SCADA supervises and controls dispersed installations remotely, such as the substations of a grid. The SAS automates and protects a substation from the inside. The DCS continuously controls an industrial process concentrated in one plant. The HMI is the screen the operator uses to see and command any of the three, and the PLC is a controller that runs field logic.
Why they get confused
In an industrial plant with its own substation, several control systems coexist, and each manufacturer names them its own way. The process DCS, the substation automation system, the utility’s SCADA and the HMIs of each panel share similar screens and sometimes the same supplier. But they answer different needs, sit in different places and follow different rules about who is in control.
What each one is
| System | What it is | Where it lives | What it controls |
|---|---|---|---|
| SCADA | Supervisory control and data acquisition at a distance | Control center | Many dispersed installations: substations, lines, plants |
| SAS | Substation automation system | Inside the substation | Protection, control, interlocking and recording of one substation |
| DCS | Distributed control system | Plant control room | A continuous process: control loops, sequences, process safety |
| HMI | Human-machine interface | In any of the above, or on a panel | Nothing by itself: it displays and sends commands to the system behind it |
| PLC | Programmable logic controller | Field or plant panel | Discrete logic and sequences of machines or station service |
SCADA. It was born to supervise installations miles apart. Its strength lies in communications with remote stations, handling alarms and events from many installations, and historical data. In the power sector it is the control center system of the transmission operator or the distribution utility. We describe it in substation SCADA and HMI.
SAS. It is the internal automation of a substation: relays, bay controllers, gateway, station HMI and network, almost always with IEC 61850. Its priority is protection and safe switching of the power equipment. Its process, bay and station levels are described in substation communication network.
DCS. It was born in the process industry (refineries, chemicals, paper, thermal generation) to regulate thousands of loops continuously with high availability. Its controllers are distributed, but the system is designed and configured as a whole, with a single database. It is not meant to operate high-voltage breakers or to apply switchyard interlocking.
HMI. It is only the operating layer. It can be a screen on the front of a panel, the station HMI of the SAS or the SCADA consoles. For the process industry, ANSI/ISA-101.01 gives HMI design criteria (navigation, alarms, consistency); in substations, the HMI follows the control model of the SAS.
PLC. It is a programmable controller using IEC 61131-3 languages. In the substation it automates processes that are not protection: station service, transfers, load shedding or cooling. Its role next to the bay controller is covered in PLCs in substations.
Which one controls which
Control of a power device is not shared equally among the systems. There is a hierarchy of levels (switchyard, bay, station and control center) and, at any moment, only one of them has authority, according to the local/remote selectors. The bay controller is the one that finally executes the command, after checking interlocks and synchronism. The rules are in control levels and the local/remote selector.
- Is it a protection function or a trip?
- YesProtective relay, never SCADA, the DCS or the PLC
- NoIs it the control of a substation breaker or disconnector?
- YesBay controller of the SAS, with its interlocks
- NoContinuous plant process in the DCS; supervision of several installations in SCADA; station service and plant sequences in the PLC
The practical rule: protection, always in the relay; substation power equipment, in the bay controller; the plant process, in the DCS or the PLC; and supervision of many installations, in SCADA. The HMI of each one displays and requests, but does not decide.
Typical case: industrial plant with its own substation
Consider a plant with a DCS and a high-voltage substation that feeds it:
- The substation has its SAS: relays and bay controllers with IEC 61850, a station HMI and a gateway.
- The DCS needs to know which feeders are available, how much power there is and whether a bus was lost, in order to reschedule loads or start on-site generation. It receives that data from the gateway, normally over Modbus TCP, IEC 60870-5-104 or OPC, or over IEC 61850 when the DCS supports it.
- The utility receives measurements and status from the point of connection in its SCADA, through the same gateway or another channel, according to the interconnection agreement.
- Load shedding can live in the SAS, in a dedicated PLC or in a power management system, but not in improvised logic inside the DCS.
The integration is planned with a common signal list and clear rules about which commands are accepted from each system. We explain it in integrating the substation into the plant SCADA.
Common mistakes
- Moving substation interlocking to the DCS or SCADA. If communication drops, the interlock disappears. Interlocking must live in the bay controller or in the wiring.
- Using the HMI as if it were the system. A screen showing a status does not guarantee that the data has good quality or a time stamp.
- Duplicating transfer or load-shedding logic in two systems, which end up working against each other.
- Choosing by brand instead of by function: an excellent DCS does not replace a bay controller, and SCADA does not replace a process control system.
- Forgetting cybersecurity at the boundary between systems. The substation network and the plant network are separated by a firewall with explicit rules.
Testing and commissioning the integration
Each system is tested separately at its FAT and then together on site. During commissioning of the integration, status, measurement, quality and time stamp are verified signal by signal in every system that receives them, as are the commands from each level with the selector in each position. A command that must be rejected is tested too.
We help you sort out your control system
At Tiza Group we configure relays, bay controllers and gateways, and integrate them with the utility’s SCADA and with the plant DCS or PLC, in substations and industry. If the problem is in a relay or its communication, remote relay configuration is the shortest path. For complete on-site integration, see SCADA and gateway integration, in Colombia, or elsewhere on request.
Related guides
- Substation SCADA and HMI
- PLCs in substations
- Bay control unit (BCU)
- Substation RTU and gateway
- Integrating the substation into the plant SCADA
- Control levels and the local/remote selector
- IEC 61850, IEC 104, DNP3 and Modbus: which one to use
- Substation control building: what is inside
- IEC 61850 in industrial plants: when it makes sense
- Protective relays: types, functions and maintenance
References
- IEC 61850-5, communication requirements for functions and device models.
- IEEE C37.1-2007, Standard for SCADA and Automation Systems (inactive-reserved).
- ANSI/ISA-101.01-2015, Human Machine Interfaces for Process Automation Systems.
- IEC 61131-3, Programmable controllers – Part 3: Programming languages.
- IEC 62443 (ISA/IEC 62443), security for industrial automation and control systems.
Frequently asked questions
Is an HMI the same as SCADA?
No. The HMI is the operator interface: screens, alarms and commands. A SCADA system includes an HMI, but it also acquires data from remote stations, keeps historical records and manages communications with many installations. A local bay or panel HMI is not SCADA.
Why is a plant substation not controlled from the DCS?
It can be supervised from the DCS, but control of the power equipment, interlocking and protection must stay in the relays and bay controllers of the substation. The DCS receives data and sends commands through a gateway, without replacing that logic.
Can the utility's SCADA control equipment in an industrial substation?
Only if the interconnection agreement says so and the substation delivers those commands through its gateway. Normally the utility receives measurements and status from the point of connection, and control stays with the plant owner, according to the local/remote selector and the control levels.