The term “smart grid” is getting a lot of use these days, with related stimulus funding reaching into the billions of dollars and the popular press promising Jetsons-like advances; it has been predicted to enable our control of home appliances from our office desktops and allow us to supply electricity back to the grid and to use our plug-in electric vehicles. What this sometimes hyperbolic coverage overlooks, however, are the many small tweaks that will add up to big reliability improvements for the larger transmission system, with fewer and shorter outages and irregularities, in a process that will be more evolutionary than revolutionary.
Popular attention has centered on smart meters, the devices serving as the communications nexus connecting utilities and customers in smart-grid planners’ schemes. It’s understandable the media would gravitate toward a device with which consumers are already familiar, but this approach overlooks the plethora of behind-the-scenes advances required to give these new meters their intelligence and ensure their ongoing functionality.
“So many people are focused on the meter,” said Katherine Hamilton, president of the Washington, D.C.-based GridWise Alliance, a smart grid advocacy organization with a membership made up of utilities, universities, equipment manufacturers and information technology companies. “There’s been a lot of hype that a smart meter is going to enable customers to make decisions, and that’s not right. A smart meter is just a piece of equipment.”
Between that meter and the central generating plant that powers it will be a new generation of sensors and controllers designed to not just report on current operating conditions but, also, to predict and react to those conditions. Consider, for example, a device called a “phasor measurement unit” (PMU). In either stand-alone designs or incorporated into electrical relays or digital-fault recorders, PMUs measure the magnitude and phase angle of the sine waves making up electric current. A radio connection to a global positioning system satellite enables accurate timestamping of all readings. When this synchronization is implemented, units may be called “synchrophasors.”
Basic PMU technology has been around for almost 20 years, and the major interconnections making up the North American grid now have about 200 in place, according to Tyrone Foster, senior marketing manager for the calibration unit of Everett, Wash.-based Fluke Corp. Cost has been a factor limiting wider adoption, but it is dropping along with the general electronics market and as more manufacturers enter the field.
PMUs take measurements 30 times per second, aiding efforts of interconnection operators to isolate potential problems before they can cascade into disasters, such as the August 2003 blackout. This contrasts with the supervisory control and data acquisition (SCADA) systems now overseeing the grid, which make their observations at the outdated rate of once every four seconds.
“That’s equivalent to driving down the road and only opening your eyes every four seconds,” Foster said. “We really need real-time monitoring.”
However, even the currently deployed PMUs lack networking capabilities, a detriment developers are seeking to correct, in one of the many less-publicized efforts to make transmission operations smarter. Included in last year’s stimulus legislation is funding for 850 more PMUs, all networked, enabling simultaneous real-time measurement of line conditions from multiple points across the nation’s major interchanges. This deployment also will help make connections with intermittent resources—such as wind turbines and solar-power systems—more secure, helping system operators understand power irregularities as these renewable generators ramp up and down.
To reach this goal, though, engineers have yet another hurdle to jump—developing a calibration system to ensure these rapid-fire, interconnected devices are all measuring the same thing at the same time. Fluke is combining a $1.4 million stimulus grant with $390,000 of its own funding to develop a methodology for just such a system. But, Foster noted, this is just one of a number of advances needed to help PMUs react to—or, even, predict—-events, not just to monitor them. This hoped-for sophistication will require analytical software and special servers to hold all the data PMUs will be generating.
All this new technology will, of course, require a work force trained to understand a digitally driven transmission and distribution system. With this need in mind, the U.S. Dept. of Energy has announced it will be providing $100 million in training grants, which teams of utilities and educational institutions will use to create required curricula. And, Hamilton added, savvy electrical contractors can take advantage of the opportunity to upgrade their companies’ capabilities in preparation for opportunities that may not even have been identified yet.
“The utilities don’t even know all the job skills that will be needed,” she said. “I think it poses a great opportunity for the electrical contracting stakeholder group—some of those folks who understand digital technology are going to have a leg up.”
ROSS is a freelance writer located in Brewster, Mass. He can be reached at email@example.com.