Setting Calculation of Relay Protection Devices

Relay protection device settings are calculated by determining pickup current, time delay, and coordination parameters to ensure selective and reliable fault isolation.

Overview

Relay setting is the process of selecting the current threshold and time delay at which a relay trips a circuit breaker during a fault. The goal is to isolate only the faulted section quickly while allowing downstream relays to operate first, ensuring system stability and equipment protection .

Key Parameters

1. Pickup Current (Ip or PSM): The minimum current at which the relay operates. Often expressed as a percentage of rated current or using a Plug Setting Multiplier (PSM) .
2. Time Dial Setting (TDS or TMS): Determines the relay's operating delay to coordinate with other relays .
3. Operating Time: Calculated based on the relay curve type (Standard Inverse, Very Inverse, Extremely Inverse, Long Time Inverse) and fault current .
4. Coordination Time Interval (CTI): The time margin between upstream and downstream relay operations to prevent simultaneous tripping .
5. Zone Settings (for distance relays): Defines the reach of the relay in terms of line impedance, typically 80–90% of the line for Zone 1 .

Step-by-Step Calculation Procedure

1. Determine System Parameters

• Collect line or transformer ratings, load current, CT ratios, and fault current levels.
• Identify relay type and curve characteristics.

2. Calculate Pickup Current

• For overcurrent relays: $I_{pickup}=I_{load}\times \text{PSM}$ Choose a PSM that provides a margin above full load, typically 125–150% .

3. Select Time Dial Setting

• Determine the Time Multiplier Setting (TMS) using the relay's inverse time characteristic and desired operating time: $t=TMS\times f(I_{fault}/I_{pickup})$ where $f$ is the relay curve function .

4. Set Coordination

• Ensure downstream relays operate first by calculating CTI: $CTI=t_{upstream}-t_{downstream}$ Adjust TMS or PSM to maintain proper selectivity .

5. Distance Relay Settings (if applicable)

• Determine impedance reach for each zone:
  • Zone 1: 80–90% of line impedance
  • Zone 2: 120–150% of line impedance
• Include resistive components like tower footing and arc resistance .
• Apply zero-sequence compensation if required.

6. Transformer Differential Relay Settings

• Convert secondary currents to per-unit values using TAP scaling.
• Ensure the sum of incoming and outgoing currents matches the reference direction.
• Set TAPmax/TAPmin ratio ≤ 7.5 for proper operation .

7. Verification and Adjustment

• Re-evaluate settings during commissioning using actual measured values.
• Adjust for protection selectivity, system changes, or updated fault levels .

Practical Tools

• Online calculators can simplify the process by computing pickup current, TMS, operating time, CTI, and PSM using input parameters like load current, CT ratio, and fault current .

Summary

Proper relay setting ensures fast, selective fault clearance while maintaining system stability. The procedure involves calculating pickup current, time delay, coordination intervals, and zone reach, followed by verification and adjustment based on actual system conditions. Using standardized formulas and relay curves ensures reliable protection across the network.