[Editor's Note: If you're interested in learning more about the emerging market for grid-interactive electric water heating, the Peak Load Management Alliance is hosting a webinar from 12:30-1:00 p.m. Eastern time on Thursday, Nov. 21. You can register here.]
Hidden in plain sight in 70,000 Minnesota basements are energy storage devices that collectively pack as much punch as a large power plant and could hold the key to releasing the vast potential of the state’s wind resources. And while they’re at it, they’re evolving from a simple demand response tool into a web-enabled component of a dynamic demand response model.
These devices aren’t particularly smart, either, as smart has come to be defined on the modern electric grid. Rather, they are mundane electric hot water tanks. But that could change in the coming years as nascent efforts to combine smart technologies with a 30-year-old demand response program converge on a most ordinary task—heating water for homes.
Great River Energy (GRE) is a transmission and distribution cooperative in Minnesota that serves its 28 member coops in most of Minnesota. And its demand response model has been pretty traditional—shave the peak and fill the valley—until now.
“We’ve been using water heaters as a demand response strategy for 30 years. The cooperative bought energy at a lower rate during the night and used it for hot water heating,” Gary Connett, GRE's director of member services, told Utility Dive.
GRE's service territory has 70,000 large capacity electric water heaters, each holding between 85 to 120 gallons. Water is heated from 11 p.m. to 7 a.m. off-peak at a lower generation rate than what consumers pay for other electricity usage during daylight hours. Each heater uses about 14 kilowatt-hours. Load control devices shut down the heater during the day, but the extra capacity provides plenty of hot water until the cycle restarts at night.
“It's well over a gigawatt-hour that we are storing every night,” Connett said. The water heaters are effectively acting as a giant battery, with a twist. “Now, we’re going to have dynamic demand response.”
The imperative came with the passage of an aggressive renewable energy standard in Minnesota in 2007, in which utilities must procure 25% of their electricity supply from intermittent renewable resources by 2025, making the water heaters more strategic, Connett said.
Minnesota is in seventh place nationally with about 3,000 MW of installed wind capacity, according to the American Wind Energy Association. “When the wind is blowing and prices are low, we’ll have this distributed battery,” Connett said.
Now, some heaters can be adjusted by radio frequency while many require an on-site visit from GRE. The future, not too far distant, is when the Internet will be used to “talk” to the water heaters. With 80% of customers connected, the water heater can be engaged or disengaged every few seconds, as a two-way dynamic load control.
That means water heaters can play a part in frequency regulation as voltage needs to be smoothed out as demand varies.
Currently, such ancillary services come from a large baseload plant, probably fossil-fuel fired, with perhaps 50 MW of its output reserved for the Independent System Operator (ISO). “Every four to five seconds, the regulator gives orders to ramp up or back down, and with a plant that size, you’re never really caught up,” Connett said.
This is where the thousands of water heaters come in, with each remotely contributing a few kilowatts, scaled up and down every few seconds. The water heaters could potentially act as a near-instantaneous ancillary service and the ISO may actually pay a premium—for energy already in the distribution system.
Utility Sales Manager Steve Koep of Vaughn Thermal Corporation said the electronic controls manufacturer has developed the technologies for when that need arrives. “In the laboratory there are the capabilities to communicate with wireless communication platforms like Zigbee, Bluetooth and others,” he said. “Usually it takes two to five years to get from the concept through the state regulators to wider adoption by utilities."
He doesn’t think the application beyond prototype would take long. And in Minnesota, that may not be too far off.
“Going forward, instead of managing our generation to meet our load, we’re going to start managing load to meet our intermittent resources,” Connett said.
