Omitting restricted earth fault protection because the transformer is dry-type, bus-bar connected, inexpensive, or backed by a second fully rated transformer treats consequence as though it removed the fault. It does not. Increasing an overcurrent pickup, changing a stabilising resistor without measurements, or relying on redundancy also misses the protection problem: a winding-to-earth fault near a solidly earthed neutral can produce too little high-voltage phase current for conventional overcurrent protection while producing substantial neutral current. Look at the protection signal chain first. Tuning does not fix wiring.
Why do the usual cost-saving fixes fail?
A direct bus-bar connection reduces exposed secondary cable and termination length, so it can reduce faults outside the transformer. It does not remove earth faults within the protected winding. Likewise, two fully rated transformers improve supply continuity after a trip, but they do not limit damage inside the faulted unit or establish that the remaining transformer can accept the load under every operating condition.
Removing REF solely because no genuine operation has been observed is also weak reasoning. Protection performance is determined by the faults it must detect, not by historical trip count. Conversely, retaining a scheme with unexplained operations is not a sound default. Incorrect CT polarity, CT mismatch, secondary-circuit defects, or an unsuitable stabilising resistor can convert an intended selective element into a source of nuisance trips.
Transformer differential and phase overcurrent are not identical substitutes. Differential sensitivity close to the neutral of a star-connected winding is limited by fault location and pickup. Figures associated with the cited application show the protected winding falling from 58% at a 10% differential setting to 41% at 20%, 28% at 30%, and 17% at 40%. An REF scheme can extend coverage beyond 90% of the winding and can operate quickly without coordinating with downstream devices.
What does REF measure that other protection can miss?
The phase CTs measure the sum of current entering the restricted zone, while the neutral CT measures current leaving through the grounded neutral. For load and faults outside the zone, these quantities balance after CT ratio and polarity are accounted for. An earth fault inside the bounded winding creates a spill current that operates the REF element.
Near the neutral point, only a small portion of the winding contributes voltage to the fault when viewed from the high-voltage phase terminals. Phase current may therefore remain below an overcurrent or transformer-differential pickup. From the neutral circuit, the faulted winding portion behaves as an autotransformer, so the neutral current can still be high. That combination is the specific gap REF addresses.
| Signal | Source | Wrong-value symptom |
|---|---|---|
| Phase residual current | Vector sum of the three phase CT secondary currents | Ratio, wiring, or polarity error creates false spill current during load or an external fault |
| Neutral current | CT in the solidly earthed neutral connection | Reversed polarity can make the scheme stable for an internal fault and operate for an external fault |
| REF operating current | Difference between the phase residual and neutral signals | Unexpected current outside the zone indicates CT or secondary-circuit error before relay setting changes are considered |
| CT excitation and secondary resistance | CT test results and complete secondary wiring path | Inadequate high-impedance stability margin can cause operation when one CT saturates during a through-fault |
Is there a kVA threshold for fitting REF?
No universal kVA boundary follows from the transformer rating alone. The installation in question uses 1 MVA to 2.5 MVA transformers in the 10 kV to 20 kV range, solidly earthed neutrals, direct bus-bar connections, and two fully rated transformers per switchboard. Those details support an economic review, but the decision still depends on fault coverage, damage limitation, plant consequence, replacement time, access, and the total installed protection cost.
Practice varies. REF has been reported as uncommon on smaller solidly earthed transformers and absent from some 3 MVA, 11/6.6 kV resistance-earthed units, while another practice observed it only at 10 MVA and above. These are examples of project practice, not protection thresholds. A rule allocating roughly 10% of equipment cost to protection is likewise a budgeting guide rather than a technical acceptance criterion.
At about GBP 1,000 per transformer, 16 units represent GBP 16,000 and 18 units represent GBP 18,000 before any differences in CT, wiring, testing, or relay-panel scope. Compare that lifecycle cost with the probable incremental damage avoided by faster clearance, outage duration, repair or replacement lead time, access restrictions, common-mode exposure, and the actual value of continuity. Redundancy reduces production loss only when the standby transformer, switchboard arrangement, and upstream supply remain available after the event.
Which checks decide whether REF adds value?
- Define the protected zone on the single-line and wiring drawings. Mark the phase CT locations, neutral CT location, transformer winding, bus bars, and every connection lying outside the zone.
- Read the grounding design. A solidly earthed neutral can supply substantial earth-fault current; a resistance-earthed installation has a different current limit and sensitivity requirement. Do not transfer settings or economics between them.
- Extract the phase-overcurrent, earth-fault, differential, and REF pickup characteristics from the relay settings and coordination study. Identify the portion of the winding that each function can detect.
- Review the consequence of delayed clearance: winding and core damage, arc energy, switchboard exposure, repair logistics, transformer replacement time, and whether one transformer can carry the required load during maintenance.
- Build the installed-cost comparison. Include CTs, relay inputs, stabilising resistor where applicable, cabling, panel space, design, injection testing, commissioning, and periodic proof testing rather than comparing only the relay price.
- Investigate every previous REF operation using disturbance records, event sequence, CT secondary measurements, polarity tests, and external-fault current. Do not change pickup or resistance until the initiating signal is identified.
How should a high-impedance REF scheme be corrected?
Start at the primary current direction and trace every secondary connection to the relay. Confirm that the three phase CTs have compatible ratios and connections and that the neutral CT polarity produces cancellation for load and external earth faults. The neutral CT deserves special attention: reversing it can produce the dangerous combination of restraint for an in-zone fault and operation for an out-of-zone fault.
For a high-impedance scheme, obtain each CT excitation characteristic, winding resistance, lead resistance, relay burden, and maximum through-fault current. Use the relay manufacturer's stated method to select the stabilising resistor and CT requirements. Class X CTs were specified for the high-impedance arrangements described here, but some newer relay schemes accept normal protection CTs. The relay design and its application manual decide the requirement; the label REF alone does not.
Inspect secondary continuity, test links, earthing, shorting facilities, resistor connections, and CT star-point arrangement. Correct wiring defects before injecting current. A resistor adjustment cannot compensate for reversed polarity, unequal CT ratios, an open circuit, or an incorrectly located CT.
How is the decision and commissioning result verified?
- Perform CT ratio, polarity, insulation, winding-resistance, and excitation tests appropriate to the selected scheme. Record results against the design values.
- Use secondary or primary injection to prove stability for balanced load and simulated external earth faults. Test at a current high enough to exercise the intended stability calculation without exceeding the approved test procedure.
- Inject an internal-zone residual condition and prove REF pickup, trip logic, circuit-breaker operation, alarms, lockout functions, and event recording.
- Confirm selectivity against downstream earth-fault protection and confirm that the REF trip path does not depend on intentional downstream grading delay.
- Review relay oscillography or measured currents. For an external fault, phase residual and neutral signals must cancel at the REF measuring point; for an internal fault, the resulting spill current must cross the specified operate threshold.
- Document the economic decision beside the protection study. State the accepted winding coverage, expected clearance path, redundancy assumptions, installed cost, repair exposure, and approval authority.
FAQ
How do I decide whether a 1 MVA to 2.5 MVA transformer needs REF?
Do not use rating alone. Compare the uncovered near-neutral winding zone, grounding method, clearance time, installed REF cost, repair lead time, access, and whether the second fully rated transformer truly preserves service after a fault.
How do I diagnose an REF trip during an external earth fault?
Check neutral CT polarity first, then phase CT polarity, ratios, secondary continuity, excitation data, lead resistance, and the stabilising-resistor calculation. Reversed neutral CT polarity can make the element operate for an external fault while remaining stable for an internal fault.
When should I stop commissioning and contact official support?
Stop if measured CT excitation, secondary resistance, through-fault duty, or relay behaviour cannot be reconciled with the manufacturer's high-impedance REF method, or if an external-fault test produces unexplained spill current. Keep the transformer isolated from the unproven trip scheme and escalate to the relay or transformer manufacturer's official technical support with drawings, settings, test sheets, and event records. Do not mask the condition by raising pickup or changing the stabilising resistor without an approved calculation.