Technology Corridor
Has the Aug. 14 blackout finally made it more than a pipe dream?
Former Secretary of Energy Bill Richardson ticked off a whole lot of people in the industry when he pronounced the United States a superpower with "a Third World electricity grid."
Yet while debate continues about the causes of the Northeast blackout, there's no arguing that the majority of transmission and distribution in this country is controlled via mechanical technology largely developed in the 1950s.
To many outside the electricity industry, using 50 year-old technology to distribute vital electricity sounds ludicrous. After all, the telecommunications industry made the switch from analog to digital networks in the 1990s, creating smart systems that can handle many system malfunctions without human intervention.
In the wake of the Northeast blackout, the idea of a similar, or even better, update of grid technology has gained new currency. And that's something that makes Clark Gellings, vice president of the Electricity Innovation Institute (E2I), pretty happy.
Gellings and his colleagues have been pushing the industry to move toward a smart, self-healing grid for the last couple years (see Figure 1). E2I, along with the Electric Power Research Institute, with which it is affiliated, formed the Consortium for Electric Infrastructure to Support a Digital Society (CEIDS) in May 2001, to provide a strategic framework for upgrading the electricity systems, particularly the transmission and distribution system.
CEIDS was born at the tail end of the dot-conomy boom, driven by concern that an industry responsible for rolling blackouts in tech-heavy California was ill-prepared to serve a burgeoning digital economy. Indeed, experts peg the cost to the U.S. business sector for power outages and power quality disturbances at somewhere between $119 billion and $188 billion annually (see Figure 2, p. 55)-and that doesn't count the costs to utilities to recover from outages.
But what exactly is a smart grid?
First and foremost, says Gellings, a smart grid is a true real-time system that collects a great deal of information on the state of the grid, and is able to take that data and do something with it, dynamically.
"People say that what we have now is real time, but it isn't," Gellings says. He points out that seconds go by before grid status information is updated on current systems. "That's not good enough," he argues. And often, the time stamps on various systems are not correct, as the blackout investigators have found.
Even if the time stamps are correct, to create the CEIDS vision, the grid needs more sensors that are integrated with a communications system. That way, Gellings says, operators can look at more points more quickly on the grid.
While some newly released sensors are rather inexpensive, and can perform some useful measurements on current power system conditions, Gellings faults them for their lack of time-stamp information.
Currently, there are some sensors that work fast enough and have the right time stamps to satisfy Gellings, but the cost can be prohibitive, he says. For example, transformer gas sensor systems do the job, but with a price 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 on. "We need to determine information at a glance," he says. Depicting data well means that operators can make a decision more quickly, rather than needing first to analyze the data and wasting precious minutes doing that rather than deciding how to handle a growing disturbance.
As Gellings says, "It's a computational ability that we really don't have now."
In fact, E2I just released a request for proposal in September, to develop some of those computational abilities. Yet even assuming that E2I can figure that out-and Gellings expects that they're only a few years away from doing so-the single biggest problem with creating the smart grid isn't technology. It's money.
Many estimates put the total for upgrading the grid at around $100 billion, which sure sounds like a lot of cash the industry simply does not have. Yet on a macro level, that is the cost of a single year's worth of outages to American business. And, of course, there is the inconvenience to consumers, 50 million of whom received a memorable shock on Aug. 14.
The blackout may prove a blessing in disguise for the industry, by focusing public attention and political pressure on the transmission system. There is even a chance that the blackout could galvanize Congress into actions that would either make or encourage transmission investment that has not been made in the last 20 years.
Perhaps Ralph Cavanagh, director of the energy program at the Natural Resources Defense Council, and former Clinton Energy Department official, put it best when he told the Washington Post, "This is the moment when the electricity industry will either make a credible showing of openness to new technology, or it will sink back into the quagmire of new transmission-line battles."
Are we ready for the life raft?
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