Change is hard. Just ask anyone still holding onto a DVD — or worse, a VHS tape — collection.
But sometimes a significant advancement in technology, culture or human knowledge can transform our thinking. And then — sooner for some, later for others — we switch from our old way of doing things to a new and more efficient way.
That, in a nutshell, is what is occurring along the electric distribution grid, where the convergence of stringent environmental regulations, changes in how we consume electricity and a proliferation of alternate energy sources are leading utilities to rethink where and how to power the grid.
Until recently, the approach was largely uniform. Power generation was concentrated in large, coal-fired plants, often operated by local utilities and located far from population centers.
“For more than 100 years, the grid has been the country’s largest continuously operating machine,” says Brad Jensen, an electrical engineer at Burns & McDonnell. “If you added a new customer,
you built a line. If equipment failed, you fixed it. But the system itself remained essentially unchanged.”
But that is changing. Technology and analytics are making the grid smarter and more flexible, and forward-looking providers are looking for ways to modernize their distribution networks to squeeze more value from them, he says.
In recent years, an evolution has begun, transitioning from large-gigawatt, centralized power plants located far from customers to smaller, more localized generation, including networks of rooftop solar panels and other renewables, storage, and smaller power sources that are pooled to meet demand. These distributed energy resources (DERs) are starting to be incorporated with new, more efficient natural gas-fueled peak units that can be ramped up quickly to serve as backup. Sometimes they are conceived as stand-alone microgrids as well.
These physical changes to the electric distribution network signal a larger shift in the energy economy as the industry prepares for, among many other things, the coming age of an electric-based transportation system.
“The electric utility industry's business model needs to change,” Jensen says. “Utilities are moving from providing kilowatt-hours to delivering energy solutions.”
Reinventing the Modern Distribution Network
Reinventing the nation’s massive distribution network to accommodate this new vision won’t be easy, and it won’t be accomplished overnight.
For one thing, the addition of residential solar panels and other DERs means that power distribution will no longer be a one-way street, according to Kory Sandven, a development analyst at Burns & McDonnell. Relays and controls, for example, will need to be modified to interpret changes in power flows caused by the power that DERs send back to the grid.
Sensors with communication capabilities also will need to be added throughout the distribution network to monitor performance, says Meghan Calabro, an electrical engineer and department manager at Burns & McDonnell. “This data will need to be sent back to a centralized brain in real time so operators can make operational tweaks.”
The goal: keeping the grid stable and operating efficiently.
Perhaps an even bigger issue will be seeing that DERs are located where they can provide the most benefit to grid operations and energy costs.
“Today, an affluent neighborhood may have 100 residential customers who can afford to add rooftop solar to their homes. But if the load isn’t sufficient to make use of that much power, DERs can negatively impact the system,” Sandven says.
Meanwhile, nearby low-income neighborhoods that could benefit from DERs cannot afford to finance residential projects.
To better match supply and demand, utilities like Southern California Edison are conducting distribution modeling to identify the best places to install future DER.
“Modeling allows utilities to see both the load and the availability for power generation at any point or any given time,” Sandven says. “These complex models provide the information needed to plan future expansion and design incentive programs that encourage DER construction in less prosperous areas.”
By enabling utilities to measure the real cost of energy at various points in their networks, distribution models give utilities the ability to adjust electric rates based on a customer’s location and time of use, he says. This could eventually lead to privatized localized marginal energy markets, where solar, wind and other DERs compete, and a utility can draw on cost data to determine which generators to turn on at a given time to generate the cleanest power at the lowest cost.
Thinking Even Bigger
Drawing on new technologies that incorporate network data and communications, engineers can have an even more profound impact on long-term performance and energy consumption.
In a demonstration project for Kansas City Power & Light, for example, Burns & McDonnell created a distribution management system and control algorithms that make it possible to pinpoint the location of downed power lines and other faults when they occur. See more details on the SmartGrid Demonstration Project.
“This system automatically reroutes electricity to minimize the percentage of customers experiencing outages while also taking steps to restore power,” Calabro says.
Other algorithms have been designed to manage voltage levels throughout another client’s distribution network.
“If you reduce voltage by 1 or 2 percent, you should reduce energy consumption by a comparable amount,” Jensen says.
That saves individual customers a few pennies every month, which might not seem like much. “But if you apply it across a large utility’s footprint, it saves tens of millions of dollars in energy consumption,” Jensen says. If similar algorithms helped cut the nation’s energy usage by just 1 percent, that would translate into hundreds of millions of dollars of savings, he adds.
The reinvention of the electric distribution grid should not only solve some of the nation’s current energy challenges but also change the nation’s energy economy.
“As the nation shifts from a centralized to a decentralized distribution system, everyone from independent power producers to your next-door neighbor will have the opportunity to participate,” Jensen says. In addition to creating their own power and selling it back to the grid, they also could install new devices in homes and businesses that help control the system.
The end goal? A cleaner, more reliable and more economical energy landscape.
How does one of the nation’s largest power supply companies decide which of the hundreds of renewable energy applications to approve each year?
Until recently, Southern California Edison did what most other utilities did: If a project was small, it got approved.
“It costs more to analyze the impact any one project had on the grid than to make a repair if something went wrong,” says Kory Sandven, a development analyst at Burns & McDonnell.
An integrated capacity analysis being conducted by Burns & McDonnell will change all that. By sifting through millions of data points and modeling thousands of scenarios, the firm is establishing the capacity of every circuit on the utility’s distribution system to determine how the addition of a new rooftop solar panel or other DER would affect it.
When the analysis is complete in 2018, Southern California Edison will use it to determine where to expand to better serve its 14 million customers and provide quick answers to groups that want to get involved. It will be the first utility in the country to analyze capacity systemwide.