This is the final installment in our five-part series on key trends at the grid edge. It focuses on efforts to create independent, self-managing systems of distributed energy resources behind the point of grid interconnection and looks at how these self-organizing units could serve as building blocks of a DER-optimized energy system in the decades to come.
Click here to read our previous entries on the challenges of integrating DERs on the grid; smart inverters as grid control agents; bridging the divide between DERs and the wholesale market; and breaking new ground for non-wires alternatives.
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As distributed energy resources (DERs) proliferate across the grid, the best way to integrate them may not be from the top down but rather from the bottom up. This isn’t a new idea.
The centralized control systems used by utilities to dispatch power plants and operate grid gear aren’t designed to monitor and manage hundreds of thousands or millions of DERs at the edges of their distribution grids. Given the highly unpredictable nature of customer-owned DERs, the math equations involved can overwhelm a supercomputer.
But there are ways to optimize DERs across buildings, campuses and neighborhoods and get them to work together, whether simply to minimize their destabilizing effects or to yield benefits that could add up to more than the sum of their individual parts.
One obvious example is microgrids, which can operate independently of the grid and sustain themselves when it goes down. Grid-connected DERs can also be organized into virtual power plants or controlled by distributed energy resource management systems to serve grid needs.
But as the DER landscape increases in complexity, so too must the approaches to managing them, says Isaac Maze-Rothstein, grid edge analyst at Wood Mackenzie. These new systems deserve new names, he said — perhaps “fractal grids,” in a nod to the self-similar mathematics of geometric fractals, or “nested grids,” to indicate how small-scale DER aggregations can be nested within ever-larger ones.
These systems will need to not only organize DERs as self-stabilizing grid agents but also allow their owners to retain the economic, environmental or resiliency values that led them to buy the resources in the first place. And because central control isn’t practical, these multiple needs will have to somehow be embedded in the interactions of DERs themselves, he said.
“The premise is creating micro-economies between the different distributed resources,” Maze-Rothstein says. “Individual assets are effectively trading with each other or creating setpoints that allow for those assets to trade amongst each other, without anyone looking at it.”
A game-theory approach to co-optimizing DERs at the micro-scale
That’s how Heila Technologies approaches this challenge. The Somerville, Mass.-based company builds the software behind the microgrids at the Stone Edge Farm winery in California, an all-electric housing project in Basalt, Colorado, at Kirtland Air Force Base outside Albuquerque, New Mexico, and most recently, in solar and battery-equipped houses in a pilot project with AEP’s Southwestern Electric Power Co. (Swepco) in Louisiana.
Heila calls its approach an “organic microgrid” because it can add and subtract many different types of DERs without reconfiguring software and controls. That’s possible because “all the decisions on our platform are being made at each of the edge devices,” said co-founder and CEO Francisco Morocz.
Heila's software is built on game theory. This branch of mathematics — popularized in the dramatization of the life of early innovator John Nash in the Oscar-winning film A Beautiful Mind — involves solving problems involving multiple "players" acting interdependently, with freedom of choice influenced by what every other player chooses to do.
In Heila’s case, the players are DERs whose interdependent operations can either lead to voltage collapse or exploding transformers in the worst case, or smooth and cost-effective optimization of each one’s strengths from moment to moment in the best case.
“It’s a way to getting to an objective, to an optimal situation for the system,” Morocz explains. “You need to make decisions without knowing what all the other agents might do.”
This approach avoids the problem of trying to manage actions that can be excessively expensive or sometimes impossible for central control systems to solve, and improves resiliency against disruption of communications and control links.
It’s also more flexible and scalable than systems designed around central controls, Morocz says. In its upcoming project with Swepco, Heila is partnering with battery provider Simpliphi to enroll each new home’s solar-battery system as it’s built. “What Heila allows is a practical partnership between customers and utilities with distributed assets,” Simpliphi CEO Catherine Von Burg says.
A similar software approach is being taken by U.K.-based Moixa to manage its rapidly growing fleets of solar and battery-equipped homes. Moixa is providing DER flexibility services for U.K. Power Networks and other distribution grid operators. In Japan, it’s orchestrating more than 10,000 residential battery systems that can “technically turn on [approximately] 70 megawatts of power” for grid use, says Moixa CEO Simon Daniel.
Moixa also uses game theory in its software. “We consider multiple factors in the home: the weather, the tariff, the carbon impact, the backup power needs...[to] come up with a battery charging plan that optimizes whatever you need to optimize.”
Whatever broader service a DER might be providing to the grid, it cannot disrupt the homeowner’s need for backup power, solar arbitrage or whatever other services they value most. “Figuring out what those devices need to do as their 'day jobs' gets you a better result” than trying to dictate their operations from the top down, Daniel says.
DER optimization from microgrid to the broader grid
At the same time, the technical capabilities of smart meters, grid communications, smart inverters and DER management systems have expanded dramatically in the past decade, and are “going to grow tremendously in the next few years," says Haresh Kamath, senior program manager at the Electric Power Research Institute.
EPRI's Engage program is working to find ways to help integrate DERs into wholesale energy markets. And the same architecture can be used to provide grid resilience in an emergency, Kamath says.
“Those assets can continue to operate off-grid. They will have grid-forming inverters in the future; they won’t have to follow the grid, they can generate their own signals and communicate with each other, and manage the grid locally.”
Turning standard solar inverters into “grid-forming” inverters requires complex and high-speed communications and control capabilities, but field trials now underway are proving it is possible. For example, the Basalt, Colorado microgrid project orchestrated by Heila’s software has shown that a technology called Real-Time Optimal Power Flow, developed by the U.S. Energy Department’s National Renewable Energy Laboratory, can coordinate inverters with batteries and controllable loads to maintain frequency and voltage needed to keep the microgrid running on its own.
Microgrids orchestrating multiple DERs could become a logical point of connection for utilities seeking to tap their grid values, Kamath noted. “If you have a number of these microgrids adjacent to each other, can you have them link their controls, have them talking to each other, or have some kind of central controls orchestrating them?”
Economic models for DER orchestration as a service
Toronto-based Opus One Solutions has been testing this kind of microgrid-to-utility integration as part of its distribution grid optimization projects with utilities, including National Grid’s distributed system platform pilot in Buffalo, New York and transactive microgrids with Nova Scotia Power and Hydro Ottawa’s MiGen Transactive Grid project.
In Illinois, which is developing a microgrid services tariff to value their mix of resiliency, energy and grid services, Opus One is working with utility Ameren on blockchain and distributed ledger technology to create a “transactive energy marketplace” for its utility microgrid. That could lay the groundwork to “engage a variety of prosumers in the market,” Hari Suthan, Opus One’s chief strategic growth and policy officer, told Greentech Media last year, referring to utility customers that are producing as well as consuming energy.
The term “transactive energy” represents an ideal end state for the kind of peer-to-peer trading of energy and grid services that could emerge from DER integration. To be clear, it’s still an aspiration rather than a reality. The country’s biggest transactive energy pilot project, which ran for about two years in the Pacific Northwest and concluded in 2015, saw some successes but also revealed many challenges in enabling such a concept at a regional scale.
But at a smaller scale, the transactive energy concept may be closer to reality — with applications that could be attractive to utilities as well as microgrid developers. That’s the view of Gary Oppedahl, vice president of emerging technologies at Emera, which owns utilities in Canada, the U.S. and the Caribbean, including several with significant microgrid projects underway.
Its subsidiary Emera Technologies has launched a company called BlockEnergy that’s put the building blocks of a distributed microgrid in a box containing lithium-ion batteries and a control system powered by Heila’s software. Its showcase project at Kirtland Air Force Base has linked multiple residences, a ground-mounted solar array, and buildings and housing facilities operated by the DOE’s Sandia National Laboratories and Photovoltaic Systems Evaluation Lab.
The microgrid broke ground in April 2019, was commissioned in December, and “has run in fully hands-off, autonomous mode ever since,” Oppedahl says. While the base uses a natural-gas-fired generator to provide always-on power, it’s optimizing the output of its solar array to minimize how often the gas generator needs to be run.
BlockEnergy provides the entire mix via a service model. “We’re giving them energy as a service — energy they control, because it’s inside the fences…renewables as a service and resiliency as a service.”
Beyond military bases and other sites looking for reliable power, “our goal is to sell to other utilities," Oppedahl says.
One example of what this could look like is New Mexico utility PNM’s Mesa del Sol, the country’s very first microgrid. Launched in 2012, Mesa del Sol provides a combination of solar and natural-gas-fired power, backed by batteries, to about 150 homes and a mixed-use commercial building near Albuquerque. The solar power helps PNM meet the state’s renewable portfolio standard, while the investment in the infrastructure is part of the utility’s rate base.
That’s an unusual arrangement, driven by the federal grants that helped finance the project. Most state utility regulators aren’t open to utilities rate-basing microgrids, preferring regulatory constructs that open third-party microgrids to earn compensation for the utility benefits they provide, as with Illinois’ microgrid services tariff, or the models being developed in California’s microgrid proceeding.
But if microgrids can provide reliable, low-carbon power to individual neighborhoods at costs that are lower than those of building and maintaining the grid connections to serve them, the cost-benefit equations for utilities and regulators may start to change.
