+971 55 954 5801

A grid station looks like one thing from the road. Inside, it is not one system at all. It is a collection of bays, each with its own switchgear, its own current and voltage transformers, its own interlocks and its own reasons to refuse a command.

The device that turns that collection into something an operator can drive from one screen is the bay control unit.

What one bay control unit actually does

Take a single feeder bay. Somewhere in it there is a circuit breaker, two or three isolators, an earth switch, and instrument transformers. The bay control unit sitting in that bay's cubicle does five things.

It knows the position of everything. Open, closed, or in the disagreement state that means a contact has failed and nobody should be trusting the mimic.

It measures. Currents, voltages, power, frequency, and the derived values the control room wants to see.

It enforces the interlocks. This is the part that matters most. An isolator must not be operated on load. An earth switch must not close on a live circuit. The bay control unit holds those rules and refuses the command if the conditions are not met, regardless of who asked.

It executes. Select, check, operate, with a synchrocheck where two systems are being paralleled.

It reports, with a timestamp taken at the bay. That last detail is what makes a disturbance investigation possible. If the sequence of events is stamped at the server, the record only tells you the order the packets arrived in.

Why ninety of them

On TRANSCO project N-15228 we replaced the substation control and monitoring system at the Musaffah 220, 33 and 11 kV grid station as main contractor. That station took ninety Schneider C264 bay control units.

The number surprises people until you count the bays. A station operating at three voltage levels has transformer bays, feeder bays, bus couplers and bus sections at each level, and every one of them is a separate electrical entity with its own switchgear and its own interlocking rules. One controller per bay is not redundancy. It is the only arrangement where a fault in one bay's controller does not take the visibility of the whole station with it.

The same job carried redundant gateways, one pair publishing the 220 kV side to the load dispatch centre and another publishing the 33 and 11 kV side to the distribution management system, plus GPS time synchronisation, station UPS and the new communication links.

The layer above

Bay control units talk to each other and to the station level, and that station level is the SCMS proper: servers, an operator workstation, an engineering workstation, and gateways out to whoever needs the data.

On TRANSCO project N-15223 we replaced that whole layer across six grid stations running from 400 kV down to 11 kV, including the servers, the human machine interface and engineering workstations, IEC 101 gateways, the bay control units themselves, station UPS, fibre optic cabling, and the integration back to the load dispatch centre, the emergency control centre and the distribution management system.

At Al Khazna the upper and lower ring SCMS was upgraded at 33 and 11 kV with the hardwired interlocking deliberately retained through the change, so the station's safety never depended on the new system being healthy while it was being installed.

At Khalifa Port the same architecture went into three primary substations at once, for a client whose cranes do not stop.

What replacing one is really like

Almost none of this work happens on a dead station. The pattern is the same every time.

Survey first, because the drawings describe an intention from years ago and the copper describes what was actually built. Then a bay by bay outage plan arranged around the station's transmission duty rather than around the works programme. Then the new bay control units installed, configured and point to point tested against the existing interlocking before anything is cut over. Then the gateways, then the control centre integration, then the training, then the documentation.

The engineering is not the hard part. The sequencing is, and the sequencing is where a station either stays in service or does not.

Working with us

Almafor has delivered substation control and monitoring system replacement and upgrade as main contractor on live transmission and distribution stations from 400 kV down to 11 kV, for TRANSCO, TAQA Distribution, Al Ain Distribution Company and AD Ports Group.

If you have a station on an unsupported platform, the first useful conversation is about what is installed, what the interlocking currently depends on, and what outages you can realistically get. Call +971 55 954 5801 or email info@almafor.com.

Common questions

Questions we are asked about this

What is a bay control unit?

A bay control unit is the controller for one bay of a substation: one transformer, one feeder, one bus coupler. It reads the position of every switch in that bay, measures its currents and voltages, enforces the interlocks that decide whether an operation is allowed, executes commands from the control room, and reports the whole state upstream with a timestamp. One per bay, which is why a large station needs dozens.

What is the difference between a BCU and a protection relay?

A protection relay exists to trip. It watches for a fault and opens a breaker in milliseconds, and it must do that whether or not anything else in the station is working. A BCU exists to control and report. It handles interlocking, synchrocheck, commands and data. Modern devices can combine both functions, but the duties stay separate: protection must never depend on the control layer being healthy.

What is an SCMS?

A substation control and monitoring system is the layer above the bay devices: the servers, the operator workstations, the engineering workstation and the gateways that publish the station to the outside world. It gives an operator one picture of the whole station and gives the load dispatch centre and the distribution management system a feed they can act on.

Can an SCMS be replaced without switching the station off?

Yes, and that is how nearly all of ours are done. The work is sequenced bay by bay against an outage plan built around the station's transmission duty, with hardwired interlocking retained through the change so the station is never dependent on the new system to stay safe. It is slower than a shutdown and it is usually the only acceptable option.

Why do stations end up replacing an SCMS at all if it still works?

Usually not because it failed. Because the platform is unsupported, the spares are gone, nobody holds the configuration, or it cannot integrate with the control centre systems the utility now runs. The trigger is unsupportability rather than failure.

We want to hear from you

Tell us about the system you need built, upgraded or kept running.

Contact us