Just a few years ago, microgrids were simple.  A diesel generator sat for long periods until a facility manager manually disconnected the site from the grid.  The generator ran until the power came back on or the fuel supply ran out.  All in all, managers faced a limited number of decisions when it came to managing a microgrid.

Now, microgrids are much more complicated.  They often have multiple generation sources, battery storage systems, controllable energy consumption devices and have live connections to the grid. It has become essential for microgrids to be intuitive when it comes to knowing what to do and when.  This helps ensure the best outcome for the lowest cost.

Here is where optimization comes in. Granted, some think optimization is a buzzword, created to sound impressive without any specificity. The fact is understanding the values of various types of optimization helps ensure microgrid owners meet their goals. Optimization automates the best results for a system, considering its site-specific limitations. Optimization is made up primarily of four core concepts:

1. Objective function: It defines the objective of the solution. For example, the objective could be to minimize the cost for supplying load. How the control variables influence that cost must be known
2. Control Variables: These are the levers you can use to achieve your objective. For microgrid operations, typical control variables are power output of generating/storage units or load connection statuses, etc.
3. Constraints: Constraints address the laws of physics such as generation output cannot be outside of the operating range of the generating unit or the load must exactly match the generation
4. Model: The optimization works on a model, where the model defines number of entities (DERs) participating in the optimization, the constraints, the relationship of the control variables to the objective function etc.

A technique that strictly adheres to these principles and method of solving a problem is referred to as “optimization”. The optimization “engine” finds the optimal values for the control variables that result in achieving the objective while respecting the constraints.

Here are some good starting points for anyone interested in optimizing a new microgrid project.

Solar energy has gained traction in the energy market, altering the load profiles that utilities have to satisfy. This is forcing them to adapt and evolve. Increasing solar generation in the afternoon is offsetting the high demand during those hours. Load continues to surge into the evening when solar generation is no longer available, exacerbating the rise.

Utilities are changing their pricing structures to cope with these variations, which is where storage comes into play. As peak price hours shift later into the day, when solar generation is unavailable, storage can be used to capitalize on the potential benefits. We’re entering a more sophisticated utility environment that no longer rewards solar only installations; adding storage is becoming necessary to make microgrids more economically viable.

It would be naive to believe that utilities will not continue making adjustments in the future. They will endeavor to stay ahead of the renewables curve, and customers are getting smarter about gaining an economic advantage from the utility rates. Using intelligent controls rather than scheduled controls is one way to achieve this. With ‘set it and forget it’ scheduled controls, a battery is set to charge before the known high rate time period, and set to discharge during that expensive period. When the utility changes that window, those settings have to be changed on every microgrid, or economic opportunities will be missed.

Self-modifying intelligent controls
Intelligent controls, on the other hand, modify themselves under changing conditions. The controls can allocate energy, or decide when to discharge the battery and by how much, in response to changes in the utility rate structure. Thresholds can be automatically altered based on assessments of demand changes, and the system can respond to live weather data, for example carefully managing the energy stored in a battery if an increase in cloud cover is predicted.

At CleanSpark, intelligent controls are applied for an off-grid microgrid in the deserts of California. The goal is to minimize the use of the rented diesel generator, to reduce cost. The facility is in the growth phase, so the site has been modeled to understand the most appropriate sizes for future diesel generation, solar and storage. Real time controls balance the load, solar, and storage to reduce the running of the generator. As a result, the generator did not run during the second half of August, saving an enormous amount of money.

A new European project, TIGON, will develop technology and demonstrate how direct current (DC) microgrids can help the European Union’s (EU) electricity grids become greener, more efficient and resilient.

The project involves 15 partners from eight different European Member States. The EU’s Horizon 2020 research and innovation program is providing part funding for the $9.4 million (US) project, which fits into the EU’s wider plans for building a low carbon and climate resilient future.

Most grids operate on alternating current (AC), but the attractiveness of DC is increasing. This is due to the proliferation of renewable energy, most of which generate a DC output, as well as the increase in DC loads from modern electrical equipment like laptops, electric vehicles, and LED lighting.

As such, project TIGON aims to demonstrate deployment of DC-based grid architectures within the current energy system, with the ability to provide ancillary services to the main network.

“In a classic approach, the electric grid is AC because it is easier to change the voltage level with power transformers; this is a useful feature,” Jesús Muñoz, TIGON project coordinator and power electronics engineer at Spanish research center Fundación CIRCE, told Microgrid Knowledge.

“If you want to connect to DC devices, it is cumbersome because you have to convert firstly to AC and afterwards back to DC.”

Developing direct current microgrid solutions

Over the four years of the project, the international team will develop new software and hardware solutions to enable local DC infrastructure to better integrate renewables and store electricity. Two microgrids in France and Spain will be used to demonstrate the solutions, with the findings subsequently applied at two sites in Finland and Bulgaria to test replicability.

When the switch is flipped on the Redwood Coast Airport Renewable Energy Microgrid, it will become the first multi-customer microgrid in Northern California and one of only a handful active in the US.

This inventive project aims to be a model for creating resilient communities, but should it be successful some of its more innovative features, as well as numerous roadblocks and archaic regulations, may make replicating this microgrid in the future unnecessarily difficult.

Traditional microgrids — typically a single building or contained campus — are becoming more commonplace. But the gradual rise of multi-customer microgrid projects further blurs the line of where electricity customers end and the utility begins, challenging traditional roles and regulatory responsibilities.

More than the sum
Implemented as a technology demonstration project, the ratepayer-funded microgrid in Humboldt County is part of California’s EPIC program to “accelerate the transformation of the electricity sector to meet the state’s energy and climate goals.”

The Redwood Coast renewable microgrid stretches over seven acres, connects multiple non-adjacent customers, and has both utility-side and behind-the-meter components, making it a unique endeavor even among microgrids. The anchor tenants are the regional airport and a US Coast Guard air station. A handful of surrounding commercial customers are also connected into the system.

The microgrid includes a solar farm with 2 MW of grid-tied capacity that can participate in competitive markets and 250 kW of net-metered capacity that will power the airport. Redwood Coast Energy Authority (RCEA) will own and operate the solar facility and maintain a 2 MW/8 MWh battery energy storage system and dynamic EV charging infrastructure that can participate in demand response programs.

The local utility, Pacific Gas & Electric (PG&E), will own and operate the microgrid circuitry and equipment, and oversee operations of the microgrid in island mode when the regional grid is inoperable or the utility implements a public safety power shutoff. This is one of a few EPIC-funded microgrids by PG&E and the state’s other investor-owned utilities that will come online in the coming months.

To understand the movement of the microgrid industry, its instructive to watch it’s large players, particularly, right now, Schneider Electric. The company has been navigating the industry’s tributaries for the last five years and seems to be signaling it sees an ocean ahead.

The signal came in the form of Schneider’s mid-August announcement of a new company it has formed with Huck Capital, a San Francisco-based private equity firm focused on clean energy. What’s noteworthy is the partnership’s customer base. It’s targeting microgrids for small to medium-sized buildings, those with an electrical load under 5 MW. Schneider has identified this as a massive market, representing 90% of buildings in the US and Canada.

Pursuing this customer base marks a demarcation from Schneider’s Alphastruxure play, a company it launched last year with the Carlyle Group to bring microgrids to airports, ports and other large infrastructure projects, such as the John F. Kennedy airport modernization. Where Alphastruxure pursues the big and few, the new company wants to serve many.

So with the formation of the new company, yet to be named, Schneider suggests that it sees a big expansion in the pool of likely microgrid candidates. Not so long ago that pool was much smaller, limited mostly to campuses and military bases.

To be clear, Schneider is not the only company going after the small-to-medium building market. Many others, particularly smaller niche players or those with specialized technologies, have been installing microgrids within this size scape, among them Bloom Energy, Enchanted Rock and Powersecure.

Renewables first
But the move by Schneider is significant because of the company’s size and market clout — Schneider has 135,000 employees worldwide and annual revenue of over $27 billion. The company has used its sizable resources to both navigate its way through the microgrid market and nudge it forward.

The U.S. microgrid market is growing, with a record 546 microgrids installed during 2019. Most of those projects were below 5 megawatts. This is a continuation of the trend starting in 2017: The number of smaller, more modular projects has consistently grown each year.

As the market has grown, it has also attracted increasingly diverse financiers, according to a new Wood Mackenzie report.

As costs have gone down, investor interest has gone up

Increasing system standardization and the declining costs of energy resources have reduced development costs and boosted the growth of small microgrids.

Standardized systems remove the need for custom builds, so less time is required for construction. That’s also made it easier for financiers to evaluate multiple projects: Due-diligence costs are lower for a portfolio of locations that run similar technologies and have the same business model as opposed to a portfolio comprising multiple customized systems with different business models.

The investor landscape is diverse and will continue to expand

An increasingly broad array of financiers with patient capital are investing in U.S. microgrids, ranging from investor-owned utilities to private equity groups. In the next two years, WoodMac forecasts that more private equity players will enter the market, especially those with experience in infrastructure and oil and gas. Many of these firms are looking for above-market returns with levels of stability comparable to those historically associated with infrastructure investments.

The City of Houston will provide electrical resiliency services to its Northeast Water Purification Plant (NEWPP) Expansion facility with a natural gas-fueled resiliency microgrid. The solution will provide facility backup for 100% of the required finished water production capacity during outages.

The solution also enables the city to fully comply with the regulatory requirements specified by the Texas Commission on Environmental Quality (TCEQ) for water treatment facilities and provide greater operational reliability during maintenance and grid outage periods. The new facility, which will service fast-growing Harris and Fort Bend counties, is scheduled for completion in Spring 2022.

“The NEWPP project will add 320 million gallons per day by 2024 to the existing water plant’s capacity,” said Ravi Kaleyatodi, P.E., Project Director, NEWPP Expansion Project, at City of Houston. The city selected Enchanted Rock, a Texas-based distributed energy company, for this project.

“Wood Mackenzie reviewed 3,389 planned and operational microgrid projects that we track in the United States, and we determined this project will be the largest microgrid in the country supporting a water pumping plant when it comes online in 2022,” said Isaac Maze-Rothstein, Research Analyst at Wood Mackenzie.

Microgrids are impressive on their own, but what if they could work together? What if they could communicate and share resources via market participation— automatically with no human intervention —to achieve even greater efficiencies than they accomplish alone? In fact, what if the electric grid eventually became a grid of self-supporting, super smart and highly predictable microgrids?

It may sound futuristic, but the idea of clustering microgrids is already being explored on the southside of Chicago in a partnership that includes Siemens, a technical college and a local utility.

Known as the Bronzeville Microgrid, the project will pair a microgrid already in operation at the Illinois Institute of Technology (IIT) with a microgrid being developed by Commonwealth Edison (ComEd) for the Bronzeville community.

With $5 million in grant funding from the U.S. Department of Energy, the $25 million project is the first utility-operated microgrid cluster being developed in the nation.

Spurred by Bronzeville community members eager to make their backyard a showcase for clean technology, the project will demonstrate how microgrids support the integration of renewable energy into the grid, enhance grid security, and keep power flowing during emergencies. The Bronzeville community will use its microgrid to ensure reliable energy for 10 facilities that provide critical services, including the Chicago Public Safety Headquarters, the De La Salle Institute and the Math & Science Academy, a library, public works buildings, restaurants, health clinics, public transportation, educational facilities and churches.

“The Bronzeville community is well-known for innovation and entrepreneurship and commitment to building a bright future,” said Paula Robinson, president of the Bronzeville Community Development Partnership. “A secure energy infrastructure and greater access to renewable sources are central to our vision…. It’s time to put this technology to the test, and Bronzeville is the perfect place to do it.”

After catastrophic wildfires in 2017 and 2018 had devastated the transmission lines owned by PG&E Corp., it was forced to declare bankruptcy. And the fallout from that has been a move to localize both the supply and delivery of electricity — power to come from green energy and to be sent using microgrids.

Microgrids are set up for several reasons that include increasing a region’s resiliency — or its ability to maintain power as well as incorporating more renewable energy to cut down on CO2 releases. And they can be set up in remote locations that have no access to the centralized grid, thus creating more economic opportunities. But in the case of PG&E, it is looking to such localized delivery systems as a way to battle wildfires and to avoid wholesale blackouts.

“In the last decade, renewable energy sources have been transforming the microgrid landscape, consequently reducing or even eliminating the need for costly fossil fuels. This has been made possible through the use of hydrogen,” says Thomas Chrometzka, a strategist with Enapter, which makes electrolyzers — a device used to split apart the hydrogen and oxygen from water. “Introducing hydrogen to microgrids solves the problem of seasonal or long-term storage that batteries cannot provide. It is the crucial jigsaw piece for 100% green microgrids.”

After catastrophic wildfires in 2017 and 2018 had devastated the transmission lines owned by PG&E Corp., it was forced to declare bankruptcy. And the fallout from that has been a move to localize both the supply and delivery of electricity — power to come from green energy and to be sent using microgrids.

Microgrids are set up for several reasons that include increasing a region’s resiliency — or its ability to maintain power as well as incorporating more renewable energy to cut down on CO2 releases. And they can be set up in remote locations that have no access to the centralized grid, thus creating more economic opportunities. But in the case of PG&E, it is looking to such localized delivery systems as a way to battle wildfires and to avoid wholesale blackouts.

“In the last decade, renewable energy sources have been transforming the microgrid landscape, consequently reducing or even eliminating the need for costly fossil fuels. This has been made possible through the use of hydrogen,” says Thomas Chrometzka, a strategist with Enapter, which makes electrolyzers — a device used to split apart the hydrogen and oxygen from water. “Introducing hydrogen to microgrids solves the problem of seasonal or long-term storage that batteries cannot provide. It is the crucial jigsaw piece for 100% green microgrids.”