Plant-wide relay protection requires calculating pickup currents, time multiplier settings, operating times, and coordination intervals to ensure selective fault isolation and reliable backup protection.

Key Principles of Relay Setting

Relay setting is the process of defining the current threshold and time delay at which a relay trips a circuit breaker during a fault. The main goal is selective fault clearing: downstream relays closest to the fault operate first, while upstream relays provide backup protection if downstream devices fail, preventing widespread outages and localizing disturbances . Modern overcurrent relays use inverse time-current characteristics based on thermal damage curves of protected equipment. IEC 60255 defines four primary curve families: Standard Inverse (SI), Very Inverse (VI), Extremely Inverse (EI), and Long Time Inverse (LTI), each with unique constants to achieve different coordination characteristics .

Essential Calculations

1. Pickup Current (Ip)
   • The minimum current at which the relay starts to operate.
   • Typically set above the maximum load current to avoid nuisance tripping.
   • Formula: $I_p=\text{Plug Setting Multiplier (PSM)}\times I_{\text{CT secondary}}$ where CT secondary is the current seen by the relay .
2. Time Multiplier Setting (TMS)
   • Adjusts the operating time of the relay according to the selected inverse curve.
   • Determines how long the relay waits before tripping once the fault exceeds the pickup current.
   • Calculated using the desired operating time and the relay's time-current characteristic constants .
3. Operating Time (t)
   • The actual time the relay takes to trip for a given fault current.
   • Calculated using the IEC 60255 equation for the selected curve type.
   • Ensures coordination with downstream relays by maintaining a Coordination Time Interval (CTI), typically 0.2–0.5 seconds between relays .
4. Plug Setting Multiplier (PSM)
   • Ratio of fault current to relay pickup current.
   • Helps determine the relay's sensitivity and ensures proper discrimination between normal load and fault conditions .
5. Coordination with Downstream Relays
   • Ensure that relays closer to the fault trip first.
   • Upstream relays are set with slightly longer operating times to act as backup.
   • Coordination involves calculating CTI and adjusting TMS accordingly .

Additional Considerations

• Fault Level Calculations: Determine maximum and minimum fault currents for different fault types (single line-to-ground, line-to-line, three-phase) to set relay thresholds accurately .
• Transformer Differential Protection: Requires calculations for differential current thresholds, through-fault stability, inrush restraint, and harmonic filtering .
• Distance Protection: For long transmission lines, impedance relays require zone reach and impedance settings to avoid overreaching .
• Primary and Secondary Ratios: Correct CT and VT ratios ensure the relay receives signals proportional to actual system conditions .

Practical Tools

Interactive calculators, such as the FIRGELLI Protection Relay Setting Calculator, allow engineers to input load current, CT ratio, fault current, plug setting, TMS, and relay curve type to compute pickup current, operating time, PSM, and CTI efficiently . These tools are particularly useful for plant-wide coordination across multiple feeders and substations.

Summary

Effective plant-wide relay protection requires a systematic approach:

• Calculate pickup currents above maximum load.
• Select appropriate inverse time-current curves.
• Determine TMS and operating times to maintain coordination.
• Ensure CTI between upstream and downstream relays.
• Consider fault levels, transformer protection, and distance protection requirements.
• Use simulation or interactive calculators to verify settings and coordination. By following these steps, engineers can achieve reliable, selective, and coordinated protection across the entire plant electrical system, minimizing equipment damage and operational disruptions .