voltech engineers relay setting calculation
DESCRIPTION
VOLTECH ENGINEERS Relay Setting CalculationTRANSCRIPT
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MAKE MODEL
3.1. Non Directional Overcurrent and Earth Fault Protection for 132/33kV Transformer(40MVA)
CT DetailsCT Ratio = 800-400/1 ACT Primary = 400 ACT Secondary = 1 AClass = PS
Transformer Data:Rated power = 40 MVARated HV Voltage = 132.00 kVRated LV Voltage = 33.00 kVFull Load current HV Side = 174.96 AFull Load current LV Side = 699.84 AImpedence = 0.138 13.80%
Phase Over current settingO/C SETTING (51):
Load current I load = 174.96 ACT secondary current, = i Load / CT ratio
= 0.44Consider 110% of transformer Full load = 192.46 PrimaryPickup Phase fault Secondary , recommended = 0.48 SecondaryTime Multiplier SettingCharacteristics = IDMT Normal inverset Required operating time in seconds =
= 0.68Minimum Fault current = 2970.00 AI Fault current at secondary = I fault / CT ratio
7.43 ATMS = (t *((If/IS)0.02 -1)) /0.14
= (0.68*(((7.43/0.5)^0.02)-1))/0.14)= 0.27
Maximum fault Current = 28280.00 A70.70
Operating time at Maximum fault Current = 0.37 SecInstantaneous Phase Overcurrent Setting
= 1648.17 A= 4.12 A
t = 0.30 Sec
Earth Over current setting HV side= 80.00 A Primary= I earth fault / CT ratio
Setting of 20% is selected = (80/400)= 0.20 A Secondary
Time Multiplier SettingCHARACTERISTICS = IDMT Normal inverset Required operating time in seconds =
= 0.77Fault current = 3720.00 AI Fault current at secondary = I fault / CT ratio
9.30TMS = (t *((If/IS)0.02 -1)) /0.14
= (0.77*(((9.3/0.2)^0.02)-1))/0.14)= 0.44
Maximum through fault Current = 28990.00 A Primary= 72.48 A Secondary
Operating time at Maximum fault Current = 0.488 SecInstantaneous Earth Overcurrent SettingFor High set considering the 200% of CT Primary Current = 800.00 A
= 2.00 At = 0.35 Sec
Calculated
VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE 16.09.13
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL) PRPD: MN
TITLE: SETTING CALCULATION FOR 132/33kV TRANSFORMER(40MVA) CKD: GP
RELAY GE F650 BAY/FEEDER 132/33kV,40 MVA Trafo 132kV Side
The relay setting shall be such that it shall not operate for max. probable load current
grading time + Downstream relay operating timeMinimum grading time interval considered
in secFrom ETAP
For High set considering the 130% of Through Fault current in HV Side
Calculated
In solidly earthed system a setting of 10 to 20% of CT Primary current is considered
From ETAP
grading time + Downstream relay operating timeMinimum grading time interval considered
in secFrom ETAP
Page 21 of 160
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MAKE MODEL
VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE 16.09.13
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL) PRPD: MN
TITLE: SETTING CALCULATION FOR 132/33kV TRANSFORMER(40MVA) CKD: GP
RELAY GE F650 BAY/FEEDER 132/33kV,40 MVA Trafo 132kV Side
Setting Table:
1 Degree
1 V
0.01 A
0.01 S
1 Degree
1 V
0.01 A
0.01 S
1 Degree
1 V
0.01 A
0.01 S
1 Degree
1 V
0.01 A
0.01 S
0 900
F650
GROUP-1 Directional Earth Overcurrent- 67N
MENU TEXT RECOMMEND SETTINGSETTING RANGE
STEP SIZE UNITMINIMUM MAXIMUM
F650
GROUP-1 Directional Phase Overcurrent- 67
MENU TEXT RECOMMEND SETTINGSETTING RANGE
STEP SIZE UNITMINIMUM MAXIMUM
Phase Overcurrent
Function EnabledMTA 45 -90 90
Enabled/Disabled
Direction Forward Forward/Reverse
F650
Curve IEC Normal Inv
Pickup Level 0.48 160
Time Dial Multiplier 0.3 0 900
Pol V Threshold 40.00 0 300
0.05
MTA 45
GROUP-1 Directional Phase Overcurrent- 67 INST
MENU TEXT RECOMMEND SETTINGSETTING RANGE
STEP SIZE UNITMINIMUM MAXIMUM
Phase Overcurrent
Function Enabled Enabled/Disabled
-90 90
Function Enabled Enabled/DisabledPhase Overcurrent
Direction Forward
Pol V Threshold 40.00
Forward/Reverse
0
MTA -45
Pickup Level 0.2 0.05 160
Curve IEC Normal Inv
300
Time Dial Multiplier 0.44
-90 90
Direction Forward Forward/Reverse
Curve Definite Time
Time Dial Multiplier
Pol V Threshold 40.00 0 300
Pickup Level 4.12 0.05 160
0.30 0 900
F650
GROUP-1 Directional Earth Overcurrent- 67N INST
MENU TEXT RECOMMEND SETTINGSETTING RANGE
STEP SIZE UNITMINIMUM MAXIMUM
Phase Overcurrent
Function Enabled Enabled/DisabledMTA -45 -90 90Direction Forward Forward/Reverse
Pol V Threshold 40.00 0 300
Pickup Level 2.0 0.05 160
Curve Definite Time
Time Dial Multiplier 0.35 0 900
Page 22 of 160
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3.2. Directional Overcurrent and Earth Fault Protection for 132kV Side of 220/132kV Transformer(160MVA)
CT DetailsCT Ratio = 800-400/1 ACT Primary = 800 ACT Secondary = 1 AClass = PS
Transformer Data:Rated power = 160 MVARated HV Voltage = 220.00 kVRated LV Voltage = 132.00 kVFull Load current HV Side = 419.90 AFull Load current LV Side = 699.84 A
Phase Over current settingO/C SETTING (51):
Load current I load = 699.84 ACT secondary current, = i Load / CT ratio
= 0.87Consider 110% of transformer Full load = 769.82 PrimaryPickup Phase fault Secondary , recommended = 0.96 Secondary
Time Multiplier SettingCharacteristics = IDMT Normal inverse
t Required operating time in seconds =
= 0.70
Fault current = 3890.00 AI Fault current at secondary = I fault / CT ratio
4.86 ATMS = (t *((If/IS)0.02 -1)) /0.14
= (0.7*(((4.86/1)^0.02)-1))/0.14)= 0.17
Instantaneous Phase Overcurrent Setting= 7581.59 A= 9.48 A
t = 0.50 Sec
Earth Over current setting HV side = 160.00 A Primary= I earth fault / CT ratio
Setting of 20% is selected = (160/800)= 0.20 A Secondary
Time Multiplier SettingCHARACTERISTICS = IDMT Normal inverse
t Required operating time in seconds =
= 0.72
Fault current = 1400.00 A AI Fault current at secondary = I fault / CT ratio
1.75TMS = (t *((If/IS)0.02 -1)) /0.14
= (0.72*(((1.75/0.2)^0.02)-1))/0.14)= 0.2
Instantaneous Earth Overcurrent Setting1310.00
For High set considering the 200% of CT Primary Current = 1965.00 A= 2.46 A
t = 0.60 Sec
grading time + Downstream relay operating timeMinimum grading time interval considered
in sec
From ETAP
grading time + Downstream relay operating timeMinimum grading time interval considered
in sec
From ETAP
For High set considering the 130% of Through Fault current in HV Side
From ETAP
In solidly earthed system a setting of 10 to 20% of CT Primary current is considered
RELAY GE F650 BAY/FEEDER 220/132kV,160 MVA Trafo 132kV Side
The relay setting shall be such that it shall not operate for max. probable load current
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL) PRPD: MN
TITLE: SETTING CALCULATION FOR 132kV SIDE TRANSFORMER(160MVA) CKD: GP
VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE 16.09.13
Page 23 of 160
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MAKE MODELRELAY GE F650 BAY/FEEDER 220/132kV,160 MVA Trafo 132kV Side
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL) PRPD: MN
TITLE: SETTING CALCULATION FOR 132kV SIDE TRANSFORMER(160MVA) CKD: GP
VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE 16.09.13
Setting Table:
1 Degree
1 V
0.01 A
0.01 S
1 Degree
1 V
0.01 A
0.01 S
1 Degree
1 V
0.01 A
0.01 S
1 Degree
1 V
0.01 A
0.01 S
Forward/Reverse
0 300
0 900
F650
GROUP-1 Directional Earth Overcurrent- 67N INST
Direction
F650
GROUP-1 Directional Earth Overcurrent- 67N
MENU TEXT RECOMMEND SETTINGSETTING RANGE
STEP SIZE UNITMINIMUM MAXIMUM
F650
GROUP-1 Directional Phase Overcurrent- 67 INST
MENU TEXT RECOMMEND SETTINGSETTING RANGE
STEP SIZE UNITMINIMUM MAXIMUM
Phase Overcurrent
Function Enabled Enabled/DisabledMTA 45 -90 90Direction Forward Forward/Reverse
900
Pol V Threshold 40.00 0 300
Pickup Level 9.48 0.05 160
MENU TEXT RECOMMEND SETTINGSETTING RANGE
STEP SIZE UNITMINIMUM MAXIMUM
Phase Overcurrent
Function Enabled Enabled/DisabledMTA -45 -90 90Direction Forward Forward/Reverse
Pol V Threshold 40.00 0 300
Pickup Level 2.5 0.05 160
Curve Definite Time
Time Dial Multiplier 0.60 0 900
0.05 160
Curve IEC Normal Inv
Time Dial Multiplier 0.23
Forward
Pol V Threshold 40.00
Pickup Level 0.2
MTA -45 -90 90Function Enabled Enabled/DisabledPhase Overcurrent
Time Dial Multiplier 0.17 0 900
Curve Definite Time
Time Dial Multiplier 0.50 0
Curve IEC Normal Inv
Pickup Level 0.96 0.05 160
Pol V Threshold 40.00 0 300
Direction Forward Forward/Reverse
MTA 45 -90 90Enabled/Disabled
Phase Overcurrent
Function Enabled
MINIMUM MAXIMUMSTEP SIZE UNITMENU TEXT RECOMMEND SETTING
SETTING RANGE
F650
GROUP-1 Directional Phase Overcurrent- 67
Page 24 of 160
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3.3. Directional Overcurrent and Earth Fault Protection for 132kV Line
CT DetailsCT Ratio = 800-400/1 ACT Primary = 400 ACT Secondary = 1 AClass = PS
Phase Over current settingO/C SETTING (51):
Load current I load = 400 ACT secondary current, = i Load / CT ratio
= 1.00Consider 110% of transformer Full load = 400.00 PrimaryPickup Phase fault Secondary , recommended = 1.00 Secondary
Time Multiplier SettingCharacteristics = IDMT Normal inverse
t Required operating time in seconds =
= 0.65
Fault current = 1940 AI Fault current at secondary = I fault / CT ratio
4.85 ATMS = (t *((If/IS)0.02 -1)) /0.14
= (0.65*(((4.85/1)^0.02)-1))/0.14)= 0.15
Earth Over current setting HV side
= 80.00 A Primary= I earth fault / CT ratio
Setting of 20% is selected = (80/400)= 0.20 A Secondary
Time Multiplier SettingCHARACTERISTICS = IDMT Normal inverse
t Required operating time in seconds =
= 0.65
Fault current = 2390 AI Fault current at secondary = I fault / CT ratio
5.98TMS = (t *((If/IS)0.02 -1)) /0.14
= (0.65*(((5.98/0.2)^0.02)-1))/0.14)= 0.33
VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE 16.09.13
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL) PRPD: MN
TITLE: SETTING CALCULATION FOR 132kV LINE CKD: GP
RELAY GE F650 BAY/FEEDER 132kV Line
The relay setting shall be such that it shall not operate for max. probable load current
grading time + Zone-2 operating timeMinimum grading time interval considered in sec
From ETAP
In solidly earthed system a setting of 10 to 20% of CT Primary current is considered
grading time + Downstream relay operating timeMinimum grading time interval considered
in sec
From ETAP
Page 25 of 160
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MAKE MODEL
VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE 16.09.13
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL) PRPD: MN
TITLE: SETTING CALCULATION FOR 132kV LINE CKD: GP
RELAY GE F650 BAY/FEEDER 132kV Line
Setting table
1 Degree
1 V
0.01 A
0.01 S
1 Degree
1 V
0.01 A
0.01 S0 900
160
F650
GROUP-1 Directional Earth Overcurrent- 67N
MENU TEXT RECOMMEND SETTINGSETTING RANGE
STEP SIZE UNITMAXIMUM
GROUP-1 Directional Phase Overcurrent- 67
STEP SIZE UNIT
F650
Phase Overcurrent
Function Enabled
MINIMUM MAXIMUM
Enabled/Disabled
MENU TEXT RECOMMEND SETTINGSETTING RANGE
90
300
Direction Forward Forward/ReversePol V Threshold 40.00 0
MTA 45.00 -90
Function
Curve IEC Normal InvPickup Level 1.00 0.05
MINIMUM
0
Time Dial Multiplier 0.15 0 900
Phase Overcurrent
MTA -45.00 -90 90
Curve
Enabled Enabled/Disabled
Direction ForwardPol V Threshold 40.00
Forward/Reverse
IEC Normal Inv
300
Time Dial Multiplier 0.33
Pickup Level 0.20 0.05 160
Page 26 of 160
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3.4. Distance Protection for 132kV-30KM Line
System Details for 220kV lineNominal system voltage,UN = 132000V 132000 VCurrent transformer ratio,Nct = 400/1A 400.0Voltage transformer ratio,Nvt = 132000/110 1200.0Ratio of secondary to primary impedance,Nct/Nvt =Protected OHL Type =Current rating in Amps = Considered CT RatioProtected OHL length = KMPositive seq.Resistance of OHL in , per kM, Rprim =Positive seq.Reactance of OHL in , per kM, Xprim =Positive seq.impedance of OHL in , per kM, Zprim = 0.463 68.8 O
Zero seq.Resistance of OHL in , per kM, Rprim =Zero seq.Reactance of OHL in , per kM, Xprim =Zero seq.impedance of OHL in , per kM, Zprim = 0.743 56.9 O
Adjacent Longest Line detailsProtected OHL length = KMPositive seq.Resistance of OHL in , per kM, Rprim =Positive seq.Reactance of OHL in , per kM, Xprim =Positive seq.impedance of OHL in , per kM, Zprim = 0.463 68.8 O
Zero seq.Resistance of OHL in , per kM, Rprim =Zero seq.Reactance of OHL in , per kM, Xprim =Zero seq.impedance of OHL in , per kM, Zprim = 0.743 56.9 O
Adjacent Shortest Line detailsProtected OHL length = KMPositive seq.Resistance of OHL in , per kM, Rprim =Positive seq.Reactance of OHL in , per kM, Xprim =Positive seq.impedance of OHL in , per kM, Zprim = 0.46 68.8 O
Zero seq.Resistance of OHL in , per kM, Rprim =Zero seq.Reactance of OHL in , per kM, Xprim =Zero seq.impedance of OHL in , per kM, Zprim = 0.74 56.9 O
PT Details:PT Ratio = 132000/110 V
PT Primary Voltage = 132000.0 VPT Secondary Voltage = 110.0 V
System Frequency = 50.0 HZ
Distance element Settings:Reactance settingsZone 1 SettingsRequired Zone 1 reach is to be 85% of the Protected line
X1prim = 85% * Xprim = 11.02X1sec = Nct/Nvt * Xprim = 3.67
Zone 2 SettingsZone 2 element setting with a reach of 120% of Protected line reactance accounts for effect of infeed.This point must be verified using a fault study to calculate the apparent ohms at the local terminal for a fault at the remote end of transmission line. In our case 120% is considered for the zone-2 elements with assurance that all faults in the protected line are detectable,even with infeed from remote terminals.
Assuming the zone-1 reach for the adjacent line protection is set at 85% of that line reactance, and it is to be verified such that the zone-2 reach of 120%(protected line) shall not extend beyond the max.effective zone-1 reach of the adjacent line protection.Zone-2 setting limit = Protected line reactance +
0.85 * adjacent shortest line reactance= 5.67
Zone-2 setting with 120% reach = 5.18Since 120%, 5.18 is lower than zone-2 limit. 5.67, so the zone-2 setting of 120% will not overreach beyond zone-1 settingof adjacent line protection. Therefore we consider 120% of protected line reactance
Hence set X2 prim = 15.55Hence set X2 sec = 5.18
11.000.1670.432
VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL)
16.09.13
PRPD:
0.622
MN
TITLE: SETTING CALCULATION FOR 132kV LINE PROTN(30KM) CKD: GP
RELAY GE D60 BAY/FEEDER
0.1670.432
0.33ACSR PANTHER
400.030.0
132kV Line-30KM
0.1670.432
0.4060.622
0.4060.622
22.80
0.406
Page 27 of 160
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VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL)
16.09.13
PRPD: MN
TITLE: SETTING CALCULATION FOR 132kV LINE PROTN(30KM) CKD: GP
RELAY GE D60 BAY/FEEDER 132kV Line-30KM
Zone 3 SettingsFor Zone3 setting , it is customery to select 1.2 (Protected line + 50% Adjacent Longest line)
X3prim, reach = 21.46X3sec = Nct/Nvt * X3prim*IN/A = 7.15
Zone 4 SettingsFor Zone4 setting, reverse reach impedence is typically 20% Zone 1 reach Impedance.
X4prim, reach = 2.20X4sec = Nct/Nvt * X4prim*IN/A = 0.73
Resistance settingsFor resistance setting of OHL, consideration of AC resistance is most important. Also tower footing resistance shall be accounted in the calculation.
Resistive Reach CalculationsMinimum Load impedence to the relay = Vn (phase - neutral) / In
= (110/3/1)
= 63.51
= 38.11 secondary
= 50.81 secondary
Ra = (28710 x L) / If^1.4
Where:If = Minimum expected phase-phase fault current (A);L = Maximum phase conductor separation (m);
Ra =
fault current = 3.89 kAConductor spaces = 2.7 mtrs
= 0.73
(RARC is = 1.325 RTFT Tower Foot Resistance = 10
Zone-1 setting(same way as done above for X reach)R1 sec = R1sec + 0.5RARC+ RTFT = 4.98
Zone-2 setting(same way as done above for X reach)R2 sec = R2sec + 0.5RARC+ RTFT = 5.56
Zone-3 setting(same way as done above for X reach)R3 sec = R3sec + 0.5RARC+ RTFT = 6.33
Zone-4 setting(same way as done above for X reach)R4 sec = R4sec + 0.5RARC+ RTFT = 3.84
Time setting Zone-1 setting = 0.00 secZone-2 setting zone-2 time delay should be set to discreminative with the primary line protection of the next line sections including circuit breaker trip time
Adjoining line protection operating time = 0.040Breaker opening time = 0.080
Local relay reset = 0.030Grading margin = 0.250
Required zone-2 time delay = 0.40set zone-2 at = 0.40 sec
Zone-3 setting zone-3 time delay shall be such that zone-2 time delay plus grading margin
zone-2 time delay = 0.400Grading margin = 0.400
Required zone-3 time delay = 0.80set zone-3 at = 0.80 sec
Typically,phase fault distance zones would avoid the minimum load impedence by a margin of 40%,earth fault zones would use a 20% margin.
This allows maximum resistive reaches for Phase faults
This allows maximum resistive reaches for Earth faults
Arc resistance, calculated from the van Warrington formula (W).
Primary resistive coverage for phase faults
Page 28 of 160
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VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL)
16.09.13
PRPD: MN
TITLE: SETTING CALCULATION FOR 132kV LINE PROTN(30KM) CKD: GP
RELAY GE D60 BAY/FEEDER 132kV Line-30KM
Zone-4 setting zone-4 might be used to provide back up protection for the local bus bar. zone-4 time delay shall be such that LBB time delay plus grading margin
LBB time delay = 0.200Grading margin = 0.250
Required zone-4 time delay = 0.45set zone-4 at = 0.50 sec
Earth Impedance matching factor for Zone-1,2,3 & 4RE/RL = 1/3 (R0/R1 -1) = 0.48XE/XL = 1/3 (X0/X1 -1) = 0.15
R0-R1 = 0.24X0-X1 = 0.19Z0-Z1 = 0.31 38.53 O
Z0/Z1 MAG & ANGLE= (Z0-Z1)/3Z1 = 0.22 -30.29 OWhere R1 is +ve seq. resistance of protected lineR0 is zero seq. resistance of protected lineX1 is +ve seq. reactance of protected lineX0 is zero seq. reactance of protected line
Load impedance valueRload prim = Umin/3*ILmax
Where Umin = minimum operating voltage, 0.9*UN = 118800
ILmax = max load current = 400.000Hence Rload prim = 171.48
Rload sec = 57.16
The above is calculated for ph to earth and for ph to ph it is same value because current is multiplied by 3 PHI load , maximum load angle As load current ideally is in phase with the voltage, the difference is indicated with the power factor cos. The largest angle of the load impedance is therefore given by the worst, smallest powerfactor. We considered the worst power factor under full load condition is 0.9.
load- max = cos -1(power factor min)load- max = cos-1 (0.9)load- max = 26.00 O
Power Swing Detection:The power swing detect element provides both power swing blocking and out-of-step tripping functions.
Power swing Shape, = QUADPower swing Mode, = Two step
Power swing Supervision, = 0.600 pu (typical setting from manual)Power swing Forward Reach(inner) = 7.15
(considered zone-3 reactance boundary)Power swing Forward RCA = 68.8 O
Power swing Forward Reach(outer) = 8.58 (120% of inner Reach)
Power swing Reverse Reach(inner) is considered as 50% zone-3 Reactance Reach + zone-4 Reactance Reach Power swing Reverse Reach(inner) = 4.31 Power swing Reverse Reach(outer) = 5.17
(120% of Reverse inner Reach)Power swing inner Right blinder = 6.33
(considered zone-3 resistive boundary)Power swing outer Right blinder = 7.59
(120% of inner Right blinder)Power swing inner Left blinder = 6.33
(considered zone-3 resistive boundary)Power swing outer Left blinder = 7.59
(120% of inner Left blinder)
VT Fuse failFunction enabled
The setting shall be applied 30% lower than calculated above = 40.01
Page 29 of 160
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VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL)
16.09.13
PRPD: MN
TITLE: SETTING CALCULATION FOR 132kV LINE PROTN(30KM) CKD: GP
RELAY GE D60 BAY/FEEDER 132kV Line-30KM
Broken Conductor Protection Full load current = 400.000 A
Considered I2 = 40.00 A (10% of fullload current)I2 / I1 = 0.10
Allow for tolerences and load varations = 200%I2 / I1 = 20.00 %
time delay = 5.00 s
Auto Reclosure:This autoreclose can be single pole tripping for single phase faults and three phase tripping for multi-phase faults.1 pole:In this mode, the recloser starts the AR-1P DEAD TIME for the first shot if the fault is single phase.If the fault is three phase or three pole trip occurred on the breaker during single initiation, the scheme goes to lockout with out reclosing.
AR Mode, = 1 poleAR Max Number of Shots, = 1.00AR Close Time Breaker 1, = 0.20 s
AR Block Time Upon Man Cls. = 10.00 sAR Reset Time, = 25.00 s
AR Breaker1 Fail Option, = LockoutAR Incomplete Sequence Time, = 2.00 s
AR 1-P Dead Time, 1.00 sAR Breaker Sequence, = 1.00
Local Breaker Backup ProtectionIn general, a breaker failure scheme determines that a breaker signaled to trip has not cleared a fault with in a definite time, so further tripping action must be performed.
BF1 MODE, = 3-PoleBF1 SOURCE, = SRC1
BF1 USE AMP SUPV, = YesBF1 USE SEAL-IN, = Yes
BF1 PH AMP SUPV, = 0.20 puBF1 N AMP SUPV, = 0.20 puBF1 USE TIMER1, = Yes
BF1 TIMER1 PICKUP DELAY, = 0.20 SBF1 TRIP DROPOUT = 0.00 S
Setting Recommendation for UVPT Ratio =
=Under voltage =
= v 90% OF Rated VoltageSelect Under voltage setting, 27 =
= V pu
Time delay setting , 27 = s
132000/1101200.00
0.90*Nominal Volt118800
118800/120099.0000.903.00
Page 30 of 160
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MAKE MODEL
VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL)
16.09.13
PRPD: MN
TITLE: SETTING CALCULATION FOR 132kV LINE PROTN(30KM) CKD: GP
RELAY GE D60 BAY/FEEDER 132kV Line-30KM
Settings Table
Line LengthPHASE DIST Z1 DIRPHASE DIST SHAPEPHS DIST Z1 REACHPHS DIST Z1 RCAPHS DIST Z1 COMP LIMITPHS DIST Z1 DIR RCAPHS DIST Z1 DIR COMP LIMITPHS DIST Z1 QUAD RGT BLDPHS DIST Z1 QUAD RGT BLD RCAPHS DIST Z1 QUAD LFT BLDPHS DIST Z1 QUAD LFT BLD RCAPHASE DIST Z1 DELAYPHS DIST Z1 SUPV
PHASE DIST Z2 DIRPHASE DIST SHAPEPHS DIST Z2 REACHPHS DIST Z2 RCAPHS DIST Z2 COMP LIMITPHS DIST Z2 DIR RCAPHS DIST Z2 DIR COMP LIMITPHS DIST Z2 QUAD RGT BLDPHS DIST Z2 QUAD RGT BLD RCAPHS DIST Z2 QUAD LFT BLDPHS DIST Z2 QUAD LFT BLD RCAPHASE DIST Z2 DELAY
PHASE DIST Z3 DIRPHASE DIST SHAPEPHS DIST Z3 REACHPHS DIST Z3 RCAPHS DIST Z3 COMP LIMITPHS DIST Z3 DIR RCAPHS DIST Z3 DIR COMP LIMITPHS DIST Z3 QUAD RGT BLDPHS DIST Z3 QUAD RGT BLD RCAPHS DIST Z3 QUAD LFT BLDPHS DIST Z3 QUAD LFT BLD RCAPHASE DIST Z3 DELAY
PHASE DIST Z4 DIRPHASE DIST SHAPEPHS DIST Z4 REACHPHS DIST Z4 RCAPHS DIST Z4 COMP LIMITPHS DIST Z4 DIR RCAPHS DIST Z4 DIR COMP LIMITPHS DIST Z4 QUAD RGT BLDPHS DIST Z4 QUAD RGT BLD RCAPHS DIST Z4 QUAD LFT BLDPHS DIST Z4 QUAD LFT BLD RCAPHASE DIST Z4 DELAY
Menu text Recommended SettingPHASE DISTANCE ELEMENTS Setting UnitLine setting
30.00 kmForward
Quadrilateral3.67 68.82 DEG90.00 DEG68.82 DEG90.00 DEG4.98 68.82 DEG4.98 68.82 DEG0.00 S0.34 pu
ForwardQuadrilateral
5.18 68.82 DEG90.00 DEG68.82 DEG90.00 DEG5.56 68.82 DEG5.56 68.82 DEG0.40 S
ForwardQuadrilateral
7.15 68.82 DEG90.00 DEG68.82 DEG90.00 DEG6.33 68.82 DEG6.33 68.82 DEG0.80 S
ReverseQuadrilateral
0.73 68.82 DEG90.00 DEG68.82 90.00 DEG6.33 68.82 DEG6.33 68.82 DEG0.50 S
Page 31 of 160
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MAKE MODEL
VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL)
16.09.13
PRPD: MN
TITLE: SETTING CALCULATION FOR 132kV LINE PROTN(30KM) CKD: GP
RELAY GE D60 BAY/FEEDER 132kV Line-30KM
GND DIST Z1 DIRGND DIST SHAPEGND DIST Z1 REACHGND DIST Z1 RCAGND DIST Z1 COMP LIMITGND DIST Z1 DIR RCAGND DIST Z1 DIR COMP LIMITGND DIST Z1 QUAD RGT BLDGND DIST Z1 QUAD RGT BLD RCAGND DIST Z1 QUAD LFT BLDGND DIST Z1 QUAD LFT BLD RCAGND DIST Z1 DELAYGND DIST Z1 Z0/Z1 MAGGND DIST Z1 Z0/Z1 ANG
GND DIST Z2 DIRGND DIST SHAPEGND DIST Z2 REACHGND DIST Z2 RCAGND DIST Z2 COMP LIMITGND DIST Z2 DIR RCAGND DIST Z2 DIR COMP LIMITGND DIST Z2 QUAD RGT BLDGND DIST Z2 QUAD RGT BLD RCAGND DIST Z2 QUAD LFT BLDGND DIST Z2 QUAD LFT BLD RCAGND DIST Z2 DELAYGND DIST Z2 Z0/Z1 MAGGND DIST Z2 Z0/Z1 ANG
GND DIST Z3 DIRGND DIST SHAPEGND DIST Z3 REACHGND DIST Z3 RCAGND DIST Z3 QUAD RGT BLDGND DIST Z3 QUAD RGT BLD RCAGND DIST Z3 QUAD LFT BLDGND DIST Z3 QUAD LFT BLD RCAGND DIST Z3 DELAYGND DIST Z3 Z0/Z1 MAGGND DIST Z3 Z0/Z1 ANG
GND DIST Z4 DIRGND DIST SHAPEGND DIST Z4 REACHGND DIST Z4 RCAGND DIST Z4 QUAD RGT BLDGND DIST Z4 QUAD RGT BLD RCAGND DIST Z4 QUAD LFT BLDGND DIST Z4 QUAD LFT BLD RCAGND DIST Z4 DELAYGND DIST Z4 Z0/Z1 MAGGND DIST Z4 Z0/Z1 ANG
LOAD ENCROACHMENTLOAD ENCROACHMENT MIN VOLTLOAD ENCROACHMENT REACHLOAD ENCROACHMENT ANGLELOAD ENCROACHMENT PKP DELAYLOAD ENCROACHMENT RST DELAY
Menu text Recommended SettingPHASE DISTANCE ELEMENTS Setting UnitLine setting
ForwardQuadrilateral
3.67 68.82 DEG90.00 DEG68.82 DEG90.00 DEG4.98 68.82 DEG4.98 68.82 DEG0.00 S0.22
-30.29 DEG
ForwardQuadrilateral
5.18 68.82 DEG90.00 DEG68.82 DEG90.00 DEG5.56 68.82 DEG5.56 68.82 DEG0.40 S0.22
-30.29 DEG
ForwardQuadrilateral
7.15 68.82 DEG6.33 68.82 DEG6.33 68.82 DEG0.80 S0.22
-30.29 DEG
ReverseQuadrilateral
0.73 68.82 DEG6.33 68.82 DEG6.33 68.82 DEG0.50 S0.22
-30.29 DEG
0.25 pu40.01 26.00 DEG0.00 S0.00 S
Page 32 of 160
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MAKE MODEL
VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL)
16.09.13
PRPD: MN
TITLE: SETTING CALCULATION FOR 132kV LINE PROTN(30KM) CKD: GP
RELAY GE D60 BAY/FEEDER 132kV Line-30KM
POWER SWING DETECTPOWER SWING SHAPEPOWER SWING MODEPOWER SWING SUPVPOWER SWING FWD REACHPOWER SWING QUAD FWD REACH OUTPOWER SWING FWD RCAPOWER SWING REV REACHPOWER SWING QUAD REV REACH OUT POWER SWING OUTER RGT BLDPOWER SWING OUTER LFT BLDPOWER SWING INNER RGT BLDPOWER SWING INNER LFT BLDPOWER SWING PICKUP DELAY1 POWER SWING RESET DELAY1 POWER SWING PICKUP DELAY2 POWER SWING PICKUP DELAY3POWER SWING PICKUP DELAY4 POWER SWING SEAL IN DELAYPOWER SWING TRIP MODE
PHASE IOC LINE PICKUPLINE UV PICKUPLINE END OPEN PICKUP DELAYLINE END OPEN RESET DELAYLINE OV PICKUP DELAYAR COORDINATION BYPASSAR COORDINATION PICKUP DELAYAR COORDINATION RESET DELAYLINE PICKUP DISTANCE TRIP
FUNCTION
FUNCTIONAR MODEMAX NUMBER OF SHOTSAR CLOSE TIME BKR1AR BLK TIME UPON MAN CLSAR RESET TIME AR BKR1 FAIL OPTIONAR INCOMPLETE SEQ TIMEAR 1-P DEAD TIME AR BKR1 SEQUENCE
FUNCTIONBR1 MODEBF1 SOURCEBF1 USE AMP SUPVBF1 USE SEAL-INBF1 PH AMP SUPV PICKUPBF1 N AMP SUPV PICKUPBF1 USE TIMER1BF1 TIMER1 PICKUP DELAYBF1 TRIP DROPOUT
TAP LEVEL IN PERCENTAGE OF I2/I1TRIP TIME
PHASE UV1 FUNCTIONPHASE UV1 MODEPHASE UV1 PICKUPPHASE UV1 DELAY
Menu text Recommended SettingPHASE DISTANCE ELEMENTS Setting Unit
QuadrilateralTwo Step
0.60 pu7.15 8.5868.82 DEG4.31 5.17 7.59 7.59 6.33 6.33 0.03 S0.05 S0.02 S0.01 S0.02 S0.40 S
Delayed SLINE PICKUP (SOTF)
1.00 pu0.70 pu0.15 S0.09 S0.04 S
Enabled0.05 S0.01 S
EnabledFUSE FAILURE
EnabledAUTO RECLOSE
Enabled1 pole1.000.20 S10.00 S25.00 S
Lockout2.00 S1.00 S1.00
BREAKER FAILURE 1Enabled3-PoleSRC1YesYes0.20 pu0.20 puYes0.20 S0.00 S
BROKEN CONDUCTOR (F650 RELAY)20.00 %
0.90 pu3.00 s
5.00 SUNDERVOLTAGE
EnabledPhase to Phase
Page 33 of 160
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3.5. Distance Protection for 132kV-30KM Line
System Details for 220kV lineNominal system voltage,UN = 132000V 132000 VCurrent transformer ratio,Nct = 400/1A 400.0Voltage transformer ratio,Nvt = 132000/110 1200.0Ratio of secondary to primary impedance,Nct/Nvt =Protected OHL Type =Current rating in Amps = Considered CT RatioProtected OHL length = KMPositive seq.Resistance of OHL in , per kM, Rprim =Positive seq.Reactance of OHL in , per kM, Xprim =Positive seq.impedance of OHL in , per kM, Zprim = 0.463 68.8 O
Zero seq.Resistance of OHL in , per kM, Rprim =Zero seq.Reactance of OHL in , per kM, Xprim =Zero seq.impedance of OHL in , per kM, Zprim = 0.743 56.9 O
Adjacent Longest Line detailsProtected OHL length = KMPositive seq.Resistance of OHL in , per kM, Rprim =Positive seq.Reactance of OHL in , per kM, Xprim =Positive seq.impedance of OHL in , per kM, Zprim = 0.463 68.8 O
Zero seq.Resistance of OHL in , per kM, Rprim =Zero seq.Reactance of OHL in , per kM, Xprim =Zero seq.impedance of OHL in , per kM, Zprim = 0.743 56.9 O
Adjacent Shortest Line detailsProtected OHL length = KMPositive seq.Resistance of OHL in , per kM, Rprim =Positive seq.Reactance of OHL in , per kM, Xprim =Positive seq.impedance of OHL in , per kM, Zprim = 0.46 68.8 O
Zero seq.Resistance of OHL in , per kM, Rprim =Zero seq.Reactance of OHL in , per kM, Xprim =Zero seq.impedance of OHL in , per kM, Zprim = 0.74 56.9 O
PT Details:PT Ratio = 132000/110 V
PT Primary Voltage = 132000.0 VPT Secondary Voltage = 110.0 V
System Frequency = 50.0 HZ
Distance element Settings:Reactance settingsZone 1 SettingsRequired Zone 1 reach is to be 85% of the Protected line
X1prim = 85% * Xprim = 8.08X1sec = Nct/Nvt * Xprim = 2.69
Zone 2 SettingsZone 2 element setting with a reach of 120% of Protected line reactance accounts for effect of infeed.This point must be verified using a fault study to calculate the apparent ohms at the local terminal for a fault at the remote end of transmission line. In our case 120% is considered for the zone-2 elements with assurance that all faults in the protected line are detectable,even with infeed from remote terminals.
Assuming the zone-1 reach for the adjacent line protection is set at 85% of that line reactance, and it is to be verified such that the zone-2 reach of 120%(protected line) shall not extend beyond the max.effective zone-1 reach of the adjacent line protection.Zone-2 setting limit = Protected line reactance +
0.85 * adjacent shortest line reactance= 4.22
Zone-2 setting with 120% reach = 3.80Since 120%, 3.80 is lower than zone-2 limit. 4.22, so the zone-2 setting of 120% will not overreach beyond zone-1 settingof adjacent line protection. Therefore we consider 120% of protected line reactance
Hence set X2 prim = 11.40Hence set X2 sec = 3.80
8.600.1670.432
VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL)
16.09.13
PRPD:
0.622
MN
TITLE: SETTING CALCULATION FOR 132kV LINE PROTN(22KM) CKD: GP
RELAY GE D60 BAY/FEEDER
0.1670.432
0.33ACSR PANTHER
400.022.0
132kV Line-22KM
0.1670.432
0.4060.622
0.4060.622
44.28
0.406
Page 34 of 160
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MAKE MODEL
VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL)
16.09.13
PRPD: MN
TITLE: SETTING CALCULATION FOR 132kV LINE PROTN(22KM) CKD: GP
RELAY GE D60 BAY/FEEDER 132kV Line-22KM
Zone 3 SettingsFor Zone3 setting , it is customery to select 1.2 (Protected line + 50% Adjacent Longest line)
X3prim, reach = 22.88X3sec = Nct/Nvt * X3prim*IN/A = 7.63
Zone 4 SettingsFor Zone4 setting, reverse reach impedence is typically 20% Zone 1 reach Impedance.
X4prim, reach = 1.62X4sec = Nct/Nvt * X4prim*IN/A = 0.54
Resistance settingsFor resistance setting of OHL, consideration of AC resistance is most important. Also tower footing resistance shall be accounted in the calculation.
Resistive Reach CalculationsMinimum Load impedence to the relay = Vn (phase - neutral) / In
= (110/3/1)
= 63.51
= 38.11 secondary
= 50.81 secondary
Ra = (28710 x L) / If^1.4
Where:If = Minimum expected phase-phase fault current (A);L = Maximum phase conductor separation (m);
Ra =
fault current = 4.8 kAConductor spaces = 2.7 mtrs
= 0.54
(RARC is = 1.325 RTFT Tower Foot Resistance = 10
Zone-1 setting(same way as done above for X reach)R1 sec = R1sec + 0.5RARC+ RTFT = 4.60
Zone-2 setting(same way as done above for X reach)R2 sec = R2sec + 0.5RARC+ RTFT = 5.03
Zone-3 setting(same way as done above for X reach)R3 sec = R3sec + 0.5RARC+ RTFT = 6.51
Zone-4 setting(same way as done above for X reach)R4 sec = R4sec + 0.5RARC+ RTFT = 3.76
Time setting Zone-1 setting = 0.00 secZone-2 setting zone-2 time delay should be set to discreminative with the primary line protection of the next line sections including circuit breaker trip time
Adjoining line protection operating time = 0.040Breaker opening time = 0.080
Local relay reset = 0.030Grading margin = 0.250
Required zone-2 time delay = 0.40set zone-2 at = 0.40 sec
Zone-3 setting zone-3 time delay shall be such that zone-2 time delay plus grading margin
zone-2 time delay = 0.400Grading margin = 0.400
Required zone-3 time delay = 0.80set zone-3 at = 0.80 sec
Typically,phase fault distance zones would avoid the minimum load impedence by a margin of 40%,earth fault zones would use a 20% margin.
This allows maximum resistive reaches for Phase faults
This allows maximum resistive reaches for Earth faults
Arc resistance, calculated from the van Warrington formula (W).
Primary resistive coverage for phase faults
Page 35 of 160
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MAKE MODEL
VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL)
16.09.13
PRPD: MN
TITLE: SETTING CALCULATION FOR 132kV LINE PROTN(22KM) CKD: GP
RELAY GE D60 BAY/FEEDER 132kV Line-22KM
Zone-4 setting zone-4 might be used to provide back up protection for the local bus bar. zone-4 time delay shall be such that LBB time delay plus grading margin
LBB time delay = 0.200Grading margin = 0.250
Required zone-4 time delay = 0.45set zone-4 at = 0.50 sec
Earth Impedance matching factor for Zone-1,2,3 & 4RE/RL = 1/3 (R0/R1 -1) = 0.48XE/XL = 1/3 (X0/X1 -1) = 0.15
R0-R1 = 0.24X0-X1 = 0.19Z0-Z1 = 0.31 38.53 O
Z0/Z1 MAG & ANGLE= (Z0-Z1)/3Z1 = 0.22 -30.29 OWhere R1 is +ve seq. resistance of protected lineR0 is zero seq. resistance of protected lineX1 is +ve seq. reactance of protected lineX0 is zero seq. reactance of protected line
Load impedance valueRload prim = Umin/3*ILmax
Where Umin = minimum operating voltage, 0.9*UN = 118800
ILmax = max load current = 400.000Hence Rload prim = 171.48
Rload sec = 57.16
The above is calculated for ph to earth and for ph to ph it is same value because current is multiplied by 3 PHI load , maximum load angle As load current ideally is in phase with the voltage, the difference is indicated with the power factor cos. The largest angle of the load impedance is therefore given by the worst, smallest powerfactor. We considered the worst power factor under full load condition is 0.9.
load- max = cos -1(power factor min)load- max = cos-1 (0.9)load- max = 26.00 O
Power Swing Detection:The power swing detect element provides both power swing blocking and out-of-step tripping functions.
Power swing Shape, = QUADPower swing Mode, = Two step
Power swing Supervision, = 0.600 pu (typical setting from manual)Power swing Forward Reach(inner) = 7.63
(considered zone-3 reactance boundary)Power swing Forward RCA = 68.8 O
Power swing Forward Reach(outer) = 9.15 (120% of inner Reach)
Power swing Reverse Reach(inner) is considered as 50% zone-3 Reactance Reach + zone-4 Reactance Reach Power swing Reverse Reach(inner) = 4.35 Power swing Reverse Reach(outer) = 5.22
(120% of Reverse inner Reach)Power swing inner Right blinder = 6.51
(considered zone-3 resistive boundary)Power swing outer Right blinder = 7.81
(120% of inner Right blinder)Power swing inner Left blinder = 6.51
(considered zone-3 resistive boundary)Power swing outer Left blinder = 7.81
(120% of inner Left blinder)
VT Fuse failFunction enabled
The setting shall be applied 30% lower than calculated above = 40.01
Page 36 of 160
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MAKE MODEL
VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL)
16.09.13
PRPD: MN
TITLE: SETTING CALCULATION FOR 132kV LINE PROTN(22KM) CKD: GP
RELAY GE D60 BAY/FEEDER 132kV Line-22KM
Broken Conductor Protection Full load current = 400.000 A
Considered I2 = 40.00 A (10% of fullload current)I2 / I1 = 0.10
Allow for tolerences and load varations = 200%I2 / I1 = 20.00 %
time delay = 5.00 s
Auto Reclosure:This autoreclose can be single pole tripping for single phase faults and three phase tripping for multi-phase faults.1 pole:In this mode, the recloser starts the AR-1P DEAD TIME for the first shot if the fault is single phase.If the fault is three phase or three pole trip occurred on the breaker during single initiation, the scheme goes to lockout with out reclosing.
AR Mode, = 1 poleAR Max Number of Shots, = 1.00AR Close Time Breaker 1, = 0.20 s
AR Block Time Upon Man Cls. = 10.00 sAR Reset Time, = 25.00 s
AR Breaker1 Fail Option, = LockoutAR Incomplete Sequence Time, = 2.00 s
AR 1-P Dead Time, 1.00 sAR Breaker Sequence, = 1.00
Local Breaker Backup ProtectionIn general, a breaker failure scheme determines that a breaker signaled to trip has not cleared a fault with in a definite time, so further tripping action must be performed.
BF1 MODE, = 3-PoleBF1 SOURCE, = SRC1
BF1 USE AMP SUPV, = YesBF1 USE SEAL-IN, = Yes
BF1 PH AMP SUPV, = 0.20 puBF1 N AMP SUPV, = 0.20 puBF1 USE TIMER1, = Yes
BF1 TIMER1 PICKUP DELAY, = 0.20 SBF1 TRIP DROPOUT = 0.00 S
Setting Recommendation for UVPT Ratio =
=Under voltage =
= v 90% OF Rated VoltageSelect Under voltage setting, 27 =
= V pu
Time delay setting , 27 = s
132000/1101200.00
0.90*Nominal Volt118800
118800/120099.0000.903.00
Page 37 of 160
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MAKE MODEL
VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL)
16.09.13
PRPD: MN
TITLE: SETTING CALCULATION FOR 132kV LINE PROTN(22KM) CKD: GP
RELAY GE D60 BAY/FEEDER 132kV Line-22KM
Settings Table
Line LengthPHASE DIST Z1 DIRPHASE DIST SHAPEPHS DIST Z1 REACHPHS DIST Z1 RCAPHS DIST Z1 COMP LIMITPHS DIST Z1 DIR RCAPHS DIST Z1 DIR COMP LIMITPHS DIST Z1 QUAD RGT BLDPHS DIST Z1 QUAD RGT BLD RCAPHS DIST Z1 QUAD LFT BLDPHS DIST Z1 QUAD LFT BLD RCAPHASE DIST Z1 DELAYPHS DIST Z1 SUPV
PHASE DIST Z2 DIRPHASE DIST SHAPEPHS DIST Z2 REACHPHS DIST Z2 RCAPHS DIST Z2 COMP LIMITPHS DIST Z2 DIR RCAPHS DIST Z2 DIR COMP LIMITPHS DIST Z2 QUAD RGT BLDPHS DIST Z2 QUAD RGT BLD RCAPHS DIST Z2 QUAD LFT BLDPHS DIST Z2 QUAD LFT BLD RCAPHASE DIST Z2 DELAY
PHASE DIST Z3 DIRPHASE DIST SHAPEPHS DIST Z3 REACHPHS DIST Z3 RCAPHS DIST Z3 COMP LIMITPHS DIST Z3 DIR RCAPHS DIST Z3 DIR COMP LIMITPHS DIST Z3 QUAD RGT BLDPHS DIST Z3 QUAD RGT BLD RCAPHS DIST Z3 QUAD LFT BLDPHS DIST Z3 QUAD LFT BLD RCAPHASE DIST Z3 DELAY
PHASE DIST Z4 DIRPHASE DIST SHAPEPHS DIST Z4 REACHPHS DIST Z4 RCAPHS DIST Z4 COMP LIMITPHS DIST Z4 DIR RCAPHS DIST Z4 DIR COMP LIMITPHS DIST Z4 QUAD RGT BLDPHS DIST Z4 QUAD RGT BLD RCAPHS DIST Z4 QUAD LFT BLDPHS DIST Z4 QUAD LFT BLD RCAPHASE DIST Z4 DELAY
Menu text Recommended SettingPHASE DISTANCE ELEMENTS Setting UnitLine setting
22.00 kmForward
Quadrilateral2.69 68.82 DEG90.00 DEG68.82 DEG90.00 DEG4.60 68.82 DEG4.60 68.82 DEG0.00 S0.34 pu
ForwardQuadrilateral
3.80 68.82 DEG90.00 DEG68.82 DEG90.00 DEG5.03 68.82 DEG5.03 68.82 DEG0.40 S
ForwardQuadrilateral
7.63 68.82 DEG90.00 DEG68.82 DEG90.00 DEG6.51 68.82 DEG6.51 68.82 DEG0.80 S
ReverseQuadrilateral
0.54 68.82 DEG90.00 DEG68.82 90.00 DEG6.51 68.82 DEG6.51 68.82 DEG0.50 S
Page 38 of 160
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MAKE MODEL
VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL)
16.09.13
PRPD: MN
TITLE: SETTING CALCULATION FOR 132kV LINE PROTN(22KM) CKD: GP
RELAY GE D60 BAY/FEEDER 132kV Line-22KM
GND DIST Z1 DIRGND DIST SHAPEGND DIST Z1 REACHGND DIST Z1 RCAGND DIST Z1 COMP LIMITGND DIST Z1 DIR RCAGND DIST Z1 DIR COMP LIMITGND DIST Z1 QUAD RGT BLDGND DIST Z1 QUAD RGT BLD RCAGND DIST Z1 QUAD LFT BLDGND DIST Z1 QUAD LFT BLD RCAGND DIST Z1 DELAYGND DIST Z1 Z0/Z1 MAGGND DIST Z1 Z0/Z1 ANG
GND DIST Z2 DIRGND DIST SHAPEGND DIST Z2 REACHGND DIST Z2 RCAGND DIST Z2 COMP LIMITGND DIST Z2 DIR RCAGND DIST Z2 DIR COMP LIMITGND DIST Z2 QUAD RGT BLDGND DIST Z2 QUAD RGT BLD RCAGND DIST Z2 QUAD LFT BLDGND DIST Z2 QUAD LFT BLD RCAGND DIST Z2 DELAYGND DIST Z2 Z0/Z1 MAGGND DIST Z2 Z0/Z1 ANG
GND DIST Z3 DIRGND DIST SHAPEGND DIST Z3 REACHGND DIST Z3 RCAGND DIST Z3 QUAD RGT BLDGND DIST Z3 QUAD RGT BLD RCAGND DIST Z3 QUAD LFT BLDGND DIST Z3 QUAD LFT BLD RCAGND DIST Z3 DELAYGND DIST Z3 Z0/Z1 MAGGND DIST Z3 Z0/Z1 ANG
GND DIST Z4 DIRGND DIST SHAPEGND DIST Z4 REACHGND DIST Z4 RCAGND DIST Z4 QUAD RGT BLDGND DIST Z4 QUAD RGT BLD RCAGND DIST Z4 QUAD LFT BLDGND DIST Z4 QUAD LFT BLD RCAGND DIST Z4 DELAYGND DIST Z4 Z0/Z1 MAGGND DIST Z4 Z0/Z1 ANG
LOAD ENCROACHMENTLOAD ENCROACHMENT MIN VOLTLOAD ENCROACHMENT REACHLOAD ENCROACHMENT ANGLELOAD ENCROACHMENT PKP DELAYLOAD ENCROACHMENT RST DELAY
Menu text Recommended SettingPHASE DISTANCE ELEMENTS Setting UnitLine setting
ForwardQuadrilateral
2.69 68.82 DEG90.00 DEG68.82 DEG90.00 DEG4.60 68.82 DEG4.60 68.82 DEG0.00 S0.22
-30.29 DEG
ForwardQuadrilateral
3.80 68.82 DEG90.00 DEG68.82 DEG90.00 DEG5.03 68.82 DEG5.03 68.82 DEG0.40 S0.22
-30.29 DEG
ForwardQuadrilateral
7.63 68.82 DEG6.51 68.82 DEG6.51 68.82 DEG0.80 S0.22
-30.29 DEG
ReverseQuadrilateral
0.54 68.82 DEG6.51 68.82 DEG6.51 68.82 DEG0.50 S0.22
-30.29 DEG
0.25 pu40.01 26.00 DEG0.00 S0.00 S
Page 39 of 160
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MAKE MODEL
VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL)
16.09.13
PRPD: MN
TITLE: SETTING CALCULATION FOR 132kV LINE PROTN(22KM) CKD: GP
RELAY GE D60 BAY/FEEDER 132kV Line-22KM
POWER SWING DETECTPOWER SWING SHAPEPOWER SWING MODEPOWER SWING SUPVPOWER SWING FWD REACHPOWER SWING QUAD FWD REACH OUTPOWER SWING FWD RCAPOWER SWING REV REACHPOWER SWING QUAD REV REACH OUT POWER SWING OUTER RGT BLDPOWER SWING OUTER LFT BLDPOWER SWING INNER RGT BLDPOWER SWING INNER LFT BLDPOWER SWING PICKUP DELAY1 POWER SWING RESET DELAY1 POWER SWING PICKUP DELAY2 POWER SWING PICKUP DELAY3POWER SWING PICKUP DELAY4 POWER SWING SEAL IN DELAYPOWER SWING TRIP MODE
PHASE IOC LINE PICKUPLINE UV PICKUPLINE END OPEN PICKUP DELAYLINE END OPEN RESET DELAYLINE OV PICKUP DELAYAR COORDINATION BYPASSAR COORDINATION PICKUP DELAYAR COORDINATION RESET DELAYLINE PICKUP DISTANCE TRIP
FUNCTION
FUNCTIONAR MODEMAX NUMBER OF SHOTSAR CLOSE TIME BKR1AR BLK TIME UPON MAN CLSAR RESET TIME AR BKR1 FAIL OPTIONAR INCOMPLETE SEQ TIMEAR 1-P DEAD TIME AR BKR1 SEQUENCE
FUNCTIONBR1 MODEBF1 SOURCEBF1 USE AMP SUPVBF1 USE SEAL-INBF1 PH AMP SUPV PICKUPBF1 N AMP SUPV PICKUPBF1 USE TIMER1BF1 TIMER1 PICKUP DELAYBF1 TRIP DROPOUT
TAP LEVEL IN PERCENTAGE OF I2/I1TRIP TIME
PHASE UV1 FUNCTIONPHASE UV1 MODEPHASE UV1 PICKUPPHASE UV1 DELAY
Menu text Recommended SettingPHASE DISTANCE ELEMENTS Setting Unit
QuadrilateralTwo Step
0.60 pu7.63 9.1568.82 DEG4.35 5.22 7.81 7.81 6.51 6.51 0.03 S0.05 S0.02 S0.01 S0.02 S0.40 S
Delayed SLINE PICKUP (SOTF)
1.00 pu0.70 pu0.15 S0.09 S0.04 S
Enabled0.05 S0.01 S
EnabledFUSE FAILURE
EnabledAUTO RECLOSE
Enabled1 pole1.000.20 S10.00 S25.00 S
Lockout2.00 S1.00 S1.00
BREAKER FAILURE 1Enabled3-PoleSRC1YesYes0.20 pu0.20 puYes0.20 S0.00 S
BROKEN CONDUCTOR (F650 RELAY)20.00 %
0.90 pu3.00 s
5.00 SUNDERVOLTAGE
EnabledPhase to Phase
Page 40 of 160
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3.6. Distance Protection for 132kV-30KM Line
System Details for 220kV lineNominal system voltage,UN = 132000V 132000 VCurrent transformer ratio,Nct = 400/1A 400.0Voltage transformer ratio,Nvt = 132000/110 1200.0Ratio of secondary to primary impedance,Nct/Nvt =Protected OHL Type =Current rating in Amps = Considered CT RatioProtected OHL length = KMPositive seq.Resistance of OHL in , per kM, Rprim =Positive seq.Reactance of OHL in , per kM, Xprim =Positive seq.impedance of OHL in , per kM, Zprim = 0.463 68.8 O
Zero seq.Resistance of OHL in , per kM, Rprim =Zero seq.Reactance of OHL in , per kM, Xprim =Zero seq.impedance of OHL in , per kM, Zprim = 0.743 56.9 O
Adjacent Longest Line detailsProtected OHL length = KMPositive seq.Resistance of OHL in , per kM, Rprim =Positive seq.Reactance of OHL in , per kM, Xprim =Positive seq.impedance of OHL in , per kM, Zprim = 0.463 68.8 O
Zero seq.Resistance of OHL in , per kM, Rprim =Zero seq.Reactance of OHL in , per kM, Xprim =Zero seq.impedance of OHL in , per kM, Zprim = 0.743 56.9 O
Adjacent Shortest Line detailsProtected OHL length = KMPositive seq.Resistance of OHL in , per kM, Rprim =Positive seq.Reactance of OHL in , per kM, Xprim =Positive seq.impedance of OHL in , per kM, Zprim = 0.46 68.8 O
Zero seq.Resistance of OHL in , per kM, Rprim =Zero seq.Reactance of OHL in , per kM, Xprim =Zero seq.impedance of OHL in , per kM, Zprim = 0.74 56.9 O
PT Details:PT Ratio = 132000/110 V
PT Primary Voltage = 132000.0 VPT Secondary Voltage = 110.0 V
System Frequency = 50.0 HZ
Distance element Settings:Reactance settingsZone 1 SettingsRequired Zone 1 reach is to be 85% of the Protected line
X1prim = 85% * Xprim = 5.51X1sec = Nct/Nvt * Xprim = 1.84
Zone 2 SettingsZone 2 element setting with a reach of 120% of Protected line reactance accounts for effect of infeed.This point must be verified using a fault study to calculate the apparent ohms at the local terminal for a fault at the remote end of transmission line. In our case 120% is considered for the zone-2 elements with assurance that all faults in the protected line are detectable,even with infeed from remote terminals.
Assuming the zone-1 reach for the adjacent line protection is set at 85% of that line reactance, and it is to be verified such that the zone-2 reach of 120%(protected line) shall not extend beyond the max.effective zone-1 reach of the adjacent line protection.Zone-2 setting limit = Protected line reactance +
0.85 * adjacent shortest line reactance= 2.85
Zone-2 setting with 120% reach = 2.59Since 120%, 2.59 is lower than zone-2 limit. 2.85, so the zone-2 setting of 120% will not overreach beyond zone-1 settingof adjacent line protection. Therefore we consider 120% of protected line reactance
Hence set X2 prim = 7.78Hence set X2 sec = 2.59
5.600.1670.432
VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL)
16.09.13
PRPD:
0.622
MN
TITLE: SETTING CALCULATION FOR 132kV LINE PROTN(15KM) CKD: GP
RELAY GE D60 BAY/FEEDER
0.1670.432
0.33ACSR PANTHER
400.015.0
132kV Line-15KM
0.1670.432
0.4060.622
0.4060.622
5.60
0.406
Page 41 of 160
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VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL)
16.09.13
PRPD: MN
TITLE: SETTING CALCULATION FOR 132kV LINE PROTN(15KM) CKD: GP
RELAY GE D60 BAY/FEEDER 132kV Line-15KM
Zone 3 SettingsFor Zone3 setting , it is customery to select 1.2 (Protected line + 50% Adjacent Longest line)
X3prim, reach = 9.23X3sec = Nct/Nvt * X3prim*IN/A = 3.08
Zone 4 SettingsFor Zone4 setting, reverse reach impedence is typically 20% Zone 1 reach Impedance.
X4prim, reach = 1.10X4sec = Nct/Nvt * X4prim*IN/A = 0.37
Resistance settingsFor resistance setting of OHL, consideration of AC resistance is most important. Also tower footing resistance shall be accounted in the calculation.
Resistive Reach CalculationsMinimum Load impedence to the relay = Vn (phase - neutral) / In
= (110/3/1)
= 63.51
= 38.11 secondary
= 50.81 secondary
Ra = (28710 x L) / If^1.4
Where:If = Minimum expected phase-phase fault current (A);L = Maximum phase conductor separation (m);
Ra =
fault current = 6.01 kAConductor spaces = 2.7 mtrs
= 0.40
(RARC is = 1.325 RTFT Tower Foot Resistance = 10
Zone-1 setting(same way as done above for X reach)R1 sec = R1sec + 0.5RARC+ RTFT = 4.27
Zone-2 setting(same way as done above for X reach)R2 sec = R2sec + 0.5RARC+ RTFT = 4.56
Zone-3 setting(same way as done above for X reach)R3 sec = R3sec + 0.5RARC+ RTFT = 4.75
Zone-4 setting(same way as done above for X reach)R4 sec = R4sec + 0.5RARC+ RTFT = 3.70
Time setting Zone-1 setting = 0.00 secZone-2 setting zone-2 time delay should be set to discreminative with the primary line protection of the next line sections including circuit breaker trip time
Adjoining line protection operating time = 0.040Breaker opening time = 0.080
Local relay reset = 0.030Grading margin = 0.250
Required zone-2 time delay = 0.40set zone-2 at = 0.40 sec
Zone-3 setting zone-3 time delay shall be such that zone-2 time delay plus grading margin
zone-2 time delay = 0.400Grading margin = 0.400
Required zone-3 time delay = 0.80set zone-3 at = 0.80 sec
Typically,phase fault distance zones would avoid the minimum load impedence by a margin of 40%,earth fault zones would use a 20% margin.
This allows maximum resistive reaches for Phase faults
This allows maximum resistive reaches for Earth faults
Arc resistance, calculated from the van Warrington formula (W).
Primary resistive coverage for phase faults
Page 42 of 160
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VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL)
16.09.13
PRPD: MN
TITLE: SETTING CALCULATION FOR 132kV LINE PROTN(15KM) CKD: GP
RELAY GE D60 BAY/FEEDER 132kV Line-15KM
Zone-4 setting zone-4 might be used to provide back up protection for the local bus bar. zone-4 time delay shall be such that LBB time delay plus grading margin
LBB time delay = 0.200Grading margin = 0.250
Required zone-4 time delay = 0.45set zone-4 at = 0.50 sec
Earth Impedance matching factor for Zone-1,2,3 & 4RE/RL = 1/3 (R0/R1 -1) = 0.48XE/XL = 1/3 (X0/X1 -1) = 0.15
R0-R1 = 0.24X0-X1 = 0.19Z0-Z1 = 0.31 38.53 O
Z0/Z1 MAG & ANGLE= (Z0-Z1)/3Z1 = 0.22 -30.29 OWhere R1 is +ve seq. resistance of protected lineR0 is zero seq. resistance of protected lineX1 is +ve seq. reactance of protected lineX0 is zero seq. reactance of protected line
Load impedance valueRload prim = Umin/3*ILmax
Where Umin = minimum operating voltage, 0.9*UN = 118800
ILmax = max load current = 400.000Hence Rload prim = 171.48
Rload sec = 57.16
The above is calculated for ph to earth and for ph to ph it is same value because current is multiplied by 3 PHI load , maximum load angle As load current ideally is in phase with the voltage, the difference is indicated with the power factor cos. The largest angle of the load impedance is therefore given by the worst, smallest powerfactor. We considered the worst power factor under full load condition is 0.9.
load- max = cos -1(power factor min)load- max = cos-1 (0.9)load- max = 26.00 O
Power Swing Detection:The power swing detect element provides both power swing blocking and out-of-step tripping functions.
Power swing Shape, = QUADPower swing Mode, = Two step
Power swing Supervision, = 0.600 pu (typical setting from manual)Power swing Forward Reach(inner) = 3.08
(considered zone-3 reactance boundary)Power swing Forward RCA = 68.8 O
Power swing Forward Reach(outer) = 3.69 (120% of inner Reach)
Power swing Reverse Reach(inner) is considered as 50% zone-3 Reactance Reach + zone-4 Reactance Reach Power swing Reverse Reach(inner) = 1.91 Power swing Reverse Reach(outer) = 2.29
(120% of Reverse inner Reach)Power swing inner Right blinder = 4.75
(considered zone-3 resistive boundary)Power swing outer Right blinder = 5.70
(120% of inner Right blinder)Power swing inner Left blinder = 4.75
(considered zone-3 resistive boundary)Power swing outer Left blinder = 5.70
(120% of inner Left blinder)
VT Fuse failFunction enabled
The setting shall be applied 30% lower than calculated above = 40.01
Page 43 of 160
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VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL)
16.09.13
PRPD: MN
TITLE: SETTING CALCULATION FOR 132kV LINE PROTN(15KM) CKD: GP
RELAY GE D60 BAY/FEEDER 132kV Line-15KM
Broken Conductor Protection Full load current = 400.000 A
Considered I2 = 40.00 A (10% of fullload current)I2 / I1 = 0.10
Allow for tolerences and load varations = 200%I2 / I1 = 20.00 %
time delay = 5.00 s
Auto Reclosure:This autoreclose can be single pole tripping for single phase faults and three phase tripping for multi-phase faults.1 pole:In this mode, the recloser starts the AR-1P DEAD TIME for the first shot if the fault is single phase.If the fault is three phase or three pole trip occurred on the breaker during single initiation, the scheme goes to lockout with out reclosing.
AR Mode, = 1 poleAR Max Number of Shots, = 1.00AR Close Time Breaker 1, = 0.20 s
AR Block Time Upon Man Cls. = 10.00 sAR Reset Time, = 25.00 s
AR Breaker1 Fail Option, = LockoutAR Incomplete Sequence Time, = 2.00 s
AR 1-P Dead Time, 1.00 sAR Breaker Sequence, = 1.00
Local Breaker Backup ProtectionIn general, a breaker failure scheme determines that a breaker signaled to trip has not cleared a fault with in a definite time, so further tripping action must be performed.
BF1 MODE, = 3-PoleBF1 SOURCE, = SRC1
BF1 USE AMP SUPV, = YesBF1 USE SEAL-IN, = Yes
BF1 PH AMP SUPV, = 0.20 puBF1 N AMP SUPV, = 0.20 puBF1 USE TIMER1, = Yes
BF1 TIMER1 PICKUP DELAY, = 0.20 SBF1 TRIP DROPOUT = 0.00 S
Setting Recommendation for UVPT Ratio =
=Under voltage =
= v 90% OF Rated VoltageSelect Under voltage setting, 27 =
= V pu
Time delay setting , 27 = s
132000/1101200.00
0.90*Nominal Volt118800
118800/120099.0000.903.00
Page 44 of 160
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VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL)
16.09.13
PRPD: MN
TITLE: SETTING CALCULATION FOR 132kV LINE PROTN(15KM) CKD: GP
RELAY GE D60 BAY/FEEDER 132kV Line-15KM
Settings Table
Line LengthPHASE DIST Z1 DIRPHASE DIST SHAPEPHS DIST Z1 REACHPHS DIST Z1 RCAPHS DIST Z1 COMP LIMITPHS DIST Z1 DIR RCAPHS DIST Z1 DIR COMP LIMITPHS DIST Z1 QUAD RGT BLDPHS DIST Z1 QUAD RGT BLD RCAPHS DIST Z1 QUAD LFT BLDPHS DIST Z1 QUAD LFT BLD RCAPHASE DIST Z1 DELAYPHS DIST Z1 SUPV
PHASE DIST Z2 DIRPHASE DIST SHAPEPHS DIST Z2 REACHPHS DIST Z2 RCAPHS DIST Z2 COMP LIMITPHS DIST Z2 DIR RCAPHS DIST Z2 DIR COMP LIMITPHS DIST Z2 QUAD RGT BLDPHS DIST Z2 QUAD RGT BLD RCAPHS DIST Z2 QUAD LFT BLDPHS DIST Z2 QUAD LFT BLD RCAPHASE DIST Z2 DELAY
PHASE DIST Z3 DIRPHASE DIST SHAPEPHS DIST Z3 REACHPHS DIST Z3 RCAPHS DIST Z3 COMP LIMITPHS DIST Z3 DIR RCAPHS DIST Z3 DIR COMP LIMITPHS DIST Z3 QUAD RGT BLDPHS DIST Z3 QUAD RGT BLD RCAPHS DIST Z3 QUAD LFT BLDPHS DIST Z3 QUAD LFT BLD RCAPHASE DIST Z3 DELAY
PHASE DIST Z4 DIRPHASE DIST SHAPEPHS DIST Z4 REACHPHS DIST Z4 RCAPHS DIST Z4 COMP LIMITPHS DIST Z4 DIR RCAPHS DIST Z4 DIR COMP LIMITPHS DIST Z4 QUAD RGT BLDPHS DIST Z4 QUAD RGT BLD RCAPHS DIST Z4 QUAD LFT BLDPHS DIST Z4 QUAD LFT BLD RCAPHASE DIST Z4 DELAY
Menu text Recommended SettingPHASE DISTANCE ELEMENTS Setting UnitLine setting
15.00 kmForward
Quadrilateral1.84 68.82 DEG90.00 DEG68.82 DEG90.00 DEG4.27 68.82 DEG4.27 68.82 DEG0.00 S0.34 pu
ForwardQuadrilateral
2.59 68.82 DEG90.00 DEG68.82 DEG90.00 DEG4.56 68.82 DEG4.56 68.82 DEG0.40 S
ForwardQuadrilateral
3.08 68.82 DEG90.00 DEG68.82 DEG90.00 DEG4.75 68.82 DEG4.75 68.82 DEG0.80 S
ReverseQuadrilateral
0.37 68.82 DEG90.00 DEG68.82 90.00 DEG4.75 68.82 DEG4.75 68.82 DEG0.50 S
Page 45 of 160
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VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL)
16.09.13
PRPD: MN
TITLE: SETTING CALCULATION FOR 132kV LINE PROTN(15KM) CKD: GP
RELAY GE D60 BAY/FEEDER 132kV Line-15KM
GND DIST Z1 DIRGND DIST SHAPEGND DIST Z1 REACHGND DIST Z1 RCAGND DIST Z1 COMP LIMITGND DIST Z1 DIR RCAGND DIST Z1 DIR COMP LIMITGND DIST Z1 QUAD RGT BLDGND DIST Z1 QUAD RGT BLD RCAGND DIST Z1 QUAD LFT BLDGND DIST Z1 QUAD LFT BLD RCAGND DIST Z1 DELAYGND DIST Z1 Z0/Z1 MAGGND DIST Z1 Z0/Z1 ANG
GND DIST Z2 DIRGND DIST SHAPEGND DIST Z2 REACHGND DIST Z2 RCAGND DIST Z2 COMP LIMITGND DIST Z2 DIR RCAGND DIST Z2 DIR COMP LIMITGND DIST Z2 QUAD RGT BLDGND DIST Z2 QUAD RGT BLD RCAGND DIST Z2 QUAD LFT BLDGND DIST Z2 QUAD LFT BLD RCAGND DIST Z2 DELAYGND DIST Z2 Z0/Z1 MAGGND DIST Z2 Z0/Z1 ANG
GND DIST Z3 DIRGND DIST SHAPEGND DIST Z3 REACHGND DIST Z3 RCAGND DIST Z3 QUAD RGT BLDGND DIST Z3 QUAD RGT BLD RCAGND DIST Z3 QUAD LFT BLDGND DIST Z3 QUAD LFT BLD RCAGND DIST Z3 DELAYGND DIST Z3 Z0/Z1 MAGGND DIST Z3 Z0/Z1 ANG
GND DIST Z4 DIRGND DIST SHAPEGND DIST Z4 REACHGND DIST Z4 RCAGND DIST Z4 QUAD RGT BLDGND DIST Z4 QUAD RGT BLD RCAGND DIST Z4 QUAD LFT BLDGND DIST Z4 QUAD LFT BLD RCAGND DIST Z4 DELAYGND DIST Z4 Z0/Z1 MAGGND DIST Z4 Z0/Z1 ANG
LOAD ENCROACHMENTLOAD ENCROACHMENT MIN VOLTLOAD ENCROACHMENT REACHLOAD ENCROACHMENT ANGLELOAD ENCROACHMENT PKP DELAYLOAD ENCROACHMENT RST DELAY
Menu text Recommended SettingPHASE DISTANCE ELEMENTS Setting UnitLine setting
ForwardQuadrilateral
1.84 68.82 DEG90.00 DEG68.82 DEG90.00 DEG4.27 68.82 DEG4.27 68.82 DEG0.00 S0.22
-30.29 DEG
ForwardQuadrilateral
2.59 68.82 DEG90.00 DEG68.82 DEG90.00 DEG4.56 68.82 DEG4.56 68.82 DEG0.40 S0.22
-30.29 DEG
ForwardQuadrilateral
3.08 68.82 DEG4.75 68.82 DEG4.75 68.82 DEG0.80 S0.22
-30.29 DEG
ReverseQuadrilateral
0.37 68.82 DEG4.75 68.82 DEG4.75 68.82 DEG0.50 S0.22
-30.29 DEG
0.25 pu40.01 26.00 DEG0.00 S0.00 S
Page 46 of 160
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VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL)
16.09.13
PRPD: MN
TITLE: SETTING CALCULATION FOR 132kV LINE PROTN(15KM) CKD: GP
RELAY GE D60 BAY/FEEDER 132kV Line-15KM
POWER SWING DETECTPOWER SWING SHAPEPOWER SWING MODEPOWER SWING SUPVPOWER SWING FWD REACHPOWER SWING QUAD FWD REACH OUTPOWER SWING FWD RCAPOWER SWING REV REACHPOWER SWING QUAD REV REACH OUT POWER SWING OUTER RGT BLDPOWER SWING OUTER LFT BLDPOWER SWING INNER RGT BLDPOWER SWING INNER LFT BLDPOWER SWING PICKUP DELAY1 POWER SWING RESET DELAY1 POWER SWING PICKUP DELAY2 POWER SWING PICKUP DELAY3POWER SWING PICKUP DELAY4 POWER SWING SEAL IN DELAYPOWER SWING TRIP MODE
PHASE IOC LINE PICKUPLINE UV PICKUPLINE END OPEN PICKUP DELAYLINE END OPEN RESET DELAYLINE OV PICKUP DELAYAR COORDINATION BYPASSAR COORDINATION PICKUP DELAYAR COORDINATION RESET DELAYLINE PICKUP DISTANCE TRIP
FUNCTION
FUNCTIONAR MODEMAX NUMBER OF SHOTSAR CLOSE TIME BKR1AR BLK TIME UPON MAN CLSAR RESET TIME AR BKR1 FAIL OPTIONAR INCOMPLETE SEQ TIMEAR 1-P DEAD TIME AR BKR1 SEQUENCE
FUNCTIONBR1 MODEBF1 SOURCEBF1 USE AMP SUPVBF1 USE SEAL-INBF1 PH AMP SUPV PICKUPBF1 N AMP SUPV PICKUPBF1 USE TIMER1BF1 TIMER1 PICKUP DELAYBF1 TRIP DROPOUT
TAP LEVEL IN PERCENTAGE OF I2/I1TRIP TIME
PHASE UV1 FUNCTIONPHASE UV1 MODEPHASE UV1 PICKUPPHASE UV1 DELAY
Menu text Recommended SettingPHASE DISTANCE ELEMENTS Setting Unit
QuadrilateralTwo Step
0.60 pu3.08 3.6968.82 DEG1.91 2.29 5.70 5.70 4.75 4.75 0.03 S0.05 S0.02 S0.01 S0.02 S0.40 S
Delayed SLINE PICKUP (SOTF)
1.00 pu0.70 pu0.15 S0.09 S0.04 S
Enabled0.05 S0.01 S
EnabledFUSE FAILURE
EnabledAUTO RECLOSE
Enabled1 pole1.000.20 S10.00 S25.00 S
Lockout2.00 S1.00 S1.00
BREAKER FAILURE 1Enabled3-PoleSRC1YesYes0.20 pu0.20 puYes0.20 S0.00 S
BROKEN CONDUCTOR (F650 RELAY)20.00 %
0.90 pu3.00 s
5.00 SUNDERVOLTAGE
EnabledPhase to Phase
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3.7. 40MVA.TRAFO DIFF. SETTING CALCULATION
Transformer Data:Rated Power, Prated = 40.0 MVARated Voltage
HV, Vnom[1] = 132.0 kVLV, Vnom[2] = 33.0 kV
% Impedance = 0.138 13.80% .Vector Group = YN yn 0
= 400.0 1.0 A
= 800.0 1.0 AOLTC Range on 132kV side + 15.0 %
to- 5.0 %
Step Size 1.25 Max Step 12.00 Min Step 4.00Voltage at Min Tap Position = 151.8 kVVoltage at Max Tap Position = 125.4 kVHighest voltage tolerence, Vmax = 37.95 kVLowest voltage tolerence,Vmin = 31.35 kV
The reference winding is determined as follows,Rated current on winding 1- Irated = Prated / (3*Vnom[1] )
= (40*1000)/(1.732*132)Irated [1], = 174.95 A
Rated current on winding 2- Irated = Prated / (3*Vnom[2] )=
Irated [2], = A
With this rated currents the CT margin for Winding1& winding 2 as follows,CT margin for windings 1, Imargin[1] = CT primary[1] / Irated[1]
=
Imargin[1], =CT margin for windings 2, Imargin[2] = CT primary[2] / Irated[2]
=
Imargin[2], =
Since Imargin[2] < Imargin[1], the reference winding Wref is winding 2.
Calculation of magnitude compensation factor (M),magnitude compensation factor for winding [1], M[1]= IPrimary [1] Vnom [1] / IPrimary [2] Vnom[2]
= 400x132000/800x33000132kV side M[1], = 2.00
magnitude compensation factor for winding [2], M[2]= IPrimary [2] Vnom [2] / IPrimary [2] Vnom[2] = 800x33000/800x33000
33kV side M[2], = 1.00
SETTING CALCULATION FOR 132/33-40MVATRAFO DIFF PROTN CKD:
RELAY GE T60 BAY/FEEDER
VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE 16.09.13
132/33-40 MVA Trafo
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL) PRPD: MN
TITLE: GP
33kV SIDE Primary-winding 2, CT Ratio (Inom,b)
Note: In the entire calculation primary and secondary windings are referred as winding "1" & "2" respectively.
The unit for calculation of the differential and restraint currents and base for the differentialrestraint setting is the CT primary associated with the reference winding.
699.82
2.29
1.14
(800-400/1A)
(800-400/1A)
(40*1000)/(1.732*33)
400/174.95
800/699.82
132kV SIDE Primary-winding 1, CT Ratio (Inom,a)
Page 48 of 160
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SETTING CALCULATION FOR 132/33-40MVATRAFO DIFF PROTN CKD:
RELAY GE T60 BAY/FEEDER
VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE 16.09.13
132/33-40 MVA Trafo
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL) PRPD: MN
TITLE: GP
a) Calculating the minimum differential pickup current required for relay to operate,Criteria:
No load current of the transformer primary current,== A
No load current refered to the CT secondary, == A
=
IS1 = A
No load current of the transf. winding2,(secondary side)=IS2 =
Differential current IdA, ==
Id A, = ARestraining current IrA, = max( | Is1|, |Is2 |)
= max( |0.044|, |0 |)IrA, = A
b) Selection of Break point 1 and slope 1:Recommened Settings,The Break point 1 setting is based on the pu value of the full load transformer current
HV side (Winding -1) = 0.44 puLV side (Winding -2) = 0.87 pu
Hence we choose Break point-1 = 2 puSlope -1 = 25%
Nominal Voltage, Vnom = 2 ( Vmax X Vmin) / (Vmax + Vmin)= 2(37.95*31.35)/(37.95+31.35)= 34.34 kv
Object current of regulated side, IN2 = SN/(1.732 X VN2)= (40*1000)/(1.732x34.336)= 672.61 A= IN2 / CT2= 672.62/800= 0.84 A ~ INobj
= IN1 / CT1= 174.95/400= 0.44 A ~ INobj
= SN/(1.732 X Vmax)= (40*1000)/(1.732x37.95)= 608.56
= IN2(+15%) / CT2= 608.56/800= 0.76 A ~ 0.90 INobj
= | IN2(+15%) - INobj |= I0.905INobj-INobjl= 0.10 INobj
Differential / Restraint Current in the Tap Changer Extreme Position:
Corresponds on the CT2 secondary side to IN2
Corresponds on the CT1 secondary side to IN1
The differential current IdA=0.0440A is found to be less than the minimum pickup selected setting of 0.1 is adequate as the relay catalogue has a setting generally recommended between 0.1 to 0.3.
Object current in maximum tap position, IN2(+15%)
Corresponds on the CT2 secondary side to IN2
Differential current in maximum tap position IDiff
Stability of relay when the transformer is operating under no load (Secondary side breaker is open) and the transformer is drawn the magnetising current(up to 5% of rated current)
The minimum differential pickup should be above the no load current of the transformer when the secondary side of the breaker is open
0.05174.95
8.7475/4008.75
0.022
0.02220.044
No load current to the relay after applying magnitude compendation factor M[1],
0.00.0
| Is1+Is2 ||0.044+0 |0.0440
0.0440
Page 49 of 160
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SETTING CALCULATION FOR 132/33-40MVATRAFO DIFF PROTN CKD:
RELAY GE T60 BAY/FEEDER
VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE 16.09.13
132/33-40 MVA Trafo
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL) PRPD: MN
TITLE: GP
= | IN2(+15%) + INobj |= I0.905INobj+INobjl= 1.90 INobj
= SN/(1.732 X Vmin)= (40*1000)/(1.732x31.35)= 736.67
= IN2(-5%) / CT2= 736.67/800= 0.92 A ~ 1.10 INobj
= | IN2(-5%) - INobj |= I1.095INobj-INobjl= 0.10 INobj
= | IN2(-5%) + INobj |= I1.095INobj+INobjl= 2.10 INobj
Iop, Relay operating current at +15% tap, = slope1 X Irest= 0.25x1.905INObj= 0.48 INObj
whereas the Idiff , 0.1 INObj is less than 0.47 INObj . Hence the relay is Stable.
Iop, Relay operating current at -5% tap, = slope1 X Irest= 0.25x2.095INObj= 0.52 INObj
whereas the Idiff , 0.1 INObj is less than 0.51 INObj . Hence the relay is Stable.
From the above calculation it is derived that , under rated condition and at Tap Changer Extreme positions, Operating current are not in the Tripping Area .
C) Selection of Break point 2 and slope 2:
break point 2 The setting for Break point -2 depend very much on the capability of CTs to correctly transform Primary into
secondary currents during external faults. Break point -2 should be set below the fault current that is most likely to saturate some CTs due to an AC Component alone
External Fault current = 12.72 pu
Break point- 2 = 8 pu Slope-2 = 98% (as per relay catalogue)
2nd HARMONICS:
INRUSH INHIBIT LEVEL, = 20%INRUSH INHIBIT FUNCTION(now a days all modern transformers produce low 2nd harmonic ratios)INRUSH INHIBIT MODE PER PHASE
5TH HARMONICS:This setting is
OVEREXCITN INHIBIT LEVEL, = 30%Instantaneous differential protection:
The pickup thersold should be set greater than the maximum spurious differential current that could be encounteredunder non-internal fault conditions ( typically maganetizing inrush current or an external fault with extremely severe CT saturation.
I) Magnetizing inrush current = 6 x Full load current= 1049.70 A= 2.62 pu
Object current in minimum tap position, IN2(-5%)
Differential current in minimum tap position IDiff
Restriant current in minimum tap position IRestaint
The percentage of harmonics present in the inrush current, for the relay to recognise the inrush current is set as 20% as per manufacturer recommended,
ADAPTIVE 2nd Harmonic
Restriant current in maximum tap position IRestaint
Corresponds on the CT2 secondary side to IN2
Page 50 of 160
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SETTING CALCULATION FOR 132/33-40MVATRAFO DIFF PROTN CKD:
RELAY GE T60 BAY/FEEDER
VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE 16.09.13
132/33-40 MVA Trafo
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL) PRPD: MN
TITLE: GP
II) External fault condition:HV Side Fault Current = 3.18 puLV Side Fault Current = 6.36 pu
8 pu
VOLTS PER HERTZ (OVER FLUX):
According to experience we set the definite time curve with the following settings,Stage-1
Volts/Hz 1 Pickup, = 1.1 puVolts/Hz 1 Curve, = Definite TimeVolts /Hz 1 TD Multiplier, = 10.0 SVolts/Hz 1 T-Reset, = 0.0 S
Stage-2 Volts/Hz 2 Pickup, = 1.2 puVolts/Hz 2 Curve, = Definite TimeVolts /Hz 2 TD Multiplier, = 1.0 SVolts/Hz 2 T-Reset, = 0.0 S
Setting Table:
0.1 pu0.25
2 pu8 pu
0.980.2
5th0.3
8 pu
1.1 pu
10 s0 s
1.2 pu
1 s0 s
VOLTS/HZ 1
VOLTS/HZ 2
VOLTS/HZ 2 CURVEVOLTS/HZ 2 TD MULTIPLIERVOLTS/HZ 2 T-RESET
VOLTS/HZ 1 PICKUPVOLTS/HZ 1 CURVEVOLTS/HZ 1 TD MULTIPLIERVOLTS/HZ 1 T-RESET
VOLTS/HZ 2 PICKUP
2nd Harmonic INRUSH INHIBIT MODE2nd Harmonic INHIBIT FUNCTIONOVEREXCITN INHIBIT FUNCTIONOVEREXCITN INHIBIT LEVELINST DIFFERENTIAL PICKUP
4 pu
2 pu50%
Definite Time
Menu Text
PERCENT DIFFERENTIAL PICKUPPERCENT DIFFERENTIAL SLOPE1PERCENT DIFFERENTIAL BREAK1PERCENT DIFFERENTIAL BREAK2PERCENT DIFFERENTIAL SLOPE2
Definite Time, IDMT 5%
5%
Setting Range
PER PHASEAdaptive
Definite Time
40%30 pu
4 pu
600 S1000 S
Adaptive, Traditional,Disabled
600 S
0.8 pu
0 S
0.8 pu
1 pu1
2 pu30 pu
2 pu
perphase,2-out-of-3,Avg.
disabled,5th1%
10.4
Definite Time, IDMT
0 S 1000 S
1%
0.05 pu15%1 pu
2nd Harmonic INRUSH INHIBIT LEVEL
For safety margin we choosen instantaneous differential protection setting
The per-unit V/HZ value is calculated using the maximum of the three-phase voltage inputs or the auxiliary voltage channel Vx input, if the source is not configured with Phase voltages.
The volts-per-Hertz protection, to protect transformers during potentially damaging over voltage and under frequency disturbances.
PERCENT DIFFERENTIAL Recomm.Setting Min Max
Page 51 of 160
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220kV FEEDERS
Page 52 of 160
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MAKE MODEL
4.1. Directional Overcurrent and Earth Fault Protection for 160MVA Transformer(220kV Side)
CT DetailsCT Ratio = 800-400/1 ACT Primary = 800 ACT Secondary = 1 AClass = PS
Transformer Data:Rated power = 160 MVARated HV Voltage = 220.00 kVRated LV Voltage = 132.00 kVFull Load current HV Side = 419.90 AFull Load current LV Side = 699.84 A
Phase Over current settingO/C SETTING (51):
Load current I load = 419.90 ACT secondary current, = i Load / CT ratio
= 0.52Consider 110% of transformer Full load = 461.89 PrimaryPickup Phase fault Secondary , recommended = 0.58 SecondaryTime Multiplier SettingCharacteristics = IDMT Normal inverset Required operating time in seconds =
= 0.62
Fault current = 3660 AI Fault current at secondary = I fault / CT ratio
4.58 ATMS = (t *((If/IS)0.02 -1)) /0.14
= (0.62*(((4.58/0.6)^0.02)-1))/0.14)= 0.19
Maximum fault Current = 28160 A Primary= 35.20 A Secondary
Operating time at Maximum fault Current = 0.30 SecInstantaneous Phase Overcurrent Setting
= 4548.95 A= 5.69 A
t = 0.35 SecEarth Over current setting HV side
= 160 A Primary= I earth fault / CT ratio
Setting of 20% is selected = (160/800)= 0.20 A Secondary
Time Multiplier SettingCHARACTERISTICS = IDMT Normal inverse
t Required operating time in seconds =
= 0.74Fault current = 1420.00 AI Fault current at secondary = I fault / CT ratio
1.78TMS = (t *((If/IS)0.02 -1)) /0.14
= (0.74*(((1.78/0.2)^0.02)-1))/0.14)= 0.24
Maximum fault Current = 25980.00 A32.48
Operating time at Maximum fault Current = 0.31 SecInstantaneous Earth Overcurrent SettingFor High set considering the 200% of CT Primary Current = 1600.00 A
= 2.00 At = 0.50 Sec
grading time + Downstream relay operating timeMinimum grading time interval considered
in secFrom ETAP
grading time + Downstream relay operating timeMinimum grading time interval considered
in sec
From ETAP
For High set considering the 130% of Through Fault current in HV Side
Calculated
In solidly earthed system a setting of 10 to 20% of CT Primary current is considered
From ETAP
From ETAP
RELAY GE F650 BAY/FEEDER 220/132kV,160 MVA Trafo 220kV Side
The relay setting shall be such that it shall not operate for max. probable load current
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL) PRPD: MN
TITLE: SETTING CALCULATION FOR 160MVA TRANSFORMER 220kV SIDE CKD: GP
VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE 16.09.13
Page 53 of 160
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MAKE MODELRELAY GE F650 BAY/FEEDER 220/132kV,160 MVA Trafo 220kV Side
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL) PRPD: MN
TITLE: SETTING CALCULATION FOR 160MVA TRANSFORMER 220kV SIDE CKD: GP
VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE 16.09.13
Setting Table:
1 Degree
1 V
0.01 A
0.01 S
1 Degree
1 V
0.01 A
0.01 S
1 Degree
1 V
0.01 A
0.01 S
1 Degree
1 V
0.01 A
0.01 S
Forward/Reverse
0 300
0 900
F650
GROUP-1 Directional Earth Overcurrent- 67N
MENU TEXT RECOMMEND SETTINGSETTING RANGE
STEP SIZE UNITMINIMUM MAXIMUM
F650
GROUP-1 Directional Phase Overcurrent- 67 INST
MENU TEXT RECOMMEND SETTINGSETTING RANGE
STEP SIZE UNITMINIMUM MAXIMUM
Phase Overcurrent
Function Enabled Enabled/Disabled
160
MTA 45 -90 90Direction Forward Forward/Reverse
0 900
Pol V Threshold 40.00 0 300
Pickup Level 5.69 0.05
F650
GROUP-1 Directional Earth Overcurrent- 67N INST
MENU TEXT RECOMMEND SETTINGSETTING RANGE
STEP SIZE UNITMINIMUM MAXIMUM
Phase Overcurrent
Function Enabled Enabled/DisabledMTA -45 -90 90Direction Forward Forward/Reverse
Pol V Threshold 40.00 0 300
Pickup Level 2.0 0.05 160
Curve Definite Time
Time Dial Multiplier 0.50 0 900
0.05 160
Curve IEC Normal Inv
Time Dial Multiplier 0.24
Direction Forward
Pol V Threshold 40.00
Pickup Level 0.2
MTA -45 -90 90Function Enabled Enabled/DisabledPhase Overcurrent
Time Dial Multiplier 0.19 0 900
Curve Definite Time
Time Dial Multiplier 0.35
Curve IEC Normal Inv
Pickup Level 0.58 0.05 160
-90 90
Enabled/Disabled
Pol V Threshold 40.00 0 300
Direction
UNIT
Phase Overcurrent
Function Enabled
Forward Forward/Reverse
MTA 45
MENU TEXT RECOMMEND SETTINGSETTING RANGE
F650
MINIMUM MAXIMUMSTEP SIZE
GROUP-1 Directional Phase Overcurrent- 67
Page 54 of 160
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MAKE MODEL
4.2. Non Directional Overcurrent and Earth Fault Protection for 220kV Buscoupler
CT DetailsCT Ratio = 1600-800/1 ACT Primary = 1600 ACT Secondary = 1 AClass = PS
Transformer Data:Rated power = 160 MVARated HV Voltage = 220 kVRated LV Voltage = 132 kVFull Load current HV Side = 420 AFull Load current LV Side = 700 A
Phase Over current settingO/C SETTING (51):
Load current I load = 1600 ACT secondary current, = i Load / CT ratio
= 1.00Consider 110% of transformer Full load = 1600.00 PrimaryPickup Phase fault Secondary , recommended = 1.00 Secondary
Time Multiplier SettingCharacteristics = IDMT Normal inverse
t Required operating time in seconds =
= 0.87
Fault current (220kV Line-3+220kV Line-4) = 7980 AI Fault current at secondary = I fault / CT ratio
4.99 ATMS = (t *((If/IS)0.02 -1)) /0.14
= (0.87*(((4.99/1)^0.02)-1))/0.14)= 0.20
Maximum fault Current = 18150 A Primary= 11.34 A Secondary
Operating time at Maximum fault Current = 0.57 Sec
Earth Over current setting HV side
= 320.00 A Primary= I earth fault / CT ratio
Setting of 20% is selected = (320/1600)= 0.20 A Secondary
Time Multiplier SettingCHARACTERISTICS = IDMT Normal inverse
t Required operating time in seconds =
= 0.56
Fault current = 6950 AI Fault current at secondary = I fault / CT ratio
4.34TMS = (t *((If/IS)0.02 -1)) /0.14
= (0.56*(((4.34/0.2)^0.02)-1))/0.14)= 0.3
Maximum fault Current = 17460 A Primary= 10.91 A Secondary
Operating time at Maximum fault Current = 0.43 Sec
From ETAP
grading time Minimum grading time interval considered in sec
From ETAP
In solidly earthed system a setting of 10 to 20% of CT Primary current is considered
grading time + Downstream relay operating timeMinimum grading time interval considered
in sec
From ETAP
RELAY GE F650 BAY/FEEDER 220kV Bus Coupler
The relay setting shall be such that it shall not operate for max. probable load current
PRPD: MN
TITLE: SETTING CALCULATION FOR 220kV BUS COUPLER CKD: GP
From ETAP
VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE 16.09.13
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL)
Page 55 of 160
-
MAKE MODELRELAY GE F650 BAY/FEEDER 220kV Bus Coupler
PRPD: MN
TITLE: SETTING CALCULATION FOR 220kV BUS COUPLER CKD: GP
VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE 16.09.13
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL)
Setting Table:
0.01 A
0.01 S
0.01 A
0.01 S
Phase Overcurrent
MENU TEXT RECOMMEND SETTING
0 900
SETTING RANGESTEP SIZE
0.05 160
Curve IEC Normal Inv
Time Dial Multiplier 0.3
GROUP-1 Directional Earth Overcurrent- 67N
Function Enabled Enabled/DisabledPickup Level 0.2
UNITMINIMUM MAXIMUM
160
Time Dial Multiplier 0.20 0 900
F650
Phase Overcurrent
Function Enabled Enabled/Disabled
Curve IEC Normal Inv
Pickup Level 1.00 0.05
F650
GROUP-1 Directional Phase Overcurrent- 67
MENU TEXT RECOMMEND SETTINGSETTING RANGE
MINIMUM MAXIMUMSTEP SIZE UNIT
Page 56 of 160
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MAKE MODEL
4.3. Non Directional Overcurrent and Earth Fault Protection for 220kV Line
CT DetailsCT Ratio = 1600-800/1 ACT Primary = 1600 A For 10kM Line
800 A For 40 & 50kM LineCT Secondary = 1 AClass = PS
Transformer Data:Rated power = 160 MVARated HV Voltage = 220 kVRated LV Voltage = 132 kVFull Load current HV Side = 420 AFull Load current LV Side = 700 A
Phase Over current settingO/C SETTING (51):
Load current I load = 1600 ACT secondary current, = i Load / CT ratio
= 1.00Consider 110% of transformer Full load = 1600.00 PrimaryPickup Phase fault Secondary , recommended = 1.00 Secondary
Time Multiplier SettingCharacteristics = IDMT Normal inverse
t Required operating time in seconds =
= 0.82Fault current = 7980 AI Fault current at secondary = I fault / CT ratio
4.99 ATMS = (t *((If/IS)0.02 -1)) /0.14
= (0.82*(((4.99/1)^0.02)-1))/0.14)= 0.2
Maximum fault Current = 28160 A Primary= 17.60 A Secondary
Operating time at Maximum fault Current = 0.45 SecEarth Over current setting HV side
= 320 A Primary= I earth fault / CT ratio
Setting of 20% is selected = (320/1600)= 0.20 A Secondary
Time Multiplier SettingCHARACTERISTICS = IDMT Normal inverse
t Required operating time in seconds =
= 0.68
Fault current = 6950 AI Fault current at secondary = I fault / CT ratio
4.34375TMS = (t *((If/IS)0.02 -1)) /0.14
= (0.68*(((4.34/0.2)^0.02)-1))/0.14)= 0.31
Maximum fault Current = 26870 A Primary= 16.79 A Secondary
Operating time at Maximum fault Current = 0.47 Sec
From ETAP
grading time + Downstream relay operating timeMinimum grading time interval
considered in secFrom ETAP
In solidly earthed system a setting of 10 to 20% of CT Primary current is considered
grading time + Downstream relay operating timeMinimum grading time interval
considered in sec
From ETAP
RELAY GE D60 BAY/FEEDER 220kV Line
The relay setting shall be such that it shall not operate for max. probable load current
PRPD: MN
TITLE: SETTING CALCULATION FOR 220kV LINE CKD: GP
From ETAP
VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE 16.09.13
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL)
Page 57 of 160
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MAKE MODELRELAY GE D60 BAY/FEEDER 220kV Line
PRPD: MN
TITLE: SETTING CALCULATION FOR 220kV LINE CKD: GP
VOLTECH ENGINEERS PVT. LTDDOCUMENT No.
VE-J108-D-E212
DATE 16.09.13
PROJECT: POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL)
Setting Table:
0.01 A
0.01 S
0.01 A
0.01 S
Phase Overcurrent
MENU TEXTRECOMMEND
SETTING
0 900
SETTING RANGESTEP SIZE
0.05 160
Curve IEC Normal Inv
Time Dial Multiplier 0.31
GROUP-1 Non Directional Earth Overcurrent- 51N
Function Enabled Enabled/DisabledPickup Level 0.2
UNITMINIMUM MAXIMUM
160
Time Dial Multiplier 0.19 0 900
F650
Phase Overcurrent
Function Enabled Enabled/Disabled
Curve IEC Normal Inv
Pickup Level 1.00 0.05
D60
GROUP-1 Non Directional Phase Overcurrent- 51
MENU TEXTRECOMMEND
SETTING
SETTING RANGE
MINIMUM MAXIMUMSTEP SIZE UNIT
Page 58 of 160
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MAKE MODEL
4.4. Distance Protection -220kV Line(50kM)
System Details for 220kV lineNominal system voltage,UN = 220000V 220000 VCurrent transformer ratio,Nct = 800/1A 800.0Voltage transformer ratio,Nvt = 220000/110 2000.0Ratio of secondary to primary impedance,Nct/Nvt =Protected OHL Type =Current rating in Amps = Considered CT RatioProtected OHL length = KMPositive seq.Resistance of OHL in , per kM, Rprim =Positive seq.Reactance of OHL in , per kM, Xprim =Positive seq.impedance of OHL in , per kM, Zprim = 0.436 78.9 O
Zero seq.Resistance of OHL in , per kM, Rprim =Zero seq.Reactance of OHL in , per kM, Xprim =Zero seq.impedance of OHL in , per kM, Zprim = 1.274 76.8 O
Adjacent Longest Line detailsProtected OHL length = KMPositive seq.Resistance of OHL in , per kM, Rprim =Positive seq.Reactance of OHL in , per kM, Xprim =Positive seq.impedance of OHL in , per kM, Zprim = 0.436 78.9 O
Zero seq.Resistance of OHL in , per kM, Rprim =Zero seq.Reactance of OHL in , per kM, Xprim =Zero seq.impedance of OHL in , per kM, Zprim = 1.274 76.8 O
Adjacent Shortest Line detailsProtected OHL length = KMPositive seq.Resistance of OHL in , per kM, Rprim =Positive seq.Reactance of OHL in , per kM, Xprim =Positive seq.impedance of OHL in , per kM, Zprim = 0.44 78.9 O
Zero seq.Resistance of OHL in , per kM, Rprim =Zero seq.Reactance of OHL in , per kM, Xprim =Zero seq.impedance of OHL in , per kM, Zprim = 1.27 76.8 O
PT Details:PT Ratio = 220000/110 V
PT Primary Voltage = 220000.0 VPT Secondary Voltage = 110.0 V
System Frequency = 50.0 HZ
Distance element Settings:Reactance settingsZone 1 SettingsRequired Zone 1 reach is to be 85% of the Protected line
X1prim = 85% * Xprim = 18.19X1sec = Nct/Nvt * Xprim = 7.28
Zone 2 SettingsZone 2 element setting with a reach of 120% of Protected line reactance accounts for effect of infeed.This point must be verified using a fault study to calculate the apparent ohms at the local terminal for a fault at the remote end of transmission line. In our case 120% is considered for the zone-2 elements with assurance that all faults in the protected line are detectable,even with infeed from remote terminals.
Assuming the zone-1 reach for the adjacent line protection is set at 85% of that line reactance, and it is to be verified such that the zone-2 reach of 120%(protected line) shall not extend beyond the max.effective zone-1 reach of the adjacent line protection.Zone-2 setting limit = (Protected line reactance +
0.85 * adjacent shortest line reactance)= 12.05
Zone-2 setting with 120% reach = 10.272Since 120%, 10.272 is lower than zone-2 limit. 12.048, so the zone-2 setting of 120% will not overreach beyond zone-1 settingof adjacent line protection. Therefore we consider 120% of protected line reactance
Hence set X2 prim = 25.68Hence set X2 sec = 10.27
PRPD: MN
CKD: GP
POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL)
220kV Line(50Km)
TITLE: SETTING CALCULATION FOR DISTANCE PROTECTION
PROJECT:
VOLTECH ENGINEERS PVT. LTDDOCUMENT No.