How Sacramento's electric utility powered up smart-grid data
- By William Jackson
- Dec 16, 2013
In 2009 the Sacramento Municipal Utility District (SMUD), the nation’s sixth largest community-owned electric utility, began a $350 million upgrade of its power distribution system to introduce smart-grid technology from transmission lines to customer meters.
A new Distribution Control Center was opened, a wireless mesh network to support automated metering was built out, more than 600,000 smart meters were installed and an advanced operating system was implemented to support new supervisory control and data acquisition (SCADA) equipment in substations and lines. The improved efficiency and reliability of the system is expected to save from $8 million to $15 million annually in power-supply costs and produce a return on investment in about seven years.
But the utility found that it takes more than automated equipment to make a power grid smart. By 2011 SMUD personnel realized they needed a way to analyze the data being produced and to understand the impact of the new technology being deployed, said Michael Greenhalgh, SMUD’s smart grid project director.
“In the back of our minds, we knew it was coming,” Greenhalgh said of the need to correlate additional data. Sensors in the automated system monitor from three to 10 variables at each point, from transformers to customer meters, and the number of points in the system being monitored quadrupled to about 7.5 million. The utility launched a Situational Awareness and Visual Intelligence program to help make sense of the new grid.
Making sense of the data
“The problem is not that they don’t have the information,” said Steve Ehrlich, a senior vice president at Space-Time Insight, which provides situational awareness tools. “The problem is that they didn’t have any way to use it.”
The company’s Situational Intelligence Server (SI Server) was installed in SMUD’s new control center to correlate data from disparate sources that included technical operational systems, business systems and outside sources such as weather information. It uses geospatial and visual analytics software to produce charts, graphs and reports.
Used initially by SMUD’s operations department, the ability of the SI Server to correlate so many types of historical and real-time data in various formats attracted the attention of other departments, Greenhalgh said. “Once we started showing this off to the rest of the business units, it really took off.”
Background on SMUD
SMUD provides electricity for 1.4 million customers across 900 square miles of California’s Sacramento County. Being community owned, it is sensitive to the need to keep customer rates down and is progressive about the use of technology to improve efficiency. The smart grid upgrade was expected to save the utility — and its customers — from 1 to 3 percent. Not a huge amount, but “it becomes an opportunity to avoid rate cases” for raising electricity rates, Greenhalgh said.
The savings from improved efficiency comes not only in the form of reduced costs but also from avoided expenses. By better understanding and controlling the power flow over the system’s circuits, SMUD expects to reduce peak summer loads by 10.4 megawatts and reduce annual energy use by 36,520 megawatt-hours. This could help the utility avoid major investment in new transmission and generation facilities, saving hundreds of millions in capital costs.
Ironically, the makeover was helped along by the poor economy. SMUD knew it needed to upgrade, but spinning out new technology in a growing utility is difficult to do. When the recession hit in 2008 growth slowed, and in 2009 federal assistance for the project became available under the Recovery and Reinvestment Act.
“It was perfect timing for us,” said Greenhalgh. “The project was shovel ready,” and SMUD received a $127.5 million Department of Energy smart grid infrastructure grant, which covered a little more than a third of the cost of the project. The grant accounted for 58 percent of the DOE smart grid money awarded in California, Greenhalgh said. “We have a very broad implementation.”
From smart meters to electric vehicles
The project began with the installation of smart meters from Landis & Gyr, which SMUD said would “lay the foundation” for the smart grid. The meters allow automatic transmission of data on energy use, providing the utility with real-time data about demand and outages and allowing customers to track and manage their consumption online. In addition to allowing the meters to be read automatically without sending meter readers into the field, they also can enable remote control of household appliances over the Internet. There was an initial test of about 80,000 meters in Sacramento and in some outlying parts of the county. Full deployment began in 2011 and the rollout was complete by April 2012.
Additional components also were being integrated into the system. The advanced operating system allows automatic sectionalizing and restoration of the system, and it can enable the use of capacitor banks to switch voltage to maintain steady levels across the system. This required retrofitting transformers with SCADA software. The utility’s outage management system was upgraded to integrate with these new elements and take advantage of the data being provided. In 2012 SMUD line-maintenance crews were equipped with mobile terminals for the outage management system that provide Web-based access displays of line condition and usage.
SMUD began looking in late 2011 for a tool to help make sense of data being generated by the new smarter technology. At that time there were a number of information management products available, but what made Space-Time Insight attractive was its use of geospatial tools to help correlate information. This lets users see what usage, transmission line and even weather conditions are in different locations, to help plan for and respond to loads and demand.
The SI Server accepts data feeds from existing sensors in the grid, meters and in-SCADA systems. It produces charts, tables and visualizations of both real-time conditions and historical trends. This is the backbone of the distribution operations center, where the data can be displayed on a 30-foot by 8-foot video wall as well as on users’ desktops.
“It doesn’t store any data,” Ehrlich said. The system already has its own storage, which the server can draw on as needed for historical data.
The system provides some data and views out of the box, but it is configured to customers’ specific needs and took about six months to become fully functional. The operators, “the ones who are most interested in keeping the lights on,” were the first users of the system, Greenhalgh said. They are most interested in current conditions rather than trends, but other departments began finding ways to use historical data and analytics to help with planning.
City designers can see what loads on specific transformers are over time to help with neighborhood planning and locating new feeder lines. The maintenance department can use the data to see where work has been done, where it needs to be done next, where crews are in the field at the moment and where they need to be to prepare for current or expected conditions.
The data also is being used to plan for the growth in use of electric vehicles. Demographic data can help determine where owners are likely to live, work and travel so that demand can be anticipated and loads can be balanced.
At this point, grid data management systems still are maturing, but they have the potential to be a robust tool in making systems more efficient, Greenhalgh said. Early adopters such as SMUD are helping to refine the tools for the industry.