Calculation of Relay Protection Settings for 10KV Distribution Network

Relay protection settings for a 10kV distribution system are calculated using fault current analysis, CT ratios, plug setting multipliers, time multiplier settings, and coordination principles to ensure selectivity and reliability.

Step 1: Determine System Parameters

• Line Voltage (Vbase): 10kV for the distribution system.
• System Base Power (Sbase): Typically the transformer or feeder rating.
• Fault Current (I_fault): Calculate the maximum and minimum short-circuit currents at the relay location using load flow or zone boundary methods .
• CT Ratio: Select a current transformer ratio that scales primary current to a manageable secondary current for the relay .

Step 2: Calculate Base and Secondary Currents

• Base Current: $I_{base}=\frac{S_{base}}{\sqrt{3}·V_{base}}$
• Secondary Current: $I_{secondary}=\frac{I_{fault}}{CT\_ratio}$ These values are essential for determining the relay pickup and operating times .

Step 3: Determine Plug Setting Multiplier (PSM)

• PSM: $PSM=\frac{I_{secondary}}{I_{pickup}}$ The PSM represents how many times the fault current exceeds the relay pickup current, which is used in inverse time calculations .

Step 4: Set Time Multiplier Setting (TMS)

• TMS adjusts the operating time of the relay to coordinate with upstream and downstream devices. A higher TMS increases the operating time, allowing proper selectivity .

Step 5: Calculate Relay Operating Time

• For inverse time overcurrent relays, the operating time can be calculated using standard IEC or IEEE curves: $OperatingTime=TMS\times \frac{0.14}{(PS{M}^{0.02}-1)}$
• For numerical relays, the time dial and TAP settings are used to fine-tune the operating time .

Step 6: Coordination and Grading

• Grading Time: Ensure a time margin between downstream and upstream relays to maintain selectivity. Typical margins are 0.2–0.5 seconds for numerical relays .
• Instantaneous Settings: Set the instantaneous pickup above the maximum load current but below the minimum fault current to avoid nuisance tripping .
• Inverse Time Settings: Adjust the time dial to coordinate with other relays on the feeder or bus, considering maximum short-circuit currents and thermal limits .

Step 7: Special Considerations

• Ground Fault Protection: Use zero-sequence compensation if required, and consider line-to-ground fault currents separately .
• Distributed Generation: If DG is connected, optimize relay settings using algorithms like Whale or LM to maintain sensitivity and quick operation .
• Transformer Protection: For LV side relays, consider TAP scaling and differential protection settings to ensure proper coordination with feeder relays .

Summary

The calculation method involves:

1. Determining system and fault parameters.
2. Calculating base and secondary currents.
3. Computing PSM and TMS.
4. Setting operating times using inverse time characteristics.
5. Coordinating relays with grading times and instantaneous settings.
6. Adjusting for ground faults, distributed generation, and transformer protection. This systematic approach ensures reliable, selective, and fast protection for 10kV distribution networks while minimizing unnecessary outages and equipment stress.