Fast growing distributed resources create technical challenges for utilities. Advanced DMS technology promises to help keep local grids balanced.
Demonstrating the Smart Grid
Pilot projects clarify the vision of an intelligent utility system.
four reclosers and a unit substation.
The idea is to use the metering data to establish a clear picture of how one part of the utility’s distribution network is working and leverage the data to enhance overall load management.
“We believe AMI technology can support communications to our distribution automation devices like transformers, switches and re-closers,” explains Glenn Pritchard, principal engineer. “Further, we think the data will help us optimize our distribution network. We may, for example, be able to uncover an overloaded circuit and then reconfigure the circuits in that vicinity to reduce power losses and better handle peak loads.”
The long-term goal, he says, is to move away from the utility’s old approach of using historical data to model system behavior and optimize the network with real-time metering data delivered every half hour.
“The Old City pilot demonstrates what we can do with AMR data. The Jenkintown pilot takes load management one step further by bringing us data from other grid devices too,” Pritchard says. “It’s what I call the convergence of AMI with distribution automation, which is arguably one of the fundamentals of the smart grid. Right now we’re validating smart grid principles by making sure the devices communicate as expected and support our data acquisition requirements.”
Lake Country Power: Smart Wilderness
While PECO’s experiences demonstrate ways to leverage remote access to metering data in a high-density area, the same benefits can be even more valuable in a more widely dispersed service territory–say, less than 100,000 customers spread over nearly 11,000 square miles.
That’s the case at Lake Country Power, which spent nearly five years deploying a full two-way advanced metering infrastructure—including 63,000 new residential and commercial meters—in northern Minnesota.
With an average of only six customers per mile, along roughly 8,000 miles of power lines, the AMI system makes it easier to conduct a range of services—including collect meter data; verify outages and power restoration in real time; check time-of-use readings for an important off-peak electrical heating program; and monitor distribution system performance back to each of 39 substations.
Lake Country, which buys its power from generation and transmission cooperative Great River Energy, offers discounted overnight rates to some 19,000 customers for off-peak electrical heating. These systems use thermal-mass storage systems that charge overnight and release heat throughout the day.
Most of the units are operated by a separate radio and meter combination that activates the heating unit at the appointed time. When a radio relay malfunctions—as roughly two percent do each year—it fails in the on position.
In the past, co-op technicians frequently went from house to house to find and repair faulty receivers, a huge task in a large territory with very few customers per mile. Now the co-op remotely can check the meter’s historical usage data and send a technician directly to homes with unusual load patterns.
“Finding a faulty receiver really was like looking for a needle in a haystack,” says Mike Birkeland, Lake Country’s director of member service. “But it’s important to ensure those devices are working properly. We expect to