22kV Switchgear Replacement: Design and Commissioning

A 110/22 kV zone substation supplying a town and its surrounding distribution network needed its 22 kV switchboard replaced. Two 110/22 kV transformers feed two 22 kV buses, and the switchboard splits that supply across twelve outgoing feeders, one of which serves an embedded generator. The original metal clad switchgear had reached the end of its serviceable life and was not arc fault contained, so a 22kV switchgear replacement was needed with the substation kept in service.

The new board is a 17 panel arc fault contained switchboard with vacuum circuit breakers. Megavar was engaged by the head contractor to deliver the design and the testing and commissioning, with the switchgear, protection relays and network switches free issued by the asset owner and the installation carried out by others. Because the substation had to stay in service, the control building was extended by 4.5 m and the replacement was staged bus by bus, with one bus energised while the other was stripped out and rebuilt.

Megavar carried the design across primary, civil and structural, building services, secondary and SCADA disciplines, then tested and commissioned the new switchboard into the operating station. The work ran from December 2024 to energisation of the completed board in February 2026, with as-built design documentation issued in May 2026. It adds to Megavar’s utilities sector experience on network substations across Australia.

• 22 kV switchgear: 17 x arc fault contained panels with vacuum circuit breakers: 2 x 2000 A incomers, 1 x 2000 A bus coupler, 2 x bus metering and VT cubicles, 12 x 630 A feeders (free issued by the asset owner)
• Protection relays: 17 x Siemens 7SJ82 (12 feeder, 2 incomer, 1 bus coupler, 2 busbar protection), firmware upgraded from v8.83 to v9.71 to match the asset owner’s standard version
• Substation LAN: 3 x Hirschmann RSP35 Ethernet switches and associated network
• 22 kV cables: Incomer and feeder cables: HV withstand, partial discharge and VLF testing
• Metering: Revenue and check metering CTs and VTs, NATA accuracy tested
• Protection schemes: Bus zone, bus coupler, incomer and feeder protection, interface and stability testing with the existing T1 and T2 transformer protection, live load blocking and auto reclose enable and disable for the embedded generator feeder
• SCADA: Station RTU and site gateway modification, IED mapping, HMI, end to end point testing to the network control centre
• Building services: VESDA fire detection, DC emergency lighting, security and access control for the building extension

Replacement in a live substation

Each 22 kV bus had to be stripped out and rebuilt while the adjacent bus stayed energised, and because the existing switchgear was not arc fault contained, arc flash segregation between the work area and the in-service bus was a permanent constraint on access and sequencing. Megavar developed a bus by bus staging and secondary isolation plan with the head contractor and the asset owner, revised through the programme, with progressive weekend works built into the sequence so the in-service bus was never left without protection. Arc flash segregation and access restrictions were designed into the staging rather than managed on the day.

The building extension on the critical path

The control building had to be extended by 4.5 m before the 22 kV B bus could be relocated and replaced, which put the civil and building works directly ahead of the electrical staging. Holding a single design authority across primary, civil, secondary and SCADA meant staging changes could be assessed and reissued quickly rather than negotiated between separate designers. Each design package was formally transmitted for client review at the concept, 80%, 100%, IFC and as-built gates.

Partial discharge on new switchgear

HV withstand and partial discharge testing on both buses identified PD sources that were not visible on inspection: contact springs requiring rectification between panels, a failed current transformer on one bus, and a further source on the other. Rather than replacing components on suspicion, the team split the bus and progressively isolated sections until each source was located. Replacement current transformers were PD bench tested before installation, retested after installation, and the affected phase retested again to confirm no other source remained. Every source was found and cleared before energisation.

Embedded generation on the network

The embedded generator on one feeder required live load blocking and auto reclose enable and disable logic on its feeder bay, live load blocking through voltage presence indicator contacts across the remaining feeders, and a back up feeder arrangement from the A bus. These schemes were designed, configured and tested as part of the protection scope.

Integration with an operating station

New protection and SCADA had to be integrated with the in-service T1 and T2 transformer protection, the existing site gateway and station RTU, revenue metering and a UFLS panel being decommissioned. An RFI and defect register was kept for the whole of testing: eight RFIs were raised, investigated, rectified with protection logic changes where required, retested across every affected feeder and formally closed, with the protection report and setting change notices reissued to match the as-commissioned state.

Holding the outage programme

Where testing windows came under pressure, additional testers were mobilised from another Megavar office and commissioning was moved into after hours and weekend work so the outage dates held. Relay firmware was upgraded to the asset owner’s standard version and as-commissioned setting files were uploaded to its protection settings database, so the asset handed over was already aligned with the client’s own standards and asset databases.