Power System Analysis, Protection, and Control
This domain tests quantitative network analysis and the protection and control layers that keep the system stable: per-unit modeling, fault and symmetrical-component analysis, relay coordination, and automatic control including AGC and special protection schemes.
Analysis fundamentals
- Convert everything to a common base; transformer impedance in percent converts to per unit by dividing by the base MVA; base current at each voltage level follows from base MVA and base kV.
- Positive, negative, and zero sequence networks are interconnected according to fault type. Single line-to-ground is the most frequent fault; three-phase is generally the most severe for equipment duty. Zero-sequence current flows only where a grounded path exists.
Protection
- Overcurrent (50/51, 50N/51N), differential (87T, 87B), distance (21) with Zone 1 near 80-85% of the line and Zone 2 reaching beyond the remote terminal, plus breaker failure (50BF) and reclosing.
- Coordination time intervals between primary and backup are typically about 0.3 seconds, set by breaker time plus relay and CT error.
- Current transformers must be checked for saturation; relay pickup is expressed in secondary amperes and must be scaled by the CT ratio.
Control
- AGC balances area control error using frequency bias and interchange schedules; governors respond with roughly 5% droop.
- State estimation, contingency analysis, underfrequency load shedding, and remedial action schemes sit on top of SCADA/EMS.
Worked example
A 50 MVA, 138/13.8 kV transformer has 8% impedance. Base current on the 13.8 kV side = 50,000 / (1.732 x 13.8) = 2,092 A. A bolted three-phase fault on the low side, with infinite source, gives 2,092 / 0.08 = 26,150 A. If a feeder relay with a 400:5 CT must not operate for that fault, its secondary current would be 26,150 x 5/400 = 327 A, well above any sane instantaneous setting, so the transformer differential or low-side main must clear first.
Traps that cost marks
- Reporting fault current in primary amperes when the relay setting is in secondary amperes.
- Setting Zone 1 to 100% of the line, so it overreaches on DC offset and measurement error.
- Assuming zero-sequence current exists on an ungrounded system.
- Forgetting that motor contribution adds to fault current near industrial loads.
- Confusing N-1 contingency analysis with N-1-1 or transient stability assessment.