In the just-ended, five-year Pacific Northwest Smart Grid Demonstration Project, Battelle found utilities using automated, electronic signals called "transactive controls" to predict peak power demand and send signals to smart grid devices were able to predict and respond to unexpected events on the grid, Battelle's director of the project Dr Ron Melton told us yesterday. Battelle took over administration of the demo project after some initial drama (SGT, 2009-Aug-28) and tested transactive controls using technology from Alstom and IBM.
The project used an Alstom-designed model that mimicked actual conditions on the grid in the region and a model from IBM of the Pacific Northwest that simulated theoretical grid scenarios, Melton said. The IBM-model tests showed that using transactive DR equipment on 30% of the regional grid could cut the region's peak power demand by about 7.8%, he added.
The transactive controls let utilities "coordinate and control" more accurately. "We were able to verify that the technology works as intended."
The transactive control technology Battelle tested could potentially be used for DR programs, but that would entail regulatory and policy changes, Melton said.
The main problem utilities faced was getting power dispatch signals from transactive technology but not being able to act on the signals using conventional DR programs, he added. But that situation could be changed.
"One area for further development would be, on the policy and regulatory side, to work out the basis for customer engagement as a responsive element of the power system, where they can respond on an event-driven basis, but to more events, or even on a continuous basis based on the demand signal," Melton said.
Transactive technology is not an endgame but a tool for expanding distributed and renewable energy-resource integration on the grid, he added. "It allows one to reveal the flexibility of behind-the-meter assets like water heaters and HVAC systems," Melton said.
Interoperability was an issue reported by utilities taking part in the project, he added. During the project, some utilities complained that integrating technology into the same project would often take much longer than planned, delaying the overall project while two vendors pointed fingers at each other without resolution, Melton said.
However, the situation is "getting better overall" as the technology matures and as vendors gain experience and learn from their challenges integrating technology in the last five years, he added.
Utilities need to identify specific interoperability needs and priorities so that the next set of standards can take them into account and respond to them, Melton said. He is also involved with the Smart Grid Interoperability Panel and the Gridwise Architecture Council.
The progress in interoperability paralleled the development of the Northwest project, and that interoperability issues were associated with technology picked at the start and do not necessarily still exist, he added.
But interoperability issues do persist, as Southern California Edison Advanced Technology Director Doug Kim recently pointed to proprietary technology as an issue that could hinder smart grid development (SGT, March-31).
Working with a large amount of data cropped up as an issue, and vendors should work to ensure they give utilities better tools for handling a much larger and more complex data stream than they may be used to, Melton said.
Generating good quality, usable data from smart grid systems can be fairly difficult, and utilities need to be able to compare data coming from their actual systems to the data that came from modeling or from sensors, so that they can flag data that does not look right, he added.
Larger utilities may have the capability to deal with data issues, whether that's through a larger staff or through a better toolset, but smaller and medium sized utilities will struggle without better vendor assistance, Melton said.
As the demo wraps up, utilities that took part are setting out on their own smart grid projects, Battelle told the press.
Idaho Falls Power will implement a conservation voltage reduction program throughout its distribution grid.
Avista Utilities will install voltage controls and fault-detection technology in its service area and also roll out an AMI program for Washington State customers next year, Battelle said.
Libby, Mont-based Flathead Electric will install 1,000 water heater load-control devices for residential and small business customers over the next five years, it added.
Source: Smart Grid Today
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