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0
Rev
Client :

Project :
Designer

For approval
Description
Date
03-01-2015
MR
Checked
OPGS

TS
Approved
2*150MW COAL BASED TPP
VOLTECH ENGINEERS PVT LTD

Tilte :

Doc.No :
Description:

VE-J-234-D-E-001
LINE PROTECTION

Relay setting calculation

PROJECT: 2*150MW COAL BASED TPP DOC.NO
CLIENT: OPGS VE-J-234-D-E-001
PRPD: AJ
TITLE: Relay setting calculation DATE REV
CKD: MR
220KV MOKHA LINE FEEDER 03-01-2015 0 APPRVD TS

220kV MOKHA LINE DISTANCE PROTECTION RELAY TYPE : P442

INPUT DETAILS
system voltage 220 kV
CT Details
CT Ratio 1600-800/1A
Adopted CT Ratio 800/1A 1600
CT Primary 1600 A
CT Secondary 1 A
Class PS

System Details
VT Ratio 220kV/√3 2000
110V/√3
VT Primary 220000 V
VT Secondary 110 V
Frequency 50HZ
fault current 40.00 kA

OHL Details
Condutor type AL-59
Line Length 14 km
Line impedence
Positive sequence impedence (Z1) 0.0021 +j 0.219
Zero sequence impedence ( Z0 ) 0.0063 +j 0.657
Line Length 14 km
Current rating in Amps 1600 (Max.CT Primary Current is considered)
Line impedences
Z1 0.219 L 89.450 Ω/km
Z0 0.657 L 89.450 Ω/km
Z0/Z1 3.000 L 0.000 °

Adjacent Longest Line details

Condutor type zebra
Line Length 57.6
Line impedence
Positive sequence impedence (Z1) 0.08 +j 0.402
Zero sequence impedence ( Z0 ) 0.218 +j 1.35
Line Length 57.6 km
Line impedences
Z1 0.410 L 78.740 Ω/km
Z0 1.367 L 80.830 Ω/km

Adjacent Shortest Line details

Condutor type zebra
Line Length 47.5 km
Line impedence
Positive sequence impedence (Z1) 0.08 +j 0.402
Zero sequence impedence ( Z0 ) 0.218 +j 1.35
Line Length 48 km
Line impedences
Z1 0.410 L 78.740 Ω/km

Z0 1.367 L 80.830 Ω/km

Relay settings
Line impedence
Ratio of secondary to primary impedence = CT ratio / VT ratio
(1600/2000)
0.8
Line impedence secondary = ratio CT/VT x line impedence primary
0.8*14*0.219
Line impedence = 2.453 L 89.0

Therefore set Line Impedence and Line Angle = 2.45 L 89.0 Ω secondary
 Zone 1 Phase Reach Settings
Required Zone 1 reach is to be 85% of the Protected line
Zone 1 Reach = (0.85*2.45)
°
Z1= 2.08 L 89 Ω secondary
The Line Angle = 89 °
Therefore actual Zone 1 reach, Z1 2.08 L 89 Ω secondary

Zone 2 Phase Reach Settings

Required Zone 2 reach is to be 120% of the Protected line

Zone 2 Reach = (1.2*2.453)

2.94 L 89 Ω secondary
Actual Zone 2 reach, Z2 2.94 L 89

Zone 3 Phase Reach Settings

Required Zone 3 forward reach
(100% of the protected line +50%of the adjacent longest line)
Zone 3 Reach = (1*2.453)+(0.5*0.41*57.6*0.8)
11.90 L 89 Ω secondary
Actual Zone 3 reach, Z3 = 11.90 L 89

Zone 4 Reverse Reach Settings

Required Zone4 reverse reach impedence,typically 20% Zone 1 reach
0.2*2.08
Z4 0.42 L 89 Ω secondary
ZONE TIMER SETTING:
tZ1 0.00 s
tZ2 0.40 s
tZ3 0.80 s
tZ4 0.50 s

Residual Compensation for Earth Fault Element

This feature is useful where line impedence characteristics change between sections or where hybrid circuits are used. here,the line
impedence characteristics not known for adjacent sections.Hence a common KZ0 factor can be applied to each zone.

kZ0 Res. Comp, │kZ0│ = (Z0-Z1) / 3Z1

kZ0 Angle, L kZ0 = L (Z0-Z1) /3Z1

(0.0063+j0.657)-(0.0021+j0.219)
Z0-Z1 = 0.0042 +j 0.438
0.438 L 89.450
(0.438/(3*0.219)) L 89.45-89.45
(Z0-Z1) / 3Z1 =
0.667 L 0.00 °
kZ0 Res. Comp, │kZ0│ = 0.667
kZ0 Angle, L kZ0 = 0.0 °

Resistive Reach Calculations

Minimum Load impedence to the relay = Vn (phase - neutral) / In

(110V/√3 /1)
Minimum Load impedence to the relay =
63.51 Ω secondary
Typically,phase fault distance zones would avoid the minimum load impedence by a margin of ≥ 40%,earth fault zones
would use a ≥ 20% margin.
This allows maximum resistive reaches for Phase faults = 38.11 Ω secondary
This allows maximum resistive reaches for Earth faults = 50.81 Ω secondary

Ra = (28710 x L) / If^1.4
Where: If = Minimum expected phase-phase fault current (A);
L = Maximum phase conductor separation (m);
Ra = Arc resistance, calculated from the van Warrington formula (W).
3-phase faults:
Source Impedance, Zs = kV/ √3 * I SCC
= 220/(1.732*40)
= 3.18 Ω
positive sequence Line Impedance = 3.066
Ztot = 6 Ω
The minimum three-phase fault current without fault resistance
I 3ph min = 220000/(1.732*6)
= 20350.48 A
fault current = 20.350 kA
Conductor spaces = 5 mtrs
Primary resistive coverage for phase
0.133 Ω
faults
assuming a typical earth fault coverage 40 Ω
RPH (min)-secondary 0.133*0.8 0.107 Ω
RG (min) 40*0.8 32 Ω

Selection of Resistive Reaches

The Zone 2 elements satisfy R2Ph ≤ (R3Ph x 80%), and R2G ≤ (R3G x 80%)
R3Ph - R4Ph should be set ≤ 80% Z minimum load - ∆R
Minimum Maximum Zone 1 Zone 2 Zones 3 & 4
Phase (RPh)Ω 0.107 38.11 19.5 24.4 30.48
Earth (RG)Ω 32 50.81 21.4 28.6 38.11

Power Swing Block

∆R and ∆X band settings are both set between 10 - 30% of R3Ph as recommended by AREVA

Minimum 10% x 30.48 = 3.05

Maximum 30% x 30.48 = 9.15
Considering power swing frequency and load impedence and angle between sources,the ∆R becomes
∆R = 0.16*Rload (min)
0.16*63.51*0.6 (40% of margin is considered)
= 6.1 (this value is well within the min&max limits above)
Biased Residual Current IN> = 40% (typical setting from manual)
Biased Negative Sequence Current I2> = 30% (typical setting from manual)
Power swing current = 2 In
minimum setting for Imax line> = 1.2 x (max.power swing current)
= 1.2*2*1
minimum setting for Imax line> = 2.4
minimum fault current level = 20350 A
Fault current in secondary = 20350*1/1600
= 12.7190 A
maximum setting for Imax line> = 0.8 x (min.phase fault current level)
= 10.18 A
Hence setting for Imax line> = 8 A

Broken Conductor Protection

Full load current = 1600 A
Considered I2 = 160 A (10% of fullload current)
I2 / I1 = 0.1
Allow for tolerences and load varations = 200%
I2 / I1 = 0.2
time delay = 5 s

SOTF
SOTF Protection operates 120% of fault current with breaker closing command
Fault current = 20350 A
= 1.2*20350.4794062777
= 24420.5753
= 15.2628596 A

LOCAL BREAKER BACKUP PROTECTION:

In general, a breaker failure scheme determines that a breaker signaled to trip has not cleared a fault with in a definite time, so further
tripping action must be performed.
CB Fail 1 Timer = 0.2 s
I< Current Set = 0.2 In
Settings Table
Menu text Setting
GROUP1 DISTANCE
ELEMENTS
Line setting
Line Length 14 km
Line Impedence 2.45 Ω
Line Angle 89
Zone setting
Zone status
KZ1 Res Comp 0.67 Ω
KZ1 Angle 0
Z1 2.08 Ω
R1G 21.4 Ω
R1ph 19.5 Ω
tZ1 0 s
KZ2 Res Comp 0.67 Ω
KZ2 Angle 0
Z2 2.94 Ω
R2G 28.6 Ω
R2ph 24.4 Ω
tZ2 0.4 s
KZ3/4 Res Comp 0.67 Ω
KZ3/4 Angle 0
Z3 11.90 Ω
R3G -R4G 38.1 Ω
R3ph - R4ph 30.5 Ω
tZ3 0.8 s
Z4 0.42 Ω
tZ4 0.5 s
GROUP1 POWER SWING
Delta R 6.1 Ω
Delta X 6.1 Ω
IN>Status Enabled
IN>(%Imax) 40%
I2>Status Enabled
I2>(%Imax) 30%
Imax line>Status Enabled
Imax line> 8 A
Unblocking Time delay 30 s
Blocking Zones 00000000

LOCAL BREAKER BACKUP PROTECTION

CB Fail & I<

Breaker Fail

CB Fail 1 Timer 0.2 s

I< Current Set 0.2 In

GROUP 1 BROKEN CONDUCTOR

Broken conductor Enabled
I2 / I1 0.2
I2 / I1 Time Delay 60 s
I2 / I1 Trip Enabled

GROUP 1 SUPERVISION
VT Supervision
VTS Time Delay 5 s
VTS I2>IO>inhibit 0.2 A
Detect 3P Enabled
Threshold 3P 10V
Delta I> 0.2 A
PROJECT: 2*150MW COAL BASED TPP DOC.NO
CLIENT: OPGS VE-J-234-D-E-001
PRPD: AJ
TITLE: Relay setting calculation DATE REV
CKD: MR
220KV MOKHA LINE FEEDER 03-01-2015 0 APPRVD TS
220kV MOKHA LINE DISTANCE PROTECTION RELAY TYPE : REL650
INPUT DETAILS

System Data
System Voltage 220 kV
System Frequency 50 Hz
Fault Level 40 kA

CT Details
CT Primary 1600 A
CT Secondary 1A

PT Details:
PT Ratio = 220000/110V
PT Primary Voltage = 220000 V
PT Secondary Voltage = 110 V
System Frequency = 50 HZ

System Details for mokha line

Nominal system voltage,UN 2200000 V 220000
Current transformer ratio,Nct 1600/1 A 1600
Voltage transformer ratio,Nvt 220000/110 2000
Ratio of secondary to primary impedance,Nct/Nvt 0.800
Protected OHL Type AL-59
current rating in Amps 1600 (Max.CT Primary Current is considered)
Protected OHL length 14.000 kM 14.000
Positive seq.Resistance of OHL in Ω, per kM, Rprim 0.002
Positive seq.Reactance of OHL in Ω, per kM, Xprim 0.219
O
Positive seq.impedance of OHL in Ω, per kM, Zprim 0.219 89
Zero seq.Resistance of OHL in Ω, per kM, Rprim 0.00630
Zero seq.Reactance of OHL in Ω, per kM, Xprim 0.65700
O
Zero seq.impedance of OHL in Ω, per kM, Zprim 0.657 89

Tower footing Resistance (Primary) 10.000 Ω

Tower footing Resistance (Secondary) 8.000 Ω

Adjacent OHL details (shortest line )

OHL length 47.5 kM 47.5
OHL Type ACSR ZEBRA
Positive seq.Resistance of OHL in Ω, per kM, Rprim 0.080
Positive seq.Reactance of OHL in Ω, per kM, Xprim 0.402
O
Positive seq.impedance of OHL in Ω, per kM, Zprim 0.410 79
Zero seq.Resistance of OHL in Ω, per kM, Rprim 0.21800
Zero seq.Reactance of OHL in Ω, per kM, Xprim 1.35000
O
Zero seq.impedance of OHL in Ω, per kM, Zprim 1.367 81

Adjacent OHL details (longest line )

OHL length 57.6 kM 57.6
OHL Type ACSR ZEBRA
Positive seq.Resistance of OHL in Ω, per kM, Rprim 0.080
Positive seq.Reactance of OHL in Ω, per kM, Xprim 0.402
O
Positive seq.impedance of OHL in Ω, per kM, Zprim 0.410 79
Zero seq.Resistance of OHL in Ω, per kM, Rprim 0.21800
Zero seq.Reactance of OHL in Ω, per kM, Xprim 1.35000
O
Zero seq.impedance of OHL in Ω, per kM, Zprim 1.367 81

Reactance & Resistance settings

Zone 1 Settings
Required Zone 1 reach is to be 85% of the Protected line
X1-Z1 prim = 85% * X1prim = 2.606
X1-Z1 sec = Nct/Nvt * X1prim = 2.085

R1- Z1 prim = 85% * R1prim = 0.025

R1-Z1 sec = Nct/Nvt * R1prim = 0.020

X0-Z1 prim = 85% * X0prim = 7.818

X0-Z1 sec = Nct/Nvt * X0prim = 6.255

R0-Z1 prim = 85% * R0prim = 0.075

R0-Z1 sec = Nct/Nvt * R0prim = 0.060

Positive Sequence Impedance, Z1 = 2.085

Zero sequence compensation factors

Resistance Ratio RE/RL(Z1) = 1/3 {(R0/R1) -1)}

= (1/3)((0.0063/0.0021)-1)
= 0.67

Reactance ratio XE/XL(Z1) = 1/3{(X0/X1) -1)}

= (1/3)((0.657/0.219)-1)
= 0.67
R0-R1 = 0.004
X0-X1 = 0.438
O
Z0-Z1 = 0.438 89
O
Z0/Z1 MAG & ANGLE= (Z0-Z1)/3Z1 = 0.67 0

Zone 2 Settings
Zone 2 element setting with a reach of 120% of Protected line reactance accounts for effect of infeed.This point must be verified
using a fault study to calculate
the apparent ohms at the local terminal for a fault at the remote end of transmission line. In our case 120% is considered for the
assurance that all faults in the protected line are detectable,even with infeed from remote terminals.

Assuming the zone-1 reach for the adjacent line protection is set at 85% of that line reactance, and it is to be verified such that the
zone-2 reach of 120%
(protected line) shall not extend beyond the max.effective zone-1 reach of the adjacent line protection.
Zone-2 setting limit = Protected line reactance + 0.85 * adjacent line reactance
= 15.437
Zone-2 setting with 120% reach = 2.943
Since 120%, 2.701 is lower than zone-2 limit, 8.744, then the zone-2 setting of 120% will not overreach beyond zone-1 setting of
adjacent line protection.
Therefore we can consider 120% of protected line reactance for zone-2.
Hence set X1 -Z2 prim = 3.679
Hence set X1-Z2 sec = 2.943

Hence set R1-Z2 prim = 0.035

Hence set R1-Z2 sec = 0.028

Hence set X0 -Z2 prim = 11.038

Hence set X0-Z2 sec = 8.830

Hence set R0 -Z2 prim = 0.106

Hence set R0-Z2 sec = 0.085

Positive Sequence Impedance, Z2 = 2.943

Zone 3 Settings
For Zone3 setting , it is customery to select (Protected line + 50% Adjacent longest line)
X1-Z3 prim, reach = 14.644
X1-Z3 sec = Nct/Nvt * X1prim*IN/A = 11.715

R1-Z3prim, reach = 2.333

R1-Z3sec = Nct/Nvt * R1prim*IN/A = 1.867

X0-Z3 prim, reach = 48.078

X0-Z3 sec = Nct/Nvt * X0prim*IN/A = 38.462

R0-Z3prim, reach = 6.367

R0-Z3sec = Nct/Nvt * R0prim*IN/A = 5.093

Positive Sequence Impedance, Z3 = 11.863

Zone 4 Settings = spare

Zone 5 Settings
For Zone5 setting, reverse reach impedence is typically 20% Zone 1 reach Impedance.
X1-Z5 prim, reach = 0.521
X1-Z5 sec = Nct/Nvt * X1prim*IN/A = 0.417

R1-Z5prim, reach = 0.005

R1-Z5sec = Nct/Nvt * R1prim*IN/A = 0.004

X0-Z5 prim, reach = 1.564

X0-Z5 sec = Nct/Nvt * X0prim*IN/A = 1.251

R0-Z5prim, reach = 0.015

R0-Z5sec = Nct/Nvt * R0prim*IN/A = 0.012

Positive Sequence Impedance, Z5 = 0.417

Time setting
Zone-1 setting = 0 sec

Zone-2 setting
zone-2 time delay should be set to discreminative with the primary line protection of the next line sections
including circuit breaker trip time
Adjoining line protection operating time = 0.04
Breaker opening time = 0.08
Local relay reset = 0.03
Grading margin = 0.25
Required zone-2 time delay = 0.4
set zone-2 at = 0.4 sec

Zone-3 setting
zone-3 time delay shall be such that zone-2 time delay plus grading margin
zone-2 time delay = 0.4
Grading margin = 0.4
Required zone-3 time delay = 0.8
set zone-3 at = 0.8 sec

Zone 4 Settings = spare

Zone-5 setting
zone-5 might be used to provide back up protection for the local bus bar. zone-5 time delay shall be such that LBB time delay
plus grading margin
LBB time delay = 0.2
Grading margin = 0.25
Required zone-5 time delay = 0.45
set zone-5 at = 0.5 sec

Load impedance and Load Angle calculation:

Maximum Load current = 1600 A

Rload prim = Umin/√3*Ilmax
Where
Umin = minimum operating voltage, 0.9*UN = 198000
ILmax = max load current = 1600
Hence Zload prim = 71.45
Zload sec = 57.159
Rload sec = Zload min sec X Cos Ø min
Cos Ø min = 0.85
Rload sec = 48.585
As load current ideally is in phase with the voltage, the difference is indicated with the power factor cosØ. The largest angle
of the load impedance is therefore given by the worst, smallest powerfactor. We considered the worst power factor under
full load condition is 0.85
Øload- min = arc cos (power factor min)
Øload- min = arc cos (0.85)
Øload- min = 32 O

Zone -1 Resistance for Phase to Phase

Based on the source and line impedance,the following minimum fault current levels can be calculated for faults on line1

Ifault = Usource
Arc Resistance Calculation: √3*Ztot

3-phase faults:
Source Impedance, Zs = kV/ √3 * I SCC
= 220/(1.732*40)
= 3.18 Ω
positive sequence Line Impedance = 0.029 +J 3.066
= 3.066 Ω
Ztot = 6 Ω
The minimum three-phase fault current without fault resistance
I 3ph min = 220000/(1.732*6)
= 20350.48 A
The arc resistance will be calculated with the following equation
Rarc = Uarc/IF1.4
The arc voltage will be calculated using the following rule of thumb which provides a very conservative estimate
(the estimate Rarc is larger than the actual value)
Uarc = 28707 * L
Where
L = Length of the arc(for Phase to phase faults)
= 5.00 m (Assumed)
∴Rarc (Primary) = (28707*5)/(20350.48)^1.4
= 0.13 Ω

∴Rarc (Secondary) = 0.11 Ω

Single phase faults:
Ztot = 1/3*(sum of positive,negative and zero sequence of source and
line impedance)
Zero sequence Line Impedance = 0.088 +J 9.198 Ω/Km
= 9.198 Ω
= 1/3*((3*3.18)+((2*3.07)+(9.2))
Ztot = 9 Ω
The minimum single-phase fault current without fault resistance
I 1ph min = 220000/(1.732*9)
= 13548.30 A

The arc resistance will be calculated with the following equation

Rarc = Uarc/IF1.4
The arc voltage will be calculated using the following rule of thumb which provides a very conservative estimate
(the estimate Rarc is larger than the actual value)
Uarc = 28707 * L
Where
L = Length of the arc(for Phase to Earth faults)
= 5.00 m (Assumed)
∴Rarc (Primary) = (28707*5)/(13548.3)^1.4
= 0.24 Ω
∴Rarc (Secondary) = 0.19 Ω

Fault Resistance Calculation:

Setting of the resistive reach for the under reaching zone-1 should follow this condition.
Fault resistance for Ph-E fault Rf < 4.5 * X1PE
< 4.5*2.085
< 9.38 Ω

Total Fault resistance (RFPE) for Ph-E fault zone 1 = RT + Rarc + R1PE
= 8+0.189+0.02
= 8.21 Ω
Rf is lower than 80% of the load, we take Rf value,
Maximum allowable Resistive reach for Zone 1 = 9.38 Ω
Our set value should be less than the above value and to get Zone segrication.
Setting of RFPE- Zone 1 = 4.00 Ω

Setting of the resistive reach for the under reaching zone-2 should follow this condition.
Fault resistance for Ph-E fault Rf < 4.5 * X2PE
< 4.5*2.943
< 16.56 Ω

Total Fault resistance (RFPE) for Ph-E fault zone 2 = RT + Rarc + R2PE
= 8+0.19+0.028
= 8.22 Ω
Rf is lower than 80% of the load, we take Rf value,
Maximum allowable Resistive reach for Zone 2 = 16.56 Ω
Our set value should be less than the above value and to get Zone segrication.
Setting of RFPE- Zone 2 = 8.00 Ω

Setting of the resistive reach for the under reaching zone-3 should follow this condition.
Fault resistance for Ph-E fault Rf < 4.5 * X3PE
< 4.5*11.715
< 52.72 Ω

Total Fault resistance (RFPE) for Ph-E fault zone 3 = RT + Rarc + R3PE
= 8+0.19+1.867
= 10.06 Ω
Rf is lower than 80% of the load, we take Rf value,
Maximum allowable Resistive reach for Zone 3 = 52.72 Ω
Our set value should be less than the above value and to get Zone segrication.
Setting of RFPE- Zone 3 = 16.00 Ω

Setting of the resistive reach for the under reaching zone-5 should follow this condition.
Fault resistance for Ph-E fault Rf < 4.5 * X5PE
< 4.5*0.417
< 1.88 Ω

Total Fault resistance (RFPE) for Ph-E fault zone 5 = RT + Rarc + R5PE
= 8+0.19+0.004
= 8.19 Ω
Rf is lower than 80% of the load, we take Rf value,
Maximum allowable Resistive reach for Zone 5 = 1.88 Ω
Our set value should be less than the above value and to get Zone segrication.
Setting of RFPE- Zone 5 = 0.40 Ω

To avoid load encroachment for the phase to earth measuring elements, the set resistive reach of any distance zone must be less
than 80%of the
minimum load impedance.
RFPE = 0.8 * Zload
= 0.8*57.159
= 45.73 Ω
 Limit the setting of the zone 1 reach in resistive direction for ph-ph loop measurement
Fault resistance for Ph-Ph fault Rf < 3* X1Z1
< 3*2.085
< 6.25 Ω
Total fault resistance (RFPP) for Ph-Ph Fault (Zone 1) = Rarc + R1PP
= 0.107+0.02
= 0.13 Ω
Rf is lesser than 160% of the load, we take Rf value,
Maximum allowable Resistive reach for Zone 1 = 6.25 Ω
Our set value should be less than the above value and to get Zone segrication.
Setting of RFPP- Zone 1 = 6.00 Ω

Limit the setting of the zone 2 reach in resistive direction for ph-ph loop measurement
Fault resistance for Ph-Ph fault Rf < 3 * X1Z2
< 3*2.943
< 8.83 Ω
Total fault resistance (RFPP) for Ph-Ph Fault (Zone 2) = Rarc + R2PP
= 0.107+0.028
= 0.13 Ω
Rf is lesser than 160% of the load, we take Rf value,
Maximum allowable Resistive reach for Zone 2 = 8.83 Ω
Our set value should be less than the above value and to get Zone segrication.
Setting of RFPP- Zone 2 = 4.00 Ω

Limit the setting of the zone 3 reach in resistive direction for ph-ph loop measurement
Fault resistance for Ph-Ph fault Rf < 3 * X1Z3
< 3*11.715
< 35.14 Ω
Total fault resistance (RFPP) for Ph-Ph Fault (Zone 3) = Rarc + R3PP
= 0.107+1.867
= 1.97 Ω
Rf is lesser than 160% of the load, we take Rf value,
Maximum allowable Resistive reach for Zone 3 = 35.14 Ω
Our set value should be less than the above value and to get Zone segrication.
Setting of RFPP- Zone 3 = 8.00 Ω

Limit the setting of the zone 5 reach in resistive direction for ph-ph loop measurement
Fault resistance for Ph-Ph fault Rf < 3 * X1Z3
< 3*0.417
< 0.06 Ω
Total fault resistance (RFPP) for Ph-Ph Fault (Zone 5) = Rarc + R3PP
= 0.107+0.004
= 0.11 Ω
Rf is lesser than 160% of the load, we take Rf value,
Maximum allowable Resistive reach for Zone 5 = 0.06 Ω
Our set value should be less than the above value and to get Zone segrication.
Setting of RFPP- Zone 5 = 0.02 Ω

To avoid load encroachment for the phase to phase measuring elements, the set resistive reach of any distance zone must be less
than 160%of the
minimum load impedance.
RFPP = 1.6 * Zload
= 1.6*57.159
= 91.45 Ω

PHASE SELECTION:

It is possible to set the reach of the phase- selection elements to cover with sufficient margin only the protected line and secure tripping of a
correct phase for the faults on the protected line only.

setting instructions:
The phase selection elements need not cover all distance protection zones with in the terminal. The main goal should be a correct
and
realiable phase selection for faults on the entire protected line.

The phase selection measuring elements must always cover the first corresponding overreaching zone (in most application cases :
zone-2)
for different fault loops.
A safety margin between 10% and 15% is recommended.
X1PP > X1PPZm2
> 2.94 Ω
> 3.00 Ω

X0PP > 9.00 Ω

RFPE > 1.1* RFPEZm2

> 1.1x8 Ω
> 9Ω

RFPP > 1.1* RFPPZm2

1.1x4 Ω
4Ω
 POWER SWING DETECTION:
The inner operate characteristic completely covers all distance protection zones, which are supposed to be blocked by
the PSD function. It is
recommended to consider at least 10% of additional safety margin.

X1InFw = 12.89 Ω

R1LIn = 2.05 Ω

R1FInFw = 8.80 Ω

RLdOutFw = KL × RL KL= 0.9

43.73 Ω
kLdRFw = 0.75

BREAKER FAILURE FUNCTION

Set the used principle forback-up tripping, with or without contact resp current checks
FunctionMode = Current

Set the used principle for current check

BUTripMode = 1 Out of 3

Setting of the operating mode for retrip of own breaker

RetripMode = CB Position check

Setting of the operating current level

IP> = 10 %IB

Setting of the operating current level for Neutral current

IN> = 10 %IB

Set the retrip time delay

t1 = 0.06 Sec

Set the back-up trip time delay

t2 = 0.12 Sec

Set the back-up trip time delay for Multi-phase start

t2MPh = 0.12 Sec

Set an additional time delay for a second back-up trip step if used. Will be added to t2 B-u trip time without checks
t3 = 0.03 Sec

Set the length of the trip pulse

tPulse = 0.2 Sec

Set the current level above which the contact base operation (if selected) is blocked
I>BlkCont = 20 %IB

Set the time to alarm for CB faults if input is used

tCBAlarm = 2 Sec

SOTF
Setting of under current
Iph< = 20 %UB
Setting of the U< voltage
Uph< = 70 %UB
Set the required duration of low UI check to achieve operation
tDuration = 0.02 Sec
Set the time during which the fault is considered being a Switch Onto Fault case
tSOTF = 1 Sec
Set the required time for all currents and all voltages to be low to Auto Initiate the SOTF function.
tDLD = 0.2 Sec
Settings Table

DISTANCE PROTECTION:
NAME RECOMMENDED SETTING
General
GlobalBaseSel 1
Setting Group1
Operation On
IMinOpPP 20 %IB
IMinOpPE 20 %IB
IMinOpiN 5 %IB
Line Angle 0 Deg
ZONE-1
NAME RECOMMENDED SETTING
RFPE1 4.00 ohm/l
RFPP1 6.00 ohm/l
Z1 2.08
KNMag1 0.67
KNAng1 0 Deg
OpModetPE1 On
OpModetPP1 On
DirMode1 Forward
tPE1 0.000 s
tPP1 0.000 s
OpMode1 Enable Ph-E PhPh
ZONE-2
NAME RECOMMENDED SETTING
RFPE2 8.00 ohm/l
RFPP2 4.00 ohm/l
Z2 2.94
KNMag2 0.67
KNAng2 0 Deg
OpModetPE2 On
OpModetPP2 On
DirMode2 Forward
tPE2 0.400 s
tPP2 0.400 s
OpMode2 Enable Ph-E PhPh
ZONE-3
NAME RECOMMENDED SETTING
RFPE3 16.00 ohm/l
RFPP3 8.00 ohm/l
Z3 11.86
OpModetPE3 On
OpModetPP3 On
DirMode3 Forward
tPE3 0.800 s
tPP3 0.800 s
OpMode3 Enable Ph-E PhPh
ZONE-5
NAME RECOMMENDED SETTING
RFPE5 0.02 ohm/l
RFPP5 0.40 ohm/l
Z5 0.42
OpModetPE5 On
OpModetPP5 On
DirMode5 Reverse
tPE5 0.500 s
tPP5 0.500 s
OpMode5 Enable Ph-E PhPh
PHASE SELECTION:
NAME RECOMMENDED SETTING
OperationZ< ON
OperationI< OFF
INBlockPP 40.00 %Iph
INReleasePE 20.00 %Iph
RLdFw 43.73 ohm/p
RLdRv 43.73 ohm/p
ArgLd 32.00 0
Iph> 120.00 %IB
IN> 20.00 %IB
X1 3.00 ohm/l
X0 9.00 ohm/l
RFFwPP 4.00 ohm/l
RFRvPP 4.00 ohm/l
RFFwPE 9.00 ohm/l
RFRvPE 9.00 ohm/l
TimerPP Off
tPP 3.00 s
TimerPE Off
tPE 3.00 s
IMinOpPP 10.00 %IB
IMinOpPE 5.00 %IB
POWER SWING DETECTION:
NAME RECOMMENDED SETTING
Operation ON
X1InFw 12.89 ohm
R1LIn 2.05 ohm
R1FInFw 8.80 ohm
X1InRv 12.89 ohm
R1FInRv 8.80 ohm
OperationLdCh ON
RLdOutFw 43.73 ohm
ArgLd 32.00 0
RLdOutRv 43.73 ohm
kLdRFw 0.75 Multi
kLdRRv 0.75 Multi
tP1 0.045 S
tP2 0.015 S
tW 0.25 S
tH 0.50 S
tR1 0.30 S
tR2 0.20 S

BROKEN CONDUCTOR:
NAME RECOMMENDED SETTING
IBase 1600.00 A
Iub> 10.00 % IM
IP> 20.00 % IB
tOper 5.00 s

BREAKER FAILURE:
NAME RECOMMENDED SETTING
Ibase 1600.00 A
FunctionMode Current
BUTripMode 1 Out of 3
RetripMode CB Position check
IP> 10.00 %IB
IN> 10.00 %IB
t1 0.06 sec
t2 0.12 sec
t2MPh 0.12 sec
t3 0.03 sec
tPulse 0.20 sec
I>BlkCont 20.00 %IB
tCBAlarm 2.00 sec
SOTF
NAME RECOMMENDED SETTING
Mode impedance
AutoInit On
Iph< 20.00 % IB
Uph< 70.00 % UB
tDuration 0.02 sec
tSOTF 1.00 sec
tDLD 0.20 sec