Substation automation and SCADA
Every bay on one screen: IEC 61850 integration of protection and metering, a live single line diagram, and reliable telemetry.
The architecture we design to
Read it top to bottom: the control centre only talks to the gateway, operators work at station level, every bay has its own panel, and each panel is wired to the equipment directly below it.
What happens when a feeder trips
- 1Fault on feeder F3The CT sees the overcurrent and the protection relay trips the breaker in about 40 ms, over hardwiring.
- 2Other bays interlockThe relay publishes a GOOSE message so the other bays interlock, and reports the trip over MMS with a 1 ms time stamp from the GPS clock.
- 3Operator sees itThe operator HMI turns F3 red on the single line diagram, raises the alarm and logs the sequence of events.
- 4Control centre informedThe gateway forwards the trip and the feeder current to the DISCOM / SLDC control centre over IEC 104.
- 5Restored and recordedAfter the fault is cleared the operator closes the breaker from the HMI. Every action is in the audit log and the outage duration goes into the report.
What each layer gives you
What we deliver
We deliver substation automation as part of power distribution and infrastructure EPC packages. Our scope is the automation layer: integrating protection, control and metering devices, building the SCADA, and connecting the substation to the people who run the network.
Integration
- Protection and control: numerical relays and bay control units over IEC 61850, with breaker and isolator control, interlocks and trip status.
- Metering: multifunction and ABT energy meters for voltage, current, power, power factor and energy on every feeder.
- Transformers: oil and winding temperature, Buchholz and pressure relief alarms, OLTC tap position and RTCC control.
- Auxiliaries: DC system and battery charger status, fire detection, AC distribution.
- Time sync: GPS clock so every event across all relays carries a consistent time stamp.
SCADA functions
A live single line diagram with breaker states, feeder loads and alarms. Every trip and operation logged in a sequence of events list. Load and energy trends stored for analysis. Reports for feeder-wise energy, maximum demand, interruptions and outage durations.
Telemetry
A gateway reports the substation to the distribution company control centre or SLDC over IEC 60870-5-104 or 101, and shares data over Modbus or OPC with plant SCADA where a substation feeds a water treatment plant or pumping station.
Why a process automation integrator
Power and process meet in the same project. A water scheme has a substation, pump houses and a treatment plant; an LPG terminal has its own HT substation. We engineer both sides, so pump starts, load shedding and power quality data sit in one coherent system.
For project heads and buyers
Every breaker, relay and meter in the substation talks to one screen. The operator can open and close feeders from the control room, and every trip is recorded to the millisecond.
- Why it matters
Utilities and large consumers now specify IEC 61850 and telemetry to the control centre. Hardwired panels cannot deliver either and cost more to change later.
- What you receive
- IEC 61850 configuration (SCD) and device integration
- Station SCADA with SLD, alarms and SOE
- Gateway to the control centre
- FAT, SAT, commissioning and training
- Helpful to have
- Single line diagram and bay list
- Relay and meter makes and models
- Control centre protocol and signal list
- Typical duration
Three to five months for a distribution substation.
How a project runs
- Scope callWe go through your P&ID, I/O list or tender clause and agree what the control system has to do.
- Technical offerA control philosophy, architecture drawing, bill of materials and price. No surprises later.
- Engineering and buildDrawings for approval, PLC logic and SCADA screens built, panels assembled and FAT tested with you present.
- CommissioningInstallation supervision, loop checks, start-up and operator training on your site.
- SupportDocumentation handover and an annual maintenance contract with a named engineer.
What to send us for a quote
Attach these to your enquiry. The three marked essential are enough for us to start a budget.
- Single line diagram and bay listEssential
They give us every breaker, isolator, transformer and feeder the SCADA must show.
- Relay and meter makes, models, firmware and available portsEssential
They decide whether a device speaks IEC 61850 or needs a gateway.
- Control centre protocol (IEC 104 or 101) and signal listEssential
The control centre's list fixes the points we must map and report.
- ICD or CID files from the relay vendors, for IEC 61850
We build the station configuration (SCD) from them before devices reach the factory.
- Interlocking requirement for each bay type
Busbar, line and transformer bays have different permissives, and we code them from your rules.
- Time synchronisation arrangement, such as a GPS clock
Sequence of events is only as accurate as the shared clock.
- Existing RTU or SCADA, if this is a retrofit, and the outage plan
We plan what stays in service while the new system is brought up.
- Utility technical specification and any regulation it cites
It sets the protocols, availability and documents we have to meet.
- Control room layout, DC supply and auxiliary power details
They fix panel positions, supply redundancy and cabling routes.
Do not have all of it? Send what you have; we work from a site visit for the rest.
What drives cost and schedule
- Number of bays
- Each bay adds devices to configure, screens to build and interlocks to test.
- IEC 61850 or legacy devices
- Older relays need protocol gateways, which add hardware and engineering.
- Mix of relay makes
- Each vendor's configuration tool and ICD files add engineering effort.
- Redundant station network and gateway
- Duplicating the network and gateway adds hardware and failover testing.
- Control centre integration
- Point-to-point checks with the control centre depend on their team's time.
- Retrofit outages
- Working in a live substation depends on shutdowns the utility grants.
Typical timeline
- Scope and signal list2 to 3 weeksBay list, device list and control centre signals agreed.
- Design and IEC 61850 engineering3 to 4 weeksDrawings approved and station configuration (SCD) built.
- Panel build and station software4 to 6 weeksGateway and station panels built, SCADA screens written.
- FAT with relays1 to 2 weeksDevices tested together with the real relays and meters.
- Site installation and SAT2 to 4 weeksInstallation, point-to-point checks and site acceptance.
- Commissioning and training1 to 3 weeksControl centre tests, interlock checks and training.
Overall: Three to five months for a distribution substation.
Budget
Every plant is different, so we price from the I/O list and scope rather than a rate card. Send the documents above and you will have a budget figure within a week, and a fixed price after the scope call.
Common questions
What is substation automation?
Networked protection relays, bay controllers and a SCADA system replace hardwired control panels and manual logging. Operators see the live single line diagram, operate breakers remotely and get a time-stamped sequence of events for every trip.
What is IEC 61850?
The international standard for communication inside substations. Devices from different makers share data over Ethernet, report to SCADA using MMS and exchange fast GOOSE messages for interlocking, removing much of the copper wiring between panels.
Can the substation report to a utility control centre?
Yes. A gateway publishes selected data over IEC 60870-5-104 or 101 so the substation can be supervised from the distribution or load dispatch centre.