This blog was co-written with Nokia and Andrea Bonetti – Senior Specialist, Megger Sweden AB

If Alexander Graham Bell were given a smartphone today, he probably wouldn’t know how to make a call. But if Thomas Edison, who opened the first investor-owned power utility in New York City 140 years ago, were to tour the switchyard of a modern substation, he would still recognize the transformers, circuit breakers, switches and capacitors.

To the naked eye, it might appear that the power grid hasn’t changed. In fact, there’s been a lot of change, particularly to the monitoring, protection and control equipment in the substation control house. And more changes are on the way.

The changes began decades ago. By the 1930s, utilities had inaugurated the era of remote monitoring by deploying Remote Terminal Units (RTUs) in the control house to read circuit breaker status and communicate with the SCADA master unit in the operations center over a pair of copper phone wires. Protection relays were introduced even earlier to safeguard the power grid from faults on power lines or transformers. These electromechanical-based systems relied on the physics of electric and magnetic fields.

In the 1980s, the advent of microprocessor and serial communications transformed RTU and protection relays into a new class of device called the intelligent electronic device (IED). SCADA gained more intelligence for automation and the ability to support digital communications with the operations center. Relays gained the ability to communicate peer to peer with relays in other substations to coordinate the protection and restoration of power lines. The era of digitalization had begun, but one problem was soon visible: The many communication protocols offered by different vendors created a lack of interoperability among protection devices, IEDs and station SCADA/HMI systems.

To tackle this challenge, IEC Technical Committee 57 (TC 57) published the IEC 61850 standard suite, titled “Communication networks and systems in substations,” in 2003. IEC 61850 defines a communication architecture for digital substations. This architecture replaces conventional hard copper wiring and proprietary communication protocols with Ethernet-based substation automation that uses standard communication protocols (GOOSE, MMS, SV, R-GOOSE, R-SV and others to come). The result is a standards-based framework that achieves the goal of interoperability among protection and control devices from different vendors.

The IEC 61850 standard also provides a powerful System Configuration Description Language (SCL). This language describes how a subset of the many thousands of standardized (semantic) system components (e.g., the position of a circuit breaker or temperature alarm) are selected to configure IEDs and the real-time information exchanges between them. It is crucial for system design and engineering as well as for device configuration.

Driven by grid automation ambitions that extended beyond the substation, IEC began to publish additions to the IEC 61850 standard in 2013. The expanded scope of the so-called “Edition 2” of the IEC 61850 communications architecture is reflected in its title, “Communication networks and systems for power utility automation.” This new edition covers communications between substations and the control center, among substations themselves, and from substations to distribution feeders throughout the field area network (FAN). It allows utilities to deploy smart grid applications everywhere. Essentially, it is now IEC 61850 everywhere!

Harnessing IEC 61850 everywhere makes it challenging to develop a network blueprint. Many use cases involve multiple domains – substation buses, wide area network (WAN) and field area network (FAN). For example, a utility would need to consider the network service requirements of each of these domains to manage a seamless, end-to-end connection between relays in two substations, or between a phase measurement unit (PMU) and a phase data concentrator (PDC) in the control center.

Figure 1: IEC 61850 brings automation and intelligence everywhere

The list of challenges doesn’t stop here. Grid assets such as merging units (MUs) and phase measurement units (PMUs) require time synchronization with accuracy in the order of 1 microsecond. Utilities are also seeking to harness the power of cloud computing technology to run grid applications inside substations and data centers.

Explore IEC 61850 evolution with us

How will the IEC 61850 community evolve the standard to meet these emerging needs and others in the future? Let’s discuss this topic together. We invite you to join our webinar on 26 April 2022 at 10AM EDT to explore IEC 61850 evolution and the ways it interlocks with communications networks.

The authors are grateful to Karlheinz Schwarz, who has kindly reviewed and commented on this blog.