel quality (availability, error rate)

l Change of the network path -> 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




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




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:


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


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.




Digital Protection of Generators and Motors Gerhard Ziegler



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


1

2

3

4

5

6

IS/In

Operating characteristic


G. Ziegler, 10/2005

Seite 117

Generator HI differential protection

a b c

A


A

A


G. Ziegler, 10/2005

Seite 118

Transverse differential protection

a

b

c

S

S S

S S

A


A

S A


G. Ziegler, 10/2005

Seite 119

HI earth current differential protection

L1 L2 L3

∆IE>



G. Ziegler, 10/2005

Seite 120

Earth current differential protection for generators

L1 L2 L3

U0>

∆IE> Tripping



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)



G. Ziegler, 10/2005

Seite 122

Transformer Differential Protection Gerhard Ziegler



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 << I 1, 2 '


Xµ

R2 '

I2'

U 2'

Equivalent electric circuit

Equivalent electromagnetic circuit

At load and short-circuit:

Iµ

X σ 2'

RTK

U1

X TK

I1 = I 2 '

I1 ⋅ w1 = I 2 ⋅ w 2

U 2'


X TK = X σ 1 + X σ 2 ' RTK = R1 + R 2 '

G. Ziegler, 10/2005

page 124

Typical Transformer data

kV/kV

Short-circuit voltage % UN

No-load magnetizing current % In

850

850/21

17

0.2

600

400/230

18.5

0.25

300

400/120

19

0.1

300

230/120

24

0.1

40

110/11

17

0.1

16

30/10.5

8.0

0.2

6.3

30/10.5

7.5

0.2

0.63

10/0.4

4.0

0.15

Rated power

Ratio

MVA



G. Ziegler, 10/2005

page 125

Transformer Inrush current

IRush

Flux

φ

φ φRem

Im

Inrush-current of a single phase transformer

U t

Source: Sonnemann, et al.: Magnetizing Inrush phenomena in transformer banks, AIEE Trans., 77, P. III, 1958, pp. 884-892



G. Ziegler, 10/2005

page 126

Inrush currents of a Y-∆-transformer Neutral of Y-winding earthed

ΦC

IA

ΦB ΦA

IB

I mC

ID

IC

I mA

Oscillogram: IA

5 1 I A = ⋅ I mA − ⋅ I mC 6 6

IA

IB

1 1 I B = − ⋅ I mA − ⋅ I mC 6 6

IB

IC

5 1 IC = ⋅ I mC − ⋅ I mA 6 6

IC

Source: Sonnemann et al. : Magnetizing Inrush phenomena in transformer banks, AIEE Trans., 77, P. III, 1958, pp. 884-892



G. Ziegler, 10/2005

page 127

Inrush current : Content of 2nd und 3rd harmonic I m (ν ) I m (1)

%

100 B

80

B

360O 60

I m (2) 40

I m (1)

I m (3) 20

I m (1) 90O

17,5%

180O

270O

360O Width of base B

240O



G. Ziegler, 10/2005

page 128

Inrush currents of a three-phase transformer recorded with relay 7UT51



G. Ziegler, 10/2005

page 129

Transformer Inrush current: Amplitude and time constant

Î Rush Î N

12

Rated power in MVA

time constant in seconds

8

0,5....1,0

0,16....0,2

6

1,0

0,2 .....1,2

10

10

>10

4

1,2 ....720

2

5

10

50

100

500

Rated transformer power in MVA



G. Ziegler, 10/2005

page 130

Sympathetic Inrush Wave form:

Transient currents:

I1

I

I1

I2

I2

IT IT I1

IT T1

G resistance

I2

Current circulating between transformers

Transformer being closed

G

RS

IT

Transformer already closed T2


t

XS


I1

I2 T1

T2

G. Ziegler, 10/2005

page 131

Transformer overfluxing

Deduction of wave form

Harmonic content Im

B 1,5

× 10 4 Gauß

U

1,0

% 100 80

I150/I50

60

I250/I50

40

I350/I50

I50/InTr

20 0

0,5

5

10

15 A Im

0


10

100

120

20 ms

% 160

140

U/Un

t


G. Ziegler, 10/2005

page 132

Vector group adaptation with matching CTs Current distribution with external ph-ph fault IR

I1

R

Ir

r

1

3

IS

I2

IT

I3

S

T

Is It

s

G

t

3 /1 87T


87T

87T


G. Ziegler, 10/2005

page 133

Vector group adaptation and I0-elimination with matching CTs Current distribution with external ph-E fault A B

Yd1

IA

Ia

r

IB

Ib

s

IC

Ic

t

C

G

cp

Ic = 3

IT=3

cn

3 /1

87T

87T

87T

Ia = 3

Cn

Cp

A0 B0 C0

30O

cp

cn

bp Bp

Ap

An

Bn


ap

ap an

30O bn

an


G. Ziegler, 10/2005

page 134

Traditional I0-elimination with matching CTs Current distribution in case of an external earth fault

a A b B c

C

87T


G

87T

87T


G. Ziegler, 10/2005

page 135

Traditional I0-elimination with matching CTs Current distribution in case of an internal earth fault

a A b B

G

c

C

! 87T


87T

87T

Ø Sensitivity only 2/3 I F! Ø Non-selective fault indication!


G. Ziegler, 10/2005

page 136

Traditional I0-correction with matching CTs Current distribution with external ph-E fault

a A b B

G

c

C

3/1

87T


87T

87T


G. Ziegler, 10/2005

page 137

Traditional I0-correction with matching CTs Current distribution with internal ph-E fault

a A b B

G

c

C

3/1

87T


87T

87T


G. Ziegler, 10/2005

page 138

Transformer differential protection, connection

L1

IA1

IB1

UA

L2

IA2

IB2

UB

(110 kV)

L3

IA3

IB3

(20 kV)

Digital protection contains: Adaptation to

7UT6

∆I

∆I

∆I

• Ratio UA / UB • Vector group

Software replica of matching transformers



G. Ziegler, 10/2005

page 139

Digital transformer protection Adaptation of currents for comparison (1) CT 1

JR-sec JS-sec JT-sec

W2

W1 JR-prim

Jr-prim

JS-prim

Js-prim

JT-prim

Jt-prim

N o r m

I N − Transf − W1 =

IR IS IT

IR* I0elim. IS* IT*

Comparison ∆I

SN

J R −sec I N − Prim − CT 1 IS = ⋅ J S −sec = kCT −1 ⋅ I N − Transf - W1 IT JT −sec


It**

Vector group adapt.

Ir* Is* It*

I0elim.

Ir Is It

N o r m

I N − Transf − W2 =

3 ⋅ U N -1

IR

Ir** Is**

J R −sec J S −sec JT −sec

CT 2

Jr-sec Js-sec Jt-sec

SN 3 ⋅ U N -2

Ir J r − sec I N − Prim − CT 2 Is = ⋅ J s − sec = k CT − 2 ⋅ I N − Transf -W2 It J t − sec


J r − sec J s − sec J t − sec

G. Ziegler, 10/2005

page 140

Digital transformer protection Adaptation of currents for comparison (2) CT 1

JR-sec JS-sec JT-sec

1 ⋅ (I R + I S + I T ) 3 IR * = IR − I0

W2

W1 JR-prim

Jr-prim

JS-prim

Js-prim

JT-prim

Jt-prim

N o r m

IR IS IT

IR* I0elim. IS* IT*

Com_ parison ∆I

I0 =

Ir** Is** It**

Vector group adapt.

Ir* Is* It*

I0elim.

Ir Is It

N o r m

IS * = IS − I0 IT * = IT − I0

I ∆ −T

IT *


It **

Ir ** −1 0 1 1 Is ** = 1 −1 0 ⋅ 3 0 1 −1 It * *


Jr-sec Js-sec Jt-sec

I0 =

Example Yd5:

I∆−R IR * Ir ** I∆−S = IS * + Is **

CT 2

Ir * Is * It *

1 ⋅ (I r + I s + I t ) 3

Ir * = Ir − I0 I s * = Is − I 0 I t * = I t − I0

G. Ziegler, 10/2005

page 141

Adaptation of currents for comparison Relay input data Input data: •n times 30O

vector group number (only for 2nd and 3rd winding, 1st winding is reference)

Winding 1 (reference) is normally: •High voltage side

•UN (kV)

Rated winding voltage

•SN (MVA)

rated winding power

•INW (A)

Primary rated CT current

At windings with tap changer:

•Line or BB

direction of CT neutral

UN = 2⋅

•Elimination / Correction / without

I0-treatment

•Side XX

Assignment input for REF

•INW S (A)

Primary rated current of neutral CT

•Neutral CT

Earth side connection to relay: Q7 or Q8?


U max ⋅ U min U max + U min


G. Ziegler, 10/2005

page 142

Digital transformer protection Current adaptation, Example (1) SN = 100 MVA UN1= 20 kV W2

3000/5 A

UN2= 110 kV

Yd5

W1

600/1 A 2.400 A

7621 A

1A 5A


∆I


G. Ziegler, 10/2005

page 143

Digital transformer protection Current adaptation, Example (2) 110-kV-side

20-kV-side

I N − Trafo − W2 =

100MVA = 2887A 3 ⋅ 20kV

I N − Trafo − W1 =

1 3 = 4,4 3 A ⋅ 13200 3000 3000 3A I Norm = ⋅ 4,4 3 = 4,57 2887 J r,s, t - sek =

J R, S, T -sek = I Norm =

4,57

I A − S = I S * + I s * * = − 2 ⋅ 4,57 I A −T = IT * + I t * * =


1 ⋅ 2400 = 4,0 A 600

600 ⋅ 4 = 4,57A 525

Vector group adaptation: Yd5 Ir * 2 −1 −1 0 4 ,57 3 1 I s * = ⋅ − 1 2 − 1 ⋅ − 4,57 = − 2 ⋅ 4 ,57 3 3 It * −1 −1 2 0 4 ,57 3

I0-elimination: Ir ** −1 0 1 4,57 3 − 4,57 / 3 1 Is ** = 1 − 1 0 ⋅ − 4,57 3 = 2 ⋅ 4,57 / 3 3 It ** 0 1 −1 0 − 4,57 / 3

IA −R = IR * + I r * * =

100MVA = 525A 3 ⋅ 110kV

4,57

3 − 4,57

3

3 + 2 ⋅ 4,57 3 − 4,57

=0 3=0

3

=0


G. Ziegler, 10/2005

page 144

Current adaptation (1) Practical example for the need of matching CTs *)

Matching CTs recommended, if k_Wan_n > 4 or k_Wan_n < 1/4: *)

To keep the specified measuring accuracy of 7UT51. For protectio n only necessary if 8
345 kV, 1050 MVA

1500/5 A

2000/5 A

500 kV, 1050 MVA

1213 A (1050 MVA)

1000/1 A 43.930 A (1050 MVA) 4,04 A 43,43 A

13,8 kV, 30 MVA

1/0.2A 8,786

7UT513 (5A Relay)


k CT _ 3* =

8,786 = 1,76 < 4! 5


G. Ziegler, 10/2005

page 145

Current adaptation (2) Practical example for the need of matching CTs I n −Tr −W 1 = I

1050 ⋅103 3 ⋅ 500

n −Tr −W 1−sec =

1213A = 4,04 A 1500 / 5

4.04 kCT −1 = = 0,809 5 I n −Tr −W 2 = I

1050 ⋅ 103 3 ⋅ 345

n −Tr −W 2− sek =

kCT − 2 =

40·In= 15 Bit +sign = 215 = 32.768 32.768

15

40·In

1

0,122%In

32.36

351,44

= 1757 A

1757 A = 4,39 A 2000 / 5

1050 ⋅103 3 ⋅13,8

n −Tr −W 3 _ sek =

kCT −3 =

Transformer winding 3

4,39 = 0,878 5

I n −Tr −W 3 = I

Transformer winding 1

Relay

= 1213A

= 43.930 A

43.930 A = 43,93 A 1000 / 1

43,93 = 8,786 > 4! 5


0,099%


1,072% G. Ziegler, 10/2005

page 146

7UT6 Operating characteristic

5

I

ST

F = IF

7UT6

7 6

I DIFF >>

AB

8

ID

IDiff/ In

I2

I1

9

IDIFF = |I1+ I2| Tripping area

IStab = |I1| + |I2|

4

2 e op Sl

3

Stable operation

2

Slope

1

I DIFF > 0 0

1

2

Additional stabilisation for high Is.c.

1 3


4

5

6

7

8

9

10


11

Istab / In

G. Ziegler, 10/2005

page 147

I0-elimination / correction: Summary

è I0- elimination necessary at all windings with earthed neutral or with grounding transformer in the protection range Earth fault sensitivity reduced to 2/3 ! Incorrect fault type indication! è I0- correction provides full earth current sensitivity and correct phase selective fault type indication, however requires CT in the neutral-to-earth connection of the transformer. è As an alternative, earth differential protection can be used to enhance earth fault sensitivity.



G. Ziegler, 10/2005

page 148

Transformer winding to earth fault Solid earthed neutral IF per unit 10 8

UR h⋅UR

IF

6

Infeed side

4

IF

IK

2

IK 0

20

40

60

80

100

Short-circuited winding part h in %

Source: P.M. Anderson: Power System Protection, McGraw-Hill and IEEE Press (Book)



G. Ziegler, 10/2005

page 149

Transformer winding to earth fault Resistance or reactance earthed neutral

UR

% 100

h⋅UR

I

Infeed side

50

IF IK

IK

RE 0

20

40 100 60 80 Short-circuited winding part h in %

h ⋅U R RE U 2n h ⋅ w2 = ⋅ IF = h ⋅ ⋅ IF w1 U 1n ⋅ 3

IF =

IK

IF

I Max

1 U 2n U R I K = h2 ⋅ ⋅ ⋅ 3 U 1n R E

Source: P.M. Anderson: Power System Protection, McGraw-Hill and IEEE Press (Book)



G. Ziegler, 10/2005

page 150

Transformer winding short-circuit

100

IK

10

IF , I K x In 80

8

60

6

IP x In

IF 4

40

IK 20

2

IF 0

5

10

15

20

25

Short-circuited winding part h in % Source: Protective Relays, Application Guide, GEC Alstom T&D, 1995



G. Ziegler, 10/2005

page 151

Restricted earth fault protection of relay 7UT6 IR IS IT K0= 4 K0= 2

100

80 2

120

60

1.2

I0 * ⋅ e ϕ (I 0 * /I 0 * *) I 0 * *40

0.8

20

1.6

K0= 1.4

140

160

0.4

K0= 1 180

Blocking

0

ϕ

+ 1 Tripping

200

I>

IN ∆ IE

0

I0*

I0**

340

220

320

240

300 260

280

Polarised earth current differential protection

3.14



G. Ziegler, 10/2005

page 152

Restricted earth fault protection 87N (7UT6) Application aspects

n Increased sensitivity with earth faults near winding neutral

Preferably used in case of resistance or reactance neutral earthing n Sensitive to turns short-circuit n I0 / IN amplitude and angle comparison n 2nd harmonic stabilised n Can protect a separate shunt reactor or neutral earthing transformer in

addition to the two winding transformer differential protection n Not applicable with autotransformers! (as only one stabilising input at transformer terminal side, -- high impedance principle to be used in this case.



G. Ziegler, 10/2005

page 153

Transformer HI-earth fault protection

IR

Ir

IS

Is

IT

It

ZE ∆IE>


IN

∆IE>


G. Ziegler, 10/2005

page 154

HI differential protection of an autotransformer

Ir

IR

Is

IS

It

IT

87


87

87


G. Ziegler, 10/2005

page 155

HI earth fault protection of an autotransformer

Ir

IR

Is

IS

It

IT

IN ∆I>



G. Ziegler, 10/2005

page 156

Transformer tank protection 64T: Principle

IE>

Insulated



G. Ziegler, 10/2005

page 157

Transformer protection, Relay design 7UT6 differential protection for

•Transformers •Generators • Motors •Busbars

7UT612: 7UT613: 7UT633: 7UT635:

for protection objects with 2 ends for protection objects with 3 ends for protection objects with 3 ends for protection objects with 5 ends


(1/3 x 19’’ case 7XP20) (1/2 x 19’’ case 7XP20) (1/1 x 19’’ case 7XP20) (1/1 x 19’’ case 7XP20)


G. Ziegler, 10/2005

page 158

7UT6 Integrated protection functions Function

ANSI No.

Function

ANSI No.

Differential

87T

Overfluxing V/Hz

24

Earth differential

87 N

Breaker failure

50BF

Phase overcurrent,

50/51

Temperature monitoring

38

Neutral overcurrent IN>, 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


Binary inputs for tripping commands


G. Ziegler, 10/2005

page 159

Application range (7UT6) ∆ ∆I ∆I Shunt Reactor

G

Three winding transformer

Two winding transformer

∆I

Generator / Motor


∆I

∆I

Transformer bank (1-1/2-LS)

∆I

∆I

Busbars


G. Ziegler, 10/2005

page 160

Digital transformer protection relay 7UT613: Current inputs and integrated protective functions YN

yn0

d5

R S T

ϑ> (2)

ϑ> (1)


I>>, I>t

∆ITE

∆IT


G. Ziegler, 10/2005

page 161

Operating characteristic (7UT6)

Idiff >> I

7 Locus of internal faults 45°

6 Op 5

In

pe o l S

operate

2

restrain

4 3 2

Idiff >

1

S lo p

0 0

2

supplementary restraint

e1

4

6

8

10

12

14

16

IRes In



G. Ziegler, 10/2005

page 162

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



G. Ziegler, 10/2005

page 163

7UT6: Temperature monitoring with hot spot calculation (1) Example: Natural cooling

Θ h = Θ O + H gr ⋅ k Y

Θh= hot spot temperature ΘO= oil temperature Hgr=hot-spot-to-oil temperature gradient k= load factor I/In Y= winding exponent

Aging rate: Oil Temp.

HV LV

V=

Aging at Θh = 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



G. Ziegler, 10/2005

page 164

7UT6: Temperature monitoring with hot spot calculation (2)

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



G. Ziegler, 10/2005

page 165

7UT6: Commissioning und service tool (1) WEB-Technology Access to WEB Browser Help system in the INTRANET / INTERNET http://www.siprotec.com

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


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

WEB server in relay firmware Server sends HTML pages and JAVA code to WEB Browser via DIAL-UP connection


G. Ziegler, 10/2005

page 166

7UT6: Commissioning and service tool (2) Display of current phasors of all terminals

Transformer YNd11d11, 110/11/11kV, 38.1MVA, IL2S2à wrong polarity



G. Ziegler, 10/2005

page 167

7UT6: Commissioning and service tool (3) Display of operating/restraint state




G. Ziegler, 10/2005

page 168

Application examples



G. Ziegler, 10/2005

page 169

Protection of a two winding transformer

7SJ600 7UT512 50

51 W1

52

87T

Bu

W1 (OS)

49

W2 (US) W2

52


52

51

52


G. Ziegler, 10/2005

page 170

Protection of a three winding transformer 7SJ600 50

51

52

7UT513 W1 49-1

Bu 87T

W1 W2

W2 49-2

W3

W3

51

52

Load



G. Ziegler, 10/2005

page 171

Restricted earth fault protection for a two winding transformer 7SJ600 7UT513 50

51 W1 49-1

52 Bu

W1 (OS)

87T W2 (US) ZE 51 87TE

52


52

W2

52


G. Ziegler, 10/2005

page 172

Protection of an autotransformer

52

7SJ600 51BF

51N

50 51

7UT513 87 TL Load

52

87 TH

7VH600

49 52

3Y

51 59 7RW600

50 BF

Bu

50 51 50 BF

7SJ600

7SJ600 51 N



G. Ziegler, 10/2005

page 173

Protection of a large transformer bank 52

52

7SA6 49

21

7UT513 87 TL

50 BF 87 TH

7VH6 (3)

49

3

Load

52 52

51 59N 7RW6

50 BF 7SJ6


7SA6 21

51N

49

51 BF

7SJ6


G. Ziegler, 10/2005

page 174

Protection of a phase regulating transformers

Phase regulator

Bu 50/50N

50/50N 51/51N

Exciting transformer

Bu

51/51N 87 TS

87 TP 51N 50N


51N


G. Ziegler, 10/2005

page 175

Protection of a compensation reactor No phase CTs at neutral side

3 52 49-1

50 51

87N

7UT613

1



G. Ziegler, 10/2005

page 176

Protection of a compensation reactor with phase CTs at neutral side

7SJ600

50

3 52

51

7UT613

49

87

87N

3

1



G. Ziegler, 10/2005

page 177

Differential protection of generation units (1) a)

c)

d)

e)

52

52

52

52

∆IT

∆IT

∆IT

∆IT

G

G G

∆IG

52

∆IG

G



∆IG

G. Ziegler, 10/2005

page 178

Differential protection of generation units (2)

52

∆IT 52 *) ∆IT

G

∆IG *) same ratio as generator CTs

52


Auxiliaries


G. Ziegler, 10/2005

page 179

Dimensioning of CTs at the station service transformer

250 MVA 220 /10 kV

T1

∆IT Fault F1: High fault currents in relation to the rated current of the station-service transformer T2 (>100xIN) and long DC time constants (>100 ms) require considerable over-dimensioning of CT cores Œ and • .

IK-T

250 MVA 10 kV

IK-G

Œ •

G F1 25 MVA 10,5 / 5 kV

∆IT

T2

Ž F2


EB

7UT61

Fault F2: uncritical as current is limited by short-circuit impedance of station-service transformer T2. CT Ž can have normal dimensions


G. Ziegler, 10/2005

page 180

Digital Transformer Differential Protection

I0-correction + vector group adaptation

Differential Protection Course

PTD Service Power Training Center

Nürnberg 2005

G. Ziegler, 5/2005

page 1

Copyright © SIEMENS AG PTD SE 2002. All rights reserved.

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


1

2

3

2

∆

∆

∆


3 Nürnberg 2005

G. Ziegler, 5/2005

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



1

1

3

2

∆

∆

∆


3 Nürnberg 2005

G. Ziegler, 5/2005

page 3


Digital Line Differential Protection Gerhard Ziegler



G. Ziegler, 10/2005

page 179

Line differential protection, Versions

Line differential protection with wire connection I1

Three-wire (control cables) up to about 15 km

current comparison

∆Ι ∆I

I2

I1

voltage comparison

I2

∆U

∆I

∆I

I2

Two-wire (telefon pilots) up to about 25 km

∆I U2

U1 I1

7SD503

7SD502/ 7SD600

Line differential protection with digital communication I

7SD61 Other services

I2

1

I 2

I1

∆I

∆I

∆I

Up to ca. 200 km line length

∆I

PCM MUX

Data net

PCM MUX

PCM MUX

dedicated optic fibres up to ca. 35 km OF or microwave

PCM MUX



7SD61

G. Ziegler, 10/2005

page 180

Digital pilot wire relay 7SD600

Combines ØTraditional pilot wire protection principle with ØModern digital relay technology Novel features: § Self-monitoring and pilot wire supervision § Saturation detector § Measurement of pilot loop resistance § Add-on functions Differential Protection Symposium


G. Ziegler, 10/2005

page 181

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



G. Ziegler, 10/2005

page 182

Digital Relay to Relay Communication (Overview)

Dedicated Optic Fiber

or E O

O

Data Comms net

E

87L

87L E

or ISDN

O

E

O E

or O

O

E

Pilot wires Communication according to given possibilities



G. Ziegler, 10/2005

page 183

Converter for digital communication via pilot wire

7SD52/61

7XV5662-0AC00

5 kV insulated 7XR9516

OF-cable mutli-mode fibre max. 1,5 km


Barrier transformer 20 kV (optional)


Wire connection

up to ca. 8 km

G. Ziegler, 10/2005

page 184

Line differential protection with converter for digital communication 7SD52/61

7XV56 Digital data network

OF Multi-mode fibre max. 1.5 km


Interface to data network: X.21 or G.703.1 (wired connection)


G. Ziegler, 10/2005

page 185

Relay to Relay Communication: Two terminal configuration with hot standby connection

Commsconverter FO 820 nm

O

FO 820 nm X21 or G703.1

Main connection interrupted

Hot standby connection Permanent supervision.

Commsconverter

E

I2 Direct FOconnection. Main connection 512 kBit/s for the 87L function

Loss of main connection

Data Comms network

E X21 or G703.1 (64 kBit/s)

I2 Hot standby connection active Switchover takes 20 ms

I1

O

Data Comms network

I1

O

E

O Main connection re-established

E

Closed ring Differential Protection Symposium


G. Ziegler, 10/2005

page 186

Relay to Relay Communication: Ring- and Chain topology, loss of one data connection tolerated Closed ring

Chain

side 2

side 2

I2

side 3 I3

side 3

I2

I3+ I1

I3

I2

I1+ I2 I1

I3+ I1

I3

I1

I1+ I2 side 1

side 1 Partial current sums



G. Ziegler, 10/2005

page 187

Line differential relay with digital communication (7SD52) Application to 3-terminal line C

5P20 1600:1 Cable tab 110 kV 8 km, 0.25 µF/km IC=40 A

A

OH-line A-B 110 kV, 60 km 8 nF/km, IC=10 A

10P10 400:1

O E

OF: 820 nm

PCM

5P20 1600:1

Digital communication network

PCM

B

O E

Wired interface: X.21 or G701.1



G. Ziegler, 10/2005

page 188

Line differential relay with digital communication (7SD52) Application to tapped line

87L

7SA52

7SA52

87L

Net

Net 7SA52 87L 7SA52 87L



G. Ziegler, 10/2005

page 189

Line differential relay with digital communication (7SD61) Transformer-line protection

10P10, 10 VA, 200:1

20 MVA, 110 kV / 20 kV, Yd5

10P10, 10 VA, 600:5

8 km 50/51

LWL

7SD61

87T 50/51 50 BF


87T 50/51 50 BF

7SD61


G. Ziegler, 10/2005

page 190

7SD52/61: Bias for CT errors

I1 Error %

i1 10%

fL

fF

Load range

Fault range I1 ALF‘/ALFN • IN-CT

f

: relay setting parameters


ALF’ •IN-CT

Example: 10P10, fL < 3%, fF = 10% at ALF‘•IN-CT


G. Ziegler, 10/2005

page 191

Relays 7SD52/61: Operating characteristic

IDiff

I2

Tripping area Restraint area

IDiff>

Operation

I3

I1

I3

I1 External fault

I2

fCT

IStab IDiff = I1 + I2 + I3

(Calculated differential current)

IStab = IDiff> + Σ Sync.error + |I1| •fCT1 +|I2| • fCT2 + |I3| • fCT3



G. Ziegler, 10/2005

page 192

7SD52/61: Impact of line charging current I1

E1

U1

I2

IC

U2

E2

IDiff = I1 + I2 + IC (currents I1 and I2 counted positive in line direction!) Without charge current compensation: Pick-up value:

IDiff> > 2,5.. 4 • I C

è Senstive setting only for short cables or lines

With charge current compensation: Pick-up value:

IDiff> > 0,2 • IN



G. Ziegler, 10/2005

page 193

7SD52/61: High resistance fault sensitivity 230 kV

A

IL= 1000 A 1000/1 A

1000/1 A

B

Infeed 7SD52

IF

Load RF

7SD52

lline = 120 km Ic = 72 A Channel unsymmetry: 0.2 ms = 4.32 O ≈ 5O (60 Hz) 5P type CT, i.e. 1% error in the load area, set: f CD= 2% Relay pick-up setting about 4xIC: IDiff> = 30% In = 300 A I Op = I A + I B = 1000 A + I F − 1000 A = I F I Re s = I Diff > + Fsync + f CTA ⋅ I A + f CTB ⋅ I B = I Diff > + ( I L + I F ) ⋅ sin

∆ϕ ∆ϕ + I L ⋅ sin + f CTA ⋅ ( I L + I F ) + f CTB ⋅ I L 2 2

I Diff > + (2 ⋅ sin (∆ϕ / 2 ) + f CTA + f CTB ) ⋅ I L 300 A + (2 ⋅ sin 5o / 2) + 0.02 + 0.02) ⋅1000 A IF > = = 457 A o 1 − (sin (∆ϕ / 2 ) + f CTA ) 1 − (sin(5 / 2) + 0.02) R F− max . =

230 kV 230 kV = = 290 Ohm 3 ⋅ I F− min . 3 ⋅ 457A



G. Ziegler, 10/2005

page 194

7SD52/7SD61: Charge comparison protection supplement Q2

Q1

Q

Q3

1/4 cycle

n+4 n+3 n+2 n+1 n n-1

speed 64 kbit/s 128 kbit/s 512 kbit/s (FO)

Calculation of the charge n+5

t +T 4 Q=

∫

i i I(t) ⋅ dt ≈ ( n + n + 5 + 2 2

t

n+4

∑ In ) ⋅ ΔT

QDiff = │Q1+Q2+Q3│

n +1

with ∆T= 1 ms (18O el.)

2 relays 21 ms 16 ms 14 ms




Trip Area Restrain Area

QDiff>> Settable pick-up value 0


0

Qrest= Σ Q errors

G. Ziegler, 10/2005

page 195

Development of IED processing and communication power

Year

Memory

1986

192 kB

0.5 MIPS

16 bit

19.2 kbps

1992

768 kB

1.0 MIPS

16 bit

115.2 kbps

1998

8.5 MB

35 MIPS

32 bit

1.5 Mbps (LAN)

2004

28 MB

80 MIPS

32 bit

100 Mbps (LAN)

Processing power


Bus width

Communication


G. Ziegler, 10/2005

page 196

21 & 87 Relay United full scheme distance and differential protection 21

87

Copy of well proven features 21, 21N

85 - 21

67N

85 - 67N

68, 68T

27 WI

79

25

59

27

49

81

51/51N

50 BF

21 & 87

2 in 1

87

∆I

IRest



G. Ziegler, 10/2005

page 197

Universal line protection relay 87 Differential 21 Distance

line protection

67 DEF For all kind of lines Short to long lines

For all kind of communication:

Parallel lines

Traditional : PLC, Pilot wires, Microwave

Multi-terminal lines

Dedicated OF

Tapped lines

Digital microwave

Transformer lines

Comms networks

For all kind of operation Single and/or three-pole ARC

Series comp. lines



G. Ziegler, 10/2005

page 198

Line with larger transformer taps Release of 87 by 21 distance overreaching zone 87

87

21

21

Net

Net

87

& 21

Permissive tripping


Allows low setting of 87 pick-up!


G. Ziegler, 10/2005

page 199

Line differential relay with digital communication (7SD61) Application to tapped line, Example 400/1 A

∆I

∆I

400/1 A Net

Net 110 kV SSC1‘‘=2000 MVA ZS1 = 6.05 Ω

l1= 8 km XL1= 3.2 Ω

l2= 10 km XL2= 4.0 Ω

20 MVA uT=12 % XSC-T= 73 Ω 1.1 ⋅ U N / 3 1.1 ⋅ 110/ 3 kV ISC ≈ = = 957 A X SC − T 73 Ω

l3= 5 km XL3 = 2.0 Ω

5 MVA uK=8 % XSC-T= 194 Ω

l4= 4 km XL4= 1.6 Ω

110 kV SSC2‘‘=1000 MVA ZS2= 12.1 Ω

10 MVA uK=10 % XSC-T= 121 Ω

S N −T ∑ ΣI Rush ≈ 5 ⋅ = 5⋅ 3 ⋅U N

35 MVA 3 ⋅110 kV

= 918 A

u Setting pick-up value ∆I > 1.3·957 A u or blocking ∆I via remote signalling when tap protection operates u or release of ∆I by an overreaching distance zone



G. Ziegler, 10/2005

page 200

Fully redundant line protection using dissimilar protection and comms principles

87

MUX

comms net

MUX

87

21

21

87

87 PLC

PLC

21

21

Fully redundant 87 and 21 teleprotection remains in operation in each combination of relay and communication failure!



G. Ziegler, 10/2005

page 201

Phase segregated 87 differential and 21 distance pilot protection: Enhanced selectivity with multiple faults

87 differential and 21 pilot protection

Ph a - E

Ph b - E

Phase selective fault clearance and auto-reclosing also with multiple-faults



G. Ziegler, 10/2005

page 202

Phase segregated 87 differential and 21 distance pilot protection: Enhanced selectivity with multiple faults

87 differential and 21 pilot protection

Ph a - E

Ph b - E

Phase selective fault clearance and auto-reclosing also with multiple-faults



G. Ziegler, 10/2005

page 203

Two-sided fault locator using 87&21 relay communication I1

I2

Grid 1

Grid 2 U1

U2

Digital comms

XL•I1

XL•I2 U2

U1 (I1+I2)•RF Distance



G. Ziegler, 10/2005

page 204

Conclusions

ü Combined distance and differential protection relays , together with modern comms, allow to enhance line protection in a cost saving way. üThe dissimilar protection principles complement each other perfectly. üDistance and differential protection can both be configured as phase segregated teleprotection schemes allowing absolute phase selective fault clearance and autoreclosure even with complex cross county and intercircuit faults. üDigital relay to relay comms allows to exchange data for upgraded two sided fault locating. üUsing a single relay type for distance and/or differential protection also saves on cost in investment and operation.



G. Ziegler, 10/2005

page 205

7SD51: Phase comparison, Dynamic supplement based on delta-quantities I1

I2

PCP

PCP

7SD512

7SD512

i2(t)

i1(t)

∆ i1(t) = i1(t) -i1(t -2T)

−


−

+

+

−

−

+

Sign.{ ∆i2 }


+

Sign.{ ∆i1 }

∆ i1(t) = i1(t) -i1(t -2T)

G. Ziegler, 10/2005

page 206

7SD51: Phase comparison I1

I2

PVS

PVS

PVS

PVS

7SD512

7SD512

7SD512

7SD512

i1(t)

I1

i1(t)

i2(t)

−

−

+

+

−

+

−

no coincidence

+

+

−

−

−

+

+

+

I2

−

no coincidence

i2(t) +

−

+

+

−

+

+ − − Full coincidence

−


−

+

+ − − Full coincidence

Tripping

External fault

+

Tripping

Internal fault,


G. Ziegler, 10/2005

page 207

7SD51: Phase comparison: Impact of charging current

I1=IL+IC

-I2= IL IL

IC

E1

I1

E2

ϕKO IC I1

-I2


-I2

undefined range

ϕ

Phase shift ϕ caused by charging current IC

ϕ

I2

Tripping range

undefined range due to discrete sampling : ±1/2∆T = ± 1,66/2 ms= ± 15O


G. Ziegler, 10/2005

page 208

Phase comparison protection 7SD51: Sampling of the rectangular sign wave and data transmission telegram

i(t)

Sampling interval (1,66 ms) 01

Sign.{ i(t) }

00 11

−+++ START

1 1

···

1 0 1

CHECK

END

Telegram acc. to IEC 60870-5 Hamming distance d= 4

4 directional signs per phase = 12 binary digits



G. Ziegler, 10/2005

page 209

Measurement based on delta quantities, Principle ∆I1, ∆I2: DELTA-quantities

Total situation after fault inception: ZV1 E1

I2

I1

∼

ZV2

RF

∼

E2

∼

E2

Load before fault inception: ZV1 E1

Pure fault part :

I1L

I2L

∼

ZV2

UFL

ZV1

∆I1=I1F

∆I2=I2F RF


∼

ZV2

UFL


G. Ziegler, 10/2005

page 210

Digital Busbar Protection Gerhard Ziegler



G. Ziegler, 10/2005

page 217

Busbar differential protection, Principle (Analog technique) Busbar

1

n

2

Iop

k ⋅ I Res

IOp

Measuring circuit

Tripping area

Operating characteristic

k% Iop> IRes



G. Ziegler, 10/2005

page 218

Part-digital Busbar protection 7SS6

4AM 3

3

2

1

ΣI

100mA∼ /IN

3

n

7SD601

=

7TM70


ΣI

=

1,9 mA= /IN


G. Ziegler, 10/2005

page 219

7SS6: Operating characteristic

IA

Internal faults (k=1) Relay characteristic k= 0.25 to 0.8

Id >

IS



G. Ziegler, 10/2005

page 220

Isolator replica, Principle, (stabilising circuit not shown) BB 1 +

1 _

+

2

+

k

_

_

BB 2

+

_

_

_

+

+

∆I1 ∆I2

_



G. Ziegler, 10/2005

page 221

Decentralised BB-protection 7SS52, Structure

Optic fibre-communication - HDLC protocol - 1,2 MBaud

Wired connections



G. Ziegler, 10/2005

page 222

7SS50/52: Maximum configuration 1

2

3

4

5

6

7

Transfer bus

7SS50 centralised Bays

7SS52 decentralised

32

48

BB-zones

8

12

couplings

4

16



G. Ziegler, 10/2005

page 223

7SS50/52: Acquisition and supervision of isolator positions

Connection to central unit OF

+



G. Ziegler, 10/2005

page 224

Operating characteristic of BB protection 7SS52

Internal faults (k=1)

IOp

Relay characteristic (k =0.1 - 0.8) k

Optional extension for networks with limited earth current (impedance earthing) (release by U0>)

∆I > ∆IE > IRes<


IRes


G. Ziegler, 10/2005

page 225

BB-Protection 7SS52 Performance in networks with earth current limitation 110 /10 kV 40 MVA

IL =

35MVA 10kV ⋅ 3

= 2 kA

I F = I E = 10/ 3kV/6Ω ≈ 1 kA

RE= 6 Ohm (IE = 1 kA)

Restraint current:

I Res = Σ I = (2 + 1) + 2 kA

Operating current:

I Op = ΣI = I E = 1 kA k=

35 MW

k

IOp

I Op I Re s

=

1 = 0.2 5

Relay operating characteristic (k =0.1 - 0.8) Additional, for earth faults (release by U0>)

∆I>

Iop-E= IE = 1kA

∆IE>= 500 A IRes-L= 4kA

IRes

Ihres-E= 1kA

IRes<= 7kA



G. Ziegler, 10/2005

page 226

Check zone of busbar protection

∆ISS1 ∆ISS2 ∆ICheck Check zone: Ø in the past used with HI protection on EHV level (needs separate CT cores) Ø in general not used with traditional low impedance busbar protection (too expensive) Ø However, now integrated as software function in full scheme versions 7SS51 and 7SS52



G. Ziegler, 10/2005

page 227

7SS52: special restraint algorithm avoids over-stabilisation

Check zone

I1

I2

IOp

I4

I3

I3 + I4

IOp I1 +I2 I1 +I2 2·(|I3| +|I4| )

I1 +I2

IRes

Normal restraint: Sum of all current magnitudes

|I3 + I4|

Special restraint algorithm: Positive and negative currents are added separately. Σ I p = I1 + I 2 + I 3 + I 4

I Res = Σ I = I1 + I2 + I3 + I 4 + I3 + I4

IRes

Σ I n = I3 + I 4

Smaller value is then taken: I Res = Σ I n = I3 + I 4



G. Ziegler, 10/2005

page 228

7SS52: Special treatment of dead zone faults (1)

BB-A BB-B


Bus coupler CB aux. contacts not connected: • 87-A trips bus coupler • Current inverted in 87-B after T-BF. Subsequently 87-B trips BB-B Coupler CB auxiliary contacts connected: • 87-B trips immediately after opening of bus coupler CB because coupler current is removed from bus protection. → time reduction (T-BF saved)


G. Ziegler, 10/2005

page 229

7SS52: Special treatment of dead zone faults (2) BB-A

A) Bus coupler CB aux. contacts not connected: • 87-A overfunctions and trips unnecessarily. • 87-B „sees“ an external fault and only trips finally through BF function (delay T-BF!) B) Bus coupler CB aux. contacts connected: • 87-A remains stable („sees“ no fault current) • 87-B trips immediately

BB-B

Coupler CB auxiliary contacts connected to 7SS52: Coupler current is removed from 87-A and 87-B current comparison with open coupler CB.



G. Ziegler, 10/2005

page 230

7SS52: Special treatment of dead zone faults (3) Two CTs in coupling bay, overlapping protection zones BB-A

Coupler CB auxiliary contacts connected: • 87-A „sees“ external fault and remains stable • 67-B correctly trips BB-B

BB-B

87 A

87 B Coupler CB auxiliary contacts connected to 7SS52: Coupler currents are removed from 87-A and 87-B current comparison with open coupler CB.



G. Ziegler, 10/2005

page 231

7SS52: Treatment of switch onto a faulted (earthed) bus

BB-A BB-B


Coupler CB close command is detected by bus protection (change of biary input signal): • Coupler current is immediately reincluded in the 87 current comparison before CB contacts close. • Selective tripping of BB-B by 87-B.


G. Ziegler, 10/2005

page 232

7SS52 : Integral breaker fail protection

Busbar protection7 SS52

Bay protection

& Fault detection

Trip

&

T-BF

Current reversal

∆I 87

Trip

With line fault and CB failure: • Trip command of bay protection hangs on at BB protection • Forced current reversal of the current of concerned bay after T-BF • Zone selective tripping only of the concerned busbar • Advantage: Reset time (overtravel time) of bay protection does not matter Differential Protection Symposium


G. Ziegler, 10/2005

page 233

External bay dedicated BF protection Zone selective tripping via isolator replica of 7SS52 busbar protection Bay (feeder) protection

trip

7SS52

T-BF

&

I>

&

Isolator replica

Selective bus trip

Fault detection

• • •

BF trip command to busbar protection binary input (for security: fault detection signal as second criterion) Distribution of trip commands via isolator replica to breakers of concerned busbar èzone selective tripping of concerned busbar



G. Ziegler, 10/2005

page 234

Fail safe design: 3-out-of-3 decision per bay

∆I of check zone calculated from all samples

∆I of discriminative zones, calculated from even samples

∆I of discriminative zones, calculated from odd samples

Trip- relay (per bay) L+

L–



G. Ziegler, 10/2005

page 235

Adaptive measurement (Booster circuit) (7SS5)

Odd Samples Even Samples

dI S dt

dI S dt

1 ms


dI S dt

Check zone


G. Ziegler, 10/2005

page 236

Digital busbar protection 7SS5, Measuring technique External fault, symmetrical fault current I1

I2

1 1

IOp= |I1+I2|

I1 0

10

20

0

1

I2

2

1.5 1 0.5 0.5 1 1.5

10

20

t

20

0

10

20

0

10

20

0

1.5

0

10

20

k·IRes = k·(|I1|+|I2|)

1 0.5

1.5

IRes=|I1|+|I2|

1

1

∆I = IOp - IRes

0.5 0

10


20

1 0.5 0.5 1 1.5


G. Ziegler, 10/2005

page 237

Digital busbar protection 7SS5, Measuring technique Internal fault, symmetrical fault current I1

I2 2

1

1

I1

0

10

20

IOp= |I1+I2|

1

I2

)

1.5 1 0.5 0.5 1 1.5

0

10

20

0

10

20

0

10

20

1.5

0

10

20

k·IRes =k·(|I1|+|I2|)

1 0.5

2

1

1

1 0.5

)

0.5 1 1.5

∆I=IOp - IRes

IRes=|I1|+|I2| 0

10

20



Tripping! G. Ziegler, 10/2005

page 238

7SS5/6: Admissible over-burdening - Necessary dimensioning of CTs with regard to symmetrical fault currents Ri

I1 IM

∫

∫

Φ = e2(t ) =(Ri + RB ) i 2(t )

RB

I2

E2

φ

5

1

2

φmax 180O

54O

90O

Im Φ max ≅

180O

180O

180O

0

o

o

∫ ALF'⋅u 2N (t) ⋅dt = (Ri + R B ) ∫ ALF'⋅i2N (t) ⋅ dt = (R i + R B )⋅ ALF'⋅Î2 ⋅ ∫ sinx ⋅ dt = (Ri + R B )⋅ ALF'⋅Î2N ⋅ 2 O

x 180 Î ˆ sinx ⋅ dt = ALF'⋅Î 2N ⋅ 2 2F sinx ⋅ dt = ALF'⋅I 2N ⋅

∫ o

∫ o


I 2F 2 = ALF'⋅ x I 2N sinx

∫

I I 2 k OB = 2F 2N = x ALF' sinx

o


∫ o

G. Ziegler, 10/2005

page 239

Required restraining factor k dependent on over-burdening factor KOB (over-dimensioning factor KTF) 1.5 1 1

IRes= |I1|+|I2|

0.5 0

10

IOp < k·IRes

Condition for stability:

1‘

sinx >

0 0

I F < k ⋅ 2 ⋅ I F ⋅ sin x

1 2⋅k

I I 2 2 ü = 2K 2N = = x n' 1 − cosx sinx (from previous transparency)

2

20

2 ⋅ I F ⋅ sin x

x

∫ o

IOp= |I1+I2|

IK

k>

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



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


60

2


G. Ziegler, 10/2005

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


20

Tripping!


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


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 =


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



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


5


G. Ziegler, 10/2005

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


IR


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 )


I F − through − max <

RR ⋅ IR R L + R CT

600 10.000 ⋅ ⋅ 0.02 1 3+ 4

I F − through − max < 17 kA = 28 ⋅ I n


G. Ziegler, 10/2005

page 247

Busbar protection, Composite current type (7SS600): Performance under unfavourable system earthing conditions Busbar

2

1

3

3

2

IM=2·IL1 + 1·IL3+ 3 ·IE =2·IF + 1 ·IF+ 3·3IF = +12 ·IF

IM=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


IRes Belo Horizonte November 2005

G. Ziegler, 10/2005

page 248

Busbar protection, Composite current type (7SS600): Performance in networks with earth current limitation IL =

110/10 kV 40 MVA

35MVA 10kV ⋅ 3

= 2 kA

I F = I E = 10/ 3 kV/6Ω ≈ 1 kA RE= 6 Ohm (IE = 1 kA)

Worst case: Fault in phase L2 Restraint current: Operating current:

Ph-E

I Res = 3 ⋅ 3 kA I Op = 3 ⋅ I KE = 3 kA k=

35 MW

I Op I Re s

IL1

IL3

IE

2·IL1

IM-L

IL2


3 3⋅ 3

= 0,57

Fault L2-E

IOp IL3

=

k=0.5 |IM-L|

IRes

Load


IRes G. Ziegler, 10/2005

page 249

Differential Protection 7UT6 Remarkable Features



G. Ziegler, 5/2005

page 248

The 7UT6 Family 7UT6 differential protection for

•Transformers •Generators • Motors •Busbars

7UT612: 7UT613: 7UT633: 7UT635:

for protection objects with 2 ends for protection objects with 3 ends for protection objects with 3 ends for protection objects with 5 ends


(1/3 x 19’’ case 7XP20) (1/2 x 19’’ case 7XP20) (1/1 x 19’’ case 7XP20) (1/1 x 19’’ case 7XP20)


G. Ziegler, 5/2005

page 249

7UT6: Hardware options

Relay version current inputs

(normal) (sensitive)

voltage inputs (Uph / UE) Binary inputs Output contacts Life contact LC Display

7UT612

7UT613

7UT633

7UT635

7 (7)1) 1 --3 4 1 4 rows3)

11 (6) 1) 1 2) 3/1 5 8 1 4 rows3)

11 (6) 1) 1 2) 3/1 21 24 1 Graphic

14 (12 1) 2 2) --29 24 1 Graphic

1)

1A, 5A, (1A, 5A, 0.1A)

2)

link selectable normal/sensitive

3)

alpha-numeric



G. Ziegler, 5/2005

page 250

7UT6: Scope of functions

Function

ANSI No.

Function

Differential

87T/G/M/L

Overfluxing V/Hz

24

Earth differential

87 N

Breaker failure

50BF

Phase overcurrent,

50/51

Temperature monitoring

38

Neutral overcurrent IN>, 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


ANSI No.

Binary inputs for tripping commands


G. Ziegler, 5/2005

page 251

7UT6: Application

(1) ∆

∆I ∆I Shunt Reactor

G

Three winding transformer

Two winding transformer

∆I

Generator / Motor


∆I

∆I

Transformer bank (1-1/2-LS)

∆I

∆I

Busbars


G. Ziegler, 5/2005

page 252

7UT6: Application Generation Unit protection (overall differential)

Y ∆

(2)

HI restricted earth fault protection

7UT6xx 7UT635

G 3~



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



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)



G. Ziegler, 5/2005

page 255

7UT6: Effect of supplementary restraint in case of CT saturation

Restrain 45°

Trip

Area of add-on restraint



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!



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



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



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



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


WEB server in relay firmware Server sends HTML pages and JAVA code to WEB Browser via DIAL-UP connection


G. Ziegler, 5/2005

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7UT6: Commissioning and service tool

(2)

Current phasors of all terminals can be displayed




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



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


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°)


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


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



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


3

1

I0-correction


1

2

3

2

∆

∆

∆

3


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



1

1

3

2

∆

∆

∆

3


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


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


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°)


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


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 Differential Protection g Ziegler

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