Sravanthi Relay Setting Chart
Transcript of Sravanthi Relay Setting Chart
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Revision
Rev Descriptions Date Approved
0 R0-Issued for approval 11.07.11
PROJECT225 MW KASHIPUR GAS COMBINED CYCLE POWERPROJECT AT KASHIPUR.
OWNER M/s. SRAVANTHI ENERGY PVT LTD.
OWNER
CONSULTANTM/S.TATA CONSULTING ENGINEERS LIMITED, BANGALORE.
EPC
CONTRACTOR
M/s. SRAVANTHI INFRATECH PVT
LTD (EPC DEVISION)
EPC
CONSULTANT
M/s. TOSHIBA TERMAL AND HYDRO POWER SYSTEM
COMPANY TOSHIBA INDIA PVT LTD.Prepared by 11.07.11
STG RELAY SETTINGSSRIRANGAN
Checked by 11.07.11 GREENESOL POWER SYSTEMS PVT. LTD.,# 995, SERVICE ROAD,RPC LAYOUT, VIJAYANAGAR,
BENGALURU 560 040.
ARK
Approved by 11.07.11
DJY
CAD File Date: Size Scale Drawing No: P-1113-G60-1-RS
Office: GPSPL NA
Job Number: P-1113
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Input Details
Generator data:
Rated Generator output: 100 MVA (80 MW)
Rated voltage between phases: 11.5 kVPower Factor: 0.8Rated speed: 3000 rpmFrequency: 50 Hz
Current at full load = 100x 106/ 3 x 11.5 x 103= 5020.58 AI2Capability : 10%I2
2t Constant: = 15Direct axis synchronous reactance Xd(UNSAT) : 2.077 p.uDirect axis synchronous reactance Xd(UNSAT) :2.7468 OhmsDirect axis transient reactance Xd(SAT) : 0.163 p.uDirect axis transient reactance Xd(SAT) :0.2155 Ohms [(kV
2/ MVA) * p.u)]Direct axis sub transient reactance Xd(SAT): 0.103 p.u
Direct axis sub transient reactance Xd(SAT):0.1362 ohms [(kV2
/ MVA) * p.u)]Fault current: 80KALine-1 length: 18km ACSR DRAKE conductor (To be confirmed by consultant)Line-2 length: 4km ACSR DRAKE conductor (To be confirmed by consultant)
Neutral grounding Transformer (NGT)Ratio: 11KV/220V
CT / PT DetailsGenerator 11.5 kV side, CT ratio: 5500/1 A
GROUND CTRATIO:50/1A
Generator PT ratio: 11.5kV/3/ 1103 V
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Generator Protection
Protection functions Generator Protection system GPR-1 G60 are:Note: Similar protection functions are enabled in GPR-2 relay also.
1. Generator Differential Protection - 872. Generator Unbalance Protection 463. Loss of Excitation Protection 404. Under Frequency 81U5. Over Frequency 81O6. Over Voltage 597. Under Voltage 27
8. Over Excitation / Over Fluxing Protection 249. Phase Instantaneous O/C Protection 50P10. Phase IDMT O/C Protection 51P11. Neutral IDMT O/C Protection 51N12. Directional Power Protection - 3713. 100% Stator Ground Fault Protection 64TN14. Dead Machine Protection 50/2715. System Back-up O/C Protection - 51V16. Back-up Impedance protection 21G17. Pole Slipping Protection (78G)18. Reverse active power protection (32P)19. Reverse reactive power protection(32Q)
Protection functions for CDG 11 relay
1. Stand-by Earth fault Protection (51S)
Protection functions for RXNB-4 relay
1. Rotor Earthfault Protection (64F)
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Generator Differential Protection (87)
Relay Type - G60Make - GE MULTILIN
CalculationThe differential current pickup setting can be set as low as 5% of rated generator current, toprovide protection for as much of the winding as possible. Thus, to obtain maximum sensitivity,the differential pickup current is chosen as 0.05 P.U.
The percentage differential element has a dual slope characteristic.The through current is adjusted to compensate for CT ratio error mismatch and CT response viaa dual slope characteristic typically as shown below.
Slope 1, set at 15% starting from 0.04 (Restrain Current) as shown below.The STATOR DIFF BREAK 1 setting should greater than the maximum overload expected for the
machine, so it is set at 1.25 PU
Slope 2, set at 80 %.The STATOR DIFF BREAK 2 setting is set at 3 PU.
0.5 2.0 3.02.51.0 1.5
0.5
2.
0
3.0
4.0
5.0
6.0
1.0
I Restraint (Multiples of CT)
IOperate
(MultiplesofCT)
Slope 115 %
Slope 2
80 %
Operating
Region
Restraint
Region
Minimum Pickup = 0.5
Fig-1
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Protection Setting
SlNo
ProtectionFunction
Setting Available in the Relay RecommendedSetting
Remarks
1 Stator Differential
PickupSlope 1Break 1
0.05 to 1 p.u in 0.001 p.u steps.1 - 100% in 1% steps.1 to 1.5 p.u in 0.01 p.u steps.
0.0515%1.25
Slope 2
Break 2
1-100%IN 1%STEPS
1.5 to 30 p.u 0.01 p.u steps
80%
3.00 p.u
Generator Unbalance Protection (46)
Calculation
System Details:
Asymmetrical short circuit performance is given by I22t = 10
Continuous negative sequence capability = 8%CT Ratio = 5500/1
The generator nominal currentInom(p.u) = (Inomprimary) / CT Primary
=5020.4/5500
= 0.912 P.URecommended settings:Stage 1Pickup = 100% x I2 capability
= 1.0 x 8%= 8 %of FLC= 8%
The minimum operate time of Stage 1 = 0.2secondsThe maximum operating time = 600 seconds
Stage 2 is typically set lower than Stage 1 with a time delay to prevent nuisance alarms forexternal faults that are normally cleared by system protection.Stage 2 pickup = 5.6% (70% of I2capability) with time delay of 10 sec.
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Protection Setting
Sl
No
Protection Function Setting Available in the Relay Recommended
Setting
Remarks
1 GEN UNBAL INOMStage 1 PickupStage 1 K-ValueStage 1 TminStage 1 TmaxStage 1 K-ResetStage 2 PickupStage 2 PickupDelay
0.000 to 1.250 p.u in steps of 0.0010.00 to 100.00% in steps of 0.010.00 to 100.00 in steps of 0.010.000 to 50.000 s in steps of 0.0010.0 to 1000.0 s in steps of 0.10.0 to 1000.0 s in steps of 0.10.05 to 30.00 p.u in steps of 0.010.0 to 1000.0 s in steps of 0.1
0.9128%100.2 s600.0 s240.0 s5.6%10 s
Stage 1for86BTrip
Stage 2for 86CTrip
Loss of Excitation Protection (40)
This protection is applicable when the unit is running in Generator Mode.
CalculationXd = 2.077 puXd = 0.163 pu
MVA =100
CTR/PTR = (5500 / 1) x (110/11500) = 52.6
Zbase(sec) = (base kV
2
/ base MVA) x (CT ratio / VT ratio)= (11.5 kV2 / 100 MVA) x (5500/ 104.5) = 69.63
Xd (sec) =Xdx Zb
= 0.163 69.63 = 11.34
Xd(sec) = Xdx Zb
= 2.07769.63 =144.62
CENTER 1 = (Zbase(sec) + Xd(sec) ) / 2 = (69.63+ 11.34) /2 = 40.48RADIUS 1 = Zbase (sec)/2 = (69.63 ) /2 = 34.81 PICKUP DELAY 1 = 0.06 seconds
The stage 1 element should be time delayed to allow for blocking by the VT fuse failure element(50mS)
CENTER 2 = (Xd(sec)+ Xd(sec)) / 2 = (144.62 +11.34 ) /2= 77.98RADIUS 2 = Xd(sec)/ 2= (144.62)/2 = 72.31
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During stable Power swing conditions the positive-sequence impedance maymomentarily enter the stage 2 characteristics. For security of the function under suchconditions, it is recommended to delay stage2 by a minimum of 0.5 seconds
FIG-2
Protection Setting
SlNo
Protection Function Setting Available in the Relay RecommendedSetting
Remarks
Center 1Radius 1UV SupervisionPickup Delay 1
Center 2Radius 2UV Supervision
Pickup Delay 2UV Supervision
0.10 to 300.00 in steps of 0.010.10 to 300.00 in steps of 0.01Disabled, Enabled0.000 to 65.535 s in steps of 0.01
0.10 to 300.00
in steps of 0.010.10 to 300.00 in steps of 0.01Disabled, Enabled
0.000 to 65.535 s in steps of 0.010.000 to 1.250 p.u in steps of 0.001
40.4834.81Enabled0.06
77.9872.31Disabled
0.50.7
BLOCK Flex logic VT FUSE FAIL
Under Frequency Protection (81U)
Rated frequency is 50 Hz
UNDERFREQUENCY 1
SlNo
Protection Function Setting Available in theRelay
RecommendedSetting
Remarks
1 Min Volt/Amp 0.10 to 1.25 p.u in stepsof 0.01
0.5 To Trip 86C
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Pickup 20.00 to 65.00 Hz in stepsof 0.01
47.5
Pickup Delay 0.000 to 65.535 s in stepsof 0.001
0.5 sec
Reset Delay 0.000 to 65.535 s in steps
of 0.001
0 sec
UNDERFREQUENCY 2
SlNo
Protection Function Setting Available in theRelay
RecommendedSetting
Remarks
1 Min Volt/Amp 0.10 to 1.25 p.u in stepsof 0.01
0.5 To Trip 86B
Pickup 20.00 to 65.00 Hz in stepsof 0.01
47.5
Pickup Delay 0.000 to 65.535 s in stepsof 0.001
3 sec
Reset Delay 0.000 to 65.535 s in stepsof 0.001
0 sec
Over Frequency Protection (81O)
Stage -1
SlNo
Protection Function Setting Available in theRelay
RecommendedSetting
Remarks
1 Min Volt/Amp 0.10 to 1.25 p.u in stepsof 0.01
0.5 To Trip 86C
Pickup 20.00 to 65.00 Hz in stepsof 0.01
52.5
Pickup Delay 0.000 to 65.535 s in stepsof 0.001
0.5 sec
Reset Delay 0.000 to 65.535 s in stepsof 0.001 0 sec
BLOCK Flex logic
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Stage-2
SlNo
Protection Function Setting Available in theRelay
RecommendedSetting
Remarks
1 Min Volt/Amp 0.10 to 1.25 p.u in steps
of 0.01
0.5 To Trip 86B
Pickup 20.00 to 65.00 Hz in stepsof 0.01
52.5
Pickup Delay 0.000 to 65.535 s in stepsof 0.001
3 sec
Reset Delay 0.000 to 65.535 s in stepsof 0.001
0 sec
BLOCK Flex logic
Over Voltage Protection (59)
These settings are used as backup for failure of AVR or other regulators. The time settings shouldalso be depended on the withstand levels of the machine
Calculations:Trip stage-1 & 2 110 % of the rated Voltage
Protection Setting Stage-1
SlNo
ProtectionFunction
Setting Available in the Relay RecommendedSetting
Remarks
Pickup 0.000 to 3.000 p.u in steps of 0.001 1.1 p.u To TRIP 86CDelayReset Delay
0.00 to 600.00 s in steps of 0.010.00 to 600.00 s in steps of 0.01
0.5 s1.00 s
Stage-2 (Flex Elements-1, 2 & 3)
SlNo
ProtectionFunction
Setting Available in the Relay RecommendedSetting
Remarks
Pickup -90 to 90 p.u in steps of 0.001 1.1 p.u To TRIP 86B
Delay 0.00 to 65.50 s in steps of 0.001 3.00 s
Under Voltage Protection (27)
Calculations:Trip stage-1 & 2 90 % of the rated Voltage
Under Voltage stage 1
SlNo
ProtectionFunction
Setting Available in the Relay RecommendedSetting
Remarks
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1 Mode Phase to Ground, Phase to Phase Phase to Phase To Trip 86C
Pickup 0.000 to 3.000 p.u in steps of 0.001 0.90 p.u
Curve
Delay
Definite Time, Inverse Time
0.00 to 600.00 s in steps of 0.01
Definite Time
0.50 s
Min Volt 0.000 to 3.000 p.u in steps of 0.001 0.100 p.u
Under Voltage stage 2
SlNo
ProtectionFunction
Setting Available in the Relay RecommendedSetting
Remarks
1 Mode Phase to Ground, Phase to Phase Phase to Phase To Trip 86B
Pickup 0.000 to 3.000 p.u in steps of 0.001 0.90 p.u
Curve
Delay
Definite Time, Inverse Time
0.00 to 600.00 s in steps of 0.01
Definite Time
3.00 s
Min Volt 0.000 to 3.000 p.u in steps of 0.001 0.100 p.u
Over Excitation Protection (24)Calculations:Rated Generator Voltage: 11.5 kV, 50 HzRatio of the voltage transformer: 11500/3/110/3
Rated generator secondary voltage: 63.5Rated generator V/Hz on secondary side: 63.5/50 = 1.27 V/Hz.With max. Permissible continuous over excitation 105% (assumed)
Definite Time Element (ALARM SETTING):Minimum Pickup Level = 1.06 x 1.27 = 1.3462 PU (106 %)Independent Time Delay= 3 s
Inverse Time Element (TRIP SETTING):Select setting 110 % of rated generator V/Hz.Minimum Pickup Level = 1.1 x 1.27 V/Hz = 1.397 PU
Protection SettingVOLTS PER HERTZ 1 (Stage-1)
SlNo
Protection Function Setting Available in the Relay RecommendedSetting
Remarks
1 Pickup 0.80 to 4.00 p.u in steps of0.01
1.35 ALARM
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2CURVES
Definite Time, Inverse A,Inverse B, Inverse C,Flex Curve A, Flex Curve B
Definite time3 seconds
3TDMULTIPLIER
0.05 to 600.00 in steps of 0.01
4 T Reset 0.0 to 1000.0 s in steps of 0.1 1 second
VOLTS PER HERTZ 2 (Stage-2)
SlNo
Protection Function Setting Available in the Relay RecommendedSetting
Remarks
1 Pickup 0.80 to 4.00 p.u in steps of0.01
1.4 To TRIP 86B
2 Curves Definite Time, Inverse A,Inverse B, Inverse C,
Flex Curve A, Flex Curve B
Inverse B
3 TD Multiplier 0.05 to 600.00 in steps of 0.01 3 sec
4 T Reset 0.0 to 1000.0 s in steps of 0.1 0.1sec
Generator Phase Instantaneous O/C (IOC) Protection (50P)
The phase instantaneous overcurrent element is used as an instantaneous element with nointentional delay or as a Definite Time element. The input current is the fundamental phasor
magnitude.The setting is selected to protect for fault at or near generator terminals.
CalculationPhase Instantaneous Over CurrentMax. Fault current of Generator = 48741.74A (i.e 5020.4 / 0.103)
Therefore we have chosen the trip setting as 30% of the total fault value for protecting thegenerator windings. i.e 48741x0.3 = 14622.52A. When it is converted into secondary we get14622.52 / 5020.4 = 2.91 p.u
PROTECTION SETTING
SlNo
Protection Function Setting Available in the Relay RecommendedSetting
Remarks
Pickup 0.000 to 30.000 p.u in steps of0.001
2.91 p.u
Delay 0.00 to 600.00 s in steps of0.01
0
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Reset Delay 0.00 to 600.00 s in steps of0.01
0
Generator Phase time O/C (TOC) Protection (51P)
This protection is implemented using a Phase TOC element.The pickup of this element is set at a safe margin above the maximum load expected on themachine.
Pickup = 1.1x Generator Nominal CurrentCT Primary
= 1.1 x 5020.45500
= 1.004P.U
The equation for IEC Curve-A is as follows:
T = TDM x KI E
I Pick up - 1
Where, I= Input current, I Pickup=Relay Setting current, K = 0.14(constant), E = 0.020
(constant) and Considered operating time for a three phase fault on the HV side oftransformer as 0.50s (to be confirmed by customer).
0.50TDM = 0.14
8.86 0.021.004 - 1
TDM = 0.16
Protection setting
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Available Setting Recommended Setting
Function Enabled, Disable Enabled
Input Phasor, RMS Phasor
Pickup 0.00 to 30.00pu in steps of 0.001 1.004P.U
Curve IEC Curve-A
TD Multiplier 0.00 to 600.00 in steps of 0.01 0.16
Reset Instantaneous, Timed InstantaneousVoltage Restraint Disabled, Enabled Disabled
Target Self-reset, Latched, Disabled Latched
Events Disabled, Enabled Enabled
Directional PowerLow Forward Power (37)
Assuming 10% as the minimum power below which the generator should trip on turbine faults, weget: 10%of 80MW = 0.1 X 80 = 8 MW
Smin = Minimum operating Power (PW)
3 X Phase CT Primary X Phase VT Ratio X Phase VT Sec
= 8MW
3 X 5500 X 104 X 63.5
= 0.073 P.U
Smin = - 0.0734 P.U (For Low forward power SMIN< 0. Refer b diagram below)Delay = 3 secondsRCA = 180
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Available setting Sensitive Power 1 Sensitive Power 2
SensitiveDirectional PowerRCA
0 to 359 in steps of 1 180 270
Stage 1 SMIN 1.200 to 1.200 pu in stepsof 0.001 - 0.0734 p.u 0.0743 p.u
Stage 1 Delay 0.00 to 600.00 s in stepsof 0.01
3 seconds 2 seconds
Stage 2 SMIN 1.200 to 1.200 pu in stepsof 0.001
0.0743 p.u NA
Stage 2 Delay 0.00 to 600.00 s in stepsof 0.01
2 seconds NA
Block VT FUSE FAIL OP VT FUSE FAIL OP
100% Stator Ground Fault Protection (64TN)
This element has two stages, stage 1 to Trip the machine & stage 2 for Alarm. Set the pickup to0.15 for both stages to provide adequate overlap with the Auxiliary voltage element. Set stage 1to 0.375V secondary (this value may be increased for security in particularly noisy environments).Stage 2 is typically set at 0.3 V secondary. The supervision settings are expressed in per unit ofthe Nominal phase VT secondary setting. The time delay settings are 5 seconds for stage 1 and 1second for stage 2 elements respectively
This protection will be set after measurement of third harmonic voltage generated by themachine at various loads.
Calculation
Stage-1 supervision = 0.375/63.5V= 0.0059 p.u
Stage-2 supervision = 0.300/63.5V= 0.0047 p.u
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Protection Setting
Available setting Recommended setting
Stage 1 Pickup 0.000 to 0.250 p.u in stepsof 0.001
0.15 p.u
Stage 1 Pickupdelay
0.00 to 600.00 s in stepsof 0.01 s
5 seconds
Stage 1 supv 0.0010 to 0.1000 p.u insteps of 0.0001 p.u
0.0059 p.u
Stage 2 Pickup 0.000 to 0.250 p.u in stepsof 0.001
0.15 p.u
Stage 2 Pickupdelay
0.00 to 600.00 s in stepsof 0.01 s
1 seconds
Stage 2 supv 0.0010 to 0.1000 p.u insteps of 0.0001 p.u
0.0047 p.u
Dead Machine Protection (50/27)
PROTECTION SETTING
SlNo
Protection Function Setting Available in the Relay RecommendedSetting
Remarks
Accdnt Enrg ArmingMode
UV or Offline / UV & Offline UV & Offline
Accdnt Enrg OC pickup 0.00 to 3.00 p.u in steps of0.01
1.0
Accdnt Enrg UV pickup 0.00 to 3.00 p.u in steps of0.01
0.7
Accdnt Enrg Offline OFF, ON OFF
Back-up Impedance protection (21G)
Generator Trafo. Impedance @ 11.5 kV base = 11.52x 0.125
95
= 0.174Ohm
Generator Transformer Impedance x 0.8 = 0.174x 0.8
= 0.1392
Secondary Impedance = 0.1392 x CT ratio
PT ratio
= 0.1392 x 52.60
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= 7.3231 Ohm
Line Backup impedance protection setting
Line Positive sequence impedance / km = 0.3Ohm (Assumed. Exact to be given by customer).
Line Voltage = 230kV
Line-1 Length = 18km
Line-2 Length = 4km
Total Line-1 Impedance (ZL1) = 0.3 x 18 = 5.4 Ohm
Total Line-2 Impedance (ZL2) = 0.3 x 4= 1.2 Ohm
Total Impedance on 230kV Base = ZL1*ZL2/ ZL1+ ZL2
= 0.981 Ohm
Impedance on 11.5 kV base = Impedance on 230kV base x 11.52
2302
= 0.9818 x 11.52
2302
= 0.002450 Ohm
Total Impedance = (Line Impedance + Transformer Impedance) x 1.1
= 0.00245+ 0.0.174x 1.1
= 0.1940 Ohm
Total Secondary Impedance = 0.1940 x CT ratio
PT ratio
= 0.1940 x 52.60
= 10.20Ohm
Generator Impedance = Xd x VL2
MVA
= j2.077 x 11.52
100
= j 2.746 Ohm
Zone 3 = (1.2 x Generator Impedance x CTR) / PTR
= (1.2 x j3.02 x 5500) / 110
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= j164.80 Ohm
Available Setting Recommended
Setting for Zone-1
Recommended Setting for
Zone-3
Function Enabled, Disabled Enabled Enabled
Function Forward, Reverse, Non-Directional Forward Reverse
Xfmr Vol
connection
Dy1, Dy3, Dy5, Dy7, Dy9,
Dy11, Yd1, Yd3, Yd5, Yd7,
Yd9, Yd11
Dy1 None
Xfmr Cur
connection
Dy1, Dy3, Dy5, Dy7, Dy9,
Dy11, Yd1, Yd3, Yd5, Yd7,
Yd9, Yd11
Dy1 None
Reach 0.02 to 500.00 Ohm in steps of
0.01
10.20 Ohm 164.80 Ohm
Delay 0.000 to 65.535s in steps of
0.001
5.00s 100ms (considering Back-
up protection for Gen. Diff)
Back-up Impedance should have time delay marginally higher than the longest time delay employed in any of
the protection system which is tripping the Generator CB.
Pole Slipping protection / Power Swing Blocking (78G)
The out of step protection is used to detect a loss of synchronism of the generator. The
impedance locus is measured as compared with blinders and MHO circle.
SGnom= 100 MVA
UGnom= 11.5 KV
IGnom= SGnom = 5020.6A3.UGnom
Generator nominal impedance in Primary value
XGnom= UGnom2
= 1.3225SGnom
Secondary impedance calculated from primary impedance, CT generator neutral end ratioand VT output ratio.
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XGsec= XGpri. CTRatio = 69.53VTRatio
Generator synchronous reactance in p.u. value
Xd = 2.077
Primary impedance calculated from nominal (generator) voltage and nominal apparentpower
Xdprim= Xd.UGnom2 = 2.745SGnom
Secondary impedance calculated from primary impedance, CT generator neutral end ratioand VT output ratio.
Xdsec= Xdprim.CTratio = 144.42PTratio
Generator transient reactance in P.U. value
Xd = 0.187
Primary impedance from nominal (generator) voltage and nominal apparent power
Xdprim= Xd .UGnom2 = 0.247SGnom
Secondary impedance calculated from primary impedance, CT generator neutral end ratioand VT output ratio.
Xdsec= Xdprim.CTratio =13.008PTratio
Transformer impedance in p.u. value
Uk = 12.5% = 0.125 p.u
Primary impedance calculated from nominal (generator) voltage and nominal apparentpower
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ZTprim= Uk . U2LVnom = 0.181STnom
Secondary impedance calculated from primary impedance and CT generator output ratio.
ZTsec=ZTprim.CTratio = 9.872PTratio
The protective function operates if the impedance locus crosses first the right blinder and within atime delay the left blinder.
Generator Impedance
The generator impedance is equal to the transient reactance:
Zg= j.Xdsec = 16.418i
Transformer Impedance
The transformer impedance is equal to the short circuit impedance:
Zt= j.ZTsec = 9.872i
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External system Impedance
Zsext= 3.97. exp (j.86 deg) (Assumed. Customer to give the exact value)
The impedance is based on 220KV and has to be adapted to the generator voltage,
Zs= Zsext. U2Gnom .CTR = 0.541(220KV)2 PTR
System Impedance:
Z = Zg+ Zt+ Zs = 0.0135+ 26.829i
MHO Characteristics
The forward reach is calculated with the transformer impedance as following:
Reach =150%
Fwdreach= |Reach.Zt| = 14.805
The forward angle is equal to the angle of the system impedance as following:
Fwdrca= arg(Z) = 89.97
The reverse reach is calculated with the generator impedance as following:
Reach=200%
Revreach= |Reach.Zg| = 32.836
The reverse angle is equal to the angle of the generator impedance
Revrca= arg(Zg) = 90
Blinder Calculation
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Greenesol Power Systems Pvt. Ltd.,
Doc No: P-1113-G60-1-RS Rev:00 Page 21 of 24
Outer Blinder
The outer blinder is calculated with the system angle as following:
out= 60
The offset between the right and left blinder is calculated according the picture above as following:
180- outtan 2
Offsetout = . |Z| = 46.46 sin (arg(Z))
With this offset the position of the right and left blinder is as following:
180
- outtan 2 |Z| |Zg|Blinderoutright = . + = 23.24
sin (arg(Z)) 2 tan(arg(Z))
Blinderoutleft = Offsetout - Blinderoutright= 23.22
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Greenesol Power Systems Pvt. Ltd.,
Doc No: P-1113-G60-1-RS Rev:00 Page 22 of 24
Inner Blinder
The inner Blinder is calculated with the system angle as following:
in= 120
The offset between the right and left blinder is calculated according the picture above as following:
180- intan 2
Offsetin = . |Z| = 15.50 sin (arg(Z))
With this offset the position of the right and left blinder is as following:
180- intan 2 |Z| |Z
g|
Blinderintright = . + = 7.75 sin (arg(Z)) 2 tan(arg(Z))
Blinderinleft = Offsetin Blinderinright = 7.75
PROTECTION SETTING
SlNo
Protection Function Setting Available in the Relay RecommendedSetting
Remarks
Power Swing Shape Mho, Quad Mho
Power Swing Mode Two step, Three stepTWO STEP
Power Swing Supv 0.050 to 30.00 p.u in steps of0.001
0.6
Power Swing Fwd Rch 0.1 to 500.00 Ohm in steps of0.01
14.8
Power Swing Quad FwdRch
0.1 to 500.00 Ohm in steps of0.01
-
Power Swing Quad FwdRch Mid
0.1 to 500.00 Ohm in steps of0.01
-
Power Swing Quad Fwd
Rch Out
0.1 to 500.00 Ohm in steps of
0.01
-
Power Swing Fwd RCA 40 to 90Deg. in steps of 1 89.97
Power Swing Rev Reach 0.1 to 500.00 Ohm in steps of0.01
32.8
Power Swing Quad RevRch Mid
0.1 to 500.00 Ohm in steps of0.01
-
Power Swing Quad RevRch Out
0.1 to 500.00 Ohm in steps of0.01
-
Power Swing Rev RCA 40 to 90Deg. in steps of 1 90
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Greenesol Power Systems Pvt. Ltd.,
Doc No: P-1113-G60-1-RS Rev:00 Page 23 of 24
Power Swing Outer LimitAngle
40 to 140Deg. in steps of 1 60
Power Swing MiddleLimit Angle
40 to 140Deg. in steps of 1 90
Power Swing Inner LimitAngle
40 to 140Deg. in steps of 1 120
Power Swing Outer Rgt
Bld
0.1 to 500.00 Ohm in steps of
0.01
23.24
Power Swing Outer LftBld
0.1 to 500.00 Ohm in steps of0.01
23.22
Power Swing Middle RgtBld
0.1 to 500.00 Ohm in steps of0.01
-
Power Swing Middle LftBld
0.1 to 500.00 Ohm in steps of0.01
-
Power Swing Inner RgtBld
0.1 to 500.00 Ohm in steps of0.01
7.75
Power Swing Inner LftBld
0.1 to 500.00 Ohm in steps of0.01
7.75
Power Swing Pickup
Delay 1
0.000 to 65.535 s in steps of
0.001
0.03
Power Swing ResetDelay 1
0.000 to 65.535 s in steps of0.001
0.05
Power Swing PickupDelay 2
0.000 to 65.535 s in steps of0.001
0.017
Power Swing PickupDelay 3
0.000 to 65.535 s in steps of0.001
0.009
Power Swing PickupDelay 4
0.000 to 65.535 s in steps of0.001
0.017
Power Swing Seal-inDelay
0.000 to 65.535 s in steps of0.001
0.4
Power Swing Trip mode Early, Delayed Early
Power Swing Blk Flex logic operand off
Power Swing target Self reset, latched, disabled Self-reset
Stand-by Earth fault relay (51S)
Relay Type - Electromagnetic relayMake - GE MULTILIN
Available setting Recommended setting
Pickup 0.1 to 2.4 x In 0.10 x In
Curve Standard Inverse
TDM 0.05 to 2.00 0.1
Rotor Earthfault relay (64F)
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Greenesol Power Systems Pvt. Ltd.,Relay Type - RXNB4Make - ABB
Available setting Recommended setting
Stage-1 **5000 Ohm
Delay 3 secs.
Stage-2 **2000 OhmDelay 2 secs.
Note: **-To be checked and decided at site.