Relay Setting Calculation rev.1.pdf

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DOCUMENT TITLE:

PRD CHKD APPD

NAME MWB MWB RSR SIZE

DATE 24-Feb-16 27-Feb-16 29-Feb-16 A4

DEC PROJECT NO NO. OF SHEETS (Incl. Title Sht.)

1 of 36

Relay setting calculations for the primary substation and Remote end grid stations

REVISION NO. 1 DOC NO:

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INDEX

S.NO TITLE PAGE NO.

1.0 OBJECTIVE 3

2.0 CONSIDERATIONS AND ASSUMPTIONS 3 3.0 RELAY SETTING CALCULATION OF RUSAIL -09 PRIMARY SUBSTATION 5

3.1 415 V MCCB SETTING 5

3.2 PHASE OVER CURRENT & EARTH FAULT PROTECTION OF 500KVA, 11/0.416 KV AUX. _{TRASFORMER FEEDER} 6 3.3 PHASE OVER CURRENT & EARTH FAULT PROTECTION OF 11KV SWITCHGEAR CAPACITOR

BANK FEEDERS 8

3.4 PHASE OVER CURRENT & EARTH FAULT PROTECTION OF 11KV SWITCHGEAR OUTGOING _{POWER FEEDERS} 10 3.5 PHASE OVER CURRENT & EARTH FAULT PROTECTION OF 11KV BUS COUPLER 12 3.6 STAND-BY EARTH FAULT PROTECTION OF 33/11KV TRANSFORMER 14 3.7 DIRECTIONAL PHASE OVER CURRENT & EARTH FAULT PROTECTION OF 11KV _{SWITCHGEAR INCOMER} 15 3.8 RESTRICTED EARTH FAULT PROTECTION OF 33/11KV , 20 MVA TRANSFORMER 18 3.9 TRANSFORMER DIFFERENTIAL PROTECTION (87T) OF 33/11KV, 20MVA TRANSFORMER 22 3.10 PHASE OVER CURRENT & EARTH FAULT PROTECTION OF 20MVA, 33/11KV _{TRANSFORMER FEEDER} 27 3.11 PHASE OVER CURRENT & EARTH FAULT PROTECTION OF 33KV BUS COUPLER 29 3.12 DIRECTIONAL PHASE OVER CURRENT & EARTH FAULT PROTECTION OF 33KV _{SWITCHGEAR INCOMER FEEDER} 31 3.13 LINE DIFFERENTIAL PROTECTION OF RUSAIL -02 33KV INCOMER(S) FROM RUSAIL GSS 34 4.0 ANNEXURE -1 : OVER CURRENT PROTECTION COORDINATION 37 5.0 ANNEXURE -2 : OC TIME CURRENT CHARACTERISTIC CURVE 39 6.0 ANNEXURE -3 : EARTH FAULT PROTECTION COORDINATION 42 7.0 ANNEXURE -4 : EF TIME CURRENT CHARACTERISTIC CURVE 44 8.0 ANNEXURE -5 : SHORT CIRCUIT STUDY RESULTS 47 9.0 ANNEXURE -6 : DIGSI FILES FOR SIEMENS RELAYS

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Tender No.: 08/2015 Calculation No.: 08/2015/E/1062/36/A4 Revision: 1 Title: Construction of 33/11kV, 3x20MVA RUSAIL-09 Primary Substation

Calculation Title: Relay Setting Calculations

Purpose:

These calculations are for the determination of protection Settings and relay coordination for The Electrical System of 33/11kV - 3X20 MVA RUSAIL-09 Pss for MEDC.

Considerations And Assumptions:

a) The resultant Fault Currents used for the protection settings calculation are based Upon The fault levels at the 33kV switchgear at RUSAIL 33kV GSS which received from MDEC and The same is attached in the annexures

b) Software tool ETAP 12.5 has been used for Fault level Calculation Study.

c) Protection Settings calculations are based on Vendor specified CT data and not on CT test reports.

d) Instantaneous elements of 33/11 KV outgoing feeders are blocked as per MDEC practice. e) The Over Current element of outgoing Feeders are based on 100% of rated current i.e. 400

A as per MDEC practice.

f) The protective rely settings are based on the short circuit currents. The relays are set to operate such as to isolate the faulted circuit from the electrical distribution system.

Max 3 Phase/ 1 Phase Fault current at RUSAIL 132kV BUS (2017) = 22.4 / 28.82 kA Max 3 Phase Fault current at RUSAIL 33kV BUS (2017) = 21.53 kA Voltage Level = 33.0kV - Due to Y-D Transformer winding connections and earthing arrangement via

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IEC curves have been considered for relay setting and coordination. The time of operation of the relays using IEC curves can be calculated using the following formula:

At Time Multiplier Setting - TMS = 1

Extremely Inverse: t = 80 ÷ [(I/Is) 2 - 1] Very Inverse: t = 13.5 ÷ [(I/Is) - 1] Standard (normal) Inverse: t = 0.14 ÷ [(I/Is) 0.02 - 1] Where,

t = tripping time I = Fault Current

Is = Inverse time over current pickup TMS = Time Multiplier Setting I/Is = Plug setting Multiplier, PMS

The selection of the type of curve (EI, VI or SI) or DT is based on the best available option for proper coordination and fast fault clearing.

g) The fault current which is mentioned in this document are from ETAP short circuit Study. h) The required TMS of the relay has been choosen as per the required operating time i) Time grading margin of 250 mSec (approx) has been considered between the adjacent

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Relay Type (Similar for all 415 V INCOMER MCCB) MCCB Make: SIEMENS

Protection feature: L:Long Time , S: Short Time , I: Instantaneous , G: Ground fault Location:

LVAC INCOMER Panels : =QA and =QB

Aux. Transformer data (Similar for all 33 kV Transformer Bays)

Rated Power: 0.5 MVA

Rated Voltage: 11 / 0.433 KV

Rated Current (Side-1) : 26.24 A

Connection : Delta (HV), Star (LV)

Vector Group : Dyn11

Transformer Percentage Impedance, Z % : 4.75 %

415 V system data

0.433 KV

Rated short circuit current of 415 V BUS,Iscc (1 Sec) : 50 _KA

50 _Hz

415 V MCCB data Make:

Type:

Rated Current : A

415 V MCCB Settings (Similar for all 415 V INCOMER MCCB)

LONG TIME (L)

= 666.69 / 1250 = 0.53335 Selected Pick-up current setting, (I>) = 0.90 A

= 2.00 SEC

SHORT TIME (S)

Selected Pick-up current setting, (I>) = 2.00 A = 0.30 SEC

INSTANTANEOUS (I)

= Disabled

GROUND FAULT (G)

= 0.20 * 1250 = 250 Selected Pick-up current setting, (I>) = 0.20 A

= 0.30 SEC Time Setting Current Setting Current Setting Time Setting Time Setting Instantaneous Function Nominal frequency: 1250 SIEMENS 3WL1112-2FG48-5FM4 3.0 RELAY SETTING CALCULATION OF RUSAYL-9 PSS

3.1 415 V MCCB SETTING

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Relay Type (Similar for all 11 kV Auxiliary Transformer Bays) 751A51 Make: SIEMENS

Protection feature: Non Directional Phase Over Current and Earth Fault Protection Location:

11 KV Auxiliary Transformer panels: =4H0 and =5H0

Aux. Transformer data (Similar for all 11 kV Aux. Transformer Bays)

Rated Power: 0.5 MVA

CT Ratios for 50, 51 & 51N Protection (Similar for all 11 kV Auxiliary Transformer Bays)

11 KV Aux. Transformer Feeders CT: 200 / 1 A Class: 5P20

The maximum transformer through-fault current calculation

short circuit MVA of the transformer = Transformer MVA ÷ %Z = 0.50 ÷ 4.75 short circuit MVA of the transformer = 10.5263 MVA

Fault current as referred to secondary = 10.5263 x 10^6 ÷ (SQRT(3)x 0.433 x 10^3) = 14035 A [ considered fault current for stability] Fault current as referred to 11 KV = 552 A

3PH fault Current at 11 KV side when 2 transformers in service = 14.6 KA 3PH fault Current at 11 KV side when one transformers in service = 8.3 KA

Relay Settings (Similar for all 11 kV Aux. Transformer Bays)

Instantaneous Phase Over Current Protection (50)

symmetrical through fault current = 1.30 x Symmetrical fault current

= 1.30 x 552.49 = 718.23 A Multiples of pickup current = 718.23 / 200 = 3.59117 In

Inrush current of the Transformer = 12 x Primary FLC [Assumed] = 12 x 26.24 = 314.92 A Multiples of pickup current = 314.92 / 200 = 1.57459 In

Since 1.3 x Tx through fault current is greater than transformer inruch current setting is selected to be greater than 1.3 x transformer through fault current.

Summary:

Selected Instantaneous Pick-up, (I>>) = 4.0 A

Time Delay, td = 0.0 Sec

Selected Tripping Characteristics = DMT

Non Directional Phase Over Current Protection (51)

Phase over current Pick-up = 120% of the Transformer full load current = ( 1.20 x 26.24 ) ÷ 200 = 0.16 A

3.0 RELAY SETTING CALCULATION OF RUSAYL-9 PSS

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Selected Pick-up current setting, (I>) = 0.16 A ( Actual Pick-up current = 31.491833 A )

Multiples of pickup current = 552 / 31.49 = 17.54386

Selected Tripping Characteristics = SI (IEC Curve)

Operating Time desired = 415 LVAC Operating Time + Grading Margin Operating Time desired = 0.3 + 0.3

Operating time desired = 0.60 Sec

Relay operating time = TMS {0.14/((I/Is)^0.02-1)}

0.60 = 0.14 x TMS / [ ( 17.5 )^0.02 -1]

= 0.25

Summary:

Selected 51 Pick-up, (I>) = 0.16 A

Selected Tripping Characteristics = SI

Selected TMS = 0.25

Non Directional Earth Fault Protection (51N)

Ground fault currents are not transferred through delta-Wye transformer

Io Setting = 0.2 In TMS = 0.05

Selected Pick-up current setting, (Io>) = 0.20 A ( Actual Pick-up current = 40 A )

Multiples of pickup current = 8640 / 40.00 = 216 > 20 then , Multiples of pickup current = 20

= 0.14 x TMS / [ ( 20 )^0.02 -1]

= 0.11

Summary:

Selected 51N Pick-up, (I>) = 0.2 A

Instantaneous Earth Fault Protection (50N)

Instantaneous Earth Fault pickup current = 5 Times of 51N current pickup current

= 5.00 x 0.20 = 1.00 In

Summary:

Relay operating time TMS

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Relay Type (Similar for all 11 kV Capacitor Bank Bays) 751A51 Make: SIEMENS

11 KV Outgoing Feeder panels: =1K0 , =2K0 and =3K0

CT Ratios for 51 & 51N Protection (Similar for all 11 kV Capacitor Bank Bays)

11.5 KV Capacitor Bank CT: 400 / 1 A Class: 5P20

Relay Settings (Similar for all 11 kV Capacitor Bank Bays)

As per Capacitor Bank Vendor Parameters , The rated Current for each Stage = 52.5 A The Capacitor bank full load Current = 5 Stages* 52.5 = 262.5 A

Phase over current Pick-up = 130% * the Capacitor bank full load Current = ( 1.30 x 262.50 ) ÷ 400

= 0.85 A

Selected Pick-up current setting, (I>) = 0.85 A ( Actual Pick-up current = 341.25 A )

= 0.05 (MDEC Practice)

Multiples of pickup current = 14.6 / 341.25 = 42.7839 > 20 Relay operating time = TMS {0.14/((I/Is)^0.02-1)}

= 0.14 x 0.05/ [ ( 20 )^0.02 -1] = 0.11 Sec

Summary:

Instantaneous Setting = Blocked (MDEC Practice)

1PH fault Current at 11 KV side when 2 transformers in service = 15.86 KA 1PH fault Current at 11 KV side when one transformers in service = 8.64 KA Earth Fault current Pick-up = 20% of the CT Ratio

= ( 0.20 x 400.00 ) ÷ 400

= 0.20 A

Selected Pick-up current setting, (Ie>) = 0.20 A ( Actual Pick-up current = 80 A )

Multiples of pickup current = 8.64 / 80 = 108 > 20 then , Multiples of pickup current = 20

= 0.14 x 0.05/ [ ( 20 )^0.02 -1] = 0.11 Sec

3.3 NON DIRECTIONAL PHASE & EARTH FAULT PROTECTION (51 & 51N) OF 11 KV CAPACITOR BANK

Selected TMS

Relay Operating Time Relay Operating Time

Selected TMS

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Summary:

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Relay Type (Similar for all 11 kV Outgoing Feeders Bays) 751A61 Make: SIEMENS

11 KV Outgoing Feeder panels: =11L5 To = 39L5

CT Ratios for 51 & 51N Protection (Similar for all 11 kV Outgoing Feeders Bays)

11.5 KV Outgoing Feeders CT: 400 / 1 A Class: 5P20

Relay Settings (Similar for all 11 kV Outgoing Feeders Bays)

3PH fault Current at 11 KV side when 2 transformers in service = 14.6 KA 3PH fault Current at 11 KV side when one transformers in service = 8.3 KA Phase over current Pick-up = 100% of the CT ratio

= ( 1.00 x 400.00 ) ÷ 400

= 1.00 A

Selected Pick-up current setting, (I>) = 1.00 A ( Actual Pick-up current = 400 A )

Multiples of pickup current = 14.6 / 400 = 36.5 > 20 Relay operating time = TMS {0.14/((I/Is)^0.02-1)}

= 0.14 x 0.05/ [ ( 20.0 )^0.02 -1] = 0.1134 Sec

Summary:

OC High set Setting = 8 In (MDEC Practice)

OC High set Clcs = Definite (MDEC Practice)

OC High set Time = 0 Sec (MDEC Practice)

1PH fault Current at 11 KV side when 2 transformers in service = 15.86 KA 1PH fault Current at 11 KV side when one transformers in service = 8.64 KA Earth Fault current Pick-up = 20% of the CT Ratio

= ( 0.20 x 400.00 ) ÷ 400 = 0.20 A

Multiples of pickup current = 8.64 / 80 = 108 > 20 Relay operating time = TMS {0.14/((I/Is)^0.02-1)}

= 0.14 x 0.05/ [ ( 20 )^0.02 -1] = 0.1134 Sec

3.4 NON DIRECTIONAL PHASE & EARTH FAULT PROTECTION (51 & 51N) OF 11 KV OUTGOING FEEDERS

Selected TMS

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Summary:

EF High set Setting = 1.6 In (MDEC Practice)

EF High set Clcs = Definite (MDEC Practice)

EF High set Time = 0 Sec (MDEC Practice)

A/R setting :

No. of shots = 1

Dead Time for first shot = 180 Sec

Reset Time For reclose cycle = 60 Sec

Reset Time Form Lock Out = 60 Sec

Dead Time for 2 to 4th Shot = Infinite

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Relay Type (Similar for all 11 kV Bus coupler Bays) 751A51 Make: SIEMENS

11 KV Bus Coupler panels: =3S0 and =4S0

CT Ratios for 51 & 51N Protection (Similar for all 11 kV Bus coupler Bays)

11.5 KV Bus Coupler CT: 1200 / 1 A Class: 5P20

Relay Settings (Similar for all 11 kV Bus coupler Bays)

3PH fault Current at 11 KV side when one transformers in service = 8.3 KA

Phase over current Pick-up = 100% of Full Load current for one transformer = 1050

= ( 1.00 x 1050.00 ) ÷ 1200

= 0.88 A

Multiples of pickup current = 8.3 / 1200 = 6.91667 ˂ 20 Bus Section CB Operating Time required = Operating time of 11 KV Feeder CB + 0.25 Sec [Grading Margin]

= 0.36 Sec Selected Tripping Characteristics = SI (IEC Curve)

0.36 = 0.14 x TMS / [ ( 6.9 )^0.02 -1]

= 0.10

Summary:

1PH fault Current at 11 KV side when one transformers in service = 8.64 KA Earth Fault current Pick-up = 20% of the CT Ratio

= ( 0.20 x 1200.00 ) ÷ 1200 = 0.20 A

Multiples of pickup current = 8.64 / 1200 = 7.2 ˂ 20 Bus Section CB Operating Time required = Operating time of 11 KV Feeder CB + 0.25 Sec [Grading Margin]

= 0.36 Sec Selected Tripping Characteristics = SI (IEC Curve)

0.36 = 0.14 x TMS / [ ( 7 )^0.02 -1]

= 0.10

TMS

3.5 NON DIRECTIONAL PHASE & EARTH FAULT PROTECTION (51 & 51N) OF 11 KV BUS COUPLER

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Summary:

3.5 NON DIRECTIONAL PHASE & EARTH FAULT PROTECTION (51 & 51N) OF 11 KV BUS COUPLER 3.0 RELAY SETTING CALCULATION OF RUSAYL-9 PSS

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Relay Type (Similar for all 11 kV Transformer Incomer Bays) 751A51 Make: SIEMENS

Protection feature: Stand-by Earth Fault Location:

11 KV Transformer Incomer panels: =1T0, =2T0 and =3T0

Transformer data (Similar for all 11 kV Transformer Incomer Bays)

Rated Power(ONAN/ONAF) : 20 MVA

Transformer Cooling ONAF/ONAN

Rated Current (HV) : 349.91 A

Rated Current (LV) : 1004.09 A

CT Ratios for 51G Protection (Similar for all 11 kV Transformer Incomer Bays)

LV 11.5 KV Transformer Feeder CT: 1200 / 1 A Class: 5P20

Relay Settings (Similar for all 11 kV Transformer Incomer Bays)

Stand-by Earth Fault Protection (51G)

1PH fault Current at 11 KV side when one transformers in service = 8.64 KA Earth Fault current Pick-up = 20% of the CT ratio

= ( 0.20 x 1200.00 ) ÷ 1200 = 0.20 A

Multiples of pickup current = 8640 / 240 = 36 > 20 Required Relay operating time = 11 KV I/C 51N Relay Operating Time + Grading Margin [0.25]

= 0.61 + 0.25 = 0.91 Sec Selected Tripping Characteristics = SI (IEC Curve)

0.91 = 0.14 x TMS / [ ( 20 )^0.02 -1] = 0.403

Summary:

Selected Pick-up, (I>) = 0.2 A

3.6 STAND-BY EARTH FAULT PROTECTION (51G) OF 33/11 KV TRANSFORMER

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Relay Type (Similar for all 11 kV Transformer Incomer Bays) 751201 Make: SIEMENS

Protection feature: Directional Phase Over Current and Earth Fault Protection Location:

11 KV Transformer Incomer panels: =1T0, =2T0 and =3T0

Transformer data (Similar for all 11 kV Transformer Incomer Bays)

CT Ratios for 67 & 67N Protection (Similar for all 11 kV Transformer Incomer Bays)

LV 11.5 KV Transformer Feeder CT: 1200 / 1 A Class: 5P20

Relay Settings (Similar for all 11 kV Transformer Incomer Bays)

Directional Phase Over Current Protection (67)

Directional Phase over current Pick-up = 50% of the CT Ratio

= ( 0.50 x 1200.00 ) ÷ 1200

= 0.50 A

Since the 67 Relay will operate only when both transformers will be in parallel and as per short circuit study the fault contribution (total) when both 20 MVA transformers are in parallel = 14.6 KA

Contribution of each transformer (fault seen by 67 relay CT) = 14.6 /2 = 7.3 KA

Multiples of pickup current = 7300 / 600 = 12.1667 ˂ 20 Operating time desired = 0.30 Sec

0.30 = 0.14 x TMS / [ ( 12 )^0.02 -1]

= 0.1

Summary:

Direction of operation = Forward ( TowardsTransformer)

RCA Recommended = _45.0◦ Directional Earth Fault Protection (67N)

Directional Earth Fault current Pick-up = 20% of the CT Ratio

= ( 0.20 x 1200.00 ) ÷ 1200 = 0.20 A

Selected Pick-up current setting, (Ie>) = 0.20 A ( Actual Pick-up current = 240 A ) 3.0 RELAY SETTING CALCULATION OF RUSAYL-9 PSS

3.7 DIRECTIONAL PHASE & EARTH FAULT PROTECTION (67 & 67N) OF 11KV SWITCHGEAR INCOMER

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Since the 67 Relay will operate only when both transformers will be in parallel and as per short circuit study the fault contribution (total) when both 20 MVA transformers are in parallel = 15.86 KA

Contribution of each transformer (fault seen by 67 relay CT) = 15.86 /2 = 7.93 KA

Multiples of pickup current = 7930 / 240 = 33.0417 > 20

= TMS {0.14/((I/Is)^0.02-1)}

= 0.14 x 0.05/ [ ( 20 )^0.02 -1] = 0.1134 Sec

Summary:

Direction of operation = Forward ( TowardsTransformer)

RCA Recommended = _-45◦ Non Directional Phase Over Current Protection (51)

3PH fault Current at 11 KV side when one transformers in service = 8.3 KA Non Directional Phase over current Pick-up= 100% of the CT Ratio

= ( 1.00 x 1200.00 ) ÷ 1200 = 1.00 A

Multiples of pickup current = 8300 / 1200 = 6.91667 ˂ 20 Operating time desired = Operating time of 11 KV bus coupler + 0.25 Sec [Grading Margin]

= 0.61 Sec

0.61 = 0.14 x TMS / [ ( 7 )^0.02 -1]

= 0.17

Summary:

1PH fault Current at 11 KV side when one transformers in service = 8.64 KA Directional Earth Fault current Pick-up = 20% of the CT Ratio

= ( 0.20 x 1200.00 ) ÷ 1200

= 0.20 A

Selected Pick-up current setting, (Ie>) = 0.20 A ( Actual Pick-up current = 240 A ) 3.0 RELAY SETTING CALCULATION OF RUSAYL-9 PSS

3.7 DIRECTIONAL PHASE & EARTH FAULT PROTECTION (67 & 67N) OF 11KV SWITCHGEAR INCOMER

Selected TMS

Relay Operating Time Relay Operating Time Relay Operating Time

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Multiples of pickup current = 8640 / 240 = 36 > 20 Operating time desired = Operating time of 11 Kvbus coupler + 0.25 Sec [Grading Margin]

= 0.61 Sec

0.61 = 0.14 x TMS / [ ( 20 )^0.02 -1]

= 0.27

Summary:

TMS

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Relay Type (Similar for all 33 kV Transformer Bays) 751A51 Make: SIEMENS

Protection feature: High Impedance REF Protection Location:

11 KV Transformer Incomer panels: =1T0, =2T0 and =3T0 Transformer data (Similar for all 33 kV Transformer Bays)

Impedance Tolerance Considered : ± 7.5 % [IEC tolerance]

Therefore Transformer Percentage Impedance, (Z%): 11.56 %

CT Ratios for High Impedance REF Protection (Similar for all 33 kV Transformer Bays)

11 KV Transformer Feeder CT: 11 KV Transformer Neutral CT:

CT Ratio: 1200 / 1 A CT Ratio: 1200 / 1 A

Class: X Class: X

Knee Point Voltage: 350 V Knee Point Voltage 350 V

CT mag. Current @ Vk/2 30 mA CT mag. Current @ Vk 30 mA

CT secondary resistance Rct: 6 Ohms CT secondary resistance Rct: 6 Ohms Relay Settings (Similar for all 33 kV Transformer Bays):

All CTs must have the same transformation ratio. To prevent maloperation of the relay during saturation of the CTs on an external fault, the actual stability voltage Vs must be at least the voltage Vs,min produced by the maximum secondary through fault current, flowing through the cable resistance and the CTs' internal resistance:

Vs > Vs,min

where

Vs,min = Ik,max,thr *(Isn/Ipn)*(Rlead + Ri)

In addition to this, the kneepoint voltage must be higher than twice the actual stability voltage: V_knee ≥ 2 * Vs (Requirement)

where :

Vs : actual stability voltage Vs,min : minimum stability voltage Vknee : kneepoint voltage of CT

Ik,max,thr : max. symmetrical short-circuit current for external faults Ipn : CT primary nominal current

Isn : CT secondary nominal current R_{i :} CT secondary winding Resistance Rlead :

3.0 RRELAY SETTING CALCULATION OF RUSAYL-9 PSS

3.8 RESTRICTED EARTH FAULT PROTECTION (87NL) OF 33/11k,20MVA TRANSFORMER SECONDARY SIDE

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Length 11 KV Side: lwire = 10 m Netural Side: lwire = ₁₀₀ _m Cross-section awire = 4 mm 2

As per vendor catalogue

Resistance (Cu)@20 ◦C R_cu20 = 0.00461 Ohms /m Temperature coefficient α per ◦C = 0.00393

Resistance (Cu)@75 ◦C Rcu75= pcu20 x (1+ α (75-20))

pcu75= 0.00561 Ohms /m Eff. Wire length p.u. k =

For 11 KV Side:

Rshortest loop = Ohm

For Neutral Side:

Rlongest loop = Ohm

in the below calculation, we will consider the resistance of the longest cable loop

Calculation of stability voltage:

The maximum transformer through-fault current calculation short circuit MVA of the transformer = Transformer MVA ÷ %Z =

= 20/ 11.56 = 172.972973 MVA

Maximum transformer through-fault current IF = short Circuit TX MVA / √3 x Rated secondary TX voltage = ( 172.973 /(√3*11))

= 8.684 KA

The minimum stability voltage of 7SJ8022 ANSI 64N(HI) to ensure stability on external faults: Vs,min = Ik,max,thr *(Isn/Ipn)*(Rlead + Ri)

Vs,min = 8684 /1200*( 1.1213 + 6 ) Vs,min = 51.5344 V

The actual stability voltageVs should be set to at least Vs,min. The actual stability voltage for the scheme can be then chosen:

Vs = 62 V (20 % Safety margin )

A higher value for the setting voltage Us is chosen in order to cater for all possible transient phenomena with a safety factor of about 1.2, a value of 65 V is selected.

The minimum knee point voltage of the CTs must be twice the relay setting voltage Vknee ≥ 2 * Vs

Vknee = 350 V

2 * Vs = 123.683 V Meets Requirement

CALCULATION OF CABLE BURDEN: Wire burden:

2 Rwire = k* lwire * Rcu75

0.1121 1.1213

CTs correctly dimensioned

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The CT knee-point voltage of 350 V exceeds the selected stabilizing voltage of 62 V several times, so under in-zone fault condition the CTs will produce enough output to operate the relay.

Calculation of maximum sensitivity:

The higher is the sensitivity, the lower the value of the fault current that is detected by the relay. According to the actual stability voltage and considering that the relay has a variable a.c. current setting on the 1 A tap of 0.001 A to 1.6 A in 0.001 A steps, the maximum primary current sensitivity Ip can be obtained

IP = Ip/Is*[Is, min +n * Iknee*(Vs/Vknee)+Ivar]

where:

Ip : Maximum primary current sensitivity

Is,min : Minimum relay current setting ( 0.2 A ) Considered N : Number of CTs in parallel with relay ( 4 )

I knee : Mag. current Iknee at Uknee ( 0.03 A ) Vs : Actual stability voltage ( 61.84128033 V ) V knee : Knee point voltage of CT ( 350 V ) Ivar : Current in non-linear resistor at the relay circuit setting

voltage, calculated as follows:

Ivar = 0.52 * [ (√2 *Vs ) / C]^1/ᵦ

for the varistor consider C = 900 and β = 0.25 ( MEDC practice) Ivar = 0.05 mA

IP = 1200 * ( 0.200 + 0.04241 + 0.00005 )

IP = 290.942 A

The calculated current Ip corresponds to a sensitivity of 24.2451816 % of nominal primary current Ipn of CT. This corresponds to a sensitivity of 28.9758 % of nominal current of the object In_obj = 1.05 KA

Desired sensitivity calculation:

For a desired decreased sensitivity of 25 % of In_obj = 251.021856 A a corresponding relay current setting can be calculated:

Is = I p,des * (Isn/Ipn) - n * Iknee*(Vs/Vknee)-Ivar

where:

Is : secondary relay current setting to reach the desired sensitivity Ip,des : desired current sensitivity of object ( 251.021856 A )

Is = [ 0.20918 - 0.04241 - 0.000046] Is = 0.16673

Considering the setting range of the relay on the 1 A tap of 0.001 A to 1.6 A in 0.001 A steps the pickup current can be chosen: Is,set = 0.20 A

the relay setting Current Is= 0.20 A

Stabilizing Resistor Calculation (R_stab)

The stabilizing resistor R_stab to ensure protection stability is: Rstab = Vs / Is

Rstab = 62 / 0.20

Rstab = 309.206 Ω

309.2064016 Ω [ Available range is 0 - 1000 Ω]

Therefore Stabilising resistor R_stab shall be set as =

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The stabilizing resistor Rstab can be chosen with a necessary minimum continuous power rating Pstab,cont of :

Pstab,cont ≥ ( Vs2 / Rstab )

Pstab,cont ≥ [ 3824.34 / 309.21 ]

P_stab,cont ≥ 12.3683 W

Moreover, Rstab must have a short time rating large enough to withstand the fault current levels before the fault is cleared. The time duration of 0.5 seconds can be typically considered (Pstab,0.5s) to take into account longer fault clearance times of back-up protection.

The rms voltage developed across the stabilizing resistor is decisive for the thermal stress of the stabilizing resistor. It is calculated according to formula:

V rms,f = 1.3 * 4√ ( V Knee 3 * Rstab * I k,Max ,int *(Isn/Ipn) )

where

I k,max,int: Max. symmetrical short-circuit current for internal faults = 8.683999 KA

V rms,f = V

The resulting short-time rating Pstab,0.5s equals to:

Pstab,0.5s ≥ ( Vrms2 /Rstab ) = 1692.90973 W

Check for the requirement of non-linear resistor (Metrosil)

If the peak voltage developed across the relay circuit under max. internal fault conditions exceeds 3000 V peak then a suitable non-linear resistor (Metrosil) should be connected across the relay and Stabilizing resistor, in order to protect the insulation of the CTs, relay and interconnecting leads.

The maximum fault voltage assuming no CT saturation shall be calculated using the below formula: R_CT = CT Internal Resistance : 6 Ω

Rst ab = Stabilizing Resistor : 309.2064016 Ω

RL = One way CT lead resistance : 0.56064515 Ω

Ifmax = Maximum secondary external fault current : 8683.999349 A

Vk = Knee point voltage of the CT : 350 V

The max. fault voltage assuming no CT saturation, = Ifmax x (Isn/Ipn) x( RCT + 2 RL + Rstab) Vf = 7.23667 x ( 6 + 1.1213 + 309.206)

Vf = 2289.16 V

The peak Voltage, Vp = 2 x SQRT [ 2x Vk x ( Vf-Vk)]

Vp = 2 x SQRT [ 2 x 350 x ( 2289.16 - 350 )] Vp = 2330.16 V

As the Peak voltage is Less than 3000V hence Metrosil is not required For Safer Side Metrosil shall be considered

The type of metrosil required is chosen by its thermal rating as defined by the formula P = ( 4 / 3.14) x { I_f x V_k/ CT ratio}

P = ( 4 / 3.14) x { 8684 x 350 / 1200 } P = 3224.9 J/S

P = 3.2249 KJ/S Select a metrosil with C=900 , β= 0.25

SUMMARY OF HIGH IMPEDANCE REF PROTECTION SETTINGS

Rstab = 309.206402 Ω

Is = 0.20 A

723.5043

(22)

Relay Type (Similar for all 33 kV Transformer Bays) 7UT612 Make: SIEMENS

Location:

33 KV Transformer Relay Panels: =CB - 1H0, =CB - 2H0 and =CB - 3H0 Transformer data (Similar for all 33 kV Transformer Bays)

Taps available @Transformer Primary: - 15% to 5% in steps of 1.67%

NO. of Taps w/o Center Tap 12.00

HV @ Highest tap position for +10% tap (Umax) : 34.65 KV

HV @ Lowest tap position for -10% tap (Umin): 28.05 KV

CT Ratios for Differential Protection (Similar for all 33 kV Transformer Bays)

HV 33 KV Transformer Feeder CT: 400 / 1 A Class: X

LV 11.5 KV Transformer Feeder CT: 1200 / 1 A Class: X

Relay Settings (Similar for all 33 kV Transformer Bays):

The individual reference currents for each winding of the transformer are calculated by 7UT612 on the basis of the set reference power and the set primary nominal voltages of the transformer.

= 20MVA/(√3x 33.00 KV) = 349.909 Amps 349.91 Amps = 20MVA/(√3x 11.5 KV) = 1004.09 Amps 1004.09 Amps Where: Reference Power

Reference Current of winding 1 and 2. Nominal voltage of winding 1 and 2 .

3.9 TRANSFORMER DIFFERENTIAL PROTECTION (87T) OF 33/11kV, 20MVA TRANSFORMER

I_{NObj SIDE 1} = S_N/(√3.V_{N SIDE 1})

INObj SIDE 1 =

INObj SIDE 2 = SN/(√3.VN SIDE 2)

INObj SIDE 2 = SN : INObj SIDE 1,2 : V_{N SIDE 1,2} : CT1 400/1 A CT2 1200/1 A SN = 20 MVA 33 KV 11 KV I1 I2

(23)

Differential Setting:

1. Idiff > 2. ldiff>>

3. SLOPE 1 and BASE POINT 1 4. SLOPE 2 and BASE POINT 2 5. Harmonic restraint

1. ldiff> : Differential current

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 and lowest tap positions.

CALCULATION OF AVRAGE VOLTAGE :

As per the relay manual ; If the transformer winding is regulated, not the actual rated voltage of the winding UNB is used, but rather the voltage which corresponds to the average current of the regulated range

Uaverage = 2/(1/Umin + 1/Umax) where,

Umax = maximum Voltage @ + 10 % Tap Umin = minimum Voltage @ -10 % Tap

Uavrg = 2/(1/Umin + 1/Umax)

Uavrg = 2 / ( 1 / 28.05 + 1 / 34.65 ) Uavrg = 31.00 KV

CALCULATION OF Idiff.> Tap Changer Regulation Effect:

Uavrg = 31.00 KV => IN,tap0= SN/Uavrg*SQRT(3) = 372.4524 A

Umax = 34.65 KV => IN,tap+= SN/Umax*SQRT(3) = 333.2469 A

Umax = 28.05 KV => IN,tap+= SN/Umax*SQRT(3) = 411.6579 A

Tap change regulation = (In,tap0 - In,tap+)/In,tap0

Tap change regulation = ( 372.4524 - 333.2469 ) / 372.4524

Tap change regulation = 10.53% ₍₁₎

Tap changer regulation Error:

INObj,tap0 = INObj1 = 372.45243 A ( IN,tap0 / CT1 ratio ) = ( 372.452 / 400 ) A I_NObj1 = 0.931131 A 1004.087 A ( remains Constant) ( INObj2 / CT2 ratio ) = ( 1004.09 / 1200 ) A INObj2 = 0.83674 A 0.83674 I_NObj

INObj2 @ the CT2 Secondary Side =

INObj2 @ the CT2 Secondary Side = 0.84

INObj2 =

INObj1 @ the CT1 Secondary Side = 0.931131068 3.0 RELAY SETTING CALCULATION OF RUSAYL-9 PSS

Max. Full load Current of the Transformer @ Center Tap =

INObj1 @ the CT1 Secondary Side =

(24)

Max. Full load Current of the Transformer @ Max. Tap = 333.24691 A ( INObj,tap+ / CT1 ratio ) = ( 333.247 / 400 ) A INObj1 (+5%) = 0.833117 A 0.894737 I_NObj

Max. Full load Current of the Transformer @ Min. Tap = 411.65795 A

( INObj,tap- / CT1 ratio ) = ( 411.658 / 400 )

A

INObj1 (-15%) = 1.029145 A

1.105263 I_NObj

|INObj1(+5%) - INObj1|= 0.105263 INObj1

IDIFF = | 0.105263 INObj1 |

IDIFF = 0.10 I_NObj ₍₂₎

|INObj1(+5%) + INObj1|= 1.894737 INObj1

IRest = | 1.894737 INObj1 |

IRest = 1.76 I_NObj

|INObj1(-15%) - INObj1 |= 0.105263 INObj1

IDIFF = | 0.105263 INObj1 |

IDIFF = 0.098 I_NObj ₍₃₎

|INObj1(-15%) + INObj1|= 2.105263 INObj1

IRest = | 2.105263 INObj1 |

IRest = 1.96 I_NObj

From 1 ,2 and 3 ,the max. differential current due to Tap changer error = 0.10

Add to this other errors like CT error , CT Magnetizing and relay. Also, considering safety margin based on variations of above factors due to variation in system condition

Available setting: 0.05 to 2 x INObj (in steps of 0.01)

Hence the selected setting

Idiff > INObj = 0.2 IN/INObj

2. ldiff>> : High-current stage

This is a simple instantaneous unrestrained highest differential over current setting . It is not influenced by restraining current (triple slope characterstics), harmonic restraint, overfluxing restraint or saturation detector. Also,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.

Diff. Current @ Min. Tap IDIFF = Diff. Current @ Max. Tap IDIFF =

INObj1(+5%) @ the CT1 Secondary Side =

INObj1 (+5%)@ the CT1 Secondary Side = 0.833117272

INObj1 (+5%) =

INObj,tap- = INObj1 (- 15%) =

INObj1(-15%)@ the CT1 Secondary Side =

INObj1 (-15%)@ the CT1 Secondary Side = 1.029144865

INObj1 (-15%) =

Restraint Current @ Max. Tap IRest =

Restraint Current @ Min. Tap IRest =

INObj,tap+ = INObj1 (+ 5%) = 3.0 RELAY SETTING CALCULATION OF RUSAYL-9 PSS

(25)

CALCULATION OF HIGH SET TRIP :

short circuit MVA of the transformer = Transformer MVA ÷ %Z = 20.00 ÷ 12.50 short circuit MVA of the transformer = 160 MVA

Fault current as referred to secondary = 160 x 10^6 ÷ (SQRT(3)x 11.5 x 10^3) = 8033 A [ considered fault current for stability] Fault current as referred to 33 KV = 2799.274

High Set setting should be set higher than 1.3 x Tx through fault current 1.3 x Tx through fault current = 3639.06 Corresponding CT secondary Current = ( 3639 / 400 )

Corresponding CT secondary Current = 9.09764 INObj (4)

Normally the transformer inrush current may go from 8-12 times the rated current. Taking 12 times the rated current for calculation,

Maximum transformer inrush current = 12 x rated current

= 12 x 349.91 = 4199 Amps

Corresponding CT secondary Current = ( 4199 / 400 )

Corresponding CT secondary Current = 10.4973 INObj (5)

From 4 , 5 and as per manual the Available setting: 0.5 to 35 x INObj (in steps of 0.1) Hence the selected setting

Idiff >> INObj = 11 IN/INObj

3. SLOPE 1 and BASE POINT 1

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 diff. current that can be attributed to the position of the Tap changer of the voltage regulator.

Tap Range (Total) = 20% [ +5% and -15%] CT errors = 5% (Assumed)

Hence the Recommended Slope-1 setting = 25%

25% and BASE POINT 1 = 0 IN/INObj

4. SLOPE 2 and BASE POINT 2

This is the second knee point of the tripping characteristic,it is set to produce stabilization in the range of high currents which may lead to current transformer saturation.

A setting of 50% is selected for Slope-2 with relay default setting for BASE POINT 2.

Hence the selected setting

50% and BASE POINT 2 = 2.5 IN/INObj SLOPE 1 =

(26)

5. Harmonic Restraint

Inrush Detector

This setting shall be "ENABLED"

When switching unloaded transformers, high magnetizing (inrush) currents may occur. These inrush currents produce differential quantities as they seem like single-end fed fault currents Hence this setting shall be enabled such that the relay is stable even during energizing the transformer

Cross Method of Measurement

Each phase is monitored and if the even harmonics present in any of the phase exceed the setting all the three phases are blocked. Hence Cross method of measurement is used for inrush detection.

2nd and 5th Harmonic Blocking Percentage (%)

The setting determines the level of harmonic (second and fourth) content in the relay operating current that will cause operation of the relay to be inhibited

As per the manufacture recommendation the setting of

15% is selected for 2nd harmonic blocking percentage setting 30% is selected for 5th harmonic blocking percentage setting

SUMMARY OF LOW IMPEDANCE TRANSFORMER DIFFERENTIAL PROTECTION SETTINGS

SN SIDE 1 , SN SIDE 2 = 20 MVA

UN-PRI SIDE 1 = 33 KV

UN-PRI SIDE 2 = 11.5 KV

CONNECTION S1, STARPNT SIDE 1 = D,Isolated CONNECTION S2, STARPNT SIDE 2 = Y, Earthed

VECTOR GRP S2 = 11

STRPNT->OBJ M1 , STRPNT->OBJ M2 = YES

IN-PRI CT M1 / IN-SEC CT M1 = 400 /1 A IN-PRI CT M2 / IN-SEC CT M2 = 1200/1 A

I-DIFF> = 0.2 I/InO

I-DIFF>> = 11 I/InO

SLOPE 1 = 25%

BASE POINT 1 = 0 I/InO

SLOPE 2 = 50%

BASE POINT 2 = 2.5 I/InO

2. HARMONIC = 15%

n. HARMONIC = 30%

3.9 TRANSFORMER DIFFERENTIAL PROTECTION (87T) OF 33/11kV, 20MVA TRANSFORMER 3.0 RELAY SETTING CALCULATION OF RUSAYL-9 PSS

(27)

Relay Type (Similar for all 33 kV Transformer Bays) 7SJ8021 Make: SIEMENS

33 KV Transformer Relay Panels: =CB -1H0, = CB - 2H0 and = CB - 3H0 Power Transformer data (Similar for all 33 kV Transformer Bays)

Rated Power: 20 MVA

CT Ratios for 50, 51 & 51N Protection (Similar for all 33 kV Transformer Bays)

11 KV Aux. Transformer Feeders CT: 400 / 1 A Class: 5P20

The maximum transformer through-fault current calculation

short circuit MVA of the transformer = Transformer MVA ÷ %Z = 20.00 ÷ 11.56 short circuit MVA of the transformer = 172.973 MVA

Fault current as referred to secondary = 172.973 x 10^6 ÷ (SQRT(3)x 11.5 x 10^3) = 8684 A [ considered fault current for stability] Fault current as referred to 33 KV = 3026.242

Relay Settings (Similar for all 33 kV Transformer Bays)

Instantaneous Phase Over Current Protection (50)

symmetrical through fault current = 1.30 x Symmetrical fault current

= 1.30 x 3026.24 = 3934.11 A

Multiples of pickup = 3934.11 / 400 = 9.84 In Inrush current of the Transformer = 12x Primary FLC [Assumed]

= 12 x 349.91 = 4198.91 A

Multiples of pickup = 4198.91 / 400 = 10.50 In

Since transformer inrush current is greater than 1.3 x TX through fault current setting is selected to be greater than transformer inrush current.

Summary:

Phase over current Pick-up = 110% of the Transformer full load current = ( 1.10 x 349.91 ) ÷ 400 = 0.96 A

(28)

Multiples of pickup current = 3026.24 / 400 = 7.56561 ˂ 20 Selected Tripping Characteristics = SI (IEC Curve)

33KV TX Incomer Operating Time required = Operating time of Incomer 11 KV + Zero Sec [Grading Margin] = 0.61 + 0.0

= 0.61 Sec Selected Tripping Characteristics = SI (IEC Curve)

0.61 = 0.14 x TMS / [ ( 8 )^0.02 -1]

= 0.18

11 KV Side Standby Earth Fault Protection should be co-ordinate with the overcurrent protection (unbalance) on the transformer primary (33 KV) Delta side of the transformer , Because an earth fault on the secondary Side would appear on the Primary Side as 1/SQRT(3) P.u fault current in two phases

1PH fault Current at 11 KV side when one transformers in service = 8.64 KA 11 KV Standby Earth fault relay operating = 0.91 Sec

33 KV Current appearing on the winding = 8640 * 11/33/SQRT(3) = 1.66277 A

Multiples of pickup current = 1.66277 / 400 = 4.15692 ˂ 20 33 KV TX OC (51) Operating Time = 0.14 x 0.180.18 / [ ( 4.15692 )^0.02 -1]

= 0.88 Sec Hence required grading is achieved

Summary:

Ground fault currents are not transferred through delta-Wye transformer

1PH fault Current at 33 KV side when one Incomer in service = 1.48 KA Io Setting = 0.2 In

33KV TX Incomer Operating Time required = Operating time of Incomer 11 KV + Zero Sec [Grading Margin] Approx. Operating time = 0.61 Sec

Selected Pick-up current setting, (Io>) = 0.20 A ( Actual Pick-up current = 80 A )

Multiples of pickup current = 1480 / 80 = 18.5 ˂ 20 Operating time desired = 0.61 Sec

0.61 = 0.14 x TMS / [ ( 19 )^0.02 -1]

= 0.05

Summary:

Instantaneous Setting = 6 A

TMS

3.10 NON DIRECTIONAL PHASE & EARTH FAULT PROTECTION(50,51 &51N)of 20MVA, 33/11 KV TRANSFORMER

(29)

Relay Type (Similar for all 33 kV Bus coupler Bays) 7SJ8021 Make: SIEMENS

Protection feature: Non Directional Phase Over Current and Earth Fault Protection Location: 33 KV Bus Coupler panels: =CB -1S0 and = CB - 2S0

CT Ratios for 51 & 51N Protection (Similar for all 33 kV Bus coupler Bays)

33 KV Bus Coupler CT: 1200 / 1 A Class: 5P20

Relay Settings (Similar for all 33 kV Bus coupler Bays)

3PH fault Current at 33 KV side when 2 Incomers in service = 21.3 KA 3PH Fault Current that can be seen by 33 KV Bus Section CB = 10.13 KA 3PH fault Current at 33 KV side when one Incomer in service = 21.1 KA Fault Current that can be seen by 33 KV Bus Section CB = 21.1 A

Phase over current Pick-up = 100% of Full Load current for one transformer

= ( 1.00 x 350.00 ) ÷ 1200 = 0.29 A

Multiples of pickup current = 10130 / 350 = 28.9429 > 20 Selected Tripping Characteristics = SI (IEC Curve)

33 KV B/C Relay operating time = 33 KV Incomer Relay Operating Time + Grading Margin [0.25] = 0.61 + 0.25 = 0.86 Sec

0.86 = 0.14 x TMS / [ ( 20 )^0.02 -1]

= 0.43

Summary:

Selected Tripping Characteristics = SI , Selected TMS = 0.43

1PH fault Current at 33 KV side when 2 Incomers in service = 1.48 KA Fault Current that can be seen by 33 KV Bus Section CB = 0.696 KA

1PH fault Current at 33 KV side when one Incomer in service = 1.48 KA Fault Current that can be seen by 33 KV Bus Section CB = 1.48 KA

Earth Fault current Pick-up = 20% of the CT Ratio

= ( 0.20 x 1200.00 ) ÷ 1200 = 0.20 A

Multiples of pickup current = 696 / 240 = 2.9 ˂ 20 33 KV B/C Relay operating time = 33 KV Incomer Relay Operating Time + Grading Margin [0.25]

= 0.61 + 0.25 = 0.86 Sec Selected Tripping Characteristics = SI (IEC Curve)

3.11 NON DIRECTIONAL PHASE & EARTH FAULT PROTECTION (51 & 51N) OF 33 KV BUS COUPLER

(30)

0.86 = 0.14 x TMS / [ ( 3 )^0.02 -1]

= 0.13

Summary:

Selected Tripping Characteristics = SI , Selected TMS = 0.13

TMS

(31)

Relay Type (Similar for all 33 kV RUSAYL Incomer Bays) 7SJ8041 Make: SIEMENS

Protection feature: Directional Phase Over Current and Earth Fault Protection Location: 33 KV UGC Incomer Relay Panels: =CB -1L5, = CB - 2L5 and = CB - 3L5 CT Ratios for 67 & 67N Protection (Similar for all 33 kV RUSAYL Incomer Bays)

33 Incomer Feeder CT: 400 / 1 A Class: 5P20

Relay Settings (Similar for all 33 kV RUSAYL Incomer Bays)

Directional Phase Over Current Protection (67)

3PH fault Current at 33 KV side when one Source in service = 21.1 KA Directional Phase over current Pick-up = 50% of the CT Ratio

= ( 0.50 x 400.00 ) ÷ 400 = 0.50 A

0.10 = 0.14 x TMS / [ ( 20 )^0.02 -1]

= 0.04

Summary:

Direction of operation = Forward ( Towards Feeder)

RCA Recommended = 45.0 ◦

Directional Earth Fault Protection (67N)

1PH fault Current at 33 KV side when one Source in service = 1.48 KA Directional Earth Fault current Pick-up = 20% of the CT Ratio

= ( 0.20 x 400.00 ) ÷ 400 = 0.20 A

Multiples of pickup current = 1480 / 80 = 18.5 ˂ 20 Selected Tripping Characteristics = SI (IEC Curve)

0.10 = 0.14 x TMS / [ ( 19 )^0.02 -1]

= 0.04

Summary:

Direction of operation = Forward ( Towards Feeder)

RCA Recommended = _{- 45.0}◦

3.12 DIR. AND NON DIR. PHASE & EARTH FAULT PROTECTION (67 /67N/51&51N) OF 33 KV RUSAYL FEEDER

TMS

(32)

3PH fault Current at 33 KV side when one source in service = 21.1 KA Non Directional Phase over current Pick-up = 100% of the CT Ratio

= ( 1.00 x 400.00 ) ÷ 400 = 1.00 A

33 KV Feeder EF Relay operating time = 33 KV BC Relay Operating Time + Grading Margin [0.25] Operating time desired = 1.11 Sec

1.11 = 0.14 x TMS / [ ( 20 )^0.02 -1]

= 0.49

Summary:

1PH fault Current at 33 KV side when one source in service = 1.48 KA Non Directional Earth Fault current Pick-up = 20% of the CT Ratio

= ( 0.20 x 400.00 ) ÷ 400 = 0.20 A Selected Pick-up current setting, (Ie>) = 0.20 A ( Actual Pick-up current = 80 A )

33 KV Feeder EF Relay operating time = 33 KV BC Relay Operating Time + Grading Margin [0.25] Operating time desired = 1.11 Sec

1.11 = 0.14 x TMS / [ ( 19 )^0.02 -1]

= 0.48

Summary:

Selected TMS = 0.48 Remote end setting

33 Incomer Feeder CT: 400 / 1 A Class: 5P20

3PH fault Current at 33 KV side when one source in service = 21.1 KA Non Directional Phase over current Pick-up = 100% of the CT Ratio

= ( 1.00 x 400.00 ) ÷ 400 = 1.00 A Selected Pick-up current setting, (I>) = 1.00 A ( Actual Pick-up current = 400 A )

3.12 DIR. AND NON DIR. PHASE & EARTH FAULT PROTECTION (67 /67N/51&51N) OF 33 KV RUSAYL FEEDER

TMS

(33)

33 KV Remote Relay operating time = 33 KV Incomer Relay Operating Time + Grading Margin [0.25] = 1.11 + 0.25 = 1.36 Sec

1.36 = 0.14 x TMS / [ ( 20 )^0.02 -1]

= 0.60

Summary:

1PH fault Current at 33 KV side when one Source in service = 1.48 KA Non Directional Earth Fault current Pick-up = 20% of the CT Ratio

= ( 0.20 x 400.00 ) ÷ 400 = 0.20 A Selected Pick-up current setting, (Ie>) = 0.20 A ( Actual Pick-up current = 80 A )

33 KV Remote Relay operating time = 33 KV Incomer Relay Operating Time + Grading Margin [0.25] = 1.11 + 0.25 = 1.36 Sec

1.36 = 0.14 x TMS / [ ( 19 )^0.02 -1]

= 0.59

Summary:

TMS

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(36)

SUMMARY OF LOW IMPEDANCE LINE DIFFERENTIAL PROTECTION SETTINGS

(For detailed relay settings, relay setting schedule shall be referred)

I-DIFF> = = 0.2 A

I-DIFF>>= = 1 A

Note:

Same CT Ratio and setting shall be adopted at 132/33 KV RUSAIL Grid S/S end.

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ANNEXURE – 6

(61)

Rusayl PSS / Incomer / 7SD522 V4.7

MLFB:

7SD52214CB999HJ0

Parameter set version:

V04.73.03

Device path: C:\Siemens\Digsi4\D4PROJ\Rusayl_P\P7DI\GV\SD\00000001

Author:

Creation date:

24.02.16 20:44:19

Last modified:

28.02.16 21:50:58

Operating mode:

Offline

Comment:

Setting values in:

Secondary value description

P R I N T - C O N T E N T S

...2

1 Device Configuration

...3

2 General Device Settings

...3

2.1 Group Device, General Settings

...4

3 Power System Data 1

...4

3.1 Group Power System Data 1; Group Transformers

...4

3.2 Group Power System Data 1; Group Power System

...4

3.3 Group Power System Data 1; Group Breaker

...5

3.4 Group Power System Data 1; Group CT Data

...6

4 Settings groups

...6

4.1 Group Power System Data 2; Group Local Line End

...6

4.2 Group Power System Data 2; Group Line Status

...6

4.3 Group 87 Differential Protection; Group General

...7

4.4 Group 87 Differential Protection; Group 87 Diff. Prot.

...7

4.5 Group 87 Differential Protection; Group Inrush

...7

4.6 Group Intertrip

...8

4.7 Group Measurement Supervision; Group Symmetry

...8

4.8 Group Measurement Supervision; Group Meas.Volt.Fail

...8

4.9 Group Measurement Supervision; Group I/U-Monitoring

...9

4.10 Group Measurement Supervision; Group VT mcb

...9

4.11 Group Measurement Supervision; Group Load Angle

...9

4.12 Group Protection Interface (Port D+E); Group General

...9

4.13 Group Protection Interface (Port D+E); Group Interface 1

...10

4.14 Group Differential Topology

(62)

1

Device Configuration

No. Function Scope

0103 Setting Group Change Option Disabled

0112 87 Differential protection Enabled

0115 21 Phase Distance Disabled

0116 21G Ground Distance Disabled

0119 Additional Threshold Iph>(Z1) Disabled

0120 68 Power Swing detection Disabled

0121 85-21 Pilot Protection for Distance prot Disabled

0122 DTT Direct Transfer Trip Disabled

0124 50HS Instantaneous SOTF Disabled

0125 Weak Infeed (Trip and/or Echo) Disabled

0126 50(N)/51(N) Backup OverCurrent Disabled

0131 50N/51N Ground OverCurrent Disabled

0132 85-67N Pilot Protection Gnd. OverCurrent Disabled

0138 Fault Locator Disabled

0139 50BF Breaker Failure Protection Disabled

0140 74TC Trip Circuit Supervision Disabled

0142 49 Thermal Overload Protection Disabled

0144 Voltage transformers connected

0145 Protection Interface 1 (Port D) Enabled

0146 Protection Interface 2 (Port E) Disabled

0160 Line sections for fault locator 1 Line Section

(63)

2

General Device Settings

2.1

Group Device, General Settings

Group Device, General Settings

No. Settings Value Group

0610 Fault Display on LED / LCD Display Targets on every Pickup All

0625A Minimum hold time of latched LEDs 0 min All

0640 Start image Default Display image 1 All

(64)

3

Power System Data 1

3.1

Group Power System Data 1; Group Transformers

Group Power System Data 1; Group Transformers

0201 CT Starpoint towards Line All

0203 Rated Primary Voltage 33.0 kV All

0204 Rated Secondary Voltage (Ph-Ph) 110 V All

0205 CT Rated Primary Current 400 A All

0206 CT Rated Secondary Current 1A All

0210 V4 voltage transformer is not connected All

0211 Matching ratio Phase-VT To Open-Delta-VT 1.73 All

0220 I4 current transformer is Neutral Current (of the protected line) All

0221 Matching ratio I4/Iph for CT's 1.000 All

3.2

Group Power System Data 1; Group Power System

Group Power System Data 1; Group Power System

0207 System Starpoint is Solid Grounded All

0208A 1-1/2 Circuit breaker arrangement NO All

0230 Rated Frequency 50 Hz All

3.3

Group Power System Data 1; Group Breaker

Group Power System Data 1; Group Breaker

0240A Minimum TRIP Command Duration 0.10 sec All

0241A Maximum Close Command Duration 1.00 sec All

0242 Dead Time for CB test-autoreclosure 0.10 sec All

(65)

3.4

Group Power System Data 1; Group CT Data

Group Power System Data 1; Group CT Data

No. Settings Value Group

0251 k_alf/k_alf nominal 1.00 All

0253 CT Error in % at k_alf/k_alf nominal 5.0 % All

0254 CT Error in % at k_alf nominal 15.0 % All

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4

Settings groups

4.1

Group Power System Data 2; Group Local Line End

Group Power System Data 2; Group Local Line End

1103 Measurem:FullScaleVoltage(Equipm.rating) 33.0 kV A

1104 Measurem:FullScaleCurrent(Equipm.rating) 400 A A

1107 P,Q operational measured values sign not reversed A

4.2

Group Power System Data 2; Group Line Status

Group Power System Data 2; Group Line Status

1130A Pole Open Current Threshold 0.10 A A

1131A Pole Open Voltage Threshold 30 V A

1132A Seal-in Time after ALL closures 0.10 sec A

1133A minimal time for line open before SOTF 0.25 sec A

1134 Recognition of Line Closures with Current flow or Manual close BI A

1135 RESET of Trip Command with Pole Open Current Threshold only A

1136 open pole detector with measurement (V/I,trip, pickup, 52a A

1150A Seal-in Time after MANUAL closures 0.30 sec A

1151 Manual CLOSE COMMAND generation NO A

1152 MANUAL Closure Impulse after CONTROL <none> All

4.3

Group 87 Differential Protection; Group General

Group 87 Differential Protection; Group General

No. Settings Value Group

1201 State of differential protection ON A