Will Solar Crash the Smart Grid?
Utilities don’t have much time to revamp their grids to accommodate the growing popularity of rooftop solar. Here are some technologies that could help.
The proliferation of solar panels will effectively transform commercial districts and neighborhoods into small, localized power plants. While that will allow utilities to cut back on coal, the unpredictable, varying nature of solar power will force grid operators to dispatch or throttle power rapidly. Solar-balancing smart grid systems now confined to pilot projects will need to become common features pretty soon.
“That future is coming, and it’s coming a lot faster than I think many people are aware of,” said Chris Baker, CIO of utility San Diego Gas & Electric. (Execs from SDG&E and other utilities will speak on this and other topics at Greentech Media’s The Networked Grid conference in San Francisco on Nov. 4.)
SDG&E has about 6,600 customers with solar rooftops, he said. While that’s growing by about 60 customers a month, it still only represents about 50 megawatts of generation, or about 1 percent of the utility’s 5,000-megawatt total load. The utility can’t monitor or control it, but there isn’t enough of it to matter that much, he said — yet (see Having Solar Energy System Trouble? Don’t Call Your Utilities).
But what happens when 20 percent or more of the homes in a neighborhood go solar and a cloud passes overhead? That changes a neighborhood of solar power producers to utility power customers in a matter of minutes – and grids built to deliver power one way at constant voltages and frequencies have trouble accommodating that two-way, intermittent flow.
Too much solar power, and local grid voltage could rise, causing potential problems for motors, lights and other equipment. Too little, and voltage can sag. That may only flicker light bulbs at home, but it can lead to million-dollar work stoppages for customers like semiconductor manufacturers and server farms that need clean power at a near-to-constant voltage and frequency.
Energy Secretary Steven Chu has pointed to the challenges of integrating intermittent wind and solar power once it gets to about 20 percent of the capacity of the Bonneville Power Administration, a big, sprawling, power delivery entity rich with reliable hydropower.
What’s the maximum amount that the neighborhood distribution grids of today can take – or, that is, what is the maximum amount that a utility is willing to support?
“We don’t know,” said Matt Wakefield, a senior project manager with the Electric Power Research Institute’s smart grid demonstration program. “Utilities are asking, where do we draw the line… They’re not sure what is the magic point on penetration and how do you manage that issue with [customers] who really want to get the benefits of solar.”
EPRI is tackling the problem in a project with Albuquerque, N.M.-based PNM Resources, aimed at an overarching grid automation system to balance out a neighborhood’s solar power with energy storage and demand response systems, Wakefield said. The Department of Energy gave out $11.8 million in July to five “solar energy grid integration system” projects with similar goals.
“Reality is going to come into play here,” Wakefield said. “We haven’t seen enough of this to see the full effects.”
Solving that problem is the focus of smart grid projects for utilities across the country (see stories here, here and here). Some of them could get a boost from the $3.4 billion in DOE smart grid grants announced last week, though more are awaiting word on a $615 million pool for more experimental projects (see Green Light posts here, here and here).
THE GOLDEN STATE
Take California, which plans to get one-third of its power from renewable sources by 2020 – the most aggressive renewable portfolio standard (RPS) of any state in the country.
The Renewable Energy Transmission Initiative, a group of California regulators and utilities, has said that looking to distributed solar power to meet a large portion of those needs could reduce the number of new transmission lines that will need to be built to carry power from far-off desert solar power plants and mountain wind farms to cities (see California ‘Green’ Transmission Lines Could Cost $15.7B).
But that distributed scenario – which mainly looked at utility-owned rooftop solar – also adds to the costs of that power, the group warned in August. One big uncertainty over its feasibility, the report said, is its “impacts on grid reliability.”
Some California utilities have already pushed back against efforts in the state legislature to expand the 2.5 percent cap on how much customer-owned solar power they’re obliged to credit to customers, though they pointed to extra costs imposed on non-solar customers, rather than grid stability, as their main objection (see Cal Net Metering Bill Stalls).
Right now, PG&E is seeing “some localized issues” with grid instability in neighborhoods where rooftop solar penetration has grown to around 5 percent, said Hal LaFlash, the utility’s director of emerging clean technologies. It’s responded with existing distribution grid systems that are suitable to the task at hand, he said.
But both the Federal Energy Regulatory Commission and the Institute of Electrical and Electronics Engineers, a standards-setting body, have put limits on distributed power sources like solar panels making up more than 15 percent of a distribution substation’s load, he noted.
“We know there’s a lot more coming,” LaFlash said. PG&E is working with various initiatives, including DOE’s Solar Vision Study, to keep abreast of the issue. But a project the utility proposed to pilot technologies to integrate solar panels with smart grid systems in San Jose didn’t receive DOE funding last week, leaving its future up in the air (see Green Light post).
PG&E and other California utilities might have to face a much larger percentage of their power coming from such sources in the near future, according to Edward Cazalet, co-founder of grid energy storage startup MegaWatt Storage Farms.
“The reality is, to achieve 33 percent, most of it is going to be done close to the load,” he said. “We’re just not going to be able to build the transmission fast enough” to bring far-off solar and wind farm power to cities, he said.
Cazalet’s main solution, as befits his company’s name, is lots of energy storage – 4 gigawatts in California to meet its 2020 renewable power goals, to be specific. He’d like state regulators to consider making it mandatory for utilities (see Green Light post).
A lot of that would be big storage, he said. That could include pumped hydro and compressed air energy storage, which EPRI’s Robert Schainker and others say will remain the most economical form of energy storage, as well as large-scale batteries like the one Southern California Edison wants A123 Systems to build to manage wind turbines in the state’s eastern Tehachapi mountains (see SoCal Edison Wants A123’s Biggest Grid Battery Ever).
Other batteries could fit into neighborhoods, where they could balance out rooftop solar sags and surges.