As utilities grapple with aging infrastructure and outage management, they are evaluating their GIS and considering the best way to keep up with the shifting demands of the electric-power industry...
tag of around $30,000 each, only a limited number can be deployed economically. And that means data which could help operators see that a transformer is on the verge of going down simply isn't available right now. As Gellings says, such gas sensors "need to be about $2,000" each, so that enough can be placed throughout the distribution and transmission system to get at that data, and so allow operators to avoid or limit an outage.
There are some utilities that have already heeded the call for a smarter, more pro-active T&D system. The Bonneville Power Administration (BPA) is often held up as an example for others to emulate.
In the early 1990s, BPA started working with EPRI on a joint collaboration to improve the utility's ability to monitor its vast, far-flung grid that boasts 15,000 miles of power lines spread over 11 states. That project grew into what is known today as WAMS, for Wide Area Measurement System.
WAMS uses a combination of Global Positioning System satellites, portable power system monitors and phaser measurement units to take measurements 30 times per second. The more frequent readings give BPA operators a leg up in isolating disturbances and repairing outages-particularly because it is much easier with WAMS to determine the precise order of events during a disturbance.
Another utility that has made heavy investments in monitoring equipment is Con Edison. According to Ted Maffetone, department manager, distribution engineering, Con Edison's system is "as close to real time as we can get at this point."
One of the distinctive characteristics of Con Edison's network is its use of power line carrier (PLC) communications to aid in collecting monitoring data. Using PLC technology allowed the company to keep the cost of system communications down. "If we tried to do it with telephone lines, it would be very costly," Maffetone explains.
Right now, about 90 percent of Con Edison's 200-plus substations are automated with remote control features, Maffetone says. The company plans on equipping the remainder of its substations by the end of the year.
Con Edison started its automated monitoring project in the 1970s. Maffetone cites two main drivers for doing so: reducing outage times, and reducing labor costs to repair outages.
And the company has largely succeeded in meeting those goals, Maffetone says. "It does save time, and that's money," he observes. The automation project has also given ConEdison some impressive bragging rights: "We're the most reliable system in the country, possibly in the world," Maffetone maintains.
Yet despite the availability of sensor equipment, deploying large quantities of it won't solve or head off problems like the Northeast blackout, or less severe outages. "You need to be able to take the data and do something with it," Gellings says.
Indeed, Maffetone says that data management and storage is one of the biggest challenges to creating a smart distribution system, in particular. "The biggest gap is in computer displays and visualization of data," he says.
Good data visualization, Maffetone says, is one of the most important aspects of the smart grid that CEIDS is working