Excitation systems and generator protection

In short

An excitation system supplies and controls the DC current in a synchronous generator's field winding, and so fixes its internal EMF — which in turn fixes terminal voltage, reactive power output and transient stability margin. Generator protection is the set of relays that detects stator, rotor, excitation and prime-mover faults and abnormal operating conditions, and trips the machine before damage occurs. Together they are the "control and safety" half of power-plant electrical engineering, examined in electrical machines and power-system protection papers and in GATE (EE), and assessed in interviews at NTPC, NHPC, NLC, SJVN, Power Grid, state gencos, BHEL, L&T, Siemens Energy, GE Vernova, ABB/Hitachi Energy, Tata Power and Adani Power. In India the requirements are mandatory, not optional: the Indian Electricity Grid Code and CEA regulations require AVR in continuous service, specified reactive capability and specified protection on every grid-connected unit.

Explained

Why excitation is needed and what limits it

• A synchronous generator produces internal EMF E ∝ Φ ∝ I_f (on the air-gap line). With the machine on an infinite bus, changing I_f changes E, hence the reactive power exchanged, not the real power (real power comes from the turbine).
• Over-excited (E > V): machine delivers lagging VARs, acts as a VAR source, behaves like a capacitor to the grid. Under-excited (E < V): machine absorbs VARs. Normal excitation: unity power factor.
• At constant power, varying I_f traces the V-curve (armature current versus field current) — minimum current at unity pf.
• The capability curve (operating chart) is bounded by: rotor/field winding heating (over-excited boundary, an arc of radius E_max·V/X_s centred at −V²/X_s), armature current heating (arc of radius S_rated at origin), and in the under-excited region stator end-core heating plus the steady-state stability limit; the top is the turbine MW limit.
• Excitation also provides field forcing during faults: a brief large field voltage holds up the internal EMF, raising synchronising power and improving first-swing stability.

Types of excitation system

1. DC (rotating) excitation — conventional. A shaft-mounted DC shunt/separately-excited main exciter, often with a smaller pilot exciter, feeds the field through slip rings and brushes. Simple and robust, but slow (exciter time constant 0.3–1 s), with commutator and brush maintenance. Modelled as IEEE Type DC1A/DC2A.
2. Static (bus-fed / potential-source) excitation. A step-down excitation transformer from the generator terminals (or auxiliary bus) feeds a thyristor (SCR) full-wave bridge, whose DC output goes to the field through slip rings. Response is almost instantaneous (≈ 20–50 ms), ceiling voltage high, and it allows negative field forcing and fast de-excitation. Drawback: at a close-in fault the terminal voltage collapses, so the source collapses too — hence compound-source (current + potential) schemes, and field flashing needed at start-up. Model: IEEE Type ST1A.
3. Brushless (rotating-rectifier) excitation. A shaft-mounted AC exciter (inverted alternator) feeds a rotating diode bridge on the shaft, which feeds the field directly — no slip rings, no brushes. A permanent-magnet generator (PMG) pilot exciter makes it self-contained and fault-independent. Used widely in DG sets and aero/marine sets; slower than static, no direct access for rotor earth-fault measurement or forced de-excitation. Model: IEEE Type AC5A/AC8B.
4. Static excitation with digital AVRs (dual-channel, hot-standby) is standard in new Indian thermal units; excitation system standards are IEC 60034-16 series and IEEE 421.1/421.2/421.4/421.5 (models and specification).

AVR loop, limiters and the power system stabiliser

• Loop: generator VT → rectifier/transducer → compare with voltage reference → error → AVR amplifier → gate pulses → thyristor bridge → field → flux → terminal voltage. A closed-loop negative-feedback regulator, usually holding voltage within ±0.5% of setpoint.
• Steady-state accuracy versus stability: high gain gives small steady-state error but can cause hunting; a transient gain reduction (lead-lag) block or exciter damping (rate feedback, K_F s/(1+sT_F)) stabilises the loop.
• Droop / reactive-current compensation (quadrature droop): a small positive droop (typically 3–5%) on reactive current is added so that machines in parallel share reactive power instead of fighting; without it one machine takes all the VARs. Line-drop (negative) compensation regulates a point inside the step-up transformer.
• Limiters, which act on the AVR before protection trips:
  • OEL / maximum excitation limiter (MXL): inverse-time limit on field current to protect the rotor winding; coordinated below the rotor thermal / field overcurrent protection (49R / 76F).
  • UEL / minimum excitation limiter: prevents operation beyond the under-excited stability / end-core heating boundary; coordinated above relay 40.
  • Stator current limiter, V/Hz limiter (protects generator-transformer core at low speed), PF limiter.
• Power System Stabiliser (PSS): a supplementary input (speed, power or frequency deviation) to the AVR that adds damping torque to low-frequency rotor oscillations (0.2–2 Hz) which high-gain AVRs otherwise reduce. IEEE types PSS1A (single input) and PSS2B/PSS2C (dual input, Δω and ΔP) are the common choices. Indian practice: AVR must stay in automatic/service continuously, and PSS is required and must be tuned on larger units — the exact MW threshold is set in the CEA Connectivity Regulations and IEGC and has been amended, so confirm the current text rather than quoting a number from memory.

Field flashing, de-excitation and field forcing

• Field flashing (initial excitation): a static exciter has no output until the machine has voltage, so at start-up the field is briefly energised from the station battery (or an auxiliary rectifier) until residual/build-up voltage is enough for the excitation transformer to take over; the flashing contactor then drops out.
• Ceiling voltage: the maximum field voltage the exciter can deliver (typically 1.6–2.0 pu for rotating exciters, 2.5–6 pu for static). Excitation system nominal response (response ratio) quantifies speed of build-up over the first 0.5 s.
• De-excitation: on tripping, the field must be discharged fast but without over-voltage. The field breaker transfers the field into a field discharge resistor (or non-linear ZnO resistor), typically 1–5 times the field resistance; thyristor bridges can additionally invert (negative field voltage) for very fast de-excitation. A crowbar protects the bridge against rotor-induced over-voltage during pole slipping or asynchronous running.
• Automatic/manual changeover: manual (field-current) control is a backup only; running on manual indefinitely is a grid-code violation because the machine then gives no voltage support.

Generator neutral earthing and fault behaviour

• Generator stator earth faults must be limited to avoid burning the stator core (iron damage rises steeply above a few amperes). Options:
  • High-resistance earthing through a distribution transformer (standard for large unit-connected sets): neutral to an 11 kV/240 V transformer with a secondary resistor, limiting earth-fault current to about 5–15 A.
  • Low-resistance / resistance earthing (a few hundred amperes) where selective earth-fault discrimination is needed on a bus-connected machine.
  • Reactance or resonant (Petersen coil) earthing, and unearthed on small sets (then neutral displacement 59N is the only detector).
• Stator faults: phase-phase and phase-earth (detected by 87G and 64G/59N), inter-turn faults in the same phase (not seen by 87G — needs split-phase differential or transverse differential in multi-winding machines).
• Rotor faults: a single field earth fault does no immediate harm (field is an unearthed circuit) but a second one short-circuits part of the field, unbalancing flux and causing severe vibration — hence relay 64F/64R alarms on the first fault.

Generator protection functions (ANSI/IEEE device numbers)

• Trip categories: *Class A* — electrical fault: trip generator breaker, field breaker and turbine simultaneously. *Class B/sequential* — mechanical: close stop valves first, let 32L/32R confirm power has fallen, then trip the breaker (avoids over-speeding the turbine).
• Standards and Indian practice: IEEE C37.102 (AC generator protection guide), C37.101 (generator ground protection), C50.12/C50.13 (machine ratings and withstand), IS/IEC 60034-1 (ratings, unbalance withstand), IS 16227 / IEC 61869 (CTs and VTs; formerly IS 2705 and IS 3156), CEA (Technical Standards for Connectivity to the Grid) Regulations 2007 as amended, CEA (Measures relating to Safety and Electric Supply) Regulations, IEGC 2023 (AVR/PSS, reactive support, frequency and voltage bands), all under the Electricity Act 2003. Grid voltage/frequency bands and PSS thresholds are periodically revised by CERC/CEA — check the current notification.

Key points

• Excitation system - supplies controlled DC to the field; sets internal EMF, terminal voltage and reactive output.
• Three families - DC rotating exciter (slow, brushes), static/thyristor (fastest, needs field flashing), brushless with rotating diodes (no brushes, moderate speed).
• AVR - closed loop on terminal voltage; must remain in automatic service per Indian grid code.
• Quadrature droop - 3–5% reactive droop lets paralleled machines share VARs instead of circulating current.
• Ceiling voltage and response ratio - measures of how hard and how fast the exciter can force the field during a fault.
• OEL / UEL - excitation limiters that keep the machine inside the capability curve; UEL set inside relay 40, OEL inside 49R.
• PSS - adds damping to 0.2–2 Hz rotor swings that high-gain AVRs tend to weaken.
• Field discharge resistor - 1–5 × field resistance; absorbs ½LI² on de-excitation while limiting induced voltage.
• 87G - biased differential, the main fast protection for stator phase faults; blind to inter-turn faults.
• High-resistance neutral earthing - limits stator earth-fault current to roughly 5–15 A to save the core.
• 100% stator earth-fault protection - third-harmonic or 20 Hz injection covers the neutral-end blind spot of 59N.
• Relay 40 - two offset mho circles: Zone 1 diameter 1.0 pu, Zone 2 diameter X_d, both offset −X′_d/2.
• Relay 46 - negative-sequence current heats the rotor surface at twice supply frequency; withstand is I₂²t = K.
• 51V, not 51 - generator fault current decays to near rated value, so overcurrent backup must be voltage-restrained or voltage-controlled.
• 32R reverse power - detects motoring on loss of steam/water; set at a fraction of a percent to a few percent of rating.
• 24 V/Hz - over-fluxing is a run-up and load-rejection risk; a generator-transformer core saturates when V/f exceeds about 1.05–1.10 pu.
• 64F - a first rotor earth fault is only an alarm condition electrically, but a second one causes damaging vibration.
• Sequential tripping - for mechanical trips, close the valves and confirm low forward power before opening the breaker.

Formulas and examples

Example 1 — excitation needed at rated load. 50 MVA, 11 kV, 3-phase star generator, X_s = 1.2 pu, R_a negligible, operating at rated MVA and 0.85 pf lagging. No-load field current for rated voltage on the air-gap line = 500 A.

• Take V = 1.0∠0° pu, I_a = 1.0∠−31.79° pu (cos⁻¹0.85 = 31.79°).
• jX_s I_a = 1.2∠(90° − 31.79°) = 1.2∠58.21° = 0.631 + j1.021 pu.
• E_f = 1.0 + 0.631 + j1.021 = 1.631 + j1.021 → |E_f| = √(2.660 + 1.042) = 1.924 pu, δ = tan⁻¹(1.021/1.631) = 32.0°.
• Required field current ≈ 1.924 × 500 = ≈ 962 A. At 0.85 pf leading, jX_sI_a = 1.2∠121.79° = −0.631 + j1.021, giving E_f = √(0.369² + 1.021²) = 1.086 pu — barely above 1.0, which is why under-excited running sits close to the stability limit.

Example 2 — sizing the neutral earthing resistor. 11 kV generator, high-resistance earthed through an 11,000/240 V distribution transformer; earth-fault current to be limited to 10 A.

• Phase-to-neutral voltage = 11,000/√3 = 6,351 V. Required total primary resistance = 6,351/10 = 635 Ω.
• Turns ratio n = 11,000/240 = 45.83, n² = 2,101. Secondary resistor R = 635/2,101 = 0.302 Ω.
• During the fault, secondary voltage = 6,351/45.83 = 138.6 V, secondary current = 10 × 45.83 = 458 A, resistor dissipation = 138.6²/0.302 = ≈ 63.6 kW — a short-time (e.g. 30 s / 5 min) rating, not continuous.
• The 59N relay on the resistor sees 138.6 V for a full terminal-end fault; a typical setting of 5% of this (≈ 7 V) covers about 95% of the winding, leaving a neutral-end blind spot that third-harmonic or 20 Hz injection protection covers.

Example 3 — negative-sequence (46) withstand. 250 MVA, 15.75 kV directly-cooled turbo-generator, continuous I₂ capability 8%, K = 10 s. An open phase on the HV side produces I₂ = 0.35 pu.

• Alarm: I₂ > 0.08 pu. Trip time t = K/I₂² = 10/0.35² = 10/0.1225 = 81.6 s.
• If I₂ rises to 0.6 pu, t = 10/0.36 = 27.8 s — the relay must be inverse-time, since a fixed time cannot cover both.
• Rated stator current = 250 × 10⁶/(√3 × 15,750) = 9,164 A, so 0.08 pu ≈ 733 A of negative-sequence current.

Example 4 — loss-of-field (40) relay settings in secondary ohms. 200 MVA, 13.8 kV machine, X_d = 1.8 pu, X′_d = 0.25 pu, CT 10,000/5, VT 13,800/110.

• Z_base = 13.8²/200 = 190.44/200 = 0.9522 Ω primary.
• Zone 1: diameter 1.0 pu = 0.952 Ω; Zone 2: diameter X_d = 1.8 pu = 1.714 Ω; offset = X′_d/2 = 0.125 pu = 0.119 Ω.
• CT ratio = 2,000, VT ratio = 125.45 → multiplier = 2,000/125.45 = 15.94.
• Secondary settings: Zone 1 diameter = 0.952 × 15.94 = 15.2 Ω, Zone 2 diameter = 1.714 × 15.94 = 27.3 Ω, offset = 0.119 × 15.94 = 1.9 Ω. Zone 1 with ~0.1 s, Zone 2 with ~0.5–1 s delay.
• Rated current = 200 × 10⁶/(√3 × 13,800) = 8,367 A, so a 51V voltage-controlled element at 50% of rated = ≈ 4,184 A, armed when V < 80% (≈ 11.0 kV).

Example 5 — de-excitation. Field inductance L_f = 2.2 H, field resistance R_f = 0.35 Ω, field current 1,200 A; peak rotor insulation stress to be kept below 2 kV.

• Stored energy = ½ × 2.2 × 1,200² = 1.1 × 1.44 × 10⁶ = 1.584 MJ.
• R_d ≤ 2,000/1,200 = 1.667 Ω → choose 1.5 Ω (≈ 4.3 × R_f), giving a peak of 1,200 × 1.5 = 1,800 V.
• τ = 2.2/(0.35 + 1.5) = 2.2/1.85 = 1.19 s; current falls to ~2% in about 4τ ≈ 4.8 s.
• Energy in the discharge resistor = 1.584 × 1.5/1.85 = ≈ 1.28 MJ; the rest heats the field winding.

Where it is used

• Thermal and nuclear stations (NTPC, NPCIL, state gencos): digital dual-channel static excitation with OEL/UEL/PSS, numerical generator protection panels (87G, 40, 46, 64G, 78, 24) on 210/500/660/800 MW units.
• Hydro and pumped storage (NHPC, SJVN, THDC, Koyna, Tehri): salient-pole machines with static excitation, brake-and-field-discharge logic, and frequent start-stop requiring reliable field flashing.
• Captive and industrial generation (steel, cement, refineries, sugar co-generation): bus-connected machines on resistance earthing, with 51V, 46, 32R and synchronising check (25).
• Diesel-generator and genset industry (Cummins, Kirloskar, Mahindra Powerol, Jakson): brushless alternators with analogue/digital AVRs, droop settings for parallel operation with the grid or other sets.
• Job roles: commissioning and relay-setting engineers, protection coordination and relay-testing engineers (Omicron/Doble), C&I and excitation OEM engineers (BHEL, ABB/Hitachi Energy, Siemens Energy, GE Vernova, Basler, Andritz), utility testing wings and plant electrical maintenance.
• Grid compliance work: AVR/PSS model validation and tuning submissions to the RLDCs/NLDC, reactive-capability demonstration tests, and protection-audit compliance under the IEGC.

Interview questions

• Q: Why does changing field current change reactive power but not real power on an infinite bus? A: Real power is set by the turbine input (P = E_fV sinδ/X_s adjusts δ to match it), while raising E_f raises E_f cosδ and hence Q = (E_fV cosδ − V²)/X_s.
• Q: What is the main drawback of a bus-fed static excitation system? A: Its supply comes from the generator terminals, so a close-in fault that collapses the voltage also collapses the excitation source — hence compound-source schemes or high ceiling ratio, and a battery for field flashing.
• Q: Why does a brushless excitation system make rotor earth-fault detection difficult? A: There are no slip rings, so the field circuit is not accessible at standstill or at speed for an injection-based 64F measurement.
• Q: What is quadrature droop and why is it needed? A: A 3–5% reduction in voltage setpoint proportional to reactive current, so paralleled machines share VARs stably instead of one machine taking all the lagging load.
• Q: Why can a high-gain AVR reduce system damping, and what fixes it? A: Fast voltage regulation adds negative damping torque to rotor oscillations; a power system stabiliser injects a phase-compensated speed/power signal into the AVR to restore positive damping.
• Q: Why can't plain overcurrent protection be used as generator backup? A: With constant excitation the sustained fault current falls towards or below rated current as reactance changes from X″_d to X_d, so pickup must be voltage-restrained or voltage-controlled (51V), or distance (21).
• Q: How does loss-of-field protection work? A: On losing excitation the machine draws VARs and the measured impedance moves into the fourth quadrant; two offset mho circles (diameters 1.0 pu and X_d, offset −X′_d/2) detect it with time delays.
• Q: Why is negative-sequence current dangerous to a turbo-generator? A: It produces a backward-rotating field that induces double-frequency currents in the rotor surface, wedges and retaining rings, causing rapid localised heating — limited by I₂²t = K.
• Q: Is a single rotor earth fault an emergency? A: Electrically no, because the field circuit is unearthed, so it is normally alarmed; a second earth fault shorts part of the field, unbalances the flux and causes severe vibration, so the first fault must be cleared promptly.
• Q: Why is generator neutral earthing usually high-resistance? A: To limit earth-fault current to around 5–15 A, which keeps stator core burning (and costly restacking) to a minimum while still permitting sensitive 59N detection.
• Q: What is sequential tripping and why use it? A: For mechanical trips the turbine valves are closed first and only after low-forward/reverse power is confirmed is the generator breaker opened, preventing over-speed from sudden load loss.
• Q: Why is V/Hz protection critical during run-up and load rejection? A: Flux is proportional to V/f, so at low speed with excitation applied, or on a sudden load throw-off that raises voltage, the generator-transformer core saturates and overheats — relay 24 trips above roughly 1.05–1.10 pu.

Common mistakes

• Saying field current controls active power, or that the AVR controls MW — the governor controls MW, the AVR controls voltage and MVAR.
• Mixing up the direction of droop: forgetting that negative (line-drop) compensation and positive (reactive) droop have opposite purposes, and setting zero droop on paralleled machines.
• Expecting 87G to detect inter-turn (same-phase) faults or stator earth faults near the neutral — it cannot; these need split-phase/transverse differential and 64G/injection schemes.
• Applying plain 50/51 as generator backup instead of 51V or 21, then being surprised the relay does not pick up.
• Forgetting to convert primary to secondary ohms using (CT ratio / VT ratio) when setting impedance-based relays 40, 21 and 78.
• Treating the excitation limiters (OEL/UEL) and the protection relays (40, 46, 49R) as interchangeable, instead of coordinating limiters to act first so the unit stays online.
• Unit slips in calculations: per-unit versus amperes for I₂, using V_LL instead of V_phase in earth-fault current, or omitting n² when referring the neutral resistor to the primary side.

Related topics

Synchronous machines · Power system protection and switchgear · Power system stability and load-frequency control · Transformers (generator-transformer protection) · Switchgear, circuit breakers and relay testing · Power system operation and the Indian grid code.