DRS_setting Calculation Reference 1

(1)

CLIENT :

ABIR INFRASTRUCTURE PVT. LTD.

MALANA-II HYDRO ELECTRIC PROJECT

Drawn: DD.MM.YYYY SS Checked: DD.MM.YYYY SS Approved: DD.MM.YYYY SKV Rev. Modification Date Check Date 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:

2 783001

Page 1 of 29

Rev.

0

(2)

MALANA-II HEP Page 2 of 29 SETTING CALCULATION

FOR DIGITAL PROTECTION SYSTEM

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.

(4)

MALANA-II HEP Page 4 of 29

2. TECHNICAL DATA Generator:

GENERATOR OUTPUT= Sn 55560.00 kVA

RATED VOLTAGE= Un 11 kV

POWER FACTOR p.f. 0.9

RATED CURRENT In 2915.9 A

RATED FREQUENCY fn 50 Hz

SYNCRONOUS REACTANCE Xd 93.30%

TRANSIENT REACTANCE (STAURATED) Xd' 26% NEGETIVE PHASE SEQUENCE WITHSTAND I2 _8%

UNBALANCED LOAD (I2/IN)²xt 20 sec

FIELD CURRENT If 875 Adc

STATOR LEAKAGE REACTANCE xs 0.0952 PU

SYNCRONOUS REACTANCE QUARD AXIS Xq 0.602 PU

Step up transformer

RATED VOLTAGE Un 11/132 kV

RATED OUTPUTS Sn 63.9 MVA

SHORT CIRCUIT VOLTAGE Uk 12.5 %

VECTOR GROUP YNd11

Auxiliary Transformer :

RATED VOLTAGE Un 11000/415 V

RATED OUTPUTS Sn 500 KVA

VECTOR GROUP Dyn11

Excitation Transformer :

RATED VOLTAGE Un 11000/364 V

RATED OUTPUTS Sn 630 KVA

VECTOR GROUP Dy5

Line Parameters:

POSITIVE SEQUENCE RESISTANCE R1 0.14 OHMS/KM POSITIVE SEQUENCE REACTANCE X1 0.387 OHMS/KM

ZERO SEQUENCE RESISTANCE R0 0.272 OHMS/KM

ZERO SEQUENCE RESISTANCE X0 1.233 OHMS/KM

LINE LENGTH L 70 KM

LENGTH OF NEXT SHORTEST LINE L1 30 KM

(5)

Current Transformer

Primary Secondary

GENERATOR TRANSFORMER HV SIDE 400A 1A

GENERATOR TRANSFORMER NEUTRAL 400A 1A

GENERATOR NEUTRAL 4000A 5A

GENERATOR TERMINAL 4000A 5A

AUX TRANSFORMER HV SIDE (OVERALL DIFF) 4000A 5A GENERATOR TRANSFORMER HV SIDE (DIFF) 600A 1A AUX TRANSFORMER HV SIDE (OVERCURRENT

PROT) 100A 1A Voltage transformer Primary Secondary PROTECTION CORE 11000V 110V AVR CORE 11000V 110V NEUTRAL TRANSFORMER 11000V 110V METERING CORE 11000V 110V LINE PT 110000V 110V

(6)

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:

55560

2916.14

3

11

3

gp

Sn

kVA

I

A

Un

kV





Generator primary current

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

2916.14A

₅

_3.65

4000

gp gs

I

A

CTratio

A







Generator secondary current

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

A

I

87s



0 .

20 

5 

1

This is in turn the equivalent to the generator rated current.

87

1 %

100 100 27.4%

3.65

s gs

I

A

I

A













The bias slope is set to

bias



40 %

Setting

Name of

parameter Range

Operate Value 1A

(7)

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 xd 93.3%

Transient reactance (saturated) xd´ 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:

11000

4000

110

5

1.5 2916.14

5 11000

100

G r G r

V

CTratio I

V

A

V

A

F

I

VTratio V

A

V















where

Ir … rated current of the relay

Vr … rated voltage of the relay (100V internally) So the adapted reactances are

1.5 0.933

1.399 '

' 1.5 0.255

0.382

d d d d

x

F x

pU

x

F x

pU

 







 







The relay function setting is calculated as follows.

1.40 '

0.382

1.4

0.891

2

d d d

Diameter x

pU

x

pU

Center

pU











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:

The Time Delay Stage 2 is set to 1 sec.

The Operate Value of the Function "27/50" is set to 50V.

& _Trip

Underexcitation Stage 1 Pickup

(8)

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

55560

_2916.14

3

11

3

g gp gp

S

kVA

I

A

V

kV





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

2916.14A

5

3.64 4000

gp gs

I

A

CTratio

A







So the CT ratio compensation is

3.64

0.73

5

gs N

I

A

CT ratio comp

I

A



A further data for the generator (manufacturer data) is the inverse time characteristic i2_{t, which is}

for example i2_t=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

2

20 3125 52

0.08 s

s

min









The tripping time can be calculated exactly



















₂ 2 2 2 2 2

ln

e trip

i

t



(9)

25 ln

0.0408 127.5

24

trip

t

 



 





s

Compared with the manufacturer data

2 2 2

3.5

20 _98.7

0.45

trip

s

t

s

i



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

V

VTratio

V

s gp

1 .

10

121 .

0 11000

110 11000

%

110 









and the time delay is set to t = 2.0 s

Stage 2 is selected to be 125% of the generator rated voltage, therefore

V

VTratio

V

s gp

1 .

25

137 .

5 11000

110 11000

%

125 









and the time delay is set to t = 0.0 s

Setting:

Name of parameter Range Unit

Operate Value Stage 1 121.0 V

Operate Value Stage 2 137.5 V

Time Delay Stage 1 2 Sec

Time Delay Stage 2 0 Sec

(10)

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 %

ns



0 .

70 

110 

77

Time delay

t

27



2 .

5 s

trip Setting:

Operate Value 77 [V]

Time Delay 2,5 [Sec]

Type 2 Under Voltage

-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

f

81.1



52 .

0 Hz

time delay

t

81.1



0 .

5 s

Trip

Stage 2 overfrequency

f

81.2



52 .

5 Hz

time delay

t

81.2



0 .

0 s

Trip

Stage 3 underfrequency

f

81.3



48 .

5 Hz

time delay

t

81.3



20 .

0 s

Trip

Stage 4 underfrequency

f

81.4



47 .

0 Hz

time delay

t

81.4



0 .

0 s

Trip

The frequency settings need to be reviewed by the grid regulator. Setting:

Min. Volt. Setting 60 – 100 [V] Max. Volt. Setting 100 – 140 [V] Operate Value St. 1 52 [Hz] Time Delay St. 1 0.5 [s] Type St. 1 Overdetection Operate Value St. 2 52.5 [Hz] Time Delay St. 2 0.00 [s] Type St. 2 Overdetection Operate Value St. 3 48.5 [Hz] Time Delay St. 3 20 [s] Type St. 3 Underdetection Operate Value St. 4 47 [Hz] Time Delay St. 4 0.00 [s] Type St. 4 Underdetection

(11)

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:

V

kV

ratio

transf

V

N Gen

63 .

5

110 /

11

1

3

11

1

3

sec











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

V

range

prot

V

_set N

63 .

5

3 .

18 %

100 %

95 %

100 %

100 .

%

100

sec































Selected value (according to setting range of the protection relay): 3.2V. Time delay 1.0s

Setting:

Operate Value 3.2 V

Time Delay 1.0 Sec

Type Over detection

-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

(12)

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:



3 rd

.

Harm

.

gen

.

ter

min

al

volt

.



ratio



3 rd

.

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



with a time delay

t

delay



10 s

(13)

Stage 1 will initiate an Alarm only.

Stage 2:

R

 1500



with a time delay

t

_delay



1 s

Stage 2 will initiate a trip.

Setting:

Name of parameter Setting Unit

Operate Value, Stage1 50 [kΩ]

Time Delay, Stage1 10 [s]

Operate Value, Stage2 1.5 [kΩ]

Time Delay, Stage2 1 [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

kW

A

kV

I

V

P

relp



3 

p



CTp



cos





3 

11 .

00 

300 

1 

5715

.

77

The required -5.0% primary reverse power setting of the machine rating is

kW

A

kV

I

V

P

p32





5 .

0 %



3 

p



g



cos







0 .

05 

3 

11 .

00 

262 .

4 

0 .

9 



225

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 Setting Unit

Operate Value -3.94 [% PN]

Time Delay 5 [s]

Power Direction Direction 1

-Phase Rotation Right

-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

(14)

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:

Operate Value I 0.2 A

Operate Value U 50 V

Time Delay 5 [s]

Phase Rotation 2 (Right)

-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

A

V

S

I

gp g gp

262 .

4

3 





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:

A

V

S

I

hvp t hvp

57 .

73

3 





HV transformer primary current

A

V

S

I

Lvp t Lvp

577 .

35

3 





LV transformer primary current

The primary short circuit impedance of the transformer is obtained by













0 .

835

100

11

50 .

7

11

100

2 2

MVA

V

k

u

S

V

Z

k t TS p

(15)

Therefore the secondary transformer impedance is calculated













0 .

825

0 .

495 11000

5

110

300

p s

Z

VTratio

CTratio

Z

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













50 %

0 .

5

1 .

73

0 .

247

21G

Z

s

Z

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

A

ratio

CT

I

Is

LV

11 .

55

300

5

35 .

577

2 .

1

2 .

1 









The time delay setting for stage 2 depends on the time grading of the remaining network. Setting:

Name of

parameter Range Unit

Operate Value 0.25 [Ohm]

Time Delay Imp. 0.2 [s]

Time Delay Curr. Depends on time grading of remaining n/w [s]

Current Interlock 11.55 A

M) DEAD MACHINE 27/51V

The overcurrent setting will be coordinated with all the other overcurrent functions (generator, transformer ...).

A

I

27/51V



1 .

10

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

110

66 .

0 %

100 %

60

51 / 27







(16)

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

2 .

0 

K

Setting:

Operate Value 1.1 [A]

Voltage Limit 66 [V]

K-Factor 0.2

-Time Delay 4 [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.

A

kV

kVA

V

S

I

hvp t hvp

57 .

74

3

110 11000

3 









HV transformer primary current

A

CTratio

I

hvs hvp

1 .

0

0 .

96

60

74 .

57 _

_



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

%

8 .

20

100

96 .

0

20 .

0 %













A

I

hvs s hvs

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

A

I

ratio

CT

I

hvp hvs

0 .

15

75

0 .

1

500 _

_









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.

5

5 .

0

11

110

1 /

60

1 /

300

2

1 .

1

2

1

2 











kV

A

system

ratio

tr

CTsystem

comp

CTratio

(17)

05 .

0

11

110

1 /

60

1 /

300

3

1 .

1

3

1

3 











kV

A

system

ratio

tr

CTsystem

comp

CTratio

Setting:

Operate Value 20%

-High Set OC 4,8A

-CT Ratio Comp. 2-1 0.5

-2nd Harmonic 20 (to be verified during commissioning) % 5th Harmonic 15 (to be verified during commissioning) %

Bias 50 %

Vector Group 1-2 1

-Vector Group 1-3 11

-Zero Sequ. Syst.1 On

-Zero Sequ. Syst.2 Off

-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 

The CT requirements for the High impedance transformer restricted earth fault protective function, is according to the following formula.

(18)

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).

A

kV

kVA

CTratio

V

S

I

F T

12 .

24

0 .

1 /

600

220

3 175000

16

3

16 









220kV lead CTs Vk = 300 V > 2 x 12.24A (5+ 2 x 0.3) = 137.16 V 220kV neutral CT 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













455

15 .

0

15 .

0

1 .

0

69

S S S ST

I

relayVA

V

R

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



V

_p



2 

_K



_f



_K



3000

VK=300V



R







V

I

V

f



F



CT



2

l



ST



R



12 .

24 

5 

2 

0 .

3 

455 

5637

Thus,

V

_p



3579

V

Due to ensure a safety margin a voltage limiting resistor is connected into the circuit. Continuous power rating of the setting resistor:

 

I

R





W

P

_con

_

_S 2

_

_ST

_

0 .

15

2

_

455 _

10 .

2

with a short time rating:





onds

for

W

R

I

R

V

R

V

P

ST F ST K ST fs short

159

0 .

5 sec

3 .

1

2 4 1 3 2



















(19)

Thermal rating of the non-linear resistor:

W

V

A

V

I

P

_F _K

12 .

24

300 4677

.

94

15 .

3

4

4 _

_

_

_

_





A

R

V

I

ST setting

0 .

15

455 69 



Settings:

Operate Value 42.5 %

-Drop Off Delay 0.5 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 

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 

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).

A

kV

kVA

CTratio

V

S

I

F T

12 .

24

0 .

1 /

600

220

3 175000

16

3

16 









(20)

220kV lead CTs Vk = 300 V > 2 x 12.24A (5+ 2 x 0.3) = 137.16 V 220kV neutral CT 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













162 .

22

15 .

0

15 .

0

1 .

0

69

S S S ST

I

relayVA

V

R

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



V

p



2 

K



f



K



3000

VK=300V





2 







12 .

24 



5 

2 

0 .

3 

162 .

22 



2055

.

28 



_F _CT _l _ST _R f

I

R

V

Thus,

V

_p



2052

.

48 V

Due to ensure a safety margin a voltage limiting resistor is connected into the circuit. Continuous power rating of the setting resistor:

 

I

R





W

P

con S ST

0 .

15

162 .

22

3 .

65

2

_

_

_

_



with a short time rating:





onds

for

W

R

I

R

V

R

V

P

ST F ST K ST fs short

2412

.

82

0 .

5 sec

3 .

1

2 4 1 3 2



















Thermal rating of the non-linear resistor:

W

V

A

V

I

P

F K

12 .

24

300 4677

.

94

15 .

3

4

4 _

_

_

_

_





(21)

A

R

V

I

ST setting

0 .

42

22 .

162

69 _



Settings:

Operate Value 42.5 %

-Drop Off Delay 0.5 s

Q) OVERFLUXING PROTECTION 99G

The degree of saturation (overfluxing) is calculated according to following formula.

f

V

f

V

S

N N





Whereby V and VNare 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 S1A=1.05 time delay t=10.0s

Stage 2 trip S2T=1.10 time delay t=1.0s

Setting:

Name of parameter Setting Unit

Operate Value St. 1 1.05 [p.U.]

Time Delay St. 1 10.00 [s]

Operate Value St. 2 1.10 [p.U.]

Time Delay St. 2 1.00 [s]

Nominal Frequency 50.0 [Hz]

Nominal Voltage 110 [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:

A

kV

kVA

V

S

I

np AT AT-HVp

26 .

24

3

11

500

3 









UAT (HV) primary current

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

A

CTratio

I

AT-HVs AT-HVp

5

4 .

37

30

24 .

26 _

_



(22)

A

V

kVA

V

S

I

np AT AT-LVp

695 .

60

3

415

500

3 









UAT (LV) primary current

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

A

CTratio

I

AT-LVs AT-LVp

1

0 .

87

800

60 .

695 _

_



UAT (LV) secondary current

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

A

I

87s



0 .

20 

5 

1 .

00

This is in turn the equivalent to the generator rated current.

%

16 .

38

100

62 .

2

0 .

1

100 %













A

I

AT-HVs s

High set overcurrent = 5.0 x IN =13.1

The bias slope is set to

bias



40 %

00 .

1

415 .

0

11

1 /

30

800

2

1 .

1

2 _









kV

A

system

ratio

tr

CTsystem

comp

CTratio

Setting:

Operate Value 38.16%

-High Set OC 13.1

-2nd Harmonic 20 (to be verified during commissioning) % 5th Harmonic 15 (to be verified during commissioning) %

Bias 40 %

Vector Group 1-2 11

-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

(23)

The protective function settings are obtained

A

kV

kVA

V

S

I

np AT ATp

26 .

24

3

11

500

3 









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

A

CTratio

I

ATs ATp

5

2 .

62

50

24 .

26 _

_



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

A

I

51



ATs

1 .

2 

2 .

62 

1 .

2 

3 .

15

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

A

I

50



51



5 .

0 

3 .

15 

5 .

0 

15 .

75

The time delay of Stage 2 is chosen to be

t

50



0 .

1 s

Setting:

Operating Val. St.1 3.15 A

TMS St.1 0.5

-Curve normal inverse

-Operating Val. St.2 15.75 A

Time delay St.2 0.1 Sec

4. Distance Protection

Line Parameters:

POSITIVE SEQUENCE RESISTANCE R1 0.0659 OHMS/KM POSITIVE SEQUENCE REACTANCE X1 0.3836 OHMS/KM

ZERO SEQUENCE RESISTANCE R0 0.272 OHMS/KM

ZERO SEQUENCE RESISTANCE X0 1.233 OHMS/KM

LINE LENGTH L1 70 KM

LENGTH OF NEXT SHORTEST LINE L2 30 KM

LENGTH OF NEXT LONGEST LINE L3 30 KM

ARC RESISTANCE PH-PH Arc ph-ph 0 OHMS

ARC RESISTANCE PH-EARTH Arc ph-e 20 OHMS

(24)

MALANA-II HEP Page 24 of 29 R1=0.0659 X1=0.3836 R0=0.272 X0=1.233









1

0 .

3892

1 _R

2

_X

2

Z







₈₀

_.

₂₅₁₇

1

1 ),

(

1

R

X

Tan

Ph

LineAngle











0

1 .

2626

0 _R

2

_X

2

Z







₇₇

_.

₅₅₉₈

0

0 ),

(

1

R

X

Tan

E

Ph

LineAngle



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:

06 .

0 

PTratio

CTratio

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:

Reactance Ratio:

Earth Compensation Factor, Ko:

04248

.

1

3

1

1 0















_





R

L G

7381

.

0

1

3

1

1 0















_





X

L G



















1

3

1

1 0 0

_Z

Z

K

(25)

K

₀



0 .

7469



0 .

0508

i

(

)

0 .

7469

2

0 .

0508

2

0 .

7486

0







K

ABS

3 .

89 7469

.

0 0508

.

0 tan

)

(

1 0





K

ARG

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

(26)

Zone3 : 100% + 100% of next longest line Zone4 : Normally 15% to 20% of Zone 1

Zone 1 Calculation:

Phase to Phase Faults:

Primary Values











(

1

1 *

0 .

8 )

3 .

69

1

1 Z

p

R

pL

arcph

ph

R





(

1

1 *

0 .

8 )

21 .

481

1

1 Z

p

X

pL

X

Secondary Values





1

1 *

0 .

06

0 .

221

1

1 Z

s

R

Z

p

R





1

1 *

0 .

06

1 .

289

1

1 Z

s

X

Z

p

X

Phase to Earth Faults:

Primary Values











(

0

1 *

0 .

8 )

35 .

232

1

0 Z

p

R

pL

arcph

e

R





(

0

1 *

0 .

8 )

69 .

048

1

0 Z

p

X

pL

X

Secondary Values





0

1 *

0 .

06

2 .

114

1

0 Z

s

R

Z

p

R





0

1 *

0 .

06

4 .

143

1

0 Z

s

X

Z

p

X

Primary Values











(

1

1 )

(

1

2 *

0 .

5 )

5 .

602

2

1 Z

p

R

pL

R

pL

arcph

ph

R









(

1

1 )

(

1

2 *

0 .

5 )

32 .

605

2

1 Z

p

X

pL

X

pL

X

Secondary Values





1

2 *

0 .

06

0 .

336

2

1 Z

s

R

Z

p

R





1

2 *

0 .

06

1 .

956

2

1 Z

s

X

Z

p

X

(27)

Phase to Earth Faults: Primary Values











(

0

1 )

(

0

2 *

0 .

5 )

43 .

120

2

0 Z

p

R

pL

R

pL

arcph

e

R









(

0

1 )

(

0

2 *

0 .

5 )

104 .

805

2

0 Z

p

X

pL

X

pL

X

Secondary Values





0

2 *

0 .

06

2 .

587

2

0 Z

s

R

Z

p

R





0

2 *

0 .

06

6 .

288

2

0 Z

s

X

Z

p

X

Primary Values











(

1

1 )

(

1

3 )

6 .

590

3

1 Z

p

R

pL

R

pL

arcph

ph

R









(

1

1 )

(

1

3 )

38 .

358

3

1 Z

p

X

pL

X

pL

X

Secondary Values





1

3 *

0 .

06

0 .

395

3

1 Z

s

R

Z

p

R





1

3 *

0 .

06

2 .

301

3

1 Z

s

X

Z

p

X

Primary Values











(

0

1 )

(

0

3 )

47 .

200

3

0 Z

p

R

pL

R

pL

arcph

e

R









(

0

1 )

(

0

3 )

123 .

300

3

0 Z

p

X

pL

X

pL

X

Secondary Values





0

3 *

0 .

06

2 .

832

3

0 Z

s

R

Z

p

R





0

3 *

0 .

06

7 .

398

3

0 Z

s

X

Z

p

X

Reverse Zone 4 Calculation:

(28)











(

1

1 *

0 .

2 )

0 .

923

4

1 Z

p

R

pL

arcph

ph

R





(

1

1 *

0 .

2 )

5 .

370

4

1 Z

p

X

pL

X

Secondary Values





1

4 *

0 .

06

0 .

055

4

1 Z

s

R

Z

p

R





1

4 *

0 .

06

0 .

322

4

1 Z

s

X

Z

p

X

Primary Values











(

0

1 *

0 .

2 )

23 .

808

4

0 Z

p

R

pL

arcph

e

R





(

0

1 *

0 .

2 )

17 .

262

4

0 Z

p

X

pL

X

Secondary Values





0

4 *

0 .

06

1 .

428

4

0 Z

s

R

Z

p

R





0

4 *

0 .

06

1 .

036

4

0 Z

s

X

Z

p

X

Settings:

Name of parameter Set Value Unit

Line Angle ph-ph_ph-e 80.2517_77.5598 Degrees Earth fault Compensation Factors Re/Rl _1.042489 Xe/Xl _0.738143 Zone 1 (Forward) ph-ph R 0.221 Ohms X 1.289 ph-e R_X 2.114_4.143 Zone 2 (Forward) ph-ph RX 0.3361.956 Ohms

(29)

ph-e R_X 2.587_6.288 Zone 3 (Forward) ph-ph R 0.395 Ohms X 2.301 ph-e R_X 2.832_7.398 Zone 4 (Reverse) ph-ph R 0.055 Ohms X 0.322 ph-e R_X 1.428_1.036 Operation time Zone 1 0 secs Zone 2 0.4 Zone 3 0.8 Zone 4 1.2

DRS_setting Calculation Reference 1

ABIR INFRASTRUCTURE PVT. LTD.

MALANA-II HYDRO ELECTRIC PROJECT

SETTINGCALCULATION NUMERICAL

PROTECTION SYSTEM

2 783001

0

Table of Contents

55560

2916.14

3

11

3

Sn

kVA

I

A

Un

kV











2916.14A

5

3.65

4000

I

I

A

A

CTratio

A









A

A

I



0

.

20



5



1

1

%

100

100 27.4%

3.65

I

A

I

I

A













bias



40

%

11000

4000

110

5

1.5

2916.14

5

11000

100

V

CTratio I

₅

_3.65

_2916.14