Protection Relay Coordination Problems Explained

In industrial and utility power systems, proper protection relay coordination is essential to ensure that only the faulted section is isolated — without causing unnecessary shutdowns or widespread blackouts. However, protection relay coordination problems are among the most common and costly issues engineers face during operation, maintenance, and system upgrades.

If coordination fails, a minor short circuit in a feeder can trip an upstream main breaker, stopping production and damaging equipment. This article dives deep into the real-world causes, diagnostic approaches, and practical field solutions to overcome coordination challenges in modern protection systems.

1. What Causes Protection Relay Coordination Problems in Industrial Power Systems?

Coordination problems usually occur when relays operate outside their intended sequence. The main causes include:

• Improper time–current settings between upstream and downstream relays

• Incorrect current transformer (CT) or voltage transformer (VT) ratios

• Overlapping time-current curves due to poor grading margins

• Software design errors in coordination studies

• Load or network modifications without updating relay settings

In short, coordination fails when the protection system isn’t tuned to reflect the real electrical behavior of the network.

2. How to Identify Coordination Problems Between Relays

Engineers can detect coordination issues by analyzing event logs, disturbance records, or fault reports. Key signs include:

• Upstream breaker trips before the feeder breaker

• Relay operation without a fault in its zone of protection

• Extended restoration time after a minor fault

• Conflicting time-current curves in protection studies

Regular analysis of relay operation sequences and event timestamps is essential to spot coordination mismatches early.

3. Coordination vs. Selectivity – What’s the Difference?

Coordination ensures that relays work together in a time-graded sequence, while selectivity ensures that only the nearest protective device clears the fault. In short:

• Selectivity = Who trips

• Coordination = When they trip

Effective protection systems require both.

4. Why Does the Upstream Relay Trip Before the Downstream Relay?

This happens when the upstream relay’s time delay or pickup setting is too low. As a result, it reacts faster than the downstream relay, violating the grading margin.
Common reasons:

• Misconfigured time dial settings

• Incorrect CT ratios

• Fault current lower than expected (causing underreach)

To fix it, engineers should re-evaluate time-current curves and verify the grading margin (typically 0.3–0.4 seconds).

5. CT and VT Errors Contributing to Coordination Problems

A mismatched or saturated CT/VT can cause relays to “see” incorrect current or voltage values. For example:

• CT saturation during high faults delays relay tripping

• Incorrect CT polarity causes false differential operation

• VT secondary errors affect directional relay accuracy

Routine CT/VT testing and proper burden calculations are vital to prevent such protection relay coordination problems.

6. Time Grading and Its Impact on Relay Coordination

Time grading defines how long each relay waits before operating. Too narrow a grading margin can lead to simultaneous tripping of multiple relays.
For industrial systems:

• Coordination margin = 0.3–0.5 seconds (standard)

• Each relay should operate slightly faster than the one upstream

Using software simulation tools ensures that these time intervals are mathematically optimized.

7. Fault Current Level Changes and Coordination Disturbances

When new equipment (like motors, VFDs, or transformers) is added, the system’s fault current level changes — sometimes drastically.
If the coordination study isn’t updated, relays calibrated for old current levels may either:

• Operate too early

• Fail to trip at all

Periodic short-circuit studies are the foundation of maintaining effective coordination.

8. Common Mistakes in Setting Coordination Curves

Engineers sometimes commit subtle errors while drawing or configuring coordination curves:

• Overlapping inverse-time characteristics

• Ignoring instantaneous elements

• Using incorrect relay curves (IEC vs ANSI)

• Forgetting CT secondary mismatch correction

Even small curve overlaps can cause nuisance tripping and major downtime events.

9. Using ETAP or DIgSILENT to Resolve Coordination Issues

Modern tools like ETAP, DIgSILENT PowerFactory, or SKM Power Tools help engineers:

• Plot time-current coordination curves (TCCs)

• Simulate different fault conditions

• Identify overlapping curves and missing time margins

• Automatically optimize grading settings

Digital coordination studies save hours of manual calculation and allow “what-if” analysis before field implementation.

10. Time Dial Setting Errors and Their Effects

Improper time dial settings are a leading cause of coordination failure.
If two relays have identical pickup and time dial values, they’ll operate nearly simultaneously — defeating coordination.
Field engineers should:

• Set downstream relays with smaller time dials

• Gradually increase time delay upstream

• Verify with actual test injections

11. Nuisance Tripping as an Indicator of Coordination Problems

Frequent tripping without visible faults (nuisance trips) often hides deeper coordination issues. Possible reasons include:

• Over-sensitive relay settings

• Harmonic distortion misinterpreted as fault current

• Parallel feeder interaction

Engineers should analyze oscillography records and retrace fault currents to isolate false triggers.

12. Relay Coordination in Radial vs. Ring Networks

• Radial systems: Coordination is simpler — current flows one way, so grading is straightforward.

• Ring systems: Current can flow from multiple directions, requiring directional elements and adaptive settings.

Without directional coordination, relays may misidentify fault direction and trip the wrong feeder.

13. Frequency of Coordination Studies in Industrial Plants

Relay coordination should be reviewed:

• After any major network modification

• Every 3–5 years as part of preventive maintenance

• Whenever relay firmware or logic settings are updated

Regular audits ensure the protection system adapts to load growth and equipment changes.

14. Impact of Adding VFDs or New Loads on Coordination

Variable frequency drives (VFDs) and nonlinear loads distort current waveforms. These distortions can:

• Affect relay pickup detection

• Alter fault current magnitude

• Shift operating times

Whenever major equipment is added, the entire relay coordination study should be revalidated to avoid hidden coordination gaps.

15. Verifying Protection Relay Coordination During Commissioning

During commissioning, engineers should simulate different fault scenarios and verify:

• Each relay operates in correct sequence

• Time delays match the coordination study

• No unexpected relay pickups occur

Testing should include current injection, secondary injection, and end-to-end system checks.

16. Best Practices to Avoid Future Protection Relay Coordination Problems

To maintain reliable protection coordination:

• Use verified CT/VT data for all relays

• Maintain updated short-circuit and load flow studies

• Validate coordination after every plant modification

• Use proper software documentation and version control

• Train staff regularly on protection philosophy

These practices reduce downtime, improve selectivity, and strengthen overall system reliability.

Conclusion

Protection relay coordination problems aren’t just theoretical — they have real operational consequences, from unnecessary trips to major production losses.
By combining proper system studies, precise settings, and modern simulation tools, engineers can ensure their protection schemes remain selective, dependable, and well-coordinated.

For industrial facilities, keeping relay coordination updated is part of motor maintenance, energy reliability, and overall electrical safety strategy.