Do 1, 2, 3, 4, 5 and 6 inHW10.pdfDownload HW10.pdfusingBHL2 Fdr1 Typ3 no crow Tx and relays.olr

Do 1, 2, 3, 4, 5 and 6 in

HW10.pdf


Download HW10.pdf


using

BHL2 Fdr1 Typ3 no crow Tx and relays.olr



Page 1 of 3 HW10 EE6560 Power System Protection 1 [1,2,3 required; 4,5,6 Bonus though I recommend doing them.] Use BHL2 Fdr1 Typ3 crowbarred Tx and relays.olr model to check Bishop Hill protection coordination which requires fault currents, relevant current flows through various relay and fuse locations. 1) Simulate a bolted L-L fault at Bishop LS 34.5kV. a. What happens to your Type 3 Wind Farms at Gen 10 Ag, Gen 6, and Aggr 40WTG locations? b. How much fault current do they contribute? 2) Simulate a L-L fault at Bishop LS 34.5kV with Fault Z = 0.50 +j0 ohm. a. What happens to your Type 3 Wind Farms at Gen 10 Ag, Gen 6, and Aggr 40WTG locations? b. How much fault current do they contribute? 3) At "6 HS 34.5kV", determine an arc resistance (use only 2 or 3 significant figures) for which fault current with Rarc satisfies the Rarc equation for each of these fault types. State Rarc and fault amps. a. PP (or L-L in ASPEN) b. 3ph (or 3LG in ASPEN) c. SLG (or 1LG in ASPEN) 4) For "6 HS" faults with Rarc from #3 check the fuse or relay Detection Margin (DM) for each fault type a. GSU Fuse at 6 HS b. Device 51 on Fdr1 at Bishop LS c. Device 51 on MCT LS at Bishop LS d. Device 51N on Fdr1 at Bishop LS e. Device 51N on MCT LS at Bishop LS 5) For "6 HS" faults with Rarc from #3 and appropriate fault type, check Coordinating Time Intervals (CTI) a. GSU Fuse at 6 HS and Device 51 on Fdr1 at Bishop LS b. GSU Fuse at 6 HS and Device 51N on Fdr1 at Bishop LS c. Device 51 on Fdr1 at Bishop LS and Device 51 on MCT LS at Bishop LS d. Device 51N on Fdr1 at Bishop LS and Device 51N on MCT LS at Bishop LS 6) Now apply the Crowbar at Gen 10 Ag, Gen 6, and Aggr 40WTG locations. Now simulate bolted faults at "6 HS 34.5kV". a. Compare fault current magnitudes to fault magnitudes from #3. b. Are DM ok? c. Are CTI ok? Page 2 of 3 Background: The nature of most wind generators (and solar inverters) yields much less fault current than traditional synchronous generators. Thus we need to do bounding calculations to determine protective relay settings and properly protect both the system (grid) and the equipment. As I explained in class 4/11/2023 I've found that either modelling load = wind farm generation or including a realistic fault impedance usually results in ASPEN being able to solve without these Type 3 Wind Farm generators shutting down. To keep it 'simple' I'm providing the ASPEN model and will have you include fault impedance in your approach. For 'no crowbar' fault calculations, I recommend including fault impedance with Blackburn 4th edition p450, section 12.18 method as I covered in class. Rarc=(440*Length in feet)/(fault current amps rms) You'll also need to check coordination for conditions when the wind generators crowbar the rotor (to avoid power electronic component damage) so you'll need to check the Crowbarred box at the Gen 10 Ag, Gen 6, and Aggr 40WTG locations. Bishop Hill (BSHL) 34.5kV substation bus and exit conductor phase spacing is 4.5 feet as shown in the plan view below. And BSHL 138kV phase spacing is 10 feet. We will assume that the underground to overhead transition at each WTG also has 4.5 feet phase spacing on the 34.5kV side of the Wind Turbine Generator (WTG) step up transformer. For simplicity we'll assume the arc length doubles for a phase to phase (PP) fault, but equals the phase spacing for single line to ground (SLG) faults (Note: insulator creep is about PP spacing; e.g., Hubbell polymer 38kV 200kV BIL has 34.5" creep, Hubbell polymer 650kV BIL has 128" creep). Page 3 of 3 Here are my fault currents with arc resistance: For example Rarc=(440*Length in feet)/(fault current amps rms)=(440*4.5)/(2862A)=0.69 ohms and entering 0.69ohms yields 2862A. Paul Nauert 4/13/2023