Distance Setting Excel

(1)

SIEMENS

PTD-HA/3000467425/ED2.121.001.W-0Document no.- Rev - 2

RELAY SETTING CALCULATION

220 KV DURSHED FEEDER - 2 DISTANCE PROTECTION RELAY

NEW 400/220KV SUBSTATION AT WARANGAL

LOA REF: C-55807-S119A-7/LOA-1/2020 DATED 31.03.2006 POWERGRID CORPORATION OF INDIA LIMITED

Name Department Telephone Place Date Signature Author:

Approval: LAXMINARAYAN PTD-HA 0124-2846155 GURGAON

-Rev Date Revised items Remarks

1 04.10.08 FOR APPROVAL KNR RL

2 19.12.08 SETTING REVISED ALL KNR RL

Total pages 25

Siemens Ltd., PTD Division

Copying this document, and giving it to others and the use or communication of the contents thereof, are forbidden without express authority. Offenders are liable to the payment of damages. All rights are reserved in the event of the grant of patent or registration of a utility model or design

TRANSMISSION SYSTEM ASSOCIATED WITH GRID STRENGTHENING FOR

TAMILNADU & ANDRA PRADESH

Page no Name of reviser Name of Approver

(2)

(3)

400/220 KV WARANGAL SUBSTATION

220kV DURSHED FEEDER

SIEMENS DISTANCE PROTECTION RELAY SETTING CALCULATION

1.0 Relay Data:

1.01 ANSI No. = 21

1.02 Description =Distance + Over Voltage Prot.

1.03 Make =SIEMENS

1.04 Model No. =7SA522

2.0 Input Data:

2.01 System voltage = 220 KV

2.02 Source substation =WARANGAL 400/220KV

2.03 Conductor used =ACSR Kundah

2.04 Protected Line length = 71 Km

2.05 Positive & Negative Sequence Line Impedance /KM

(R1=R2) = 0.0791 Ω/KM

(X1=X2) = 0.403 Ω/KM

2.06 Zero Sequence Line impedance per KM

R0 = 0.255 Ω/KM

X0 = 1.51 Ω/KM

2.07 Longest Line length = 50 Km

2.08 Conductor used =ACSR KUNDAH

(R1=R2) = 0.079 Ω/KM

(X1=X2) = 0.403 Ω/KM

R0 = 0.255 Ω/KM

X0 = 1.51 Ω/KM

2.11 Shortest Line length (Durichedu 1 Fdr.) = 71 Km

(4)

(R1=R2) = 0.079 Ω/KM

(X1=X2) = 0.403 Ω/KM

R0 = 0.255 Ω/KM

X0 = 1.51 Ω/KM

2.15 3Ф fault current at WARANGAL 220 KV Substation Magnitude Angle

= 40000 -79

2.16 1Ф fault current at WARANGAL 220 KV Substation Magnitude Angle

= 40000 -79

2.17 Tower Footing Resistance = 10 Ω

2.18 Direction - Zone I =Forward

2.19 Direction - Zone II =Forward

2.20 Direction - Zone III =Forward

2.21 Direction - Zone IV =Reverse

2.22 Direction - Zone V =Disabled

2.23 Direction - Zone 1B =Forward

2.24 Time delay - Zone I = 0 sec

2.25 Time delay - Zone II = 0.4 sec

2.26 Time delay - Zone III = 1 sec

2.27 Time delay - Zone IV = 1 sec

2.28 Time delay - Zone V = ∞ sec

2.29 Time delay - Zone 1B = 0 sec

3.0 Err:511

3.01 C.T Ratio =1600-800/1A

3.02 Selected Ratio = 800 / 1

3.03 Class = PS

(5)

3.05 Iex = <=50 ma 3.06 Rct = 4 Ω 4.0 Err:511 4.01 P.T Ratio = ( 220 KV / √ 3) / ( 0.11KV / √ 3) 4.02 Class = 3P 4.03 Burden = 50 VA

5.0 Transformer Data at Next 220KV Substation

5.01 Voltage level & Type =220KV / 132KV Auto transformer

5.02 220KV / 132KV Auto transformer = 2 Nos.

5.03 Rating of Transformer = 100 MVA

5.04 Vector Group = YNa0d11

5.05 Percent Impedances HV-MV a) Z1 at Principal Tap = 12.50% ± 10% b) Z0 at Principal Tap = 11.50% 5.06 High Voltage = 220 KV 5.07 Medium Voltage = 132 KV 5.08 Low Voltage = 11 KV

6.0 MAIN I DISTANCE PROTECTION: 6.1 Protected Line parameters:

6.1.1 Conductor used = ACSR Kundah

6.1.2 Line Length = 71 KM

6.1.3 Positive & Negative Sequence Line Impedance /KM

(R1=R2) = 0.0791 Ω/KM

(X1=X2) = 0.403 Ω/KM

6.1.4 Positive Sequence impedance of the Line Magnitude Angle

(6)

= 0.41069 78.9 = Err:511

6.1.5 Zero Sequence Line impedance per KM

R0 = 0.255 Ω/KM

X0 = 1.51 Ω/KM

6.1.6 Zero Sequence impedance of the Line Magnitude Angle

Per Unit Length (Z0) in Ω/KM =

= 1.53138 80.41

= Err:511

6.2 Longest Line parameters at Next 220KV Substation

6.2.1 Conductor used = ACSR KUNDAH

6.2.2 Line Length Assumed = 50 KM

(R1=R2) = 0.079 Ω/KM

(X1=X2) = 0.403 Ω/KM

Per unit length(Z1) in Ω/KM =

= 0.41067 78.91

= Err:511 6.2.5 Zero Sequence Line impedance per KM

R0 = 0.255 Ω/KM

X0 = 1.51 Ω/KM

= 1.53138 80.41

= Err:511

6.3 Shortest Line parameters at Next 220KV Substation

√(R02 _{+ X0}2₎ _tan-1_(X0/R0)

√(R12 _{+ X1}2₎ _tan-1_(X1/R1)

(7)

6.3.1 Conductor used = ACSR KUNDAH

6.3.2 Line Length Assumed = 71 KM

(R1=R2) = 0.079 Ω/KM

(X1=X2) = 0.403 Ω/KM

Per unit length(Z1) in Ω/KM =

= 0.41067 78.9

= Err:511 6.3.5 Zero Sequence Line impedance per KM

R0 = 0.255 Ω/KM

X0 = 1.51 Ω/KM

= 1.53138 80.4

= Err:511

6.4 Transformer Rating at Next 220kV Substation

6.4.1 220KV / 132KV Auto transformer = 2 Nos

6.4.2 Rating of Transformer = 100 MVA

6.4.3 Vector Group = YNa0d11

6.4.4 Percent Impedances HV-MV

Z1 at Principal Tap = 12.50% ± 10%

Z0 at Principal Tap = 11.50%

6.4.5 Magnetising Inrush Current = 6 times of the rated current

= 6 x 262.44 = 1574.64 A 6.4.6 Line Current(HV) = √(R12 _{+ X1}2₎ _tan-1_(X1/R1) √(R02 _{+ X0}2₎ _tan-1_(X0/R0) Rating/(√3 x V)

(8)

= 100000 / (1.732 x 220 ) = 262.44 A 6.4.7 Line Current(MV) = = 100000 / (1.732 x 132 ) = 437.4 A 6.4.8 Line Current(LV) = = 100000 / (1.732 x 11 ) = 5248.79 A 6.5 System Parameter: 6.5.1 3-Phase Fault Level:

a) Magnitude Angle

Err:511 = 40000 -79

= Err:511

= 40 KA

Therefore, maximum 3 Φ Fault Level = √3 x Isc x V

= √3 x 40x 220

= 15241.6 MVA

b) Minimum 3 Φ Fault current

(assumed-30% of max) = 12000 Amps

= 12 KA

c) X/R Ratio As per Calculations = X1 / R1

= 0.403 / 0.0791

= 5.095

6.5.2 1-Phase Fault Level:

a) Magnitude Angle

220KV BUS of Warangal SubStation = 40000 -79

= Err:511

= 40 KA

Rating/(√3 x V)

Maxium 3Ф Fault Current as per Calculation at

(9)

Therefore, maximum 1 Φ Fault Level = Isc x V = Err:511

= 8800 MVA

b) Minimum 1 Φ Fault current

(assumed-30% of max) = 12000 Amps

= 12 KA

c) X/R Ratio As per Calculations = X1 / R1

0.403 / 0.0791 5.095

6.6 Conversion of CT & PT Secondary Values:

Zsec = C.T Ratio

P.T Ratio

= Err:511

( 220/ √3 ) / ( 0.11 / √3 )

= 0.4

6.7 Line Impedances of the Protected Line:

6.7.1 Positive Sequence Impedance of the = Positive sequence impedance x

Protected Line(Z1) Protected line length

= ( 0.41069 < 78.9°) x 71

Magnitude Angle

= 29.15899 78.9 ohms

6.7.2 Positive sequence Impedance of the = Positive sequence impedance x C.F

Line per unit Length (X) refered to sec. in Ω/KM

= ( 0.41069 < 78.9°) x 0.4 x Z_pri

x Z_pri

(10)

Magnitude Angle

= 0.164276 78.9 ohms

6.7.3 Line Angle = 78.9

6.7.4 Distance Angle = 78.9

(Assumed equal to Line Angle)

6.7.5 Zero Sequence Impedance of the = Zero sequence impedance x

Protected Line(Z0) Protected line length

= Err:511 Magnitude Angle = 108.72798 80.41 ohms 6.7.6 = 1/3 * ((R0/R1) - 1) = 1/3 x (( 0.255 / 0.079 ) -1) = 0.743 6.7.7 = 1/3 * ((X0/X1) - 1) = 1/3 x (( 1.51 / 0.403 ) -1) = 0.916

6.7.8 Zero Sequence Compensation Factor Ko

= 1/3 * ((Z0/Z1) - 1)

= 1/3 x ((1.53138 / 0.41067) - 1)

Magnitude Angle

= 0.910 -178

Zero Sequence Compensation Factor R_E/R_L

(11)

6.8 Apparent Maximum Power:

6.8.1 Apparent Maximum Power: = 150.00 MVA

= 150.00 MVA

6.8.2 Rated full load current = 393.66 Amps

6.8.3 Source Impedance =

Magnitude Angle

= 3.18 78.91

6.9 Maximum Allowable Reach:

6.9.1 Min. Load Impedance at 0.8 p.f =

= ( 220^2 / ( 150 )) x 0.4 )

= 129.07 Ω

6.9.2 Maximum reach of Load Impedance = 80% of min. Load impedance

= 0.8 x 129.07

= 103.256 Ω

7.0 Computation of Fault Resistance Tolerance for Reach Setting :

7.1 Tower Footing Resistance = 10 Ω

7.2

= 1.26 Ω

7.3 For Phase to Phase Fault: Rt-Φ

(Considering 50% of Arc Resistance including a safety margin of 20%)

Resistance Tolerance with respect to Secondary = 0.312 Ω

7.4 For Phase to Earth Fault :- Resistance Tolerance with respect to secondary-Rt-e

= 1.2 x (1+I2/I1*((Rarc+RTF)/(1+RE/RL)) x C.F = 1.2 x (1+ 3 x ((10 + 1.26 ) / (1 + 0.743 )) x 0.4

= 9.783 Ω

Where,

I2/I1 is ratio of current at the opposite end and local end = 3

(2202_{/Max. 3 ph Fault MVA)}

(KV2 _{/ (MVA)) x CF}

(12)

8.0 DISTANCE RELAY PROTETION FOR 220KV Line feeder - 1 8.1 Zone I : Reach Setting Proposed at 80% of the protected Line

8.1.1 Direction = Forward

8.1.2 Resistive Reach For Φ to Φ Faults, =(80%x L x R(Z1) x C.F)+(R-TolerenceΦ-Φ)

R(Z1): = ( 0.8 x 71 x 0.0791 x 0.4 ) + 0.312

= 2.109 Ω

8.1.3 Resistive Reach For Φ to E Faults, = (R(Z1) x Ko)+R-TolerencePh-E

RE(Z1): = ( 0.8 x 71 x 0.0791 x 0.4 ) x 0.91 ) + 9.783

(13)

8.1.4 Reactance Reach,X(Z1) = 80% ofProtected line * X1 * C.F = 0.8 x 71 x 0.403 x 0.4

= 9.156 Ω

8.1.5 Time Delay: = 0 secs

Selected Setting:

Zone Direction

Zone I 11.418 Forward 2.109 9.156 80% 0

8.2 Zone II: Reach Setting Proposed at (100% of the protected Line + 50% of the shortest line at Next substation)

8.2.2 Resistive Reach For Φ to Φ Faults,R(Z2): = (((100% of Prot. line length x R1) +

(50% of short line x R1)) x C.F)+Rt-Φ = ((1 x 71 x 0.0791) + (0.5 x 71 x 0.079) x 0.4)+(0.312) = 3.68 Ω 8.2.3 = (R(Z2) x Ko) + Rt-e [ { (1 x 71 x 0.0791) + (0.5 x 71 x 0.079) x 0.4 } x = 0.91 ] + 9.783 = 12.848 Ω

8.2.4 Reactance Reach,X(Z2) = ((100% of Prot. line length x X1) +

(50% of short line x X1) x C.F ((1 x 71 x 0.403) +

(0.5 x 71 x 0.403) x 0.4

= 17.168 Ω

8.2.5 Time Delay: = 0.4 secs

Resistive Reach for Ph to

Earth Fault,R_E(Z1) Resistive Reach for Ph to Ph Fault,R (Z1) Reactance Reach,

X(Z1) Protected Length DelayTime

(14)

Zone Direction

Zone II 12.848 Forward 17.168 3.68 100% 0.4

8.3Zone III: Reach Setting

8.3.1 Base Impedance of the Transformer =

= Err:511

= 484 Ω

8.3.2 Equivelent Transformer Impedance = (KV2 / MVA)*Zo

= (220^2 / 100) x 0.115

= 55.66 Ω

8.3.3 Impedance of two transformers running in Parallel = 28 Ω

8.3.4 Impedance of Protected line at 100% = (Protected line x Z1 x C.F)

= (71 x 0.41069 x 0.4)

= 11.66

8.3.5 Total Impedance of both Transformers & = 39.66 Ω

Protected Line At 100%

(Comparing the above value with the reach of prot. line and the longest line at the remote)

8.3.6 Zone-3 impedance = (110% PL+100% OF NEXT)

= 52.61 Ω

Largest line at the Remote StationPrimary value

As the transformer capacities are variable the reach is as calculted from the above 8.3.8 is taken for reach setting which is nearer to the calculated value at8.3.5

8.3.8 Resistive Reach For Φ to Φ Faults, = { [(110% of Protected line length x R1) +

R(Z3) (100% of longest line x R1) ] x C.F } + Rt-Φ

[(1.1 x 71 x 0.0791) + (50 x 0.079) ] x 0.4)+ 0.312

4.362 Ω

8.3.9 Resistive Reach For Φ to E Faults, = { [(110% of Protected line length x R1) +

Earth Fault,R_E(Z2) Reactance Reach, X(Z2) Resistive Reach for Ph to Ph Fault,R(Z2) Protected Length Time Delay KV2_{/ MVA}

(15)

RE(Z3) (100% of longest line x R1) ] x C.F } + Rt-e [(1.1 x 71 x 0.0791) + (50 x 0.079) ] x 0.4)+ 9.783

13.833 Ω

8.3.10 Reactance Reach, X(Z3) = { 110% of Protected line length x X1) +

(100% of longest line x X1) ] x C.F } [(1.1 x 71 x 0.403) + (50 x 0.403) ] x 0.4)

20.65

Ω

Selected Setting: (110% PL+100% OF NEXT)

Zone Direction

Zone III 13.833 Forward 20.65 4.362 110% 1

8.4 Zone IV: Reach Setting Proposed at 25% of Zone1

8.4.1 Direction = Reverse

8.4.2 Resistive Reach For Φ to Φ Faults,R(Z4): =0.25 x R(Z1)

= 0.25 x 2.109 = 0.527 Ω 8.4.3 = = 0.25 x 11.418 = 2.855 Ω 8.4.4 Reactance Reach,X(Z4) =0.25 * X(Z1) = 0.25 x 9.156 = 2.289 Ω

Zone Direction

Zone IV 2.8545 Reverse 2.289 0.5273 25% 1

Earth Fault,R_E(Z2) Reactance Reach, X(Z2) Resistive Reach for Ph to Ph Fault,R(Z2) Protected Length Time Delay

Resistive Reach For Φ to E Faults,R_E(Z4): 0.25 x R_E(Z1)

(16)

8.5 Zone V Relay Setting Disabled

8.6 Controlled Zone (Z1B) Reach Setting Proposed at 120% of the Protected Line

8.6.1 Direction = 1 Forward

8.6.2 Resistive Reach For Φ to Φ Faults,R(ZIB)

at 120% of the Protected Line = (120% of Protd linex R1xC.F)+Rt-Ph

= 1.2 x 0.0791 x 71 x 0.4) + 0.312

= 3.008 Ω

8.6.3

at 120% of the Protected Line = (120% of Protd line x R1 x Ko x C.F)

+ Rt-E

= (1.2 x 71 x 0.0791 x 0.4 x 0.91) + 9.783

= 12.2361 Ω

8.6.4 Reactance Reach, X(ZIB)

at 120% of the Protected Line = 120% of Protected line * X1 * C.F

= 1.2 x 0.403 x 71 x 0.4

= 13.734 Ω

8.6.5 Time Delay = 0 secs

Zone Direction

Zone IB 12.24 Forward 13.73 3.01 120% 0

9 OVER VOLTAGE PROTECTION:

9.1 1 Voltage Protection : Enabled

9.2 2 Over Voltage Phase - Earth Protection:

9.3 = ON

9.4 Initial Stage for Minor Over voltage 110%of Un= 69.85 Volts 9.5 Time Delay for Initial Stage Setting = 5 Secs

Resistive Reach For Φ to E Faults,R_E(ZIB)

U_ph-e>(>):Phase Voltage Stages U_ph-e>:

(17)

9.6 Stage for Higher Voltage 150%ofUn= 95.25 Volts

9.7 Time delay for Longer Setting = 0 Secs

9.8 = 0.95

9.9 CURR.SUP.Uph-e>: = ON

11.0 DIRECTIONAL EARTH FAULT

11.1 Zero Sequence Source =

Impedance (Z0s) √3 x 220 x Min.1ph Fault Current

= 3 x 220^2 / (√3 x 220 x 12)

= 31.755196 Ω

11.2 Line Impedance of the Protected Line = Forward Ω

11.3 Earth Fault Current Pick-up = 20% of rated Full load current / C.T ratio

Setting(3I0>) = (0.2 x MVA / (√3 x KV)) / C.T ratio = (0.2 x 150000 / (1.732 x 220)) / ( 800 / 1) = 0.0984149 ≈ 0.1 A 11.4 = Disabled 11.5 Direction = Forward

11.6 Curve = Normal Inverse

11.7 TMS = 0.337

11.8 = Enabled

11.9 Characteristic Angle = Enabled

11.10 Tele protection Earth Fault: = N/A

Directional Comparison Pick-up 13.0 SOTF O/C

12.1 SOTF OVER CURRENT = Enabled

12.2 The magnitude of the current for picking up of

the switchon to fault I>>> = 2.5 times the FLC

= 2.5 x 150000 / (1.732 x 220)

U_ph-e>>: TU_ph-e>> :

U_ph-e>(>)RESET: Drop out to Pick Up Ratio

3 x KV2

Earth Fault Current Pick-up setting(3I_0>>)

(18)

= 984 A

(19)

400/220 KV WARANGAL SUBSTATION

220kV DURSHED FEEDER

SIEMENS DISTANCE PROTECTION RELAY SETTING

1 Device Configuration

No. Function Scope

103 Setting Group Change Option Disabled

110 Trip mode 3 pole

112 Phase Distance Quadrilateral

113 Earth Distance Quadrilateral

120 Power Swing detection Enabled

121 Teleprotection for Distance prot. POTT

122 DTT Direct Transfer Trip Disabled

124 Instantaneous HighSpeed SOTF Overcurrent Enabled

125 Weak Infeed (Trip and/or Echo) Disabled

126 Backup overcurrent _Disabled

131 Earth fault overcurrent Time Overcurrent Curve IEC

132 Teleprotection for Earth fault overcurr. Disabled

133 Auto-Reclose Function 1 AR-cycle

134 Auto-Reclose control mode with Trip and Action time

135 Synchronism and Voltage Check Disabled

136 Over / Underfrequency Protection Disabled

137 Under / Overvoltage Protection Enabled

138 Fault Locator Enabled

140 Trip Circuit Supervision Disabled

2 General Device Settings 2.1 Group Device

No. Settings Value

(20)

640 Start image Default Display image 1 3 Power System Data 1

3.1 Group Power System Data 1; Group Transformers

No. Settings Value

201 CT Starpoint towards Line

203 Rated Primary Voltage 220 KV

204 Rated Secondary Voltage (Ph-Ph) 110 V

205 CT Rated Primary Current 800.00 A

206 CT Rated Secondary Current 1A

210 U4 voltage transformer is Usy2 transformer

211 Matching ratio Phase-VT To Open-Delta-VT 1.73

215 Matching ratio Usy1 / Usy2 1

220 I4 current transformer is Neutral Current (of the protected line)

221 Matching ratio I4/Iph for CT's 1

3.2 Group Power System Data 1; Group Power System

No. Settings Value

207 System Starpoint is Solid Earthed

230 Rated Frequency 50 Hz

235 Phase Sequence L1 L2 L3

236 Distance measurement unit km

237 Setting format for zero seq.comp. format Zero seq. comp. factors RE/RL and XE/XL

0238A Earth Fault O/C: setting for 1pole AR all stages together

3.3 Group Power System Data 1; Group Breaker

No. Settings Value

0240A Minimum TRIP Command Duration 0.10 sec

0241A Maximum Close Command Duration 0.10 sec

242 Dead Time for CB test-autoreclosure 1.00 sec

(21)

4.1 Group Power System Data 2; Group Power System

No. Settings Value

1103 Measurement: Full Scale Voltage (100%) 220 KV

1104 Measurement: Full Scale Current (100%) 800.00 A

1105 Line Angle 78.9

1211 Angle of inclination, distance charact. 78.9

1107 P,Q operational measured values sign not reversed

1110 x' - Line Reactance per length unit 0.164276

1111 Line Length 71.0 KM

1116 Zero seq. comp. factor RE/RL for Z1 0.74

1117 Zero seq. comp. factor XE/XL for Z1 0.92

1118 Zero seq. comp.factor RE/RL for Z1B...Z5 0.74

1119 Zero seq. comp.factor XE/XL for Z1B...Z5 0.92

4.2 Group Power System Data 2; Group Line Status

No. Settings Value

1130A Pole Open Current Threshold 0.10 A

1131A Pole Open Voltage Threshold 30 V

1132A Seal-in Time after ALL closures 0.20 sec

1133A minimal time for line open before SOTF 0.25 sec

1134 Recognition of Line Closures with CBaux OR Current or Manual close BI

1135 RESET of Trip Command with CBaux open AND I < PoleOpenCurrent

1136 open pole detector with measurement (U/I,trip,pickup,CBaux)

1140A CT Saturation Threshold 5.0 A

1150A Seal-in Time after MANUAL closures 0.30 sec

1151 Manual CLOSE COMMAND generation NO

1152 MANUAL Closure Impulse after CONTROL <none>

4.3 Group Power System Data 2; Group Trip 1-/3-pole

(22)

1155 3 pole coupling with Trip

1156A Trip type with 2phase faults 3pole

4.4 Group Distance protection, general settings; Group General

No. Settings Value

1201 Distance protection ON

1202 Phase Current threshold for dist. Meas. 0.10 A

1211 Angle of inclination, distance charact. 78.9

1208 Series compensated line NO

1232 Instantaneous trip after SwitchOnToFault with Zone Z1B

1241 R load, minimum Load Impedance (ph-e) 129.1 Ohms

1242 PHI load, maximum Load Angle (ph-e) 37 °

1243 R load, minimum Load Impedance (ph-ph) 258.1 Ohms

1244 PHI load, maximum Load Angle (ph-ph) 45 °

1317A Single pole trip for faults in Z2 NO

1357 YES

4.5 Group Distance protection, general settings; Group Earth faults

No. Settings Value

1203 3I0 threshold for neutral current pickup 0.10 A

1204 3U0 threshold zero seq. voltage pickup 5 V

1207A 3I0>-pickup-stabilisation (3I0> /Iphmax) 0.15

1209A criterion of earth fault recognition 3I0> OR 3U0>

1221A Loop selection with 2Ph-E faults all loops

4.6 Group Distance protection, general settings; Group Time Delays

No. Settings Value

1210 Condition for zone timer start with distance pickup

1305 T1-1phase, delay for single phase faults 0.00 sec

1306 T1multi-ph, delay for multi phase faults 0.00 sec

(23)

1325 T3 delay 1.00 sec

1345 T5 delay N/A

1355 T1B-1phase, delay for single ph. Faults 0.00 sec

1356 T1B-multi-ph, delay for multi ph. Faults 0.00 sec

4.7 Group Distance zones (quadrilateral); Group Zone Z1

No. Settings Value

1301 Operating mode Z1 Forward

1302 R(Z1), Resistance for ph-ph-faults 2.109 Ohms

1303 X(Z1), Reactance 9.156 Ohms

1304 RE(Z1), Resistance for ph-e faults 11.418 Ohms

1307 Zone Reduction Angle (load compensation) 0 °

4.8 Group Distance zones (quadrilateral); Group Zone Z1Bexten.

No. Settings Value

1351 Operating mode Z1B (_verreach zone) Forward

1352 R(Z1B), Resistance for ph-ph-faults 3.008 Ohms

1353 X(Z1B), Reactance 13.734 Ohms

1354 RE(Z1B), Resistance for ph-e faults 12.236 Ohms

1355 T1B-1phase, delay for single ph. Faults 0.00 sec

1356 T1B-multi-ph, delay for multi ph. Faults 0.00 sec

1357 YES

No. Settings Value

(24)

1317A Single pole trip for faults in Z2 NO

No. Settings Value

1331 Operating mode Z4 Reverse

No. Settings Value

1341 Operating mode Z5 Inactive

1342 R(Z5), Resistance for ph-ph-faults N/A

1343 X(Z5)+, Reactance for Forward direction N/A

1344 RE(Z5), Resistance for ph-e faults N/A

1345 T5 delay N/A

1346 X(Z5)-, Reactance for Reverse direction N/A

(25)

No. Settings Value

2002 Power Swing Operating mode Z2 to Z5 Block

2006 Power swing trip YES

2007 Trip delay after Power Swing Blocking 0.08 sec

4.14 Group Teleprotection for Distance prot.

No. Settings Value

2101 Teleprotection for Distance protection PUTT(Z1B)

2102 Type of Line Two Terminals

2103A Time for send signal prolongation 0.07 sec

2109A Transient Block.: Duration external flt. oo sec

2110A Transient Block.: Blk.T. after ext. flt. 0.05 sec

4.15 Group Instantaneous HighSpeed SOTF Overcurrent

No. Settings Value

2401 Inst. High Speed SOTF-O/C is ON

2404 I>>> Pickup 2.5 A

4.16 Group Measurement Supervision; Group Balance / Summ.

No. Settings Value

2901 Measurement Supervision ON

2902A Voltage Threshold for Balance Monitoring 10

2903A Balance Factor for Voltage Monitor 0.8

2904A Current Balance Monitor 0.1

2905A Balance Factor for Current Monitor 0.05

2906A Summated Current Monitoring Threshold 0.10 A

2907A Summated Current Monitoring Factor 0.1

2908A T Balance Factor for Voltage Monitor 5 sec

2909A T Current Balance Monitor 5 sec

4.17 Group Measurement Supervision; Group Fuse Fail. Mon.

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2910 Fuse Failure Monitor ON

2911A Minimum Voltage Threshold U> 50 V

2912A Maximum Current Threshold I< 0.20 A

2913A Maximum Voltage Threshold U< (3phase) 5 V

2914A Delta Current Threshold (3phase) 0.10 A

2915 Voltage Failure Supervision with current supervision

2916A Delay Voltage Failure Supervision 3.00 sec

4.18 Group Measurement Supervision; Group VT mcb

No. Settings Value

2921 VT mcb operating time 0 ms

4.19 Group Measurement Supervision; Group Load Angle

No. Settings Value

2941 Limit setting PhiA 200 °

2942 Limit setting PhiB 340 °

2943 Minimum value I1> 0.05 A

2944 Minimum value U1> 20 V

4.20 Group Earth fault overcurrent; Group General

No. Settings Value

3101 Earth Fault overcurrent function ON

3102 Block E/F for Distance protection with every Pickup

3174 Block E/F for Distance Protection Pickup in each zone

3103 Block E/F for 1pole Dead time YES

3104A Stabilisation Slope with Iphase 10%

3109 Single pole trip with earth flt.prot. YES

3170 2nd harmonic ratio for inrush restraint 15%

3171 Max.Current, overriding inrush restraint 7.50 A

3172 Instantaneous mode after SwitchOnToFault with Pickup and direction

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4.21 Group Earth fault overcurrent; Group 3I0>>>

No. Settings Value

3110 Operating mode Inactive

3111 3I0>>> Pickup N/A

3112 T 3I0>>> Time delay N/A

3113 Instantaneous trip via Teleprot./BI N/A

3114 Instantaneous trip after SwitchOnToFault N/A

3115 Inrush Blocking N/A

4.22 Group Earth fault overcurrent; Group 3I0>>

No. Settings Value

3121 3I0>> Pickup N/A

3122 T 3I0>> Time Delay N/A

4.23 Group Earth fault overcurrent; Group 3I0>

No. Settings Value

3131 3I0> Pickup N/A

3132 T 3I0> Time Delay N/A

4.24 Group Earth fault overcurrent; Group 3I0 InverseTime

No. Settings Value

3140 Operating mode Forward

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3143 3I0p Time Dial 0.34 sec

3147 Additional Time Delay 0.00 sec

3148 Instantaneous trip via Teleprot./BI YES

3149 Instantaneous trip after SwitchOnToFault NO

3150 Inrush Blocking YES

3151 IEC Curve Normal Inverse

4.25 Group Earth fault overcurrent; Group Direction

No. Settings Value

3160 Polarization with U0 + IY (dual polarized)

3162A ALPHA, lower angle for forward direction 338 °

3163A BETA, upper angle for forward direction 122 °

3164 Min. zero seq.voltage 3U0 for polarizing N/A

3166 Min. neg. seq. polarizing voltage 3U2 5.0 V

3167 Min. neg. seq. polarizing current 3I2 0.50 A

3168 Compensation angle PHI comp. for Sr 255 °

3169 Forward direction power threshold 0.3 VA

4.26 Group Automatic Reclosure; Group General

No. Settings Value

3401 Auto-Reclose function ON

3402 CB ready interrogation at 1st trip NO

3403 Reclaim time after successful AR cycle 3.00 sec

3404 AR blocking duration after manual close 1.00 sec

3406 Evolving fault recognition with Trip

3407 Evolving fault (during the dead time) starts 3pole AR-cycle

3408 AR start-signal monitoring time 0.20 sec

3409 Circuit Breaker (CB) Supervision Time 3.00 sec

3410 Send delay for remote close command

∞sec

(29)

4.27 Group Automatic Reclosure; Group 1st AR-cyle

No. Settings Value

3450 Start of AR allowed in this cycle YES

3451 Action time 0.20 sec

3456 Dead time after 1pole trip 1.20 sec

3457 Dead time after 3pole trip 0.50 sec

3458 Dead time after evolving fault 1.20 sec

3459 CB ready interrogation before reclosing NO

3460 Request for synchro-check after 3pole AR NO

4.28 Group Automatic Reclosure; Group 3pTRIP/DLC/RDT

No. Settings Value

3430 3pole TRIP by AR YES

3431 Dead Line Check or Reduced Dead Time Without

3438 Supervision time for dead/ live voltage 0.10 sec

3440 Voltage threshold for live line or bus 48 V

3441 Voltage threshold for dead line or bus 30 V

4.29 Group Automatic Reclosure; Group Start AR with..

No. Settings Value

3420 AR with distance protection YES

3421 AR with switch-onto-fault overcurrent NO

3423 AR with earth fault overcurrent prot. NO

4.30 Group Voltage Protection; Group U> Phase-Earth

No. Settings Value

3701 Operating mode Uph-e overvoltage prot. ON

3702 Uph-e> Pickup 69.9 V

3703 T Uph-e> Time Delay 5.00 sec

3704 Uph-e>> Pickup 95.3 V

(30)

3709A Uph-e>(>) Reset ratio 0.95 4.31 Group Fault Locator

No. Settings Value

3802 Start fault locator with Pickup

(31)

SIEMENS 400/220kV WARANGAL _SUBSTATION

400/220 KV WARANGAL SUBSTATION

220kV DURSHED FEEDER

ABB DISTANCE PROTECTION RELAY SETTING CALCULATION

Type : ABB make REL670

System Particulars A Line Parameters

1 Rated line voltage 220 KV

2 Line Length 71 KM

3 Max power flow in the line (assumed) 150 MVA

4 Postive sequence resistance 0.0791 ohms/km

5 Postive sequence reactance 0.403 ohms/km

6 Zero sequence resistance 0.255 ohms/km

7 Zero sequence reactance 1.51 ohms/km

8 Zero sequence mutual resistance (MR) 0 ohms/km

(If Parallel line in service Mutual Impedance is 60% of zero seq.)

9 Zero sequence mutual reactance (MX) 0 ohms/km

B Adjoining line parameters B.1 Adjacent Line(Short Line)

1 Length of adjacent line 71 KM

B.2 longest line

1 Length of longest line 50 KM

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46 OF 205 B.3 Transformer

1 Transformer impedance in p.u 0.125

2 Transformer rating 100 MVA

C Source impedance

1 Local End max. Fault MVA =1.732*220*40 15241.6 MVA 2 Local End min. Fault MVA =30 % of 15241.6 4572 MVA 3 Local End Z magnitude = (220 x 220) / 15241.6 3.176 ohms

4 Local End Z argument 84 deg.

5 Remote End Max. Fault MVA (Assumed -Not available) 7500 MVA 6 Remote End Min. Fault MVA (Assumed -Not available) 3000 MVA 7 Remote End Z magnitude = (220 x 220) / 7500 6.45 ohms

8 Remote End Z argument 84 deg.

(33)

10 Postive sequence reactance at local end = line length x +ve seq.X 28.613 ohms 11 Postive sequence resistance at remote end = line length x +ve seq. R 5.6161 ohms 12 Postive sequence reactance at remote end = line length x +ve seq. X 28.613 ohms

D CT and PT Detail 1 CT primary rating 800 A 2 CT secondary rating 1 A 3 PT primary rating 220000 V 4 PT secondary rating 110 V E Relay Detail 1 Rated current 1 A 2 Rated voltage 110 V F System Parameters

1 Arc Resistance + Tower footing resistance - Rfn 50.000 ohms

2 Rf for phase to phase fault 10.000

3 Imp Ratio = CTR / PTR 0.400

4 % for zone-1 setting 0.800

5 % of the adjoining line for Zone2 0.500

6 % of the adjoining line for Zone 3 1.100

G Protected Line Impedance in CT secondary

1 Postive sequence resistance = line length x + ve seq. R x Imp Ratio = 2.246 ohms 2 Postive sequence reactance = line length x + ve seq. X x Imp Ratio = 11.445 ohms 3 Zero sequence resistance = line length x Z0 x Imp Ratio = 7.242 ohms 4 Zero sequence reactance = line length x Z0X x Imp Ratio = 42.884 ohms 5 Zero sequence mutual resistance = line length x MR x Imp Ratio = 0.000 ohms 6 Zero sequence mutual reactance = line length x MX x Imp Ratio = 0.000 ohms H Adjacent Line Impedance in CT secondary

1 Postive sequence resistance = line length x + ve seq. R x Imp Ratio = 2.244 ohms 2 Postive sequence reactance = line length x + ve seq. X x Imp Ratio = 11.445 ohms 3 Zero sequence resistance = line length x Z0 x Imp Ratio = 7.242 ohms 4 Zero sequence reactance = line length x Z0X x Imp Ratio = 42.884 ohms

I Longest Line Impedance in CT secondary

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48 OF 205

2 Postive sequence reactance = line length x + ve seq. X x Imp Ratio = 8.060 ohms 3 Zero sequence resistance = line length x Z0 x Imp Ratio = 5.100 ohms 4 Zero sequence reactance = line length x Z0X x Imp Ratio = 30.200 ohms J Zone I : Reach Setting Proposed at 80% of the protected Line

1 Reach For Postive sequence resistance

(80% line length x Postive sequence resistance x Imp Ratio

=0.8 x 71 x 0.0791 x 0.4 1.797 ohms

2 Reach For Postive sequence reactance

(80% line length x Postive sequence reactance x Imp Ratio

=0.8 x 71 x 0.403 x 0.4 9.156 ohms

3 Reach For Zero sequence resistance

(80% line length x Zero sequence resistance x Imp Ratio

=0.8 x 71 x 0.255 x 0.4 5.794 ohms

4 Reach For Zero sequence reactance

(80% line length x Zero sequence reactance x Imp Ratio

=0.8 x 71 x 1.51 x 0.4 34.307 ohms

5 Fault Resistance - ph-e

= 1.797 + ( 9.156 x TAN ( 25 ) = 6.067 = 4.5 x 1.797 = 8.0865 = 50 x 0.4 = 20.000 Maximum of 6.067 and 20 = 20.000 Minimum of 8.0865 and 20 = 8.087 ohms Hence fault resistance between phase to earth = 8.087 ohms

6 Fault Resistance - ph-ph

= 1.797 + ( 9.156 x TAN ( 25 ) = 6.067 = 3 x 1.797 = 5.391 = 10 x 0.4 = 4.000

(35)

Maximum of 6.067 and 4 = 6.067 Minimum of 5.391 and 6.067 = 5.391 Hence fault resistance between phase to phase =2 times of the above 10.782 ohms

K Zone II: Reach Setting at (100% of the protected Line + 50% of the shortest line at Next substation)

1 Reach For Postive sequence resistance

100% line length x Postive sequence resistance x Imp Ratio + 50% shortest line length x Postive sequence resistance x Imp Ratio

=71 x 0.0791 x 0.4 + 0.5 x 71 x 0.0791 x 0.4 3.368 ohms

100% line length x Postive sequence reactance x Imp Ratio + 50% shortest line length x Postive sequence reactance x Imp Ratio

=71 x 0.403 x 0.4 + 0.5 x 71 x 0.403 x 0.4 17.168 ohms

100% line length x Zero sequence resistance x Imp Ratio + 50% shortest line length x Zero sequence resistance x Imp Ratio

=71 x 0.255 x 0.4 + 0.5 x 71 x 0.255 x 0.4 10.863 ohms

100% line length x Zero sequence reactance x Imp Ratio + 50% shortest line length x Zero sequence reactance x Imp Ratio

=71 x 1.51 x 0.4 + 0.5 x 71 x 1.51 x 0.4 64.326 ohms

5 Fault Resistance - ph-e 15.156 ohms

6 Fault Resistance - ph-ph 20.208 ohms

L Zone III: Reach Setting Proposed at 110% of the prot Line & 100%of the longest line 1 Reach For Postive sequence resistance

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50 OF 205

110% line length x Postive sequence resistance x Imp Ratio + 100% Longest line length x Postive sequence resistance x Imp Ratio

= 1.1 x 71 x 0.0791 x 0.4 + 50 x 0.0791 x 0.4 4.053 ohms

110% line length x Postive sequence reactance x Imp Ratio + 100% Longest line length x Postive sequence reactance x Imp Ratio

= 1.1 x 71 x 0.403 x 0.4 + 50 x 0.403 x 0.4 20.650 ohms

110% line length x Zero sequence resistance x Imp Ratio + 100% Longest line length x Zero sequence resistance x Imp Ratio

= 1.1 x 71 x 0.255 x 0.4 + 50 x 0.255 x 0.4 13.066 ohms

110% line length x Zero sequence reactance x Imp Ratio + 100% Longest line length x Zero sequence reactance x Imp Ratio

= 1.1 x 71 x 1.51 x 0.4 + 50 x 1.51 x 0.4 77.372 ohms

5 Fault Resistance - ph-e 18.239 ohms

6 Fault Resistance - ph-ph 24.319 ohms

M Power Swing Block Function

1

2 22.715

3 28.980

4 28.393

5 36.224

Reactive direction are set so that the inner characteristic covers completely all the distance protection zones,which are to be blocked by the PSD function.At least 10%of additional safely margin

Reactive Reach of the Inner characteristic of the Power swing blocking element = 1.1* X3

Reactive Reach of the Inner characteristic of the Power swing blocking element = 1.1(2R3+Rf)

Reactive Reach of the Outer characteristic of the Power swing blocking element

(37)

N Source Impedance refered to CT secondary

1 Local End Z magnitude 1.270

2 Local End Z argument 80.000

3 Remote End Z magnitude 2.580

4 Remote End Z argument 80.000

5 Postive sequence resistance at local end in ohms(RISA) 2.246 6 Postive sequence reactance at local end in ohms(XISA) 11.445 7 Postive sequence resistance at remote end in ohms(R1SB) 2.246 8 Postive sequence reactance at remote end in ohms(X1SB) 11.445 O Phase Selection 1 X1Phs 41.299 2 X0Phs 154.745 3 Calculated RFPEphs 50.593 4 Calculated RFPPphs 44.584 5 104.544 6 RFPEphs 50.593

7 Conditions for 2nd Zone 29.360

8 Conditions for 4th Zone 4.180

9 Conditions for 3-ph fault 51.979

10 RFPPphs 44.584

9.451 13.985 Z_loadmin=(KV)2_\MVA

(38)

SIEMENS 400/220kV WARANGAL SUBSTATION

400/220 KV WARANGAL SUBSTATION

220kV DURSHED FEEDER

ABB DISTANCE PROTECTION RELAY SETTING

Type : ABB make REL670

DESCRIPTION PARAMETER SETTING RECOMMENDED

Max. load current \ CT primary current lb (FLC \ CT Primary) 0.492

lminop 0.200

Distance Protection zone 1

operating mode and directionaity of zone I operation Forward Settings of Phase to Phase measurement

Operation of distance protection zone I for Ph-I Operation PP On Positive sequence reactance of zone 1 for ph-ph fault X1PP 9.156 Positive sequence reactance of zone 1 for ph-ph fault R1PP 1.797 Resisitive reach of distance protection for ph-ph faults RFPP 10.782

Timer t1PP On

t1PP 0.000

Settings of Phase to earth element

Operation of distance protection zone I for Ph-I Operation PE On

X1PE 9.156

Positive sequence resistive reach of distance zone 1 for ph-E fault R1PE 1.797

XOPE 34.307

ROPE 5.794

Resisitive reach for zone 1 Ph-E faults RFPE 8.087

Timer t1PP On

Operating mode of time delayed trip for the distance protection zone 1 for ph-ph faults

Time delayed trip operation for the distance protection zone 1 for ph-ph faults

Zero sequence line reactance included in distance protection zone I for Ph-E faults

Operating mode of time delayed trip for the distance protection zone 1 for ph-E faults

(39)

t1PE 0.000

(40)

Distance Protection zone II ZONE II

operating mode and directionaity of distance zone II operation Forward Settings of Phase to Phase measurement

Operation of distance protection zone 2 for Ph-Ph fault Operation PP On Positive sequence reactance of zone 2 for ph-ph fault X1PP 17.168 Positive sequence reactance of zone 2 for ph-ph fault R1PP 3.368 Resisitive reach of distance protection for ph-ph faults RFPP 20.208

Timer t1PP On

t1PP 0.400

Settings of Phase to earth element

Operation of distance protection zone 2 for Ph-E faults Operation PE On

X1PE 17.168

Positive sequence resistive reach of distance zone 2 for ph-E fault R1PE 3.368

XOPE 64.326

ROPE 10.863

Resisitive reach for zone 2 Ph-E faults RFPE 15.156

Timer t1PP On

t1PE 0.400

Distance protection zone lll ZONEIII

Operating mode and directionality of zone 3 Operation Forward SETTINGS OF PHASE TO PHASE MEASUREMENT

Operation of Distance protection Zone 3 for Ph fault Operation PP On Positive sequence reactance of zone 3 for phase to phase faults X1PP 20.650 Positive sequence resistance of zone 3 for phase to phase faults R1PP 4.053 Positive reach of distance protectin for phase to phase faults RFPP 24.319 Operating mode of time delayed trip for the distance protection

zone 2 for ph-ph faults

Zero sequence line reactance included in distance protection zone 2 for Ph-E faults

Operating mode of time delayed trip for the distance protection zone 2 for ph-E faults

(41)

Timer t3PP On

t3PP 1.000

SETTINGS OF PHASE TO EARTH MEASUREMENT

Operating mode of distance protection zone 3 for Ph-E faults Operation PE On Positive sequence reactive reach of distance zone 3 for Ph-E faults X1PE 20.650 Positive sequence resistive reach of distance zone 3 for Ph-E faults R1PE 4.053

X0PE 77.372

R0PE 10.863

Resistive reach for zone 3 for Ph-E faults RFPE 18.239

Timer t3PE On

t3PE 1.000

Manual energising time T manenerg 0.200

PHASE SELECTION

operation of phase selection operation On

positive sequence reactive reach for ph-ph loop measurement X1PP 20.650

Resistive reach for ph-ph loop measurement RFPP 24.319

positive sequence reactive reach for ph-e loop measurement X1PE 20.650 Zero sequence reactive for ph-e loop measurement XOPE 77.372

Resistive reach for ph-e loop measurement RFPE 18.239

Power swing blocking PSB

power swing function on/off operation On

Operating mode of internal PSD function detection on

positive sequence reactive reach of the inner boundary X1IN 22.715 positive sequence reactive reach of the inner boundary R1IN 28.980 reach multiplication for the outer reactive boundary KX 1.250 reach multiplication for the outer reactive boundary KR 1.250

Initial PSD timer tp1 0.045

Fast PSD timer tp2 0.015

Operating mode of time delayed trip for the distance protection zone 3 for Ph-Ph faults

Time delaye trip operation for the distnce protection zone 3 for Ph-Ph faults

zero sequence line reactance included in distance protection zone 3 for Ph-E faults

Zero sequence line reactance included in distance protection zone 3 for Ph-E faults

Operating mode of time delayed trip for the distance protection zone 3 for Ph-E faults

Time delayed trip operation of the distance protection zone 3 for Ph-E faults

(42)

Hold timer for activation of fast PSD timer tw 0.250

Hold timer for PSD detected th 0.5s

Timer over coming 1-phase reclosing dead time tEF 3 s

Timer to time delay block by the residual current tR1 0.300 On delay timer for blocking of output signal at very slow swings tR2 2.000

Scheme communication logic Zcom

Operation of zoom scheme communication logic Operation On

Operation mode Schemetype Permissive UR

Coordination timer T coord 0.050s

Minimum duration of a carrier send signal T sendmin 0.1s

Operation mode for an unblocking signal Unblock Off

Security timer T security 0.035s

Operation mode of current reversal function Currev Off

Pick up time of current reversal function T pickup NA

Time delay for current reversal T delay NA

Operation mode of WEI function WEI Off

Coordination time for WEI function Twei NA

Voltage detection for PH-E faults UPN< NA

voltage detection for Ph-Ph faults UPP< NA

Automatic SOTF SOTF

Operation of SOTF Operation On

FUSE FAILURE FUNCTION FFR

FFR zero sequence function On\Off Zeroseq On

Operating value of voltage U0 3U0> 0.100

Operating value of current I0 3Uo< 0.100

BROKEN CONDUCTOR SUPERISION SSUP

Broken conductor function On\Off Operation On

(43)

Time delay T 0.200

Loss of voltage YU<

Loss of voltage function On\Off Operation On

Operating phase voltage as a% UPE< 0.700

overload I>

Overload function On\Off Operation On

operating value of phase current IP> 1.000

Time delay T 20s

FAULT LOCATOR

Unit for presentation of line length Length unit Km

Length of protected line Line length 71.000

Positive sequence reactance of line X1 28.613

Positive sequence resistance of line R1 5.616

zero sequence reactance of line X0 107.210

Zero sequence resistance of line R1 18.105

Positive sequence reactance of source at local end X1SA 28.613 Positive sequence resistance of source at local end R1SA 5.616

Positive source reactance at remote end X1SB 28.613

Positive source resistance at remote end R1SB 5.616

Zero sequence mutual reactance for double circuit line XM0 Zero sequence mutual resistance for double circuit line RM0

Selection of presentation mode for the distance to fault * Distance unit Km

Analogue signal name** Name

Primary phase-phase voltage VT prim 220.000

Primary rated current CT prim 800.000

NOTES: ALL parameters of fault locator are set in the menu-settings-functions-group n-line.reference *Settings done in menu: settings - Distrbreport-faultlocator

(44)

SIEMENS 400/220kV WARANGAL SUBSTATION SYNCRO CHECK AND ENERGISATION CHECK FUNCTIONS:

Operation of syncro check function Operation On

Reference voltage either phase to ground or phase to phase Input phase L1

Phase shift between U bus & U line Phase shift 10.000

Voltage ratio between U bus & Uline U ratio 1.000

Bus arrangment for voltage selection U selection single bus

Autoenergisation check Autoenerg Off

Mannual energisation check Manenerg Off

Mannual energisation check ManDBDL Off

High voltage limit Uhigh 0.800

Low voltage limit Ulow 0.400

Frequency difference limit Freqdiff 0.200

Phase angle difference limit Phasediff 20.000

Voltage difference limit Udiff 0.200

Autoenergisation check T autoenerg 0.200