From the street, Georgia Transmission Corporation’s 230-kV substation on the edge of Douglasville, Georgia, looks like a pretty traditional setup. But this seemingly normal facility is actually part of an ongoing revolution in the role and technology of substations.

For decades, the primary function of a substation has been to manage voltage, stepping it up or down as required, and to protect the system and route power. Demands on substations, however, are expanding significantly as distributed generation (DG), smart grid technology, and analytics change both capabilities and expectations.

“It’s critical to recognize that the substation has a very different role than it has had in years past,” says Tom Lovas, NRECA technical liaison and consultant. “Now, we have to consider a whole lot of different things: communications technology, the interoperability of devices, the role of resiliency, and certainly the issue of being able to monitor and control the operation of distributed resources.”

An increased focused on security, both cyber and physical, and greater integration of local generation and storage are also expected to play a broadening role in substations, says Patti Metro, NRECA’s senior grid operations and reliability director.

The substation of the future is coming into focus in changes already underway. Solid-state and microprocessor relays have been part of substation upgrades since before the start of the millennium. In combination with broadband communications, they’ve helped to transform the amount of data from and degree of control over substation components.

Even greater monitoring and analytic capabilities lie ahead.

Improving situational awareness

At the Douglasville substation operated by Georgia Transmission Corp. (GTC), headquartered in Tucker, Georgia, online monitors track the condition of transformers, breakers, and relays. This information is concentrated and stored on site using Schweitzer Engineering hardened computers.

Overall, these systems provide multiple data sets, which help the G&T identify equipment that needs to be replaced or repaired, making it easier to schedule proactive maintenance and improve performance and reliability.

The project also includes a new human-machine interface on a substation display that gives insight to workers attending to a trouble call, says Eric Schultz, GTC transmission services engineer. “It really improves situational awareness.”

The substation’s upgrades are part of a pilot project in a larger research effort sponsored by NRECA and led by the Centre for Energy Advancement through Technological Innovation (CEATI), a research institute based in Montreal. The goal is to develop the framework for performance and diagnostic centers at power utilities to advance system monitoring.

Schultz believes improving substation diagnostics will be essential in the future.

“If you want to keep improving reliability, you’re going to have to be more proactive through these types of devices and get smarter in how you monitor what’s happening and smarter about using the data you already have,” he says. “We’ve made great strides in reliability over the years. But if you want to take that next step and go even further, this is one of the ways to do it.”

Managing an influx of DG

NRECA’s Lovas notes that the newest technology for substations significantly expands their role in electric co-op operations.

“The substation is no longer just a delivery point on the system,” he says. “It’s now an information node and, for distributed energy, a collection point.”

The value of a substation as an information node is one reason Buckeye Rural Electric Cooperative (BREC), based in Rio Grande, Ohio, is upgrading its system. The co-op is in the middle of a multi-year project that includes its first SCADA system, installing fiber for high-speed communications with some substations, and upgrading to solid-state reclosers and regulators.

The new reclosers provide fault current data that allows the co-op to pinpoint fault locations, which SCADA can automatically pass on to field crews.

“Our system is so widespread, so rural, this technology is really going to enhance our ability to serve our members,” says Ed Mollohan, BREC’s operations manager.

The co-op is integrating substation security into its new SCADA to alert staff of trespassers, which they hope will reduce theft and vandalism. The upgrades also allow a new level of transformer monitoring.

“They can see if they have oil issues, oil temperature issues,” says Jim Weikert, vice president of sales for Power Systems Engineering, the contractor working with BREC on the upgrades.

BREC serves about 18,800 members across nine counties in southeastern Ohio. The membership is 98 percent residential, Mollohan says, but DG is still coming to the co-op’s service territory.

“We’ve got four solar hookups tomorrow,” he says.

The regulators being incorporated into the system will provide data to enable the voltage control necessary to handle the influx.

“With DG now being another source of power on the system, they will have the ability to manage the voltage actively,” Weikert says.

Volt/VAR works with AMI

Sophisticated voltage control is expected to be a big part of the substation of the future. Choptank Electric Cooperative, based in Denton, Maryland, recently completed a volt/VAR optimization program that takes advantage of advanced metering infrastructure (AMI) data and automated smart electronics at substations.

“They wanted to be able to lower their peak demand costs,” says Richmond Miller, executive manager at Dominion Voltage, which worked through NRTC to plan and manage the implementation. “They were able to coordinate all the information to lower the voltage taps in their substations using AMI data to make sure they knew exactly what the impact was on their consumer-members.

“They were able to drop overall voltage at their substations over 3 percent without having their customers falling into voltage alarm issues.”

The voltage drop “resulted in a more than 5 percent reduction in total energy costs,” Miller says, “which translates to lots of dollars.”

Becoming more than substations

The increasing sophistication of the technology and software at substations, along with broadband connectivity, brings additional responsibility to future substation design.

“It’s going to become more and more critical to develop solutions to manage the expectations of grid security,” says NRECA’s Metro. “We will have to do things concerning electronic security to protect data and control systems, but we will also be doing more and more physical security.”

The North American Electric Reliability Corporation has standards regarding physical security for transmission substations. Distribution cooperatives and other utilities have not faced the same requirements, but Metro says we will likely see a greater emphasis in this area as part of overall security concerns.

In the future, she adds, some substations are likely to become more than substations.

“At a substation location, if you already have the land available, you might be seeing some solar arrays and battery storage,” Metro says. “Why at the substation? Because you already have the assets there.”

The combination could be particularly valuable at isolated or end-of-the-line substations.

“You may be able to manage load by having some type of generation available and battery storage to keep critical loads on-line,” Metro says.

Buckeye Rural Electric’s Mollohan foresees the substation of the future functioning both as an “information-gathering system” and a more sophisticated power-control center, giving electric co-ops new ways to manage their systems to boost both reliability and efficiency.

“It’s exciting, and it could be a game changer,” he says. “It’s one of those moments in cooperative history where really interesting things are happening.”