Switchgear Protection Relay Types: Complete Selection Guide for Medium Voltage Systems (2026)

Every piece of medium voltage switchgear — whether a vacuum circuit breaker, a ring main unit, or an SF6 load break switch — is only as reliable as its protection relay. The relay is the intelligence that decides when to trip: it must act fast enough to clear faults before equipment is damaged, but slow enough to allow transient conditions (motor starting, transformer inrush) to pass without nuisance tripping.

This guide covers the main protection relay types used in medium voltage switchgear, the engineering principles behind each one, and a practical framework for selecting and setting relays in 6–35 kV distribution systems.

Why Protection Relay Selection Matters for Switchgear

A medium voltage fault releases enormous energy in milliseconds. A bolted three-phase fault on a 12 kV bus with 16 kA symmetrical fault current delivers roughly 3,300 MW of power into the fault point — before the breaker clears it. Every millisecond of delay allows more thermal and mechanical damage to busbars, cable insulation, and transformer windings.

At the same time, over-sensitive protection causes nuisance trips that interrupt supply to healthy feeders, damage rotating machines through repeated starts, and reduce overall system reliability. The relay selection and coordination task is to find the window between "too slow" and "too fast" for every device in the system.

Medium voltage switchgear in China and international markets is governed by IEC 60255 (protection relay performance), IEC 62271 (switchgear standards), and GB/T 14285 (China national relay protection specification). NAIJI Electric designs our switchgear panels to accommodate standard numerical relay formats (7TE or 6U height, 19" rack or flush-panel mounting) from major relay vendors.

Protection Relay Function Codes (ANSI/IEEE C37.2)

Protection functions are internationally identified by ANSI device function numbers. The most common in medium voltage switchgear are:

Type 1: Overcurrent Relays (ANSI 50/51)

Overcurrent protection is the foundation of medium voltage distribution protection. It is applied to virtually every feeder circuit breaker, fused switch, and ring main unit in a distribution system.

Operating Principle

The relay measures the secondary current from a line current transformer (CT). When the measured current exceeds the pickup setting (Ip), the relay starts timing. When the timer expires, it issues a trip command to the circuit breaker.

The key distinction is between the instantaneous element (50) and the time-overcurrent element (51):

• 50 (instantaneous): Trips with no intentional delay when current exceeds the pickup. Operates in 20–80 ms (relay operate time only, excluding breaker clearing time). Used to clear close-in high-magnitude faults rapidly — but set high enough to avoid operation during transformer inrush (typically 8–12× transformer rated current) or motor starting (typically 6–8× rated current).
• 51 (time-overcurrent): Trips after a time delay that depends on the current magnitude relative to pickup. Provides coordination with downstream devices — a downstream fuse or relay trips first for faults in its zone; the upstream relay trips only if the downstream device fails to clear.

IDMT Curve Selection

IEC 60255-151 defines four standard IDMT curves, each suited to a different application context:

The operating time for an IDMT relay is calculated as:

t = TMS × [k / ((I/Ip)^α − 1)]

Where TMS = time multiplier setting, I = measured current, Ip = pickup current, and k/α are curve constants defined by IEC 60255-151 for each curve type (Standard Inverse: k=0.14, α=0.02; Very Inverse: k=13.5, α=1.0; Extremely Inverse: k=80, α=2.0).

CT Ratio Selection for Overcurrent Relays

The CT must be sized to avoid saturation during maximum fault current while providing adequate secondary current for relay measurement at minimum fault current. Key selection rules:

• Primary rating: 125–150% of maximum continuous load current. Example: a 400 A feeder uses a 500/5 or 600/5 CT.
• Secondary rating: 1 A for cable runs >10 m; 5 A for short runs. IEC preference is 1 A for long wiring in modern installations.
• Accuracy class: 5P20 minimum for protection — this means 5% composite error at 20× rated current (accuracy limit factor). For high fault-current systems, 10P20 may be acceptable.
• Burden: Total CT burden (relay input + wiring resistance) must not exceed the CT's rated burden. Exceeding burden causes CT saturation, reducing secondary current and causing relay under-reach.

Type 2: Earth-Fault Relays (ANSI 50N/51N)

Earth-fault (ground-fault) protection detects current flowing from a phase conductor to earth — a condition that can occur through insulation breakdown, cable damage, or equipment failure. In solidly earthed systems (common at 35 kV and above in China), earth-fault currents are large (tens of kA) and can be detected by phase overcurrent relays. In resistance-earthed or isolated-neutral systems (common at 6–12 kV in industrial applications), earth-fault current may be only 5–50 A — too small for phase CTs to detect reliably.

Core Balance CT (Zero-Sequence CT)

For sensitive earth-fault protection in resistance-earthed or isolated systems, a core-balance CT (CBCT) — also called a zero-sequence CT or toroidal CT — is used. All three phase conductors pass through the centre of the CBCT. Under normal conditions (balanced load), the three-phase currents sum to zero and the CBCT produces no output. During an earth fault, the zero-sequence current component produces a net flux in the CBCT core, generating a secondary output that the relay measures.

CBCT sensitivity is typically 0.5–5 A primary, compared to 10–20% of rated current for phase CTs. This makes CBCT-based earth-fault protection 20–100× more sensitive than using the residual connection of phase CTs.

Pickup Settings for Earth-Fault Relays

Type 3: Directional Overcurrent Relays (ANSI 67/67N)

In radial distribution systems, standard overcurrent relays work well — current only flows in one direction (from source to load). But in ring networks, meshed systems, or systems with distributed generation, fault current can flow in both directions through a switching point. Standard overcurrent relays cannot discriminate between fault current flowing toward a fault and load current flowing away from it.

Directional relays solve this by measuring both the magnitude of current (like a standard overcurrent relay) AND the phase angle between the current and a reference voltage (polarizing quantity). The relay only operates when fault current flows in the designated "operate" direction — typically toward the protected feeder, away from the bus.

Polarizing Methods

• Voltage polarized: Uses the phase-to-phase voltage of the healthy phases as the reference. Standard for phase-to-phase and three-phase faults. Requires a VT (voltage transformer) in the switchgear panel.
• Zero-sequence voltage polarized (3V0): Uses the residual voltage (sum of three phase-to-neutral voltages) as the reference for earth-fault direction detection. Required when phase voltage collapses during a close-in fault.
• Negative-sequence polarized: Uses the negative-sequence component of voltage. Most robust for close-in fault conditions where positive-sequence voltage collapses.

Directional relays are standard in ring main unit applications where the same RMU may carry load current in normal direction but fault current in reverse direction during a ring-operated switching configuration.

Type 4: Differential Protection (ANSI 87)

Differential protection compares the current entering and leaving a protected zone. Under normal load conditions and through-fault conditions, current in equals current out (Kirchhoff's current law), so the differential current (Id = I_in − I_out) is near zero. During an internal fault, current flows into the fault point without a corresponding outflow — the differential current spikes, and the relay trips.

The protected zone is defined by the location of the CTs on both ends. This makes differential protection inherently selective — it operates only for faults within its zone, regardless of external fault current magnitude. This is its key advantage over overcurrent protection, which must be coordinated with other devices.

Transformer Differential Protection (87T)

The most common application of differential protection in medium voltage systems is power transformer protection. The relay must handle two complicating factors:

• CT ratio mismatch: The CTs on the HV and LV sides of the transformer have different ratios (because the transformer changes voltage and hence current). Modern numerical 87T relays internally compensate for this ratio mismatch in software.
• Transformer inrush: When a transformer is energized, the magnetizing inrush current (which enters the HV winding but does not exit the LV winding) appears as a large differential current. The 87T relay uses second-harmonic restraint to distinguish inrush (which has high second-harmonic content, typically 15–20% of fundamental) from genuine faults (which are dominated by fundamental frequency).

Busbar Differential Protection (87B)

In primary substations where multiple feeders connect to a common busbar, a busbar fault (typically from insulation failure, contamination, or animal ingress) must be cleared by tripping all breakers connected to the faulted bus section simultaneously. A busbar differential relay sums the currents from all feeder CTs connected to the bus. Under normal operation, the sum is zero. During a busbar fault, the sum equals the fault current — the relay detects this and trips all bus-connected breakers in <30 ms.

Type 5: Distance Protection (ANSI 21)

Distance relays measure the impedance between the relay location and the fault point. Since impedance is proportional to distance along the feeder (for a given conductor), the measured impedance tells the relay approximately where the fault is. Distance protection is the primary protection method for high-voltage and extra-high-voltage overhead transmission lines, where the long line lengths make simple overcurrent coordination difficult.

In medium voltage switchgear (6–35 kV), distance protection is less common but is applied in these scenarios:

• Long MV overhead lines (>20 km) where fault current levels at the remote end are too low for reliable overcurrent relay operation.
• Lines with variable source impedance (e.g., when local generation can change the fault level dramatically).
• Interconnected MV networks where directional overcurrent coordination is difficult.

Distance relays operate in zones (Zone 1, Zone 2, Zone 3), each covering a different percentage of the protected line with different time delays — typically: Zone 1 covers 80–85% of the line instantaneously, Zone 2 covers 120% with 0.3–0.5 s delay (as backup for the adjacent line), Zone 3 covers 200–250% with 0.6–1.0 s delay (remote backup).

Relay Coordination Principles for Medium Voltage Switchgear

Protection coordination (also called grading or discrimination) ensures that the relay closest to a fault operates first, minimizing the extent of the supply interruption. In radial distribution systems, coordination is achieved by a combination of current grading (higher-set relays closer to the source) and time grading (upstream relays have longer delays).

Coordination Time Interval (CTI)

The minimum time difference between the operating time of an upstream relay and a downstream relay at the same fault current level. CTI must account for:

• Breaker interrupting time: typically 40–80 ms for vacuum circuit breakers
• Relay overshoot time (electromechanical relays): up to 50 ms; numerical relays: <10 ms
• CT transient errors: up to 20 ms
• Safety margin: 50 ms minimum

Recommended CTI for modern numerical relay + vacuum circuit breaker combinations: 200–300 ms. For older electromechanical relays with oil circuit breakers: 400–500 ms. Tighter CTI values are possible with high-speed communication-based protection schemes (GOOSE messaging in IEC 61850 substations).

Coordination Example: 12 kV Radial Feeder

Consider a simple radial system: 110/12 kV transformer → 12 kV bus → Feeder A → Distribution transformer T1:

The 400 ms CTI between R2 and R1 gives sufficient margin for the breaker at Feeder A to interrupt and for R1 to reset before tripping.

Numerical vs Electromechanical Relays in Modern Switchgear

Modern medium voltage switchgear is equipped almost exclusively with numerical (microprocessor-based) protection relays. The last generation of electromechanical induction-disc relays is still found in equipment from the 1970s–1990s that has not been retrofitted, but new installations universally use numerical devices.

For new switchgear installations and retrofits, NAIJI Electric specifies numerical relays from established manufacturers (SEL, Siemens SIPROTEC, ABB REF, Schneider Sepam, NR Electric) that mount in our standard circuit breaker panel relay compartment. We supply the switchgear mechanically and electrically prepared for relay mounting, wiring, and CT connections.

Communication-Based Protection: IEC 61850 GOOSE

IEC 61850 is the international standard for communication in electrical substations. Its GOOSE (Generic Object Oriented Substation Event) messaging protocol allows protection relays to exchange binary signals (trip commands, block signals, switch positions) over a local area network (LAN) with latency <4 ms — fast enough for protection purposes.

GOOSE-based protection schemes enable functions that would be difficult or expensive with traditional hardwired schemes:

• Busbar protection: Each feeder relay can send its measured current contribution to a central bus protection IED, which calculates differential current and trips all feeders simultaneously via GOOSE — without copper wiring between relay panels.
• Transfer trip: A relay at one end of a cable can trip the circuit breaker at the remote end via GOOSE over fiber, enabling rapid clearance of cable faults that would otherwise require waiting for backup protection to operate.
• Adaptive coordination: When the network topology changes (a tie switch closes, switching from radial to ring operation), relays automatically receive new settings via GOOSE to maintain correct coordination in the new configuration.

IEC 61850 capability is increasingly specified by utilities and industrial buyers for medium voltage switchgear above 33 kV, and is becoming common in 12 kV distribution automation systems. NAIJI Electric's switchgear panels are engineered with the secondary wiring, relay mounting space, and fiber optic cable routing required for IEC 61850 implementations.

Protection Relay Selection: Step-by-Step Framework

When specifying protection relays for a medium voltage switchgear project, work through these steps in order:

Step 1 — Define the network: Radial, ring, or meshed? Neutral earthing (solid, resistance, isolated)? Number of sources (single infeed or multiple, including DG)? This determines whether directional elements (67/67N) are needed.

Step 2 — Calculate fault levels: Maximum and minimum three-phase fault current at each busbar, and maximum single-phase earth-fault current. These values set the operating range for relay and CT selection. Minimum fault current sets the sensitivity requirement; maximum sets the CT saturation and CT accuracy limit factor requirement.

Step 3 — Define the coordination chain: List all protective devices from the fault location back to the source, in order. Assign a maximum operating time to each level, working backward from the closest device to the fault (fastest) to the source (slowest).

Step 4 — Select CT ratios: Size CTs at 125–150% of maximum load current (primary), choose 1 A or 5 A secondary, and verify accuracy class 5P20 is adequate for the maximum fault current and relay burden.

Step 5 — Select relay functions: At minimum, every feeder circuit breaker needs 50/51 + 50N/51N. Add 67/67N for ring or multi-source systems. Add 87T for transformer protection. Add 79 (auto-reclose) for overhead line feeders.

Step 6 — Calculate settings: Set 51 pickup at 1.2–1.5× maximum load current. Select IDMT curve to match downstream fuse characteristics. Calculate TMS from the required operating time at the minimum fault current seen at the relay. Set 50 pickup above transformer inrush (8× for 51 inrush, or 1.25× maximum through-fault current).

Step 7 — Verify coordination: Plot time-current curves (TCC curves) for all devices in the coordination chain on the same log-log graph. Confirm the CTI between each adjacent pair of devices is ≥200 ms at all fault current levels. Adjust TMS values if any device pair violates the CTI.

NAIJI Electric Switchgear and Protection Integration

At NAIJI Electric, we manufacture medium voltage switchgear — vacuum circuit breakers, ring main units, and SF6 load break switches — and we work closely with protection relay suppliers to ensure our switchgear is ready for seamless relay integration. Our panels are designed with:

• Standardized CT secondary terminal blocks (1 A and 5 A configurations) with shorting facilities for safe CT secondary circuit work
• VT secondary terminal blocks with 63 V and 110 V outputs for voltage-polarized directional elements
• Relay mounting space in 19" rack format (6U or 9U) or dedicated relay panels
• Trip circuit supervision (TCS) wiring for relay and breaker health monitoring
• Fiber optic conduit routing for IEC 61850 GOOSE communication cables

Whether you are specifying new switchgear for a 12 kV distribution substation or retrofitting protection on aging equipment, our technical team can advise on relay selection, CT sizing, and setting recommendations. Contact NAIJI Electric to discuss your protection requirements.