Listen to article
6 minutes

This audio is automatically generated. Please let us know if you have any feedback.

Diving certificate:

• Wider deployment of high-resolution sensor capabilities at the edge of the grid and political support for wireless alternatives could significantly reduce the need for costly distribution system upgrades over the next decade, panelists said at a Webinar from 22 August presented by Heatmap Labs and Sense, a grid edge software provider.
• Massachusetts, New York and other markets are rolling out grid-edge sensors and software that can collect data from individual customers in milliseconds, potentially enabling far more effective distribution grid operations, said panelist and Sense CEO Mike Phillips.
• Policies that encourage the deployment of advanced metering infrastructure (AMI) and limit utilities’ financial incentives to invest in physical capacity could help keep customer rates low and mitigate the negative impacts of the energy transition, Phillips said.

Diving insight:

Talk of an infrastructure for modern measurement technology, as if its introduction was still a long way off, is refuted by the actual facts, said Phillips.

National Grid is Install 5,000 Sense-enabled smart meters every week in New York. The goal is to equip the entire customer base in the state with around 1.7 million meters by 2027 and to begin installing an additional 1.3 million Sense-enabled smart meters. in Massachusetts and Rhode Island Beginning of next year.

Sense-enabled measuring devices can be connected to a smartphone app that Perform 1 million voltage measurements per secondwhich, panelists said, provides much better insight into the dynamics at the edge of the grid than traditional smart meters that operate on a 15-minute cycle. For example, high-resolution meter data can show the exact location and time of power flow disruptions. caused by vegetationwhich typically occur on a millisecond timescale, Phillips said.

Xcel Energy expects to complete the installation of smart meters across its seven-state territory next year, said panelist Dave Mino, a Colorado-based manager of distribution system planning and strategy for the investor-owned utility.

Although Xcel’s smart meter inventory operates at a 15-minute metering interval, it will create a library of historical data that will help the utility develop and market customer programs, improve functionality for customers with behind-the-meter solar, expand system operators’ monitoring and control capabilities and enable longer-term forecasting for the distribution system, Mino said.

In collaboration with Kevala, a grid intelligence provider, Xcel is studying how to integrate AMI data into bottom-up forecasts for a range of future load scenarios over the next 30 years, Mino said.

AMI data is an important complement to grid data from other sources that measure power flow at specific points or areas of the grid, such as remote terminal units and monitoring and data acquisition systems, said panelist Mads Almassalkhi, associate professor in the University of Vermont’s Department of Electrical and Biomedical Engineering.

“(The goal is to) use data to make better decisions (and) build better models,” Almassalkhi said. “More data … makes our models better.”

With the increasing use of bidirectional distributed energy resources, SCADA and remote terminal unit data are necessary but no longer sufficient, underscoring the need for high-resolution AMI data, Phillips said.

“We have a lot of resources spread across the system that provide valuable information,” he said. “Once we finally deploy AMI, we’ll be able to leverage a lot more.”

Distribution grid models should be flexible and powerful enough to answer immediate questions, such as “Should I charge this electric vehicle now?” while also solving longer-term puzzles, such as what infrastructure improvements should be made over the next decade, Almassalkhi said.

Phillips compared the evolution from AMI 1.0 to AMI 2.0 and beyond to the evolution of mapping apps that use high-frequency location data from smartphones. An iPhone network that sends location data to Verizon at 15-minute intervals and then to Google at 3-hour intervals “would not be an engaging consumer application and would not give us what we have now, which is real-time traffic information (visibility) supported by edge devices reporting their location,” he said.

Real-time visibility of the distribution grid is a prerequisite for more effective operation of the distribution grid through distributed “levers” such as actuators, motors and power electronics, Almassalkhi said. In Vermont, Green Mountain Power aims to improve grid stability through dynamic management of distributed battery systems, while Vermont Electric Cooperative is using inverters to determine distribution setpoints, he added.

For utilities like Xcel, which is “at an inflection point (in Colorado) for load growth through building and vehicle electrification,” high-resolution visibility of the distribution network will enable more effective capacity investments, including wireless alternatives, Mino said. Xcel’s recent plan for the Colorado distribution network included two calls for tenders for wireless alternativeshe noted.

Better distribution network data could help convince utility regulators that, as electrification increases, larger investments in capital-intensive networks make more sense than costly infrastructure improvements, Phillips said.

“There is a risk of a backlash from the energy transition if it drives up costs for consumers,” he said.