HV Protection Relays Setting Calculation Rev-4

HNP

HUBCO

Hubco Narowal Project

P60110-E-PRSC-001

Switch-Yard-System

Status: 2011-02-25

HV Protection Relays Setting Calculation

Prepared by: AREVA

Reviewed by: MAN Diesel & Turbo

Approved by: Owner

Confirmed by: WAPDA

Date:

Date:

Date:

Date:

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HV Protection Relays Setting Calculation

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Rev.4

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P60110-E-PRSC-001

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Table of Content: A.

Protection Relays Setting on 132kV Transformer Relay Panels for Transformer Bays E01, E03, E06, and E08

1. Transformer Differential Protection Relay Settings-MiCOM P631 2. Transformer Backup Overcurrent Protection Relay Settings-MiCOM P122 3. Transformer CB Failure Protection Relay Settings-MiCOM P821 B.

Protection Relays Setting on 132kV Line Relay Panels for Line Bays E07 (132kV NRW2) and E09 (132kV NRW-4).

1. Line Distance Protection Relay Settings-MiCOM P442 2. Line Backup Overcurrent Protection Relay Settings-MiCOM P122 3. Line CB Failure Protection Relay Settings-MiCOM P821 4. Line Synchronism Check Relay Settings-KAVS100 C.

Protection Relays Setting on 132kV Line Relay Panel for Line Bay E02 (132kV Badomali Line BDL-1).

1. Line Distance Protection Relay Settings-MiCOM P442 2. Line Backup Overcurrent Protection Relay Settings-MiCOM P122 3. Line CB Failure Protection Relay Settings-MiCOM P821 4. Line Synchronism Check Relay Settings-KAVS100 D.

Protection Relays Setting on 132kV Relay Panel For Line Bay E04 (132kV NRW-1)

1. Line Distance Protection Relay Settings-MiCOM P442 2. Line Backup Overcurrent Protection Relay Settings-MiCOM P122 3. Line CB Failure Protection Relay Settings-MiCOM P821 4. Line Synchronism Check Relay Settings-KAVS100

HV Protection Relays Setting Calculation

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P60110-E-PRSC-001 E.

Switch-Yard-System

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Protection Relays Setting on 132kV Buscoupler Relay Panel (Bay E05)

1. High Impedance BB Diff. Protection Relay Settings-MFAC34 2. Buswire Supervision Relay Settings-MVTP31 3. Buscoupler Overcurrent Protection Settings-MiCOM P122 4. Buscoupler CB Failure Protection Relay Settings-MiCOM P821 5. Line Synchronism Check Relay Settings-KAVS100

F.

WAPDA reference letters about relay settings recommendation.

1. Letter No. GM(WPPO) CE-IV/7208 Dated 31-05-2010 2. Letter No. GM(WPPO) CE-IV/13827-29 Dated 06-10-2010

Note: Protection Relay Settings on 15kV System are required to be coordinated with given below 132kV Protection Relay Settings.

Comments on Rev-3: 1. Settings are revised after recommended revised settings given by WAPDA in letter Ref# GM(WPPO)/CE-IV/13827-29 for OC &EF relays of Bay E02(Badomali line BDL-1) , E04(Narowal line NRW-1) and Step up Transformer Bays E01,E03,E06 & E08. 2. Settings are revised to correct some typographical mistakes of rev-1, in OC & EF relay settings of Buscoupler Bay. Comments on Rev-4: 1. After meeting with IE of Fichtner GmbH on 25-02-2011, new setting Id>>= 8 x Iref for transformer differential relay MiCOM P631and I>= 1.0 x In with TMS= 0.27 for transformer overcurrent relay MiCOM P122 for all four transformers have been decided.

HV Protection Relays Setting Calculation

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Protection Relays Setting on 132kV Transformer Relay Panels for Transformer Bays E01, E03, E06 and E08.

HV Protection Relays Setting Calculation

4 of 58

Rev.4

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P60110-E-PRSC-001

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1. Transformer Differential Protection Relay: Relay Type (Similar For All 132kV Transformer Bays): MiCOM P631 Make: AREVA Location: 132kV Transformer Relay Panels: =E01+R1, E03+R1, E06+R1, E08+R1. Transformer Data (Similar For All 132kV Transformer Bays) Rated Power (ONAN/ONANF): 50/70MVA Rated Voltage: 132/15KV Rated Current (HV): 218.7/306.2A Rated Current (LV): 1924.5/2694.3A Connection: Star (HV), Delta (LV) Vector Group:YNd5 HV/LV Short Circuit Impedance base on 70MVA: 14% CT Ratios For Differential Protection (Similar For All 132kV Transformer Bays) HV 132kV Transformer Feeder CT : 400/1, 5P20 LV 15kV Transformer Feeder CT: 3000/1, 5P20 Relay Settings (Similar For All 132kV Transformer Bays): MiCOM P631 provides a very fast differential protection function. With automatic CT ratio matching and vector group compensation, makes this relay an ideal solution even for the most demanding applications. The individual reference currents for each winding of the transformer are calculated by P631 on the basis of the set reference power and the set primary nominal voltages of the transformer. Iref,a = Sref/( 3.Vnom,a) = 70MVA/( 3 x 132kV) = 306.2 Amps Iref,a= 306.2 Amps Iref,b = Sref/( 3.Vnom,b) = 70MVA/( 3 x 15kV) = 2694.3 Amps Iref,b= 2694.3 Amps Where: Sref: Reference Power Iref,a,b: reference current of winding a, b. Vnom,a,b: nominal voltage of winding a, b. The P631 calculates the matching factors on the basis of the reference currents and the set nominal currents of the system current transformers. kam,a=Inom,a/Iref,a = 400/306.2 = 1.306 kam,a= 1.306 kam,b=Inom,b/Iref,b = 3000/2694.3 = 1.113 kam,b = 1.113

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Rev.4

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P60110-E-PRSC-001

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Where: kam,a,b: amplitude matching factor of winding a or b. Inom,a,b: primary nominal currents of the main current transformers. Differential Setting: 2) 3) 4) 5) 6) 7)

Idiff> Idiff>> Idiff>>> m1 IR,m2 m2

1) Idiff>: Differential initial setting should be set above the steady-state magnetizing current of the transformer. Unbalance current checking in regarding with the tap changer position on highest (1) and lowest (17) tap positions. Rated HV current at highest tap position = 278.3 A Rated HV current at lowest tap position = 340.2 A Secondary current at highest tap & lowest tap position with selected CT multiplier: At highest tap position with ct multiplier = (278.3/400) x 1.306 = 0.90865 x Iref At lowest tap position with ct multiplier = (340.2/400) x 1.306 = 1.11075 x Iref LV side current = 2694.3 A Secondary LV side current with selected ct multiplier = (2694.3/3000) x 1.113 = 0.99958 x Iref Differential Current on highest and lowest tap position with selected CT Multiplier: Allowing 5% to accommodate ct errors, Differential Current on highest tap position = (0.90865 x 0.95) - (0.99958 x 1.05) = 0.8632-1.0495 = 0.1863 x Iref Differential current on lowest tap position = (1.11075 x 1.05) – (0.99958 x 0.95) = 1.1663-0.9496 = 0.2167 Available setting: 0.1 to 2.5 x Iref ( in steps of 0.01) Hence the selected setting

HV Protection Relays Setting Calculation

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Hubco Narowal Project

P60110-E-PRSC-001

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Idiff> = 0.22 x Iref 2.) Idiff>> This setting is to be set just above the inrush current rms value so that blocking of the triple slope characteristic by second harmonic restraint or by saturation detector is removed. Normally the transformer Inrush current may go from 4-8 times the rated current. Taking 4 times the rated current for calculation, Maximum transformer inrush current = 4 x rated current = 4 x 306.2 = 1225 Amps Corresponding ct secondary current = (1225/400) x 1.306 = 4 x Iref In order to prevent transformer from false tripping which may be possible if inrush current is higher, Setting of 8 x Iref = 2.450 kA is recommended by Independent Engineer ( Fichtner GmbH) , We can verify the setting if { 2-phase min short circuit current )/ Set value} >= 1.5 Generator short circuit current is 4350A, For 3 Generators connected to single bus, we have I gen-sc = 4350A x 3 =13.05kA at 15 kV level. At, 132kV side, Igen-sc= {(13.05 x 15)/132} = 1.482kA Xgen= 132kV/1.732 x 1.482=51.5 ohm Xtrafo=(0.14 x 132kV x 132kV)/70MVA= 34.848 Ohm X total = 51.5 + 34.848 = 86.35 Ohm Therefore , 3-phase short circuit value from 3 generators = 132000/ (1.732 x 86.35)= 0.88kA With all four trafo, we have 3-phase short circuit value = 0.88kA x 4= 3.52 kA Three phase min short circuit current at 132kv side = 7.1 kA ( contribution from Wapda and generators both) Therefore, 7.1-3.52= 3.58kA Two phase short circuit current will be = {(Root3)/2} x 3.58 = 3.1kA Since by exclusive case (the energizing only from the system without any transformer with generators), 3.1kA/ (8xIref) = 3.1kA/2.450kA=1.26 which is less than 1.5 but > 1.2. By operation only one transformer two phase short circuit current will be = {(Root3) x (7.1 – (3 x 0.88)) = 3.88kA Since 3.88kA/(8 x Iref)= 3.88/2.450= 1.58 which is > 1.5 Hence the selected setting has the necessary sensitivity in most possible cases - it is in order Id>> = 8 x Iref

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Rev.4

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HNP Hubco Narowal Project

P60110-E-PRSC-001

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3.) I diff>>> This is a simple instantaneous unrestrained highest differential over current setting. It is not influenced by restraining current (triple slope characteristics), harmonic restraint, overfluxing restraint or saturation detector. Hence for fast fault clearance, Id>>> could be set below the current for a fault at the transformer terminals. Such a fault involves the bus fault level as it is not limited by the winding impedances. This is set greater than the transformer inrush current and below the fault at the transformer terminals. The 3-phase minimum fault current at 132kV side = 7.100kA 2-phase minimum fault current at 132kV side = 7100 x 1.732/2 = 6148 A Iref for Bus fault = (6148/400) x 1.306 = 20.07 x Iref Idiff>>> should be less than 20.07 x Iref. Hence the selected setting Idiff>>> = 8 x Iref 4) m1 This is the second section of the tripping characteristic covers the load current range, so that in this section we must reckon not only with the transformer magnetizing current, which appears as differential current, but also with differential current that can be attributed to the transformation errors of the current transformer sets. The second section of the tripping characteristic forms a straight line, the slope of which should correspond to the cumulative total error of the participating current transformer sets. The curve slope m1 can be set. The differential and restraining current variables for each measurement system are calculated from the current variables after amplitude and vector group matching. The Following equation is used to calculate the differential and restraining current. (Id/Iref) = m1 x (IR/Iref) + (Idiff>/Iref) x (1-0.5 x m1) However the suitability of this setting is verified as below. Differential current on highest and lowest tap position with selected ct multiplier: As calculated above, Differential current on highest tap position = 0.1863 x Iref Differential current on lowest tap position = 0.2167 x Iref Restraining current on highest and lowest tap positions: Restraining current on highest tap position = (0.90865 + 0.99958)/2 = 0.9541 Restarining current on lowest tap position = (1.11075 + 0.99958)/2 = 1.0551 Therefore: For highest tap position: IR = 0.9541 x Iref, & Idiff = 0.1863 x Iref For Lowest tap position: IR = 1.0551 x Iref & Idiff = 0.2167 x Iref Boundary of the operating region is calculated below: With Id> = 0.22 and m1 = 0.2:

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HNP Hubco Narowal Project

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For highest tap position: (Id/Iref) = m1 x (IR/Iref) + (Idiff>/Iref) x (1-0.5 x m1) = 0.2 x 0.9541 + 0.22 x (1- 0.5 x 0.2) = 0.3888 For lowest tap position: (Id/Iref) = m1 x (IR/Iref) + (Idiff>/Iref) x (1-0.5 x m1) = 0.2 x 1.0551 + 0.22 x (1- 0.5 x 0.2) = 0.4090 Therefore: For highest tap position: IR = 0.9541 x Iref, & Idiff = 0.3888 x Iref For Lowest tap position: IR = 1.0551 x Iref & Idiff = 0.4090 x Iref It is clear from above values that the differential current on relay during full load current on highest and lowest tap positions of the transformer is outside the operating region with selected Id>=0.22 and m1= 0.2 Hence the selected setting m1= 0.2 5) IR,m2 This is the second knee point of the tripping characteristic determines the end of the overcurrent zone in the direction of increasing restraining current in fault free operation. It is recommended to set half the maximum through fault current. Max through fault current (Limited by transformer impedance) at lowest tap: Max through fault current = rated current at lowest tap / % imp of trf at lowest tap = 340.2/0.1310 = 2.597kA Corresponding ct secondary current = (2597/400) x 1.306 = 8.479 x Iref Max through fault current (Limited by transformer impedance) at highest tap: Max through fault current = rated current at highest tap / % imp of trf at highest tap = 278.3/0.1445 = 1.926kA Corresponding ct secondary current = (1926/400) x 1.306 = 6.288 x Iref Max through fault current at lowest tap position = 8.479 x Iref Max through fault current at highest tap position = 6.288 x Iref Half the max. through fault current on lowest tap position = 8.479/2 = 4.24 x Iref Half the max. through fault current on highest tap position = 6.288/2 = 3.144x Iref Therefore 4.24 to be set based on half the maximum through fault current. The selected IR,m2 setting IR,m2 = 4.3 x Iref

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HNP Hubco Narowal Project

P60110-E-PRSC-001

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6.) m2 The third slope m2 characteristics are to accommodate ct errors during heavy through fault conditions. There is no specific advantage in setting the slope m2 very closer to the through fault operating conditions. It is desirable to give a safety factor 1.5 for the differential current. Max through fault current at lowest tap position = 8.479 x Iref (as calculated above) Max through fault current at highest tap position = 6.288 x Iref (as calculated above) Max through fault current at highest and lowest tap positions at LV side: LV side through fault current on highest tap position = 1926 x (145.2kV/15kV) = 18.644 kA CT secondary LV through fault current on highest tap= (18644/3000) x 1.113 = 6.917 x Iref LV side through fault current on lowest tap position = 2597 x (118.8kV/15kV) = 20.568 kA CT secondary LV through fault current on lowest tap= (20568/3000) x 1.113 = 7.630 x Iref Differential currents on highest and lowest tap positions: Allowing 5% to accommodate CT errors and assuming worst case. Differential current on highest tap position = (6.288 x 0.95) - (6.917 x 1.05) = 5.973-7.263 = 1.29 x Iref Differential current on highest tap position with safety factor 1.5 = 1.29 x1.5 =1.935 x Iref Differential current on lowest tap position = ( 8.479 x 1.05) – ( 7.630 x 0.95) = 8.903-7.248 = 1.655 x Iref Differential current on lowest tap position with safety factor 1.5 = 1.655 x1.5 = 2.482 x Iref Restraining current on highest and lowest tap positions: Restraining current on highest tap position = (6.288+6.917)/2 = 6.6025 x Iref Restraining current on lowest tap position = (8.479+7.630)/2 = 8.054 x Iref Therefore: For highest tap position: IR = 6.6025 x Iref, & Idiff = 1.935 x Iref For Lowest tap position: IR = 8.054 x Iref & Idiff = 2.482 x Iref The following equation is used to calculate the boundary of the operating region. Id/Iref = m2 x IR/Iref + Idiff>/Iref x (1-0.5 x m1) + (IR,m2/Iref ) x (m1-m2)

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P60110-E-PRSC-001

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Boundary of the operating region is calculated below: With Id> = 0.22 and m1 = 0.2 and m2 = 0.4: For highest tap position: Id/Iref = m2 x IR/Iref + Idiff>/Iref x (1-0.5 x m1) + (IR,m2/Iref ) x (m1-m2) = 0.4 x 6.6025 + 0.22 x (1-0.5 x 0.2) + 3.3 x (0.2-0.4) = 2.179 For lowest tap position: Id/Iref = m2 x IR/Iref + Idiff>/Iref x (1-0.5 x m1) + (IR,m2/Iref ) x (m1-m2) = 0.4 x 8.054 + 0.22 x (1-0.5 x 0.2) + 3.3 x (0.2-0.4) = 2.76 As the boundary is very close to actual operating differential current at max. and minimum tap positions, therefore we take m2=0.5 to recalculate for suitability of setting as given below. With Id> = 0.22 and m1 = 0.2 and m2 = 0.5: For highest tap position: Id/Iref = m2 x IR/Iref + Idiff>/Iref x (1-0.5 x m1) + (IR,m2/Iref ) x (m1-m2) = 0.5 x 6.6025 + 0.22 x (1-0.5 x 0.2) + 3.3 x (0.2-0.5) = 2.509 For lowest tap position: Id/Iref = m2 x IR/Iref + Idiff>/Iref x (1-0.5 x m1) + (IR,m2/Iref ) x (m1-m2) = 0.5 x 8.054 + 0.22 x (1-0.5 x 0.2) + 3.3 x (0.2-0.5) = 3.235 It is clear from above values that the differential current on relay during maximum through fault current on highest and lowest tap positions of the transformer is outside the operating region with selected m2=0.5 Operating region should be away from the differential current region, the slope is set to 0.5. Hence the selected m2 setting m2=0.5 Configuration: 1. Output relay assignment and operating mode configuration (OUTP) - Fct. Assignm. K901: Diff Trip Signal - Fct. Assignm. K902: Diff Trip Signal - Fct. Assignm. K903: Blocked/Faulty - Fct. Assignm. K904: Diff Trip Signal - Fct. Assignm. K905: Diff Trip Signal - Fct. Assignm. K906: Diff Trip Signal - Fct. Assignm. K907: Diff Trip Signal - Fct. Assignm. K908: Without function -Oper.Mode K901: Follower -Oper.Mode K902: Follower Rst on Flt -Oper.Mode K903: Follower Rst on Flt -Oper.Mode K904: Follower -Oper.Mode K905: Follower -Oper.Mode K906: Follower

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-Oper.Mode K907: Follower -Oper.Mode K908: Follower 2. Enabling differential protection (DIFF) -Differential PR (87): Enabled Function Settings: 1. Main Global Settings(MAIN) -Protection Enabled: Yes -User Test Mode: No -Frequency fn: 50Hz -Phase Rotation: A-B-C -In CT. prim., end a: 400A -In CT. prim., end b: 3000A -In Device, end a: 1A -In Device, end b: 1A -CT Orientation Iph, a: Standard -CT Orientation Iph, b: Standard -Minimum Iph Meas’mt: 0.00 In -Minimum I2 Meas’mt: 0.00 In -Minimum I1 Meas’mt: 0.00 In -Minimum IN Meas’mt: 0.00 In -Minimum IY Meas’mt: 0.00 In -Time Const Iph Dem.: 15 min -Fct.Assign.Block1 to 4: Disabled -Trip Cmd. Block USER: No -Fct. Assig Trip Cmd.1 to 3: Differential Trip Signal -Fct. Assig Trip Cmd.4: Manual Trip Signal -tDWELL trip Cmd. 1 to 4: 0.25 sec -Latching trip Cmd. 1 to 4: No -Fct Assign Fault: Disabled 2. Setting group selection(GROUP) -Control via USER: Yes -Setting Grp Sel USER: Setting Group SG1 -Hold Timer: Blocked 3. Main Common Settings (MAIN) -Vn prim., end a: 132kV -Vn prim., end b: 15kV -Hold Time Dyn. Settg. : Blocked 4) Differential Protection Common Settings (DIFF) -General Enable User: Yes -Rated Ref Power Sref: 70MVA -Minimum Id Meas’mt: 0.000 Iref -Minimum IR Meas’mt: 0.000Iref 5) Setting Group SG1 -Enable SG1: Yes -Vec. Gr. Ends b-a: 5 -Idiff>: 0.22 Iref - Idiff>>: 8.0Iref (Revised setting as per recommendation of Independent Engineer of Fichtner GmbH) -Idiff>>>: 8.0 Iref

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-m1: 0.2 -m2: 0.5 -IR, m2: 4.3 Iref -Op. Mode Inrush: Not phase-Selective nd -Inrush 2 Harmon: 20% -I0 filt a Enab: Yes -I0 filt b Enab: No -O/Flux Blk Enab: No -O/Flux 5th Harmon :20% -Op.del.,trip sig: 0.00s -Hyst. Effective: No

HV Protection Relays Setting Calculation

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2. Transformer Backup Overcurrent Protection Settings: Relay Type (Similar For All 132kV Transformer Bays): MiCOM P122, Make: Areva Location: 132kV Transformer Relay Panels: =E01+R1, E03+R1, E06+R1, E08+R1. CT Ratio For Backup O/C Protection (Similar For All 132kV Transformer Bays): HV 132kV Transformer Feeder CT : 400/1, 5P20 Relay Settings( Similar For All 132kV Transformer Bays): MiCOM P122 serves as backup protection for 132kV side transformer winding. The O/C Pickup setting is usually 115% of the maximum overload acceptable. Required phase overcurrent setting I>=1.15 x 306.2 = 352A This is slightly above the maximum current at end tap position of 340.2A. Normal inverse curve is selected. As recommended by independent engineer of Fichner GmbH, setting of 400 A (taking into account the max. possible overload of transformer) is selected. The 132kV-OC protection is set to operate with a delay of about 1.1sec (950ms+150ms) on the maximum through fault current of 2.187kA at 132kv side. The time multiplier setting can be calculated from the formula: Tms =Required trip time ‘t’/ [0.14 / (I/Is)0.02 -1] 0.02 =1.1 / [0.14 / (2187/400) -1] =0.27 The 132kV earth fault stage is set to 20% of the rated transformer current of 306.2A. The 132kV earth fault protection at the transformer neutral is set to operate with a delay of about 1.1 sec ( 950ms+150ms) on the maximum through fault current of 2.187kA at 132kV side. Required earth fault setting Ie>= 20% of 306.2= 0.2 x 306.2= 61A Recommended setting for Ie>= 120A The time multiplier setting can be calculated from the formula: Tms =Required trip time ‘t’/ [0.14 / (I/Is)0.02 -1] 0.02 =1.1/ [0.14 / (2187/120) -1] =0.47 The instantaneous protection is set to 120% of the max 132kV through fault current. Required Instantaneous setting I>>= Ie>>=1.2x2187= 2624A. Since the max. possible contribution from all generators connected to this transformer by fault at the 132 kV side is I gen sum = 0.88 kA < 6.56 x 0.4 = 2.624 kA, this stage of overcurrent protection is selective with all line protections.

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The time delay of 0.1 sec stabilizes the I>> stage against any kind of transient phenomena. Definite time curve is selected. [50/51] Phase OC Setting: I> = YES I> = 400/400= 1.0 x In (Revised setting as per recommendation of Independent Engineer of Fichtner GmbH) Delay Type = IDMT Curve = Standard Inverse Time Multiplier = 0.27 (Revised time multiplier setting due to chane in I> setting above) t Reset=60 ms I>>=Yes I>> =2624/400= 6.56xIn Delay Type= DMT Curve: DT Time Delay: 0.1 sec I>>>= Not Enable [50N/51N] E/Gnd OC Setting: le >=YES le >=120/400=0.3 x In (Revised setting as per WAPDA Lettter GM(WPPO)/CE-IV/13827-29 Dated 06-

10-2010)

Delay Type=IDMT Curve = Standard Inverse Time Multiplier= 0.47 (Revised setting as per WAPDA Lettter GM(WPPO)/CE-IV/13827-29 Dated 06-

10-2010)

t Reset=60 ms Ie>>=Yes Ie>> =2624/400= 6.56xIn Delay Type= DMT Curve: DT Time Delay: 0.1 sec Ie>>>= Not Enable

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3. Transformer Circuit Breaker Failure Protection Settings: Relay Type (Similar For All 132kV Transformer Bays): MiCOM P821, Make: Areva Location: 132kV Transformer Relay Panels: =E01+R1, E03+R1, E06+R1, E08+R1. CT Ratio For CB Failure Protection (Similar For All 132kV Transformer Bays): HV 132kV Transformer Feeder CT : 400/1, 5P20 Relay Settings (Similar For All 132kV Transformer Bays): CB FAIL FUNCT : YES Description: Enable/Disable the Circuit Breaker Failure protection. CB FAIL PHASE: YES Description: Enable/Disable the Circuit Breaker Failure protection by phase. I> BF: 0.5 x In Description: Select the phase current threshold. CB FAIL EARTH:YES Description: Enable/Disable the Circuit Breaker Failure protection on earth. Ie> BF: 0.15 x In Description: Select the earth current threshold. Delay Stage1: 150 ms Description: Set the retrip delay. Delay Stage2: 280 ms Description: Set the general back-trip delay. External Reset: YES Description: Reset configuration of tBF1 after drop off of the external tripping.

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B.

Switch-Yard-System

Status: 2011-02-25

Protection Relays Setting on 132kV Line Relay Panels for Line Bays E07 (132kV NRW-2) and E09 (132kV NRW-4).

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Switch-Yard-System

Status: 2011-02-25

1. Line Distance Protection Settings: Relay Type (Similar For Both Line Bays): MiCOM P442, Make: Areva Location: 132kV Line Relay Panels: =E07+R1 and =E09+R1 System and Line Data (Similar For Both Line Bays): Transmission Line: 132kV NRW-2 and NRW-4 System Voltage: 132KV, 50Hz CT Ratio: 1200/1 VT Ratio: (132KV/1.732)/(110V/1.732) Fault Levels: At HUBCO Narowal: Max KA= 9.7, Min KA=7.1 At Narowal Grid Station: Max KA= 8.9, Min KA= 6.6 Line Length: 10.422 KM, on Rail conductor Line Impedance: Positive Sequence ZL1 = (0.06+j0.3921) Ohm/Km Zero Sequence ZL0 = (0.2461+j1.1248) Ohm/Km Rated current carrying capacity of each line = 884A Opposite End Grid Station Shortest and Longest Lines Data: Shortest Line: 10.422Km, Rail conductor (132kV HUBCO to 132kV Narowal) Longest Line: 36Km, Lynx conductor (132kV Narowal to 132kV Shakargarh) T/L Conductor data at ambient temperature: Lynx conductor: Positive Seq. Impedance: Zero Seq. Impedance:

R1+jX1= 0.1583+j0.4004 Ohms/Km R0+jX0= 0.3246+j1.228 Ohms/Km

Rail conductor: Positive Seq. Impedance: Zero Seq. Impedance:

R1+jX1= 0.06+j0.3921 Ohms/Km R0+jX0= 0.2461+j1.1248 Ohms/Km

Distance Zone Reach Calculation (Similar For Both Line Bays): The distance zone reach is determined according to the following principles: -Zone 1: 85% of impedance of protected line and trips independently with 0s delay. -Zone 2: Impedance of protected line + 50% of impedance of adjacent shortest T/L and trip delay time 350ms delay. -Zone 3: Impedance of protected line + 120% of impedance of adjacent longest T/L and trip delay time 700ms delay.

HV Protection Relays Setting Calculation

18 of 58

Rev.4

HNP

HUBCO

Hubco Narowal Project

P60110-E-PRSC-001

Switch-Yard-System

Status: 2011-02-25

1. Line Impedance: Ratio of secondary to primary impedance = (1200/1)/{(132000/1.732)/(110/1.732)}=1 Line impedance ZL1= 10.422 x (0.06+j0.3921) = 0.6253+j4.0864 ZL1= 4.134= 1.3 x In = 1560A (primary) Recommended earth fault setting Ie>= 0.07 x In = 84A (primary) (Note: WAPDA again revised in letter ref# GM(WPPO)/CE-IV/13827-29 , earth fault setting as 120A for all other line bays and transformer bays, therefore recommended setting for earth fault is 120A.) Overcurrent operation time should be greater than zone-3 operation time (i.e. 700ms) of distance protection relay. For definite time o/c, the proposed setting is 800msec. (i.e 100ms is added to backup o/c time to coordinate with zone-3 operating time of 700ms). [50/51] Phase OC Setting: I> = YES I> = 1560/1200= 1.3 x In Delay Type = DMT Curve = DT Time Delay= 0.8s t Reset=60 ms I>> =Not Enable I>>>= Not Enable [50N/51N] E/Gnd OC Setting: le >=YES le >=120/1200=0.1 x In ( Revised as per Wapda recommendations for other line and trafo bays letter ref# GM(WPPO)/CE-IV/13827-29) Delay Type=DMT Curve = DT Time Delay= 0.8s t Reset=60 ms Ie>> =Not Enable Ie>>>= Not Enable

HV Protection Relays Setting Calculation

23 of 58

Rev.4

HNP

HUBCO

Hubco Narowal Project

P60110-E-PRSC-001

Switch-Yard-System

Status: 2011-02-25

3. Line Circuit Breaker Failure Protection Settings: Relay Type (Similar For Both Line Bays): MiCOM P821, Make: Areva Location: 132kV Line Relay Panels: =E07+R1 and E09+R1 CT Ratio For CB Failure Protection (Similar For Both Line Bays): 1200/1 Relay Settings (Similar For Both Line Bays): CB FAIL FUNCT : YES Description: Enable/Disable the Circuit Breaker Failure protection. CB FAIL PHASE: YES Description: Enable/Disable the Circuit Breaker Failure protection by phase. I> BF: 0.5 x In Description: Select the phase current threshold. CB FAIL EARTH:YES Description: Enable/Disable the Circuit Breaker Failure protection on earth. Ie> BF: 0.15 x In Description: Select the earth current threshold. Delay Stage1: 150 ms Description: Set the retrip delay. Delay Stage2: 280 ms Description: Set the general back-trip delay. External Reset: YES Description: Reset configuration of tBF1 after drop off of the external tripping.

HV Protection Relays Setting Calculation

24 of 58

Rev.4

HNP

HUBCO

Hubco Narowal Project

P60110-E-PRSC-001

Switch-Yard-System

Status: 2011-02-25

4. Line Synchronism Check Relay Settings: Relay Type (Similar For Both Line Bays): KAVS100, Make: Areva Location: 132kV Line Relay Panel: =E07+R1, and =E09+R1 System Data (Similar For Both Line Bays): System Voltage: 132kV, 50Hz Line VT Ratio: (132kV/1.732)/(110V/1.732) Bus VT Ratio: (132kV/1.732)/(110V/1.732) Relay Settings (Similar For Both Line Bays): Check Synchronism Settings (CSS) -CSS V.T. Ratio= 132000: 110 -CSS Phase Angle=20° -CSS Slip Freq.= 50mHz -CSS Synch. Timer=1 Second -CSS Split Angle=170° -CSS Split Timer=1 Second -CSS System Angle=20° -CSS System Slip Freq.= 50mHz -CSS System Timer=1 Second -CSS V.B/L Live= 32V -CSS V.B/L Dead= 13V -CSS Under voltage= 80V -CSS Diff. Voltage= 5V

HV Protection Relays Setting Calculation

25 of 58

Rev.4

HNP

HUBCO

Hubco Narowal Project

P60110-E-PRSC-001

C.

Switch-Yard-System

Status: 2011-02-25

Protection Relays Setting on 132kV Line Relay Panel for Line Bay E02 (132kV Badomali Line BDL-1).

HV Protection Relays Setting Calculation

26 of 58

Rev.4

HNP

HUBCO

Hubco Narowal Project

P60110-E-PRSC-001

Switch-Yard-System

Status: 2011-02-25

1. Line Distance Protection Settings: Relay Type: MiCOM P442, Make: AREVA Location: 132kV Relay Panel: = E02+R1 System Data: Transmission Line: 132kV Badomali BDL-1 System Voltage: 132kV, 50Hz CT Ratio: 1200/1 VT Ratio: (132kV/1.732)/(110V/1.732) Fault Levels at HUBCO Narowal: Max kA= 9.7, Min kA=7.1 Fault Levels at Badomali Grid Stn: Max kA=7.3, Min kA=4.3 Line Length: 11.7 KM on Lynx conductor Line Impedance: Positive Sequence ZL1 = (0.1583+j0.4004)Ohm/Km Zero Sequence ZL0 = (0.3246+j1.228)Ohm/Km Rated current carrying capacity of the line = 488A Opposite End Grid Station Shortest and Longest Lines Data: Shortest Line: 21Km, Lynx conductor (132kV Badho Mali to 132kV Narang) Longest Line: 21Km, Lynx conductor (132kV Badho Mali to 132kV Narang) T/L Conductor data at ambient temperature: Lynx conductor: Positive Seq. Impedance: Zero Seq. Impedance:

R1+jX1= 0.1583+j0.4004 Ohms/Km R0+jX0= 0.3246+j1.228 Ohms/Km

Rail conductor: Positive Seq. Impedance: Zero Seq. Impedance:

R1+jX1= 0.06+j0.3921 Ohms/Km R0+jX0= 0.2461+j1.1248 Ohms/Km

Distance Zone Reach Calculation : The distance zone reach is determined according to the following principles: -Zone 1: 85% of impedance of protected line and trips independently with 0s delay. -Zone 2: Impedance of protected line + 50% of impedance of adjacent shortest T/L and trip delay time 350ms delay. -Zone 3: Impedance of protected line + 120% of impedance of adjacent longest T/L and trip delay time 700ms delay.

HV Protection Relays Setting Calculation

27 of 58

Rev.4

HNP

HUBCO

Hubco Narowal Project

P60110-E-PRSC-001

Switch-Yard-System

Status: 2011-02-25

1. Line Impedance: Ratio of secondary to primary impedance = (1200/1)/{(132000/1.732)/(110/1.732)}=1 Line impedance ZL1= 11.7 x (0.1583+j0.4004)= 1.8521+j4.6847 ZL1= 5.037= 0.8 x In = 960A Recommended earth fault setting Ie>= 0.1 x In = 120 A Overcurrent operation time should be greater than zone-3 operation time (i.e. 700ms) of distance protection relay. For definite time o/c, the proposed setting is 800msec. (i.e 100ms is added to backup o/c time to coordinate with zone-3 operating time of 700ms). [50/51] Phase OC Setting: I> = YES I> = 960/1200= 0.8 x In (Revised setting as per WAPDA Lettter GM(WPPO)/CE-IV/13827-29 Dated 06-

10-2010)

Delay Type = DMT Curve = DT Time Delay= 0.8s t Reset=60 ms I>> =Not Enable I>>>= Not Enable [50N/51N] E/Gnd OC Setting: le >=YES le >=120/1200=0.1 x In (Revised setting as per WAPDA Lettter GM(WPPO)/CE-IV/13827-29 Dated 06-

10-2010)

Delay Type=DMT Curve = DT Time Delay= 0.8s t Reset=60 ms Ie>> =Not Enable Ie>>>= Not Enable

HV Protection Relays Setting Calculation

32 of 58

Rev.4

HNP

HUBCO

Hubco Narowal Project

P60110-E-PRSC-001

Switch-Yard-System

Status: 2011-02-25

3. Line Circuit Breaker Failure Protection Settings: Relay Type: MiCOM P821, Make: Areva Location: 132kV Line Relay Panel: = E02+R1 CT Ratio: 1200/1 Relay Settings: CB FAIL FUNCT : YES Description: Enable/Disable the Circuit Breaker Failure protection. CB FAIL PHASE: YES Description: Enable/Disable the Circuit Breaker Failure protection by phase. I> BF: 0.5 x In Description: Select the phase current threshold. CB FAIL EARTH:YES Description: Enable/Disable the Circuit Breaker Failure protection on earth. Ie> BF: 0.15 x In Description: Select the earth current threshold. Delay Stage1: 150 ms Description: Set the retrip delay. Delay Stage2: 280 ms Description: Set the general back-trip delay. External Reset: YES Description: Reset configuration of tBF1 after drop off of the external tripping.

HV Protection Relays Setting Calculation

33 of 58

Rev.4

HNP

HUBCO

Hubco Narowal Project

P60110-E-PRSC-001

Switch-Yard-System

Status: 2011-02-25

4. Line Synchronism Check Relay Settings: Relay Type: KAVS100, Make: Areva Location: 132kV Line Relay Panel: = E02+R1 System Data: System Voltage: 132kV, 50Hz Line VT Ratio: (132kV/1.732)/(110V/1.732) Bus VT Ratio: (132kV/1.732)/(110V/1.732) Relay Settings: Check Synchronism Settings (CSS) -CSS V.T. Ratio= 132000: 110 -CSS Phase Angle=20° -CSS Slip Freq.= 50mHz -CSS Synch. Timer=1 Second -CSS Split Angle=170° -CSS Split Timer=1 Second -CSS System Angle=20° -CSS System Slip Freq.= 50mHz -CSS System Timer=1 Second -CSS V.B/L Live= 32V -CSS V.B/L Dead= 13V -CSS Under voltage= 80V -CSS Diff. Voltage= 5V

HV Protection Relays Setting Calculation

34 of 58

Rev.4

HNP

HUBCO

Hubco Narowal Project

P60110-E-PRSC-001

D.

Switch-Yard-System

Status: 2011-02-25

Protection Relays Setting on 132kV Relay Panel for Line Bay E04(132kV NRW-1).

HV Protection Relays Setting Calculation

35 of 58

Rev.4

HNP

HUBCO

Hubco Narowal Project

P60110-E-PRSC-001

Switch-Yard-System

Status: 2011-02-25

1. Line Distance Protection Settings: Relay Type: MiCOM P442, Make: AREVA Location: 132kV Relay Panel: = E04+R1 System Data: Transmission Line: 132kV Narowal NRW-1 System Voltage: 132kV, 50Hz CT Ratio: 1200/1 VT Ratio: (132kV/1.732)/(110V/1.732) Fault Levels: At HUBCO Narowal: Max KA= 9.7, Min KA=7.1 At Narowal Grid Station: Max KA= 8.9, Min KA= 6.6 Line Length: 10.50 KM on Lynx conductor Line Impedance: Positive Sequence ZL1 = (0.1583+j0.4004)Ohm/Km Zero Sequence ZL0 = (0.3246+j1.228)Ohm/Km Rated current carrying capacity of the line = 488A Opposite End Grid Station Shortest and Longest Lines Data: Shortest Line: 10.422Km, Rail conductor (132kV HUBCO to 132kV Narowal) Longest Line: 36Km, Lynx conductor (132kV Narowal to 132kV Shakargarh) T/L Conductor data at ambient temperature: Lynx conductor: Positive Seq. Impedance: Zero Seq. Impedance:

R1+jX1= 0.1583+j0.4004 Ohms/Km R0+jX0= 0.3246+j1.228 Ohms/Km

Rail conductor: Positive Seq. Impedance: Zero Seq. Impedance:

R1+jX1= 0.06+j0.3921 Ohms/Km R0+jX0= 0.2461+j1.1248 Ohms/Km

Distance Zone Reach Calculation : The distance zone reach is determined according to the following principles: -Zone 1: 85% of impedance of protected line and trips independently with 0s delay. -Zone 2: Impedance of protected line + 50% of impedance of adjacent shortest T/L and trip delay time 350ms delay. -Zone 3: Impedance of protected line + 120% of impedance of adjacent longest T/L and trip delay time 700ms delay.

HV Protection Relays Setting Calculation

36 of 58

Rev.4

HNP

HUBCO

Hubco Narowal Project

P60110-E-PRSC-001

Switch-Yard-System

Status: 2011-02-25

1. Line Impedance: Ratio of secondary to primary impedance = (1200/1)/{(132000/1.732)/(110/1.732)}=1 Line impedance ZL1= 10.500 x (0.1583+j0.4004)= 1.6621+j4.2042 ZL1= 4.521= 0.8 x In = 960A Recommended earth fault setting Ie>= 0.1 x In = 120A Overcurrent operation time should be greater than zone-3 operation time (i.e. 700ms) of distance protection relay. For definite time o/c, the proposed setting is 800msec. (i.e 100ms is added to backup o/c time to coordinate with zone-3 operating time of 700ms). [50/51] Phase OC Setting: I> = YES I> = 960/1200= 0.8 x In (Revised setting as per WAPDA Lettter GM(WPPO)/CE-IV/13827-29 Dated 06-

10-2010)

Delay Type = DMT Curve = DT Time Delay= 0.8s t Reset=60 ms I>> =Not Enable I>>>= Not Enable [50N/51N] E/Gnd OC Setting: le >=YES le >=120/1200=0.1 x In (Revised setting as per WAPDA Lettter GM(WPPO)/CE-IV/13827-29 Dated 06-

10-2010)

Delay Type=DMT Curve = DT Time Delay= 0.8s t Reset=60 ms Ie>> =Not Enable Ie>>>= Not Enable

HV Protection Relays Setting Calculation

41 of 58

Rev.4

HNP

HUBCO

Hubco Narowal Project

P60110-E-PRSC-001

Switch-Yard-System

Status: 2011-02-25

3. Line Circuit Breaker Failure Protection Settings: Relay Type: MiCOM P821, Make: Areva Location: 132kV Line Relay Panel: = E04+R1 CT Ratio: 1200/1 Relay Settings: CB FAIL FUNCT : YES Description: Enable/Disable the Circuit Breaker Failure protection. CB FAIL PHASE: YES Description: Enable/Disable the Circuit Breaker Failure protection by phase. I> BF: 0.5 x In Description: Select the phase current threshold. CB FAIL EARTH:YES Description: Enable/Disable the Circuit Breaker Failure protection on earth. Ie> BF: 0.15 x In Description: Select the earth current threshold. Delay Stage1: 150 ms Description: Set the retrip delay. Delay Stage2: 280 ms Description: Set the general back-trip delay. External Reset: YES Description: Reset configuration of tBF1 after drop off of the external tripping.

HV Protection Relays Setting Calculation

42 of 58

Rev.4

HNP

HUBCO

Hubco Narowal Project

P60110-E-PRSC-001

Switch-Yard-System

Status: 2011-02-25

4. Line Synchronism Check Relay Settings: Relay Type: KAVS100, Make: Areva Location: 132kV Line Relay Panel: = E04+R1 System Data: System Voltage: 132kV, 50Hz Line VT Ratio: (132kV/1.732)/(110V/1.732) Bus VT Ratio: (132kV/1.732)/(110V/1.732) Relay Settings: Check Synchronism Settings (CSS) -CSS V.T. Ratio= 132000: 110 -CSS Phase Angle=20° -CSS Slip Freq.= 50mHz -CSS Synch. Timer=1 Second -CSS Split Angle=170° -CSS Split Timer=1 Second -CSS System Angle=20° -CSS System Slip Freq.= 50mHz -CSS System Timer=1 Second -CSS V.B/L Live= 32V -CSS V.B/L Dead= 13V -CSS Under voltage= 80V -CSS Diff. Voltage= 5V

HV Protection Relays Setting Calculation

43 of 58

Rev.4

HNP

HUBCO

Hubco Narowal Project

P60110-E-PRSC-001

E.

Switch-Yard-System

Status: 2011-02-25

Protection Relays Setting on 132kV Buscoupler Relay Panel for Buscoupler Bay E05.

HV Protection Relays Setting Calculation

44 of 58

Rev.4

HNP

HUBCO

Hubco Narowal Project

P60110-E-PRSC-001

Switch-Yard-System

Status: 2011-02-25

1. High Impedance Differential Protection of 132kV Busbar: Relay Type: 3-Nos. MFAC34, Make: Areva Location: 132kV Buscoupler Relay Panel: = E05+R1 System Data: System Voltage: 132kV, 50Hz Busbar Current Rating: 1600A, 40kA/1sec Fault Levels at HUBCO Narowal: Max KA= 9.7, Min KA=7.1 CT ratios of all bays for Busbar Protection: 2400/1 CT secondary winding resistance:

14 Ohm

CT Knee Point Voltage: Approx. 800Volts CT Exciting current at 75Volt: Approx 3mA (approximated from curve) Cable size used for CT secondary circuit: 6mm2 Lead length: Approx 200M Lead resistance: 3.685 Ohm/Km = 0.737 Ohm Relay Settings: (Applicable For Discriminating Zone-1, Zone-2 and Check Zone Relay): MFAC34 is a voltage operated relay having seven equally spaced settings which may be selected by means of a plug bridge. The relay may be used for any type of high impedance circulating current protection. As per scheme, there are 2-discriminating zones for bus-1 and bus-2 and a check zone. Discriminating Feature: Relay voltage setting = (Fault current/CT Ratio ) x ( Rct + 2x Rlead) = {9.7kA / (2400/1)} x (14 + 2 x 0.737) = 62.54Volts The relay plug setting voltage VR must be set to the nearest tap above this value. The available tap is 75 volt. Therefore: VR= 75 volts Knee point voltage of the current transformers should not be less than twice the relay setting voltage. VK

2 VR

HV Protection Relays Setting Calculation

45 of 58

Rev.4

HNP

HUBCO

Hubco Narowal Project

P60110-E-PRSC-001 VK

2 x 75

VK

150 volts

Switch-Yard-System

Status: 2011-02-25

Therefore current transformers VK of approx. 800 volts is OK. The primary current for relay operation is given by: Ip = CT Ratio (IRelay + n IE ) Where, n = max. number of current transformers in parallel with the relay = 9 IE = ct exciting current at relay setting voltage = approx 3mA at 75volts Therefore: Ip = 2400 ( 0.019 + 9 x 0.003) Ip = 110 Amps It is desirable that the primary effective setting should not exceed 30% of the minimum fault current i.e. 30% of 7.1KA= 2130Amps. Where 30% of the minimum fault current is more than the full load current of the largest circuit, the primary operating current should be made more than the full load current i.e 130% of the full load current. Taking full load current of single 70MVA transformer =306 Amps The primary operating current = 1.3 x 306 = 398 Amps Since the resultant value of ‘Ip=110 Amps’ is too low, it may be increased by the addition of a shunt resistor RSH to give a current of Taking: RSH = 625 ISH = VR / RSH = 75 volts/625

= 0.12 Amps

Therefore the new increased value of primary current: Ip = CT Ratio (IRelay + n IE + ISH) Ip = 2400 {0.019 + 9(0.003) + 0.12}=398 Amps Each MFAC relay is applied with an external metrosil which must be wired across the relay circuit. This provides a shunt circuit for high internal fault currents and prevents a high voltage being developed across the CT and relay circuits.

HV Protection Relays Setting Calculation

46 of 58

Rev.4

HUBCO

HNP Hubco Narowal Project

P60110-E-PRSC-001

Switch-Yard-System

Status: 2011-02-25

Check Feature: Relay setting Voltage VR= 75 volts No. of ct circuits = 8 Relay Current IRelay = 19mA Therefore Primary Operating Current = Ip = 2400 ( 0.019 + 8 x 0.003) = 103A As the difference in number of parallel circuit for check and discrimination zone is not significant, therefore same value of RSH = 625 is taken for increased operating value of primary current. RSH = 625

HV Protection Relays Setting Calculation

47 of 58

Rev.4

HNP

HUBCO

Hubco Narowal Project

P60110-E-PRSC-001

Switch-Yard-System

Status: 2011-02-25

2. Supervision Relay For High Impedance Type Busbar Protection Scheme Relay Type: MVTP31, Make: Areva Location: 132kV Buscoupler Relay Panel: = E05+R1 Relay Settings: (Applicable For Discriminating Zone-1 and Zone-2 ‘MVTP31’ Relays): The MVTP31 provides continuous supervision of buswires in high impedance type busbar protection schemes. Open circuit connections between CT’s and relay circuit result in unbalance currents which may operate the protection. Supervision is applied by a voltage relay across differential relay circuit. MVTP relays have setting rang 1-16V, in one volt steps, and a fixed operating time of 3-seconds. Voltage setting of Supervision Relay VSP= I x {(R x Zm)/(R + Zm)} Where, I= Supervision Operating Current R= Resistance of High Impedance Relay Zm= Parallel impedance of CT magnetizing impedances assuming 1 CT is open circuit. Whenever possible, the supervision primary operating current should not be more than 25Amps primary or 10% of the smallest circuit, whichever is greater. Assuming I = 25A At 75 volt, the magnetizing current of ct is approx. = 3mA. Assuming one ct is open circuit out of 9, the magnetizing impedance will be: ... Zm= (75/0.003)/8= 25000

/8= 3125

At 75 volt setting, relay operating current is 19mA. ... R= 75/.019= 3947 Hence, VSP= I x {(R x Zm)/(R + Zm)} = (25/2400) x {(3947 x 3125)/(3947+3125)} = 18 volt As the maximum available setting is 16volt, therefore: Voltage Setting of Supervision Relay VSP= 16 Volt. Operating current at 16 volt will be, I= 16/{(3947 x 3125)/(3947+3125)} x 2400 I= 22 amps primary

HV Protection Relays Setting Calculation

48 of 58

Rev.4

HNP

HUBCO

Hubco Narowal Project

P60110-E-PRSC-001

Switch-Yard-System

Status: 2011-02-25

3. Buscoupler Overcurrent Protection Settings: Relay Type: MiCOM P122, Make: Areva Location: 132kV Buscoupler Relay Panel: = E05+R1 CT Ratio: 1200/1 Relay Settings: Recommended setting for I> = 1.6 x In = 1920A Recommended setting for Ie> = 0.075 x In = 90A A 150ms delay at maximum current should be allowed for an instantaneous line protective relay to actuate and a line circuit breaker to trip and to allow margin for uncertainty. Therefore the proposed setting for time delay is: tI> = 800ms +150ms = 950ms [50/51] Phase OC Setting: I> = YES I> = 1920/1200 = 1.6 x In ( This setting is in accordance with WAPDA letter ref. GM(WPPO)/CE-IV/7208

Dated 31-05-2010. It was mistakenly wrongly typed in revision-1 and has been corrected now in rev-2.)

Delay Type = DMT Curve = DT Time Delay= 950ms ( This setting is in accordance with WAPDA letter ref. GM(WPPO)/CE-IV/7208 Dated

31-05-2010. It was mistakenly wrongly typed in revision-1 and has been corrected now in rev-2.) t Reset=60 ms I>> =Not Enable I>>>= Not Enable

[50N/51N] E/Gnd OC Setting: le >=YES le >=90/1200=0.075 x In ( This setting is in accordance with WAPDA letter ref. GM(WPPO)/CE-IV/7208

Dated 31-05-2010. It was mistakenly wrongly typed in revision-1 and has been corrected now in rev-2.)

Delay Type=DMT Curve = DT Time Delay= 950ms ( This setting is in accordance with WAPDA letter ref. GM(WPPO)/CE-IV/7208 Dated

31-05-2010. It was mistakenly wrongly typed in revision-1 and has been corrected now in rev-2.) t Reset=60 ms Ie>> =Not Enable Ie>>>= Not Enable

HV Protection Relays Setting Calculation

49 of 58

Rev.4

HNP

HUBCO

Hubco Narowal Project

P60110-E-PRSC-001

Switch-Yard-System

Status: 2011-02-25

4. Buscoupler Circuit Breaker Failure Protection Settings: Relay Type: MiCOM P821, Make: Areva Location: 132kV Buscoupler Relay Control Panel: =E05+R1 CT Ratio: 1200/1 Relay Settings: CB FAIL FUNCT : YES Description: Enable/Disable the Circuit Breaker Failure protection. CB FAIL PHASE: YES Description: Enable/Disable the Circuit Breaker Failure protection by phase. I> BF: 0.5 x In Description: Select the phase current threshold. CB FAIL EARTH:YES Description: Enable/Disable the Circuit Breaker Failure protection on earth. Ie> BF: 0.15 x In Description: Select the earth current threshold. Delay Stage1: 150 ms Description: Set the retrip delay. Delay Stage2: 280 ms Description: Set the general back-trip delay. External Reset: YES Description: Reset configuration of tBF1 after drop off of the external tripping.

HV Protection Relays Setting Calculation

50 of 58

Rev.4

HNP

HUBCO

Hubco Narowal Project

P60110-E-PRSC-001

Switch-Yard-System

Status: 2011-02-25

5. Buscoupler Synchronism Check Relay Settings: Relay Type: KAVS100, Make: Areva Location: 132kV Buscoupler Relay Control Panel: = E05+R1 System Data: System Voltage: 132kV, 50Hz Line VT Ratio: (132kV/1.732)/(110V/1.732) Bus VT Ratio: (132kV/1.732)/(110V/1.732) Relay Settings: Check Synchronism Settings (CSS) -CSS V.T. Ratio= 132000: 110 -CSS Phase Angle=20° -CSS Slip Freq.= 50mHz -CSS Synch. Timer=1 Second -CSS Split Angle=170° -CSS Split Timer=1 Second -CSS System Angle=20° -CSS System Slip Freq.= 50mHz -CSS System Timer=1 Second -CSS V.B/L Live= 32V -CSS V.B/L Dead= 13V -CSS Under voltage= 80V -CSS Diff. Voltage= 5V

HV Protection Relays Setting Calculation

51 of 58

Rev.4

HNP

HUBCO

Hubco Narowal Project

P60110-E-PRSC-001

F.

Switch-Yard-System

Status: 2011-02-25

WAPDA reference letters about relay settings recommendation.

HV Protection Relays Setting Calculation

52 of 58

Rev.4

HUBCO

HNP Hubco Narowal Project

P60110-E-PRSC-001

Switch-Yard-System

Status: 2011-02-25

1. Letter No. GM(WPPO) CE-IV/7208 Dated 31-05-2010

HV Protection Relays Setting Calculation

53 of 58

Rev.4

HUBCO

HNP Hubco Narowal Project

P60110-E-PRSC-001

HV Protection Relays Setting Calculation

Switch-Yard-System

54 of 58

Status: 2011-02-25

Rev.4

HUBCO

HNP Hubco Narowal Project

P60110-E-PRSC-001

HV Protection Relays Setting Calculation

Switch-Yard-System

55 of 58

Status: 2011-02-25

Rev.4

HUBCO

HNP Hubco Narowal Project

P60110-E-PRSC-001 2.

Switch-Yard-System

Status: 2011-02-25

Letter No. GM(WPPO) CE-IV/13827-29 Dated 06-10-2010

HV Protection Relays Setting Calculation

56 of 58

Rev.4

HUBCO

HNP Hubco Narowal Project

P60110-E-PRSC-001

HV Protection Relays Setting Calculation

Switch-Yard-System

57 of 58

Status: 2011-02-25

Rev.4

HUBCO

HNP Hubco Narowal Project

P60110-E-PRSC-001

HV Protection Relays Setting Calculation

Switch-Yard-System

58 of 58

Status: 2011-02-25

Rev.4