Relay Setting Calculation rev.1.pdf

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DOCUMENT TITLE:

Relay setting calculations for the primary substation and Remote end grid stations REVISION NO.

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27-Feb-16

29-Feb-16

08-2015/E/1062/36 DEC PROJECT NO

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Dawood Engineering Consultancy

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Construction of 33/11kV, 3x20MVA Rusail-09 Primary Substation

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INDEX TITLE

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1.0

OBJECTIVE

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CONSIDERATIONS AND ASSUMPTIONS

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3.0

RELAY SETTING CALCULATION OF RUSAIL -09 PRIMARY SUBSTATION

5

3.1

415 V MCCB SETTING PHASE OVER CURRENT & EARTH FAULT PROTECTION OF 500KVA, 11/0.416 KV AUX. TRASFORMER FEEDER

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3.2

6

3.3

PHASE OVER CURRENT & EARTH FAULT PROTECTION OF 11KV SWITCHGEAR CAPACITOR BANK FEEDERS

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3.4

PHASE OVER CURRENT & EARTH FAULT PROTECTION OF 11KV SWITCHGEAR OUTGOING POWER FEEDERS

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3.5

PHASE OVER CURRENT & EARTH FAULT PROTECTION OF 11KV BUS COUPLER

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3.6

STAND-BY EARTH FAULT PROTECTION OF 33/11KV TRANSFORMER

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3.7

DIRECTIONAL PHASE OVER CURRENT & EARTH FAULT PROTECTION OF 11KV SWITCHGEAR INCOMER

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3.8

RESTRICTED EARTH FAULT PROTECTION OF 33/11KV , 20 MVA TRANSFORMER

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3.9

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

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3.10

PHASE OVER CURRENT & EARTH FAULT PROTECTION OF 20MVA, 33/11KV TRANSFORMER FEEDER

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3.11

PHASE OVER CURRENT & EARTH FAULT PROTECTION OF 33KV BUS COUPLER

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3.12

DIRECTIONAL PHASE OVER CURRENT & EARTH FAULT PROTECTION OF 33KV SWITCHGEAR INCOMER FEEDER

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3.13

LINE DIFFERENTIAL PROTECTION OF RUSAIL -02 33KV INCOMER(S) FROM RUSAIL GSS

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4.0

ANNEXURE -1 : OVER CURRENT PROTECTION COORDINATION

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5.0

ANNEXURE -2 : OC TIME CURRENT CHARACTERISTIC CURVE

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6.0

ANNEXURE -3 : EARTH FAULT PROTECTION COORDINATION

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7.0

ANNEXURE -4 : EF TIME CURRENT CHARACTERISTIC CURVE

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8.0

ANNEXURE -5 : SHORT CIRCUIT STUDY RESULTS

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9.0

ANNEXURE -6 : DIGSI FILES FOR SIEMENS RELAYS

10.0

ANNEXURE -7 : ATTACHMENTS

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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 Max 3 Phase/ 1 Phase Fault current at RUSAIL 132kV BUS (2017) Max 3 Phase Fault current at RUSAIL 33kV BUS (2017) Voltage Level -

= 22.4 / 28.82 kA = 21.53 kA = 33.0kV

Due to Y-D Transformer winding connections and earthing arrangement via earthing transformer, the 1-ph short circuit currents are limited to max. 1.5 KA

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.

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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 relay.

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3.0 RELAY SETTING CALCULATION OF RUSAYL-9 PSS 3.1 415 V MCCB SETTING

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 Rated Current (Side-2) : 666.69 A Connection : Delta (HV), Star (LV) Vector Group : Dyn11 4.75 % Transformer Percentage Impedance, Z % : 415 V system data 0.433 Nominal voltage, Un: KV 50 Rated short circuit current of 415 V BUS,Iscc (1 Sec) : KA 50 Nominal frequency: Hz 415 V MCCB data SIEMENS Make: 3WL1112-2FG48-5FM4 Type: 1250 A Rated Current : 415 V MCCB Settings (Similar for all 415 V INCOMER MCCB) LONG TIME (L) Current Setting = 666.69 / 1250 = 0.53335 Selected Pick-up current setting, (I>) = 0.90 A Time Setting 2.00 SEC = SHORT TIME (S) Selected Pick-up current setting, (I>) = 2.00 A Time Setting 0.30 SEC = INSTANTANEOUS (I) Instantaneous Function = Disabled GROUND FAULT (G) Current Setting = 0.20 * 1250 = 250 Selected Pick-up current setting, (I>) = 0.20 A Time Setting 0.30 SEC =

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3.0 RELAY SETTING CALCULATION OF RUSAYL-9 PSS 3.2 NON DIRECTIONAL PHASE & EARTH FAULT PROTECTION(50,51 &51N) OF 500KVA, 11/0.433 KV AUX. TRANS.

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 Rated Voltage: 11 / 0.433 KV Rated Current (Side-1) : 26.24 A Rated Current (Side-2) : 666.69 A Connection : Delta (HV), Star (LV) Vector Group : Dyn11 4.75 % Transformer Percentage Impedance, Z % : 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 718.23 / 200 Multiples of pickup current = = 3.59117 In Inrush current of the Transformer = 12 x Primary FLC [Assumed] = 12 x 26.24 = 314.92 A 314.92 / 200 Multiples of pickup current = = 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

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3.0 RELAY SETTING CALCULATION OF RUSAYL-9 PSS 3.2 NON DIRECTIONAL PHASE & EARTH FAULT PROTECTION(50,51 &51N) OF 500KVA, 11/0.433 KV AUX. TRANS.

Selected Pick-up current setting, (I>) = 0.16 A ( Actual Pick-up current = 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] TMS = 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 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 Io Setting = 0.2 In = TMS 0.05 Selected Pick-up current setting, (Io>) = 0.20 A ( Actual Pick-up current = / 216 Multiples of pickup current = 8640 40.00 = > then , Multiples of pickup current = 20 Selected Tripping Characteristics = SI (IEC Curve) Relay operating time = TMS {0.14/((I/Is)^0.02-1)} = 0.14 x TMS / [ ( 20 )^0.02 -1] Relay operating time = 0.11 Summary: Selected 51N Pick-up, (I>) = 0.2 A Selected Tripping Characteristics = SI Selected TMS = 0.05 Instantaneous Earth Fault Protection (50N) Instantaneous Earth Fault pickup current = 5 Times of 51N current pickup current = 5.00 x 0.20 = Summary: Selected Instantaneous Pick-up, (I>>) = 1.0 A Time Delay, td = 0.0 Sec Selected Tripping Characteristics = DMT

31.491833 A )

40

A)

20

1.00

In

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3.0 RELAY SETTING CALCULATION OF RUSAYL-9 PSS 3.3 NON DIRECTIONAL PHASE & EARTH FAULT PROTECTION (51 & 51N) OF 11 KV CAPACITOR BANK

Relay Type (Similar for all 11 kV Capacitor Bank Bays) 751A51 Make: SIEMENS Protection feature: Non Directional Phase Over Current and Earth Fault Protection Location: 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) Non Directional Phase Over Current Protection (51) 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 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 Selected Tripping Characteristics = SI (IEC Curve) Selected TMS = 0.05 (MDEC Practice) Multiples of pickup current = 14.6 / 341.25 = 42.7839 > Relay operating time = TMS {0.14/((I/Is)^0.02-1)} Relay Operating Time = 0.14 x 0.05/ [ ( 20 )^0.02 -1] Relay Operating Time = 0.11 Sec Summary: Selected 51 Pick-up, (I>) = 0.85 A Selected Tripping Characteristics = SI Selected TMS = 0.05 Instantaneous Setting = Blocked (MDEC Practice) Non Directional Earth Fault Protection (51N) 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 Selected Tripping Characteristics = SI (IEC Curve) Selected TMS = 0.05 (MDEC Practice) = Multiples of pickup current = 8.64 / 80 108 > then , Multiples of pickup current = 20 Relay operating time = TMS {0.14/((I/Is)^0.02-1)} Relay Operating Time = 0.14 x 0.05/ [ ( 20 )^0.02 -1] Relay Operating Time = 0.11 Sec

A)

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3.0 RELAY SETTING CALCULATION OF RUSAYL-9 PSS 3.3 NON DIRECTIONAL PHASE & EARTH FAULT PROTECTION (51 & 51N) OF 11 KV CAPACITOR BANK

Summary: Selected 51N Pick-up, (I>) Selected Tripping Characteristics Selected TMS Instantaneous Setting

= = = =

0.2 A SI 0.05 Blocked (MDEC Practice)

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3.0 RELAY SETTING CALCULATION OF RUSAYL-9 PSS 3.4 NON DIRECTIONAL PHASE & EARTH FAULT PROTECTION (51 & 51N) OF 11 KV OUTGOING FEEDERS

Relay Type (Similar for all 11 kV Outgoing Feeders Bays) 751A61 Make: SIEMENS Protection feature: Non Directional Phase Over Current and Earth Fault Protection Location: 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) Non Directional Phase Over Current Protection (51) 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 Selected Tripping Characteristics = SI (IEC Curve) Selected TMS = 0.05 (MDEC Practice) = Multiples of pickup current = 14.6 / 400 36.5 > Relay operating time = TMS {0.14/((I/Is)^0.02-1)} Relay Operating Time = 0.14 x 0.05/ [ ( 20.0 )^0.02 -1] Relay Operating Time = 0.1134 Sec Summary: Selected 51 Pick-up, (I>) = 1.0 A Selected Tripping Characteristics = SI Selected TMS = 0.05 OC High set Setting = 8 In (MDEC Practice) OC High set Clcs = Definite (MDEC Practice) OC High set Time = 0 Sec (MDEC Practice) Instantaneous Setting = Blocked (MDEC Practice) Non Directional Earth Fault Protection (51N) 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 Selected Tripping Characteristics = SI (IEC Curve) Selected TMS = 0.05 (MDEC Practice) = Multiples of pickup current = 8.64 / 80 108 > Relay operating time = TMS {0.14/((I/Is)^0.02-1)} Relay Operating Time = 0.14 x 0.05/ [ ( 20 )^0.02 -1] Relay Operating Time = 0.1134 Sec

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3.0 RELAY SETTING CALCULATION OF RUSAYL-9 PSS 3.4 NON DIRECTIONAL PHASE & EARTH FAULT PROTECTION (51 & 51N) OF 11 KV OUTGOING FEEDERS

Summary: Selected 51N Pick-up, (I>) Selected Tripping Characteristics Selected TMS EF High set Setting EF High set Clcs EF High set Time Instantaneous Setting A/R setting : No. of shots Dead Time for first shot Reset Time For reclose cycle Reset Time Form Lock Out Dead Time for 2 to 4th Shot

= = = = = = =

0.2 SI 0.05 1.6 In Definite 0 Sec Blocked

= = = = =

1 180 Sec 60 Sec 60 Sec Infinite

A

(MDEC Practice) (MDEC Practice) (MDEC Practice) (MDEC Practice)

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

Relay Type (Similar for all 11 kV Bus coupler Bays) 751A51 Make: SIEMENS Protection feature: Non Directional Phase Over Current and Earth Fault Protection Location: 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) Non Directional Phase Over Current Protection (51) 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 Selected Pick-up current setting, (I>) = 0.88 A ( Actual Pick-up current = 1050 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) Operating time desired = 0.36 Sec Relay operating time = TMS {0.14/((I/Is)^0.02-1)} 0.36 = 0.14 x TMS / [ ( 6.9 )^0.02 -1] TMS = 0.10 Summary: Selected 51 Pick-up, (I>) = 0.88 A Selected Tripping Characteristics = SI Selected TMS = 0.10 Instantaneous Setting = Blocked (MDEC Practice) Non Directional Earth Fault Protection (51N) 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 240 A) Selected Pick-up current setting, (Ie>) = 0.20 A ( Actual Pick-up current = = 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) Operating time desired = 0.36 Sec Relay operating time = TMS {0.14/((I/Is)^0.02-1)} 0.36 = 0.14 x TMS / [ ( 7 )^0.02 -1] TMS = 0.10

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Summary: Selected 51 Pick-up, (I>) Selected Tripping Characteristics Selected TMS Instantaneous Setting

= = = =

0.2 A SI 0.10 Blocked (MDEC Practice)

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3.0 RELAY SETTING CALCULATION OF RUSAYL-9 PSS 3.6 STAND-BY EARTH FAULT PROTECTION (51G) OF 33/11 KV TRANSFORMER

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 Voltage: 33 / 11.5 KV Rated Current (HV) : 349.91 A Rated Current (LV) : 1004.09 A Connection : Delta (HV), Star (LV) Vector Group : Dyn11 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 Selected Pick-up current setting, (Ie>) = 0.20 A ( Actual Pick-up current = 240 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) Operating time desired = 0.91 Sec Relay operating time = TMS {0.14/((I/Is)^0.02-1)} 0.91 = 0.14 x TMS / [ ( 20 )^0.02 -1] TMS = 0.403 Summary: Selected Pick-up, (I>) = 0.2 A Selected Tripping Characteristics = SI Selected TMS = 0.40 Instantaneous Setting = Blocked (MDEC Practice)

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3.0 RELAY SETTING CALCULATION OF RUSAYL-9 PSS 3.7 DIRECTIONAL PHASE & EARTH FAULT PROTECTION (67 & 67N) OF 11KV SWITCHGEAR INCOMER

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) Rated Power(ONAN/ONAF) : 20 MVA Transformer Cooling ONAF/ONAN Rated Voltage: 33 / 11.5 KV Rated Current (HV) : 349.91 A Rated Current (LV) : 1004.09 A Connection : Delta (HV), Star (LV) Vector Group : Dyn11 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 600 A) Selected Pick-up current setting, (I>) = 0.50 A ( Actual Pick-up current = Since the 67 Relay will operate only when both transformers will be in parallel and as per short circuit study KA the fault contribution (total) when both 20 MVA transformers are in parallel = 14.6 7.3 KA Contribution of each transformer (fault seen by 67 relay CT) = 14.6 /2 = Selected Tripping Characteristics = SI (IEC Curve) = Multiples of pickup current = 7300 / 600 12.1667 ˂ 20 Operating time desired = 0.30 Sec Relay operating time = TMS {0.14/((I/Is)^0.02-1)} 0.30 = 0.14 x TMS / [ ( 12 )^0.02 -1] TMS = 0.1 Summary: Selected 67 Pick-up, (I>) = 0.5 A Selected Tripping Characteristics = SI Selected TMS = 0.1 Instantaneous Setting = Blocked (MDEC Practice) Direction of operation = Forward ( TowardsTransformer) ◦ RCA Recommended = 45.0 Directional Earth Fault Protection (67N) Directional Earth Fault current Pick-up = = = Selected Pick-up current setting, (Ie>) =

20% (

0.20

0.20 0.20

of the CT Ratio x 1200.00 ) ÷ A A ( Actual Pick-up current =

1200 240

A)

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Since the 67 Relay will operate only when both transformers will be in parallel and as per short circuit study KA the fault contribution (total) when both 20 MVA transformers are in parallel = 15.86 7.93 KA Contribution of each transformer (fault seen by 67 relay CT) = 15.86 /2 = Selected Tripping Characteristics = SI (IEC Curve) = Multiples of pickup current = 7930 / 240 33.0417 > 20 Selected TMS = 0.05 (MDEC Practice) Relay Operating Time = TMS {0.14/((I/Is)^0.02-1)} Relay Operating Time = 0.14 x 0.05/ [ ( 20 )^0.02 -1] Relay Operating Time = 0.1134 Sec Summary: Selected 67 Pick-up, (I>) = 0.20 A Selected Tripping Characteristics = SI Selected TMS = 0.05 Instantaneous Setting = Blocked (MDEC Practice) 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 Selected Pick-up current setting, (I>) = 1.00 A ( Actual Pick-up current = 1200 A) Selected Tripping Characteristics = SI (IEC Curve) = 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 Relay operating time = TMS {0.14/((I/Is)^0.02-1)} 0.61 = 0.14 x TMS / [ ( 7 )^0.02 -1] TMS = 0.17 Summary: Selected 51 Pick-up, (I>) = 1.0 A Selected Tripping Characteristics = SI Selected TMS = 0.17 Instantaneous Setting = Blocked (MDEC Practice) Non Directional Earth Fault Protection (51N) 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 0.20 A ( Actual Pick-up current = 240 A) Selected Pick-up current setting, (Ie>) =

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= SI (IEC Curve) Selected Tripping Characteristics = Multiples of pickup current = 8640 / 240 36 > Operating time desired = Operating time of 11 Kvbus coupler + 0.25 Sec [Grading Margin] = 0.61 Sec Relay operating time = TMS {0.14/((I/Is)^0.02-1)} 0.61 = 0.14 x TMS / [ ( 20 )^0.02 -1] TMS = 0.27 Summary: Selected 67 Pick-up, (I>) = 0.20 A Selected Tripping Characteristics = SI Selected TMS = 0.27 Instantaneous Setting = Blocked (MDEC Practice)

20

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3.0 RRELAY SETTING CALCULATION OF RUSAYL-9 PSS 3.8 RESTRICTED EARTH FAULT PROTECTION (87NL) OF 33/11k,20MVA TRANSFORMER SECONDARY SIDE

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) Rated Power(ONAN/ONAF) : 20 MVA Transformer Cooling ONAF/ONAN Rated Voltage: 33 / 11.5 KV Rated Current (HV) : 349.91 A Rated Current (LV) : 1004.09 A Connection : Delta (HV), Star (LV) Vector Group : Dyn11 12.50 % Transformer Percentage Impedance, Z % : 7.5 Impedance Tolerance Considered : ± % [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: 1200 / 1 A 1200 / 1 A CT Ratio: CT Ratio: X X Class: Class: 350 V 350 V Knee Point Voltage: Knee Point Voltage CT mag. Current @ Vk/2 30 mA CT mag. Current @ Vk 30 mA 6 Ohms 6 Ohms CT secondary resistance Rct: CT secondary resistance Rct: 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: (Requirement) Vknee ≥ 2 * Vs 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 Ri : CT secondary winding Resistance longest cable loop resistance Rlead :

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CALCULATION OF CABLE BURDEN: Wire burden: Length 11 KV Side: lwire =

10

m

lwire =

100

a wire =

4

m mm 2

0.00461

Ohms /m

Netural Side: Cross-section As per vendor catalogue Resistance (Cu)@20 ◦C

Rcu20 = ◦

Temperature coefficient α per C Resistance (Cu)@75 ◦C Eff. Wire length p.u.

= 0.00393 Rcu75 = pcu20 x (1+ α (75-20)) pcu75= 0.00561 k= 2 Rwire = k* lwire * Rcu75

Ohms /m

For 11 KV Side: Rshortest loop =

0.1121

Ohm

For Neutral Side: 1.1213 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 = 2 * Vs =

V 123.683 V 350

Meets Requirement CTs correctly dimensioned

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The CT knee-point voltage of 350 V exceeds the selected stabilizing voltage of 62 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

V

I P = I p/I s *[Is, min +n * Iknee*(Vs/Vknee)+Ivar] where: Ip :

Is,min : N: I knee : Vs : V knee : Ivar :

Maximum primary current sensitivity 0.2 Minimum relay current setting ( Number of CTs in parallel with relay ( 4 0.03 Mag. current Iknee at Uknee ( 61.84128033 Actual stability voltage ( Knee point voltage of CT ( 350 Current in non-linear resistor at the relay circuit setting voltage, calculated as follows:

A)

Considered

) A) V) V)

Ivar = 0.52 * [ (√2 *Vs ) / C]^1/ᵦ for the varistor consider C = 900 and β = 0.25 Ivar = 0.05 mA

( MEDC practice)

0.00005 ) IP = 1200 * ( 0.200 + 0.04241 + 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 * (I sn/I pn) - n * I knee*(Vs /Vknee)-I var where: Is : secondary relay current setting to reach the desired sensitivity 251.021856 A ) Ip,des : desired current sensitivity of object ( 0.000046 ] Is = [ 0.20918 0.04241 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= Stabilizing Resistor Calculation (Rstab)

0.20

A

The stabilizing resistor Rstab to ensure protection stability is: Rstab = Vs / Is / 0.20 Rstab = 62 Rstab = 309.206 Ω 309.2064016 Ω [ Available range is 0 - 1000 Ω] Therefore Stabilising resistor Rstab 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 ≥ ( Vs 2 / Rstab )

≥ [ Pstab,cont ≥

Pstab,cont

3824.34

/

12.3683

W

309.21

]

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 = 723.5043 V The resulting short-time rating Pstab,0.5s equals to: = 1692.90973 W Pstab,0.5s ≥ ( Vrms 2 /Rstab ) 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: 6 R CT = CT Internal Resistance : Ω 309.2064016 R stab = Stabilizing Resistor : Ω RL = One way CT lead resistance : 0.56064515 Ω Ifmax = Maximum secondary external fault current : 8683.999349 A 350 V Vk = Knee point voltage of the CT : 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 { If x Vk / CT ratio} P = ( 4 / 3.14) x { 8684 x 350 / 1200 } P= P=

3224.9 3.2249

J/S KJ/S

Select a metrosil with C=900 , β= 0.25 SUMMARY OF HIGH IMPEDANCE REF PROTECTION SETTINGS Rstab = 309.206402 Is = 0.20

Ω A

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

CT1 400/1 A

CT2 1200/1 A

SN = 20 MVA 11 KV

33 KV

I2

I1

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) Rated Power(ONAN/ONAF) : 20 MVA Transformer Cooling ONAF/ONAN Rated Voltage: 33 / 11.5 KV Rated Current (HV) : 349.91 A Rated Current (LV) : 1004.09 A Connection : Delta (HV), Star (LV) Vector Group : Dyn11 Taps available @Transformer Primary: - 15% to 5% in steps of 1.67% NO. of Taps w/o Center Tap 12.00 34.65 KV HV @ Highest tap position for +10% tap (Umax) : 28.05 KV HV @ Lowest tap position for -10% tap (Umin): 12.50 % Transformer Percentage Impedance, Z % : 7.5 Impedance Tolerance Considered : ± % [IEC tolerance] Therefore Transformer Percentage Impedance, (Z%): 11.56 % CT Ratios for Differential Protection (Similar for all 33 kV Transformer Bays) HV 33 KV Transformer Feeder CT: 400 / 1 A Class: X 1200 / 1 A X LV 11.5 KV Transformer Feeder CT: Class: 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. INObj SIDE 1 = SN/(√3.VN SIDE 1)

20MVA/(√3x 33.00 KV) = INObj SIDE 1 = 349.91 Amps

=

349.909

Amps

INObj SIDE 2 = SN/(√3.VN SIDE 2)

=

20MVA/(√3x 11.5 KV)

=

1004.09

Amps

INObj SIDE 2 = Where:

SN : INObj SIDE 1,2 : VN SIDE 1,2 :

1004.09

Amps

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

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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 10.53% Tap change regulation = (1) Tap changer regulation Error: Max. Full load Current of the Transformer @ Center Tap = INObj,tap0 = INObj1 = 372.45243 A INObj1 @ the CT1 Secondary Side = ( IN,tap0 / CT1 ratio ) = ( 372.452 / 400 ) INObj1 @ the CT1 Secondary Side = 0.931131068 A INObj1 = 0.931131 A The rated current of the Transformer @ unregulated Side INObj2 = 1004.087 A INObj2 @ the CT2 Secondary Side = ( INObj2 / CT2 ratio ) = ( 1004.09 / 1200 ) INObj2 @ the CT2 Secondary Side = 0.84 INObj2 = 0.83674 A INObj2 =

0.83674

INObj

( remains Constant)

A

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Max. Full load Current of the Transformer @ Max. Tap = INObj,tap+ = INObj1 (+ 5%) = INObj1(+5%) @ the CT1 Secondary Side = ( INObj,tap+ / CT1 ratio ) = ( 333.247 / 400 ) INObj1 (+5%)@ the CT1 Secondary Side = 0.833117272 0.833117 A INObj1 (+5%) = INObj1 (+5%) =

0.894737

1.105263

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

INObj

|

IRest = IDIFF = IDIFF =

INObj1

A

0.105263 INObj1

1.894737 INObj1

|

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

0.098

INObj

|

2.105263

0.105263 INObj1

(3)

Restraint Current @ Min. Tap IRest = |INObj1(-15%) + INObj1|= IRest =

A

INObj

1.76

Diff. Current @ Min. Tap IDIFF =

1.894737

411.65795

(2)

Restraint Current @ Max. Tap IRest = |INObj1(+5%) + INObj1|= IRest =

A

INObj

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

0.10

A

INObj

Max. Full load Current of the Transformer @ Min. Tap = INObj,tap- = INObj1 (- 15%) = INObj1(-15%)@ the CT1 Secondary Side = ( INObj,tap- / CT1 ratio ) = ( 411.658 / 400 ) INObj1 (-15%)@ the CT1 Secondary Side = 1.029144865 INObj1 (-15%) = 1.029145 A INObj1 (-15%) =

333.24691

INObj1

2.105263 INObj1

|

INObj IRest = 1.96 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 = IN/INObj 0.2

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.

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CALCULATION OF HIGH SET TRIP : short circuit MVA of the transformer = Transformer MVA ÷ %Z = 20.00 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] 2799.274 Fault current as referred to 33 KV = 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)

÷

12.50

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) CT errors

= =

20% 5%

[ +5% and -15%] (Assumed)

Hence the Recommended Slope-1 setting =

25%

SLOPE 1 = 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 SLOPE 2 =

50%

and BASE POINT 2 =

2.5

IN/INObj

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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%

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3.0 RELAY SETTING CALCULATION OF RUSAYL-9 PSS 3.10 NON DIRECTIONAL PHASE & EARTH FAULT PROTECTION(50,51 &51N)of 20MVA, 33/11 KV TRANSFORMER

Relay Type (Similar for all 33 kV Transformer Bays) 7SJ8021 Make: SIEMENS Protection feature: Non Directional Phase Over Current and Earth Fault Protection Location: 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 Rated Voltage: 33 / 11.5 KV Rated Current (HV) : 349.91 A Connection : Delta (HV), Star (LV) Vector Group : Dyn11 12.50 % Transformer Percentage Impedance, Z % : 7.5 Impedance Tolerance Considered : ± % [IEC tolerance] Therefore Transformer Percentage Impedance, (Z%): 11.56 % 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] 3026.242 Fault current as referred to 33 KV = 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: Selected Instantaneous Pick-up, (I>>) = 11.0 A Time Delay, td = 0.0 Sec Selected Tripping Characteristics = DMT Non Directional Phase Over Current Protection (51) Phase over current Pick-up = 110% of the Transformer full load current = ( 1.10 x 349.91 ) ÷ 400 = 0.96 A

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3.0 RELAY SETTING CALCULATION OF RUSAYL-9 PSS 3.10 NON DIRECTIONAL PHASE & EARTH FAULT PROTECTION(50,51 &51N)of 20MVA, 33/11 KV TRANSFORMER

Selected Pick-up current setting, (I>) = 1.0 A ( Actual Pick-up current = 400 A ) = 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) Operating time desired = 0.61 Sec Relay operating time = TMS {0.14/((I/Is)^0.02-1)} 0.61 = 0.14 x TMS / [ ( 8 )^0.02 -1] = 0.18 TMS 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 0.18 0.18 / [( 4.15692 )^0.02 -1] = 0.88 Sec Hence required grading is achieved Summary: Selected Pick-up, (I>) = 1.0 A Selected Tripping Characteristics = SI Selected TMS = 0.18 Non Directional Earth Fault Protection (51N) 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) Selected Tripping Characteristics = SI (IEC Curve) = Multiples of pickup current = 1480 / 80 18.5 ˂ 20 Operating time desired = 0.61 Sec Relay operating time = TMS {0.14/((I/Is)^0.02-1)} 0.61 = 0.14 x TMS / [ ( 19 )^0.02 -1] TMS = 0.05 Summary: Selected 51N Pick-up, (I>) = 0.2 A Selected Tripping Characteristics = SI Selected TMS = 0.05 Instantaneous Setting = 6 A

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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) Non Directional Phase Over Current Protection (51) 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 Selected Pick-up current setting, (I>) = 0.29 A ( Actual Pick-up current = 350 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 Selected Tripping Characteristics = SI (IEC Curve) Operating time desired = 0.86 Sec Relay operating time = TMS {0.14/((I/Is)^0.02-1)} 0.86 = 0.14 x TMS / [ ( 20 )^0.02 -1] TMS = 0.43 Summary: Selected Pick-up, (I>) = 0.29 A Selected Tripping Characteristics = SI , Selected TMS = 0.43 Instantaneous Setting = Blocked (MDEC Practice) Non Directional Earth Fault Protection (51N) 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 Selected Pick-up current setting, (Ie>) = 0.20 A ( Actual Pick-up current = 240 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) Operating time desired = 0.86 Sec

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Relay operating time 0.86

=

Summary: Selected Pick-up, (I>) Selected Tripping Characteristics Instantaneous Setting

= TMS {0.14/((I/Is)^0.02-1)} 0.14 x TMS / [ ( 3 )^0.02 -1] TMS = 0.13 = = =

0.20 A SI , Selected TMS Blocked (MDEC Practice)

=

0.13

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3.0 RELAY SETTING CALCULATION OF RUSAYL-9 PSS 3.12 DIR. AND NON DIR. PHASE & EARTH FAULT PROTECTION (67 /67N/51&51N) OF 33 KV RUSAYL FEEDER

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 Selected Pick-up current setting, (I>) = 0.50 A ( Actual Pick-up current = 200 A ) = Multiples of pickup current = 21100 / 200 105.5 > 20 Selected Tripping Characteristics = SI (IEC Curve) Operating time desired = 0.10 Sec Relay operating time = TMS {0.14/((I/Is)^0.02-1)} 0.10 = 0.14 x TMS / [ ( 20 )^0.02 -1] TMS = 0.04 Summary: Selected 67 Pick-up, (I>) = 0.5 A Selected Tripping Characteristics = SI Selected TMS = 0.050 Instantaneous Setting = Blocked (MDEC Practice) 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 Selected Pick-up current setting, (Ie>) = 0.20 A ( Actual Pick-up current = 80 = Multiples of pickup current = 1480 / 80 18.5 ˂ Selected Tripping Characteristics = SI (IEC Curve) Operating time desired = 0.10 Sec Relay operating time = TMS {0.14/((I/Is)^0.02-1)} 0.10 = 0.14 x TMS / [ ( 19 )^0.02 -1] TMS = 0.04 Summary: Selected 67N Pick-up, (I>) = 0.2 A Selected Tripping Characteristics = SI Selected TMS = 0.05 Direction of operation = Forward ( Towards Feeder) RCA Recommended

=

- 45.0

◦

A A)

20

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Non Directional Phase Over Current Protection (51) 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 ) = Multiples of pickup current = 21100 / 400 52.75 > 20 Selected Tripping Characteristics = SI (IEC Curve) 33 KV Feeder EF Relay operating time = 33 KV BC Relay Operating Time + Grading Margin [0.25] Operating time desired = 1.11 Sec Relay operating time = TMS {0.14/((I/Is)^0.02-1)} 1.11 = 0.14 x TMS / [ ( 20 )^0.02 -1] TMS = 0.49 Summary: Selected 51 Pick-up, (I>) = 1.0 A Selected Tripping Characteristics = SI Selected TMS = 0.49 Instantaneous Setting = Blocked (MDEC Practice) Non Directional Earth Fault Protection (51N) 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) = Multiples of pickup current = 1480 / 80 18.5 ˂ 20 Selected Tripping Characteristics = SI (IEC Curve) 33 KV Feeder EF Relay operating time = 33 KV BC Relay Operating Time + Grading Margin [0.25] Operating time desired = 1.11 Sec Relay operating time = TMS {0.14/((I/Is)^0.02-1)} 1.11 = 0.14 x TMS / [ ( 19 )^0.02 -1] TMS = 0.48 Summary: Selected 51N Pick-up, (I>) = 0.2 A Selected Tripping Characteristics = SI Selected TMS = 0.48 Remote end setting 33 Incomer Feeder CT: 400 / 1 A Class: 5P20 Non Directional Phase Over Current Protection (51) 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 ) = Multiples of pickup current = 21100 / 400 52.75 > 20 = SI (IEC Curve) Selected Tripping Characteristics

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33 KV Remote Relay operating time = 33 KV Incomer Relay Operating Time + Grading Margin [0.25] = 1.11 + 0.25 = 1.36 Sec Relay operating time = TMS {0.14/((I/Is)^0.02-1)} 0.14 x TMS / [ ( 20 )^0.02 -1] 1.36 = TMS = 0.60 Summary: Selected 51 Pick-up, (I>) = 1.0 A Selected Tripping Characteristics = SI Selected TMS = 0.60 Instantaneous Setting = Blocked (MDEC Practice) Non Directional Earth Fault Protection (51N) 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) = Multiples of pickup current = 1480 / 80 18.5 ˂ 20 Selected Tripping Characteristics = SI (IEC Curve) 33 KV Remote Relay operating time = 33 KV Incomer Relay Operating Time + Grading Margin [0.25] = 1.11 + 0.25 = 1.36 Sec Relay operating time = TMS {0.14/((I/Is)^0.02-1)} 1.36 = 0.14 x TMS / [ ( 19 )^0.02 -1] = 0.59 TMS Summary: Selected 51N Pick-up, (I>) = 0.2 A Selected Tripping Characteristics = SI Selected TMS = 0.59

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3.0 RELAY SETTING CALCULATION OF RUSAYL-9 PSS 3.13 LINE DIFFERENTIAL PROTECTION (87L) OF 33 KV INCOMER(S) FROM RUSAYL GSS

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.

ANNEXURE – 6 DIGSI FILES FOR SIEMENS RELAYS

7SD522 V4_7_prn

SIMATIC

Rusayl PSS / Incomer / 7SD522 V4.7/7SD522

28.02.16 22:03:41

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

PRINT - CONTENTS 1 2 2.1 3 3.1 3.2 3.3 3.4 4 4.1 4.2 4.3 4.4 4.5 4.6 4.7 4.8 4.9 4.10 4.11 4.12 4.13 4.14

Device Configuration .................................................................................................................................................................2 General Device Settings ...........................................................................................................................................................3 Group Device, General Settings ...............................................................................................................................................3 Power System Data 1 ...............................................................................................................................................................4 Group Power System Data 1; Group Transformers .................................................................................................................. 4 Group Power System Data 1; Group Power System ................................................................................................................ 4 Group Power System Data 1; Group Breaker ........................................................................................................................... 4 Group Power System Data 1; Group CT Data .......................................................................................................................... 5 Settings groups .........................................................................................................................................................................6 Group Power System Data 2; Group Local Line End ................................................................................................................ 6 Group Power System Data 2; Group Line Status ..................................................................................................................... 6 Group 87 Differential Protection; Group General ...................................................................................................................... 6 Group 87 Differential Protection; Group 87 Diff. Prot. ............................................................................................................... 7 Group 87 Differential Protection; Group Inrush ......................................................................................................................... 7 Group Intertrip ...........................................................................................................................................................................7 Group Measurement Supervision; Group Symmetry ................................................................................................................ 8 Group Measurement Supervision; Group Meas.Volt.Fail .......................................................................................................... 8 Group Measurement Supervision; Group I/U-Monitoring .......................................................................................................... 8 Group Measurement Supervision; Group VT mcb .................................................................................................................... 9 Group Measurement Supervision; Group Load Angle .............................................................................................................. 9 Group Protection Interface (Port D+E); Group General ............................................................................................................ 9 Group Protection Interface (Port D+E); Group Interface 1 ........................................................................................................ 9 Group Differential Topology ....................................................................................................................................................10

Page 1 of 10

7SD522 V4_7_prn Device Configuration Rusayl PSS / Incomer / 7SD522 V4.7/7SD522

SIMATIC

28.02.16 22:03:41

Device Configuration

1 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

Page 2 of 10

7SD522 V4_7_prn General Device Settings Rusayl PSS / Incomer / 7SD522 V4.7/7SD522

SIMATIC 2

General Device Settings

2.1

Group Device, General Settings

28.02.16 22:03:41

Group Device, General Settings No. 0610

Settings Fault Display on LED / LCD

Value

Group

Display Targets on every Pickup

All

0625A Minimum hold time of latched LEDs

0 min

All

0640

image 1

All

Start image Default Display

Page 3 of 10

7SD522 V4_7_prn Power System Data 1 Rusayl PSS / Incomer / 7SD522 V4.7/7SD522

SIMATIC 3

Power System Data 1

3.1

Group Power System Data 1; Group Transformers

28.02.16 22:03:41

Group Power System Data 1; Group Transformers No.

Settings

Value

Group

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 No. 0207

Settings System Starpoint is

Value

Group

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 No.

Settings

Value

Group

0240A Minimum TRIP Command Duration

0.10 sec All

0241A Maximum Close Command Duration

1.00 sec All

0242

0.10 sec All

Dead Time for CB test-autoreclosure

Page 4 of 10

7SD522 V4_7_prn Group Power System Data 1; Group CT Data Rusayl PSS / Incomer / 7SD522 V4.7/7SD522 SIMATIC 3.4

28.02.16 22:03:41

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

Page 5 of 10

7SD522 V4_7_prn Settings groups Rusayl PSS / Incomer / 7SD522 V4.7/7SD522

SIMATIC 4

Settings groups

4.1

Group Power System Data 2; Group Local Line End

28.02.16 22:03:41

Group Power System Data 2; Group Local Line End No.

Settings

Value

Group

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 No.

Settings

Value

Group

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

All

4.3

Group 87 Differential Protection; Group General

Group 87 Differential Protection; Group General No.

Settings

1201 State of differential protection

Value Group ON

A

Page 6 of 10

7SD522 V4_7_prn Group 87 Differential Protection; Group 87 Diff. Prot. Rusayl PSS / Incomer / 7SD522 V4.7/7SD522 SIMATIC 4.4

28.02.16 22:03:41

Group 87 Differential Protection; Group 87 Diff. Prot.

Group 87 Differential Protection; Group 87 Diff. Prot. No.

Settings

Value

Group

1210

87-1 Pickup

0.20 A

A

1213

87-1 Value under switch on condition

0.20 A

A

1217A 87-1 Trip time delay

0.00 sec A

1219A 87-1 Min. local current to release Trip

0.00 A

A

1233

87-2 Pickup

1.0 A

A

1235

87-2 Value under switch on condition

1.0 A

A

4.5

Group 87 Differential Protection; Group Inrush

Group 87 Differential Protection; Group Inrush No.

Settings

Value

Group

2301 Inrush Restraint

OFF

A

2302 2nd. harmonic in % of fundamental

15 %

A

2303 Cross Block

NO

A

2305 Maximum inrush-peak value

15.0 A

A

2310 Time for Crossblock with 2nd harmonic

0.00 sec A

4.6

Group Intertrip

Group Intertrip No.

Settings

Value

Group

1301 State of transmit. the intertrip command

NO

A

1302 Reaction if intertrip command is receiv.

Trip

A

1303 Delay for intertrip via binary input

0.02 sec A

1304 Prolongation for intertrip via bin.input

0.00 sec A

Page 7 of 10

7SD522 V4_7_prn Group Measurement Supervision; Group Symmetry Rusayl PSS / Incomer / 7SD522 V4.7/7SD522 SIMATIC 4.7

28.02.16 22:03:41

Group Measurement Supervision; Group Symmetry

Group Measurement Supervision; Group Symmetry No.

Settings

2901

Measurement Supervision

Value Group ON

A

2902A Voltage Threshold for Balance Monitoring

50 V

A

2903A Balance Factor for Voltage Monitor

0.75

A

2904A Current Threshold for Balance Monitoring

0.50 A A

2905A Balance Factor for Current Monitor

0.50

A

2908A T Balance Factor for Voltage Monitor

5 sec

A

2909A T Current Balance Monitor

5 sec

A

4.8

Group Measurement Supervision; Group Meas.Volt.Fail

Group Measurement Supervision; Group Meas.Volt.Fail No. 2910

Settings Fuse Failure Monitor

Value

Group

ON

A

2911A Minimum Voltage Threshold V>

30 V

A

2912A Maximum Current Threshold I<

0.10 A

A

2913A Maximum Voltage Threshold V< (3phase)

15 V

A

2914A Differential Current Threshold (3phase)

0.10 A

A

2915

with current supervision

A

3.00 sec

A

Voltage Failure Supervision

2916A Delay Voltage Failure Supervision

4.9

Group Measurement Supervision; Group I/U-Monitoring

Group Measurement Supervision; Group I/U-Monitoring No.

Settings

Value Group

2931

Fast broken current-wire supervision

OFF

A

2933

State of fast current summation supervis

ON

A

2906A Summated Current Monitoring Threshold

0.25 A A

2907A Summated Current Monitoring Factor

0.50

A

Page 8 of 10

7SD522 V4_7_prn Group Measurement Supervision; Group VT mcb Rusayl PSS / Incomer / 7SD522 V4.7/7SD522 SIMATIC 4.10

28.02.16 22:03:41

Group Measurement Supervision; Group VT mcb

Group Measurement Supervision; Group VT mcb No.

Settings

Value Group

2921 VT mcb operating time

4.11

0 ms

A

Group Measurement Supervision; Group Load Angle

Group Measurement Supervision; Group Load Angle No.

Settings

Value Group

2941 Limit setting PhiA

200 °

A

2942 Limit setting PhiB

340 °

A

2943 Minimum value I1>

0.05 A A

2944 Minimum value U1> 20 V

4.12

A

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

Group Protection Interface (Port D+E); Group General No.

Settings

Value

Group

4509 Time delay for data disturbance alarm

0.10 sec A

4510 Time delay for transmiss. failure alarm

6.0 sec

4512 Remote signal RESET DELAY for comm.fail

0.00 sec A

4.13

A

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

Group Protection Interface (Port D+E); Group Interface 1 No.

Settings

Value

Group

4501

State of protection interface 1

ON

A

4502

Connection 1 via

Direct connection with fiber optic cable

A

4505A Prot 1: Maximal permissible delay time

30.0 ms

A

4506A Prot 1: Diff. in send and receive time

0.100 ms

A

4513A Prot 1: Maximal permissible error rate

1.0 %

A

4515A Prot.1: Block. due to unsym. delay time

YES

A

Page 9 of 10

7SD522 V4_7_prn Group Protection Interface (Port D+E); Group Interface 1 Rusayl PSS / Incomer / 7SD522 V4.7/7SD522 SIMATIC

4.14

28.02.16 22:03:41

Group Differential Topology

Group Differential Topology No.

Settings

Value Group

4701 Identification number of relay 1

1

A

4702 Identification number of relay 2

2

A

4710 Local relay is

relay 1 A

Page 10 of 10

7SJ804 V4_6_prn

SIMATIC

Rusayl PSS / Incomer / 7SJ804 V4.6/7SJ804

28.02.16 22:10:06

Rusayl PSS / Incomer / 7SJ804 V4.6 MLFB: 7SJ80415*B901FC0 Parameter set version: V04.61.06 Device path: C:\Siemens\Digsi4\D4PROJ\Rusayl_P\P7DI\GV\SD\00000002 Author: Creation date: 24.02.16 20:59:38 Last modified: 28.02.16 22:07:49 Operating mode: Offline Comment: Setting values in: Secondary value description

PRINT - CONTENTS 1 2 2.1 3 3.1 3.2 3.3 3.4 3.5 3.6 4 4.1 4.2 4.3 4.4 4.5 4.6 4.7 4.8 4.9 4.10 4.11 4.12 4.13 4.14 4.15 4.16

Device Configuration .................................................................................................................................................................2 General Device Settings ...........................................................................................................................................................3 Group Device, General Settings; Group General ...................................................................................................................... 3 Power System Data 1 ...............................................................................................................................................................4 Group Power System Data 1; Group Power System ................................................................................................................ 4 Group Power System Data 1; Group Prot.Op. quant. ............................................................................................................... 4 Group Power System Data 1; Group CT's ................................................................................................................................ 4 Group Power System Data 1; Group VT's ................................................................................................................................ 5 Group Power System Data 1; Group Breaker ........................................................................................................................... 5 Group Power System Data 1; Group Threshold BI ................................................................................................................... 5 Settings groups .........................................................................................................................................................................6 Group Power System Data 2; Group General ........................................................................................................................... 6 Group 50/51 Phase/Ground Overcurrent; Group General ........................................................................................................ 6 Group 50/51 Phase/Ground Overcurrent; Group 50 ................................................................................................................. 6 Group 50/51 Phase/Ground Overcurrent; Group 51 ................................................................................................................. 7 Group 50/51 Phase/Ground Overcurrent; Group 50N .............................................................................................................. 7 Group 50/51 Phase/Ground Overcurrent; Group 51N .............................................................................................................. 8 Group 67 Directional Phase/Ground Overcurrent; Group General ........................................................................................... 8 Group 67 Directional Phase/Ground Overcurrent; Group 67 .................................................................................................... 8 Group 67 Directional Phase/Ground Overcurrent; Group 67-TOC ........................................................................................... 9 Group 67 Directional Phase/Ground Overcurrent; Group 67N .................................................................................................. 9 Group 67 Directional Phase/Ground Overcurrent; Group 67N-TOC ......................................................................................... 9 Group Measurement Supervision; Group General .................................................................................................................. 10 Group Measurement Supervision; Group MeasSupervision ................................................................................................... 10 Group Measurement Supervision; Group Fuse Fail Mon. ....................................................................................................... 10 Group Measurement Supervision; Group VT broken wire ...................................................................................................... 11 Group Energy; Group Measurement ....................................................................................................................................... 11

Page 1 of 11

7SJ804 V4_6_prn Device Configuration Rusayl PSS / Incomer / 7SJ804 V4.6/7SJ804

SIMATIC

28.02.16 22:10:06


1 No.

Function

Scope


Disabled

0104 Oscillographic Fault Records

Enabled

0112 50/51

Time Overcurrent Curve IEC

0113 50N/51N


0115 67, 67-TOC


0116 67N, 67N-TOC


0117 Cold Load Pickup

Disabled

0122 2nd Harmonic Inrush Restraint

Disabled

0131 (sensitive) Ground fault

Disabled

0130 (sens.) Ground fault dir. characteristic

cos phi / sin phi measurement (standard)

0140 46 Negative Sequence Protection

Disabled


Disabled

0150 27, 59 Under/Overvoltage Protection

Disabled

0154 81 Over/Underfrequency Protection

Disabled


Disabled

0172 52 Breaker Wear Monitoring

Disabled


Disabled

0192 Capacitive voltage measurement

NO

Flexible Function

Page 2 of 11

7SJ804 V4_6_prn General Device Settings Rusayl PSS / Incomer / 7SJ804 V4.6/7SJ804

SIMATIC 2


2.1

Group Device, General Settings; Group General

28.02.16 22:10:06

Group Device, General Settings; Group General No.

Settings

Value

Group

0610 Fault Display on LED / LCD


All

0611 Spontaneous display of flt.annunciations

NO

All

0640 Start image Default Display

image 1

All

Page 3 of 11

7SJ804 V4_6_prn Power System Data 1 Rusayl PSS / Incomer / 7SJ804 V4.6/7SJ804

SIMATIC 3

Power System Data 1

3.1


28.02.16 22:10:06

Group Power System Data 1; Group Power System No.

Settings

Value

Group

0214

Rated Frequency

50 Hz

All

0209

Phase Sequence

ABC

All

0201

CT Starpoint

towards Line

All

0280

Holmgreen-conn. (for fast sum-i-monit.)

NO

All

0251A CT Connection

Ia, Ib, Ic, (IGnd) All

0213

Van, Vbn, Vcn

All

YES

All

VT Connection, three-phase

0235A Storage of th. Replicas w/o Power Supply

3.2

Group Power System Data 1; Group Prot.Op. quant.

Group Power System Data 1; Group Prot.Op. quant. No.

Settings

Value

Group

0250A 50, 51 Time Overcurrent with 2ph. prot.

OFF

0613A Ground Overcurrent protection with

Ignd (measured) All

3.3

All

Group Power System Data 1; Group CT's

Group Power System Data 1; Group CT's No.

Settings

Value Group


400 A All


1A

0217 Ignd-CT rated primary current

400 A All

0218 Ignd-CT rated secondary current

1A

All All

Page 4 of 11

7SJ804 V4_6_prn Group Power System Data 1; Group VT's Rusayl PSS / Incomer / 7SJ804 V4.6/7SJ804

SIMATIC 3.4

28.02.16 22:10:06

Group Power System Data 1; Group VT's

Group Power System Data 1; Group VT's No.

Settings

Value

Group

0202

Rated Primary Voltage

33.00 kV All

0203

Rated Secondary Voltage (L-L)

110 V

All

1.73

All

0206A Matching ratio Phase-VT To Open-Delta-VT

3.5



Settings

Value

Group


0.15 sec All


1.00 sec All

0212

Closed Breaker Min. Current Threshold

0.04 A

3.6

Group Power System Data 1; Group Threshold BI

All

Group Power System Data 1; Group Threshold BI No.

Settings

Value

Group

0220 Threshold for Binary Input 1

Threshold for Binary Input: 88V

All



All



All



All



All



All



All

Page 5 of 11

7SJ804 V4_6_prn Settings groups Rusayl PSS / Incomer / 7SJ804 V4.6/7SJ804

SIMATIC 4

Settings groups

4.1

Group Power System Data 2; Group General

28.02.16 22:10:06

Group Power System Data 2; Group General No.

Settings

Value

Group

1101 Measurem:FullScaleVoltage(Equipm.rating)

33.00 kV

A


400 A

A


not reversed A

4.2

Group 50/51 Phase/Ground Overcurrent; Group General

Group 50/51 Phase/Ground Overcurrent; Group General No. 1201

Settings

Value ON

A

1213A Manual Close Mode

50-2 instantaneously

A

1215A 50 Drop-Out Time Delay

0.00 sec

A

1301

ON

A


50N-2 instantaneously

A

1315A 50N Drop-Out Time Delay

0.00 sec

A

4.3

50, 51 Phase Time Overcurrent

Group

50N, 51N Ground Time Overcurrent

Group 50/51 Phase/Ground Overcurrent; Group 50

Group 50/51 Phase/Ground Overcurrent; Group 50 No.

Settings

Value

Group

1219A 50-3 measurement of

Fundamental component

A

1216A 50-3 active

Always

A

1217

50-3 Pickup

oo A

A

1218

50-3 Time Delay

0.00 sec

A



A

1214A 50-2 active

Always

A

1202

50-2 Pickup

oo A

A

1203

50-2 Time Delay

0.00 sec

A



A

1204

oo A

A

50-1 Pickup

Page 6 of 11

7SJ804 V4_6_prn Group 50/51 Phase/Ground Overcurrent; Group 50 Rusayl PSS / Incomer / 7SJ804 V4.6/7SJ804 SIMATIC

28.02.16 22:10:06

Group 50/51 Phase/Ground Overcurrent; Group 50(2) No.

Settings

Value

1205

50-1 Time Delay

4.4


0.50 sec

Group A


Settings

Value

Group

1222A 51 measurement of


A

1207

51 Pickup

1.00 A

A

1208

51 Time Dial

0.49 sec

A

1210

Drop-out characteristic

Disk Emulation

A

1211

IEC Curve

Normal Inverse

A

4.5

Group 50/51 Phase/Ground Overcurrent; Group 50N

Group 50/51 Phase/Ground Overcurrent; Group 50N No.

Settings

Value

Group

1319A 50N-3 measurement of


A

1317

50N-3 Pickup

oo A

A

1318

50N-3 Time Delay

0.05 sec

A



A

1302

50N-2 Pickup

oo A

A

1303

50N-2 Time Delay

0.10 sec

A



A

1304

50N-1 Pickup

oo A

A

1305

50N-1 Time Delay

0.50 sec

A

1314A 50N-2 active

Always

A

1316A 50N-3 active

Always

A

Page 7 of 11

7SJ804 V4_6_prn Group 50/51 Phase/Ground Overcurrent; Group 51N Rusayl PSS / Incomer / 7SJ804 V4.6/7SJ804 SIMATIC 4.6

28.02.16 22:10:06



Settings

Value

Group

1322A 51N measurement of


A

1307

51N Pickup

0.20 A

A

1308

51N Time Dial

0.48 sec

A

1310

Drop-Out Characteristic

Disk Emulation

A

1311

IEC Curve

Normal Inverse

A

4.7

Group 67 Directional Phase/Ground Overcurrent; Group General

Group 67 Directional Phase/Ground Overcurrent; Group General No. 1501

Settings

Value ON

A



A

1516

Phase Direction

Forward

A


0.00 sec

A

1519A Rotation Angle of Reference Voltage

45 °

A

1601

ON

A



A

1616

Ground Direction

Forward

A

1617

Ground Polarization

with VN and IN

A


0.00 sec

A

1619A Rotation Angle of Reference Voltage

-45 °

A

4.8

67, 67-TOC Phase Time Overcurrent

Group

67N, 67N-TOC Ground Time Overcurrent

Group 67 Directional Phase/Ground Overcurrent; Group 67

Group 67 Directional Phase/Ground Overcurrent; Group 67 No.

Settings

Value

Group

1502

67-2 Pickup

oo A

A

1503

67-2 Time Delay

0.10 sec

A



A

1504

67-1 Pickup

oo A

A

1505

67-1Time Delay

0.50 sec

A



A

1514A 67-2 active

always

A

Page 8 of 11

7SJ804 V4_6_prn Group 67 Directional Phase/Ground Overcurrent; Group 67 Rusayl PSS / Incomer / 7SJ804 V4.6/7SJ804 SIMATIC

4.9

28.02.16 22:10:06

Group 67 Directional Phase/Ground Overcurrent; Group 67-TOC

Group 67 Directional Phase/Ground Overcurrent; Group 67-TOC No.

Settings

Value

Group

1507

67-TOC Pickup

0.50 A

A

1508

67-TOC Time Dial

0.05 sec

A

1522A 67-TOC measurement of


A

1510


Disk Emulation

A

1511

IEC Curve

Normal Inverse

A

4.10

Group 67 Directional Phase/Ground Overcurrent; Group 67N

Group 67 Directional Phase/Ground Overcurrent; Group 67N No.

Settings

Value

Group

1602

67N-2 Pickup

oo A

A

1603

67N-2 Time Delay

0.10 sec

A



A

1604

67N-1 Pickup

oo A

A

1605

67N-1 Time Delay

0.50 sec

A



A

1614A 67N-2 active

always

A

4.11

Group 67 Directional Phase/Ground Overcurrent; Group 67N-TOC

Group 67 Directional Phase/Ground Overcurrent; Group 67N-TOC No.

Settings

Value

Group

1607

67N-TOC Pickup

0.20 A

A

1608

67N-TOC Time Dial

0.05 sec

A

1622A 67N-TOC measurement of


A

1610


Disk Emulation

A

1611

IEC Curve

Normal Inverse

A

Page 9 of 11

7SJ804 V4_6_prn Group Measurement Supervision; Group General Rusayl PSS / Incomer / 7SJ804 V4.6/7SJ804 SIMATIC 4.12

28.02.16 22:10:06

Group Measurement Supervision; Group General

Group Measurement Supervision; Group General No.

Settings

Value Group

8101 Measurement Supervision

ON

A

5301 Fuse Fail Monitor

OFF

A

5310 Block protection by FFM

YES

A

5201 VT broken wire supervision

OFF

A

4.13

Group Measurement Supervision; Group MeasSupervision

Group Measurement Supervision; Group MeasSupervision No.

Settings

Value Group

8102 Voltage Threshold for Balance Monitoring

50 V

A

8103 Balance Factor for Voltage Monitor

0.75

A

8104 Current Threshold for Balance Monitoring

0.50 A A

8105 Balance Factor for Current Monitor

0.50

4.14

A

Group Measurement Supervision; Group Fuse Fail Mon.

Group Measurement Supervision; Group Fuse Fail Mon. No.

Settings

Value Group

5302 Zero Sequence Voltage

30 V

A

5303 Residual Current

0.10 A A

5307 I> Pickup for block FFM

1.00 A A

Page 10 of 11

7SJ804 V4_6_prn Group Measurement Supervision; Group VT broken wire Rusayl PSS / Incomer / 7SJ804 V4.6/7SJ804 SIMATIC 4.15

28.02.16 22:10:06

Group Measurement Supervision; Group VT broken wire

Group Measurement Supervision; Group VT broken wire No.

Settings

Value

Group

5202 Threshold voltage sum

8.0 V

A

5203 Maximum phase to phase voltage

16.0 V

A

5204 Minimum phase to phase voltage

16.0 V

A

5205 Symmetry phase to phase voltages

16.0 V

A

5206 Minimum line current

0.04 A

A

5208 Alarm delay time

1.25 sec A

4.16

Group Energy; Group Measurement

Group Energy; Group Measurement No.

Settings

Value

Group

8315 Meter resolution Standard A

Page 11 of 11

7UT612 V4_6_prn

SIMATIC

Rusayl PSS / Transformer / 7UT612 V4.6/7UT612

28.02.16 22:17:12

Rusayl PSS / Transformer / 7UT612 V4.6 MLFB: 7UT6121*EB901AA0 Parameter set version: V04.62.07 Device path: C:\Siemens\Digsi4\D4PROJ\Rusayl_P\P7DI\GV\SD\00000004 Author: Creation date: 24.02.16 22:23:03 Last modified: 28.02.16 22:16:57 Operating mode: Offline Comment: Setting values in: Secondary value description

PRINT - CONTENTS 1 2 2.1 3 3.1 3.2 3.3 3.4 3.5 3.6 4 4.1 4.2 4.3 4.4 4.5 4.6 4.7 4.8 4.9 4.10 4.11

Device Configuration .................................................................................................................................................................2 General Device Settings ...........................................................................................................................................................3 Group Device, General Settings; Group General ...................................................................................................................... 3 Power System Data 1 ...............................................................................................................................................................4 Group Power System Data 1; Group CT-Numbers ................................................................................................................... 4 Group Power System Data 1; Group CT-Assign ....................................................................................................................... 4 Group Power System Data 1; Group Power System ................................................................................................................ 4 Group Power System Data 1; Group Transf. ............................................................................................................................ 5 Group Power System Data 1; Group CT's ................................................................................................................................ 5 Group Power System Data 1; Group CB .................................................................................................................................. 5 Settings groups .........................................................................................................................................................................6 Group Power System Data 2; Group PoleOpen Detect ............................................................................................................ 6 Group 87 Differential Protection; Group General ...................................................................................................................... 6 Group 87 Differential Protection; Group I-Diff ........................................................................................................................... 6 Group 87 Differential Protection; Group Characteristic ............................................................................................................. 7 Group 87 Differential Protection; Group Inrush 2.HM ............................................................................................................... 7 Group 87 Differential Protection; Group Restr. n.HM ................................................................................................................ 7 Group Measurement Supervision; Group General .................................................................................................................... 8 Group Measurement Supervision; Group Balance I M1 ........................................................................................................... 8 Group Measurement Supervision; Group Balance I M2 ........................................................................................................... 8 Group Supervision; Group General ........................................................................................................................................... 8 Group Measurement; Group Measurement .............................................................................................................................. 9

Page 1 of 9

7UT612 V4_6_prn Device Configuration Rusayl PSS / Transformer / 7UT612 V4.6/7UT612

SIMATIC

28.02.16 22:17:12


1 No.

Function

Scope


Disabled

0105 Protection Object

3 phase Transformer

0112 87 Differential Protection

Enabled


Disabled

0120 50/51

Disabled

0122 50N/51N

Disabled

0124 50G/51G

Disabled


Disabled

0180 Disconnect measurment location

Disabled

0181 Measured Values Supervision

Enabled

0186 External Trip Function 1

Disabled

0187 External Trip Function 2

Disabled

Page 2 of 9

7UT612 V4_6_prn General Device Settings Rusayl PSS / Transformer / 7UT612 V4.6/7UT612

SIMATIC 2


2.1


28.02.16 22:17:12


Settings

Value

Group



All

0204 Start image Default Display

image 1

All

Page 3 of 9

7UT612 V4_6_prn Power System Data 1 Rusayl PSS / Transformer / 7UT612 V4.6/7UT612

SIMATIC 3

Power System Data 1

3.1

Group Power System Data 1; Group CT-Numbers

28.02.16 22:17:12

Group Power System Data 1; Group CT-Numbers No.

Settings

Value Group

0211 Number of connected Measuring Locations

2

All

0212 Number of assigned Measuring Locations

2

All

0213 Number of Sides

2

All

3.2

Group Power System Data 1; Group CT-Assign

Group Power System Data 1; Group CT-Assign No.

Settings

Value

Group

0220 Assignment at 2 assig.Meas.Loc./ 2 Sides

S1:M1, S2:M2

All

0251 Auxiliary CT IX1 is used as

Not connected

All

0253 Auxiliary CT IX3 is used as

Not connected

All

0255 Type of auxiliary CT IX3

sensitiv current input

All

3.3



Settings

Value

Group

0270 Rated Frequency

50 Hz

All

0271 Phase Sequence

ABC

All

0276 Unit of temperature measurement

Degree Celsius All

Page 4 of 9

7UT612 V4_6_prn Group Power System Data 1; Group Transf. Rusayl PSS / Transformer / 7UT612 V4.6/7UT612 SIMATIC 3.4

28.02.16 22:17:12

Group Power System Data 1; Group Transf.

Group Power System Data 1; Group Transf. No.

Settings

Value

Group

0311 Rated Primary Voltage Side 1

33.0 kV

0312 Rated Apparent Power of Transf. Side 1

20.00 MVA All

0313 Starpoint of Side 1 is

Isolated

All

0314 Transf. Winding Connection Side 1

D (Delta)

All

0321 Rated Primary Voltage Side 2

11.5 kV

All

0322 Rated Apparent Power of Transf. Side 2

20.00 MVA All

0323 Starpoint of Side 2 is

Grounded

All

0324 Transf. Winding Connection Side 2

Y (Wye)

All

0325 Vector Group Numeral of Side 2

11

All

3.5

All



Settings

Value Group

0511 CT-Strpnt. Meas. Loc.1 in Dir. of Object

YES

All

0512 CT Rated Primary Current Meas. Loc. 1

400 A

All

0513 CT Rated Secondary Current Meas. Loc. 1

1A

All

0521 CT-Strpnt. Meas. Loc.2 in Dir. of Object

YES

All

0522 CT Rated Primary Current Meas. Loc. 2

1200 A All

0523 CT Rated Secondary Current Meas. Loc. 2

1A

3.6

All

Group Power System Data 1; Group CB

Group Power System Data 1; Group CB No.

Settings

Value

Group

0831

Switchgear / CBaux at Side 1

Q0

All

0832

Switchgear / CBaux at Side 2

All

0836

Switchgear / CBaux at Measuring Loc. M1

All

0837

Switchgear / CBaux at Measuring Loc. M2

All


0.15 sec All

Page 5 of 9

7UT612 V4_6_prn Settings groups Rusayl PSS / Transformer / 7UT612 V4.6/7UT612

SIMATIC 4

Settings groups

4.1

Group Power System Data 2; Group PoleOpen Detect

28.02.16 22:17:12

Group Power System Data 2; Group PoleOpen Detect No.

Settings

Value

Group

1111 Pole Open Current Threshold Side 1

0.10 I/InS A

1112 Pole Open Current Threshold Side 2

0.10 I/InS A

1121 Pole Open Current Threshold Meas.Loc. M1

0.04 A

A

1122 Pole Open Current Threshold Meas.Loc. M2

0.04 A

A

4.2

Group 87 Differential Protection; Group General

Group 87 Differential Protection; Group General No.

Settings

Value

Group

1201 87 Differential Protection

ON

A

1205 87 Increase of Trip Char. During Start

OFF

A

1206 87 Inrush with 2. Harmonic Restraint

ON

A

1207 87 n-th Harmonic Restraint

5. Harmonic A

4.3

Group 87 Differential Protection; Group I-Diff

Group 87 Differential Protection; Group I-Diff No. 1221

Settings 87-1 Pickup Value of Differential Curr.

Value

Group

0.20 I/InO A

1226A 87-1 T I-DIFF> Time Delay

0.00 sec

1231

11.0 I/InO A

87-2 Pickup Value of High Set Trip

1236A 87-2 T I-DIFF>> Time Delay

0.00 sec

A A

Page 6 of 9

7UT612 V4_6_prn Group 87 Differential Protection; Group Characteristic Rusayl PSS / Transformer / 7UT612 V4.6/7UT612 SIMATIC 4.4

28.02.16 22:17:12

Group 87 Differential Protection; Group Characteristic

Group 87 Differential Protection; Group Characteristic No.

Settings

Value

Group

1241A 87 Slope 1 of Tripping Characteristic

0.25

1242A 87 Base Point for Slope 1 of Charac.

0.00 I/InO A

1243A 87 Slope 2 of Tripping Characteristic

0.50

1244A 87 Base Point for Slope 2 of Charac.

2.50 I/InO A

1251A 87 I-RESTRAINT for Start Detection

0.10 I/InO A

1252A 87 Factor for Increas. of Char. at Start

1.0

A

1253

5.0 sec

A

87 Maximum Permissible Starting Time

A A

1261A 87 Pickup for Add-on Stabilization

4.00 I/InO A

1262A 87 Duration of Add-on Stabilization

15 Cycle

A

1263A 87 Time for Cross-block Add-on Stabiliz.

15 Cycle

A

4.5

Group 87 Differential Protection; Group Inrush 2.HM

Group 87 Differential Protection; Group Inrush 2.HM No. 1271

Settings 87 2nd Harmonic Content in I-DIFF

1272A 87 Time for Cross-blocking 2nd Harm.

4.6

Value 15 %

Group A

3 Cycle A

Group 87 Differential Protection; Group Restr. n.HM

Group 87 Differential Protection; Group Restr. n.HM No. 1276

Settings 87 n-th Harmonic Content in I-DIFF

Value

Group

30 %

A

1277A 87 Time for Cross-blocking n-th Harm.

0 Cycle

A

1278A 87 Limit IDIFFmax of n-th Harm.Restr.

1.5 I/InO A

Page 7 of 9

7UT612 V4_6_prn Group Measurement Supervision; Group General Rusayl PSS / Transformer / 7UT612 V4.6/7UT612 SIMATIC 4.7

28.02.16 22:17:12



Settings

Value Group

8101 Current Balance Supervision

OFF

A

8105 Current Phase Rotation Supervision

OFF

A

4.8

Group Measurement Supervision; Group Balance I M1

Group Measurement Supervision; Group Balance I M1 No.

Settings

Value Group

8111

Current Balance Monitor Meas. Loc. 1

0.50 A A

8112

Bal. Factor for Curr. Monitor Meas.Loc.1

0.50

A

5 sec

A

8113A Symmetry Iph: Pick-up delay

4.9

Group Measurement Supervision; Group Balance I M2

Group Measurement Supervision; Group Balance I M2 No.

Settings

Value Group

8121

Current Balance Monitor Meas. Loc. 2

0.50 A A

8122

Bal. Factor for Curr. Monitor Meas.Loc.2

0.50

A

5 sec

A

8123A Symmetry Iph: Pick-up delay

4.10

Group Supervision; Group General

Group Supervision; Group General No.

Settings

Value

Group

8401 Fast Broken Current-wire Supervision

OFF

A

8414 Delay time for BWD supervision

1.0 sec

A

8415 min differential current for BWD

1.00 I/InO A

Page 8 of 9

7UT612 V4_6_prn Group Measurement; Group Measurement Rusayl PSS / Transformer / 7UT612 V4.6/7UT612 SIMATIC 4.11

28.02.16 22:17:12

Group Measurement; Group Measurement

Group Measurement; Group Measurement No.

Settings

7601 Calculation of Power

Value

Group

with V setting A

Page 9 of 9

7SJ802 V4_6_prn

SIMATIC

Rusayl PSS / Transformer / 7SJ802 V4.6/7SJ802

28.02.16 22:18:32

Rusayl PSS / Transformer / 7SJ802 V4.6 MLFB: 7SJ80215*B901FA0 Parameter set version: V04.61.06 Device path: C:\Siemens\Digsi4\D4PROJ\Rusayl_P\P7DI\GV\SD\00000005 Author: Creation date: 24.02.16 22:48:37 Last modified: 28.02.16 22:18:00 Operating mode: Offline Comment: Setting values in: Secondary value description

PRINT - CONTENTS 1 2 2.1 3 3.1 3.2 3.3 3.4 3.5 4 4.1 4.2 4.3 4.4 4.5 4.6 4.7 4.8 4.9

Device Configuration .................................................................................................................................................................2 General Device Settings ...........................................................................................................................................................3 Group Device, General Settings; Group General ...................................................................................................................... 3 Power System Data 1 ...............................................................................................................................................................4 Group Power System Data 1; Group Power System ................................................................................................................ 4 Group Power System Data 1; Group Prot.Op. quant. ............................................................................................................... 4 Group Power System Data 1; Group CT's ................................................................................................................................ 4 Group Power System Data 1; Group Breaker ........................................................................................................................... 5 Group Power System Data 1; Group Threshold BI ................................................................................................................... 5 Settings groups .........................................................................................................................................................................6 Group Power System Data 2; Group General ........................................................................................................................... 6 Group 50/51 Phase/Ground Overcurrent; Group General ........................................................................................................ 6 Group 50/51 Phase/Ground Overcurrent; Group 50 ................................................................................................................. 6 Group 50/51 Phase/Ground Overcurrent; Group 51 ................................................................................................................. 7 Group 50/51 Phase/Ground Overcurrent; Group 50N .............................................................................................................. 7 Group 50/51 Phase/Ground Overcurrent; Group 51N .............................................................................................................. 7 Group Measurement Supervision; Group General .................................................................................................................... 8 Group Measurement Supervision; Group MeasSupervision ..................................................................................................... 8 Group Energy; Group Measurement ......................................................................................................................................... 8

Page 1 of 8

7SJ802 V4_6_prn Device Configuration Rusayl PSS / Transformer / 7SJ802 V4.6/7SJ802

SIMATIC

28.02.16 22:18:32


1 No.

Function

Scope


Disabled


Enabled

0112 50/51


0113 50N/51N



Disabled


Disabled


Disabled


Disabled


Disabled


Disabled


Disabled


Disabled

Flexible Function

Page 2 of 8

7SJ802 V4_6_prn General Device Settings Rusayl PSS / Transformer / 7SJ802 V4.6/7SJ802

SIMATIC 2


2.1


28.02.16 22:18:32


Settings

Value

Group



All


NO

All

Page 3 of 8

7SJ802 V4_6_prn Power System Data 1 Rusayl PSS / Transformer / 7SJ802 V4.6/7SJ802

SIMATIC 3

Power System Data 1

3.1


28.02.16 22:18:32


Settings

Value

Group

0214

Rated Frequency

50 Hz

All

0209

Phase Sequence

ABC

All

0201

CT Starpoint

towards Line

All

0280


NO

All

0251A CT Connection



YES

3.2

All



Settings

Value

Group


OFF


Ignd (measured) All

3.3

All



Settings

Value Group


400 A All


1A


400 A All


1A

All All

Page 4 of 8

7SJ802 V4_6_prn Group Power System Data 1; Group Breaker Rusayl PSS / Transformer / 7SJ802 V4.6/7SJ802 SIMATIC 3.4

28.02.16 22:18:32



Settings

Value

Group


0.15 sec All


1.00 sec All

0212


0.04 A

3.5


All


Settings

Value

Group



All



All



All



All



All



All



All

Page 5 of 8

7SJ802 V4_6_prn Settings groups Rusayl PSS / Transformer / 7SJ802 V4.6/7SJ802

SIMATIC 4

Settings groups

4.1


28.02.16 22:18:32


Settings

Value

Group


400 A


not reversed A

4.2

A



Settings

Value ON

A



A


0.00 sec

A

1301

ON

A



A


0.00 sec

A

4.3


Group




Settings

Value

Group



A

1216A 50-3 active

Always

A

1217

50-3 Pickup

11.00 A

A

1218

50-3 Time Delay

0.00 sec

A



A

1214A 50-2 active

Always

A

1202

50-2 Pickup

oo A

A

1203

50-2 Time Delay

0.00 sec

A



A

1204

50-1 Pickup

oo A

A

1205

50-1 Time Delay

0.50 sec

A

Page 6 of 8

7SJ802 V4_6_prn Group 50/51 Phase/Ground Overcurrent; Group 50 Rusayl PSS / Transformer / 7SJ802 V4.6/7SJ802 SIMATIC

4.4

28.02.16 22:18:32



Settings

Value

Group



A

1207

51 Pickup

1.00 A

A

1208

51 Time Dial

0.18 sec

A

1210


Disk Emulation

A

1211

IEC Curve

Normal Inverse

A

4.5



Settings

Value

Group



A

1317

50N-3 Pickup

oo A

A

1318

50N-3 Time Delay

0.05 sec

A



A

1302

50N-2 Pickup

oo A

A

1303

50N-2 Time Delay

0.10 sec

A



A

1304

50N-1 Pickup

oo A

A

1305

50N-1 Time Delay

0.50 sec

A

1314A 50N-2 active

Always

A

1316A 50N-3 active

Always

A

4.6



Settings

Value

Group



A

1307

51N Pickup

0.20 A

A

1308

51N Time Dial

0.05 sec

A

1310


Disk Emulation

A

Page 7 of 8

7SJ802 V4_6_prn Group 50/51 Phase/Ground Overcurrent; Group 51N Rusayl PSS / Transformer / 7SJ802 V4.6/7SJ802 SIMATIC

28.02.16 22:18:32

Group 50/51 Phase/Ground Overcurrent; Group 51N(2) No.

Settings

Value

Group

1311

IEC Curve

Normal Inverse

A

4.7



Settings

Value Group


4.8

ON

A



Settings

Value Group


0.50 A A


0.50

4.9

A



Settings

Value

Group


Page 8 of 8

7SJ802 V4_6_prn

SIMATIC

Rusayl PSS / Bus coupler / 7SJ802 V4.6/7SJ802

28.02.16 22:12:29

Rusayl PSS / Bus coupler / 7SJ802 V4.6 MLFB: 7SJ80215*B901FA0 Parameter set version: V04.61.06 Device path: C:\Siemens\Digsi4\D4PROJ\Rusayl_P\P7DI\GV\SD\00000003 Author: Creation date: 24.02.16 21:24:16 Last modified: 28.02.16 22:11:55 Operating mode: Offline Comment: Setting values in: Secondary value description

PRINT - CONTENTS 1 2 2.1 3 3.1 3.2 3.3 3.4 3.5 4 4.1 4.2 4.3 4.4 4.5 4.6 4.7 4.8 4.9

Device Configuration .................................................................................................................................................................2 General Device Settings ...........................................................................................................................................................3 Group Device, General Settings; Group General ...................................................................................................................... 3 Power System Data 1 ...............................................................................................................................................................4 Group Power System Data 1; Group Power System ................................................................................................................ 4 Group Power System Data 1; Group Prot.Op. quant. ............................................................................................................... 4 Group Power System Data 1; Group CT's ................................................................................................................................ 4 Group Power System Data 1; Group Breaker ........................................................................................................................... 5 Group Power System Data 1; Group Threshold BI ................................................................................................................... 5 Settings groups .........................................................................................................................................................................6 Group Power System Data 2; Group General ........................................................................................................................... 6 Group 50/51 Phase/Ground Overcurrent; Group General ........................................................................................................ 6 Group 50/51 Phase/Ground Overcurrent; Group 50 ................................................................................................................. 6 Group 50/51 Phase/Ground Overcurrent; Group 51 ................................................................................................................. 7 Group 50/51 Phase/Ground Overcurrent; Group 50N .............................................................................................................. 7 Group 50/51 Phase/Ground Overcurrent; Group 51N .............................................................................................................. 7 Group Measurement Supervision; Group General .................................................................................................................... 8 Group Measurement Supervision; Group MeasSupervision ..................................................................................................... 8 Group Energy; Group Measurement ......................................................................................................................................... 8

Page 1 of 8

7SJ802 V4_6_prn Device Configuration Rusayl PSS / Bus coupler / 7SJ802 V4.6/7SJ802

SIMATIC

28.02.16 22:12:29


1 No.

Function

Scope


Disabled


Enabled

0112 50/51


0113 50N/51N



Disabled


Disabled


Disabled


Disabled


Disabled


Disabled


Disabled


Disabled

Flexible Function

Page 2 of 8

7SJ802 V4_6_prn General Device Settings Rusayl PSS / Bus coupler / 7SJ802 V4.6/7SJ802

SIMATIC 2


2.1


28.02.16 22:12:29


Settings

Value

Group



All


NO

All

Page 3 of 8

7SJ802 V4_6_prn Power System Data 1 Rusayl PSS / Bus coupler / 7SJ802 V4.6/7SJ802

SIMATIC 3

Power System Data 1

3.1


28.02.16 22:12:29


Settings

Value

Group

0214

Rated Frequency

50 Hz

All

0209

Phase Sequence

ABC

All

0201

CT Starpoint

towards Line

All

0280


NO

All

0251A CT Connection



YES

3.2

All



Settings

Value

Group


OFF


Ignd (measured) All

3.3

All



Settings

Value Group


1200 A All


1A


1200 A All


1A

All All

Page 4 of 8

7SJ802 V4_6_prn Group Power System Data 1; Group Breaker Rusayl PSS / Bus coupler / 7SJ802 V4.6/7SJ802 SIMATIC 3.4

28.02.16 22:12:29



Settings

Value

Group


0.15 sec All


1.00 sec All

0212


0.04 A

3.5


All


Settings

Value

Group



All



All



All



All



All



All



All

Page 5 of 8

7SJ802 V4_6_prn Settings groups Rusayl PSS / Bus coupler / 7SJ802 V4.6/7SJ802

SIMATIC 4

Settings groups

4.1


28.02.16 22:12:29


Settings

Value

Group


1200 A


not reversed A

4.2

A



Settings

Value ON

A



A


0.00 sec

A

1301

ON

A



A


0.00 sec

A

4.3


Group




Settings

Value

Group



A

1216A 50-3 active

Always

A

1217

50-3 Pickup

oo A

A

1218

50-3 Time Delay

0.00 sec

A



A

1214A 50-2 active

Always

A

1202

50-2 Pickup

oo A

A

1203

50-2 Time Delay

0.00 sec

A



A

1204

50-1 Pickup

oo A

A

1205

50-1 Time Delay

0.50 sec

A

Page 6 of 8

7SJ802 V4_6_prn Group 50/51 Phase/Ground Overcurrent; Group 50 Rusayl PSS / Bus coupler / 7SJ802 V4.6/7SJ802 SIMATIC

4.4

28.02.16 22:12:29



Settings

Value

Group



A

1207

51 Pickup

0.29 A

A

1208

51 Time Dial

0.43 sec

A

1210


Disk Emulation

A

1211

IEC Curve

Normal Inverse

A

4.5



Settings

Value

Group



A

1317

50N-3 Pickup

oo A

A

1318

50N-3 Time Delay

0.05 sec

A



A

1302

50N-2 Pickup

oo A

A

1303

50N-2 Time Delay

0.10 sec

A



A

1304

50N-1 Pickup

oo A

A

1305

50N-1 Time Delay

0.50 sec

A

1314A 50N-2 active

Always

A

1316A 50N-3 active

Always

A

4.6



Settings

Value

Group



A

1307

51N Pickup

0.20 A

A

1308

51N Time Dial

0.13 sec

A

1310


Disk Emulation

A

Page 7 of 8

7SJ802 V4_6_prn Group 50/51 Phase/Ground Overcurrent; Group 51N Rusayl PSS / Bus coupler / 7SJ802 V4.6/7SJ802 SIMATIC

28.02.16 22:12:29

Group 50/51 Phase/Ground Overcurrent; Group 51N(2) No.

Settings

Value

Group

1311

IEC Curve

Normal Inverse

A

4.7



Settings

Value Group


4.8

ON

A



Settings

Value Group


0.50 A A


0.50

4.9

A



Settings

Value

Group


Page 8 of 8

Relay Setting Calculation rev.1.pdf

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