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Digital Differential Protection G. Ziegler Differential Protection Symposium Belo Horizonte, 7 to 9 Nov. 2005 No.: 1 Differential Protection: Discussion Subjects Ø Mode of operation Ø Measuring technique Ø Current transformers Ø Communications Ø Generator and motor differential protection Ø Transformer differential protection Ø Line differential protection Ø Busbar differential protection Differential Protection Symposium Belo Horizonte, 7 to 9 Nov. 2005 No.: 2 Digital Differential Protection Principles and Application Gerhard Ziegler Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 1 Contents Pages Mode of operation 3 - 27 Measuring technique 28 - 45 Current transformers 46 - 86 Communications 87 - 115 Generator and motor differential protection 116 - 122 Transformer differential protection 123 - 178 Line differential protection 179 - 216 Busbar differential protection 217 - 247 7UT6 product features 248 - 264 Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 2 Digital Differential Protection Mode of operation Gerhard Ziegler Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 3 Comparison protection - Principles Absolute selectivity by using communications IA IB B A Exchange of YES / NO signals (fault forward / reverse) protection range reverse forward Relay forward communication reverse • Current comparison | ∆I | Relay Sampled values Phasors Binary decisions t •Directional comparison IA IB •comparison of momentary values or phasors B • | ∆I | = | IA - IB | > limiting value A Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 4 Protection Criterion “current difference“ (differential protection) n Kirchhoff‘s law: II1 + I2 + I3 + ... InI= Idiff = 0; Current difference indicates fault n Security by through-current dependent restraint |I1|+|I2|+ ... |In| = IRes protection object n Characteristic: Idiff Trip Ires n Absolute zone selectivity (limits: CT locations) No “back-up“ for external faults n Differential protection: for generators, motors, transformers, lines and busbars Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 5 Current differential protection: Basic principle I1 i1 I2 Protection object i2 ∆I> ∆I=I1 + I2 =0 external fault or load Differential Protection Symposium I1 I2 Protection object i1 i2 i1 ∆I> ∆I=I1 + I2 i2 internal fault Belo Horizonte November 2005 G. Ziegler, 10/2005 page 6 Differential protection: Connection circuit Traditional technique Digital technique L1 L1 L2 L3 L2 L3 ∆I ∆I ∆I Galvanically connected circuits must only be earthed once! Different CT ratios need to be adapted by auxiliary CTs! Differential Protection Symposium ∆I CT circuits of digital relays are segregated and must each be earthed ! Digital relays have integrated numerical ratio adaptation ! Belo Horizonte November 2005 G. Ziegler, 10/2005 page 7 Generator and transformer differential protection L1 L2 L3 L1 L2 L3 ∆I ∆I ∆I Differential Protection Symposium Yd5 Matching transformer Belo Horizonte November 2005 ∆I ∆I ∆I G. Ziegler, 10/2005 page 8 Transformer differential protection Yd5 L1 L2 L3 Matching transformer Differential Protection Symposium ∆I ∆I ∆I Belo Horizonte November 2005 G. Ziegler, 10/2005 page 9 Current transformer: Principle, transformation ratio, polarity i1 i2 i1 w1 u1 i2 1 Φ u2 i1 ⋅ w1 = i2 ⋅ w2 Function principle i1 u2 u1 u 2 = w1 w2 2 w2 u1 Polarity marks P1 P2 i2 i1 u1 i2 u2 S1 Equivalent electrical circuit Differential Protection Symposium S2 Designation of CT terminals according to IEC 60044-1 Belo Horizonte November 2005 G. Ziegler, 10/2005 page 10 Busbar differential protection Digital protection 7SS52 Analog protection 7SS10/11/13 7SS600 with digital measuring relay (∆I) ∆I Central Unit 2 4 3 Optic fibres 0 ∆I BU BU BU BU 0 G M Grid infeed BU: bay unit G Load Differential Protection Symposium M Grid infeed Belo Horizonte November 2005 Load G. Ziegler, 10/2005 page 11 Line differential protection 50/60 Hz current comparison through wire connection I1 Phasor with digital communication via OF, microwave or pilot wires I1 I2 I2 ∆I DI ∆I ∆I ∆I I1 I2 dedicated O.F. up to about 35 km Other services PCM MUX PCM MUX Other services O.F. or Microwave Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 12 Two wire (pilot wire) line differential protection Voltage comparison principle I2 I1 Grid G ∆I RS U1 ∆U ∆I U2 RS 3 3 ∆I Differential Protection Symposium ∆I Belo Horizonte November 2005 G. Ziegler, 10/2005 page 13 False differential currents during load or external faults I∆ / In te ri st ic 4 ac ∆IGF = total false current re la y ch ar 3 2 ∆IWF = CT false current ∆IAF = Inaccurate adaptation (CT ratios, tap changer) 1 ∆IWF = Transformer magnetising current 1 10 Differential Protection Symposium 15 ID / In Belo Horizonte November 2005 G. Ziegler, 10/2005 page 14 Percentage differential relay A = I1− I2 operate stabilise B S = I1+ I2 I1 Basicpick-up value (B) I2 I1+ I2 Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 15 Differential protection: analog measuring circuit Rectifier bridge comparator with moving coil relay I2 I1 protection object i1 Fault characteristic (single side infeed) i2 ΔI = W2 W1 W3 k1 ⋅ I Re s k1 ⋅ I Re s I1 − I 2 Relay characteristic W1 k 2 ⋅ I Op = k1 ⋅ (I 1 − I 2 ) k1 = I1 + I 2 > k ⋅ I1 − I 2 W4 w1 w2 Differential Protection Symposium k= k2 ⋅ I Op Σ I = I1 + I 2 = k2 ⋅ (I1 + I 2 ) k2 = w3 w4 k1 k2 with digital relays: ΣI = I1 + I 2 Belo Horizonte November 2005 G. Ziegler, 10/2005 page 16 Multi-end differential protection: Analog measuring principle 1 n 2 Iop = I1 + I 2 + .... + I n = Σ I Differential Protection Symposium k ⋅ I Re s I Op I Res = I1 + I 2 + .... + I n = Σ I Belo Horizonte November 2005 G. Ziegler, 10/2005 page 17 Optimised relay characteristic G R 2000A Ideal fault characteristic ∆Ι IOp = I1 − I 2 internal fault 300A F Load RL IOp = 2000 A relay characteristic IS = 2600 A I F1 I F2 G G CT saturation ∆Ι I Res = I1 + I 2 Healthy protection object δ I Op = 2 ⋅ I F ⋅ cos Differential Protection Symposium I Re s = 2 ⋅ I F δ 2 Belo Horizonte November 2005 G. Ziegler, 10/2005 page 18 Digital differential protection: Relay characteristic IOp Positive current polarity k2 ∆I k1 Id > IR0 I Op = ΣI = I1 + I 2 Settings: I Res = Σ I = I1 + I 2 • slope k1 IRes • Pick-up value Id > • slope k2 with footing point IR0 Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 19 ∆I / ΣI und I1 / I2 diagram ΔI = I1 + I 2 I1 Internal faults IS0 1+ k + ⋅B 2 2⋅k k [% / 100 ] slope B IS0 IS0 1− k ⋅B + 2 2⋅k Σ I = I1 + I 2 ( 1 I1 + I 2 > k I1 + I 2 − I S 0 2 I1 + I 2 > B Differential Protection Symposium ) IS0 2 Belo Horizonte November 2005 G. Ziegler, 10/2005 page 20 I2 Polar diagram of differential protection I1 + I 2 > k ⋅ I1 − I 2 β-Plane (remote/local current) I 1+ 2 1+β I1 > k or >k I2 1- β 1− I1 I  Im  2  I1  I β= 2 I1 I2 Protection object ∆Ι I with β = 2 I1 − I1 1+ k 1− k +1 -1 (k=0,5) − 1− k 1+ k I  Re 2   I1  Restraint area Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 21 Polar diagram of digital differential protection: Basic pick-up value B > 0 90 I 2 jϕ e I1 120 I1 + I 2 > k ⋅ ( I1 + I 2 ) + B or  I2 > k ⋅ 1 + 1+  I1  I2 I1  B +  I 1  60 ϕ 150 30 180 0 5 210 10 330 300 240 270 B/I1= 0,3 a1(Φ): k=0,3 a2(Φ): k=0,6 a3(Φ): k=0,8 Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 22 Mixing transformer of composed current differential protection IL1 IL2 IL3 IL1 Composed current during symmetrical 3-ph fault or load IM 2 IL3 7SD503: IM = 100 mA 7SS600: IM = 100 mA 7SD502: IM = 20 mA 1 IE 3 Mixing transformer IM = IL3 1 ⋅ 3 ⋅ I Ph −3 w 2 ·IL1 IL3 IL1 I M = 2 ⋅ I L1 + 1 ⋅ I L3 + 3 ⋅ I E IL3 IL2 Differential Protection Symposium = 5 ⋅ I L1 + 3 ⋅ I L2 + 4 ⋅ I L3 ⇒ composed current (vector sum) Belo Horizonte November 2005 G. Ziegler, 10/2005 page 23 Mixing transformer: Pickup sensitivity of standard connection (IM= 2IL1+IL3+3IE ) Fault type Per unit composed current related to 3-phase symmetrical current Composed current L1-E IML1-E = 5 IL1 IL2 = IL3 = 0 IML1-E / IM = 5 / √ 3 = 2.9 L2-E IML2-E = 3 IL2 IL1 = IL3 = 0 IML2-E / IM = 3 / √3 = 1.73 L3-E IML3-E = 4 IL3 IL1 = IL2 = 0 IML3-E / IM = 4 / √3 = 2.3 L1-L2 IML12 = 5 I L1 + 3 I L2 IL3 = 0 IML12 / IM = 2 / √3 = 1.15 L2-L3 IML23 = 3 I L2 + 4 I L3 IL1 = 0 IML23 / IM = 1 / √3 = 0.58 L1-L3 IML13 = 5 I L1 + 4 I L3 IL2 = 0 IML13 / IM = 1 / √3 = 0.58 L1-L2-L3 IML123 = 5 IL1 + 3IL2 + 4IL3 |IL1| = |I L2| = |I L3| IML123 / IM = √3 / √3 = 1 Differential Protection Symposium Belo Horizonte November 2005 Highest sensitivity G. Ziegler, 10/2005 page 24 Composed current differential protection Behaviour during cross country fault (isolated/compensated network) ∆I A B L1 L2 L3 IF L1 internal und L3 external: IM-A= 5⋅IF - 4⋅IF = 1⋅IF und IM-B= + 4⋅IF ∆I = |IM-A + IM-B| = 5IF und ΣI = |IM-A| + |IM-B| = 5⋅IF ∆I/ΣI = 5/5 = 1.0 Tripping L2 internal, L3 external IM-A= - 1⋅IF und IM-B= + 4⋅IF ∆I = |IM-A + IM-B| = 3 ⋅IF und ΣI = |IM-A| + |IM-B| = 5⋅IF ∆I/ΣI = 3/5 = 0.6 Tripping if k-setting < 0.6 Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 25 Composed current differential protection Through current stabilisation with unsymmetrical earthing conditions 2 1 3 3 2 IM2=2·IL1 + 1·IL3+ 3 ·IE =2·IF + 1 ·IF+ 3·3IF = +12 ·IF IM1=2·IL1 + 1·IL3 + 3 ·IE =2 ·(–IF) + 1 ·(–IF) + 3·0= –3·IF IOp=| IM1 + IM2 | = 9 ·IF IRes=|IM1| +|IM2| = 15 ·IF 1 k=9/15 = 0.6 IOp Fault L2-E k=0.5 Faults in other phases: Fault L1-E: IOp = (3+12) ·IF = 15 ·IF, IRes= (3+12) ·IF = 15 ·IF, k=1 Fault L3-E: IOp = (0+12) ·IF = 12 ·IF, IRes= (0+12) ·IF = 12 ·IF, k=1 Differential Protection Symposium IRes Belo Horizonte November 2005 G. Ziegler, 10/2005 page 26 High impedance differential protection: Principle Behaviour during external fault with CT saturation with ideal current transformers ISC RCT RCT ISC ISC ISC UR ECT −1 = (RL + RCT ) ⋅ iSC ECT −1 = 2 ⋅ (RL + RCT ) ⋅ iSC UR = 0 ECT −2 = (RL + RCT ) ⋅ iSC Differential Protection Symposium U R = (RL + RCT ) ⋅ iSC Belo Horizonte November 2005 G. Ziegler, 10/2005 page 27 High impedance differential protection: Calculation example (busbar protection) Given: n = 8 feeders rCT = 600/1 A UKN = 500 V RCT = 4 Ohm ImR = 30 mA (at relay pick-up value) Pick-up sensitivity: ( 600 ⋅ (0.02 + 0.05 + 8 ⋅ 0.03) 1 I F − min = 186 A ⋅ (31% ) Differential Protection Symposium RR = 10 kOhm Ivar = 50 mA (at relay pick-up value) Stability: I F −min = rCT ⋅ I R − pick −up + IVar + n ⋅ I mR I F − min = RL= 3 Ohm (max.) IR-pick-up.= 20 mA (fixed value) ) I F −through − max < rCT ⋅ I F −throuh − max < 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 Differential Protection Symposium Belo Horizonte November 2005 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. Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 29 Electro-mechanical differential protection based on induction relay I2 I1 Schutzobjekt i1 Differential Protection Symposium ∆i i2 Belo Horizonte November 2005 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 Differential Protection Symposium N S Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 = Differential Protection Symposium when n sampled values exceed the pick-up limit I= f ∆ϕ = ω ⋅ ∆Tsamp. = N ⋅ 360O fA Belo Horizonte November 2005 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 Belo Horizonte November 2005 G. Ziegler, 10/2005 page 35 Discrete Fourier-Transformation (Principle) sin 2π ⋅i n 0 1 2 . . i( k −n+i ) . Correlate: Multiply samples and add for one cycle n Correlate IS(k) i k-n I (k) = I S(k) + j ⋅ I C(k) k Correlate IC(k) I (k ) j IC(k) cos 2π ⋅i n Differential Protection Symposium Belo Horizonte November 2005 ϕ IS(k) G. Ziegler, 10/2005 page 36 Discrete Fourier-Transformation (calculation formulae) i 0 i1 i2 i 3 iN ∆t N   I = 2  ∑ sin(ω ⋅n⋅ Δt )⋅in S N  n=1  N i  i N-1 I = 2  O + N + ∑ cos(ω ⋅n ⋅ Δt)⋅in C N  2 2 n=1  N-1 0 1 2 3 .... n 0 1 2 3 ... Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 37 Orthogonal components of a current phasor dependent on the position of the data window Data window Φ = ωt IS = Φ 1 ⋅ ∫ I (ω ⋅ t ) ⋅ sin ωt ⋅ dt 2π Φ −360 IC = Φ 1 ⋅ ∫ I (ω ⋅ t ) ⋅ cos ωt ⋅ dt 2π Φ −360 I Φ = I S + j ⋅ IC I0 = 1+ j ⋅ 0 I O O O I30 3 1 = + j⋅ I 2 2 O I 60 1 3 = + j⋅ I 2 2 O jIC I IS ωt t=0 I90 = 0 + j ⋅1 I O Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 38 Transfer function of a one cycle Fourier-filter Hrel 1,0 0,75 0,5 0,25 0 0 1 Differential Protection Symposium 2 3 4 5 6 f/fn Belo Horizonte November 2005 G. Ziegler, 10/2005 page 39 Digital protection Fast current phasor estimation N k-N i(t) k Data window i(t) = A ⋅ sin( ωt ) + Task: Method: Delta =  t  −   B ⋅  cos( ωt) - e τ  + C ⋅ cos( ωt)       Estimation of the coefficients A, B, C on basis of measured currents and voltages Gauß‘s Minimization of error squares: Delta = quality value k = sampling number k N = length of data window 2 ∑ i(n ⋅ ∆T) - f (n) MIN n = variable n=k-N ∆T = sampling interval sampled values ( ) Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 40 Differential protection with phasors (principle) A ∆I B IAC , IAS IBC , IBS ∆I ∆I trip ∆I> restraint j·IAS ΣI Operating quantity : ∆I = I A + I B Restrainin g quantity : Σ I = I A + I B IBC IAC j·IBS Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 41 Digital line differential protection Synchronisation of phasors (ping-pong time alignment) A tA1 tA2 ∆I ∆I curre n phas t o rs α ... tPT1 tAR tA5 tA1 tPT2 tV tB3 tA1 tBR tB2 α= tB3 nt curre . . . rs ph aso Differential Protection Symposium t B3 - t A3 ⋅ 360 ° TP tB4 Signal transmission time: t PT1 = t PT2 = Sampling instant: IB( tB3 ) tB1 tD tA3 tA4 IB( tA3 ) B 1 (t A1 - t AR - t D ) 2 t B3 = t A3 - t PT2 Belo Horizonte November 2005 G. Ziegler, 10/2005 page 42 Split path data transmission Impact of unsymmetrical propagation time I1 I2 ∆I ∆I 180o ∆T[ms ]⋅ α 10ms ∆I = I ⋅ sin = I ⋅ sin 2 2 α I2 I1 Example: Transmit channel time 3 ms Receive channel time 4.2 ms → time difference ∆ = 1.2 ms 180o 1.2ms ⋅ 10ms = I ⋅ 0.19 ∆I = I ⋅ sin 2 ∆I α/2 ∆I = 19%! To keep the false differential current below about 2 to 5%, the propagation time difference should not exceed about 0.1 to 0.25 ms! Otherwise: → more insensitive relay setting → or GPS synchronisation Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 43 Synchronisation of Differential relays via GPS Line end 1 Line end 2 GPS-Antenna RS232 GPS-Antenna GPS RS232 UH DC GPS-Empfänger supply DCF-SIM A B LWL LWL IRIG-B 24V GPS GPS-Empfänger Hopf DC supply DCF-SIM A B LWL LWL IRIG-B 24V IRIG-B Telegram Sec. impulse (highly accurate) LWL K1 LWL BE2 K2 IRIG-B Telegram Sec. impulse (highly accurate) LWL K2 K1 7XV5654 Sync-Trans. K1 X1 K2 K2 LWL BE2 K2 K2 7XV5654 Sync-Trans. K1 X1 K2 K2 + - 24V + 1 3 8 4 + - 24V + 1 3 8 4 Y-cable 7XV5105 1 3 8 4 RUN 7SD52 SIEMENS ERR OR L1 402,1A L2 402,1A L3 402,1A E 00.0A to max. Differential Protection Symposium SIEMENS ERR OR L1 402,1A L2 402,1A L3 402,1A E 00.0A 7SD52 6 V4 SIPROTEC RUN Max450.1A Max450.1A Max450.1A Anr. L1 Anr. L2 Anr. L3 Anr. Erde Automat 1 3 8 4 V4 SIPROTEC RUN Max450.1A Max450.1A Max450.1A Anr. L1 Anr. L2 Anr. L3 Anr. Erde Automat 1 1 3 8 4 V4 SIPROTEC L1 402,1A L2 402,1A L3 402,1A E 00.0A Y-cable 7XV5105 1 3 8 4 V4 SIEMENS UH SIEMENS ERR OR SIPROTEC RUN Max450.1A Max450.1A Max450.1A L1 402,1A L2 402,1A L3 402,1A E 00.0A Anr. L1 Anr. L2 Anr. L3 Anr. Erde Automat ERR OR Max450.1A Max450.1A Max450.1A Anr. L1 Anr. L2 Anr. L3 Anr. Erde Automat 1 t0 max. Belo Horizonte November 2005 6 G. Ziegler, 10/2005 page 44 Devices for GPS time synchronisation n GPS receiver with 2 optical outputs (7XV5664-0AA00). Output for IRIB-B telegram and output for second/ minute pulse n Galvanic separation between the receiver and the tranceiver 7XV5654 n Optic/electric signal conversion in the tranceiver n Distribution of the electrical signals via Y-bus cable to port A of the relays (telegram) n Electronic contact for the minute pulse in case of synchronisation through binary input with battery voltage Differential Protection Symposium Outdoor antenna FG4490G10 for GPS GPS receiver 7XV5664 Tranceiver 7XV5654 Belo Horizonte November 2005 G. Ziegler, 10/2005 page 45 Additional components for SICAM SAS GPS-System • • • • Differential Protection Symposium 24 satellites move in a height of 20 000km on 6 different paths Transmission frequency 1,57542GHz For a continuous time reception min. 4 satellites is necessary High accuracy : 1 usec Belo Horizonte November 2005 G. Ziegler, 10/2005 page 46 Operating characteristic of digital differential relays I∆ =|I1+ I2| I1 I2 b% ∆I I∆> a% I∑ b Differential Protection Symposium I∑ = |I1|+ |I2| Belo Horizonte November 2005 G. Ziegler, 10/2005 page 47 Differential protection CT saturation with internal and external faults ∆I Protection object I2 I1 Internal fault External fault I1 I2 Σ I= |I1| + |I2| ∆I=|I1 +I2| t=0 t=10 Differential Protection Symposium t=20 ms t=0 t=10 t=20 ms Belo Horizonte November 2005 G. Ziegler, 10/2005 page 48 Saturation detector: Locus of ∆I/ΣI for external faults without and with CT saturation i Op( n ) = i1( n ) + i 2( n ) 6' 7' saturation 3' re s i 2( n ) in tra n 8' External fault 5' 4' with CT i1( n ) e rat e op i1( n ) + i 2( n ) 9' 0 10 External fault (ideal CTs) 1 2 3 4 5 9 8 7 6 i Re s ( n ) = i1(n ) + i 2( n ) Differential Protection Symposium i1(n ) + i 2( n ) n=0 n=10 Belo Horizonte November 2005 n=20 G. Ziegler, 10/2005 page 49 Differential current caused by transient CT saturation (ext. fault) with operating and restraint current of busbar protection 7SS5 I1 100 50 I2 0 50 IRes.= |I1| + |I2| IOp=|I1 +I2| Differential current appears only every second half wave! Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 50 Tripping logic of digital busbar protection 7SS600/7SS5 with saturation detector (simplified) di Re s > k s [A / ms] dt i Op > iset i Op > k ⋅ i Re s A N D A N D A N D 3 ms A N D Transient blocking Differential Protection Symposium 1-out-of-1 2 150 ms Saturation detected 3 ms Trip n=2 Adaptive restraint A N D O R Trip 2-out-of-2 Trip Belo Horizonte November 2005 G. Ziegler, 10/2005 page 51 Transformer differential protection 7UT6: Saturation detection and automatic increase stabilisation Internal faults Trip Restrain Area of add-on restraint Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 52 Transient CT saturation causes false differential currents IF IF +I1 +I2 87 I1 IF I2 +∆I ∆I Wave shape similar to transformer inrush current ? Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 53 Adaptive restraint against CT errors (7SD52/61) Detection of CT saturation (wave shape analysis) CT Error approximation (no-saturation) Error % Load range Fault range fL fF 10% ALF‘/ALFN • IN-CT Differential Protection Symposium ALF’ •IN-CT Belo Horizonte November 2005 G. Ziegler, 10/2005 page 54 Adaptive 87 restraint (7SD52/61) considers current CT- errors IDiff I1 Trip Area Trip level With saturation Block-Area IDiff> 0 0 Current summation: Trip level Without saturation I2 External Fault I2 I1 Max. error (ε) without saturation IDiff = │I1+ I2│ Max. error (ε) with saturation. IRest Max. error summation: IRestraint = ΣIError = IDiff> + εCT1 ·I1 + fSat· εCT2 ·I2 Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 55 External fault Increase of stabilisation after detection of saturation Begin of saturation ∆Ι (K1:iE = -K1:iL1) Increase of restraint I∆ IRestraint ΣΙ Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 56 Fast charge comparison supplement speeds up phasor based line differential protection (7SD52/61) Q2 Q1 iL1/kA 20 10 0 -10 -0,02 -0,01 -0,00 0,01 0,02 0,03 0,04 0,05 0,06 0,07 0,08 -0,02 -0,01 -0,00 0,01 0,02 0,03 0,04 0,05 0,06 0,07 0,08 -0,02 -0,01 -0,00 0,01 0,02 0,03 0,04 0,05 0,06 0,07 0,08 t/s -0,02 -0,01 -0,00 0,01 0,02 0,03 0,04 0,05 0,06 0,07 0,08 t/s t/s -20 -30 -40 iL2/kA 20 10 0 -10 Q3 t/s -20 -30 -40 iL3/kA 20 10 0 -10 -20 -30 Diff G-AUS Q 1/4 cycle 1 cycle data windows for phasor comparison •Synchronized with fault inception ¼ cycle data windows of fast charge comparison Differential Protection Symposium •Released by Idiff >> Belo Horizonte November 2005 G. Ziegler, 10/2005 page 57 Generator, Motor and Transformer protection: Adaptive algorithms to upgrade relay stability and dependability with CT saturation (7UT6) Measured value processing i1L i2L Side 1 Side 2 Sampled momentary values iRes = | i1 | + | i2 | iOp = i1 + i2 Mean values IRes = Mean(iRes) Fundamental wave IOp = RMS(iDiff)60Hz 87 algorithm Operating characteristic IOp IDiff> IRes. Motor start DC component & Trip IOp> Saturation detector For security: Harmonic Analysis: -2nd Harmon. Blocking -Cross Blocking Adaptive restraint IOp IDiff> > For dependability: Fast tripping using sampled momentary values ensures fast operation with very high currents before extreme CT saturation occurs! Differential Protection Symposium iOp ≥1 Trip IOp>> IDiff>>> Belo Horizonte November 2005 G. Ziegler, 10/2005 page 58 Current Transformers for Differential Relaying Requirements and Dimensioning Gerhard Ziegler Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 46 Equivalent current transformer circuit I2′ = I1 ⋅ I1 jX1 R1 N1 N2 Im P1 N1 P2 jX2 N2 U2 Ideal transformer R2 I2 S1 Zm Zb S2 X1 = Primary leakage reactance R1 = Primary winding resistance X2 = Secondary leakage reactance Z0 = Magnetising impedance R2 = Secondary winding resistance Zb = Secondary load Note: Normally the leakage fluxes X 1 and X2 can be neglected Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 47 Current transformer: Phase displacement (δ) and current ratio error (ε) w1 . I1 w 2 w1:w2 j·X2 R2 U2 I2 I1 ZB ε I2 δ I‘1= w1 ·I w2 1 Im I2 Em I1 Em R2 U2 RB Xm Differential Protection Symposium Im Im Belo Horizonte November 2005 G. Ziegler, 10/2005 page 48 Dimensioning of CTs for differential protection Pi = I sec .2 × R CT CT classes to IEC 60044-1: 5P or 10P Specification: 300/1 A 5P10, 30 VA RCT ≤ 5 Ohm Rated burden (nominal power) PN Ratio In -Prim / In -Sek. 5% accuracy at I= n x In Actual accuracy limit factor in operation is higher as the CT is normally under-burdened : Operating ALF: ALF‘ Accuracy limit factor ALF Dimension criterium: P + PN ALF ' = ALF × i Pi + PB I ALF ' ≥ SC − max × KTF In KTF (over-dimensioning factor) considers the single sided CT over-magnetising due to the d.c. component in short circuit current I SC. KTF values required in practice depend on relay type and design. Recommendations are provided by manufacturers (see Application Guide) Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 49 Current transformer, Standard for steady-state performance IEC 60044-1 specifies the following classes: Accuracy class Current error at nominal current (In) 5P ±1% 10P ± 5% Differential Protection Symposium Angle error δ at rated current In Total error at n x In (rated accuracy limit) ± 60 minutes 5% 10 % Belo Horizonte November 2005 G. Ziegler, 10/2005 page 50 Current transformers, Standard for transient performance IEC 60044-6 specifies four classes: Class Error at rated current Ratio error TPX (closed iron core) TPY with anti-remanence air-gap TPZ linear core TPS closed iron core Maximum error at rated accuracy limit Remanence Angle error ± 0,5 % ± 30 min εˆ ≤ 10 % ± 1,0 % ± 30 min εˆ ≤ 10 % ± 1,0 % ± 180 ± 18 min εˆ ≤ 10% (a.c. current only) Special version for high impedance protection (Knee point voltage, internal secondary resistance) Differential Protection Symposium Belo Horizonte November 2005 no limit < 10 % negligible No limit G. Ziegler, 10/2005 page 51 Definition of the CT knee-point voltage (BS and IEC) British Standard BS3938: Class X U2 10 % or IEC 60044-1 Amendment 2000/07: Class PX UKN 50 % Specify: Knee point voltage Secondary resistance RCT Im I U KN ≥ K TF ⋅ (R CT + R B − connected ) ⋅ SC − max . I n − CT Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 52 CT specification according to ANSI C57.13 w1 I‘1= w ·I1 2 I2 Im Em ANSI C57.13 specifies: RCT RB U2 • Secondary terminal voltage U2 at 20 times rated current (20x5=100 A) and rated burden • Error <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 Belo Horizonte November 2005 G. Ziegler, 10/2005 page 53 Current transformer saturation Steady-state saturation with a.c. current Transient saturation with offset current Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 54 CT saturation Currents and magnetising IP t φ saturation flux t IS t Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 55 Transient CT saturation due to DC component ISC Short circuit current DC flux non-saturated ΦS Φ Im Differential Protection Symposium AC flux Magnetising current Belo Horizonte November 2005 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 Φ̂ a.c. Differential Protection Symposium t K td − max = 1 + ωTp = 1 + Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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) Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium 80 100 100 0 0 0 1 2 3 4 Belo Horizonte November 2005 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 Differential Protection Symposium 60 Belo Horizonte November 2005 G. Ziegler, 10/2005 page 61 Current transformer Magnetising and de-magnetising ΙP B t B BMax BR BMax BR Ιm t Differential Protection Symposium Belo Horizonte November 2005 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 ~         Differential Protection Symposium Belo Horizonte November 2005 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) Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 64 Current transformers TPX und TPY Course of the flux with non-successful auto-reclosure BR BR tF1 tDT Differential Protection Symposium tF2 closed iron core (TPX) core with antiremanence air-gaps (TPY) t Belo Horizonte November 2005 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 Differential Protection Symposium tDT tF2 Belo Horizonte November 2005 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 Differential Protection Symposium 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 Belo Horizonte November 2005 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 Differential Protection Symposium 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 Belo Horizonte November 2005 G. Ziegler, 10/2005 page 69 CT dimensioning for differential protection (1) 1. Calculation of fault currents 110/20 kV F1 40 MVA 110 kV, 3 GVA uT=12% F2 OH-line: l = 8 km, zL‘= 0,4 Ω/km F3 Net 300/1A 7SD61 7UT61 Impedances related to 20 kV: Impedances related to 110 kV: Transf. : ∆ IL ∆ IL ∆ IT Net : 200/1A 200/1A 1200/1A F4 U N 2  kV 2    110 2 ZN = = = 4.03 Ω S SC ' ' [MVA ] 3000 Net : U N 2  kV 2    uT [% ] 110 2 12 % ZT = ⋅ = ⋅ = 36.3 Ω PN -T [MVA ] 100 40 100 Transf. : U N 2  kV 2    20 2 ZN = = = 0.13 Ω SSC ' ' [MVA ] 3000 U N 2  kV 2    uT [% ] 20 2 12 % ZT= ⋅ = ⋅ = 1.2 Ω PN - T [MVA ] 100 40 100 Line : Z L = l[km ] ⋅ z L ' [Ω/km ] = 8 ⋅ 0,4 = 3,2 Ω Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 70 CT dimensioning for differential protection (2) F1 I F1 = 1.1 ⋅ U N / 3 1.1 ⋅ 110kV/ 3 = = 17.3 kA ZN 4.03 Ω F2 I F2 = 1.1 ⋅ U N / 3 1,1 ⋅ 110kV/ 3 = = 1.73 kA Z N + ZT 4.03 Ω + 36.3 Ω F3 I F3 = F4 I F4 = 1.1 ⋅ U N / 3 1.1 ⋅ 20kV/ 3 = = 9.55 kA Z N + ZT 0.13Ω + 1.2Ω 1.1 ⋅ U N / 3 1,1 ⋅ 20kV/ 3 = = 2.8 kA Z N + Z T + Z L 0.13Ω + 1.2Ω + 3.2Ω Dimensioning of the 110 kV CTs for the transformer differential protection: Manufacturer recommends for relay 7UT61: 1) Saturation free time ≥ 4ms for internal faults 2) Over-dimensioning factor KTF ≥ 1,2 for through flowing currents (external faults) The saturation free time of 3 ms corresponds to KTF≥ 0,75 See diagram, page 59 Criterion 1) therefore reads: I 17300 ALF' ≥ K TF ⋅ F1 = 0,75 ⋅ = 43 IN 300 For criterion 2) we get: I 1730 ALF' ≥ K TF ⋅ F2 = 1,2 ⋅ =7 IN 300 The 110 kV CTs must be dimensioned according to criterion 1). Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 71 CT dimensioning for differential protection (3) We try to use a CT type: 300/1, 10 VA, 5P?, internal burden 2 VA. ALF ≥ Pi + Poperation 2 + 2.5 ⋅ ALF ' = ⋅ 43 = 16.1 (Connected burden estimated to about 2.5 VA) Pi + Prated 2 + 10 Chosen, with a security margin : 300 /1 A, 5P20, 10 VA, R2≤ 2 Ohm (Pi ≤ 2VA) Specification of the CTs at the 20 kV side of the transformer: It is good relaying practice to choose the same dimensioning as for the CTs on the 110 kV side: 1200/1, 10 VA, 5P20, R2≤ 2 Ohm (Pi ≤ 2VA) Dimensioning of the 20 kV CTs for line protection: For relay 7SD61, it is required: The saturation free time of 3 ms corresponds to KTF≥ 0.5 See diagram, page 59 Criterion 1‘) therefore reads: I 9550 ALF' ≥ K TF ⋅ F3 = 0.5 ⋅ = 24 IN 200 1‘) Saturation free time ≥ 3ms for internal faults 2‘) Over-dimensioning factor KTF ≥ 1.2 for through flowing currents (external faults) For criterion 2‘) we get: I 2800 ALF' ≥ KTF ⋅ F4 = 1.2 ⋅ = 16 .8 IN 200 The 20 kV line CTs must be dimensioned according to criterion 1‘). Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 72 CT dimensioning for differential protection (4) For the 20 kV line we have considered the CT type: 200/5 A, 5 VA, 5P?, internal burden ca. 1 VA Pi + Poperation 1+1 ⋅ ALF ' = ⋅ 24 = 8 ALF ≥ Pi + Prated 1+ 5 (Connected burden about 1 VA) Specification of line CTs: We choose the next higher standard accuracy limit factor ALF=10 : Herewith, we can specify: CT Type TPX, 200/5 A, 5 VA, 5P10, R2≤ 0.04 Ohm ( Pi≤ 1 VA) Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 73 Interposing CTs, Basic versions w1 i1 separate winding connection i2 i1 w2 wa i2 wb i1 -i2 Relay i2 = w1 ⋅ i1 w2 auto-transformer connection Relay i2 = wb ⋅ i1 wa + wb No galvanic separation! Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 74 Interposing CTs, Example 1A W1= 21 turns 600/1 A 1A 600/1 A Differential Protection Symposium 1,5 A W2= 14 turns 1A Wa=16 turns 0,5 A Wb=32 turns RB 1,5 A RB Belo Horizonte November 2005 G. Ziegler, 10/2005 page 75 Interposing CTs in Y-∆-connection Yd5 -I1c I1a I2a-c I1b I2b-a I2c-b I1c w1 I2a I1a -I1b I2c I1b I1c w1 = w2 w2 I1 = Differential Protection Symposium 150O I2b I2b I2c -I1a I2a o 1 w ⋅ I 2 ⋅ 2 ⋅ e j ⋅( n⋅30 ) w1 3 Belo Horizonte November 2005 G. Ziegler, 10/2005 page 76 False operation during external fault of transformer differential protection without zero-sequence current filter L1 L2 L3 ∆I Differential Protection Symposium ∆ I ∆I ∆I>0 without delta winding! Belo Horizonte November 2005 G. Ziegler, 10/2005 page 77 Zero-sequence current filter I1a I3a I2a I1b I3b I2b I1c I3c I2c I 1a ⋅ w1 + I 2a ⋅ ww2 + I 3a ⋅ w3 = 0 I 1b ⋅ w1 + I 2b ⋅ ww2 + I 3b ⋅ w3 = 0 I 1c ⋅ w1 + I 2c ⋅ ww2 + I 3c ⋅ w3 = 0 I 3a = I 3b = I 3c I 2a + I 2b + I 2c = 0 Differential Protection Symposium Relay I w I +I +I I 3a = I 3b = I 3c = 1 ⋅ 1a 1b 1c = E w3 3 3 I +I +I  w  I 2a = 1  I 1a − 1a 1b 1c   w2  3  I 1a + I 1b + I 1c  w1   I 2b = I −  3 w2  1b  I +I +I  w  I 2c = 1  I 1c − 1a 1b 1c   3 w2   Belo Horizonte November 2005 G. Ziegler, 10/2005 page 78 Biasing of transformer differential protection during external earth fault with zero-sequence current filter (closed delta winding) L1 L2 L3 With delta winding: ∆I=0 ! Differential Protection Symposium ∆I ∆ I ∆I Belo Horizonte November 2005 G. Ziegler, 10/2005 page 79 Current matching with interposing CTs (1) Calculation example 110 kV ±16% L1 75 / 1 A Yd5 6.3 kV 53.9A 915A 1200 / 5 A L2 L3 0.719A 3.81A ∆I 3,81 = 2,20 3 Differential Protection Symposium ∆I ∆I In-Relay = 5A Belo Horizonte November 2005 G. Ziegler, 10/2005 page 80 Current matching with interposing CTs (2) Calculation example Current transformation ratio: We take through flowing rated current as reference: : 110kV-side: Mean current value of upper and lower tap changer position: I1 = 10,000kVA = 45.2A 3 ⋅ (110kV + 16% 6 kV-side: I2 = 10,000kVA = 62.5A 3 ⋅ (110kV − 16% I1' = I1− mean = 45.2 + 62.5 = 53.9A 2 10.000kVA = 915A 3 ⋅ 6.3kV The corresponding secondary currents are: i1 = 53 . 9 ⋅ 1 = 0 . 719 A 75 and i 2 = 915 ⋅ 5 = 3.813 1200 . The current in the star connected winding of the interposing transformer is The current in the delta connected winding is: i.1 i2 / 3 . The ratio of the interposing CT must be : w1 i 2 / 3 3.813 / 3 2.202 = = = = 3.06 w2 i1 0.719 0.719 Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 81 Link selectable interposing CT 4AM5170-7AA P1 S1 i2 A B C DE 1 0,013 2 F G H I 7 0,025 0,08 S2 P2 i1 K L M N O P Q 16 1 2 7 16 Windings 0,75 0,013 0,025 0,08 0,75 R in Ohm 2 4 14 32 2 4 14 32 U-max. in V 5 5 5 1 5 5 5 1 Rated current in A w1 i2 / 3 3,813 / 3 2, 202 = = = = 3.06 w2 i1 0,719 0,719 chosen : w1 16 + 16 + 2 34 = = = 3,09 w 2 7 + 2 + 1 + 1 11 Connection and links as shown. Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 82 Designation of transformer or CT vector groups (1) Clock-wise notation according to IEC 60076-1 11 12 0 1 0 2 10 9 3 8 4 7 6 4 8 0 6 0 6 4 1 0 4 1 0 8 2 8 2 5 9 1 (13) 5 Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 83 Designation of transformer or CT vector groups (2) Clock-wise notation according to IEC 60076-1, examples I II III 12 I II 12 III I I III II III II HS I I II III NS II 12 III 11 12 I III II I III II I II III Dyn11 12 II III I 5 Yny0d5 Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 84 Frequently used vector groups (IEC 60076-1) Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 85 Finding the vector group by using the clock principle Proceed in the following steps: 1. Starting on the high voltage winding, the phase connection terminals are numbered with 0, 4, 8 (always 4 x 30 O= 120O phase shift). 2. The opposite end of each winding is labelled with a number incremented by +6 relative to the phase connection (6x 30 O =180O). 3. The secondary windings are numbered the same. In this context it is assumed that the polarity of the windings is the same in the diagram. (If in doubt, polarity marks may also be applied.) 4. The phase connection is labelled with the average value of the corresponding terminal designations belonging to the winding terminals connected to this phase terminal, e.g. (6+4)/2= 5 5. The difference between the high and low voltage side terminal numbers of same phases corresponds each with the vector group number, being Yd5 in this case. Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 86 Checking the connections of transformer differential protection using the clock-wise notation method Yd5 L1 L2 L3 6 0 10 4 2 0 6 0 6 5 4 10 4 10 9 5 11 8 2 8 2 1 9 3 1 7 8 6 12 6 12 11 10 4 8 10 4 3 2 8 7 2 Yd5 Differential Protection Symposium ∆I ∆I ∆I Belo Horizonte November 2005 G. Ziegler, 10/2005 page 87 Current distribution in Y-∆-transformer circuits for different external fault types 3 1 3 G G G 3 1 Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 88 Checking the connections of transformer differential protection using the arrow method (two-phase fault) Yd5 1 3 L1 3 L2 L3 3 3 = 3 3 ∆I ∆I Differential Protection Symposium ∆I 3 Dy5 Belo Horizonte November 2005 G. Ziegler, 10/2005 page 89 Checking the connections of transformer differential protection using the arrow method (single-phase earth fault) Yd5 1 L1 L2 L3 ∆I ∆I Differential Protection Symposium ∆I 3 Dy5 3 Belo Horizonte November 2005 G. Ziegler, 10/2005 page 90 Digital Differential Protection Communications Gerhard Ziegler Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 87 Comparison protection Absolute selectivity by using communication IA A IB B • Directial comparison distance protection Exchange of YES/NO signals (e.g. fault forward / reverse) • Current comparison (phasors) differential protection Protection Relay Communication samples, phasors, binary signals | ∆I | Protection Relay IA IB | ∆I | = | IA - IB | > Ipick-up Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 88 Signal transmission channels for differential relaying Pilot wires - AC (50/60 Hz), voice frequency and digital communication (128 - kbit/s) - for short distances (< about 20 km) - influenced by earth short-circuit currents! Optical fibres - wide-band communication (n · 64 kbit/s) - digital signal transmission (PCM) - up to about 150 km without repeater stations - noise proof Digital microwave channels 2 - 10 GHz - wide-band communication (n · 64 kbit/s) - digital signal transmission (PCM) - up to about 50 km (sight connection) - dependent on weather conditions (fading) Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 89 Analog pilot wire differential relaying 3 3 87L 87L • Pilot wires are normally operated insulated form earth • Voltage limiters (glow dischargers) connected to earth , as used with telephone lines, are not allowed! Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 90 Relay-to-Relay pilot wires communication New technology on existing (copper-) pilots Traditional: Composed current measurement Comparison of analogue values Modern: E O O E Phase segregated measurement Digital data transmission 64 kbps bi-directional 4 value digital code (2B1Q) Amplitude and phase modulation Spectrum mid frequency: 80 kHz Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 91 Wire pilot cables Longitudinal voltage induced by earth currents Relay B Relay A G IF Φ E F1 E/2 F2 Differential Protection Symposium A) Symmetrical coupling along the pilot cable E/2 F2 F1 E Belo Horizonte November 2005 B) Unsymmetrical Coupling along the pilot cable G. Ziegler, 10/2005 page 92 Disturbance voltage caused by rise in station potential RG STP STP E Ω = I SC − G ⋅ R G PGA RGP Legend: RG STP PGA RGP E station grounding resistance station potential potential gradient area remote ground potential station potential rise against remote ground (ohmic coupled disturbance voltage ) Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 93 HV insulated protection pilot cable (example) core diameter pilot resistance Core Loop pilot capacitance mm Ω/km Ω/km nF/km 1,4 0,8 11,9 --- --73,2 --60 test voltage (r.m.s. value) triple pair pair to core- coretriple to core core shield core pair to triple core kV kV kV kV kV 2,5 8 8 8 2 2 2 Symmetry: better 10–3 (60 db) at 800/1000 Hz better 10–4 (80 db) at 50/60 Hz (Uq <10–4·Ul) Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 94 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 Differential Protection Symposium potential of the pilot wires Belo Horizonte November 2005 potential of the remote earth G. Ziegler, 10/2005 page 95 Optic fibre (OF) Cable Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 96 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 Differential Protection Symposium 10 µm 125 µm 250 µm Belo Horizonte November 2005 G. Ziegler, 10/2005 page 97 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 Differential Protection Symposium Belo Horizonte November 2005 Output impulse G. Ziegler, 10/2005 page 98 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) Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 99 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 Belo Horizonte November 2005 G. Ziegler, 10/2005 page 100 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 Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 101 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 Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 102 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) Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 103 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 Differential Protection Symposium coding base band transmission Belo Horizonte November 2005 G. Ziegler, 10/2005 page 104 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 Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 105 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 Differential Protection Symposium Information Field any length Belo Horizonte November 2005 Frame Check FCS Closing Flag 16 or 32 bits 01111110 G. Ziegler, 10/2005 page 106 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 Differential Protection Symposium Clock Belo Horizonte November 2005 G. Ziegler, 10/2005 page 107 Communication through transmission networks M U X A User / Source Modem Network node circuit / packet switching trunk Modem Station user terminal point M U X line Transmission path B loop Differential Protection Symposium User / Destination Belo Horizonte November 2005 G. Ziegler, 10/2005 page 108 Structure of a modern data communication network 622 Gbit/s ØNetworks are plesiochronous (PDH), synchronous (SDH) or asynchronous (ATM) ØData terminal devices (e.g. relays) are synchronised through the network ØRings guarantee redundance. ØData of different services (e.g. telephone and protection are commonly transmitted (time multiplexed) ØProtection relays must be adapted to the given network conditions (e.g. changing propagation time due to path witching. 622 Gbit/s POTS: Plain Old Telephone Services ISDN: Integrated Services Digital Network STM-n: Synchronous Transport Module level n SMA: Synchronous Module Access ATM: Asynchronous Transmission Mode ISP: Internet Service Provider Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 109 Comparison of Switching Methods Circuit Switching Packet switching The physically assigned channel is established before and disconnected after communication Data stream is segmented to packets POT (Plain old telephony), ISDN Digital networks on basis of PCM with plesiochronous digital hierarchy (PDH) Reliable and fast transmission possible when connection is established. Circuit establishment requires a free channel from A to B Connection occupies channel also when no data is exchanged Deterministic data transmission (fixed data transmission time per channel) Differential Protection Symposium Transmission runs connection-oriented or connection-less Synchronous digital hierarchy (SDH), ATM Backbone Cannel not occupied during whole connection time Channels can be used quasi-simultaneously Data transmission by principle time is random. SDH and ATM can provide virtual circuitswitched channels. However, split path signal routing may however result in unsymmetrical signal transmission times. Belo Horizonte November 2005 G. Ziegler, 10/2005 page 110 SDH network: Split path routing Node F Node E Node D Standby path Node A tP2‘ Node B Relay End 1 Differential Protection Symposium tP1 Node C tP1‘ tP2 Healthy path Relay End 2 Belo Horizonte November 2005 G. Ziegler, 10/2005 page 111 Digital Transport Systems: Bundling of channels PCM 7680 PDH Hierarchy PCM 1920 Plesiochronous (almost synchronous) PCM 480 PCM 120 PCM 30 M U X M U X M U X M U X M U X 565 Mbit/s 140 Mbit/s 32 Mbit/s 8 Mbit/s 2 Mbit/s 64 kbit/s SDH Hierarchy Synchronous SMT-1 155 Mbit/s SMT-4 622 Mbit/s 1 SMT-16 2.5 Gbit/s 1 2 1 2 2 3 3 3 4 Differential Protection Symposium SMT-64 10 Gbit/s 1 4 4 Belo Horizonte November 2005 G. Ziegler, 10/2005 page 112 PDH (Plesiochronous Digital Hierarchy) Multiplexing structure: ØBase rate 64 kbit/s (digital equivalent of analogue telephone channel) ØEquipments may generate slightly different bit rates due to independent internal clocks ØBit stuffing is used to bring individual signals up to the same rate prior to multiplexing (Dummy bits are inserted at the sending side and removed at the receiving side) ØIntermediate inserting and extracting of individual channels is not possible, but the full multiplexing range has always to be run through. Hierarchical level 0 1 2 3 4 Europe 64 kbit/s 2‘048 Mbit/s 8‘448 Mbit/s 34‘368 Mbit/s 139‘264 Mbit/s Differential Protection Symposium USA 56 kbit/s 1‘544 Mbit/s 6‘312 Mbit/s 44‘736 Mbit/s 139‘264 Mbit/s Belo Horizonte November 2005 G. Ziegler, 10/2005 page 113 SDH (Synchronous Digital Hierarchy) Multiplexing structure Ø SONET (Synchronous Optical Network) first appeared in USA (1985) Ø ITU-T (formerly CCITT) issued B-ISDN as world wide standard (1988) Ø All multiplexing functions operate synchronously using clocks derived from a common source Ø Designed to carry also future ATM SDH STM level STM-1 STM-4 SZM-16 STM-64 Aggregate Rate 155,520 Mbit/s 622,080 Mbit/s 2‘488,320 Mbit/s 9‘953,280 Mbit/s Differential Protection Symposium SONET OC level STS level Aggregate Rate OC-1 OC-3 OC-12 OC-48 OC-192 STS-1 STS-3 STS-12 STS-48 STS-192 51,840 Mbit/s 155,520 Mbit/s 622,080 Mbit/s 2‘488,320 Mbit/s 9‘953,280 Mbit/s Belo Horizonte November 2005 G. Ziegler, 10/2005 page 114 ATM (Asynchronous Transfer Mode) and Broadband B-ISDN Features of ATM: Ø Synchronisation individually per packet Voice Audio Fax Data Video Ø Packets carry each complete address of destination so that each can be separately delivered (Datagrams, here called Cells) Ø Information stream is segmented into cells that are 53 octets long Ø ATM sets up a virtual switched connection and sends data along a switched path from source to destination ISDN Ø Requirements on bandwidth, bounded delay and delay variation can be set by the user ØSingle cells can be inserted or removed at the nodes, as required Ø The predominant use is for net backbones Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 115 TDM over optical fiber Hicom FO MUX >2 Mbit/s L1-L2 21,3 KA 73,6 kW I O Optic fibres in the core of earth wires x 64 kbit/s V Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 116 Bit error rate (of data channels) Bit error rate: p= number of faulty bits total number of sent bits Typical bit error rates of public services: Telephone circuits ca. 10 -5 Digital data networks (Germany) ca. 10 -6 to 10-7 Coaxial cables (LAN) ca. 10 -9 Fiber optic communication ca. 10 -12 Utility conditions (CIGRE SC34 Report 2001): Fiber optic communication ca. 10 -6 Data networks (PDH, SDH, ATM) ca. 10-6 Microwave ca. 10 -3 Requirements acc. to CIGRE report: Protection and control in general: < 10-6 Function guaranteed up to < 10 -3 however downgraded (reduced operating speed) Line differential protection < 10 -6 and < 10-5 during power system faults Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 117 Error detection methods: Cyclic redundancy check 01111110 Flag 01111110 Address Control I(x) Data field Check field Flag I(x) + R(x) Receiver Sender Division by G(x) R(x) = CRC error free data block CRC 16: G(x) = X16 + X15 + X2 + 1 binary: 1 1000 0000 0000 0101 Reduction of the block failure rate by the factor > 10 -5 against the bit failure rate! (CRC 32: > 10-10) Differential Protection Symposium Division by G(x) R(x) = 0 faulty data block Belo Horizonte November 2005 G. Ziegler, 10/2005 page 118 Data integrity (line differential protection 7SD52/61) Received data Block failure rate P = 10-5 Error detection e.g. CRC = 32 Residual data Block failure rate R = 10-15 Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 119 Residual error rate Residual error rate: R= number of not detected faulty telegrams (data blocks) total number of sent telegrams (data blocks) Practical range of protection and control systems: Time between 2 not detected errors: T= R < 10 -10 to 10-15 n v⋅R n= length of telegram (data block) v= transmission speed in bit/s Example: Telegrams of n =200 bit are continuously transmitted at 64 kbit/s. R T 10-7 20 hours 10-10 2.3 years 10-15 230000 years typical application cyclic transmission (metering) remote control and protection Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 120 Protection of a short line lines Differential relay using direct digital relay-to-relay communication A B D 7SA6 D 7SA6 Communication via direct relay-relay connection Fibre type optical wave length maximum attenuation permissible distance Multi-mode 62.5/125 µm 820 nm 16 dB ca. 3.5 km Monomode 9/ 125 µm 1300 nm 29 dB ca. 60 km 9/ 125 µm 1500 nm 29 dB ca. 100 km Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 121 Line differential relaying using digital communication A B D 7SD52 D 7SD52 D 7SD52 Chain topology or redundant ring topology typical <1.5 km multimode fibre 62.5/ 9/ 125 µm C O Communication network E X21 or G703.1 Differential Protection Symposium O E Communication converter X21 or G703.1 Belo Horizonte November 2005 G. Ziegler, 10/2005 page 122 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 Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 123 Individual time references by synchro-phasors Definition of a synchrosynchro-phasor: phasor: SynchroSynchro-phasors, phasors, are phasors, phasors, which are measured at different network locations by independent devices and referred to a common time basis Time reference iB iA Ort : A Ort : B IM IA relay A RE IB relay B Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 124 Phasor synchronisation between line ends A tA1 tA2 ∆I ∆I curre n phas t o rs tAR tA5 B α ... tA1 tPT1 tB2 tBR α= tB3 tPT2 ... tV tB3 tA1 nt curre rs ph aso Signal transmission time: Sampling instant: Differential Protection Symposium IB( tB3 ) tB1 tD tA3 tA4 IB( tA3 ) t B3 - t A3 ⋅ 360 ° TP tB4 t PT1 = t PT2 = 1 (t A1 - t AR - t D ) 2 t B3 = t AR - tTP2 Belo Horizonte November 2005 G. Ziegler, 10/2005 page 125 Specification of data channel for line differential protection based on Cigre Report: Protection using Telecommunication *) Data rate 64 kbit/s (min.) Channel delay time: < 5 ms Channel delay time unsymmetry: < 0.2 ms Bit error rate normal: < 10 -6 during power system fault Availability: < 10-5 *) > 99.99 % *) Report of WG34/35.11, Brochure REF. 192, Cigre Central Office, Paris, 2001, *) It is suggested that for a BER of less than 10-6 the dependability shall not suffer a noticeable deterioration . For a BER of 10-6 to 10-3 the teleprotection may still able to perform its function although a loss in dependability is to be expected. Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 126 Digital Protection of Generators and Motors Gerhard Ziegler Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 Seite 116 Generator differential protection a a c S S S A IA/In 3 2 S S A 1 S A Connection circuit Differential Protection Symposium 1 2 3 4 5 6 IS/In Operating characteristic Belo Horizonte November 2005 G. Ziegler, 10/2005 Seite 117 Generator HI differential protection a b c A Differential Protection Symposium A A Belo Horizonte November 2005 G. Ziegler, 10/2005 Seite 118 Transverse differential protection a b c S S S S S A Differential Protection Symposium A S A Belo Horizonte November 2005 G. Ziegler, 10/2005 Seite 119 HI earth current differential protection L1 L2 L3 ∆IE> Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 Seite 120 Earth current differential protection for generators L1 L2 L3 U0> ∆IE> Tripping Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 Seite 121 Motor starting current 20 IRush /IN TRush 15 Tst 10 Ist/IN 5 0 5 0 50 100 150 200 250 300 tst (ms) Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 Seite 122 Transformer Differential Protection Gerhard Ziegler Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 123 Transformer: Function principle and equivalent circuits I1 w1 w2 I2 U1 Xσ1 R1 Φ U2 Φ σ1 Φ σ2 U1 I1 I ⋅ w + I ⋅ w = I µ ⋅ w1 1 1 2 2 I µ << I 1, 2 ' Differential Protection Symposium 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' Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 128 Inrush currents of a three-phase transformer recorded with relay 7UT51 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium t XS Belo Horizonte November 2005 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 Differential Protection Symposium 10 100 120 20 ms % 160 140 U/Un t Belo Horizonte November 2005 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 Differential Protection Symposium 87T 87T Belo Horizonte November 2005 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 Differential Protection Symposium ap ap an 30O bn an Belo Horizonte November 2005 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 Differential Protection Symposium G 87T 87T Belo Horizonte November 2005 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 Differential Protection Symposium 87T 87T Ø Sensitivity only 2/3 I F! Ø Non-selective fault indication! Belo Horizonte November 2005 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 Differential Protection Symposium 87T 87T Belo Horizonte November 2005 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 Differential Protection Symposium 87T 87T Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium 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 Belo Horizonte November 2005 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 * Differential Protection Symposium It ** Ir ** −1 0 1 1 Is ** = 1 −1 0 ⋅ 3 0 1 −1 It * * Belo Horizonte November 2005 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? Differential Protection Symposium U max ⋅ U min U max + U min Belo Horizonte November 2005 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 Differential Protection Symposium ∆I Belo Horizonte November 2005 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 * * = Differential Protection Symposium 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 Belo Horizonte November 2005 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 <k_Wan_n <1/8 345 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) Differential Protection Symposium k CT _ 3* = 8,786 = 1,76 < 4! 5 Belo Horizonte November 2005 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 Differential Protection Symposium 0,099% Belo Horizonte November 2005 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 Differential Protection Symposium 4 5 6 7 8 9 10 Belo Horizonte November 2005 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. Differential Protection Symposium Belo Horizonte November 2005 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) Differential Protection Symposium Belo Horizonte November 2005 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) Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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. Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 153 Transformer HI-earth fault protection IR Ir IS Is IT It ZE ∆IE> Differential Protection Symposium IN ∆IE> Belo Horizonte November 2005 G. Ziegler, 10/2005 page 154 HI differential protection of an autotransformer Ir IR Is IS It IT 87 Differential Protection Symposium 87 87 Belo Horizonte November 2005 G. Ziegler, 10/2005 page 155 HI earth fault protection of an autotransformer Ir IR Is IS It IT IN ∆I> Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 156 Transformer tank protection 64T: Principle IE> Insulated Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium (1/3 x 19’’ case 7XP20) (1/2 x 19’’ case 7XP20) (1/1 x 19’’ case 7XP20) (1/1 x 19’’ case 7XP20) Belo Horizonte November 2005 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 Differential Protection Symposium Binary inputs for tripping commands Belo Horizonte November 2005 G. Ziegler, 10/2005 page 159 Application range (7UT6) ∆ ∆I ∆I Shunt Reactor G Three winding transformer Two winding transformer ∆I Generator / Motor Differential Protection Symposium ∆I ∆I Transformer bank (1-1/2-LS) ∆I ∆I Busbars Belo Horizonte November 2005 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) Differential Protection Symposium I>>, I>t ∆ITE ∆IT Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium 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 Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 167 7UT6: Commissioning and service tool (3) Display of operating/restraint state Transformer YNd11d11, 110/11/11kV, 38.1MVA, IL2S2à wrong polarity Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 168 Application examples Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium 52 51 52 Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium 52 W2 52 Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium 7SA6 21 51N 49 51 BF 7SJ6 Belo Horizonte November 2005 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 Differential Protection Symposium 51N Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 ∆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 Differential Protection Symposium Auxiliaries Belo Horizonte November 2005 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 Differential Protection Symposium EB 7UT61 Fault F2: uncritical as current is limited by short-circuit impedance of station-service transformer T2. CT Ž can have normal dimensions Belo Horizonte November 2005 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 Differential Protection Course 1 2 3 2 ∆ ∆ ∆ PTD Service Power Training Center 3 Nürnberg 2005 G. Ziegler, 5/2005 page 2 Copyright © SIEMENS AG PTD SE 2002. All rights reserved. Transformer differential protection with I0-correction Internal fault L3 L1 L2 L2 L3 L1 Yd5 3 3 3 L1 L2 L3 1 3 1:3 1 I0-correction Differential Protection Course Vector group adaptation 1 1 3 2 ∆ ∆ ∆ PTD Service Power Training Center 3 Nürnberg 2005 G. Ziegler, 5/2005 page 3 Copyright © SIEMENS AG PTD SE 2002. All rights reserved. Digital Line Differential Protection Gerhard Ziegler Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium Barrier transformer 20 kV (optional) Belo Horizonte November 2005 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 Differential Protection Symposium Interface to data network: X.21 or G.703.1 (wired connection) Belo Horizonte November 2005 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 Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium 87T 50/51 50 BF 7SD61 Belo Horizonte November 2005 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 Differential Protection Symposium ALF’ •IN-CT Example: 10P10, fL < 3%, fF = 10% at ALF‘•IN-CT Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 3 relays 21 ms 16 ms 14 ms Differential Protection Symposium 6 relays 41 ms 24 ms 17 ms Trip Area Restrain Area QDiff>> Settable pick-up value 0 Belo Horizonte November 2005 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 Differential Protection Symposium Bus width Communication Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium Allows low setting of 87 pick-up! Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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! Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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. Differential Protection Symposium Belo Horizonte November 2005 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) − Differential Protection Symposium − + + − − + Sign.{ ∆i2 } Belo Horizonte November 2005 + 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 − Differential Protection Symposium − + + − − Full coincidence Tripping External fault + Tripping Internal fault, Belo Horizonte November 2005 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 Differential Protection Symposium -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 Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium ∼ ZV2 UFL Belo Horizonte November 2005 G. Ziegler, 10/2005 page 210 Digital Busbar Protection Gerhard Ziegler Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 218 Part-digital Busbar protection 7SS6 4AM 3 3 2 1 ΣI 100mA∼ /IN 3 n 7SD601 = 7TM70 Differential Protection Symposium ΣI = 1,9 mA= /IN Belo Horizonte November 2005 G. Ziegler, 10/2005 page 219 7SS6: Operating characteristic IA Internal faults (k=1) Relay characteristic k= 0.25 to 0.8 Id > IS Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 220 Isolator replica, Principle, (stabilising circuit not shown) BB 1 + 1 _ + 2 + k _ _ BB 2 + _ _ _ + + ∆I1 ∆I2 _ Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 221 Decentralised BB-protection 7SS52, Structure Optic fibre-communication - HDLC protocol - 1,2 MBaud Wired connections Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 223 7SS50/52: Acquisition and supervision of isolator positions Connection to central unit OF + Differential Protection Symposium Belo Horizonte November 2005 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< Differential Protection Symposium IRes Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 228 7SS52: Special treatment of dead zone faults (1) BB-A BB-B Differential Protection Symposium 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) Belo Horizonte November 2005 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. Differential Protection Symposium Belo Horizonte November 2005 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. Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 231 7SS52: Treatment of switch onto a faulted (earthed) bus BB-A BB-B Differential Protection Symposium 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. Belo Horizonte November 2005 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 Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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– Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 235 Adaptive measurement (Booster circuit) (7SS5) Odd Samples Even Samples dI S dt dI S dt 1 ms Differential Protection Symposium dI S dt Check zone Belo Horizonte November 2005 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 Differential Protection Symposium 20 1 0.5 0.5 1 1.5 Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 x ∫ Î 2F sinx ⋅ dt = ALF'⋅Î 2N ⋅ o O 180 ∫ sinx ⋅ dt = ALF'⋅Î2N ⋅ 2 o Differential Protection Symposium I 2F 2 = ALF'⋅ x I 2N sinx ∫ I I 2 k OB = 2F 2N = x ALF' sinx o Belo Horizonte November 2005 ∫ 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 Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 240 Digital busbar protection 7SS5, Measuring technique External fault, fault current with DC offset I1 I2 2 2 I1 IOp= |I1+I2| 0 20 40 1 60 0 20 0 20 40 60 40 60 40 60 2 I2 0 20 40 60 k·IRes =k·(|I1|+|I2|) 1 2 t 2 IRes=|I1|+|I2| 1 ∆I=IOp - IRes 1 0 20 1 0 20 40 Differential Protection Symposium 60 2 Belo Horizonte November 2005 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 Differential Protection Symposium 20 Tripping! Belo Horizonte November 2005 G. Ziegler, 10/2005 page 242 CT dimensioning for busbar protection 7SS5, Example (1) 25 ⋅ 106 I N −T = = 1440A 10 ⋅103 ⋅ 3 110kV SSC‘‘= 4 GVA 110/10 kV 25 MVA uT= 14% TT= 60 ms G 1500/1 2MW 600/1 300/1 150/1 5MW 10 kV 10 MVA Xd‘‘= 15% TG= 100 ms 300/1 300/1 ISt= 6·IN Xd‘‘= 17% TM= 35 ms M M 5MW 5MW Differential Protection Symposium I N −G = 10 ⋅10 6 = 577A 3 10 ⋅ 10 ⋅ 3 5 ⋅10 6 ΣI N − M -HV = 2 ⋅ = 577A 3 10 ⋅ 10 ⋅ 3 IF−T = 1.1 ⋅ 1440 = 11.3 kA 0.14 IF−G = 1.1 ⋅ 577 = 4.2 kA 0.15 ΣI F − M = Belo Horizonte November 2005 1.1 ⋅ 577 = 3.7 kA 0.17 G. Ziegler, 10/2005 page 243 CT dimensioning for busbar protection 7SS5 and 7SS6, Example (2) As worst case, the CT 150/1 A in bay 1 is considered. Total fault current with a fault at the transformer HV terminals: ΣI F = I F − T + I F − G + ΣI F − M = 11,3 + 4,2 + 3,7 = 19,2 kA Equivalent time constant: I ⋅ T + I F − G ⋅ TG + ΣI F − M ⋅ TM 11.3 ⋅ 60 + 4.2 ⋅ 100 + 3.7 ⋅ 35 TEquiv. = F − T T = = 64 ms I F − T + I F − G + ΣI F − M 11.3 + 4.2 + 3.7 We consider a CT type 5P?, 30 VA, internal burden Pi= 15% (4.5 VA): Connected burden Pa= 1 VA CT over-dimensioning factor for 3ms saturation free time: KTF ca. 0.45 Corresponding to an overburdening factor of kOB= 1/KTF = 2.2 Checking of the k-setting (Stability with symmetrical fault currents): ALF ' = ΣI F I N − CT ⋅ K TF = 19 .200 ⋅ 0 . 45 = 58 150 k> k OB 4 ⋅ kOB − 1 ALF = = 2,2 = 0 .5 (chosen: k=0.6) 4 ⋅ (2 .2 − 1) Pa + Pi 1 + 4.5 ⋅ ALF ' = ⋅ 58 = 9.3 PN + Pi 30 + 4.5 We finally choose: CT 5P10, 150/1, 30 VA, R2≤ 4.5 Ohm Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 244 Transient performance of iron closed CT cores (type TPX) Over-dimensioning factor KTF for short time to saturation 1.5 1.5 KTF 1.4 TM 1.3 KTF 1.4 1.2 1.2 5 ms 1.1 1.1 1 1 0.9 0.9 0.8 4 ms 0.7 0.5 0.5 3 ms 0.3 0.2 0.2 0.1 0.1 10 20 30 40 50 60 70 80 90 100 3 ms 0.4 0.3 0 4 ms 0.7 0.6 0.4 5 ms 0.8 0.6 0 TM 1.3 0 0 1 2 3 4 6 7 8 9 10 TN TN Differential Protection Symposium 5 Belo Horizonte November 2005 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 Differential Protection Symposium IR Belo Horizonte November 2005 G. Ziegler, 10/2005 page 246 HI busbar protection, calculation example RL= 3 Ohm (max.) IR=20 mA (fixed value) RRV = 10 kOhm RRS = 250 Ohm Iv = 50 mA (at relay pick-up voltage) Given: :n = 8 feeders rCT = 600/1 A UKN = 500 V RCT = 4 Ohm ImR = 30 mA (at relay pick-up voltage) Primary pick-up current: I F − min = rCT ⋅ (I R + IS + I V + n ⋅ I mR I F − min = Stability with external faults: ) I F − through − max < rCT ⋅ 600 ⋅ (0.02 + 0.89 + 0.05 + 8 ⋅ 0.03 ) 1 I F − min = 666A ⋅ (111%I N − CT ) Differential Protection Symposium I F − through − max < RR ⋅ IR R L + R CT 600 10.000 ⋅ ⋅ 0.02 1 3+ 4 I F − through − max < 17 kA = 28 ⋅ I n Belo Horizonte November 2005 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 Differential Protection Symposium 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 Differential Protection Symposium 3 3⋅ 3 = 0,57 Fault L2-E IOp IL3 = k=0.5 |IM-L| IRes Load Belo Horizonte November 2005 IRes G. Ziegler, 10/2005 page 249 Differential Protection 7UT6 Remarkable Features Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium (1/3 x 19’’ case 7XP20) (1/2 x 19’’ case 7XP20) (1/1 x 19’’ case 7XP20) (1/1 x 19’’ case 7XP20) Belo Horizonte November 2005 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 Differential Protection Symposium Belo Horizonte November 2005 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 Differential Protection Symposium ANSI No. Binary inputs for tripping commands Belo Horizonte November 2005 G. Ziegler, 5/2005 page 251 7UT6: Application (1) ∆ ∆I ∆I Shunt Reactor G Three winding transformer Two winding transformer ∆I Generator / Motor Differential Protection Symposium ∆I ∆I Transformer bank (1-1/2-LS) ∆I ∆I Busbars Belo Horizonte November 2005 G. Ziegler, 5/2005 page 252 7UT6: Application Generation Unit protection (overall differential) Y ∆ (2) HI restricted earth fault protection 7UT6xx 7UT635 G 3~ Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 5/2005 page 253 7UT6: selectable: I0-correction or restricted earth fault protection YN yn0 d5 R S T 49 (1) 49 (2) 50 51 ∆ITE ∆IT 7UT613 Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 5/2005 page 254 7UT6: operating characteristic Idiff >> 7 Locus of internal faults 6 I Op In 45° 5 S operate e2 p lo restrain 4 *) 3 2 Idiff > 1 e1 p o l S 0 0 2 supplementary restraint 4 6 8 10 12 14 16 IRes *) Slope of add on characteristic: In 7UT6 à as slope 1 (7UT5 à ½ of slope 1) Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 5/2005 page 255 7UT6: Effect of supplementary restraint in case of CT saturation Restrain 45° Trip Area of add-on restraint Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 5/2005 page 256 Differential protection functions IDiff> and IDiff>> Sampled momentary values Measuring value processing i1L iRes = |i1|+ |i2| Side 1 i2L iOp = i1 + i2 Side 2 Average value IStab = iRest Fundamental wave: IDiff = Eff(iDiff)50Hz Operating characteristic, Saturation detector IDiff IDiff> IStab & Trip IDiff> ≥1 Trip IDiff>> Motor start, DCcomonent Harmonic Analysis: -2nd Harmon. Blocking -Cross Blocking iRes IRes IDiff IDiff IDiff>> I / InO I / InO iDiff ms iDiff 2·IDiff>> ms Fast tripping using sampled momentary values ensures dependable operation in case of extreme CT saturation! Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 5/2005 page 257 7SA6: Temperature monitoring RS485 Interface 7XV5662-(x)AD10 7XV5662-(x)AD10 Two thermo-devices can be connected to the serial service interface (RS485) Monitoring of up to 12 measuring points (6 per thermo-device) - each with two pick-up levels Display of the measured temperatures - directly at the thermo-device (which can also be used stand alone) - at the relay One input is reserved for hot spot monitoring (measurement of oil temperature) Thermistors: Pt100, Ni100 or Ni120 Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 5/2005 page 258 7UT6: Temperature monitoring with hot spot calculation (1) Example: Natural cooling Θ h = Θ O + H gr ⋅ k Y Θh= hot spot temperature Θh= oil temperature Hgr=hot-spot-to-oil temperature gradient k= load factor I/In Y= winding exponent Aging rate: Oil Temp. HV LV Aging at Θh V= = 2(Θ h −98)/6 Aging at 98°C 98O is reference for the aging of Cellulose insulation Mean value of aging during a fixed time interval: T 2 1 L= ⋅ ∫ V ⋅ dt T2 − T1 T1 Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 5/2005 page 259 7UT6: Temperature monitoring with hot spot calculation (1) Example: Natural cooling Θ h = Θ o + H gr ⋅ k Y ≈ 73 + 23 ⋅1.151.6 = 102°C (L) V = 2(Θ h −98)/6 = 2(102−98)/6 ≈ 1.6 108°C k, V, L 98°C 102°C 73°C Θh Hot spot temp. Θo oil temp. (from thermodevice) [°C] Θh Θo 1.6 k (I/In) V (relative aging) L (mean value of V) 1.15 t Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 5/2005 page 260 7UT6: Commissioning und service tool (1) WEB-Technology Access to WEB Browser Help system in the INTRANET / INTERNET http://www.siprotec.com Relay homepage address of : http://141.141.255.160 IP-address can be set with program DIGSI 4 at the front or service interface of the relay 1. Serial connection Directy or with modem to standard DIAL-UP network 2. HTM L page view at IP-address of the relay http://141.141.255.160 Differential Protection Symposium WEB server in relay firmware Server sends HTML pages and JAVA code to WEB Browser via DIAL-UP connection Belo Horizonte November 2005 G. Ziegler, 5/2005 page 261 7UT6: Commissioning and service tool (2) Current phasors of all terminals can be displayed Transformer YNd11d11, 110/11/11kV, 38.1MVA, IL2S2à wrong polarity Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 5/2005 page 262 7UT6: Commissioning and service tool (3) Operating/restraint position can be displayed Transformer YNd11d11, 110/11/11kV, 38.1MVA, IL2S2à wrong Polarität Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 5/2005 page 263 Power Transmission and Distribution Differential Protection (7UT) Determination of the Transformer Vector Group Transformer with Vector Group Yy0 7UT612 80 MVA Yy0 2500A/1A 20 kV 110 kV 500A/1A PTD PA13 N. M Tests 7UT 05/03 No. 2 Method of Vector Group Determination (ExampleYy0) IL1,S2 Side 2: Side 1: 2L1 1L1 IL1,S1 2L2 1L2 2L3 1L3 IL1,S2 = IL1 UL1,S1 UL1,S2 IL1,S1 UL3,S2 UL2,S2 UL3,S1 UL2,S1 0° Vector group is Yy0 PTD PA13 N. M Tests 7UT 05/03 No. 3 Transformer Protection 7UT612 80 MVA Yd11 2500A/1A 20 kV 110 kV 500A/1A PTD PA13 N. M Tests 7UT 05/03 No. 4 Method of Vector Group Determination (ExampleYd11) IL1,S2 Side 2: Side 1: 2L1 IL1,S1 2L2 1L1 1L2 2L3 1L3 IL1,S2 = IL1 - IL2 IL1,S1 UL1,S1 UL1,S2 UL2,S2 UL3,S1 UL2,S1 UL3,S2 Vector group is Y d 11 330° (n * 30°) PTD PA13 N. M Tests 7UT 05/03 No. 5 Definitions in SIPROTEC 4 Relays Vector definition to a node is positive The shown vectors or phase angles are transformed in this positive definition The phase angle is displayed mathematics positive. The reference phase is always phase L1 on side 1 How to see the vector group Yd11? Original Siprotec 4 (Browser) Phase angles Side 1: 0° (reference phase) Side 2: 210° Please subtract 180°, than you get 30° (360° - 30° = 330°) PTD PA13 N. M Tests 7UT 05/03 No. 6 Web Tool (Browser) Vector group YNd11 PTD PA13 N. M Tests 7UT 05/03 No. 7 Vector Group Determination via Fault Record IL1;Side 2 lags 150° or leads 210° Star point is towards the protected object IL1;Side 1 Way 1: IL1 Side: 150° + 180° = 330° Way 2: IL1 Side: 210° - 180° = 30° leads 30° or lags 330° Phase shift is according the vector group definition 330° → 11 * 30° PTD PA13 N. M Tests 7UT 05/03 No. 8 Digital Transformer Differential Protection I0-correction + vector group adaptation Differential Protection Symposium Belo Horizonte November 2005 G. Ziegler, 10/2005 page 1 Transformer differential protection with I0-correction External fault L3 L1 L2 L2 L3 L1 Yd5 3 3 3 L1 L2 L3 1 3 1:3 Vector group adaptation 3 1 I0-correction Differential Protection Symposium 1 2 3 2 ∆ ∆ ∆ 3 Belo Horizonte November 2005 G. Ziegler, 10/2005 page 2 Transformer differential protection with I0-correction Internal fault L3 L1 L2 L2 L3 L1 Yd5 3 3 3 L1 L2 L3 1 3 1:3 1 I0-correction Differential Protection Symposium Vector group adaptation 1 1 3 2 ∆ ∆ ∆ 3 Belo Horizonte November 2005 G. Ziegler, 10/2005 page 3 Power Transmission and Distribution Differential Protection (7UT) Determination of the Transformer Vector Group Transformer with Vector Group Yy0 7UT612 80 MVA Yy0 2500A/1A 20 kV 110 kV 500A/1A PTD PA13 N. M Tests 7UT 05/03 No. 2 Method of Vector Group Determination (ExampleYy0) IL1,S2 Side 2: Side 1: 2L1 1L1 IL1,S1 2L2 1L2 2L3 1L3 IL1,S2 = IL1 UL1,S1 UL1,S2 IL1,S1 UL3,S2 UL2,S2 UL3,S1 UL2,S1 0° Vector group is Yy0 PTD PA13 N. M Tests 7UT 05/03 No. 3 Transformer Protection 7UT612 80 MVA Yd11 2500A/1A 20 kV 110 kV 500A/1A PTD PA13 N. M Tests 7UT 05/03 No. 4 Method of Vector Group Determination (ExampleYd11) IL1,S2 Side 2: Side 1: 2L1 IL1,S1 2L2 1L1 1L2 2L3 1L3 IL1,S2 = IL1 - IL2 IL1,S1 UL1,S1 UL1,S2 UL2,S2 UL3,S1 UL2,S1 UL3,S2 Vector group is Y d 11 330° (n * 30°) PTD PA13 N. M Tests 7UT 05/03 No. 5 Definitions in SIPROTEC 4 Relays Vector definition to a node is positive The shown vectors or phase angles are transformed in this positive definition The phase angle is displayed mathematics positive. The reference phase is always phase L1 on side 1 How to see the vector group Yd11? Original Siprotec 4 (Browser) Phase angles Side 1: 0° (reference phase) Side 2: 210° Please subtract 180°, than you get 30° (360° - 30° = 330°) PTD PA13 N. M Tests 7UT 05/03 No. 6 Web Tool (Browser) Vector group YNd11 PTD PA13 N. M Tests 7UT 05/03 No. 7 Vector Group Determination via Fault Record IL1;Side 2 lags 150° or leads 210° Star point is towards the protected object IL1;Side 1 Way 1: IL1 Side: 150° + 180° = 330° Way 2: IL1 Side: 210° - 180° = 30° leads 30° or lags 330° Phase shift is according the vector group definition 330° → 11 * 30° PTD PA13 N. M Tests 7UT 05/03 No. 8

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