voltech engineers relay setting calculation

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


in secFrom ETAP

Page 21 of 160

MAKE MODEL


VE-J108-D-E212

DATE 16.09.13


TITLE: SETTING CALCULATION FOR 132/33kV TRANSFORMER(40MVA) CKD: GP


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



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



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


300

Time Dial Multiplier 0.44

-90 90


Curve Definite Time

Time Dial Multiplier



0.30 0 900

F650

GROUP-1 Directional Earth Overcurrent- 67N INST



Phase Overcurrent

Function Enabled Enabled/DisabledMTA -45 -90 90Direction Forward Forward/Reverse



Curve Definite Time


Page 22 of 160

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3.2. Directional Overcurrent and Earth Fault Protection for 132kV Side of 220/132kV Transformer(160MVA)


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



= 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


Time Multiplier SettingCHARACTERISTICS = IDMT Normal inverse


= 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


in sec

From ETAP


in sec

From ETAP


From ETAP





TITLE: SETTING CALCULATION FOR 132kV SIDE TRANSFORMER(160MVA) CKD: GP


VE-J108-D-E212

DATE 16.09.13

Page 23 of 160

MAKE MODELRELAY GE F650 BAY/FEEDER 220/132kV,160 MVA Trafo 132kV Side


TITLE: SETTING CALCULATION FOR 132kV SIDE TRANSFORMER(160MVA) CKD: GP


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


Direction

F650




F650




Phase Overcurrent

Function Enabled Enabled/DisabledMTA 45 -90 90Direction Forward Forward/Reverse

900





Phase Overcurrent




Curve Definite Time


0.05 160



Forward


Pickup Level 0.2

MTA -45 -90 90Function Enabled Enabled/DisabledPhase Overcurrent


Curve Definite Time

Time Dial Multiplier 0.50 0





MTA 45 -90 90Enabled/Disabled

Phase Overcurrent

Function Enabled

MINIMUM MAXIMUMSTEP SIZE UNITMENU TEXT RECOMMEND SETTING

SETTING RANGE

F650


Page 24 of 160

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3.3. Directional Overcurrent and Earth Fault Protection for 132kV Line



Load current I load = 400 ACT secondary current, = i Load / CT ratio




= 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




= 0.65


5.98TMS = (t *((If/IS)0.02 -1)) /0.14

= (0.65*(((5.98/0.2)^0.02)-1))/0.14)= 0.33


VE-J108-D-E212

DATE 16.09.13


TITLE: SETTING CALCULATION FOR 132kV LINE CKD: GP

RELAY GE F650 BAY/FEEDER 132kV Line


grading time + Zone-2 operating timeMinimum grading time interval considered in sec

From ETAP



in sec

From ETAP

Page 25 of 160

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VE-J108-D-E212

DATE 16.09.13



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



STEP SIZE UNITMAXIMUM


STEP SIZE UNIT

F650

Phase Overcurrent

Function Enabled

MINIMUM MAXIMUM

Enabled/Disabled


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


Phase Overcurrent

MTA -45.00 -90 90

Curve

Enabled Enabled/Disabled

Direction ForwardPol V Threshold 40.00

Forward/Reverse

IEC Normal Inv

300



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


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


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


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

MAKE MODEL


VE-J108-D-E212

DATE


16.09.13

PRPD: MN


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.


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




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


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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VE-J108-D-E212

DATE


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PRPD: MN



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


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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VE-J108-D-E212

DATE


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PRPD: MN



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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VE-J108-D-E212

DATE


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PRPD: MN



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



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



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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VE-J108-D-E212

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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 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


LOAD ENCROACHMENTLOAD ENCROACHMENT MIN VOLTLOAD ENCROACHMENT REACHLOAD ENCROACHMENT ANGLELOAD ENCROACHMENT PKP DELAYLOAD ENCROACHMENT RST DELAY



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



-30.29 DEG


7.15 68.82 DEG6.33 68.82 DEG6.33 68.82 DEG0.80 S0.22

-30.29 DEG


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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DATE


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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

MAKE MODEL


















8.600.1670.432


VE-J108-D-E212

DATE


16.09.13

PRPD:

0.622

MN



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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VE-J108-D-E212

DATE


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PRPD: MN









= (110/3/1)

= 63.51

= 38.11 secondary

= 50.81 secondary

Ra = (28710 x L) / If^1.4


Ra =


= 0.54


















Page 35 of 160

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VE-J108-D-E212

DATE


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PRPD: MN







R0-R1 = 0.24X0-X1 = 0.19Z0-Z1 = 0.31 38.53 O





Rload sec = 57.16
















Page 36 of 160

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VE-J108-D-E212

DATE


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PRPD: MN






time delay = 5.00 s












=Under voltage =


= V pu


132000/1101200.00


118800/120099.0000.903.00

Page 37 of 160

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VE-J108-D-E212

DATE


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PRPD: MN



Settings Table






22.00 kmForward








Page 38 of 160

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VE-J108-D-E212

DATE


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PRPD: MN











-30.29 DEG



-30.29 DEG


7.63 68.82 DEG6.51 68.82 DEG6.51 68.82 DEG0.80 S0.22

-30.29 DEG


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

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VE-J108-D-E212

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FUNCTION







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


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



0.90 pu3.00 s

5.00 SUNDERVOLTAGE


Page 40 of 160

MAKE MODEL


















5.600.1670.432


VE-J108-D-E212

DATE


16.09.13

PRPD:

0.622

MN



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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VE-J108-D-E212

DATE


16.09.13

PRPD: MN









= (110/3/1)

= 63.51

= 38.11 secondary

= 50.81 secondary

Ra = (28710 x L) / If^1.4


Ra =


= 0.40


















Page 42 of 160

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VE-J108-D-E212

DATE


16.09.13

PRPD: MN







R0-R1 = 0.24X0-X1 = 0.19Z0-Z1 = 0.31 38.53 O





Rload sec = 57.16
















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VE-J108-D-E212

DATE


16.09.13

PRPD: MN






time delay = 5.00 s












=Under voltage =


= V pu


132000/1101200.00


118800/120099.0000.903.00

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VE-J108-D-E212

DATE


16.09.13

PRPD: MN



Settings Table






15.00 kmForward








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VE-J108-D-E212

DATE


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PRPD: MN











-30.29 DEG



-30.29 DEG


3.08 68.82 DEG4.75 68.82 DEG4.75 68.82 DEG0.80 S0.22

-30.29 DEG


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

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VE-J108-D-E212

DATE


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PRPD: MN





FUNCTION







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


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



0.90 pu3.00 s

5.00 SUNDERVOLTAGE


Page 47 of 160

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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


VE-J108-D-E212

DATE 16.09.13

132/33-40 MVA Trafo


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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VE-J108-D-E212

DATE 16.09.13

132/33-40 MVA Trafo


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


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%)


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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VE-J108-D-E212

DATE 16.09.13

132/33-40 MVA Trafo


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


Page 50 of 160

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VE-J108-D-E212

DATE 16.09.13

132/33-40 MVA Trafo


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

220kV FEEDERS

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4.1. Directional Overcurrent and Earth Fault Protection for 160MVA Transformer(220kV Side)


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



= 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


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




= 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


in secFrom ETAP


in sec

From ETAP


Calculated


From ETAP

From ETAP




TITLE: SETTING CALCULATION FOR 160MVA TRANSFORMER 220kV SIDE CKD: GP


VE-J108-D-E212

DATE 16.09.13

Page 53 of 160

MAKE MODELRELAY GE F650 BAY/FEEDER 220/132kV,160 MVA Trafo 220kV Side


TITLE: SETTING CALCULATION FOR 160MVA TRANSFORMER 220kV SIDE CKD: GP


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




F650




Phase Overcurrent


160

MTA 45 -90 90Direction Forward Forward/Reverse

0 900


Pickup Level 5.69 0.05

F650




Phase Overcurrent




Curve Definite Time


0.05 160



Direction Forward


Pickup Level 0.2

MTA -45 -90 90Function Enabled Enabled/DisabledPhase Overcurrent


Curve Definite Time




-90 90

Enabled/Disabled


Direction

UNIT

Phase Overcurrent

Function Enabled

Forward Forward/Reverse

MTA 45


F650

MINIMUM MAXIMUMSTEP SIZE


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4.2. Non Directional Overcurrent and Earth Fault Protection for 220kV Buscoupler


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






= 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


Operating time at Maximum fault Current = 0.57 Sec

Earth Over current setting HV side

= 320.00 A Primary= I earth fault / CT ratio




= 0.56


4.34TMS = (t *((If/IS)0.02 -1)) /0.14

= (0.56*(((4.34/0.2)^0.02)-1))/0.14)= 0.3



From ETAP

grading time Minimum grading time interval considered in sec

From ETAP



in sec

From ETAP

RELAY GE F650 BAY/FEEDER 220kV Bus Coupler


PRPD: MN

TITLE: SETTING CALCULATION FOR 220kV BUS COUPLER CKD: GP

From ETAP


VE-J108-D-E212

DATE 16.09.13


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MAKE MODELRELAY GE F650 BAY/FEEDER 220kV Bus Coupler

PRPD: MN

TITLE: SETTING CALCULATION FOR 220kV BUS COUPLER CKD: GP


VE-J108-D-E212

DATE 16.09.13


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




Function Enabled Enabled/DisabledPickup Level 0.2

UNITMINIMUM MAXIMUM

160


F650

Phase Overcurrent




F650



MINIMUM MAXIMUMSTEP SIZE UNIT

Page 56 of 160

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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






= 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


Operating time at Maximum fault Current = 0.45 SecEarth Over current setting HV side

= 320 A Primary= I earth fault / CT ratio




= 0.68


4.34375TMS = (t *((If/IS)0.02 -1)) /0.14

= (0.68*(((4.34/0.2)^0.02)-1))/0.14)= 0.31



From ETAP

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

RELAY GE D60 BAY/FEEDER 220kV Line


PRPD: MN


From ETAP


VE-J108-D-E212

DATE 16.09.13


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MAKE MODELRELAY GE D60 BAY/FEEDER 220kV Line

PRPD: MN



VE-J108-D-E212

DATE 16.09.13


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



GROUP-1 Non Directional Earth Overcurrent- 51N

Function Enabled Enabled/DisabledPickup Level 0.2

UNITMINIMUM MAXIMUM

160


F650

Phase Overcurrent




D60

GROUP-1 Non Directional Phase Overcurrent- 51

MENU TEXTRECOMMEND

SETTING

SETTING RANGE

MINIMUM MAXIMUMSTEP SIZE UNIT

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4.4. Distance Protection -220kV Line(50kM)













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



PRPD: MN

CKD: GP

POWER TRANSMISSION CORPORATION OF UTTARKHAND LIMITED(PTCUL)

220kV Line(50Km)

TITLE: SETTING CALCULATION FOR DISTANCE PROTECTION

PROJECT:


voltech engineers relay setting calculation

Documents

maximum fault current

ai fault current

minimum fault current

current setting hv

ct primary current

current settingoc setting

act secondary current

kvfull load current