MV Protection Commissioning Checklist: Step-by-Step

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 MV protection systems are essential for ensuring safe and reliable operation of medium voltage equipment in industrial facilities. Whether you are working in a cement plant, power station, or substation, proper commissioning of MV protection is critical to avoid equipment damage, unplanned outages, and safety hazards.

Many engineers focus heavily on design and installation, but fail to apply the same attention to commissioning. The truth is, a protection relay can pass factory tests and still fail in the field — simply because something critical was missed before energization.

In this article, we present a detailed and practical MV protection commissioning checklist based on real challenges engineers face in industrial environments.

Why is MV Protection Commissioning So Important?

Commissioning is more than routine testing. It is the final verification that the entire protection system ,including CTs, VTs, relays, trip circuits, breakers, and logic functions , operates correctly as an integrated system under real conditions.

Without proper commissioning, protection systems may respond too late, fail to trip, or even trip under no-fault conditions. These failures often result in costly downtime, damage to high-value equipment, or safety incidents.

Checklist for MV Protection Commissioning

1. Current and Voltage Transformer (CT/VT) Verification

  • Confirm the correct installation orientation and polarity of all CTs and VTs.

  • Perform insulation resistance testing to check cable health.

  • Compare CT and VT ratios with the system design and relay settings.

  • If possible, perform ratio tests to ensure expected transformation accuracy.

Incorrect CT polarity is a common error that can lead to the protection relay misinterpreting fault direction or magnitude, which can cause delayed or failed tripping.

2. Protection Relay Setting Validation

  • Review all relay settings against the approved protection coordination study.

  • Verify pick-up values, time delays, and protection zones.

  • Ensure breaker failure protection, overload protection, and earth fault protection are configured properly.

  • Document all relay settings before and after adjustments.

Using default or unverified relay settings can lead to poor fault discrimination, nuisance tripping, or unprotected zones.

3. Trip Circuit Continuity and Function Testing

  • Test the continuity of trip circuits from the relay to the breaker trip coils.

  • Simulate trip signals from the relay and confirm breaker response.

  • Measure the DC voltage at the relay during trip operation.

  • Check for the presence of redundant trip paths if applicable.

It is possible for a protection relay to detect a fault and send a trip signal — but nothing will happen if the trip circuit is not healthy. This is one of the most overlooked issues in commissioning.

4. Circuit Breaker Functional Testing

  • Perform manual opening and closing of all breakers to verify mechanical integrity.

  • Check interlocking mechanisms, both mechanical and electrical.

  • Confirm the breaker's response to a remote trip from the protection relay.

  • Validate auxiliary contacts used in logic or feedback.

A relay may function correctly, but if the breaker fails to operate due to mechanical problems, the system is still at risk.

5. Primary Injection Testing

  • Inject current directly into CT circuits and observe relay response.

  • Measure the trip time and verify it matches expected protection curves.

  • Confirm that the relay logs the event correctly, including fault type and timestamp.

  • Use the opportunity to validate the entire trip path — from detection to breaker operation.

Primary injection is the only way to fully simulate real fault conditions and ensure the system will perform as intended.

6. Logic Functions and Interlocks

  • Verify all logic configurations such as undervoltage, reverse power, breaker failure, and blocking schemes.

  • Test interlocks between feeders and tie-breakers where applicable.

  • Simulate fault scenarios to validate automatic responses.

Incorrect or untested logic can cause protection zones to fail or trip unexpectedly. Every logic function configured in the relay should be verified during commissioning.

7. SCADA or DCS Integration Checks

  • Ensure communication protocols (such as Modbus or IEC 61850) are configured properly.

  • Verify alarm, status, and trip signals are being transmitted and received accurately.

  • Check that timestamps in SCADA match those recorded in the relay.

  • Confirm all required data points are mapped correctly to the control system.

In modern plants, protection systems are often integrated into control systems. If the relay communicates incorrect or delayed data, operational visibility is compromised.

8. Event Logs and Fault Record Review

  • Trigger test faults and confirm that waveform captures are logged in the relay.

  • Review event logs for timestamp accuracy and correct phase identification.

  • Export logs and verify that the memory capacity and format meet project requirements.

  • Confirm that protection engineers and operators have access to event data.

Relay logs are essential for post-event analysis. If no logs are captured, or data is missing, investigating real faults later will be nearly impossible.

9. Verification of Labeling and Documentation

  • Confirm that all CTs, VTs, relays, and terminal blocks are labeled according to the schematic.

  • Ensure that wiring diagrams and as-built drawings match field conditions.

  • Document all test results and keep digital copies for record and audit.

Proper documentation is part of commissioning. Inconsistent labeling can cause delays during future maintenance or troubleshooting.

Read About: Short Circuit Protection Relay Basics for Safer Systems

Common Issues Found During MV Protection Commissioning

Many real-world protection failures trace back to one of these issues:

  • CT wiring reversed or swapped between phases

  • Trip coil not energized due to a loose terminal

  • Incorrect time-current curves or miscoordination

  • Relay firmware bugs not updated before site delivery

  • Missing SCADA points or wrong device IDs

These aren’t theoretical — they happen in live plants. And all of them are preventable during a proper commissioning process.

Conclusion

MV protection commissioning is not optional — it’s your last chance to catch design flaws, wiring errors, configuration issues, or logic gaps before putting your system under load. Skipping steps or rushing through tests can cost thousands in damage, downtime, or safety violations.

Follow a disciplined, well-documented checklist. Involve the right experts. And always test the system as a whole — not just the individual devices.

If you need help with on-site testing, protection relay settings, or full MV protection commissioning, our engineering team is ready to support your plant with field-proven experience.

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