The challenge
The network’s substations are unmanned. When a feeder trips, the first alert is often a customer complaint, and a technician is sent out to find which breaker opened and why. Restoration time is dominated by finding the fault, not fixing it.
Most substations already have protection relays, energy analysers and transformer temperature monitors, but they use different protocols and report to nobody. Load-shedding makes it worse: breakers switch several times a day and generators and UPS units start and stop, with no confirmation that they did so correctly.
Battery chargers (rectifiers) and fire panels fail silently, and the failure is only discovered during the outage they were meant to cover.
Our approach
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Substation survey
We inventory every substation’s protection relays, meters, transformer monitoring and auxiliary systems, and record which already use IEC 61850, which use Modbus and which have no communications at all.
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An RTU in every substation
An RTU reads breaker positions, trip signals, transformer temperatures, rectifier and fire alarms, and generator and UPS status. Where relays already use IEC 61850, the RTU reads them directly as an MMS client.
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Event-driven telemetry
Changes are pushed to SCADA the moment they happen over IEC 60870-5-104: time-stamped events, not values polled minutes later. Links run over fibre where available and LTE elsewhere, on a segmented OT network.
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Operations and reporting
Operators see the whole network on one single-line view, acknowledge alarms with notes and, where switching procedures allow, operate motorised breakers remotely. Energy analyser data feeds hourly, daily and monthly reports.
System architecture
How the layers connect, from the people using the system down to the equipment in the field.
- Control room and standby technicians
- Alarm notifications
- Engineering reports
- SCADA single-line diagrams
- Alarm management and event log
- Energy reports per feeder
- IEC 60870-5-104 over fibre or LTE
- Segmented OT network, private APN
- RTU per substation
- IEC 61850 MMS client
- Modbus gateways for legacy meters
- Breaker position and trip
- Protection relays
- Transformer temperature
- Rectifier, fire, generator and UPS status
What we’d deploy
- RTU in every substation with time-stamped event logging
- IEC 61850 protection relays read directly as an MMS client
- Modbus gateways for legacy energy analysers
- Transformer temperature monitoring: instantaneous and peak values
- Rectifier, fire panel, generator and UPS status monitoring
- Motorised breaker control and fault detection where approved
Target outcomes
Targets we would design and report against, not measured results from a named client. Actual results depend on the baseline established in the audit.
