Canada is building a microgrid of microgrids. On Tuesday, Sustainable Development Technology Canada announced a $16.4 million Canadian ($12.4 million) project to link three widely dispersed microgrids in Toronto, Nova Scotia, and upstate Maine into a “transactive energy” framework.
Utility partners Nova Scotia Power, Emera Maine, and Toronto Hydro will contribute most of the funding, with CAD $5.4 million ($4.1 million) coming from the Sustainable Development Technology Canada (SDTC), a public-private group that’s invested billions of dollars in Canadian green technology efforts.
Leading the technology portion of the project is Opus One Solutions, an Ontario, Canada-based startup that’s built a “GridOS” technology platform for real-time monitoring, analyzing and managing of distributed energy resources down to the feeder level. It’s going to be in charge of the front-of-the-meter portion of the project, connecting various distributed energy resources to grid sensors and other utility equipment.
The consortium also includes Advanced Microgrid Solutions, the San Francisco-based startup with some 80 megawatts and counting in battery-backed, demand-response-enabled microgrids, and Smarter Grid Solutions, a Scottish startup with technology managing some 120 megawatts of grid-responsive generation and load in the U.K.
The overall goal of the project is to “demonstrate the use of technical and economic signals to manage the exchange of electricity,” a term that has been dubbed “transactive energy” by its proponents. In a perfect world, a transactive energy system would have thousands of independent energy actors, from central power plants to dispersedsolarpanels, batteries, smart thermostats and other grid edge assets, all telling each other what their energy needs are and what they’re willing to pay for them.
There are many steps between today’s grid and this vision, of course -- and microgrids serve as a useful stepping stone. By collecting a lot of behind-the-meter assets in a logical way to provide local energy stability, a microgrid is already halfway to becoming a grid asset. Adding distribution grid intelligence and control closes the loop.
“We optimize distributed energy resources to control load on the customer side of the meter, and use the whole customer load as a grid resource for the operator,” Susan Kennedy, CEO of Advanced Microgrid Solutions, said in a Tuesday interview. “The Opus One layer, their grid operating system, optimizes distributed energy resources across the whole feeder, or the grid itself -- or multiple microgrids, within the scope of the operations of the feeder.”
Each of the three projects will use Opus One’s software to interact with the grid, but aside from that, they’re quite different. Emera Maine is combining solar, batteries and backup diesel generators at its Hampden Operations Center, which manages its grid system and its interactions with regional grid operator New England ISO. Nova Scotia Power will manage utility-scale and behind-the-meter residential energy storage to balance vagaries in wind farm generation -- an extension of the work it's done as part of the PowerShift Atlantic project. And Toronto Hydro has been working on a set of microgrid projects to see how distributed energy resources (DERs) can support local grid controls.
AMS has been working with Opus One for about a year now, after searching around for different partners in the distributed energy resource management system (DERMS) field, Kennedy said. “What the utility gets from Opus One is situational awareness, not based on modeling,” as with most of today’s distribution management system platforms, but rather based “on real-time data.”
That adds a new level of functionality to what AMS can do with its own software platform, she noted. Today, the vast majority of its projects are built to serve as a steady source of capacity for utilities, by charging and discharging their core batteries and shifting energy use within buildings for hours at a time.
But with Opus One as a partner, “they can take advantage of something as focused as us controlling the load with a battery behind the meter, and use that as a resource for voltage balancing across an entire circuit,” said Kennedy. It’s a more localized approach to conservation voltage reduction (CVR) systems, which lower voltages to save energy, or potentially balance out over-voltages caused by lots of rooftop solar PV, while keeping each circuit within voltage minimums to ensure power quality.
Emera Maine is AMS’ primary contract in the newly announced trio of projects, she said. The site already has backup generators, given its critical status as the center of operations for its power grid. Adding solar and lithium-ion batteries will allow AMS to start to shape and shift the building’s load curve, with an eye on balancing utility-bill reduction against making money on it.
“Between the battery and the solar, you have the ability to service the load or harness it for the wholesale market. The generators give it resiliency,” she said. At the same time, the utility and Opus One will be monitoring how these changes affect the operations of the grid circuit that feeds it power.
Combining the two sets of real-time data streams and analysis allows local grid needs to become part of the broader economic calculus AMS already performs, Kennedy said -- “Do I need this resource on the site to handle the load, or can I use it in the wholesale market? This obliterates the line between the two.”
Ben Kellison, director of grid research at GTM Research, noted that Opus One’s technology looks a bit like the circuit-level analytics performed by Gridiant, the decades-old software design firm acquired by Toshiba’s Landis+Gyr in 2014, but with a tighter focus to date on individual feeder-level management. Previous work includes Hydro One’s Distributed Energy Management and Storage Network project.