Selectivity is a system property
Selective protection removes the smallest practical part of the system for a fault while preserving equipment safety. It cannot be proven by comparing two pickup numbers or one point on a time-current curve (TCC). Fault current changes with location and network state; device curves have tolerances; breakers need interrupting time; CTs can saturate; and equipment has thermal/mechanical limits.
1. Build a validated study model
Collect utility source minimum/maximum fault levels and X/R, transformer ratings/impedances/taps/vector groups, generator/IBR contributions, cable size/length/installation, motor contribution, grounding impedances, CT ratios/classes, breaker interrupting/clearing time, relay firmware/curve equations and fuse manufacturer minimum-melt/total-clearing curves. Validate the one-line and operating modes with operations staff.
Run at least maximum and minimum source conditions plus tie open/closed, transformers parallel/separate, generator online/offline and island operation where applicable.
2. Put all constraints on the TCC
| Curve/boundary | Why it belongs |
|---|---|
| Maximum load and emergency load | Protection must carry legitimate current. |
| Motor start or transformer inrush envelope | Avoid nuisance operation while retaining fault sensitivity. |
| Cable short-circuit withstand / ampacity | Relay must clear before thermal damage. |
| Transformer through-fault withstand/inrush | Coordinate primary/secondary devices and protect winding. |
| Fuse minimum-melt and total-clearing bands | Upstream device must coordinate with the entire tolerance band. |
| Relay min/max operating tolerance and CT error | Nominal line alone is not the guaranteed response. |
| Breaker clearing time | Add mechanical interruption after relay output. |
| Minimum and maximum fault markers | Show sensitivity and high-current coordination/duty. |
3. Coordination intervals
The grading margin covers downstream relay overtravel/accuracy, upstream accuracy, both breakers’ clearing times, CT transient error and study uncertainty. Numerical relays and modern breakers may permit smaller margins than old electromechanical systems, but there is no universal 0.2 s or 0.3 s rule. Use manufacturer guaranteed data and owner criteria.
Where the plotted curve already includes total clearing, do not add breaker time twice. Clearly label what each software curve represents.
4. Relay-to-relay coordination
Choose downstream pickup above maximum load and upstream pickup above expected aggregate load, while both remain below the minimum fault they must detect. Select curve shapes that preserve margin across current range. A definite-time high-set may coordinate better than two inverse curves at high current. Check instantaneous stages separately; they can overreach a downstream bus under maximum source even when 51 curves coordinate perfectly.
5. Relay-to-fuse coordination
A fuse is a band, not one line. For fuse-saving, an upstream fast relay/recloser may clear transient faults before the lateral fuse melts, then reclose; the delayed sequence coordinates for permanent faults. For fuse-blowing, the fuse clears the lateral before the upstream device. In industrial transformer/motor circuits, ensure the fuse carries inrush/start but clears high-current faults within contactor/transformer withstand.
Check current-limiting fuse operation using manufacturer let-through data as well as TCC where peak/I²t duty matters. Do not extrapolate curves outside the published range.
6. Ground-fault coordination
Earth-fault current is governed by grounding, not the three-phase fault level. Plot separate ground TCCs with NGR/earthing-transformer duty and minimum high-resistance fault. In resistance-grounded systems, feeder CBCT protection should normally clear before transformer neutral backup while the total time remains within the resistor rating. In isolated/resonant systems, phasor direction and transient methods cannot be represented adequately by a simple current TCC; use a functional selectivity study.
7. Worked coordination point
An 11 kV feeder has 51 pickup 320 A with IEC very inverse curve. At 4 kA, M = 12.5. If the downstream total clearing time is 0.25 s and the required grading interval is 0.30 s, the upstream target is 0.55 s. The approximate TMS is:
Now repeat at the minimum coordination current, maximum fault, downstream high-set transition and fuse-band boundaries. Confirm cable and switchgear withstand. One calculated point is a setting seed, not an approved study.
8. Selectivity versus arc-flash energy
Intentional delay improves selectivity but can increase incident energy. Mitigation options include bus differential, arc-flash light detection, ZSI, maintenance mode, differential feeder protection or communications-assisted tripping. Do not simply reduce delays without reviewing downstream coordination and nuisance-trip consequences. Record the normal and maintenance protection states and update labels/studies accordingly.
9. Study QA checklist
- One-line matches as-built topology and ratings.
- Minimum/maximum utility and all source states modeled.
- Device manufacturer, exact type, firmware curve and tolerance verified.
- CT ratio/class and breaker clearing time included.
- Phase and ground studies separated.
- Damage/inrush/start envelopes plotted.
- Instantaneous/high-set reach checked with maximum external faults.
- Generator/IBR island state tested for sensitivity.
- Arc-flash and breaker-failure implications reviewed.
- Settings exported, independently checked and linked to drawing revision.
Related protection guides
Engineering limitation
This guide explains a defensible engineering workflow; it is not a project setting calculation. Final protection functions, settings, wiring and trip logic must be based on the approved single-line diagram, short-circuit and coordination studies, equipment data, grid code, relay manual, and verified commissioning results. Changes require formal protection-management control.
References and further reading
- IEC 60255-151:2009 — overcurrent relay functional/time characteristics
- IEEE C37.112-2018 — inverse-time equations and allowances
- IEEE 242-2001 — industrial/commercial protection and coordination principles
- IEEE C37.230-2020 — distribution protection applications
- ABB selectivity techniques — manufacturer explanation of time/current and other selectivity methods
Standards must be applied using the edition required by the project, utility and local law. Standards summaries on public pages are not substitutes for the controlled documents.