Generator Relay Settings

Input Details Generator data: Rated Generator output: 187.5 MVA (150 MW) Rated voltage between phases: 15.75 kV Power Factor: 0.8 Rated speed: 3000 rpm Frequency: 50 Hz Current at full load = 187.5 x 106 / √3 x 15.75 x 103 = 6873 A I2 Capability: 15% I22t Constant: = 20 Direct axis synchronous reactance Xd(SAT) : 2.105 Ohms Direct axis transient reactance X’d(SAT) : 0.227 Ohms Direct axis sub transient reactance X”d(SAT) : 0.139 Ohms Line length: 0.2 km from Generator to Switchyard Neutral grounding Transformer (NGT) Ratio: 15.75KV/250V

CT / PT Details Generator 15.75kV side, CT ratio: 8000/1 A GROUND CT RATIO: 50/1 A Generator PT ratio: 15.75kV/ 3/ 110/ 3 V

Doc No: P-1104 Rev:01

Generator Protection Protection functions Generator Protection system GPR-1 & 2 G60 are 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19.

Generator Differential Protection – 87G Generator Unbalance Protection – 46 Loss of Excitation Protection – 40 Under Voltage – 27 Over Voltage – 59 Under Frequency – 81U Over Frequency – 81O Rate of change of frequency - 81 Over Fluxing Protection – 24 Phase Over Current Protection – 50/51 Neutral E/F Protection – 50N/51N Active Reverse power Protection - 32P Reactive Reverse power Protection – 32Q Low forward power Protection - 37 100% Stator Ground Fault Protection – 27TN Back-up Impedance/Phase Distance Protection – 21G Power swing detect/Pole Slipping Protection - 78G Dead Machine Protection – 50/27 Local Breaker Back-up Protection (50LBB)

Protection functions for F650 relay is 1.

Dead Machine Protection (50/27)

Protection function for CDG11 relay is 1. Standby Earth fault/Back up Earth fault Protection (64ST) Protection functions for IWX-YWX relay is 1. Rotor Earth fault Protection (64F) Protection functions from Generator Control panel are 1. Generator Stator Winding Temperature trip 2. Generator Bearing Temperature trip

Doc No: P-1104 Rev:01

Relay Type Make

-

G60 GE MULTILIN

Generator Differential Protection (87) 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 10% starting from 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 1.15 PU Slope 2, set at 80 %. The STATOR DIFF BREAK 2 setting is set at 3 PU. 6.0

IOperate (Multiples of CT)

5.0

4.0 Operating Region

Slope 2 80 %

3.0 2. 0 1.0

Restraint Region

Slope 1 15 % Minimum Pickup = 0.5

0.5 0.5

1.0

1.5

2.0

I Restraint (Multiples of CT)

Example: Fig-1

Doc No: P-1104 Rev:01

2.5

3.0

Protection Setting Sl Protection No Function 1 Stator Differential Pickup Slope 1 Break 1 Slope 2 Break 2

Setting Available in the Relay

Recommende d Setting

Remarks To trip 86A

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 10% 1.15

1 - 100% IN 1% STEPS

80%

1.5 to 30 p.u 0.01 p.u steps

3.00 p.u

To trip 86A

Generator Unbalance Protection (46) System Details: Asymmetrical short circuit performance is given by I22 t = 20 Continuous negative sequence capability = 15% CT Ratio = 8000/5 The generator nominal current Inom (p.u)

= (Inom primary) / CT Primary = 6873/8000 = 0.859 P.U

Recommended settings: Stage 1 Pickup

The minimum operate time of Stage 1 The maximum operating time

= 60% x I2 capability = 0.6 x 15% = 9.0 % of FLC = 5 seconds = 600 seconds

Stage 2 is set higher than Stage 1 Stage 2 shall be set at 70% of I2 capability. Stage 2 pickup = 10.5% of FLC with time delay of 0.2 sec.

Doc No: P-1104 Rev:01

Protection Setting Protection Sl No Function 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

Setting Available in the Relay 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

Recommended Setting 0.859 9% 20 5s 600.0 s 240.0 s 10.5 % 0.2 s

Loss of Excitation Protection (40) Xd X’d

= 2.105 pu = 0.227 pu

MVA

= 187.5

CTR/PTR Zbase (sec)

= (8000 / 5 ) x (110/15750) = 11.1746 = (base kV2 / base MVA) x (CTR/VTR) = (15.75 kV2 / 187.5 MVA) x 11.1746 = 14.78

X’d (sec)

=X’d x Zb = 0.227×14.78 = 3.355

Xd (sec)

= Xd x Zb = 2.105 ×14.78 =31.112

CENTER 1 = (Zbase (sec) + X’d (sec) ) / 2 = (14.78 RADIUS 1 = Zbase (sec)/2 = (14.78) /2 = 7.39 PICKUP DELAY 1 = 0.06 seconds CENTER 2 RADIUS 2

+ 3.355 ) /2 = 9.067

= (Xd (sec)+ X’d (sec)) / 2 = (31.112 +3.355 ) /2= 17.2335 = Xd (sec)/ 2=(31.112)/2 = 15.556

Doc No: P-1104 Rev:01

Remarks

Stage 1 for 86C Trip Stage 2 for 86B Trip

PROTECTION SETTING Sl Protection No Function Center 1 Radius 1 UV Supervision Pickup Delay 1

Setting Available in the Relay 0.10 to 300.00 in steps of 0.01 0.10 to 300.00 in steps of 0.01 Disabled, Enabled 0.000 to 65.535 s in steps of 0.01

Recommended Remarks Setting 9.067 To trip 86A 7.39 Enabled 0.06

Center 2 Radius 2 UV Supervision

0.10 to 300.00 in steps of 0.01 0.10 to 300.00 in steps of 0.01 Disabled, Enabled

17.2335 15.556 Disabled

Pickup Delay 2 UV Supervision

0.000 to 65.535 s in steps of 0.01 0.000 to 1.250 p.u in steps of 0.001

0.5 0.7

BLOCK

Flex logic

VT FUSE FAIL

To trip 86B

Under Voltage Protection (27) Trip stage-1 & 2 90 % of the rated Voltage Under Voltage stage 1 Sl Protection Setting Available in the Relay No Function 1 Mode Phase to Ground, Phase to Phase

Recommended Setting Phase to Phase

Pickup

0.000 to 3.000 p.u in steps of 0.001 0.92 p.u

Curve

Definite Time, Inverse Time

Definite Time

Delay

0.00 to 600.00 s in steps of 0.01

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 Protection Setting Available in the Relay No Function 1 Mode Phase to Ground, Phase to Phase Pickup

Recommended Setting Phase to Phase

0.000 to 3.000 p.u in steps of 0.001 0.90 p.u

Doc No: P-1104 Rev:01

Remarks To Trip 86C

Remarks To Trip 86B

Curve

Definite Time, Inverse Time

Definite Time

Delay

0.00 to 600.00 s in steps of 0.01

2.00 s

Min Volt

0.000 to 3.000 p.u in steps of 0.001 0.100 p.u

Over Voltage Protection (59) The time settings should also be depended on the withstand levels of the machine Trip stage-1 & 2 110 % of the rated Voltage Protection Setting – Stage-1 Sl Protection Setting Available in the Relay Recommended No Function Setting Pickup 0.000 to 3.000 p.u in steps of 0.001 1.08 p.u 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

Stage-2 (Flex Elements-1, 2 & 3) Sl Protection Setting Available in the Relay No Function Pickup -90 to 90 p.u in steps of 0.001 Delay

0.00 to 65.50 s in steps of 0.001

Remarks To TRIP 86C

0.5 s 1.00 s

Recommended Setting 1.1 p.u

Remarks To TRIP 86B

2.00 s

Under Frequency Protection (81U) Rated frequency is 50 Hz UNDERFREQUENCY 1 Sl Protection Function No 1 Min Volt/Amp Pickup

Doc No: P-1104 Rev:01

Setting Available in the Relay 0.10 to 1.25 p.u in steps of 0.01 20.00 to 65.00 Hz in steps of 0.01

Recommended Setting 0.5 47.8

Remarks To Trip 86C

Pickup Delay

0.000 to 65.535 s in steps 0.5 sec of 0.001

Reset Delay

0.000 to 65.535 s in steps 0 sec of 0.001

UNDERFREQUENCY 2 Sl Protection Function No 1 Min Volt/Amp Pickup

Setting Available in the Relay 0.10 to 1.25 p.u in steps of 0.01 20.00 to 65.00 Hz in steps of 0.01

Recommended Setting 0.5

Remarks To Trip 86B

47.5

Pickup Delay

0.000 to 65.535 s in steps 2.0 sec of 0.001

Reset Delay

0.000 to 65.535 s in steps 0 sec of 0.001

Over Frequency Protection (81O) OVERFREQUENCY 1 Sl Protection Function No 1 Min Volt/Amp Pickup

Setting Available in the Relay 0.10 to 1.25 p.u in steps of 0.01 20.00 to 65.00 Hz in steps of 0.01

Recommended Setting 0.5 52.0

Pickup Delay

0.000 to 65.535 s in steps 0.5 sec of 0.001

Reset Delay

0.000 to 65.535 s in steps 0 sec of 0.001

BLOCK

Flex logic

Doc No: P-1104 Rev:01

Remarks To Trip 86C

OVERFREQUENCY 2 Sl Protection Function No 1 Min Volt/Amp Pickup

Setting Available in the Relay 0.10 to 1.25 p.u in steps of 0.01 20.00 to 65.00 Hz in steps of 0.01

Recommended Setting 0.5

Remarks To Trip 86B

52.5

Pickup Delay

0.000 to 65.535 s in steps 3.0 sec of 0.001

Reset Delay

0.000 to 65.535 s in steps 0 sec of 0.001

BLOCK

Flex logic

Frequency Rate of Change Protection (81U/O)

Sl Protection Function No 1 Freq Rate -1 Trend

Freq Rate -1 Pick Up Freq Rate -1 OV Supv Pick Up Freq Rate -1 OC Supv Pick Up Freq Rate -1 Min Frequency Freq Rate -1 Max Frequency Freq Rate -1 Pick Up Delay

Setting Available in the Relay Increasing Decreasing Bi-Directional 0.10 to 15.00 Hz/sec in steps of 0.01 0.100 to 3.000 pu in steps of 0.001 0.100 to 3.000 pu in steps of 0.001 20.00 to 80.00 Hz in steps of 0.01 20.00 to 80.00 Hz in steps of 0.01 0 to 65.535 s in steps of 0.001

Recommended Setting 'Increasing

'0.5 Hz/sec 0.7 sec 0.2 sec 45 55 0.1

Over Excitation/Over fluxing Protection (24) Calculations: Rated Generator Voltage: 15.75 kV, 50 Hz Ratio of the voltage transformer: 15750/ 3/110/ 3 Rated Phase VT secondary voltage: 63.5 Rated generator V/Hz on secondary side: 63.5/50 = 1.27 V/Hz.

Doc No: P-1104 Rev:01

Remarks To Trip 86C

With max. Permissible continuous over excitation 105% (assumed) Definite Time Element (ALARM SETTING): Minimum Pickup Level = 1.05 x 1.27 = 1.3335 PU (105 %) 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) Setting Available in the Sl Protection Function Relay No 1 Pickup 0.80 to 4.00 p.u in steps of 0.01 2

3 4

CURVES

TD MULTIPLIER T Reset

Definite Time, Inverse A, Inverse B, Inverse C, Flex Curve A, Flex Curve B

Inverse B

0.05 to 600.00 in steps of 0.01

3sec

0.0 to 1000.0 s in steps of 0.1

0.1 sec

VOLTS PER HERTZ 2 (Stage-2) Sl Protection Function Setting Available in the Relay No 1 Pickup 0.80 to 4.00 p.u in steps of 0.01

2

Curves

Definite Time, Inverse A, Inverse B, Inverse C, Flex Curve A, Flex Curve B

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

Doc No: P-1104 Rev:01

Recommende d Setting 1.4

Recommende d Setting 1.34

Definite time 3 seconds

0.1sec

Remarks To TRIP 86B

Remarks Alarm

Generator Phase Instantaneous O/C (IOC) Protection (50P) The phase instantaneous overcurrent element is used as an instantaneous element with no intentional delay. The input current is the fundamental phasor magnitude. The setting is selected to protect for fault at or near generator terminals. Phase Instantaneous Over Current Full load current= 6873A Hence selected pickup value as 3 times the max. full load current i.e 2.577 p.u (3x6873/8000) PROTECTION SETTING Sl Protection Function No Pickup

Setting Available in the Relay 0.000 to 30.000 p.u in steps of 0.001 0.00 to 600.00 s in steps of 0.01 0.00 to 600.00 s in steps of 0.01

Delay Reset Delay

Recommende d Setting 2.577 p.u

Remarks To trip 86B

0 0

Generator Phase O/C (TOC) Protection (51P) 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 6873 8000 = 0.945 P.U The equation for IEC Curve-A is as follows: T = TDM x

K I I Pick up

E -1

Where, K = 0.14 and E = 0.020, I=Input current and I pickup = Nominal current

Doc No: P-1104 Rev:01

Considered operating time for a three phase fault on the HV side of transformer as 0.50s.

TDM =

0.50 0.14 0.945 0.859

0.02 -1

TDM = 0.0068

Protection setting

Function Input Pickup Curve TD Multiplier Reset Voltage Restraint Target Events

Available Setting Enabled, Disable Phasor, RMS 0.00 to 30.00pu in steps of 0.001 0.00 to 600.00 in steps of 0.01 Instantaneous, Timed Disabled, Enabled Self-reset, Latched, Disabled Disabled, Enabled

Recommended Setting Enabled Phasor 0.945 P.U IEC Curve-A 0.0068 Instantaneous Disabled Latched Enabled

Generator Neutral IDMT O/C (TOC) Protection (51N) The Neutral TOC pickup setting is set as 2% of rated generator current. PICKUP = 0.02 x Generator Nominal Current CT Primary

= 0.02 x (6873/8000) = 0.0171pu

PROTECTION SETTING Sl Protection Function No 1 Pickup

Setting Available in the Relay 0.000 to 30.00 p.u in steps of 0.01 IEEE Mod Inv, IEEE Very Inv, IEEE Ext Inv

Recommended Remarks Setting To trip 86A 0.0171

TD Multiplier

0 To 65.535 in steps of 0.001

0.1

Reset

Instantaneous, Timed

Instantaneous

Curve

Doc No: P-1104 Rev:01

IEC Curve A

Generator Neutral Instantaneous O/C Protection (50N) The Neutral IOC pickup setting is set as 50% of rated generator current. PICKUP = 0.5 x Generator Nominal Current CT Primary

= 0.5 x (6873/8000) = 0.429pu

PROTECTION SETTING Sl Protection Function No 1 Pickup

Recommended Remarks Setting To trip 86A 0.429

Delay

Setting Available in the Relay 0.000 to 30.00 p.u in steps of 0.01 0 To 65.535 in steps of 0.001

Reset

Instantaneous, Timed

Instantaneous

0.0

Directional Power Reverse Active Power (32P)- To trip 86B Assuming 2% as the motoring power required of the O/P power of generator 2% of 150MW = 0.02 X 150 = 3.0 MW

Smin

=

½ X Rated Motoring Power (PW) 3 X Phase CT Primary X Phase VT Ratio X Phase VT Sec

=

½ X 3.0MW 3 X 8000 X 143.18 X 63.5

=

0.0068 P.U

To prevent mal-operation for power swings the element is typically time delayed for Trip by 2 seconds

Doc No: P-1104 Rev:01

Reverse Reactive Power (32Q)- To trip 86B Smin = -0.013 P.U Delay = 3 seconds RCA = 270˚ Low Forward Power (37) - To trip 86B Assuming 10% as the minimum power below which the generator should trip on turbine faults, we get: 10% of 135MW = 0.1 X 150 = 15.0 MW

Smin

=

Minimum operating Power (PW) 3 X Phase CT Primary X Phase VT Ratio X Phase VT Sec

15.0MW

=

3 X 8000 X 143.18182 X 63.5

=

0.0687 P.U

Smin = 0.0687 P.U (For Low forward power SMIN < 0. Refer ‘b’ diagram below) Delay = 1 seconds RCA = 180˚

Doc No: P-1104 Rev:01

Directional Power RCA1 Stage 1 pickup Stage 1 Delay Stage 2 pickup Stage 2 Delay

Available setting 0 to 359° in steps of 1

Power 1 180˚

Power 2 270˚

–1.200 to 1.200 pu in steps of 0.001 0.00 to 600.00 s in steps of 0.01 –1.200 to 1.200 pu in steps of 0.001 0.00 to 600.00 s in steps of 0.01

0.0068 p.u

-0.013 p.u

2 seconds

3 seconds

Block

-0.068 p.u 1 seconds 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 for 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. Stage-1 supervision = 0.375/63.5V = 0.0057 p.u Stage-2 supervision = 0.300/63.5V = 0.0045 p.u Protection Setting Available setting Stage 1 Pickup Stage 1 Pickup delay Stage 1 supv Stage 2 Pickup Stage 2 Pickup delay

0.000 to 0.250 p.u in steps of 0.001 0.00 to 600.00 s in steps of 0.01 s 0.0010 to 0.1000 p.u in steps of 0.0001 p.u 0.000 to 0.250 p.u in steps of 0.001 0.00 to 600.00 s in steps of 0.01 s

Doc No: P-1104 Rev:01

Recommended setting 0.15 p.u 5 seconds 0.0057 p.u 0.15 p.u 1 seconds

Remarks To trip 86A

Stage 2 supv

0.0010 to 0.1000 p.u in steps of 0.0001 p.u

0.0045 p.u

Back-up Impedance / Phase Distance Protection (21G) Generator Trafo. Impedance @ 15.75kV base

= 15.752 x 0.145 200

= 0.179 Ohm Generator Transformer Impedance x 0.8 = 0.179 x 0.8 = 0.1438 Secondary Impedance

= 0.1438 x CT ratio PT ratio

= 0.1438 x 1600 143.18 = 1.607 Ohm Line Backup impedance protection setting Line Positive sequence impedance / km = 0.2509 Ohm Line Voltage = 400kV Line-1 Length = 0.2 km (Plant to SS) Line-2 Length = 0.2 km (Plant to SS) Total Line-1 Impedance (ZL1) = 0.2509 x 0.2 = 0.05 Ohm Total Line-2 Impedance (ZL2) = 0.2509 x 0.2 = 0.05 Ohm Total Impedance on 400kV Base = ZL1*ZL2 / ZL1 + ZL2 = 0.0252 Ohm Impedance on 15.75kV base = Impedance on 400kV base x 15.752 4002 = 0.0252 x 15.752 4002 = 0.00004 Ohm

Doc No: P-1104 Rev:01

Total Impedance = (Line Impedance + Transformer Impedance) x 1.1 = (0.00004 + 0.1438) x 1.1 = 0.158 Ohm Total Secondary Impedance

= 0.158 x CT ratio PT ratio

= 0.158 x 1600 143.18 = 1.768 Ohm Generator Impedance

= Xd x VL2 MVA

= j2.105 x 15.752 187.5 = j2.785Ohm Zone 3 = (1.2 x Generator Impedance x CTR) / PTR = (1.2 x j2.785 x 1600) / 143.18 = j37.346Ohm Available Setting

Function Function Xfmr Vol connection Xfmr Cur connection Reach Delay

Enabled, Disabled Forward, Reverse, NonDirectional Dy1, Dy3, Dy5, Dy7, Dy9, Dy11, Yd1, Yd3, Yd5, Yd7, Yd9, Yd11 Dy1, Dy3, Dy5, Dy7, Dy9, Dy11, Yd1, Yd3, Yd5, Yd7, Yd9, Yd11 0.02 to 500.00 Ohm in steps of 0.01 0.000 to 65.535s in steps of 0.001

Doc No: P-1104 Rev:01

Recommended Setting for Zone1 Enabled Forward

Recommended Setting for Zone-3

Dy1

None

Dy1

None

1.768Ohm

37.346Ohm

5.00s

100ms (considering Back-up protection for Gen. Diff)

Enabled Reverse

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 = 187.5MVA UGnom = 15.75KV IGnom = SGnom 3. UGnom

= 6873A

Generator nominal impedance in Primary value XGnom = UGnom2 SGnom

= 1.323

Secondary impedance calculated from primary impedance, CT generator neutral end ratio and VT output ratio. XGsec = XGpri . CTRatio VTRatio

= 14.78

Generator synchronous reactance in p.u. value Xd = 2.105

Primary impedance calculated from nominal (generator) voltage and nominal apparent power Xdprim = Xd . UGnom2 SGnom

= 2.785

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

Doc No: P-1104 Rev:01

Xdsec = Xdprim . CTratio PTratio

= 31.12

Generator transient reactance in P.U. value Xd’ = 0.227

Primary impedance from nominal (generator) voltage and nominal apparent power Xd’prim = Xd’ . UGnom2 SGnom

= 0.3

Secondary impedance calculated from primary impedance, CT generator neutral end ratio and VT output ratio. Xd’sec = Xd’prim . CTratio PTratio

= 3.356

Transformer impedance in p.u. value Uk = 14.5% = 0.145 p.u Primary impedance calculated from nominal (generator) voltage and nominal apparent power ZTprim = Uk . U2LVnom STnom

= 0.179

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

Doc No: P-1104 Rev:01

= 2.0

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

= 3.356i

Transformer Impedance The transformer impedance is equal to the short circuit impedance: Zt = j.ZTsec

= 2.00i

External system Impedance Zsext = 3.97

. exp (j.86 deg)

(Assumed. Customer to give the exact value)

The impedance is based on 400KV and has to be adapted to the generator voltage,

Doc No: P-1104 Rev:01

Zs = Zsext . U2Gnom . CTR (400KV)2 PTR

= 0.0687

System Impedance: Z = Zg + Zt + Zs

= 0.0145 + 5.427i

MHO Characteristics The forward reach is calculated with the transformer impedance as following: Reach =150% Fwdreach = |Reach.Zt|

= 3.0

The forward angle is equal to the angle of the system impedance as following: Fwdrca = arg(Z)

= 79˚

The reverse reach is calculated with the generator impedance as following: Reach=200%

Revreach = |Reach.Zg|

= 6.712

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

= 79˚

Blinder Calculation

Doc No: P-1104 Rev:01

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˚ tan 2

out

Offsetout =

. |Z|

= 9.575

sin (arg(Z))

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

Blinderoutright

180˚ - out tan 2 = sin (arg(Z))

Blinderoutleft =

|Z| .

|Zg| +

2

Offsetout - Blinderoutright

Doc No: P-1104 Rev:01

= 5.942 tan(arg(Z))

= 3.63

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˚ tan 2

in

Offsetin =

. |Z|

= 3.189

sin (arg(Z))

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

tan

180˚ 2

in

Blinderintright =

|Z| .

sin (arg(Z))

+ 2

Blinderinleft = Offsetin – Blinderinright

|Zg| = 2.247 tan(arg(Z))

= 0.941

PROTECTION SETTING Sl Protection Function No Power Swing Shape Power Swing Mode Power Swing Supv Power Swing Fwd Rch Power Swing Quad Fwd Rch Power Swing Quad Fwd Rch Mid

Doc No: P-1104 Rev:01

Setting Available in the Relay Mho, Quad Two step, Three step

Recommende d Setting Mho

0.050 to 30.00 p.u in steps of 0.001 0.1 to 500.00 Ohm in steps of 0.01 0.1 to 500.00 Ohm in steps of 0.01 0.1 to 500.00 Ohm in steps of 0.01

0.6

TWO STEP

3.0 -

Remarks To trip 86B

Power Swing Quad Fwd Rch Out Power Swing Fwd RCA Power Swing Rev Reach Power Swing Quad Rev Rch Mid Power Swing Quad Rev Rch Out Power Swing Rev RCA Power Swing Outer Limit Angle Power Swing Middle Limit Angle Power Swing Inner Limit Angle Power Swing Outer Rgt Bld Power Swing Outer Lft Bld Power Swing Middle Rgt Bld Power Swing Middle Lft Bld Power Swing Inner Rgt Bld Power Swing Inner Lft Bld Power Swing Pickup Delay 1 Power Swing Reset Delay 1 Power Swing Pickup Delay 2 Power Swing Pickup Delay 3 Power Swing Pickup Delay 4 Power Swing Seal-in Delay Power Swing Trip mode

Doc No: P-1104 Rev:01

0.1 to 500.00 Ohm in steps of 0.01 40 to 90Deg. in steps of 1

-

0.1 to 500.00 Ohm in steps of 0.01 0.1 to 500.00 Ohm in steps of 0.01 0.1 to 500.00 Ohm in steps of 0.01 40 to 90Deg. in steps of 1 40 to 140Deg. in steps of 1

6.712

40 to 140Deg. in steps of 1

90

40 to 140Deg. in steps of 1

120

0.1 to 500.00 Ohm in steps of 0.01 0.1 to 500.00 Ohm in steps of 0.01 0.1 to 500.00 Ohm in steps of 0.01 0.1 to 500.00 Ohm in steps of 0.01 0.1 to 500.00 Ohm in steps of 0.01 0.1 to 500.00 Ohm in steps of 0.01 0.000 to 65.535 s in steps of 0.001 0.000 to 65.535 s in steps of 0.001 0.000 to 65.535 s in steps of 0.001 0.000 to 65.535 s in steps of 0.001 0.000 to 65.535 s in steps of 0.001 0.000 to 65.535 s in steps of 0.001 Early, Delayed

5.942

79

79 60

3.63 2.247 0.941 0.03 0.05 0.017 0.009 0.017 0.4 Early

Power Swing Blk Power Swing target

Flex logic operand Self reset, latched, disabled

off Self-reset

Dead Machine Protection (50/27) PROTECTION SETTING Sl Protection Function No Accdnt Enrg Arming Mode Accdnt Enrg OC pickup Accdnt Enrg UV pickup Accdnt Enrg Offline

Setting Available in the Relay UV or Offline / UV & Offline 0.00 to 3.00 p.u in steps of 0.01 0.00 to 3.00 p.u in steps of 0.01 OFF, ON

Recommende d Setting UV & Offline

Remarks To trip 86A

0.4 0.7 OFF

Local Breaker Back-up protection (50LBB) Find below LBB logic. We have considered this protection using current operated pickup elements with additional timing of 200ms using Flex Logic.

Relay Type Make

-

F650 GE MULTILIN

Dead machine protection – dedicated relay with 3rd DC supply.- To trip 86A Over Current ( for 50/27) PROTECTION SETTING Sl Protection Function No Inst. OC pickup level Trip time

Doc No: P-1104 Rev:01

Setting Available in the Relay 0.05 to 160.00 in steps of 0.01 0.00 to 900.00 in steps of 0.01

Recommende d Setting 0.4 0.01s

Remarks

Under Voltage ( for 50/27) Sl Protection Function No UV pickup level Trip time Operation logic

Relay Type Make

-

Setting Available in the Relay 3 to 300.00 in steps of 1V

Recommende d Setting

0.00 to 900.00 in steps of 0.01

0.01s Any phase

Relay Type Make

0.1 to 0.4 x In 0.1 to 1.00

-

77V

CDG11 AREVA

Stand-by Earthfault relay (64ST) Available setting Pickup Curve TMS

Remarks

Recommended setting 0.10 x In Standard Inverse 0.1

IWX-YWX ABB

Rotor Earthfault relay (64F) Recommended setting Stage-1 **5000 Ohm Delay 3 secs. Stage-2 **2000 Ohm Delay 2 secs. Note: **-To be checked and decided at site. From GCP metering panel Temperature Scanner. Generator Stator Winding Temperature Protection: 115 Deg.C for alarm and 120 Deg.C for Trip Generator DE/NDE Bearing Temperature Protection: 85 Deg.C for alarm and 90 Deg.C for Trip

Doc No: P-1104 Rev:01

Generator Transformer data: Generator Transformer Rating: 200 MVA Voltage Ratio: 420/15.75 kV Frequency: 50 Hz Rated Current at HV side = 274.93 A Rated Current at LV side = 7331.43 A Impedance Z% : 14.5 CT / PT Details Generator Transformer HV side, CT ratio: 400/1 A NEUTRAL CT RATIO: 400/1 A PT ratio: 400KV/ 3/ 110/ 3 V Generator Transformer Protection Protection functions Generator Transformer Protection system T60-1&T60-2 are 1. 2. 3. 4.

Generator Transformer Differential Protection – 87GT Restricted Ground Fault Protection – 64 Over Fluxing Protection – 24 Phase Over Current Protection – 50/51

Protection functions Generator Transformer Protection system T60-87O is 1. Overall Differential Protection (87O) Protection function for CDG11 relay 64ST1 & 64ST2 is 1. Standby Earth fault - T60 Relay Type Make - GE MULTILIN

Doc No: P-1104 Rev:01

Generator Transformer Differential Protection (87T) Percentage Differential Protection Setting Sl Protection No Function 1 T/F Percentage Differential Pickup Slope 1 Break 1 Slope 2 Break 2

Setting Available in the Relay

Recommende d Setting

0.050 to 1.000pu in steps of 0.001 15 to 100% in steps of 1 1.000 to 2.000 pu in steps of 0.001 50 TO 100% IN STEPS OF 1 2.000 to 30.00 pu in steps of 0.001

0.2 25% 2 80% 8.00 p.u

1

Disabled,Adapt.2nd,Trad.2nd

Adapt.2nd

Per phase,2-out-0f-3,Average 1.0 to 40.0% of f0 in steps of 0.1 Disabled,5th 1.0 to 40.0% of f0 in steps of 0.1

Per phase 15% 5th 10

Inrush inhibit function Inrush inhibit mode Inrush inhibit level Over exci.inhibit fn Over exci.inhibit lvl

Remarks

Instantaneous Differential Protection Setting Sl Protection Setting Available in the Relay Recommended No Function Setting 1 T/F Instantaneous 2.000 to 30.000pu in steps of 0.001 6.0 Differential Pickup

Remarks

Restricted Ground fault Protection (64) PROTECTION SETTING Sl Protection No Function

Doc No: P-1104 Rev:01

Setting Available in the Relay

Recommended Remarks Setting

1

Pickup

0.005 to 30.000pu in steps of 0.001

Slope

0 to 100% in steps of 1

20

Pick up delay

0.000 to 600.000pu in steps of 0.01

0.04

Reset delay

0.000 to 600.000pu in steps of 0.01

0

0.08

Over fluxing Protection (24) Calculations: Rated GT HV Voltage: 420 kV, 50 Hz Ratio of the voltage transformer: 400 KV/ 3/110/ 3 Rated Phase VT secondary voltage: 63.5 Rated 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 = 1.05 x 1.27 = 1.3335 PU (105 %) Independent Time Delay= 3 s Definite Time Element (TRIP SETTING): Select setting 110 % of rated T/F V/Hz. Minimum Pickup Level = 1.1 x 1.27 V/Hz = 1.397 PU Protection Setting VOLTS PER HERTZ 1 (Stage-1) Sl Protection Function Setting Available in the Relay No 1 Pickup 0.80 to 4.00 p.u in steps of 0.01

Recommende d Setting 1.4

2

Definite Time, Inverse A, Inverse B, Inverse C, Flex Curve A, Flex Curve B 0.05 to 600.00 in steps of 0.01

Definite Time

0.0 to 1000.0 s in steps of 0.1

0.1sec

3 4

CURVES

TD MULTIPLIER T Reset

VOLTS PER HERTZ 2 (Stage-2) Sl Protection Function Setting Available in the Relay No 1 Pickup 0.80 to 4.00 p.u in steps of 0.01

Doc No: P-1104 Rev:01

Remarks To trip

0.05 sec

Recommende d Setting 1.34

Remarks alarm

2

Curves

3 4

TD Multiplier T Reset

Definite Time, Inverse A, Inverse B, Inverse C, Flex Curve A, Flex Curve B 0.05 to 600.00 in steps of 0.01 0.0 to 1000.0 s in steps of 0.1

Definite Time

0.05 sec 0.0sec

Phase Over Current (TOC) Protection (51P) The phase overcurrent element is used as definite time element. The input current is the fundamental phasor magnitude. PROTECTION SETTING Sl Protection Function No Phase TOC1 Input Pickup Phase TOC1 Curve Phase TOC1 TD Multiplier Phase TOC1 Reset Phase TOC1 Voltage Restraint

Setting Available in the Relay

Recommend Remarks ed Setting Phasor/RMS Phasor 0.000 to 30.000pu in steps of 0.001 1.1 p.u Over Current Type Table IEC CURVE A 0.00 to 600.00 in steps of 0.01

0.5

Instantaneous/Timed

'Instantaneo us 'Disabled

Disabled/Enabled

Phase Instantaneous Over Current (IOC) Protection (50P) The phase overcurrent element is used as definite time element. The input current is the fundamental phasor magnitude. PROTECTION SETTING Sl Protection Function No Phase IOC1 Input Pickup Delay Phase IOC1 Reset

Doc No: P-1104 Rev:01

Setting Available in the Relay

Recommend ed Setting Phasor/RMS Phasor 0.000 to 30.000pu in steps of 0.001 3 p.u 0.00 to 600.00 in steps of 0.01 0.1 Instantaneous/Timed 'Instantaneo us

Remarks

Relay Type Make

-

T60 GE MULTILIN

Overall Differential Protection (87O) Percentage Differential Protection Setting Sl No 1

1

Protection Function

Setting Available in the Relay

Recommende d Setting

Percentage Differential Pickup Slope 1 Break 1 Slope 2 Break 2

0.050 to 1.000pu in steps of 0.001 15 to 100% in steps of 1 1.000 to 2.000 pu in steps of 0.001 50 TO 100% IN STEPS OF 1 2.000 to 30.00 pu in steps of 0.001

0.2 25% 2 80% 8.00 p.u

Disabled,Adapt.2nd,Trad.2nd

Adapt.2nd

Per phase,2-out-0f-3,Average 1.0 to 40.0% of f0 in steps of 0.1 Disabled,5th 1.0 to 40.0% of f0 in steps of 0.1

Per phase 15% 5th 10

Inrush inhibit function Inrush inhibit mode Inrush inhibit level Over exci.inhibit fn Over exci.inhibit lvl

Remarks

Instantaneous Differential Protection Setting Sl Protection Setting Available in the Relay Recommended No Function Setting 1 Instantaneous 2.000 to 30.000pu in steps of 0.001 6.0 Differential Pickup

Relay Type Make

-

CDG11 AREVA

Stand-by Earthfault relay (64ST-1 & 64ST-2) Available setting Recommended setting Pickup 0.1 to 0.4 x In 0.10 x In Curve Standard Inverse TMS 0.1 to 1.00 0.1

Doc No: P-1104 Rev:01

Remarks

Unit Auxiliary Transformer data: Unit Auxiliary Transformer Rating: 25 MVA Voltage Ratio: 15.75 KV/6.9KV Frequency: 50 Hz Rated Current at HV side = 916.42 A Rated Current at LV side = 2091.85 A Impedance Z% : 10.0 CT / PT Details Unit Auxiliary Transformer HV side, CT ratio: 1000/1 A NEUTRAL CT RATIO: 400/1 A PT ratio: 15.75KV/ 3/ 110/ 3 V and LV side 6.9KV/ 3/ 110/ 3 V Unit Auxiliary Transformer Protection Protection functions Unit Auxiliary Transformer Protection system T60-1&T60-2 are 1. Unit Auxiliary Transformer Differential Protection – 87T 2. Restricted Ground Fault Protection – 64 3. Phase Over Current Protection – 50/51 Protection function for CDG11 relay 64ST is 1. Standby Earth fault Relay Type Make

-

T60 GE MULTILIN

Unit Auxiliary Transformer Differential Protection (87T) Percentage Differential Protection Setting Sl No 1

Protection Function

Setting Available in the Relay

Recommended Setting

T/F Percentage Differential Pickup Slope 1 Break 1

0.050 to 1.000pu in steps of 0.001 15 to 100% in steps of 1 1.000 to 2.000 pu in steps of 0.001

0.2 25% 2

Doc No: P-1104 Rev:01

Remarks

1

Slope 2 Break 2

50 TO 100% IN STEPS OF 1 2.000 to 30.00 pu in steps of 0.001

80% 8.00 p.u

Inrush inhibit function Inrush inhibit mode Inrush inhibit level Over exci.inhibit fn Over exci.inhibit lvl

Disabled,Adapt.2nd,Trad.2nd

Adapt.2nd

Per phase,2-out-0f-3,Average 1.0 to 40.0% of f0 in steps of 0.1 Disabled,5th 1.0 to 40.0% of f0 in steps of 0.1

Per phase 15% 5th 10

Instantaneous Differential Protection Setting Sl Protection Setting Available in the Relay Recommended No Function Setting 1 T/F Instantaneous 2.000 to 30.000pu in steps of 0.001 6.0 Differential Pickup

Remarks

Restricted Ground fault Protection (64) PROTECTION SETTING Sl Protection No Function 1 Pickup

Setting Available in the Relay 0.005 to 30.000pu in steps of 0.001

Recommended Remarks Setting 0.08

Slope

0 to 100% in steps of 1

20

Pick up delay

0.000 to 600.000pu in steps of 0.01

0.04

Reset delay

0.000 to 600.000pu in steps of 0.01

0

Phase Over Current (TOC) Protection (51P) The phase over current element is used as definite time element. The input current is the fundamental phasor magnitude. PROTECTION SETTING Sl Protection Function No Phase TOC1 Input Doc No: P-1104 Rev:01

Setting Available in the Relay Phasor/RMS

Recommend ed Setting Phasor

Remarks

Pickup Phase TOC1 Curve

0.000 to 30.000pu in steps of 0.001 1.1 p.u Over Current Type Table IEC CURVE A

Phase TOC1 TD Multiplier Phase TOC1 Reset

0.00 to 600.00 in steps of 0.01

0.5

Instantaneous/Timed

'Instantaneo us 'Disabled

Phase TOC1 Voltage Restraint

Disabled/Enabled

Phase Instantaneous Over Current (IOC) Protection (50P) The phase overcurrent element is used as definite time element. The input current is the fundamental phasor magnitude. PROTECTION SETTING Sl Protection Function No Phase IOC1 Input Pickup Delay Phase IOC1 Reset

Relay Type Make

-

Setting Available in the Relay

Recommend ed Setting Phasor/RMS Phasor 0.000 to 30.000pu in steps of 0.001 3 p.u 0.00 to 600.00 in steps of 0.01 0.1 Instantaneous/Timed 'Instantaneo us

CDG11 AREVA

Stand-by Earthfault relay (64ST-1) Available setting Pickup Curve TMS

0.1 to 0.4 x In 0.1 to 1.00

Doc No: P-1104 Rev:01

Recommended setting 0.10 x In Standard Inverse 0.1

Remarks