DRS_setting Calculation Reference 1

SETTING CALCULATION NUMERICAL PROTECTION SYSTEM

2 X 50 MW MALANA-II HYDRO ELECTRIC PROJECT

CLIENT :

ABIR INFRASTRUCTURE PVT. LTD.

MALANA-II HYDRO ELECTRIC PROJECT

Rev.

Modification

Date

Check

Date

Drawn:

DD.MM.YYYY

SS

Checked:

DD.MM.YYYY

SS

Approved:

DD.MM.YYYY

SKV

Appd PROJECT NO: C. 290

PLANT: 2 X 50 MW MALANA-II HYDRO ELECTRIC PROJECT

= FU

PLN

= LO CUSTOMER No:

SETTINGCALCULATION NUMERICAL PROTECTION SYSTEM

Internal Drawing Number:

Rev.

2 783001

0

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THIS DOCUMENT IS THE PROPERTY OF VA TECH HYDRO AND MUST NEITHER BE COPEID NOR USED IN ANY OTHER WAY WIHTOUT THE WRITTEN CONSENT OF VA TECH HYDRO NEITHER IT IS TO BE HANDED OVER, NOR IN OTHER WAY COMMUNICATED TO A THIRD PARTY. INFRINGMENT WILL LEAD TO PROSECUTION



SETTING CALCULATION FOR DIGITAL PROTECTION SYSTEM

Table of Contents

1.

GENERAL ............................................................................................................................3

2.

TECHNICAL DATA ..............................................................................................................4

3.

GENERATOR, TRANSFORMER AND UNIT AUXILIARY TRANSFORMER PROTECTION ...6 A) B) C) D) E) F) G) H) I) J) K) L) M) N) O) P) Q) R) S)

4.

GENERATOR DIFFERENTIAL PROTECTION 87G .............................................................. 6 GENERATOR UNDEREXCITATION PROTECTION 40G....................................................... 7 GENERATOR NEGATIVE PHASE SEQUENCE PROTECTION 46G ........................................ 8 GENERATOR OVERVOLTAGE PROTECTION 59................................................................ 9 GENERATOR UNDERVOLTAGE PROTECTION 27G ......................................................... 10 GENERATOR OVER/UNDERFREQUENCY PROTECTION 81O/U ........................................ 10 GENERATOR STATOR EARTH FAULT PROTECTION 64G1 .............................................. 11 GENERATOR STATOR EARTH FAULT PROTECTION 64G2 .............................................. 11 ROTOR EARTH FAULT PROTECTION 64R ..................................................................... 12 GENERATOR REVERSE POWER PROTECTION 32G ........................................................ 13 VOLTAGE SUPERVISION FUNCTION 60G, 60M AND 60A ............................................... 13 GENERATOR UNDERIMPEDANCE PROTECTION 21G ..................................................... 14 DEAD MACHINE 27/51V .............................................................................................. 15 UNIT DIFFERENTIAL PROTECTION 87GT ..................................................................... 16 RESTRICTED EARTH FAULT PROTECTION 64REF ......................................................... 17 RESTRICTED EARTH FAULT PROTECTION 64REF- DISCRETE RELAY ............................. 19 OVERFLUXING PROTECTION 99G ................................................................................ 21 UAT DIFFERENTIAL PROTECTION 87UAT..................................................................... 21 UAT OVERCURRENT PROTECTION 50U/51U................................................................. 22 DISTANCE PROTECTION .................................................................................................23

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1.GENERAL This document provides information about the various protective schemes for the unit transformer protection, generator protection and UAT. The document lists the particular protective functions as how they overlap and complement each other for back-up and outlines the philosophy about the selection of the protection setting values. Please note that the generator and transformer characteristics and capability curves and data are contained in separate documents. Also the documentation with detailed descriptions of the various protection systems are provided in separate relay documents. Note: The calculated relay settings are based on different data sheets available during the workout (e.g. generator data sheet, CB data, and single line diagram) of the document. In case of any equipment modification or change of various electrical characteristics this document has to be revised. Therefore all the settings have to be checked and revised during the commissioning on site. Generally the calculation of the settings is done according to our best knowledge and conscience. So we can’t accept any responsibility for errors included in the document. Further we are not liable for any incident or damage resulting from the content of this setting calculation. Some protection settings (e.g. frequency, voltage) have to be checked and approved also from the power distribution owner.

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2. TECHNICAL DATA Generator: GENERATOR OUTPUT= RATED VOLTAGE= POWER FACTOR RATED CURRENT RATED FREQUENCY SYNCRONOUS REACTANCE TRANSIENT REACTANCE (STAURATED) NEGETIVE PHASE SEQUENCE WITHSTAND UNBALANCED LOAD FIELD CURRENT STATOR LEAKAGE REACTANCE SYNCRONOUS REACTANCE QUARD AXIS

Sn Un p.f. In fn Xd Xd' I2 (I2/IN)²xt If xs Xq

55560.00 11 0.9 2915.9 50 93.30% 26% 8% 20 875 0.0952 0.602

kVA kV

Un Sn Uk

11/132 63.9 12.5 % YNd11

kV MVA

Un Sn

11000/415 500 Dyn11

V KVA

Un Sn

11000/364 630 Dy5

V KVA

R1 X1 R0 X0 L L1 L2

0.14 0.387 0.272 1.233 70 30 30

A Hz

sec Adc PU PU

Step up transformer RATED VOLTAGE RATED OUTPUTS SHORT CIRCUIT VOLTAGE VECTOR GROUP Auxiliary Transformer : RATED VOLTAGE RATED OUTPUTS VECTOR GROUP Excitation Transformer : RATED VOLTAGE RATED OUTPUTS VECTOR GROUP Line Parameters: POSITIVE SEQUENCE RESISTANCE POSITIVE SEQUENCE REACTANCE ZERO SEQUENCE RESISTANCE ZERO SEQUENCE RESISTANCE LINE LENGTH LENGTH OF NEXT SHORTEST LINE LENGTH OF NEXT LONGEST LINE

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OHMS/KM OHMS/KM OHMS/KM OHMS/KM KM KM KM

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SETTING CALCULATION NUMERICAL PROTECTION SYSTEM Current Transformer GENERATOR TRANSFORMER HV SIDE GENERATOR TRANSFORMER NEUTRAL GENERATOR NEUTRAL GENERATOR TERMINAL AUX TRANSFORMER HV SIDE (OVERALL DIFF) GENERATOR TRANSFORMER HV SIDE (DIFF) AUX TRANSFORMER HV SIDE (OVERCURRENT PROT) Voltage transformer PROTECTION CORE AVR CORE NEUTRAL TRANSFORMER METERING CORE LINE PT

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Primary 400A 400A 4000A 4000A 4000A 600A

Secondary 1A 1A 5A 5A 5A 1A

100A

1A

Primary 11000V 11000V 11000V 11000V 110000V

Secondary 110V 110V 110V 110V 110V

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3.GENERATOR, TRANSFORMER AND UNIT AUXILIARY TRANSFORMER PROTECTION

A) GENERATOR DIFFERENTIAL PROTECTION 87G This function protects the generator system from the neutral CTs to the generator terminal CTs. When function operates, the unit will be shut down immediately. The differential setting value is calculated as follows:

Igp 

Sn 55560kVA   2916.14 A Generator primary current Un  3 11kV  3

Now with a CT ratio = 4000/5 A the generator secondary current is calculated

Igs 

Igp 2916.14A   5 A  3.65 A Generator secondary current CTratio 4000 A

The differential current setting is chosen to be 20% of the relay current rating, i.e.

I 87 s  0.20  5 A  1A This is in turn the equivalent to the generator rated current.

I % 

I 87 s 1A 100  100  27.4% Igs 3.65 A

The bias slope is set to

bias  40%

Setting Name of parameter Operate Value Bias

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Range 1A 40%

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B) GENERATOR UNDEREXCITATION PROTECTION 40G The under excitation MHO protection is used to detect failures in the excitation system of synchronous generators and to prevent damage to the equipment and power swings in the system. The given direct reactances are Synchronous reactance Transient reactance (saturated)

xd xd´

93.3% 26%

A compensation factor F must be determined according to the equation below, in order to adjust the reactances to the CT and VT ratios:

F

VG CTratio Ir 11000V 4000 A 110V 5A       1.5 IG VTratio Vr 2916.14 A 5 A 11000V 100V

where Ir … Vr …

rated current of the relay rated voltage of the relay (100V internally)

So the adapted reactances are

xd  F  xd  1.5  0.933 pU  1.399 pU xd '  F  xd '  1.5  0.255 pU  0.382 pU The relay function setting is calculated as follows.

Diameter  xd  1.40 pU Center 

xd ' xd 0.382 pU 1.4 pU     0.891 pU 2 2 2 2

The relay will be set to the next possible set point: Diameter: 1.4 pU Center: 0.89 pU The Time Delay Stage 1 is set to 5 sec. The parameters Operate Value St. 2, Rotor Cur. Comp., Rotor Cur. Offset has no relevance. Stage 2 is using the following logical function: Underexcitation Stage 1 Pickup Undervoltage 27/40 Pickup

&

Time Delay Stage 2

Trip

The Time Delay Stage 2 is set to 1 sec. The Operate Value of the Function "27/50" is set to 50V.

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C) GENERATOR NEGATIVE PHASE SEQUENCE PROTECTION 46G

The calculation of the setting values is done according to e.g. following generator data: Rated power SG =55560 KVA Rated voltage VG = 11 kV Negative phase sequence current withstand 8% Therefore the generator primary current is

Igp 

Sg 55560kVA   2916.14 A Vgp  3 11kV  3

and by using a current transformer with a CT ratio of 12000A/1A the corresponding secondary current is

Igs 

Igp 2916.14A   5 A  3.64 A CTratio 4000 A

So the CT ratio compensation is

CT ratio comp 

I gs IN



3.64 A  0.73 5A

A further data for the generator (manufacturer data) is the inverse time characteristic i2t, which is for example i2t=20s Note: This characteristic is only valid for high current values i, as shown below (calculation tripping time). So the time constant is selected to be



20 s  3125s 0.082

 52min

The tripping time can be calculated exactly

 i2  ttrip    ln 2 2 2  i i   2 2e  In case of a failure with n.p.s=45%, i2 results to 5xi2e, and the tripping time is

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ttrip    ln


25    0.0408  127.5s 24

Compared with the manufacturer data

ttrip 

3.5s 20 s   98.7 s 2 i2 0.452

The values for the "neg.ph.sequ.alarm" and "neg.ph.sequ.trip" are selected as a percentage of the load limit. The load limit is reached after approximately 4 time constants when running constant admissible unbalance current. Typical values are (depends on the customer wishes): neg.ph.sequ.alarm=80% neg.ph.sequ.trip=100% D) GENERATOR OVERVOLTAGE PROTECTION 59 The overvoltage function protects the generator and the transformer against electrical field stresses. The function is provided with 2 stages whereby stage 1 has a lower voltage setting and a larger time delay to cater for voltage regulator response time in case of full load rejections and stage 2 is provided with a higher voltage setting above loss of load conditions and minimum time delay. The calculation of the setting value for Stage 1 is as follows The setting is chosen to be 110% of the generator rated voltage, therefore

Vs 

Vgp 11000V  110V  110%   1.10  121.0V VTratio 11000V

and the time delay is set to t = 2.0 s Stage 2 is selected to be 125% of the generator rated voltage, therefore

Vs 

Vgp 11000V  110V  125%   1.25  137.5V VTratio 11000V

and the time delay is set to t = 0.0 s Setting: Name of parameter Operate Value Stage 1 Operate Value Stage 2 Time Delay Stage 1 Time Delay Stage 2 Type

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Range 121.0 137.5 2 0 1 Over Voltage

Unit V V Sec Sec

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E) GENERATOR UNDERVOLTAGE PROTECTION 27G The function is enabled during the generator set being connected to the power system and is disabled (blocked) by the 220kV CB open position. It is a 1-stage function. The function settings are selected as follows.

V 27  70% Vns  0.70 110V  77V Time delay trip t 27  2.5s Setting: Name of parameter Operate Value Time Delay Type

Range 77 2,5 2 Under Voltage

Unit [V] [Sec] -

F) GENERATOR OVER/UNDERFREQUENCY PROTECTION 81O/U The protective function has 4 Stages providing separate adjustable over- and under-frequency alarm and trip facilities. In addition to the mechanical overspeed and excitation system underspeed detection it provides backup protection for such conditions. All stages will initiate an alarm and trip the unit. The function settings are selected as follows. Stage 1 overfrequency Stage 2 overfrequency Stage 3 underfrequency Stage 4 underfrequency

f 81.1  52.0 Hz f 81.2  52.5 Hz f 81.3  48.5 Hz f 81.4  47.0 Hz

time delay t 81.1  0.5s

Trip

time delay t 81.2  0.0 s

Trip

time delay t 81.3  20.0 s time delay

t 81.4  0.0 s

Trip Trip

The frequency settings need to be reviewed by the grid regulator. Setting: Name of parameter Min. Volt. Setting Max. Volt. Setting Operate Value St. 1 Time Delay St. 1 Type St. 1 Operate Value St. 2 Time Delay St. 2 Type St. 2 Operate Value St. 3 Time Delay St. 3 Type St. 3 Operate Value St. 4 Time Delay St. 4 Type St. 4 MALANA-II HEP

Range 60 – 100 100 – 140 52 0.5 Overdetection 52.5 0.00 Overdetection 48.5 20 Underdetection 47 0.00 Underdetection

Unit [V] [V] [Hz] [s] [Hz] [s] [Hz] [s] [Hz] [s]

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G) GENERATOR STATOR EARTH FAULT PROTECTION 64G1 The function should serve as an earth fault function for the complete 11kV-system and for the generator up to 90% of its winding. With an earth fault in the 11kV-system (respectively on the terminals of the generator) we receive the following voltage in the generator neutral:

VN sec 

VGen 1 11kV 1     63.5V 3 transf ratio 3 11kV / 110V

For a protection range of 90% we are able to calculate the setting value:

100%  prot.range  100%  95%   VN sec   Vset    63.5V  3.18V  100%    100%  Selected value (according to setting range of the protection relay): 3.2V. Time delay 1.0s Setting: Name of parameter Operate Value Time Delay Type

Range 3.2 1.0 Over detection

Unit V Sec -

H) GENERATOR STATOR EARTH FAULT PROTECTION 64G2 For simplification an evenly distribution of the 3rd harmonic over neutral and terminals for the generator in healthy condition is assumed (see figure below).

This distribution of the 3rd harmonic over neutral and terminal side is taken for the evaluation of earth faults close to the generator neutral. The 3rd harmonic is measured in the generator neutral with a single-phase voltage transformer and on the generator leads with a voltage transformer in open delta MALANA-II HEP

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connection. In case of an earth fault, the 3rd harmonic in the neutral is shorted whereby the value on the generator terminals is increased by the same value (see figure below).

The following requirement is assumed: the relay with the measurement of the 3rd harmonic shall protect the 15% of the stator coil close to the neutral point. The other 85% are protected by a normal overvoltage relay with the measurement of the fundamental frequency. The correct settings will be determined on site during earth fault tests. For this purpose different measurements of the 3rd harmonic in the generator neutral and on the generator leads have to be done in dependence of different generator loads for the healthy condition and for an earth fault. The 3rd harmonics are processed via the following formula:

 3rd .Harm.gen.terminal volt.  ratio  3rd .Harm.gen.neutral volt.   measured values There should be a difference between the measured values for the healthy condition and for the case of an earth fault. Setting: Settings will be determined on site during earth fault tests.

I) ROTOR EARTH FAULT PROTECTION 64R This protection function comprises an auxiliary supply, which is connected between the earth and one side of the field circuit. A direct voltage appears at the output, which is indirectly proportional to the rotor insulation value and corresponds to the resistance. If this measured resistance is smaller than the setting value, the required trip sequences for a unit shutdown are carried out. The setting of the rotor earth fault protection is selected to Stage 1: R  50 k MALANA-II HEP

with a time delay t delay  10 s Page 12 of 29



Stage 1 will initiate an Alarm only. Stage 2: R  1500

with a time delay

t delay  1s

Stage 2 will initiate a trip. Setting: Name of parameter Operate Value, Stage1 Time Delay, Stage1 Operate Value, Stage2 Time Delay, Stage2

Setting 50 10 1.5 1

Unit [kΩ] [s] [kΩ] [s]

J) GENERATOR REVERSE POWER PROTECTION 32G When operating on reverse power this protective function will perform a unit shut down. The setting is selected due to our experience, i.e. -5.0% of the generator rating power. The relay function setting is calculated as follows. The relay primary power is

P relp  3  Vp  ICTp  cos   3  11.00kV  300 A 1  5715.77 kW The required -5.0% primary reverse power setting of the machine rating is

Pp 32  5.0%  3  Vp  Ig  cos   0.05  3  11.00kV  262.4 A  0.9  225kW The required relay setting is Pp32/Prelp = -225/5715.77 = -3.94% The time delay is set to t 32  5.0 s Setting: Name of parameter Operate Value Time Delay Power Direction Phase Rotation

Setting

Unit

-3.94 5 Direction 1 Right

[% PN] [s] -

K) VOLTAGE SUPERVISION FUNCTION 60G, 60M AND 60A The setting for the negative phase sequence voltage for unbalanced secondary phase to phase voltages is selected to Operate Value U=50.0 V

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with a time delay t=5s

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The second condition of the function is the setting for the negative phase sequence current. A high negative phase sequence current indicates e.g. a failure in the network and the protection function is blocked. Normally an unbalanced voltage causes only a small n.p.s. current. So the setting is chosen to be Operate Value I=0.2 A The selection parameter declares the setting for the phase rotation. Setting: Name of parameter Operate Value I Operate Value U Time Delay Phase Rotation

Range 0.2 50 5 2 (Right)

Unit A V [s] -

L) GENERATOR UNDERIMPEDANCE PROTECTION 21G This protection function consists of two stages, whereby the first stage is a so called impedance protection relay with a current interlock and the second stage is a backup protection, which is designed as overcurrent protection relay. Therefore the generator current is

Igp 

Sg Vgp  3

 262.4 A Generator primary current

The current and voltage transformer are designed according to the related voltage and rated current of the generator. For this purpose the VT ratio is selected to be 11000V/110V and the CT ratio of the current transformer at the neutral is selected to be 10000/1A The HV and LV transformer currents are:

Ihvp 

ILvp 

St Vhvp  3 St VLvp  3

 57.73 A

HV transformer primary current

 577.35 A

LV transformer primary current

The primary short circuit impedance of the transformer is obtained by

Zp 

V

2

TS

St

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

11k V 2  7.50 uk   0.835 100 11MVA  100 Page 14 of 29



Therefore the secondary transformer impedance is calculated

Zs 

CTratio 300  110  Zp   0.825  0.495 VTratio 5  11000

In order not to overreach on external system faults an impedance of approximately 50% to 70% of the transformer is selected with a corresponding setting of

Z 21G  50%  Zs  0.5  1.73  0.247 

With time delay t 21G  0.2 s

The impedance current interlock setting, i.e. the overcurrent stage is a starting element for the under impedance stage, is set to 120% of the generator rated current and calculated as follows

Is  1.2  ILV 

1 5  1.2  577.35   11.55 A CT ratio 300

The time delay setting for stage 2 depends on the time grading of the remaining network. Setting: Name of parameter Operate Value Time Delay Imp. Time Delay Curr. Current Interlock

Range

Unit

0.25 0.2 Depends on time grading of remaining n/w 11.55

[Ohm] [s] [s] A

M) DEAD MACHINE 27/51V The overcurrent setting will be coordinated with all the other overcurrent functions (generator, transformer ...).

I 27 / 51V  1.10 A The typical operating range of a generator lies between 90% and 110% of the rated voltage. For generators with an isolated starpoint or with an earthed starpoint via a resistor the generator voltage drops to values of about 30% caused of a phase to phase fault. For this case the parameter "Voltage Limit" has to be chosen in that way, that the generator voltage is below the setting of this parameter. The operating value of the current setting will then be reduced to the "K-Factor". The setting is chosen to be 60% of the generator nominal voltage; this is for the secondary side:

V 27 / 51V 

60%  110  66.0V 100%

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The k-factor is chosen to be 20% (to make sure that the current exceeds the setting value).

 K  0. 2 Setting: Name of parameter Operate Value Voltage Limit K-Factor Time Delay

Range 1.1 66 0.2 4

Unit [A] [V] [s]

N) UNIT DIFFERENTIAL PROTECTION 87GT The unit differential protection is protecting the system from the transformer 220kV CTs up to the 11kV generator neutral and Auxiliary Transformer busbar CTs. When operating the unit is tripped and will be shut down immediately.

Ihvp 

Ihvs 

St Vhvp  3



11000kVA 110kV  3

 57.74 A

HV transformer primary current

Ihvp 57.74 A   1.0 A  0.96 A CTratio 60 A

HV transformer secondary current

With a differential current setting of 0.20xIn the setting as a percentage of the transformer rated current can be calculated

%Ihvs 

Is 0.20 A   100  20.8% Ihvs 0.96 A

By choosing a differential current setting of 0.20A secondary the primary setting is calculated as follows.

Ihvp  CT ratio  Ihvs 

500 A  0.15 A  75 A 1.0 A

High set over current = 5.0 x IN =4.8 To cater for the different CT ratios on the transformer HV and LV side the CT ratio compensation factor system2/system1 and systm3/system1 is calculated according to following formulas whereby system 1 refers to the 220kV HV winding, system 2 to the generator leg and system 3 to the aux transformer LV winding.

CTratio comp 2  1 

CTsystem 2 CTsystem1  tr.ratio

system1 system2



300 / 1A  0.5 110kV 60 / 1A  11kV

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CTratio comp3  1 

CTsystem3 CTsystem1  tr.ratio

system1 system3




300 / 1A  0.05 110kV 60 / 1A  11kV

Setting: Name of parameter Operate Value High Set OC CT Ratio Comp. 2-1 CT Ratio Comp. 3-1 2nd Harmonic 5th Harmonic Bias Vector Group 1-2 Vector Group 1-3 Zero Sequ. Syst.1 Zero Sequ. Syst.2 Zero Sequ. Syst.3

Range 20% 4,8A 0.5 0.05 20 (to be verified during commissioning) 15 (to be verified during commissioning) 50 1 11 On Off Off

Unit % % % -

O) RESTRICTED EARTH FAULT PROTECTION 64REF The grid transformer restricted earth fault protection 64REF is protecting the system from the transformer 220kV CTs up to the grid transformer neutral to cater for faults near the neutral point (grid transformer). High impedance scheme and high speed tripping is provided. When operating the function trips the generator unit. CT data for the 220kV transformer feeder switchgear CT’s. CT ratio 600/1,0 A CT secondary current In = 1,0 A Estimated CT knee point voltage Vk > 300 V Estimated CT secondary resistance Rct = 5  Estimated single lead resistance to relay Rl = 0.3  CT data for the 220kV transformer neutral CT CT ratio 600/1,0 A CT secondary current In = 1,0 A Estimated CT knee point voltage Vk > 300 V Estimated CT secondary resistance Rct = 5  Estimated single lead resistance to relay Rl = 0.3  The CT requirements for the High impedance transformer restricted earth fault protective function, is according to the following formula. Vk > 2IF ( Rct + 2 Rl + Rext )

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Whereby IF is the maximum secondary three phase through fault current considering a short circuit failure. The secondary fault current IF at the 220kV level is calculated as follows (British EATS 48-3 standard).

IF  16 

ST 175000kVA  16   12.24 A 3  220kV  600 / 1.0 A 3  V  CTratio Vk = 300 V > 2 x 12.24A (5 + 2 x 0.3 ) = 137.16 V Vk = 300 V > 2 x 12.24A (5 + 2 x 0.3 ) = 137.16 V

220kV lead CTs 220kV neutral CT

Therefore the selected restricted earth fault protection voltage setting is chosen to be greater than the minimum stability voltage IFx( Rct + 2 Rl + Rext )=68.58V Vs=69V and the resulting external stabilising resistor for a relay setting IS = 0.15A (33% rated current) is

RST 

0.1 relayVA 69  0.15  455 IS  IS 0.15

VS 

The minimum CT kneepoint voltage should be greater than twice the relay voltage setting 220kV:

Vk = 300V > 2 x VS = 138V

Check, whether a voltage limiting device is required:

V p  2  2 VK  V f  VK   3000V VK=300V

V f  I F  RCT  2 Rl  RST  R R   12.24  5  2  0.3  455  5637V Thus, V p  3579V Due to ensure a safety margin a voltage limiting resistor is connected into the circuit. Continuous power rating of the setting resistor:

Pcon  I S   RST  0.15  455  10.2W 2

2

with a short time rating:

Pshort 

V fs

2

RST

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

 3  V K  RST  I F  RST



1 4

2

  1.3   159W for 0.5 sec onds

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Thermal rating of the non-linear resistor:

P

4 4  I F  VK  12.24 A  300V  4677.94W  3.15

Isetting 

V 69   0.15 A RST 455

Settings: Name of parameter Operate Value Drop Off Delay

Range 42.5 % 0.5

Unit s

P) RESTRICTED EARTH FAULT PROTECTION 64REF- DISCRETE RELAY The grid transformer restricted earth fault protection 64REF is protecting the system from the transformer 220kV CTs up to the grid transformer neutral to cater for faults near the neutral point (grid transformer). High impedance scheme and high speed tripping is provided. When operating the function trips the generator unit. CT data for the 220kV transformer feeder switchgear CT’s. CT ratio 600/1,0 A CT secondary current In = 1,0 A Estimated CT knee point voltage Vk > 300 V Estimated CT secondary resistance Rct = 5  Estimated single lead resistance to relay Rl = 0.3  CT data for the 220kV transformer neutral CT CT ratio 600/1,0 A CT secondary current In = 1,0 A Estimated CT knee point voltage Vk > 300 V Estimated CT secondary resistance Rct = 5  Estimated single lead resistance to relay Rl = 0.3  The CT requirements for the High impedance transformer restricted earth fault protective function, is according to the following formula. Vk > 2IF ( Rct + 2 Rl + Rext ) Whereby IF is the maximum secondary three phase through fault current considering a short circuit failure. The secondary fault current IF at the 220kV level is calculated as follows (British EATS 48-3 standard).

IF  16  MALANA-II HEP

ST 175000kVA  16   12.24 A 3  V  CTratio 3  220kV  600 / 1.0 A Page 19 of 29


220kV lead CTs 220kV neutral CT


Vk = 300 V > 2 x 12.24A (5 + 2 x 0.3 ) = 137.16 V Vk = 300 V > 2 x 12.24A (5 + 2 x 0.3 ) = 137.16 V

Therefore the selected restricted earth fault protection voltage setting is chosen to be greater than the minimum stability voltage IFx( Rct + 2 Rl + Rext )=68.58V Vs=69V and the resulting external stabilising resistor for a relay setting IS = 0.15A (33% rated current) is

RST 

0.1 relayVA 69  0.15  162.22 IS  IS 0.15

VS 

The minimum CT kneepoint voltage should be greater than twice the relay voltage setting 220kV:

Vk = 300V > 2 x VS = 138V

Check, whether a voltage limiting device is required:

V p  2  2 VK  V f  VK   3000V VK=300V

V f  I F  RCT  2 Rl  RST  RR   12.24  5  2  0.3  162.22   2055.28 Thus, V p  2052.48V Due to ensure a safety margin a voltage limiting resistor is connected into the circuit. Continuous power rating of the setting resistor:

Pcon  I S   RST  0.15  162.22  3.65W 2

2

with a short time rating:

Pshort 

V fs

2

RST



 3  VK  RST  I F  RST

 1.3 1 4

2

  2412.82W for 0.5 sec onds

Thermal rating of the non-linear resistor:

P

4 4  I F  VK  12.24 A  300V  4677.94W  3.15

MALANA-II HEP

Page 20 of 29


Isetting 


V 69   0.42 A RST 162.22

Settings: Name of parameter Operate Value Drop Off Delay

Range 42.5 % 0.5

Unit s

Q) OVERFLUXING PROTECTION 99G The degree of saturation (overfluxing) is calculated according to following formula.

S

V  fN VN  f

Whereby V and VN are the actual voltage and rated voltage and f and fN the actual frequency and rated frequency respectively. The operating value of stage 1 is set to the maximum continuous overfluxing withstand of the generator, which must be specified by the manufacturer of the generator, i.e. to 105% voltage at rated frequency and the other stage is set to increasing higher levels. Stage 1 alarm Stage 2 trip

S1A=1.05 time delay t=10.0s S2T=1.10 time delay t=1.0s

Setting: Name of parameter Operate Value St. 1 Time Delay St. 1 Operate Value St. 2 Time Delay St. 2 Nominal Frequency Nominal Voltage

Setting 1.05 10.00 1.10 1.00 50.0 110

Unit [p.U.] [s] [p.U.] [s] [Hz] [V]

R) UAT DIFFERENTIAL PROTECTION 87UAT This function protects the UAT system from the HV side CTs to the LV side CTs and operates for phase to phase and three phase faults. The differential setting value is calculated as follows:

IAT-HVp 

SAT 500kVA   26.24 A Vnp  3 11kV  3

UAT (HV) primary current

Now with a CT ratio = 30/5 A the generator secondary current is calculated

IAT-HVs 

IAT-HVp 26.24 A   5 A  4.37 A CTratio 30 A

MALANA-II HEP

UAT (HV) secondary current Page 21 of 29


IAT-LVp 

SAT 500kVA   695.60 A Vnp  3 415V  3


UAT (LV) primary current

and with a CT ratio of 800/5A the corresponding secondary current is

IAT-LVs 

IAT-LVp 695.60 A   1A  0.87 A CTratio 800 A

UAT (LV) secondary current

The differential current setting is chosen to be 20% of the relay current rating, i.e.

I 87 s  0.20  5 A 1.00 A This is in turn the equivalent to the generator rated current.

I % 

Is IAT-HVs

 100 

1.0 A 100  38.16% 2.62 A

High set overcurrent = 5.0 x IN =13.1 The bias slope is set to

CTratio comp 

bias  40% CTsystem 2

system1 CTsystem1  tr.ratio system2



800  1.00 11kV 30 / 1A  0.415kV

Setting: Name of parameter Operate Value High Set OC CT Ratio Comp. 2-1 2nd Harmonic 5th Harmonic Bias Vector Group 1-2 Zero Sequ. Syst.1 Zero Sequ. Syst.2

Range 38.16% 13.1 1.00 20 (to be verified during commissioning) 15 (to be verified during commissioning) 40 11 Off Off

Unit % % % -

S) UAT OVERCURRENT PROTECTION 50U/51U This function protects the auxiliary transformer against substantial overloading and heavy internal and external HV side short circuits and will trip the generator unit when operating. For the overcurrent protection stage 1 an inverse time characteristic is chosen to cater for field forcing conditions and the current setting is selected to be 1.0x the transformer rated current. The overcurrent protection stage 2 setting is chosen to be about 5 x In with a small time delay MALANA-II HEP

Page 22 of 29



The protective function settings are obtained

IATp 

SAT 500kVA   26.24 A auxiliary transformer primary current Vnp  3 11kV  3

and with a CT ratio of 50/5A the corresponding secondary current is

IATs 

IATp 26.24 A   5 A  2.62 A CTratio 50 A

auxiliary transformer secondary current

Hence the current setting for Stage 1 is selected to be 120% of the rated current

I 51  IATs 1.2  2.62 A 1.2  3.15 A With a Time Multiplier setting TMS  0.5

normally inverse time characteristic

The Stage 2 current setting is selected to be approximately 5 x In and is obtained

I 50  I 51  5.0  3.15 A  5.0  15.75 A The time delay of Stage 2 is chosen to be t 50  0.1s

Setting: Name of parameter Operating Val. St.1 TMS St.1 Curve Operating Val. St.2 Time delay St.2

Range 3.15 0.5 normal inverse 15.75 0.1

Unit A A Sec

4. Distance Protection Line Parameters: POSITIVE SEQUENCE RESISTANCE POSITIVE SEQUENCE REACTANCE ZERO SEQUENCE RESISTANCE ZERO SEQUENCE RESISTANCE LINE LENGTH LENGTH OF NEXT SHORTEST LINE LENGTH OF NEXT LONGEST LINE ARC RESISTANCE PH-PH ARC RESISTANCE PH-EARTH

R1 X1 R0 X0 L1 L2 L3 Arc ph-ph Arc ph-e

0.0659 0.3836 0.272 1.233 70 30 30 0 20

OHMS/KM OHMS/KM OHMS/KM OHMS/KM KM KM KM OHMS OHMS

Primary Values per Km: MALANA-II HEP

Page 23 of 29



R1=0.0659 X1=0.3836 R0=0.272 X0=1.233

Z1  R1 2  X 12  0.3892 LineAngle( Ph  Ph), 1  Tan 1

X1  80.2517 R1

Z 0  R0 2  X 0 2  1.2626

LineAngle( Ph  E ),  0  Tan 1

X0  77.5598 R0

Values Protected Line: Primary Value: R1pL1=0.0659*70=4.6130 X1pL1=0.3836*70=26.8508 R0pL1=0.2720*70=19.0400 X0pL1=1.2330*70=86.3100 Secondary Value:

CTratio  0.06 PTratio R1sL1=4.6130*0.06=0.2767 X1sL1=26.8508*0.06=1.6110 R0sL1=19.0400*0.06=1.1424 X0sL1=86.3100*0.06=5.1786

Earth Impedance (residual) Compensation: Resistance Ratio:

RG 1  R 0      1  1.04248 RL 3  R1 

Reactance Ratio:

XG 1  X 0     1  0.7381 XL 3  X 1 

Earth Compensation Factor, Ko: MALANA-II HEP

 1 Z K 0    0  1 3  Z1 

Page 24 of 29



K 0  0.7469  0.0508i

ABS ( K 0 )  0.7469 2  0.0508 2  0.7486 0.0508 ARG ( K 0 )  tan 1  3.89 0.7469 Next Shortest Line: Primary Value: R1pL2=0.0659*30= 1.9770 X1pL2=0.3836*30= 11.5075 R0pL2=0.2720*30= 8.1600 X0pL2=1.2330*30= 36.99 Secondary Values: R1sL2=1.9770*0.06=0.1186 X1sL2=11.5075*0.06=0.6904 R0sL2=8.1600*0.06=0.4896 X0sL2=36.9900*0.06=2.2194 Next Longest Line: Primary Value: R1pL3=0.0659*30= 1.9770 X1pL3=0.3836*30= 11.5075 R0pL3=0.2720*30= 8.1600 X0pL3=1.2330*30= 36.99

Secondary Values: R1sL3=1.9770*0.06=0.1186 X1sL3=11.5075*0.06=0.6904 R0sL3=8.1600*0.06=0.4896 X0sL3=36.9900*0.06=2.2194

KPCL Setting Philosophy: Zone1 :

80% of Protected Line

Zone2 :

100% of protected line + 50% of next shortest line

MALANA-II HEP

Page 25 of 29


Zone3 :

100% + 100% of next longest line

Zone4 :

Normally 15% to 20% of Zone 1


Zone 1 Calculation: Phase to Phase Faults:

Primary Values

R1Z 1 p  ( R1 pL1 * 0.8)  arcph  ph  3.69 X 1Z1 p  ( X 1 pL1 * 0.8)  21.481 Secondary Values

R1Z1s  R1Z1 p * 0.06  0.221 X 1Z1s  X 1Z1 p * 0.06  1.289 Phase to Earth Faults:

Primary Values

R 0 Z1 p  ( R 0 pL1 * 0.8)  arcph  e  35.232 X 0 Z 1 p  ( X 0 pL1 * 0.8)  69.048 Secondary Values

R 0Z1s  R 0Z1 p * 0.06  2.114 X 0 Z 1s  X 0 Z1 p * 0.06  4.143

Zone 2 Calculation: Phase to Phase Faults:

Primary Values

R1Z 2 p  ( R1 pL1)  ( R1 pL 2 * 0.5)  arcph  ph  5.602 X 1Z 2 p  ( X 1 pL1)  ( X 1 pL 2 * 0.5)  32.605 Secondary Values

R1Z 2 s  R1Z 2 p * 0.06  0.336 X 1Z 2 s  X 1Z 2 p * 0.06  1.956 MALANA-II HEP

Page 26 of 29



Phase to Earth Faults:

Primary Values

R0 Z 2 p  ( R0 pL1)  ( R0 pL 2 * 0.5)  arcph  e  43.120 X 0 Z 2 p  ( X 0 pL1)  ( X 0 pL 2 * 0.5)  104.805 Secondary Values

R0Z 2s  R0Z 2 p * 0.06  2.587 X 0 Z 2 s  X 0 Z 2 p * 0.06  6.288 Zone 3 Calculation: Phase to Phase Faults: Primary Values

R1Z 3 p  ( R1 pL1)  ( R1 pL3)  arcph  ph  6.590 X 1Z 3 p  ( X 1 pL1)  ( X 1 pL3)  38.358 Secondary Values

R1Z 3s  R1Z 3 p * 0.06  0.395 X 1Z 3s  X 1Z 3 p * 0.06  2.301 Phase to Earth Faults:

Primary Values

R 0 Z 3 p  ( R0 pL1)  ( R0 pL3)  arcph  e  47.200 X 0 Z 3 p  ( X 0 pL1)  ( X 0 pL3)  123.300 Secondary Values

R0 Z 3s  R0 Z 3 p * 0.06  2.832 X 0 Z 3s  X 0 Z 3 p * 0.06  7.398 Reverse Zone 4 Calculation: Phase to Phase Faults: Primary Values MALANA-II HEP

Page 27 of 29



R1Z 4 p  ( R1 pL1 * 0.2)  arcph  ph  0.923 X 1Z 4 p  ( X 1 pL1 * 0.2)  5.370 Secondary Values

R1Z 4 s  R1Z 4 p * 0.06  0.055 X 1Z 4 s  X 1Z 4 p * 0.06  0.322 Phase to Earth Faults:

Primary Values

R0 Z 4 p  ( R0 pL1 * 0.2)  arcph  e  23.808 X 0 Z 4 p  ( X 0 pL1 * 0.2)  17.262 Secondary Values

R0Z 4s  R0Z 4 p * 0.06  1.428 X 0 Z 4 s  X 0 Z 4 p * 0.06  1.036

Settings: Name of parameter Line Angle Earth fault Compensation Factors Zone 1 (Forward) Zone 2 (Forward) MALANA-II HEP

ph-ph ph-e ph-ph

ph-ph ph-e Re/Rl Xe/Xl R X R X R X

Set Value 80.2517 77.5598

Unit Degrees

1.042489 0.738143 0.221 1.289 2.114 4.143 0.336 1.956

Ohms Ohms Page 28 of 29

SETTING CALCULATION NUMERICAL PROTECTION SYSTEM R X R X R X R X R X

ph-e Zone 3 (Forward) Zone 4 (Reverse)

ph-ph ph-e ph-ph

Operation time

MALANA-II HEP

ph-e Zone Zone Zone Zone

1 2 3 4

2.587 6.288 0.395 2.301 2.832 7.398 0.055 0.322 1.428 1.036 0 0.4 0.8 1.2


Ohms

Ohms

secs

Page 29 of 29

DRS_setting Calculation Reference 1

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