According to a guidebook issued by Sandia National Laboratories, a U.S. Department of Energy (DOE) multi-mission laboratory, microgrids are defined as a group of interconnected loads and distributed energy resources (DERs) that act as a single controllable entity. A microgrid can operate in either grid-connected or island mode, which includes some entirely off-grid applications. A microgrid can span multiple properties, generating and storing power at a dedicated/shared location, or it can be contained on one privately owned site. The latter condition, where all generation, storage, and conduction occur on one site, is commonly referred to as “behind-the-meter.”
Microgrids come in a wide variety of sizes. Behind-the-meter installations are growing, especially as entities like hospitals and college campuses are installing their own systems. Where some once served a single residence or building, many now power entire commercial complexes and large housing communities.
“Today, there’s a whole new way to do DER management, which is a significant component of microgrids,” Nick Tumilowicz, director of Product Management for Distributed Energy Management with Itron, said as a guest on The POWER Podcast. “There is a way now to do that in a very local, automated, and cost-effective way just by leveraging what utilities have already deployed—hundreds of thousands of meters and the mesh networks that are communicating with those meters.”
Tumilowicz said a variety of factors can influence if and/or when a microgrid gets deployed. Sometimes, a company is focused on running cleaner and greener operations. Other times, the grid a company is connected to may have reliability challenges that are affecting business adversely, or the company may just want to be energy independent, so the decision is frequently case specific. “The customer has this motivation to have this backup concept known as resiliency—if the grid’s not there for me, I’ll be there for me,” he said.
“Generally speaking, nationally, we’re well above 99.9% grid reliability,” Tumilowicz noted. Yet, even when power outages are rare, a microgrid can still provide value. “It can provide flexible services, such as capacity or resource adequacy, or energy services back to the distribution and the transmission up to the market operator level,” explained Tumilowicz. “So, this is a whole other way to be able to start thinking about how we participate with microgrids when 99-plus percent of the time they’re grid connected, but they’re also there for when the grid is not connected—in that very low probability of time.”
However, the return on investment for microgrid systems is highly affected by location. “If you’re in Australia, the equation is different than if you’re in Hawaii, versus if you’re in the northeast U.S.—one of the better-known accelerated paybacks to do this,” said Tumilowicz. For example, in areas where the market operator, such as an independent system operator or regional transmission organization, places a high value on peak power reductions within its system, the economics for microgrid owners can be greatly improved.
The federal government is also supporting microgrid development. In October, the DOE announced the largest-ever investment in America’s electric grid—$3.46 billion—which represented the first round of project funding under the broader $10.5 billion Grid Resilience and Innovation Partnerships (GRIP) program. Among the projects revealed was a comprehensive smart grid infrastructure update in Georgia, which includes investments in battery storage, local microgrids, and grid reliability, as well as new transmission lines.
Also publicized was a DTE Energy project in Michigan that will deploy adaptive networked microgrids, which have the capability to adapt to changing energy demands and supply conditions in real time, especially after extreme weather events. The microgrids will rely on new grid sensing and fault location devices, and communication tools that will enhance reliability and reduce the number and total duration of outages in the microgrid areas.
But regardless of what may have driven the initial decision to create a microgrid, Tumilowicz said being flexible is important. “You might deploy your microgrid to satisfy three use cases and market mechanisms that exist in the beginning of 2024, but you need to be open and receptive—and this is where the innovation comes in—to add use cases over time, because the system is going through a significant energy transition, and you need to be dynamic and accommodating to do that,” he said.
“One of the ways that we’re doing it here at Itron is through what we call distributed intelligence,” Tumilowicz continued. “So, that’s basically: the infrastructure is there, the DERs are already there, the network is already there, these systems have the ability to locally control and automate those DERs and those microgrids when they’re interconnected and online, and also automatically transition them and isolate them when the grid is not available.”
To hear the full interview with Tumilowicz, which contains more about the benefits of microgrids, how technology is helping manage DER systems, and what leading utilities are doing with microgrids, listen to The POWER Podcast. Click on the SoundCloud player below to listen in your browser now or use the following links to reach the show page on your favorite podcast platform:
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—Aaron Larson is POWER’s executive editor (@AaronL_Power, @POWERmagazine).