Switchgear failure at a Rhode Island distribution substation after feeder fault

In August 2022 a major equipment failure occurred at a distribution substation in Rhode Island, United States. The substation, commissioned in the early 1980s, had a single 115 kV to 13.8 kV load tap changing transformer supplying four 13.8 kV distribution feeders serving several communities and a neighbouring utility. The failure took all four distribution feeders offline and interrupted supply to approximately 9,300 customers, including a hospital and a mental health facility. The operator mobilised more than 50 personnel for restoration, deployed contracted emergency generation, replaced the failed switchgear and progressively restored customers. The state regulator carried out a formal investigation and published its findings.

According to the published investigation, the initiating event was a phase to phase fault on one distribution feeder caused by a fallen tree. The recloser on that feeder cleared the fault, but the fault persisted for longer than a bolted, low impedance fault would have done, because tree contact produces a higher impedance fault with lower fault current, for which protective relays are set to allow a longer clearing time. The investigation reported that the combination of fault duration and fault location placed significant stress on the upstream substation switchgear. Engineering guidance in use at the time recommended that bolted faults at the end of the protected zone be cleared in under one second, while explicitly allowing longer clearing times for higher impedance faults. The post incident analysis considered whether protection coordination at substations of this design vintage could be adjusted to reduce the stress imposed during such fault clearing events.

Lessons drawn from the published investigation:

1. review protection coordination settings at older substations against current engineering standards, recognising the trade off between fast clearing, which increases the risk of tripping on transient conditions, and permissive settings, which extend the duration of real faults;
2. include high impedance fault scenarios, such as tree contact, alongside bolted fault scenarios in protection coordination studies, as the stress profile imposed on upstream equipment differs;
3. carry out periodic thermal modelling of switchgear at substations of older design vintages against realistic protection coordination scenarios, since thermal margins may be lower than in current designs;
4. reflect the criticality of connected customers, such as hospitals and care facilities, in outage contingency plans and restoration priorities;
5. plan in advance for both immediate restoration measures, such as contracted emergency generation and customer by customer switching, and longer term reinforcement options, such as an additional supply line or a second transformer;
6. record and publish incident findings in a form that can be cited and reviewed, so that protection and equipment lessons are available beyond the operator concerned.

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