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Protective relay and breaker coordination after a switchgear upgrade must be checked against the equipment and system that were actually installed—not carried forward on the assumption that the old settings still fit. Collect the as-installed settings and drawings, validate the short-circuit model and operating configurations, review primary and backup protection, then verify the relay-to-breaker trip path during commissioning. The exact settings are site-specific; a generic pickup or delay is not a safe substitute for an engineering study.
Why revisit relay settings after replacing switchgear?
A switchgear project can change the equipment, fault-current paths, breaker characteristics, or operating arrangements on which the existing protection scheme depends. Any of those changes may affect whether the intended primary device operates first and whether backup protection clears a fault if primary protection fails. That does not mean every replacement requires different numerical settings: it means the assumptions behind the existing settings need to be verified against the installed system.
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1Scan for outdated or missing drivers - takes under a minute2Repair Windows errors before they cause bigger problems3Fix the driver behind crashes, sound loss and screen glitchesStart with the protection philosophy and study boundary, not a setting copied from a prior project or a relay template. Schweitzer Engineering Laboratories (SEL) recommends reviewing installed settings and verifying the equipment parameters and fault currents used to establish pickups. Its guidance also stresses an accurate short-circuit model and a clear protection philosophy when setting new equipment. SEL’s discussion of a systematic coordination-review process is a useful reference for that approach.
The practical distinction is between checking settings and changing them. A review may conclude that existing values remain suitable, that settings need revision, that a logic or wiring change is required, or that an exception must be resolved or explicitly accepted through the facility’s engineering process. Only the responsible protection engineer, using the actual system data and applicable requirements, can determine which outcome is appropriate.
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What information should be assembled before the study?
Build a verified picture of the as-installed protection system before recalculating or approving settings. A model that reflects drawings but not field changes—or relay files that are not the in-service files—can produce a polished but unreliable coordination result.
- In-service relay configuration: Collect the settings files for the relays in scope, together with relevant firmware and configuration records. Identify which file and revision correspond to each installed device; do not assume a project export is the current field configuration.
- Drawings and wiring: Gather the current one-line diagrams and DC schematics, then reconcile them with installed equipment and field wiring. Record discrepancies for resolution rather than silently choosing the drawing or the field condition.
- Equipment data: Verify breaker, bus, current-transformer (CT), and voltage-transformer (VT) data, ratings, and operating characteristics needed for the protection study. Confirm the installed relay and breaker models, not only their intended specifications.
- Fault-current model: Update or validate the short-circuit model and available fault currents for the relevant configurations. Confirm the system and equipment assumptions used for settings, and check model outputs against available project or utility information.
- External-system assumptions: Obtain utility or interconnecting-party model data and assumptions where they affect the study boundary. SEL recommends involving relevant stakeholders for interconnection model information when applicable.
- Operating cases: Identify normal and alternate configurations as well as relevant contingency, maintenance, and bypass arrangements. A setting coordination result for one breaker lineup should not be presumed valid for every lineup or temporary mode.
- Protection philosophy and history: Document intended primary and backup device pairs, existing coordination exceptions, approved practices, and the reasoning behind them. Include adjacent devices within the relevant protection boundary so a local review does not overlook an upstream or downstream interaction.
Keep an input register showing the source and revision of each important item, who validated it, and any unresolved uncertainty. If a fault-current value, CT ratio, relay file, or breaker status is uncertain, treat it as an open engineering issue. Do not bury it in a footnote or let a software default stand in for a verified input.
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Use the validated equipment and system data to update the short-circuit and protection model, then evaluate the actual primary and backup device pairs across the faults and operating cases that matter. The review should answer not just whether curves appear separated, but whether the intended devices detect and clear relevant faults in the correct order under the modeled conditions.
- Define the study boundary and cases. Identify the upgraded switchgear, connected sources and loads, adjacent protective devices, and applicable normal, alternate, contingency, and maintenance configurations. List the fault types and locations that need evaluation; document exclusions and why they are outside scope.
- Validate short-circuit inputs and results. Check the updated model against the installed arrangement, source assumptions, equipment data, and available fault-current information. Review the currents seen by the relevant protection devices for the modeled fault locations and configurations.
- Identify primary and backup pairs. For each relevant fault, state which device is expected to clear it first and which device provides backup. Include the upstream and downstream devices needed to establish the real coordination relationship rather than stopping at the new switchgear boundary.
- Reassess pickups and delays against the study. Review each relay’s applicable elements and operating delays in relation to the validated faults, equipment characteristics, and protection philosophy. The study should establish the proposed values; there is no universal pickup or time-delay table for a switchgear upgrade.
- Review coordination margins and exceptions. Record the separation between primary and backup operation for each evaluated case and identify cases that fail the stated engineering basis or require an exception. Explain the fault, configuration, affected devices, severity, and disposition for every exception.
- Check all relevant operating configurations. Repeat or otherwise evaluate the applicable cases with the breaker lineup, sources, and modes that can change protection behavior. An acceptable result in the normal configuration does not establish coordination during a contingency or bypass mode.
Time-current curves (TCCs) are useful for showing how overcurrent devices operate over a range of current levels. Impedance, or R-X, plots can help assess distance-protection relationships. Both are views of defined model cases; neither is a substitute for checking the assumptions and intended sequence of operation.
Coordination time interval (CTI) is the time separation between primary and backup protection operation for the evaluated case. Its adequacy depends on the equipment, relay behavior, study assumptions, governing requirements, and engineering basis. An SEL paper presents example CTI risk bands of at least 0.40 seconds as “No risk,” 0.20 seconds to less than 0.40 seconds as “Low” risk or marginal, and less than 0.20 seconds as “High” risk or potential for misoperation. Those are the paper’s example classifications—not universal acceptance limits or settings instructions. The responsible engineer must identify the applicable margin and basis rather than adopting an example band as a site rule.
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When are static curves and sequential analysis both useful?
Static coordination analysis asks how devices compare under a defined, fixed breaker configuration; sequential analysis asks how protection and projected backup clearing proceed through a modeled fault event. SEL recommends static coordination followed by sequential verification where appropriate, while noting that each method has limitations that must be considered.
| Method | What it evaluates | Useful for | Limitations to account for |
|---|---|---|---|
| Static coordination analysis | Time-current curves and, where relevant, R-X plots for defined cases and a fixed breaker configuration. | Reviewing device relationships and coordination margins across modeled fault cases. | It represents the selected configuration and plotted behavior; it does not by itself prove the event sequence or actual trip path. |
| Sequential event analysis | The modeled order of protection operation and projected backup clearing after a fault. | Checking whether the primary device acts as intended and assessing backup timing in a sequence, including cases where sequential clearing matters. | Remote relay operation may be represented without capturing remote breaker failure unless its timing is modeled. Current seen by time-overcurrent relays can also vary with fault location. |
Use the methods as complementary evidence, not competing verdicts. Weak sources or outfeed can make a sequential check especially important, according to SEL’s paper. Conversely, a sequential result does not make a static review unnecessary: the engineer still needs to understand the device relationships, modeled cases, and limitations behind both results.
Coordination software can help represent relay and breaker models, run short-circuit cases, produce curves or setting reports, and preserve study assumptions. ETAP describes these capabilities in its overcurrent protection and selectivity software information and a plant-expansion case study. These vendor materials establish a software example, not an independent comparison or proof that software output is correct. A qualified engineer must validate inputs, model behavior, decisions, and final settings.
How should bypass and temporary protection modes be checked?
Evaluate the protection available in every temporary mode the site will actually permit, especially when a primary protective function is disabled or isolated for maintenance. A normal-mode coordination study cannot establish that a bypass arrangement has an adequate backup response.
SEL’s utility-station upgrade paper describes a particular tertiary-bus fault where backup phase overcurrent clearing took around one second while differential protection was disabled in bypass mode. The authors warn that delayed clearing in that case raised safety and system-stability concerns. This is a project example, not a general expected clearing time or a threshold for other installations. Its useful lesson is to explicitly assess bypass practices, document cutoff-switch use, and ensure protection is restored after maintenance.
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For each relevant bypass or maintenance state, document which functions remain active, which are unavailable, what backup protection is expected, and how the state is controlled and cleared. The site’s approved procedures should define who may authorize the mode, what safeguards apply, and how restoration is confirmed. This article is not a switching instruction; use the facility’s electrical safety and operating procedures.
How do you verify relay logic, wiring, and breaker trips?
Commission the whole protection path, from sensing and logic through output wiring and breaker operation—not just the numerical settings file. Compare relay logic and input/output assignments with the actual DC schematic and installed wiring, then verify the status and trip functions needed for the intended scheme.
An upgrade example in SEL’s 2025 utility-station upgrade paper describes a relay output wired for breaker-failure initiation even though an I/O table labeled it as future use. Following only the table resulted in an inactive output setting. The discrepancy shows why an I/O table alone is not enough: check the actual schematic, wiring, configured logic, and downstream function together.
A practical commissioning review should verify, as applicable to the approved project scope:
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- Settings and relay logic match the approved, version-controlled files; the installed device and configuration are correctly identified.
- Input and output assignments agree with the current DC schematics and the wiring actually installed, including breaker-failure initiation and other interlocks or trip functions in scope.
- Status inputs reflect the relevant breaker and protection states, and changes in state produce the expected logic behavior.
- Trip outputs reach the intended breaker trip path, and the function is checked using approved commissioning methods and safety procedures.
- Event records and relay reports can be retrieved and interpreted for the devices in scope, so unexpected operation can be investigated with evidence.
- Protection disabled for commissioning, testing, or maintenance is restored and its in-service status is confirmed under site procedures.
SEL’s commissioning paper documents six incidents, including disabled line differential protection, an incorrect transformer compensation matrix, loss of breaker status, and an incorrect directional relay setting found during a load-bank test. The paper describes using event reports, relay waveform captures, logic diagrams, manuals, and functional specifications to identify causes. The cases support a broad functional review: protection can be affected by configuration, status, logic, and system interactions as well as by the setting values themselves.
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What should be documented and approved?
Preserve the engineering basis and commissioning evidence together so that operators and future project teams can determine what was studied, installed, checked, and accepted. Use the site’s management-of-change and document-control processes to record the result.
- The validated short-circuit and coordination model, its revision, inputs, assumptions, study boundary, and operating cases.
- The approved relay settings files and relevant configuration or firmware records, identified to the installed devices.
- Reviewable TCCs, R-X plots where applicable, sequential results where used, and the fault cases and device pairs each result represents.
- All coordination exceptions, their severity, engineering rationale, affected configurations, and approval or resolution.
- Updated one-line diagrams, DC schematics, I/O information, and records of discrepancies resolved during the project.
- Commissioning and functional-check records, event or test evidence as applicable, restoration confirmation, and review approvals.
Where a regulatory requirement applies, verify the current standard, the site’s applicability, and the approved compliance method with the responsible compliance and protection personnel. SEL’s paper discusses NERC PRC-027-1, including one study option described as requiring a complete coordination study within an interval not exceeding six calendar years and a fault-current deviation threshold that may not exceed 15 percent. The authors also discuss interpretation and study-boundary questions. Those descriptions are not a compliance determination for a particular facility; confirm the current standard and applicability rather than treating either figure as a universal project requirement.
Who should own the review?
A qualified protection engineer or engineering firm should own or formally review the model, coordination decisions, settings, and commissioning scope, working with the project team and site personnel who can verify field conditions and operating practices. The facility owner remains responsible for ensuring that the work follows its engineering, safety, and change-control procedures.
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What should you do if the study or field checks find a problem?
Keep the affected condition visible, assess its engineering and safety significance, and route it through the site’s approved process before treating the protection system as accepted. A mismatch between a drawing and installed wiring, an unexplained setting difference, a coordination exception, or an unexpected event record should be resolved or formally dispositioned—not silently edited away.
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The responsible engineer should identify the affected device, fault case or function, system configurations, and credible consequence; determine whether corrective action or an approved exception is appropriate; and document the decision and required follow-up. If a change to a setting, logic, wiring, or operating practice is made, preserve the approved revision and verify the resulting function under the commissioning and management-of-change process. Do not use a generic setting from another installation as a field fix.
Frequently Asked Questions
Does NERC PRC-027-1 automatically apply to every facility with upgraded switchgear?
No. Applicability depends on the facility and its regulatory context, and the cited SEL paper is not a compliance determination. Ask the site’s compliance personnel to confirm the current standard, applicability, and accepted compliance method.
Can I copy settings from the old relay into a replacement relay?
A copied file is not proof that the replacement is correctly configured. Verify the installed relay model and configuration, confirm the imported values against the approved study and current settings record, and check the logic and input/output mapping as well.
What if the one-line diagram or I/O table conflicts with the wiring in the field?
Treat the mismatch as an unresolved engineering and document-control issue, not as a choice to make by convenience. Have qualified project personnel reconcile the installed wiring, schematics, relay logic, and intended function, then update controlled records and verify the affected protection path.
Can coordination software approve relay settings on its own?
No. Software can model devices and generate curves or reports, but its results depend on correct inputs, device representations, and assumptions. Engineering review must determine whether the model and conclusions fit the installed system and applicable requirements.
