Technology Solutions: Automating substations for better asset management

Automating substations for better asset management

Providing reliable power to end-users is one of the key priorities of power utilities. However, an increase in load and technical breakdowns in the system can hamper the supply of uninterrupted power. Therefore, it is critical that substations are properly controlled and monitored, for which the utility undertakes the necessary measures in a timely manner. In this regard, substation automation plays a critical role in maintaining robust operations as it allows the utility to control and monitor substations.

Key components of substation automation

A substation automation system (SAS) deploys a number of devices that are integrated into a single functional array to monitor, control and configure the substation. Some of the key components of an SAS are intelligent electronic devices (IEDs), bay controller units (BCUs), human-machine interface (HMI) and communication interface.

IEDs are a critical component of the SAS. They are microprocessor-based devices which are equipped with a communications port to enable the electronic transfer of analog, status and control data of the substation in a standard transmission format. IEDs facilitate the exchange of both operational and non-operational data. While the former is time-critical data, which comprises instantaneous values of the power system analog and status points such as volts, amps, MW, MVAR, circuit breaker status, switch position used to monitor and control the power system, the latter includes files and waveforms such as event summaries, oscillographic event reports, and sequential event records.

The introduction of IEDs has revolutionised the SAS and owing to the economic benefits, the deployment of these devices is rapidly gaining momentum. Prior to this, in the conventional protection system, the data and control signals from relays were sent through a remote terminal unit (RTU) to the supervisory control and data acquisition (SCADA) system. This required an extensive network of cables between various bays in the substation and the control room. However, real communication was introduced into the SAS following the launch of IEDs, wherein intelligent RTUs allow two-way direct communication between the IEDs and the utility’s SCADA system.

Another important component of the SAS is the BCU. It performs various functions such as managing close or open commands to the switchgear and the operations of the protective relay equipment, and also undertakes synchronism checks for circuit breakers. Besides this, the BCU monitors all other equipment at the substation and records the activity of the substation after a certain time interval.

Levels of substation automation

Substation automation can be structured into three levels – process-, bay- and station-level automation.

At the process level, information from the sensors in the substation is extracted and transferred to an upper-level device called the bay-level device. Another task at the process level is to receive control command from the bay-level device and execute the same.

At the bay level, maintenance work is undertaken only within one bay. The bay-level devices are usually located close to the switchgear. At this level, the IEDs of different bays such as circuit breakers, transformers and capacitor banks are protected and controlled.

The third level, which is the station level, is located in a shielded control room and provides an overview of the whole substation. Station-level automation includes HMI, master station computers, backup station computers and global positioning system receivers. At the station level, two types of functions are performed: process-related station-level functions, which include collection of substation data like voltage, current and power factor from bay-level devices, and interface-related station level functions comprising interactive interface of the SAS with the local station operator HMI and control activities of the tele-control interface. The equipment at the bay and station levels is called secondary equipment.

For the purpose of monitoring, there are control points at the three levels and remote monitoring is undertaken through a router or a modem. The station computer acts as substation server equipment and undertakes control and monitoring of the entire substation.


A communication system is vital for real-time automation of the substation. All secondary equipment within a substation is interlinked with communication buses. In conventional substations, communication devices relied on one-way communication. Serial communication buses or proprietary communication interface with associated protocols were used for local HMI, as well as for remote SCADA communication. Modern communication systems entail two-way exchange of substation data within the three levels – station, bay and process.

The three levels communicate through a high-speed Ethernet station bus and a process bus. While the station bus facilitates communication between the station level and the bay level, the process bus is used for time-critical messages between the process level and the bay level. Most of the substation protection and control functions rely on the performance of the process bus. While at the station level, time-based data from multiple bays or substation-level database is analysed and processed, at the bay level, the protection unit and the control unit collect data from bays and perform actions on the primary equipment, and at the process level, performance and condition information is read from essential station equipment.

Besides this, in the SAS, the operation centre, the master control centre, or the SCADA master station receives and processes data from several substations and takes appropriate control actions. There can also be multiple master stations and thus different topologies can be used to interconnect them for synchronising the grid operational data.

Issues and challenges

One of the key challenges in substation automation is interoperability. There is a need to ensure a generic interface for the IEDs, which is not proprietary to the supplier. Another critical issue is the inability to efficiently extract the required information from the system, owing to the large quantity of data originating from IEDs. Different devices store data in different formats such as waveform samples or event reports, which are not easy to compare. Further, it is important to undertake comprehensive data acquisition as some information may not be important for a particular group of users, but more significant for others. Moreover, it is critical to ensure that substation automation equipment is in the best operating condition. Constant tracking and monitoring of various operational parameters of different substation devices improves the availability and reliability of the equipment.

To conclude, the SAS provides real-time and enterprise-wide information to the utility, thus enabling better asset management. This helps improve the overall reliability of the system. The choice of IEDs in a system must be decided on a substation-to-substation basis, depending on specific requirements. In addition, it is critical to undertake adequate analysis of the data collected from the SAS to gauge its health and take the necessary actions.