Growing Scope

Switchgear requirements for substation automation

Switchgear requirements differ in conventional substations and automated substations. In a conventional substation, all signals, controls and interlocks are hardwired and records are manually maintained in a logbook. Therefore, a lot of work and effort is required to draw comparisons for analysis and troubleshooting. An automated substation, wherein all operations are automated, is more efficient and requires less manpower.  Traditionally, remote terminal units (RTUs) were used in substations as a link between the switchgear and the control centre. Some of these RTUs had intelligence features such as interlocking functions, but no substation- or region-wide automation was available. However, today, more and more RTUs are being replaced by or complemented with specialised intelligent electrical devices (IEDs) that are capable of multiple protections and measurements. In addition, intelligent gateways and data concentrators have been introduced in the substation. Monitoring and signalling are becoming an integral part of switchgear, in addition to protection and control functions.

The IEC 61850 standard

For controlling switchgear in process plants with high power requirements, International Electrotechnical Commission (IEC) 61850 is the globally recognised standard. All manufacturers can adapt their products to the same communication model and protocol, enabling the IEDs to operate with each other. A wide array of IEDs covers virtually every system automation task. These devices are generally controlled from a control system that is operated and monitored separately from the plant’s distributed control system.

Communication network

The performance of a substation automation system can be enhanced by an effective communication system that connects all the protection, monitoring and control devices within the substation. There are three basic communication network topologies – bus, ring, and star. These are mainly implemented with Ethernet switches in substations.

In a typical star architecture, all switches are linked to a common central node called the “backbone” switch. Of all topologies, this one offers the lowest latency along with a time delay for the message transmission, which complies with the IEC 61850 standard requirements. However, reliability is an issue since there is no redundancy and all devices are connected to a single central switch, which is highly susceptible to environmental and electromagnetic conditions.

The cascading (bus) architecture has each switch connected to the previous and/or next switch in the cascade via one of its ports. These ports operate at a higher speed than the ports connected to other devices, but there is also a retransmission delay caused by the internal processing time of each switch called the switch latency. Therefore, the maximum number of switches that are cascaded depends on the worst-case delay that can be tolerated by the system. This network architecture may provide acceptable time delays in a cost-effective manner, but complete reliability is still not achieved since it does not offer redundancy.

The ring architecture is very similar to the bus topology except that the loop is closed from the last switch to the first switch. A ring topology with managed switches allows sub-second network reconfiguration during a communication fault, thus offering physical redundancy. This network architecture provides allowable time delays and offers more reliability as compared to the other two topologies at the cost of being more expensive and complex than the remaining configurations.

Protection, control and metering

Manufacturers are including built-in protection and control IEDs in switchgear to enhance grid efficiency and reliability. Voltage measurements shared via the local area network are used in IEDs for protection purposes. In modern primary switchgear, bay-dedicated functions like protection, control and measurement are carried out by feeder terminals. Horizontal communication between feeder terminals in each cubicle provides the possibility for station level automation and gateway connections to upper level systems for real-time control and monitoring of the primary distribution network.

Another emerging technology trend is process bus automation. A key advantage of the process bus is that it eliminates the use of electrical cable connections between the process equipment and IEDs by providing optical fibre-based communication. Other advantages include improved safety and flexibility of the protection system. A non-conventional instrument transformer (NCIT) with a digital interface based on a process bus eliminates issues relating to differences in protection and metering requirements. The successful implementation of NCIT in various applications requires the availability of a wide range of products including merging units, current transformer based on optical sensors and primary electronics, voltage transformers based on capacitor dividers and primary electronics, and IEDs.

Conclusion

With the arrival of smart grids, substation automation is expected to expand significantly, providing increased control of relays, capacitor banks, voltage regulators and feeders. Given their critical role in substation automation, the scope of switchgear is also expected to grow considerably in the near future.

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