Interview questions & answers
Q1. What is load flow analysis and why is it performed?
Load flow (power flow) analysis calculates the steady-state voltage magnitude and angle at every bus, active and reactive power flows in every transmission line, and generator reactive power output for a specified operating condition. It is used to verify that no line or transformer exceeds its rating, that all bus voltages remain within ±5% of nominal (as per Indian Electricity Grid Code), and to plan generation dispatch. In the Southern Regional Grid of India, load flow studies on the 400 kV network are routinely performed before commissioning new transmission lines to ensure voltage profiles remain acceptable under both normal and N-1 contingency conditions.
Follow-up: What are the Gauss-Seidel and Newton-Raphson methods for solving load flow equations, and which converges faster?
Q2. What are the different types of buses in a power system and what variables are specified at each?
Three bus types exist in load flow analysis: the slack bus (reference bus) has specified voltage magnitude and angle (usually 1.0 pu, 0°), and P and Q are computed — there is always exactly one slack bus that absorbs the power balance; PV buses (generator buses) have specified active power P and voltage magnitude V, with Q and δ computed; PQ buses (load buses) have specified P and Q (from load data), with V and δ computed. The Western Regional Grid interconnection has the Vindhyachal 500 MW units specified as PV buses, while all distribution substations are PQ buses.
Follow-up: Why can a PV bus not always remain a PV bus during the iterative load flow solution?
Q3. What is reactive power and why is it important in power systems?
Reactive power (Q, measured in VAR) is the component of apparent power that oscillates between source and reactive load without doing net work — it is essential for maintaining voltage levels in the transmission network. Inductive loads (motors, transformers) absorb reactive power, pulling down bus voltages, while capacitive elements (capacitor banks, lightly loaded cables) supply reactive power, raising voltages. In the Indian grid, 11 kV distribution feeder voltages during summer afternoons often fall to 0.92–0.95 pu when air conditioning loads peak — installing 1 MVAR capacitor banks at distribution substations raises voltage to the 0.97–1.03 pu target range.
Follow-up: What is the difference between voltage regulation and reactive power compensation in distribution networks?
Q4. What is the per-unit system and how is the base chosen for a power network?
The per-unit system normalises all electrical quantities to a chosen base value, making the equivalent circuit independent of voltage level and allowing different voltage levels to be directly combined in calculations. A common system MVA base (e.g., 100 MVA) is chosen, and the base voltage at each bus is dictated by the transformer turns ratios from the chosen slack bus base (e.g., 220 kV base at the EHV bus, 11 kV at the generator bus). For NTPC''s Rihand STPP (3000 MW), the 500 kV switchyard calculations use a 100 MVA base with 500 kV base, giving a base impedance of (500²/100) = 2500 Ω — all transformer and line impedances are then expressed as fractions of this 2500 Ω.
Follow-up: How does the per-unit impedance of a transformer change when the system MVA base is changed?
Q5. What is the concept of voltage stability and how does it differ from angle stability?
Voltage stability refers to the ability of the power system to maintain acceptable voltages at all buses after a disturbance — it fails when load demand exceeds the maximum power transfer capability of the network, causing voltage collapse. Angle stability (rotor angle stability) refers to synchronous generators maintaining synchronism after a disturbance — it fails when generator rotor angles diverge following a fault. The 2012 North India blackout was a voltage stability/loading issue (transmission lines were overloaded beyond their thermal limits) rather than an angle stability failure — the distinction matters for the type of remedial action (load shedding for voltage stability, fast fault clearing and damping for angle stability).
Follow-up: What is the nose point (P-V curve) and how does it relate to voltage collapse?
Q6. What is the significance of the X/R ratio in power systems and how does it affect fault calculations?
The X/R ratio of a power system at a fault point determines the DC offset component of fault current — a high X/R ratio (typical EHV transmission at 10–20) means the DC offset decays slowly (time constant L/R = X/(ωR) seconds) and the first peak of fault current can be 1.5–2.0× the symmetric AC peak. For a 400 kV bus with X/R = 15 at 50 Hz, the DC time constant is 15/(314) = 47 ms — circuit breakers must be rated for the asymmetric momentary current (including DC offset) at the time of first current peak (typically 10–20 ms after fault inception). This is why switchgear standards specify both breaking current (symmetric RMS) and making current (peak asymmetric).
Follow-up: What is the difference between a circuit breaker''s breaking capacity and making capacity?
Q7. What is Kirchhoff's Current Law as applied to power systems bus analysis?
In bus admittance matrix (Y-bus) formulation, KCL states that the sum of current injections at each bus equals the sum of currents flowing into the network from that bus — expressed as I = Y_bus × V, where I is the vector of bus current injections and V is the vector of bus voltages. The Y-bus is a sparse, symmetric matrix in which the diagonal element Yii is the sum of all admittances connected to bus i, and off-diagonal element Yij is the negative of the admittance of the branch between buses i and j. For the Indian 765 kV inter-regional network with 200+ buses, the Y-bus has over 40,000 elements but only about 3–5% are non-zero due to the sparsity of the network graph.
Follow-up: How is the Y-bus matrix modified to account for transformer off-nominal tap ratios?
Q8. What is economic dispatch and how is it different from unit commitment?
Economic dispatch determines the optimal active power output of each online (committed) generator to meet the current load demand at minimum total fuel cost, subject to transmission constraints. Unit commitment decides which generators to start up or shut down over a planning horizon (typically 24–168 hours) considering start-up costs, minimum up/down times, and spinning reserve requirements. In the Central Electricity Authority''s merit order dispatch for the national grid, coal plants with lower variable cost (₹2–3/kWh) are dispatched first, then gas (₹4–6/kWh), then diesel — this economic dispatch can save ₹50–100 crore per day compared to arbitrary dispatch.
Follow-up: What is the incremental cost criterion (lambda dispatch) in economic dispatch?
Q9. What is the equal area criterion in power system stability?
The equal area criterion provides a graphical method to assess transient stability of a single-machine-infinite-bus system — the machine is transiently stable if the decelerating area above the post-fault power-angle curve equals or exceeds the accelerating area under the fault-on curve. During a 3-phase fault on the 220 kV line connecting Kota Super TPS to the Jaipur load, the generator accelerates (accelerating area) until the fault is cleared — if the fault clears quickly enough, the decelerating area balances the accelerating area and the machine remains in synchronism. The critical clearing time (CCT) is the maximum fault duration before instability, typically 100–200 ms for large generators on high-voltage networks.
Follow-up: How does the pre-fault power transfer level affect the critical clearing angle in the equal area criterion?
Q10. What is FACTS and name three common FACTS devices with their functions?
FACTS (Flexible AC Transmission Systems) are power electronics-based controllers that enhance controllability and increase power transfer capability of AC transmission lines. Three key devices: SVC (Static VAR Compensator) uses thyristor-controlled reactors and capacitor banks to dynamically control reactive power and voltage at up to ±200 MVAR in tens of milliseconds — installed at Raipur–Wardha 765 kV corridor in India. TCSC (Thyristor Controlled Series Capacitor) inserts variable series capacitance to increase power transfer by reducing effective line reactance — used on the Raipur–Aurangabad 400 kV line. STATCOM uses a voltage source converter (VSC) to supply or absorb reactive power faster than an SVC with no bulky capacitor banks.
Follow-up: What is the difference between a STATCOM and an SVC in terms of reactive power capability at low voltage?
Common misconceptions
Misconception: Active power controls voltage and reactive power controls frequency.
Correct: It is the opposite: active power (real power) balance determines system frequency, while reactive power balance determines bus voltage levels.
Misconception: The slack bus is always the largest generator in the system.
Correct: The slack bus is a mathematical reference bus chosen for computational convenience — typically the largest, most reliable generator is selected, but it is a modelling choice, not a physical requirement.
Misconception: Reactive power can be transmitted over long distances without significant losses.
Correct: Reactive power transmission causes significant reactive voltage drops in series reactance of transmission lines — reactive power should ideally be generated close to the point of consumption to avoid large voltage gradients.
Misconception: A power system with all bus voltages at 1.0 pu is fully stable and optimal.
Correct: Flat voltage profile does not imply stability or optimality — angle stability depends on rotor angles and fault clearing times, and economic optimality depends on generation mix and transmission losses, all independent of voltage magnitude.