HomeRegional NewsAfricaThe truth about distribution automation in substations and pole-tops

The truth about distribution automation in substations and pole-tops

Technological advances in all-in-one communication and automation processors allow distribution of information in many protocols while performing sophisticated logic functions and alarm annunciation.

This article first appeared in ESI Africa Issue 2-2020.
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Utility substation automation schemes are typically complex, involving a variety of intelligent electronic devices (IEDs), microprocessor-based relays, meters, and monitoring devices. The information collected is then sent to communication processors or RTUs, before being passed on to proprietary human-machine interfaces (HMI), SCADA master stations, energy management systems (EMS) and/or enterprise networks.

Within this scheme, the component parts are often cobbled together by utility automation groups from a multitude of competitor options with varying protocols (some proprietary), configuration options, wireless transmission bands and interconnections.

Given that utilities may have hundreds of substations and even more pole-tops to monitor and control remotely, the complexity of distribution automation has traditionally been staggering. Fortunately, over the past two decades, substation automation has evolved and changed.

“In the past, the design of the substation was a patchwork of many different
devices,” says Russ Fanning, a principal engineer with previously over a decade of experience in the automation group of a large US-based utility.

“Once you finally got the patchwork figured out, you could replicate that
pattern but when you went to the next substation and you wanted to bring in something new, you were starting from scratch again and trying to patch that new piece in.”

Today, Fanning says, the focus is on stripping out as much of the complexity associated with substation automation as possible. Technological advances over the past several years have reduced the need for the same amount of hardware in favour of all-in-one communication and automation processor units that can interpret and distribute information in many protocols while performing sophisticated logic functions and alarm annunciation without
the need for PLCs and racks of RTUs. These all-in-one devices even eliminate the need for security-risk PCs and proprietary HMI interfaces.

The communication and automation processor can connect to nearly any
substation device in its native protocol, perform advanced maths and logic, and securely present the source or calculated data to any number of clients in their preferred protocol.

For utilities installing equipment in greenfield substations, upgrading aging
legacy technology, or concerned about support, this is a welcome development.

Interpreting communications and protocols

Fanning, who was previously employed at a Wisconsin-based utility for 38
years, started his career as a protection technician. After getting his engineering degree in 1990, he worked in substation engineering as a protection engineer, then R&D engineer and in 2007 became a principal engineer in a substation automation group.

“In my last 5-6 years at the utility, I was responsible for distribution automation and substation integration, using the Orion Substation Automation Platform to interface with all the IEDs that were inside the substation and at the pole-tops. I integrated pole-top device IEDs into the distribution automation systems when they were enabled with communication capabilities,” says Fanning.

According to Fanning, the distribution automation system he installed when
he worked at the utility specifically involved 30 Orion units using NovaTech’s Distribution Automation algorithm designed to automate the
switching of substation breakers and pole-top devices to restore power and/or to avoid power outages and equipment damage.

The challenge at the time was having to work around ways to retrieve the
data from the IEDs and other devices, says Fanning. Multiple protocols are
often used for distribution automation, including proprietary protocols with custom communication links.

“In a typical substation set-up at the time, there was often different software in each device and I would have to manipulate the data just to be able to share it,” explains Fanning. “For one system I worked on, I needed a proprietary protocol and software just to communicate to the device.”

In most modern substations, microprocessor-based relays involve a proprietary protocol, so the communications processors must be able to retrieve real-time fault event data and records by speaking to the relays in their native protocol.

Another standard protocol is DNP (Distributed Network Protocol), which is
often used by SCADA Master Stations, RTUs, IEDs and also for relays. To
promote interoperation of IEDs from different vendors, the IEC 61850 is
an international standard defining communication protocols for IEDs.
Older IEDs may still use Modbus or other legacy protocols.

“There is a wealth of information that is being created inside newer IEDs, microprocessor-based relays and meters that, until recently, has been left behind because it was too challenging to collect and distribute it,” adds Fanning. “Today you can drill down into those IEDs from a remote location using a secure connection.” Reducing the travel time to remote sites was one of the biggest drivers in automating the substations, as well. The utility headquarters, and his home, were a 2 to 3-hour drive to some substations.

Today, open-source web-based SCADA and HMI solutions eliminate the need for a substation PC and its inherent software and cybersecurity concerns, at a fraction of the cost. In this approach, engineers can build interactive screens accessible from standard web browsers.

For example, a browser can be used to view data from connected IEDs and
RTUs. The software comes with pre-configured pages for data archiving,
sequence of events recording, alarm annunciation, alarms, trending and communications diagnostics. Customised screens can easily be built
for one-line diagrams, IED faceplates, and control screens.

As for HMIs, web-based systems provide a direct-to-touchscreen connection out of the box without a PC as an intermediary. Information can also be accessed by smartphone, which will bring up a substation and graphically show the faceplate of each device with push buttons as if the technicians were physically there.

“The HMI is served up through webpages that are easily constructed with graphic software. It’s all integrated in one package, so building an HMI is so
much simpler than it used to be,” says Fanning.

If there is a physical manifestation of the reduction in complexity, Fanning points to the substation. In many substations he worked in there would be racks or cabinets of devices with hundreds of wires and blinking lights.

“Today, substation layout is much cleaner. You can probably eliminate entire writing racks and cabinets – or at least make them much smaller –
depending on how you are handling the Input/Outputs to the IEDs,” says
Fanning. ESI

This is an edited version of an article originally published by our sister
publication, POWERGRID International. www.power-grid.com