7SA522 arelay Setting Calculation
description
Transcript of 7SA522 arelay Setting Calculation
SIEMENSPTD-HA/3000467425/ED2.121.001.W-0
Document 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
1 of 25
400/220 KV xxxxxxxxx SUBSTATION
220kV yyyyyyyyyy 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 = 75 Km
2.05 Positive & Negative Sequence Line Impedance /KM
(R1=R2) = 0.079 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 = 71 Km
2.08 Conductor used = ACSR KUNDAH
2.09 Positive & Negative Sequence Line Impedance /KM
(R1=R2) = 0.079 Ω/KM
(X1=X2) = 0.403 Ω/KM
2.10 Zero Sequence Line impedance per KM
R0 = 0.255 Ω/KM
X0 = 1.51 Ω/KM
2.11 Shortest Line length (.) = 53 Km
2.12 Conductor used = ACSR KUNDAH
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2.13 Positive & Negative Sequence Line Impedance /KM
(R1=R2) = 0.079 Ω/KM
(X1=X2) = 0.403 Ω/KM
2.14 Zero Sequence Line impedance per 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
3.0 220 KV WARANGAL C.T Parameters
3.01 C.T Ratio = 1600-800/1A
3.02 Selected Ratio = 800 / 1
3.03 Class = PS
3.04 KPV = 800 V
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3.05 Iex = <=50 ma
3.06 Rct = 4 Ω
4.0 220 KV WARANGAL P.T Parameters
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 = 75 KM
6.1.3 Positive & Negative Sequence Line Impedance /KM
(R1=R2) = 0.079 Ω/KM
(X1=X2) = 0.403 Ω/KM
6.1.4 Positive Sequence impedance of the Line Magnitude Angle
Per unit length(Z1) in Ω/KM = √(R12 + X12) tan-1(X1/R1)
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= 0.41067 78.91
= 0.41067 < 78.91°
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
= 1.53138 < 80.41°
6.2 Longest Line parameters at Next 220KV Substation
6.2.1 Conductor used = ACSR KUNDAH
6.2.2 Line Length Assumed = 71 KM
6.2.3 Positive & Negative Sequence Line Impedance /KM
(R1=R2) = 0.079 Ω/KM
(X1=X2) = 0.403 Ω/KM
6.2.4 Positive Sequence impedance of the Line Magnitude Angle
Per unit length(Z1) in Ω/KM =
= 0.41067 78.91
= 0.41067 < 78.91°
6.2.5 Zero Sequence Line impedance per KM
R0 = 0.255 Ω/KM
X0 = 1.51 Ω/KM
6.2.6 Zero Sequence impedance of the Line Magnitude Angle
Per Unit Length (Z0) in Ω/KM =
= 1.53138 80.41
= 1.53138 < 80.41°
6.3 Shortest Line parameters at Next 220KV Substation
√(R02 + X02) tan-1(X0/R0)
√(R12 + X12) tan-1(X1/R1)
√(R02 + X02) tan-1(X0/R0)
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6.3.1 Conductor used = ACSR KUNDAH
6.3.2 Line Length Assumed = 53 KM
6.3.3 Positive & Negative Sequence Line Impedance /KM
(R1=R2) = 0.079 Ω/KM
(X1=X2) = 0.403 Ω/KM
6.3.4 Positive Sequence impedance of the Line Magnitude Angle
Per unit length(Z1) in Ω/KM =
= 0.41067 78.9
= 0.41067 < 78.91°
6.3.5 Zero Sequence Line impedance per KM
R0 = 0.255 Ω/KM
X0 = 1.51 Ω/KM
6.3.6 Zero Sequence impedance of the Line Magnitude Angle
Per Unit Length (Z0) in Ω/KM =
= 1.53138 80.4
= 1.53138 < 80.41°
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 + X12) tan-1(X1/R1)
√(R02 + X02) tan-1(X0/R0)
Rating/(√3 x V)
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= 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
WARANGAL 220 Kv Substation = 40000 -79
= 40000 < -79°
= 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 / 0.079
= 5.101
6.5.2 1-Phase Fault Level:
a) Magnitude Angle
220KV BUS of Warangal SubStation = 40000 -79
= 40000 < -79°
= 40 KA
Rating/(√3 x V)
Rating/(√3 x V)
Maxium 3Ф Fault Current as per Calculation at
Maxium 1Ф Fault Current as per Calculation at
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Therefore, maximum 1 Φ Fault Level = Isc x V
= 40x 220
= 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 / 0.079
5.101
6.6 Conversion of CT & PT Secondary Values:
Zsec = C.T Ratio
P.T Ratio
= 800 / 1
( 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
= ( 0.41067 < 78.91°) x 75
Magnitude Angle
= 30.80025 78.91 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
= ( 0.41067 < 78.91°) x 0.4
x Zpri
x Zpri
X Zpri
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Magnitude Angle
= 0.164268 78.91 ohms
6.7.3 Line Angle = 78.91
6.7.4 Distance Angle = 78.91
(Assumed equal to Line Angle)
6.7.5 Zero Sequence Impedance of the = Zero sequence impedance x
Protected Line(Z0) Protected line length
= 1.53138 x 75
Magnitude Angle
= 114.8535 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 RE/RL
Zero Sequence Compensation Factor XE/XL
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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
Arc Resistance (RArc) = = 76KV2/Short ckt. KVA at min. Fault Current
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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 75 x 0.079 x 0.4 ) + 0.312
= 2.208 Ω
8.1.3 Resistive Reach For Φ to E Faults, = (R(Z1) x Ko)+R-TolerencePh-E
RE(Z1): = ( 0.8 x 75 x 0.079 x 0.4 ) x 0.91 ) + 9.783
= 11.508 Ω
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8.1.4 Reactance Reach,X(Z1) = 80% ofProtected line * X1 * C.F
= 0.8 x 75 x 0.403 x 0.4
= 9.672 Ω
8.1.5 Time Delay: = 0 secs
Selected Setting:
Zone Direction
Zone I 11.508 Forward 2.208 9.672 80% 0
8.2 Zone II: Reach Setting Proposed at (100% of the protected Line +
50% of the shortest line at Next substation)
8.2.1 Direction = Forward
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 75 x 0.079) +
(0.5 x 53 x 0.079) x 0.4)+(0.312)
= 3.519 Ω
8.2.3 = (R(Z2) x Ko) + Rt-e
[ { (1 x 75 x 0.079) +
(0.5 x 53 x 0.079) x 0.4 } x
= 0.91 ] + 9.783
= 12.702 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 75 x 0.403) +
(0.5 x 53 x 0.403) x 0.4
= 16.362 Ω
8.2.5 Time Delay: = 0.4 secs
Selected Setting:
Resistive Reach for Ph to Earth Fault,RE(Z1)
Resistive Reach for Ph to Ph Fault,R
(Z1)
Reactance Reach, X(Z1)
Protected Length
Time Delay
Resistive Reach For Φ to E Faults,RE(Z2):
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Zone Direction
Zone II 12.702 Forward 16.362 3.519 100% 0.4
8.3 Zone III: Reach Setting
8.3.1 Base Impedance of the Transformer =
= 220^2 / 100
= 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)
= (75 x 0.41067 x 0.4)
= 12.3
8.3.5 Total Impedance of both Transformers & = 40.3 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)
= 63 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
8.3.7 Direction = Forward
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 75 x 0.079) + (71 x 0.079) ]
x 0.4)+ 0.312
5.162 Ω
8.3.9 Resistive Reach For Φ to E Faults, = { [(110% of Protected line length x R1) +
Resistive Reach for Ph to Earth Fault,RE(Z2)
Reactance Reach,
X(Z2)
Resistive Reach for Ph to Ph Fault,R(Z2)
Protected Length
Time Delay
KV2 / MVA
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RE(Z3) (100% of longest line x R1) ] x C.F } + Rt-e
[(1.1 x 75 x 0.079) + (71 x 0.079) ]
x 0.4)+ 9.783
14.633 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 75 x 0.403) + (71 x 0.403) ] x 0.4)
24.74
Ω
8.3.11 Time Delay: = 1 secs
Selected Setting: (110% PL+100% OF NEXT)
Zone Direction
Zone III 14.633 Forward 24.74 5.162 110% 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 2.208
= 0.55 Ω
8.4.3 =
= 0.25 x 11.508
= 2.88 Ω
8.4.4 Reactance Reach,X(Z4) = 0.25 * X(Z1)
= 0.25 x 9.672
= 2.42 Ω
8.4.5 Time Delay: = 1 secs
Selected Setting:
Zone Direction
Zone IV 2.877 Reverse 2.418 0.552 25% 1
Resistive Reach for Ph to Earth Fault,RE(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,RE(Z4): 0.25 x RE(Z1)
Resistive Reach for Ph to Earth Fault,RE(Z2)
Reactance Reach,
X(Z2)
Resistive Reach for Ph to Ph Fault,R(Z2)
Protected Length
Time Delay
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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 0.079 x 75 x 0.4) + 0.312
= 3.16 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 75 x 0.079 x 0.4 x 0.91)
+ 9.783
= 12.371 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 75 x 0.4
= 14.508 Ω
8.6.5 Time Delay = 0 secs
Selected Setting:
Zone Direction
Zone IB 12.37 Forward 14.51 3.16 120% 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,RE(ZIB)
Resistive Reach for Ph to Earth Fault,RE(Z2)
Reactance Reach,
X(Z2)
Resistive Reach for Ph to Ph Fault,R(Z2)
Protected Length
Time Delay
Uph-e>(>): Phase Voltage Stages
Uph-e> :
TUph-e> :
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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)
= 31.7552 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)
= 0.098415 ≈ 0.1 A
11.4 = Disabled
11.5 Direction = Forward
11.6 Curve = Normal Inverse
11.7 TMS = 0.34
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)
Uph-e>> :
TUph-e>> :
Uph-e>(>) RESET: Drop out to Pick Up Ratio
3 x KV2
Earth Fault Current Pick-up setting(3I0>>)
Zero Sequence Voltage Stage 3U0>
16 of 25
= 984 A
12.3 Setting adopted = 2.5 times FLC/ CTR I>>> 1.23 A
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400/220 KV WARANGAL SUBSTATION
220kV yyyyyyyyyy 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
610 Fault Display on LED / LCD Display Targets on TRIP only
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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
4 Settings groups
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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 78.91
1211 Angle of inclination, distance charact. 78.91
1107 P,Q operational measured values sign not reversed
1110 x' - Line Reactance per length unit 0.164268
1111 Line Length 53.0 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
No. Settings Value
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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. 78.91
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
1315 T2-1phase, delay for single phase faults 0.40 sec
Z1B enabled before 1st AR (int. or ext.)
19 of 25
1316 T2multi-ph, delay for multi phase faults 0.40 sec
1325 T3 delay 1.00 sec
1335 T4 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 2.208 Ohms
1303 X(Z1), Reactance 9.672 Ohms
1304 RE(Z1), Resistance for ph-e faults 11.508 Ohms
1305 T1-1phase, delay for single phase faults 0.00 sec
1306 T1multi-ph, delay for multi phase faults 0.00 sec
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 3.156 Ohms
1353 X(Z1B), Reactance 14.508 Ohms
1354 RE(Z1B), Resistance for ph-e faults 12.371 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
4.9 Group Distance zones (quadrilateral); Group Zone Z2
No. Settings Value
1311 Operating mode Z2 Forward
1312 R(Z2), Resistance for ph-ph-faults 3.519 Ohms
Z1B enabled before 1st AR (int. or ext.)
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1313 X(Z2), Reactance 16.362 Ohms
1314 RE(Z2), Resistance for ph-e faults 12.702 Ohms
1315 T2-1phase, delay for single phase faults 0.40 sec
1316 T2multi-ph, delay for multi phase faults 0.40 sec
1317A Single pole trip for faults in Z2 NO
4.10 Group Distance zones (quadrilateral); Group Zone Z3
No. Settings Value
1321 Operating mode Z3 Forward
1322 R(Z3), Resistance for ph-ph-faults 5.162 Ohms
1323 X(Z3), Reactance 24.740 Ohms
1324 RE(Z3), Resistance for ph-e faults 14.633 Ohms
1325 T3 delay 1.00 sec
4.11 Group Distance zones (quadrilateral); Group Zone Z4
No. Settings Value
1331 Operating mode Z4 Reverse
1332 R(Z4), Resistance for ph-ph-faults 0.552 Ohms
1333 X(Z4), Reactance 2.418 Ohms
1334 RE(Z4), Resistance for ph-e faults 2.877 Ohms
1335 T4 delay 1.00 sec
4.12 Group Distance zones (quadrilateral); Group Zone Z5
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
4.13 Group Power Swing
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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.
No. Settings Value
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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
3173 Trip time delay after SOTF 0.00 sec
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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
3120 Operating mode Inactive
3121 3I0>> Pickup N/A
3122 T 3I0>> Time Delay N/A
3123 Instantaneous trip via Teleprot./BI N/A
3124 Instantaneous trip after SwitchOnToFault N/A
3125 Inrush Blocking N/A
4.23 Group Earth fault overcurrent; Group 3I0>
No. Settings Value
3130 Operating mode Inactive
3131 3I0> Pickup N/A
3132 T 3I0> Time Delay N/A
3133 Instantaneous trip via Teleprot./BI N/A
3134 Instantaneous trip after SwitchOnToFault N/A
3135 Inrush Blocking N/A
4.24 Group Earth fault overcurrent; Group 3I0 InverseTime
No. Settings Value
3140 Operating mode Forward
3141 3I0p Pickup 0.10 A
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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
3411A Maximum dead time extension ∞sec
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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
3705 T Uph-e>> Time Delay 0.10 sec
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3709A Uph-e>(>) Reset ratio 0.95
4.31 Group Fault Locator
No. Settings Value
3802 Start fault locator with Pickup
3806 Load Compensation YES
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220kV yyyyyyyyyy 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 75 KM
3 Max power flow in the line (assumed) 150 MVA
4 Postive sequence resistance 0.079 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 53 KM
2 Postive sequence resistance 0.079 ohms/km
3 Postive sequence reactance 0.403 ohms/km
4 Zero sequence resistance 0.255 ohms/km
5 Zero sequence reactance 1.51 ohms/km
B.2 longest line
1 Length of longest line 71 KM
2 Postive sequence resistance 0.079 ohms/km
3 Postive sequence reactance 0.403 ohms/km
4 Zero sequence resistance 0.255 ohms/km
5 Zero sequence reactance 1.51 ohms/km
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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.
9 Postive sequence resistance at local end = line length x + ve seq. R 5.925 ohms
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10 Postive sequence reactance at local end = line length x +ve seq.X 30.225 ohms
11 Postive sequence resistance at remote end = line length x +ve seq. R 4.187 ohms
12 Postive sequence reactance at remote end = line length x +ve seq. X 21.359 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 = 2.370 ohms
2 Postive sequence reactance = line length x + ve seq. X x Imp Ratio = 12.090 ohms
3 Zero sequence resistance = line length x Z0 x Imp Ratio = 7.650 ohms
4 Zero sequence reactance = line length x Z0X x Imp Ratio = 45.300 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 = 1.675 ohms
2 Postive sequence reactance = line length x + ve seq. X x Imp Ratio = 8.544 ohms
3 Zero sequence resistance = line length x Z0 x Imp Ratio = 5.406 ohms
4 Zero sequence reactance = line length x Z0X x Imp Ratio = 32.012 ohms
I Longest Line Impedance in CT secondary
1 Postive sequence resistance = line length x + ve seq. R x Imp Ratio = 2.244 ohms
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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
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 75 x 0.079 x 0.4 1.896 ohms
2 Reach For Postive sequence reactance
(80% line length x Postive sequence reactance x Imp Ratio
=0.8 x 75 x 0.403 x 0.4 9.672 ohms
3 Reach For Zero sequence resistance
(80% line length x Zero sequence resistance x Imp Ratio
=0.8 x 75 x 0.255 x 0.4 6.120 ohms
4 Reach For Zero sequence reactance
(80% line length x Zero sequence reactance x Imp Ratio
=0.8 x 75 x 1.51 x 0.4 36.240 ohms
5 Fault Resistance - ph-e
= 1.896 + ( 9.672 x TAN ( 25 ) = 6.406
= 4.5 x 1.896 = 8.5320
= 50 x 0.4 = 20.000
Maximum of 6.406 and 20 = 20.000
Minimum of 8.532 and 20 = 8.532 ohms
Hence fault resistance between phase to earth = 8.532 ohms
6 Fault Resistance - ph-ph
= 1.896 + ( 9.672 x TAN ( 25 ) = 6.406
= 3 x 1.896 = 5.688
= 10 x 0.4 = 4.000
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Maximum of 6.406 and 4 = 6.406
Minimum of 5.688 and 6.406 = 5.688
Hence fault resistance between phase to phase =2 times of the above 11.376 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
=75 x 0.079 x 0.4 + 0.5 x 75 x 0.079 x 0.4 3.207 ohms
2 Reach For Postive sequence reactance
100% line length x Postive sequence reactance x Imp Ratio +
50% shortest line length x Postive sequence reactance x Imp Ratio
=75 x 0.403 x 0.4 + 0.5 x 75 x 0.403 x 0.4 16.362 ohms
3 Reach For Zero sequence resistance
100% line length x Zero sequence resistance x Imp Ratio +
50% shortest line length x Zero sequence resistance x Imp Ratio
=75 x 0.255 x 0.4 + 0.5 x 75 x 0.255 x 0.4 10.353 ohms
4 Reach For Zero sequence reactance
100% line length x Zero sequence reactance x Imp Ratio +
50% shortest line length x Zero sequence reactance x Imp Ratio
=75 x 1.51 x 0.4 + 0.5 x 75 x 1.51 x 0.4 61.306 ohms
5 Fault Resistance - ph-e 14.432 ohms
6 Fault Resistance - ph-ph 19.242 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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110% line length x Postive sequence resistance x Imp Ratio +
100% Longest line length x Postive sequence resistance x Imp Ratio
= 1.1 x 75 x 0.079 x 0.4 + 71 x 0.079 x 0.4 4.851 ohms
2 Reach For Postive sequence reactance
110% line length x Postive sequence reactance x Imp Ratio +
100% Longest line length x Postive sequence reactance x Imp Ratio
= 1.1 x 75 x 0.403 x 0.4 + 71 x 0.403 x 0.4 24.744 ohms
3 Reach For Zero sequence resistance
110% line length x Zero sequence resistance x Imp Ratio +
100% Longest line length x Zero sequence resistance x Imp Ratio
= 1.1 x 75 x 0.255 x 0.4 + 71 x 0.255 x 0.4 15.657 ohms
3 Reach For Zero sequence reactance
110% line length x Zero sequence reactance x Imp Ratio +
100% Longest line length x Zero sequence reactance x Imp Ratio
= 1.1 x 75 x 1.51 x 0.4 + 71 x 1.51 x 0.4 92.714 ohms
5 Fault Resistance - ph-e 20.000 ohms
6 Fault Resistance - ph-ph 29.104 ohms
M Power Swing Block Function
1
2 27.219
3 32.671
4 34.023
5 40.839
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
Reactive Reach of the Outer characteristic of the Power swing blocking element
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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) 2.370
6 Postive sequence reactance at local end in ohms(XISA) 12.090
7 Postive sequence resistance at remote end in ohms(R1SB) 1.675
8 Postive sequence reactance at remote end in ohms(X1SB) 8.544
O Phase Selection
1 X1Phs 49.488
2 X0Phs 185.428
3 Calculated RFPEphs 56.905
4 Calculated RFPPphs 49.701
5 104.544
6 RFPEphs 52.272
7 Conditions for 2nd Zone 35.158
8 Conditions for 4th Zone 5.003
9 Conditions for 3-ph fault 62.212
10 RFPPphs 49.701
11.288 16.746
Zloadmin =(KV)2\MVA
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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 9.672
Positive sequence reactance of zone 1 for ph-ph fault R1PP 1.896
Resisitive reach of distance protection for ph-ph faults RFPP 11.376
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 9.672
Positive sequence resistive reach of distance zone 1 for ph-E fault R1PE 1.896
XOPE 36.240
ROPE 6.120
Resisitive reach for zone 1 Ph-E faults RFPE 8.532
Timer t1PP On
t1PE 0.000
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
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
Time delayed trip operation for the distance protection zone 1 for ph-ph faults
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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 16.362
Positive sequence reactance of zone 2 for ph-ph fault R1PP 3.207
Resisitive reach of distance protection for ph-ph faults RFPP 19.242
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 16.362
Positive sequence resistive reach of distance zone 2 for ph-E fault R1PE 3.207
XOPE 61.306
ROPE 10.353
Resisitive reach for zone 2 Ph-E faults RFPE 14.432
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 24.744
Positive sequence resistance of zone 3 for phase to phase faults R1PP 4.851
Positive reach of distance protectin for phase to phase faults RFPP 29.104
Operating mode of time delayed trip for the distance protection zone 2 for ph-ph faults
Time delayed trip operation for the distance protection zone 2 for ph-ph faults
Zero sequence line reactance included in distance protection zone 2 for Ph-E 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
Time delayed trip operation for the distance protection zone 2 for ph-ph faults
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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 24.744
Positive sequence resistive reach of distance zone 3 for Ph-E faults R1PE 4.851
X0PE 92.714
R0PE 10.353
Resistive reach for zone 3 for Ph-E faults RFPE 20.000
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 24.744
Resistive reach for ph-ph loop measurement RFPP 29.104
positive sequence reactive reach for ph-e loop measurement X1PE 24.744
Zero sequence reactive for ph-e loop measurement XOPE 92.714
Resistive reach for ph-e loop measurement RFPE 20.000
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 27.219
positive sequence reactive reach of the inner boundary R1IN 32.671
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 faultsZero 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 faultsTime delayed trip operation of the distance protection zone 3 for Ph-E faults
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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
Operating phase current as a% IP> 0.100
Time delay T 0.200
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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 75.000
Positive sequence reactance of line X1 30.225
Positive sequence resistance of line R1 5.925
zero sequence reactance of line X0 113.250
Zero sequence resistance of line R1 19.125
Positive sequence reactance of source at local end X1SA 30.225
Positive sequence resistance of source at local end R1SA 5.925
Positive source reactance at remote end X1SB 21.359
Positive source resistance at remote end R1SB 4.187
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
**settings done in menu:configuration-analogue inputs-u1,u2 etc
SYNCRO CHECK AND ENERGISATION CHECK FUNCTIONS:
Operation of syncro check function Operation On
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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
Manual energising time T manenerg 0.200