Calculation Method for Relay Protection Setting

Relay protection settings are calculated using a combination of Plug Setting Multiplier (PSM), Time Multiplier Setting (TMS), and coordination principles to ensure selective and reliable fault clearance.

Overview of Relay Settings

Relay protection ensures fast and selective fault detection to minimize damage and maintain system stability. Key settings include:

• Plug Setting Multiplier (PSM): Determines the pickup current at which the relay operates. It is expressed as a multiple of the rated CT current.
• Time Multiplier Setting (TMS): Adjusts the operating time of the relay to coordinate with upstream and downstream devices.
• Grading Time: The intentional time difference between consecutive protection stages to maintain selectivity. Proper calculation ensures that only the faulted section is isolated while minimizing supply interruptions to healthy parts of the network .

Step-by-Step Calculation Procedure

1. Determine Rated Currents

Identify the rated current of the protected equipment (transformer, feeder, or line) and the CT ratios. This forms the basis for calculating pickup currents .

2. Calculate Plug Setting Multiplier (PSM)

The PSM defines the relay pickup current:

• Choose PSM based on the maximum load current and fault current levels.
• Typical PSM values range from 50% to 150% of rated current .

3. Determine Time Multiplier Setting (TMS)

TMS adjusts the relay operating time according to coordination requirements:

• Use relay characteristic curves (IDMT or definite time) to find the operating time for the selected PSM.
• Adjust TMS to ensure proper coordination with upstream and downstream relays, maintaining grading time margins .

4. Establish Grading Time

Grading time is the time difference between consecutive protection stages:

• For inverse time relays, longer grading times are required due to measurement inaccuracies.
• Ensure that the relay closest to the fault operates first, while backup relays operate with a delay .

5. Transformer Differential Protection (if applicable)

For transformer protection (e.g., SEL-787):

• Convert secondary currents to per-unit values using TAP scaling.
• Ensure that the sum of incoming currents equals 1.0 per unit and outgoing currents equal –1.0 per unit.
• Verify that the ratio ${\text{TAP}}_{\text{max}}/{\text{TAP}}_{\text{min}}\le 7.5$ for proper differential operation .

6. Verify Coordination and Selectivity

• Check that relay operating times maintain selectivity with upstream and downstream devices.
• Adjust PSM and TMS iteratively to achieve optimal fault clearance without unnecessary tripping of healthy sections .

7. Document and Test Settings

• Record all calculated settings for each relay.
• Perform simulation or field testing to validate the settings under different fault scenarios .

Example Formula for Overcurrent Relay

Where TDS is the Time Dial Setting, controlling the relay delay to coordinate with other relays .

Key Considerations

• System stability: Faster relay operation reduces voltage dips and post-fault load peaks.
• Selectivity: Only the faulted section should be isolated.
• Inverse vs definite time relays: Inverse time relays require longer grading times.
• Numerical relays: Grading times can be calculated using standard equations for precise coordination . By following this procedure, engineers can ensure reliable, selective, and coordinated protection for power systems.