A substation automation system (SAS) is the set of protective relays, bay controllers, gateway, HMI and communication network that protects, controls, measures, records and interlocks the equipment of a substation, and links it to the control center. It is organized in process, bay and station levels, and in new substations it is almost always integrated with IEC 61850.
What a substation automation system is
Substation automation brings together in one system the secondary functions that used to be handled by electromechanical relays, annunciator panels, stand-alone recorders and miles of control cable. That set is known as a substation automation system (SAS).
A SAS is not a single device: it is the sum of the protective relays, the bay control units (BCU), the gateway or RTU, the station HMI, the time synchronization clock and the network that ties them together. It serves transmission and distribution substations as well as industrial substations, at medium, high and extra-high voltage. How it differs from SCADA, DCS and an HMI is explained in SCADA, SAS, DCS and HMI: differences. Downstream, on the feeders, distribution automation carries the same idea to the reclosers.
What a SAS automates
| Function | What it does | Usually performed by |
|---|---|---|
| Protection | Detects the fault and opens the breaker | Protective relays |
| Control | Local and remote control of breakers and disconnectors, with select-before-operate | Bay controller, HMI, gateway |
| Interlocking | Prevents unsafe switching based on the position of the devices | Bay controller, hardwired or by GOOSE |
| Sequences | Multi-step automatic switching, transfers, restoration | Bay controller or PLC |
| Metering | Voltages, currents, power and energy | Bay IEDs and meters |
| Recording | Time-stamped events and oscillography | Relays, fault recorders |
| Supervision | Alarms from primary equipment, station service and the network itself | All IEDs, HMI |
| Telecontrol | Sends data to and receives commands from the control center | Gateway or RTU |
Protection remains the most critical function. The rest of the system may degrade without leaving the substation unprotected, and the design must respect that hierarchy. Interlocking, for example, has its own series: substation interlocking.
Station, bay and process levels
IEC 61850-5 describes the automation functions in three levels inside the substation and the logical interfaces between them. In practice a fourth level sits outside the fence:
- Process. The primary equipment: breakers, disconnectors, current and voltage transformers. In a digital substation the merging units and breaker IEDs also live here.
- Bay. One protective relay and one controller per bay (or one device that does both at medium voltage). Each bay operates autonomously.
- Station. HMI, gateway, engineering server, recorders and clock. It coordinates the bays and is the boundary to the outside.
- Control center. The SCADA of the utility or the owner, which receives the data over the wide area network.
The process bus sits between process and bay; the station bus, between bay and station. The architecture of that network, its redundancy and its timing are covered in substation communication network.
From the centralized RTU to the distributed IED
Older substations have centralized automation: an RTU with input and output cards receives each signal over a cable from the yard or the relays and transmits it to the control center. Interlocks are hardwired and the local HMI, if any, is a mimic panel.
Numerical relays brought distributed automation. Each bay IED knows its own signals and shares them over the network; the RTU becomes a gateway that translates protocols instead of reading contacts. The result is less wiring, more information per device and remote diagnostics of every IED.
- 01HardwiredElectromechanical relays, contact-based interlocking and annunciator panel
- 02Centralized RTUSignals hardwired to an RTU that sends them to the control center
- 03Networked IEDs with proprietary or serial protocolsNumerical relays reporting to the RTU over 103, Modbus or DNP3
- 04IEC 61850 on the station busMMS to the HMI and gateway, GOOSE between bays
- 05Digital substationProcess bus with sampled values and less copper in the yard
Most substations in service are at some intermediate stage, with bays of different generations. That is why a real SAS is almost never homogeneous; how to replace it in stages is covered in modernizing a substation automation system.
Where IEC 61850 comes in
IEC 61850 is the series of standards that defines how the data of each IED is named, which services can be requested on it and how it travels over the network. It contributes three things to the SAS: a common data model across brands, the GOOSE message for interlocks and trips between bays, and engineering based on SCL files that describe the complete system. The difference between GOOSE and MMS is in GOOSE vs MMS in IEC 61850; the system file is built with a system configurator, and when the IEDs come from several brands it is worth reviewing GOOSE between relays of different brands.
IEC 61850 normally covers communication inside the substation. Toward the control center the gateway translates to IEC 60870-5-104 or DNP3 (IEEE 1815), as explained in IEC 61850 to the control center; when each protocol fits is compared in IEC 61850, IEC 104, DNP3 and Modbus. The overview of the standard is in IEC 61850: what it is and parts of the standard.
What goes wrong in practice
SAS problems are rarely in the hardware. The usual ones are:
- Configurations that do not match. The file loaded in an IED is not the one the rest of the system uses, and a GOOSE or a report stops arriving.
- Incomplete or outdated signal lists. The control center receives a signal under another name, another address or without quality.
- Commands rejected by the local/remote selector, by an interlock or by the IED mode.
- Poor time synchronization, which scrambles the sequence of events.
- Changes without version control after commissioning, so nobody knows which configuration is current.
Almost all of them are solved in engineering and testing: in the FAT of the complete system, in the SAT on site and in bay-by-bay commissioning before energization. The signal list and SCD configuration management are the tools that prevent these failures most, and both must be required in the specification, as explained in specifying a SAS. You can review an SCD before loading it with our free IEC 61850 SCL viewer.
How it is tested and commissioned
A SAS is verified in several stages: factory tests of each IED, factory acceptance test (FAT) of the integrated system, site acceptance test (SAT) and point-to-point tests of every signal up to the control center. IEC 61850-4 sets out project and quality management, but the test protocol is defined by the specification of each project; the standards are covered in standards for commissioning, FAT and SAT. The simulators and analyzers used are in IEC 61850 test tools, and the complete on-site process in substation commissioning.
We help you with your automation
At Tiza Group we configure relays, bay controllers and gateways of the main brands, for medium, high and extra-high voltage substations and for industry. The fastest way to start is remote relay configuration: we load and verify settings, logic and communications remotely. When the work is on site, with IEC 61850 integration, gateway and testing of the complete system, we do it with our control, protection and communications configuration service, in Colombia, or elsewhere on request.
Related guides
- Bay control unit (BCU): parts, functions and testing
- Substation RTU and gateway: functions, protocols and testing
- Substation SCADA and HMI
- PLCs in substations: uses, IEC 61131-3 languages and testing
- Substation interlocking
- IEC 61850 digital substation: process bus, GOOSE and SV
- Substation communication network: levels and protocols
- Migrating from 103, 101 or Modbus to IEC 61850
- Substation control building: what is inside
- Electrical substation: what it is, parts and how it works
References
- IEC 61850-5, Communication networks and systems for power utility automation – Part 5: Communication requirements for functions and device models.
- IEC 61850-4, System and project management.
- IEEE C37.1-2007, Standard for SCADA and Automation Systems (inactive-reserved).
- CIGRE, Technical Brochure 246, The automation of new and existing substations: why and how, WG B5.07, 2004.
- CIGRE, Technical Brochure 329, Guidelines for specification and evaluation of substation automation systems, WG B5.18, 2007.
Frequently asked questions
What is the difference between a SAS and SCADA?
The SAS lives inside the substation: it protects, controls and interlocks the equipment of that installation and has its own local HMI. The SCADA system at the control center supervises and controls many substations remotely and receives their data through the SAS gateway.
Is a substation with an RTU and hardwired relays already automated?
Yes, although in a centralized way: the RTU collects hardwired signals and sends them to the control center, and interlocks are usually hardwired. A distributed SAS spreads those functions across networked bay IEDs, with less wiring and more information per device.
Is IEC 61850 mandatory to automate a substation?
There is no general obligation: it depends on the specification of the owner or the utility. In practice almost every new high-voltage substation calls for it, while IEC 60870-5-104 or DNP3 (IEEE 1815) are still used toward the control center.