How to Select a Feeder Protection Relay: A Practical Guide for Engineers

Introduction

Selecting a feeder protection relay is more complex than picking a model with the right voltage rating.

Choose wrong, and you risk nuisance tripping, protection blind zones, or equipment damage. Poor selectivity can shut down entire feeder sections unnecessarily. Some engineers focus only on the number of protection functions, ignoring CT performance, grounding method, or coordination requirements.

This guide walks through a practical selection process. We will cover system parameters, protection functions, CT matching, grounding considerations, and communication needs. Use this as a checklist for your next project.

This guide on Feeder Protection Relay Selection explains how to select a feeder protection relay based on the actual requirements of a power distribution system.

What Is a Feeder Protection Relay?

A feeder protection relay detects faults on distribution feeders and sends trip signals to circuit breakers. It protects overhead lines, underground cables, transformer feeders, and motor feeders.

What Does a Feeder Protection Relay Protect?

• Distribution feeders (11 kV to 66 kV)
• Overhead lines and underground cables
• Industrial feeders
• Transformer feeders
• Motor feeders

Why Is Feeder Relay Selection Important?

Fault detection must be fast and accurate. Selectivity ensures only the faulty section trips. Reliability prevents unnecessary outages. Backup protection covers equipment failures. System continuity depends on all of these working together.

What Should You Consider When Selecting a Feeder Protection Relay?

Start with this checklist. It covers the key factors engineers evaluate before choosing a relay.

Selection Factor	What to Check
System voltage	11 kV, 22 kV, 33 kV, 66 kV, etc.
Feeder type	Cable, overhead line, or mixed feeder
System grounding	Solid, resistance, impedance, or isolated
Maximum load current	Normal and emergency loading conditions
Short-circuit current	Maximum and minimum fault levels
CT ratio	Primary/secondary current rating
CT class	Accuracy and protection requirements
Protection functions	50/51, 50N/51N, 67/67N, 49, 46, etc.
Coordination	Upstream and downstream protection devices
Communication	IEC 61850, Modbus, DNP3, etc.
Application	Utility, industrial, or renewable energy

Step 1 — Determine the Feeder Voltage and Current Rating

Check the System Voltage

Common medium-voltage levels include 11 kV, 13.8 kV, 22 kV, 33 kV, and 66 kV. The relay must match the protection system and CT/VT configuration. Do not select a relay based solely on nominal voltage.

Calculate the Maximum Feeder Load Current

Use this formula for three-phase current:

Where:

• S = apparent power (kVA or MVA)
• V = line-to-line voltage (kV)

Consider transformer capacity, feeder demand, power factor, and overload conditions. A relay with insufficient current rating will not measure fault currents accurately.

Step 2 — Identify the Feeder Type and Application

Different feeders have different fault characteristics.

Overhead Distribution Feeders

Overhead lines experience transient faults from lightning and conductor contact. Phase-to-ground faults are common. These feeders often benefit from auto-reclosing to clear temporary faults.

Underground Cable Feeders

Cables have thermal limits and higher charging currents. Insulation faults and earth faults require sensitive detection. Cable feeders do not typically use auto-reclosing because faults are usually permanent.

Transformer Feeders

Transformer feeders must handle inrush current during energization. They need short-circuit protection and backup protection for downstream faults. Harmonic restraint prevents nuisance tripping during transformer energization.

Industrial and Motor Feeders

Motor feeders face high starting currents. Protection must distinguish between starting current and fault current. Overload, locked rotor, and phase loss protection are required.

Step 3 — Determine the Required Feeder Protection Functions

This table shows common ANSI protection functions and their applications. Select functions based on the feeder type and fault risks.

ANSI Function	Protection Function	Typical Application
50	Instantaneous overcurrent	High-current phase faults
51	Time overcurrent	Phase fault protection with coordination
50N/50G	Instantaneous earth fault	High-magnitude ground faults
51N/51G	Time earth fault	Sensitive ground fault detection
67	Directional overcurrent	Parallel feeders and ring networks
67N	Directional earth fault	Ground fault direction on multi-source systems
46	Negative sequence	Phase imbalance and broken conductors
49	Thermal overload	Cable and feeder thermal protection
27	Undervoltage	Voltage-related protection
59	Overvoltage	Voltage-related protection
79	Auto-reclosing	Overhead distribution feeders
50BF	Breaker failure	Backup protection
74	CT supervision	CT circuit monitoring

Overcurrent Protection — 50/51

The 50 element provides instantaneous protection for high-current faults. The 51 element provides time-delayed protection based on current magnitude. Use both for phase fault protection in most feeders.

Earth Fault Protection — 50N/51N

Grounding method determines earth fault current magnitude. Solidly grounded systems have high ground fault currents. Resistance-grounded or isolated systems have lower currents and require sensitive elements. Use residual current or core-balance CT connections.

Directional Protection — 67/67N

Directional protection becomes necessary when fault current can flow in more than one direction. Applications include ring networks, parallel feeders, distributed generation, and grid-connected solar systems.

Auto-Reclosing — ANSI 79

Auto-reclosing improves service continuity on overhead feeders. It is not recommended for cable feeders or feeders serving large motors. A multi-shot sequence can clear temporary faults before locking out.

Step 4 — Check CT Requirements Before Choosing the Relay

CT performance affects relay accuracy. This step is often overlooked and causes field issues.

Select the Correct CT Ratio

The CT primary rating should exceed the maximum load current. The secondary rating (1 A or 5 A) must match the relay input. The relay’s measuring range must cover expected fault currents.

Check CT Accuracy and Saturation

CT class defines accuracy and burden capability. Class 10P or 5P CTs are typical for protection. Verify the CT does not saturate at maximum fault current. Saturated CTs produce distorted secondary currents, causing relay misoperation.

A practical check uses:

This ensures the CT can accurately reproduce fault currents.

Match the Relay Input to the CT Secondary

Select a relay with 1 A or 5 A inputs based on the CT secondary rating. Most modern numerical relays accept both through configurable settings.

Step 5 — Consider the Feeder Grounding Method

The grounding method determines earth fault current and affects relay sensitivity.

Solidly Grounded Systems

Ground fault currents can be as high as phase fault currents. Standard 50N/51N elements work well.

Resistance-Grounded Systems

Ground fault current is limited by the neutral resistor. Typical values range from 100 A to 1000 A at 11 kV. The relay must be sensitive enough to detect these limited currents.

Isolated or Ungrounded Systems

Ground fault current is small, typically capacitive charging current. Sensitive earth fault detection is required. Use 51N with low pickup settings or 59N (residual overvoltage) for backup detection.

Why Grounding Affects Relay Selection

Grounding directly affects earth fault current magnitude. This influences the required sensitivity and settings of the feeder protection relay. Select earth fault elements based on the grounding method, not on phase fault settings.

Step 6 — Check Protection Coordination and Selectivity

Coordination ensures the nearest relay to a fault operates first. This minimizes the outage area.

What Is Feeder Protection Coordination?

Coordination means upstream relays provide backup for downstream devices. Each device has a specific pickup current and time delay. The time-current curves should not overlap.

Coordinate the Feeder Relay With:

• Downstream relays
• Upstream relays
• Fuses
• Circuit breakers
• Transformer protection

Time-Current Coordination

Key parameters include:

• Pickup current
• Time multiplier setting (TMS)
• Inverse or definite-time curves
• Instantaneous settings

Avoid Nuisance Tripping

Set the relay to ride through transformer inrush and motor starting currents. Use harmonic restraint or cold load pickup functions to prevent false trips.

Step 7 — Decide Between Non-Directional and Directional Feeder Protection

Directional protection adds complexity but is required in certain networks.

Network	Typical Choice
Radial feeder	Non-directional overcurrent
Ring network	Directional protection
Parallel feeders	Directional protection
Distributed generation	Directional protection
Bidirectional power flow	Directional protection

When Is a Non-Directional Relay Enough?

Radial feeders with a single source do not need directional protection. Fault current always flows from source to fault.

When Do You Need 67/67N Directional Protection?

Directional protection is required when multiple sources can feed a fault. It ensures the relay trips only for faults in its forward direction.

Step 8 — Choose Electromechanical, Static, or Numerical Feeder Relays

Most new installations use numerical relays due to their flexibility and communication capabilities.

Relay Type	Advantages	Limitations
Electromechanical	Simple, proven, robust	Limited functions, no communication
Static	Faster, compact	Less flexible than numerical
Numerical	Multiple functions, communication, event records	Higher configuration complexity

Why Numerical Feeder Protection Relays Are Common in Modern Substations

Numerical relays offer:

• Multiple protection functions in one unit
• Event and fault recording
• Self-monitoring and diagnostics
• Communication for SCADA integration

Step 9 — Check Communication and Automation Requirements

Most projects require remote monitoring and control.

Common Communication Protocols

• IEC 61850 (GOOSE and SV for digital substations)
• Modbus RTU and Modbus TCP
• DNP3
• IEC 60870-5-103

IEC 61850 is increasingly required for digital substations and future-proof system design.

Integration With SCADA and Substation Automation

Look for:

• Remote monitoring and control
• Sequence of events (SOE) logging
• Disturbance recording
• Time synchronization (PTP or IRIG-B)

Step 10 — Check Environmental and Installation Requirements

Relays must operate reliably in their installed environment.

Panel or Switchgear Installation

Consider the relay’s form factor. Some relays are 4U height, suitable for standard panel mounting. Check if the relay fits available space.

Ambient Temperature

Relays have specified operating temperature ranges. Verify the range matches site conditions.

Humidity and Altitude

High humidity or altitude may require derating or special enclosures.

EMC and Electrical Noise

Substations have high electromagnetic interference. Choose relays with IEC 60255 EMC compliance.

Auxiliary Power Supply

Common voltages include DC 24 V, 48 V, 110 V, 220 V, and AC 110-240 V. The relay’s power supply must match site availability.

Feeder Protection Relay Selection Example

Example: 33 kV Distribution Feeder

Known Data:

• System voltage: 33 kV
• Maximum load: 8 MVA
• Grounding: resistance grounded
• CT: 400/1 A
• Network: radial
• Feeder: overhead line + underground cable
• Upstream transformer protection is installed

1. Calculate the Full-Load Current

2. Determine Short-Circuit Protection Requirements

Assume maximum fault current = 10 kA. Minimum fault current at feeder end = 2 kA.

3. Select Phase Overcurrent Protection

• 50 element: Set at 8 kA (instantaneous)
• 51 element: Pickup at 200 A (1.4 × full load), standard inverse curve, TMS to coordinate with upstream

4. Select Earth Fault Protection

Resistance-grounded with 1000 A earth fault current limit. Set 51N pickup at 100 A (10% of limit). Use standard inverse curve for coordination.

5. Check CT Compatibility

CT ratio 400/1 A. At 10 kA fault, CT secondary current = 25 A. Verify relay input range covers this.

6. Check Coordination With the Upstream Relay

The feeder 51 curve must be below the upstream relay curve. The 50 element must be above maximum downstream fault current to avoid overreach.

7. Determine Communication Requirements

Project requires IEC 61850 integration with SCADA. Select a relay with IEC 61850 support.

Recommended Relay Configuration

• Numerical feeder protection relay
• ANSI 50/51 and 50N/51N
• Directional elements not required (radial network)
• IEC 61850 communication
• Event and fault recording
• CT supervision (ANSI 74)

Feeder Protection Relay Selection Checklist

Before selecting a relay, verify:

• [ ] System voltage
• [ ] Maximum load current
• [ ] Minimum and maximum fault current
• [ ] Feeder type (overhead, cable, or mixed)
• [ ] Grounding method
• [ ] CT ratio
• [ ] CT class
• [ ] Required ANSI functions
• [ ] Protection coordination
• [ ] Circuit breaker characteristics
• [ ] Communication protocol
• [ ] Auxiliary power
• [ ] Environmental conditions
• [ ] SCADA requirements
• [ ] Event/fault recording requirements

Common Mistakes When Selecting a Feeder Protection Relay

Selecting a Relay Based Only on Voltage

Voltage rating is not the primary selection factor. Protection functions, CT matching, and coordination matter more.

Ignoring CT Saturation

Saturated CTs cause under-reach or delayed operation. Verify CT performance at maximum fault current.

Using the Same Settings for Every Feeder

Each feeder has different load, fault current, and coordination requirements. Settings must be calculated individually.

Ignoring Grounding Method

Earth fault protection depends entirely on grounding. Using the wrong element can result in failure to detect faults.

Choosing Too Many Protection Functions

Adding functions increases complexity and cost. Select only functions required for the application.

Not Checking Coordination With Upstream and Downstream Devices

Failure to coordinate leads to unnecessary outages or delayed fault clearing.

Ignoring Future Distributed Generation

Distributed generation can change fault current direction. Consider whether directional elements may be needed in the future.

Feeder Protection Relay Selection: Final Recommendations

Follow this decision logic:

System → Feeder → Fault → CT → Protection Functions → Coordination → Communication → Relay

The best feeder protection relay is not the relay with the most functions. It is the relay whose protection functions, measurement inputs, settings range, communication capability, and coordination characteristics match the actual feeder.

Frequently Asked Questions About Feeder Protection Relay Selection

How do I choose a feeder protection relay?

Start with system parameters: voltage, load current, fault current, and grounding method. Then select protection functions based on feeder type and coordination requirements.

What protection functions are required for a feeder?

At minimum, phase overcurrent (50/51) and earth fault (50N/51N) are standard. Directional protection (67/67N) may be required for ring or parallel feeders.

What is the difference between 50/51 and 67 feeder protection?

50/51 are non-directional overcurrent elements. 67 adds directional capability, so the relay trips only for faults in the forward direction.

When is directional protection required for a feeder?

Directional protection is required when fault current can flow in more than one direction. Examples include ring networks, parallel feeders, and systems with distributed generation.

How do I select the CT ratio for a feeder protection relay?

The CT primary rating should exceed maximum load current. The secondary rating (1 A or 5 A) must match the relay input. Verify CT accuracy at maximum fault current.

Do all feeder protection relays need earth fault protection?

Most feeders require earth fault protection. The element type depends on the grounding method. Solidly grounded systems use 50N/51N. Resistance-grounded or isolated systems may need sensitive 51N.

What relay is commonly used for 11 kV and 33 kV feeders?

Numerical feeder protection relays with 50/51 and 50N/51N are standard for 11 kV and 33 kV feeders. Common models include 4U panel-mount relays with IEC 61850 communication capability.

How does feeder relay coordination work?

Coordination ensures the relay closest to a fault operates first. This is achieved by setting pickup currents and time delays so upstream relays provide backup only if downstream relays fail.

References

1. IEEE Standard C37.112-2018 – Standard for Inverse-Time Characteristics of Overcurrent Relays.
2. IEC 60255 Series – Measuring Relays and Protection Equipment.
3. IEC 61850 – Communication Networks and Systems for Power Utility Automation.
4. IEEE Standard C37.91-2021 – Guide for Protecting Power Transformers.
5. IEC 60044-1 – Instrument Transformers – Part 1: Current Transformers.
6. IEC 60909-0 – Short-Circuit Currents in Three-Phase AC Systems.
7. CIGRE Technical Brochure 774 – Protection of Distribution Systems with Distributed Generation.