Power system protection: relays and circuit breakers

In short

Power system protection is the set of current/voltage transformers, relays, trip circuits and circuit breakers that detect a fault (short circuit, earth fault, overload, abnormal frequency or voltage) and isolate only the faulty element, fast enough to protect equipment and keep the rest of the grid stable. A relay is the brain that decides; the circuit breaker is the muscle that interrupts current, including arcing currents tens of thousands of amperes. The subject is examined heavily in GATE EE (Power Systems section carries protection every year), in university Power System Protection / Switchgear papers, and in interviews at POWERGRID (PGCIL), NTPC, NHPC, state transcos and discoms, Tata Power, Adani, L&T, Siemens, ABB/Hitachi Energy, Schneider, GE Grid and Crompton. Indian practice follows IS/IEC 60255 (relays), IEC 62271-100/IS 13118 (breakers) and the CEA and CERC grid code requirements.

Explained

Philosophy, zones and relay qualities

• Purpose: isolate the faulted element quickly, limit damage and fire risk, protect personnel, and preserve stability of the remaining system (the actual fault clearing time must stay below the system's critical clearing time).
• Five qualities: *selectivity* (trip only the faulty zone), *speed* (typically 1–3 cycles at EHV), *sensitivity* (detect minimum fault current, e.g. high-resistance earth faults), *reliability* = dependability + security, and *economy*.
• Zones of protection: overlapping regions defined by CT locations around each generator, transformer, busbar, line and motor. Overlap at the breaker ensures no blind spot; a fault in the overlap trips both zones.
• Primary (main) protection acts first. Backup acts if primary or its breaker fails: *local backup* (second relay, breaker-failure/LBB protection), *remote backup* (Zone 2/Zone 3 of the distance relay at the far substation, or upstream IDMT grading).
• Unit (restricted) protection — differential, REF, pilot wire — responds only to faults inside its zone, needs no grading, is fast and selective, but needs interconnected CTs and, for line schemes, a communication channel. Non-unit protection — overcurrent, distance — reaches beyond its zone and must be time-graded.
• Trip chain: CT/VT → relay measurement → relay contact/output → breaker trip coil (usually 110/220 V DC from the station battery) → breaker opens → arc extinguished at current zero. Trip circuit supervision monitors the healthiness of this DC path continuously.

Instrument transformers

• CT: steps fault and load current down to 1 A or 5 A secondary. Measuring CTs (class 0.2S, 0.5) must saturate early to protect meters; protection CTs (class 5P10, 10P20, class PS/PX) must stay linear up to many times rated current.
• 5P10 means ≤5% composite error at 10 × rated current (accuracy limit factor 10). Class PS/PX CTs are specified by knee-point voltage Vk, magnetising current at Vk/2 and winding resistance — used for differential and restricted earth fault (REF).
• Knee point = the point where a 10% rise in voltage needs a 50% rise in magnetising current. CT saturation during heavy or DC-offset faults produces distorted secondary current and can cause maldoperation of differential relays.
• Burden = VA the relay plus leads impose on the CT; excessive burden pushes the CT into saturation. CT secondary must never be open-circuited when energised — dangerous induced voltage.
• VT/PT: electromagnetic VTs up to ~132 kV; CVT (capacitor voltage transformer) at 220 kV and above, doubling as a PLCC coupling. CVTs have transient response errors that affect distance relays for close-in faults.
• Polarity: CT P1/P2 (primary) and S1/S2 (secondary) dots must be consistent — wrong polarity makes directional and differential schemes fail.

Relay types by construction and by function

Construction (historical to modern):

1. Electromagnetic attraction — plunger/attracted-armature; instantaneous, used for definite-time and high-set units.
2. Electromagnetic induction — induction disc (inverse-time) and induction cup (fast, directional, distance). The disc's torque ∝ φ₁φ₂ sin θ gives the classic IDMT characteristic.
3. Static relays — transistor/op-amp comparators; faster, low burden, no moving parts, but sensitive to transients and supply quality.
4. Digital/numerical relays — microprocessor sampling of CT/VT signals, DFT-based phasor estimation; multi-function (overcurrent + distance + autoreclose + metering), self-monitoring, event and disturbance recording, IEC 61850 station bus with GOOSE messaging. These dominate new Indian substations.

Function:

• Overcurrent (50/51) and earth fault (50N/51N): instantaneous (50) and inverse-time (51).
• Directional overcurrent (67/67N): adds a polarising voltage so the relay responds only to faults in one direction — essential on ring mains, parallel feeders and in-feeds.
• Differential (87): compares currents entering and leaving a zone.
• Distance (21): measures V/I to estimate the distance to the fault.
• Others: under/overvoltage (27/59), under/overfrequency (81U/81O), negative sequence (46), thermal overload (49), reverse power (32), loss of field (40), out-of-step (78), breaker failure (50BF), lockout (86), autoreclose (79). The numbers are ANSI/IEEE C37.2 device numbers, used universally in Indian relay panels.

Overcurrent protection, IDMT characteristics and grading

• Settings: *plug setting* (PS, pickup, expressed as % of CT secondary rating) and *time multiplier setting* (TMS, 0.025–1.0 scaling the curve).
• Plug setting multiplier PSM = (fault current in CT secondary) / (relay pickup current). The curve gives time only in terms of PSM.
• IEC 60255-151 curves: standard inverse (SI), very inverse (VI), extremely inverse (EI), long-time inverse. EI (t ∝ 1/I²) matches fuses and transformer damage curves; VI suits sources where fault current falls steeply with distance.
• Grading methods: *time grading* (fixed discrimination margin), *current grading* (high-set instantaneous set above the far-end fault level), and the usual *combination* of both.
• Discrimination/grading margin: typically 0.3–0.4 s between successive IDMT relays with modern numerical relays and fast breakers (older electromechanical practice used 0.5 s). It covers breaker operating time, relay overshoot, CT errors and a safety margin.
• Pickup rule of thumb: phase overcurrent pickup set above maximum load (about 1.2–1.5 × full load) but below minimum fault current; earth fault pickup can be set much lower (10–40%) since healthy-system residual current is small.
• Directional feature needs a polarising quantity: 90° connection (quadrature) is standard for phase relays; residual voltage (3V₀) or neutral CT current polarises earth-fault directional elements.

Differential and distance protection

• Percentage (biased) differential: operating quantity |I₁ − I₂|, restraint |I₁ + I₂|/2. A bias slope (typically 20–40%, often dual slope) prevents tripping on spill current from CT mismatch and saturation during heavy through-faults.
• Transformer differential: must handle (a) turns ratio and CT ratio mismatch, (b) vector group phase shift (Dyn11 → 30°), (c) star-point zero-sequence current — corrected by interposing CTs/delta CT connection in old schemes, by software in numerical relays; and (d) magnetising inrush, blocked using 2nd-harmonic restraint (inrush is rich in 2nd harmonic), with 5th-harmonic restraint for overexcitation.
• Restricted earth fault (REF): high-impedance scheme comparing neutral CT current with residual of phase CTs — very sensitive for earth faults near the star point.
• Busbar protection: high-impedance differential or low-impedance numerical busbar schemes with check zones; must be very secure because a false trip blacks out the whole bus.
• Distance protection: relay computes apparent impedance Z = V/I; it trips if Z falls inside the characteristic. Advantage: reach depends on line impedance, not on source fault level, so settings are stable.
• Characteristics on the R–X diagram: impedance (circle at origin, non-directional), mho (self-polarised circle passing through origin — inherently directional, the standard for phase faults on EHV lines), reactance (for earth faults, tolerant of arc resistance), quadrilateral (numerical relays — independent resistive and reactive reach), and offset mho (for close-in faults and power-swing blocking).
• Zone settings (typical Indian EHV practice): Zone 1 = 80–85% of the line, instantaneous (under-reach guards against measurement error); Zone 2 = 120–150% of the line (covers remainder plus busbar), delay 0.3–0.4 s; Zone 3 = line + 120% of the longest adjacent line, delay 0.8–1.0 s, as remote backup. Zone 4 (reverse) is used for bus/backup.
• Problems: arc resistance, in-feed from intermediate substations (relay under-reaches), series compensation, and load encroachment — Zone 3 picking up on heavy load. Power-swing blocking (PSB) and out-of-step tripping are provided; Zone 3 operation on load encroachment contributed to the 30–31 July 2012 Indian grid blackouts, after which load-encroachment blocking and PSB review became standard.
• Pilot/carrier schemes: permissive under-reach (PUTT), permissive over-reach (POTT), blocking and direct-transfer-trip schemes over PLCC or fibre give 100% line coverage at Zone 1 speed; line differential over fibre is now common on new 400 kV lines.

Circuit breakers: arc interruption and types

• Operation: a trip signal releases stored energy (spring, pneumatic or hydraulic) to separate contacts; an arc forms, and the breaker must deionise the gap at a natural current zero faster than the dielectric stress rebuilds.
• Arc theories: *Slepian's recovery-rate theory* — interruption succeeds if dielectric strength of the gap rises faster than the restriking voltage; *Cassie–Mayr energy-balance theory* — succeeds if the rate of heat removal exceeds the rate of heat generation in the arc column.
• Methods of arc extinction: high-resistance method (lengthening, cooling, splitting the arc — used in LV air breakers) and low-resistance / current-zero method (used in all AC HV breakers).
• Restriking voltage is the transient voltage across the contacts immediately after interruption; recovery voltage is the power-frequency voltage that settles after the transient. RRRV (rate of rise of restriking voltage, kV/µs) decides success.
• Types:
  • ACB (air circuit breaker) — LV, up to 1,000 V, arc chutes and splitter plates; draw-out switchgear in Indian LV panels.
  • MOCB / bulk-oil and minimum-oil — arc decomposes oil into hydrogen which cools and deionises; largely obsolete (fire risk, maintenance).
  • Air-blast (ABCB) — compressed air blast; fast, used earlier at 220/400 kV; noisy, now replaced.
  • Vacuum (VCB) — interruption in a vacuum of 10⁻⁴ torr or better; very high dielectric recovery in microseconds, long contact life (10,000+ operations), maintenance-free. The standard for 11 kV–33 kV Indian distribution; now also available up to 145 kV.
  • SF₆ — excellent electronegative gas; puffer or self-blast (thermal expansion) interrupters. The standard at 132 kV and above, and the basis of GIS. Limitation: SF₆ has a global warming potential around 23,500 and is covered by handling/leak-rate rules; vacuum and SF₆-free alternatives (C4-FN mixtures, clean air) are being introduced.
  • HVDC breakers — no natural current zero, so hybrid solid-state/mechanical designs force a zero.
• Special phenomena: current chopping in vacuum and air-blast breakers (small inductive currents forced to zero before natural zero) causes switching overvoltage; capacitive switching risks restrike and voltage escalation; short-line (kilometric) fault gives a severe sawtooth RRRV; resistance switching (a resistor across the interrupter) damps the transient and reduces RRRV.
• Ratings (per IEC 62271-100 / IS 13118): rated voltage, rated normal current, rated short-circuit breaking current (rms symmetrical, kA, with a DC component percentage), rated short-circuit making current (peak), short-time withstand current and duration (e.g. 40 kA for 1 s or 3 s), rated operating sequence (O–0.3 s–CO–3 min–CO for autoreclosing duty), break time (typically 2–3 cycles at EHV), and rated insulation levels (power frequency and BIL).
• Autoreclosure: most EHV faults are transient, so single-pole autoreclose (dead time ~1 s) is standard on Indian 220/400 kV lines; three-pole autoreclose on distribution.

Fuses, earthing and other protection

• HRC fuse: silver element in quartz sand; it cuts off the current before the prospective peak, limiting let-through energy (I²t). Fast, cheap, maintenance-free, but single-shot and non-selective at low overloads. Covered by IS/IEC 60269 and IS 13703 (LV), IS 9385 (HV).
• Fuse terms: rated current, minimum fusing current, fusing factor = minimum fusing current / rated current, cut-off current, prospective current, breaking capacity.
• Transformer non-electrical protection: Buchholz relay (gas accumulation alarm, oil surge trip, for conservator-type transformers above ~500 kVA), pressure relief device, oil and winding temperature indicators, sudden pressure relay.
• Generator protection: differential (87G), stator earth fault (95% and 100% schemes), rotor earth fault (64R), negative-sequence/unbalanced loading (46), loss of excitation (40), reverse power (32), over/under frequency, over-fluxing (V/Hz, 24), and pole-slipping (78).
• Motor protection: thermal overload, locked rotor, unbalance/single-phasing, under-voltage, earth fault; motor protection relays per IS/IEC 60255.
• Neutral earthing decides earth-fault current: solid earthing (LV and EHV), resistance earthing (generators, industrial 11 kV), Petersen coil (resonant earthing) and unearthed systems (where earth-fault current is tiny and only alarm/directional detection is possible). Earthing practice follows IS 3043.
• Indian framework: Electricity Act 2003; CEA (Measures relating to Safety and Electric Supply) Regulations, 2023 (in force 8 June 2023, superseding the 2010 Regulations) mandate protective devices and earthing; CEA (Technical Standards for Connectivity to the Grid) Regulations; the CERC Indian Electricity Grid Code sets protection, relay-setting coordination, disturbance recorder and event-logger obligations for grid-connected users — specific clauses have been revised (IEGC 2023), so check the current notified version before quoting a clause.

Key points

• Protection zone - overlapping region bounded by CT locations; overlap at the breaker leaves no unprotected gap.
• Unit vs non-unit - differential/REF are selective without grading; overcurrent and distance reach outside the zone and need time grading.
• Dependability vs security - dependability is tripping when required; security is not tripping when not required; reliability needs both.
• PSM - fault current in CT secondary divided by relay pickup; the IDMT curve is a function of PSM only.
• TMS - time multiplier that scales the whole curve; used to grade relays in series.
• Grading margin - 0.3–0.4 s typical with numerical relays; covers breaker time, overshoot and errors.
• Directional relay - needs a polarising voltage; the 90° (quadrature) connection is standard for phase faults.
• Percentage bias - restraint proportional to through-current prevents differential maloperation on CT saturation.
• 2nd-harmonic restraint - blocks transformer differential during magnetising inrush; 5th harmonic blocks on overexcitation.
• Distance Zone 1/2/3 - 80%, 120%, line + 120% of adjacent line, with 0, ~0.35 s and ~0.9 s delays.
• Mho relay - self-polarised circle through the origin; inherently directional, standard for EHV phase-fault distance protection.
• Knee-point voltage - CT voltage at which a 10% voltage rise needs 50% more magnetising current; defines class PS CTs for differential schemes.
• RRRV - rate of rise of restriking voltage; interruption fails if the gap's dielectric recovery is slower.
• Making capacity - peak current the breaker can close onto, about 2.5 × rms symmetrical breaking current at 50 Hz.
• Current chopping - premature forcing of small inductive current to zero in vacuum/air-blast breakers, producing overvoltage L·di/dt.
• VCB below 36 kV, SF₆ above 132 kV - the default Indian selection; SF₆ is a potent greenhouse gas with handling obligations.
• HRC fuse cut-off - fuse clears before the prospective peak, limiting let-through I²t energy.
• CT secondary open circuit - never permitted while energised; produces dangerously high voltage.

Formulas and examples

Example 1 — IDMT relay operating time. CT 500/5, plug setting 125%, TMS 0.6, standard inverse. Fault current 6,000 A.

• Secondary current = 6,000 × 5/500 = 60 A; pickup = 1.25 × 5 = 6.25 A.
• PSM = 60 / 6.25 = 9.6.
• 9.6^0.02 = e^{0.02 × 2.2618} = 1.04627 → denominator = 0.04627.
• t = 0.6 × 0.14 / 0.04627 = 1.82 s.

Example 2 — grading the upstream relay. The upstream relay sees the same 6,000 A through CT 1000/5, plug setting 100%. Grading margin 0.4 s → required time = 1.82 + 0.4 = 2.22 s.

• Secondary current = 6,000 × 5/1000 = 30 A; pickup = 5 A → PSM = 6.
• 6^0.02 = e^{0.02 × 1.7918} = 1.03649 → denominator = 0.03649; 0.14/0.03649 = 3.837.
• TMS = 2.22 / 3.837 = 0.579 → set TMS ≈ 0.58 (nearest available step).

Example 3 — restriking voltage and RRRV. 132 kV, 50 Hz system; L = 5 mH, C = 0.02 µF per phase; interruption at current zero, no damping.

• Peak phase voltage V_m = 132/√3 × √2 = 76.21 × 1.4142 = 107.8 kV.
• √(LC) = √(5×10⁻³ × 2×10⁻⁸) = √(1×10⁻¹⁰) = 1×10⁻⁵ s; f_n = 1/(2π×10⁻⁵) = 15.9 kHz.
• Peak restriking voltage = 2 × 107.8 = 215.6 kV; time to peak = π × 10⁻⁵ = 31.4 µs.
• Average RRRV = 215.6 / 31.4 = 6.9 kV/µs; maximum RRRV = V_m/√(LC) = 107.8 kV / 10⁻⁵ s = 10.8 kV/µs.
• Critical damping resistor R = 0.5√(L/C) = 0.5√(5×10⁻³/2×10⁻⁸) = 0.5 × 500 = 250 Ω.

Example 4 — breaker rating selection. A 33 kV bus has a symmetrical fault level of 1,400 MVA.

• I_sym = 1,400 × 10⁶ / (√3 × 33 × 10³) = 24.5 kA → choose the standard 25 kA breaker.
• Breaking capacity = √3 × 33 × 25 = 1,429 MVA.
• Making capacity (peak) = 2.5 × 25 = 62.5 kA (62.5–63.8 kA depending on the factor used).
• Short-time withstand: 25 kA for 3 s; a 33 kV VCB or SF₆ breaker is suitable.

Example 5 — distance relay reach. 220 kV line, 100 km, z = 0.4 Ω/km; CT 600/1, PT 220 kV/110 V (ratio 2000:1).

• Z_line(primary) = 40 Ω → Z_sec = 40 × 600/2000 = 12 Ω.
• Zone 1 (80%) = 9.6 Ω secondary (32 Ω primary), instantaneous.
• Zone 2 (120%) = 14.4 Ω secondary (48 Ω primary), ~0.35 s.
• Zone 3 (line + 120% of a 60 km adjacent line = 40 + 28.8 = 68.8 Ω primary) = 20.6 Ω secondary, ~0.9 s.

Where it is used

• Transmission utilities — POWERGRID and state transcos: 400/220/132 kV distance and line-differential schemes, busbar protection, breaker-failure protection, SF₆ and GIS switchyards, disturbance and event recording for grid-code compliance.
• Distribution utilities — discoms (BSES, Tata Power-DDL, MSEDCL, TANGEDCO): 11/33 kV VCB panels with numerical overcurrent and earth-fault relays, autoreclosers, ring main units, sectionalisers and HRC fuses.
• Generation — NTPC, NHPC, NPCIL, captive and solar/wind plants: generator and generator-transformer protection, over-fluxing, islanding and anti-islanding protection for renewables.
• Industry — steel, cement, refinery and data-centre substations: motor protection relays, transformer differential, arc-flash protection, LV ACB and MCCB selectivity studies.
• Job roles — protection and control (P&C) engineer, relay testing/commissioning engineer (Omicron CMC test sets), protection coordination engineer doing ETAP/DIgSILENT studies, substation automation engineer working on IEC 61850 configuration.
• Manufacturers — Hitachi Energy, Siemens, Schneider, GE Vernova, Crompton, Easun, CG Power and L&T supply relays, breakers and switchgear tested to IS/IEC at CPRI and ERDA.

Interview questions

• Q: Difference between unit and non-unit protection? A: Unit protection (differential, REF) responds only to faults inside a defined zone and needs no time grading; non-unit protection (overcurrent, distance) sees beyond its zone and must be graded in time, making it slower but useful as backup.
• Q: What are PSM and TMS? A: PSM is the fault current in the CT secondary divided by the relay pickup current, and fixes the point on the curve; TMS scales that curve's time linearly so relays in series can be graded.
• Q: Why is Zone 1 of a distance relay set to only 80% of the line? A: CT/VT errors, line-impedance data errors and relay measurement tolerance mean a 100% setting could over-reach into the next line and trip instantaneously for an external fault.
• Q: Why does a transformer differential relay use second-harmonic restraint? A: Magnetising inrush current flows only on one side and looks like an internal fault; inrush is rich in second harmonic, so detecting it blocks the trip.
• Q: What is percentage bias and why is it needed? A: The operating threshold rises with through-current, so spill current caused by CT ratio mismatch or CT saturation during a heavy external fault does not cause a false trip.
• Q: What is restriking voltage and how does it differ from recovery voltage? A: Restriking voltage is the high-frequency transient appearing across the contacts just after current zero; recovery voltage is the power-frequency voltage that remains after the transient has died out.
• Q: Why is RRRV more important than the magnitude of the recovery voltage? A: Interruption fails if the voltage across the gap rises faster than the gap regains dielectric strength, so the rate — not just the final value — decides re-ignition.
• Q: Why is a vacuum breaker preferred at 11 kV and SF₆ at 400 kV? A: Vacuum gives extremely fast dielectric recovery, compact size and near-zero maintenance, but a single vacuum gap is limited in voltage withstand; SF₆ has superior insulation and arc-quenching at EHV and supports multi-break and GIS designs.
• Q: What is current chopping and why is it a problem? A: A vacuum or air-blast breaker can force a small inductive current to zero before the natural zero; the sudden di/dt across the load inductance produces an overvoltage I√(L/C), which may need surge arresters or RC snubbers.
• Q: Why must a CT secondary never be open-circuited? A: With no secondary ampere-turns to oppose it, the full primary MMF magnetises the core, driving it deep into saturation and inducing dangerously high peaky voltages across the open terminals.
• Q: What is breaker failure (LBB) protection? A: If the fault current persists after a trip command for a set time (typically 150–250 ms), the scheme assumes the breaker has failed and trips all adjacent breakers on that bus.
• Q: Why can Zone 3 cause problems during heavy loading? A: A large load with low voltage presents a low apparent impedance that can enter the Zone 3 characteristic (load encroachment), so load-blinder or quadrilateral characteristics and power-swing blocking are used.

Common mistakes

• Using primary fault current directly against the relay pickup setting instead of converting through the CT ratio to get PSM.
• Forgetting that the TMS scales time linearly — reading the curve value and quoting it as the operating time without multiplying by TMS.
• Mixing up the IEC constants: 0.14/α = 0.02 is standard inverse, 13.5/α = 1 is very inverse, 80/α = 2 is extremely inverse.
• Confusing making capacity (a peak current, ≈2.5 × symmetrical rms) with breaking capacity (an rms symmetrical current, or MVA).
• Treating restriking voltage and recovery voltage as the same quantity, and quoting 2V_m as the recovery voltage.
• Ignoring the Dyn11 phase shift and the star-point zero-sequence current when setting transformer differential protection.
• Assuming a differential relay needs time grading, or that an overcurrent relay alone gives adequate transmission-line protection.

Related topics

Load flow and fault analysis · Power system stability · Distribution systems and substations · High-voltage engineering and insulation · Power system operation, SCADA and EMS · Transmission lines and cables