Relay Protection Branch Calculation

Relay protection branch calculation ensures selective, reliable operation of protective relays by determining pickup currents, time settings, and coordination margins for each branch.

Overview of Relay Protection Calculation

Relay protection calculation involves selecting settings that allow relays to operate selectively and reliably during faults, ensuring only the relay closest to the fault trips while upstream relays remain inactive . This process is essential for protecting feeders, transformers, and lines from overcurrent, short circuits, and ground faults.

Key Steps in Relay Branch Calculation

1. Determine Design Current (Ib) Calculate the design current of the branch based on connected loads. For motors, consider full-load current and starting currents .
2. Select Relay Pickup Current (Ipickup) The relay pickup current is set as a multiple of the branch load current. Instantaneous units should not trip for currents below downstream fault levels. Typical settings for numerical relays use 10 times the maximum load current for instantaneous elements .
3. Choose Time-Current Characteristics
   • Definite Time Relays: Operate after a fixed time regardless of fault magnitude.
   • Inverse Time Relays: Operating time decreases as fault current increases, suitable for radial networks .
   • Extremely Inverse or Very Inverse: Used when short-circuit currents vary significantly along the feeder .
4. Calculate Operating Time (t1) for the Branch Relay Use the relay's time dial (TAP/DIAL) and the fault current to determine the operating time from the time-current characteristic curve .
5. Determine Upstream Relay Coordination (t2) Ensure selectivity by adding a grading margin (typically 0.2–0.5 s for numerical relays) to the downstream relay operating time: t2 = t1 + t_margin .
6. Verify Short-Circuit and Thermal Limits Ensure the relay can safely interrupt the maximum prospective short-circuit current and that the protected equipment is not thermally overloaded .
7. Zone and Impedance Settings (for Distance Relays) For transmission lines, set zone 1 reach to 80–90% of line impedance, including resistive and arc components. Apply zero-sequence compensation for ground faults if required .
8. Check Selectivity and Coordination Plot time-current curves for all relays in the branch to verify that downstream relays operate first and upstream relays only operate if downstream relays fail .

Practical Considerations

• Numerical Relays allow precise TAP and DIAL settings, enabling both definite and inverse time operation .
• Grading Time must balance speed and selectivity; longer grading times are needed for inverse time relays due to measurement inaccuracies .
• Transformer and Feeder Coordination: LV side relays may be overridden unless communication with feeder relays exists .

Example Formula for Upstream Relay Time

For an inverse-time overcurrent relay: t_upstream = t_downstream + t_margin where t_downstream is obtained from the relay curve using the fault current multiple of pickup, and t_margin is the coordination time (e.g., 0.2 s for numerical relays), . By following these steps, engineers can ensure reliable, selective, and safe operation of protective relays across all branches of a power system.