Sravanthi Relay Setting Chart

(1)

Revision Revision Rev

Rev Descriptions Descriptions Date Date ApprovedApproved 0

0 R0-Issued R0-Issued for for approval approval 11.07.1111.07.11

PROJECT

PROJECT 225 MW KASHIPUR GAS COMBINED CYCLE POWER225 MW KASHIPUR GAS COMBINED CYCLE POWER PROJECT AT KASHIPUR

PROJECT AT KASHIPUR.. OWNER

OWNER M/s. SRAVA NTHI ENERGM/s. SRAVANTHI ENERGY PVT LTD.Y PVT LTD. OWNER

OWNER

CONSULTANT

CONSULTANT M/S.TATA CONSULTING ENGINEERS LIMITED, BANGALORE.M/S.TATA CONSULTING ENGINEERS LIMITED, BANGALORE. EPC EPC CONTRACTOR CONTRACTOR M/s. SRAVANTHI INFRATECH PVT M/s. SRAVANTHI INFRATECH PVT LTD (EPC DEVISION) LTD (EPC DEVISION) EPC EPC CONSULTANT CONSULTANT M/s. TOSHIBA

M/s. TOSHIBA TERMAL TERMAL AND HYDRO POWER SYSAND HYDRO POWER SYSTEMTEM COMPANY TOSHIBA INDIA PVT LTD.

COMPANY TOSHIBA INDIA PVT LTD. Prepared Prepared by by 11.07.1111.07.11

STG RELAY SETTINGS

SRIRANGAN SRIRANGAN Checked

Checked by by 11.07.1111.07.11 GREENESOL POWER SYSTEMS PVT. LTD.,GREENESOL POWER SYSTEMS PVT. LTD., # 995, SERVICE ROAD, # 995, SERVICE ROAD, RPC LAYOUT, VIJAYANAGAR, RPC LAYOUT, VIJAYANAGAR, BENGALURU – 560 040. BENGALURU – 560 040. ARK ARK Approved Approved by by 11.07.1111.07.11 DJY DJY CAD

CAD File File Date: Date: Size Size Scale Scale Drawing No: Drawing No: P-1113-G60-1-RSP-1113-G60-1-RS Office:

Office: GPSPL GPSPL NANA

Job Number: P-1113 Job Number: P-1113

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Input Details Input Details Generator data: Generator data:

Rated Generator output: 100 MVA (80 MW) Rated Generator output: 100 MVA (80 MW) Rated voltage between phases: 11.5 kV Rated voltage between phases: 11.5 kV Power Factor: 0.8 Power Factor: 0.8 Rated speed: 3000 rpm Rated speed: 3000 rpm Frequency: 50 Hz Frequency: 50 Hz

Current at full load = 100

Current at full load = 100 x 10 x 1066 / /

√

3 x 11.5 x 103 x 11.5 x 1033 == 5020.585020.58 AA II22 Capability : Capability : 10%10%

II2222t Constant: =t Constant: = 1515

Direct axis synchronous reactance X

Direct axis synchronous reactance Xd(UNSAT)d(UNSAT): 2.077 p.u: 2.077 p.u

Direct axis synchronous reactance X

Direct axis synchronous reactance Xd(UNSAT)d(UNSAT):2.7468 Ohms:2.7468 Ohms

Direct axis transient reactance X’

Direct axis transient reactance X’d(SAT)d(SAT):: 0.163 p.u0.163 p.u

Direct axis transient reactance X’

Direct axis transient reactance X’d(SAT)d(SAT):0.2155 Ohms [(kV:0.2155 Ohms [(kV22 / MVA) * p.u)] / MVA) * p.u)]

Direct axis sub transient reactance X”

Direct axis sub transient reactance X”d(SAT)d(SAT) : : 0.103 p.u0.103 p.u

Direct axis sub transient reactance X”

Direct axis sub transient reactance X”d(SAT)d(SAT) :0.1362 ohms [(kV :0.1362 ohms [(kV22 / MVA) * p.u)] / MVA) * p.u)]

Fault current: 80KA Fault current: 80KA Line-1 length:

Line-1 length: 18km ACSR DRAKE conductor (To be confirmed by 18km ACSR DRAKE conductor (To be confirmed by consultant)consultant) Line-2 length:

Line-2 length: 4km ACSR DRAKE conductor (To be confirmed by 4km ACSR DRAKE conductor (To be confirmed by consultant)consultant) Neutral grounding Transformer (NGT)

Neutral grounding Transformer (NGT) Ratio: 11KV/220V

Ratio: 11KV/220V

CT / PT Details CT / PT Details

Generator 11.5 kV side, CT ratio: 5500/1 A Generator 11.5 kV side, CT ratio: 5500/1 A G

GROUNDROUNDCTCT RATIO RATIO:: 50/150/1 AA Generator PT ratio: 11.5kV/

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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 a lso.

1. Generator Differential Protection - 87 2. Generator Unbalance Protection – 46 3. Loss of Excitation Protection – 40 4. Under Frequency – 81U

5. Over Frequency – 81O 6. Over Voltage – 59 7. Under Voltage – 27

8. Over Excitation / Over Fluxing Protection – 24 9. Phase Instantaneous O/C Protection – 50P 10. Phase IDMT O/C Protection – 51P

11. Neutral IDMT O/C Protection – 51N 12. Directional Power Protection - 37

13. 100% Stator Ground Fault Protection – 64TN 14. Dead Machine Protection – 50/27

15. System Back-up O/C Protection - 51V 16. Back-up Impedance protection – 21G 17. 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

(4)

Generator Differential Protection (87)

Relay Type - G60

Make - GE MULTILIN Calculation

The differential current pickup setting can be set as low as 5% of rated generator current, to provide 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 via a 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 1.0 1.5 2.0 2.5 3.0 0.5 2. 0 3.0 4.0 5.0 6.0 1.0 I Restraint (Multiples of CT) I O p e r a t e ( M u l t i p l e s o f C T ) Slope 1 15 % Slope 2 80 % Operating Region Restraint Region Minimum Pickup = 0.5 Fig-1

(5)

Protection Setting Sl

No

Protection Function

Setting Available in the Relay Recommended Setting Remarks 1 Stator Differential Pickup Slope 1 Break 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.

0.05 15% 1.25 Slope 2 Break 2 1 - 100% IN1% 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 I22 t = 10

Continuous negative sequence capability = 8%

CT Ratio = 5500/1

The generator nominal current

Inom (p.u) = (Inom primary) / CT Primary

= 5020.4/5500 = 0.912 P.U Recommended settings: Stage 1 Pickup = 100% x I2capability = 1.0 x 8% = 8 % of FLC = 8%

The minimum operate time of Stage 1 = 0.2seconds The maximum operating time = 600 seconds

Stage 2 is typically set lower than Stage 1 with a time delay to prevent nuisance alarms for external faults that are normally cleared by system protection.

(6)

No

Protection Function Setting Available in the Relay Recommended Setting

Remarks 1 GEN UNBAL INOM

Stage 1 Pickup Stage 1 K-Value Stage 1 Tmin Stage 1 Tmax Stage 1 K-Reset Stage 2 Pickup Stage 2 Pickup Delay 0.000 to 1.250 p.u in steps of 0.001 0.00 to 100.00% in steps of 0.01 0.00 to 100.00 in steps of 0.01 0.000 to 50.000 s in steps of 0.001 0.0 to 1000.0 s in steps of 0.1 0.0 to 1000.0 s in steps of 0.1 0.05 to 30.00 p.u in steps of 0.01 0.0 to 1000.0 s in steps of 0.1 0.912 8% 10 0.2 s 600.0 s 240.0 s 5.6% 10 s Stage 1 for 86BTrip Stage 2 for 86C Trip

Loss of Excitation Protection (40)

This protection is applicable when the unit is running in Generator Mode. Calculation

Xd = 2.077 pu

X’d = 0.163 pu

MVA = 100

CTR/PTR = (5500 / 1) x (110/11500) = 52.6

Zbase (sec) = (base kV2 / base MVA) x (CT ratio / VT ratio)

= (11.5 kV2 / 100 MVA) x (5500/ 104.5) = 69.63 Ω

X’d(sec) =X’d x Zb

= 0.163 ×69.63 = 11.34Ω

Xd (sec) = Xd x Zb

= 2.077 ×69.63 =144.62Ω

CENTER 1 = (Zbase (sec) + X’d (sec) ) / 2 = (69.63Ω + 11.34 Ω) /2 = 40.48Ω

RADIUS 1 = Zbase (sec)/2 = (69.63 Ω) /2 = 34.81 Ω

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)+ X’d (sec)) / 2 = (144.62 Ω+11.34 Ω) /2= 77.98Ω

(7)

During stable Power swing conditions the positive-sequence impedance may momentarily enter the stage 2 characteristics. For security of the function under such conditions, it is recommended to delay stage2 by a minimum of 0.5 seconds

FIG-2

No

Protection Function Setting Available in the Relay Recommended Setting Remarks Center 1 Radius 1 UV Supervision Pickup Delay 1 Center 2 Radius 2 UV Supervision Pickup Delay 2 UV Supervision 0.10 to 300.00 Ω in steps of 0.01 0.10 to 300.00 Ω in steps of 0.01 Disabled, Enabled 0.000 to 65.535 s in steps of 0.01 0.10 to 300.00 Ω in steps of 0.01 0.10 to 300.00 Ω in steps of 0.01 Disabled, Enabled 0.000 to 65.535 s in steps of 0.01 0.000 to 1.250 p.u in steps of 0.001 40.48 34.81 Enabled 0.06 77.98 72.31 Disabled 0.5 0.7

BLOCK Flex logic VT FUSE FAIL

Under Frequency Protection (81U) Rated frequency is 50 Hz

UNDERFREQUENCY 1 Sl

No

Protection Function Setting Available in the Relay

Recommended Setting

Remarks 1 Min Volt/Amp 0.10 to 1.25 p.u in steps

of 0.01

(8)

Pickup 20.00 to 65.00 Hz in steps of 0.01

47.5

Pickup Delay 0.000 to 65.535 s in steps of 0.001

0.5 sec

Reset Delay 0.000 to 65.535 s in steps of 0.001

0 sec

UNDERFREQUENCY 2 Sl

No

Recommended Setting

of 0.01

0.5 To Trip 86B

47.5

3 sec

0 sec

Over Frequency Protection (81O) Stage -1

Sl No

Recommended Setting

of 0.01

0.5 To Trip 86C

52.5

0.5 sec

0 sec

(9)

Stage-2 Sl

No

Recommended Setting

of 0.01

0.5 To Trip 86B

52.5

3 sec

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 should also be depended on the withstand levels of the machine

Calculations:

Trip stage-1 & 2 110 % of the rated Voltage Protection Setting – Stage-1

Sl No

Protection Function

Setting Available in the Relay Recommended Setting

Remarks Pickup 0.000 to 3.000 p.u in steps of 0.001 1.1 p.u To TRIP 86C Delay Reset Delay 0.00 to 600.00 s in steps of 0.01 0.00 to 600.00 s in steps of 0.01 0.5 s 1.00 s Stage-2 (Flex Elements-1, 2 & 3)

Sl No

Protection Function

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

Sl No

Protection Function

(10)

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 Sl

No

Protection Function

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 Hz

Ratio of the voltage transformer: 11500/√ 3/110/√ 3 Rated generator secondary voltage: 63.5

Rated 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 Setting

VOLTS PER HERTZ 1 (Stage-1) Sl

No

Remarks 1 Pickup 0.80 to 4.00 p.u in steps of

0.01

(11)

2

CURVES Definite Time, Inverse A, Inverse B, Inverse C,

Flex Curve A, Flex Curve B

Definite time 3 seconds

3

TD MULTIPLIER 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) Sl

No

Remarks 1 Pickup 0.80 to 4.00 p.u in steps of

0.01

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 no intentional 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. Calculation

Phase Instantaneous Over Current

Max. 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 the

generator windings. i.e 48741x0.3 = 14622.52A. When it is converted into secondary we get

14622.52 / 5020.4 =

2.91 p.u

PROTECTIONSETTING Sl

No

Remarks Pickup 0.000 to 30.000 p.u in steps of

0.001

2.91 p.u Delay 0.00 to 600.00 s in steps of

(12)

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 the

machine.

Pickup

= 1.1 x Generator Nominal Current

CT Primary

= 1.1 x 5020.4

5500

= 1.004P.U

The equation for IEC Curve-A is as follows:

T = TDM x

K

I

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 of

transformer as

0.50s (to be confirmed by customer).

0.50 TDM =

0.14

8.86

0.02

1.004 - 1

TDM = 0.16

Protection setting

(13)

Available Setting

Recommended Setting

Function

Enabled, Disable

Enabled

Input

Phasor, RMS

Phasor

Pickup

0.00 to 30.00pu in steps of 0.001

1.004 P.U

Curve

IEC Curve-A

TD Multiplier

0.00 to 600.00 in steps of 0.01

0.16 Reset

Instantaneous, Timed

Instantaneous

Voltage Restraint

Disabled, Enabled

Disabled

Target

Self-reset, Latched, Disabled

Latched

Events

Disabled, Enabled

Enabled

Directional Power

Low Forward Power (37)

Assuming 10% as the minimum power below which the generator should trip on turbine faults, we get: 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 seconds RCA = 180˚

(14)

Available setting Sensitive Power 1 Sensitive Power 2 Sensitive

Directional Power RCA

0 to 359° in steps of 1 180˚ 270˚

Stage 1 SMIN –1.200 to 1.200 pu in steps of 0.001

- 0.0734 p.u 0.0743 p.u Stage 1 Delay 0.00 to 600.00 s in steps

of 0.01

3 seconds 2 seconds Stage 2 SMIN –1.200 to 1.200 pu in steps

of 0.001

0.0743 p.u NA

Stage 2 Delay 0.00 to 600.00 s in steps of 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 to 0.15 for both stages to provide adequate overlap with the Auxiliary voltage element. Set stage 1 to 0.375V secondary (this value may be increased fo r security in particularly noisy environments). Stage 2 is typically set at 0.3 V secondary. The supervision settings are expressed in per unit of the Nominal phase VT secondary setting. The time delay settings are 5 seconds for stage 1 and 1 second for stage 2 elements respectively

This protection will be set after measurement of third harmonic voltage generated by the machine 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

(15)

Protection Setting

Available setting Recommended setting Stage 1 Pickup 0.000 to 0.250 p.u in steps

of 0.001 0.15 p.u Stage 1 Pickup delay 0.00 to 600.00 s in steps of 0.01 s 5 seconds Stage 1 supv 0.0010 to 0.1000 p.u in

steps of 0.0001 p.u

0.0059 p.u Stage 2 Pickup 0.000 to 0.250 p.u in steps

of 0.001 0.15 p.u Stage 2 Pickup delay 0.00 to 600.00 s in steps of 0.01 s 1 seconds Stage 2 supv 0.0010 to 0.1000 p.u in

steps of 0.0001 p.u

0.0047 p.u

Dead Machine Protection (50/27) PROTECTIONSETTING

Sl No

Remarks Accdnt Enrg Arming

Mode

UV or Offline / UV & Offline UV & Offline Accdnt Enrg OC pickup 0.00 to 3.00 p.u in steps of

0.01 1.0

Accdnt Enrg UV pickup 0.00 to 3.00 p.u in steps of 0.01

0.7

Accdnt Enrg Offline OFF, ON OFF

Back-up Impedance protection (21G)

Generator Trafo. Impedance @ 11.5 kV base = 11.52 x 0.125 95

= 0.174 Ohm Generator Transformer Impedance x 0.8 = 0.174 x 0.8

= 0.1392 Secondary Impedance = 0.1392 x CT ratio

PT ratio

(16)

= 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 + 0.0.174 x 1.1

= 0.1940 Ohm

Total Secondary Impedance = 0.1940 x CT ratio PT ratio = 0.1940 x 52.60 = 10.20 Ohm 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

(17)

= 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 = 5020.6A √_3._U_Gnom

Generator nominal impedance in Primary value X_Gnom = U_Gnom2 = 1.3225Ω

S_Gnom

Secondary impedance calculated from primary impedance, CT generator neutral end ratio and VT output ratio.

(18)

XGsec = XGpri

.

CTRatio = 69.53Ω

VTRatio

Generator synchronous reactance in p.u. value Xd = 2.077

Primary impedance calculated from nominal (generator) voltage and nominal apparent power

Xdprim = Xd

.

UGnom2 = 2.745Ω SGnom

Xdsec = Xdprim

.

CTratio = 144.42Ω

PTratio

Generator transient reactance in P.U. value Xd’ = 0.187

Primary impedance from nominal (generator) voltage and nominal apparent power Xd’prim = Xd’

.

UGnom2 = 0.247Ω

S_Gnom

Xd’sec = Xd’prim

.

CTratio =13.008Ω

PTratio

Transformer impedance in p.u. value Uk = 12.5% = 0.125 p.u

Primary impedance calculated from nominal (generator) voltage and nominal apparent power

(19)

ZTprim = Uk

.

U2LVnom = 0.181Ω

STnom

Secondary impedance calculated from primary impedance and CT generator output ratio. ZTsec =ZTprim

.

CTratio = 9.872Ω

PTratio

The protective function operates if the impedance locus crosses first the right blinder and within a time delay the left blinder.

Generator Impedance

The generator impedance is equal to the transient reactance: Zg = j.Xd’sec = 16.418iΩ

Transformer Impedance

The transformer impedance is equal to the short circuit impedance: Zt = j.ZTsec = 9.872iΩ

(20)

External system Impedance

Zsext = 3.97Ω. 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 = 0.541Ω

(220KV)2 PTR

System Impedance:

Z = Zg + Zt + Zs = 0.0135 + 26.829iΩ

MHO Characteristic s

The forward reach is calculated with the transformer impedance as following: Reach =150%

Fwdreach = |Reach.Zt| = 14.805Ω

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| = 32.836Ω

The reverse angle is equal to the angle of the generator impedance Revrca = arg(Zg) = 90˚

(21)

Outer Blinder

The outer blinder is calculated with the system angle as following:

Θ_out_{= 60}˚

The offset between the right and left blinder is calculated according the picture above as following:

180˚ - Θout

tan 2

Offsetout = . |Z| = 46.46Ω

sin (arg(Z))

With this offset the position of the right and left blinder is as following:

180˚ - Θout

tan 2 |Z| |Zg|

Blinder outright = . + = 23.24Ω

sin (arg(Z)) 2 tan(arg(Z))

(22)

Inner Blinder

The inner Blinder is calculated with the system angle as following:

Θ_in_{= 120}˚

The offset between the right and left blinder is calculated according the picture above as following:

180˚ - Θin

tan 2

Offset_in = . |Z| = 15.50Ω

sin (arg(Z))

With this offset the position of the right and left blinder is as following:

180˚ - Θin

tan 2 |Z| |Zg|

Blinder intright = . + = 7.75Ω

sin (arg(Z)) 2 tan(arg(Z))

Blinder inleft = Offsetin – Blinder inright = 7.75 Ω

PROTECTIONSETTING Sl

No

Remarks

Power Swing Shape Mho, Quad Mho

Power Swing Mode Two step, Three step

TWO STEP Power Swing Supv 0.050 to 30.00 p.u in steps of

0.001

0.6 Power Swing Fwd Rch 0.1 to 500.00 Ohm in steps of

0.01

14.8 Power Swing Quad Fwd

Rch

0.1 to 500.00 Ohm in steps of 0.01

-Power Swing Quad Fwd

Rch Mid

-Power Swing Quad Fwd

Rch Out

-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 of

0.01

32.8 Power Swing Quad Rev

Rch Mid

-Power Swing Quad Rev

Rch Out

(23)

-Power Swing Outer Limit Angle

40 to 140Deg. in steps of 1 60 Power Swing Middle

Limit Angle

40 to 140Deg. in steps of 1 90 Power Swing Inner Limit

Angle

40 to 140Deg. in steps of 1 120 Power Swing Outer Rgt

Bld

23.24 Power Swing Outer Lft

Bld

23.22 Power Swing Middle Rgt

Bld

-Power Swing Middle Lft

Bld

-Power Swing Inner Rgt

Bld

7.75 Power Swing Inner Lft

Bld

7.75 Power Swing Pickup

Delay 1