Reliability demands will drive automation investments.
In the days and weeks following Aug. 14, 2003, politicians scrambled to assess blame for the blackouts that plagued the United States and Canada.
Even today, as the blame game proceeds, the precise cause of the grid's collapse remains uncertain. But Republicans, Democrats, and the utility industry alike seem to agree on one thing: the U.S. power grid needs major investment.
"We need between $50 billion and $100 billion over several years to upgrade the nation's transmission system," said Kurt Yeager, president and CEO of the Electric Power Research Institute (EPRI) in Palo Alto, Calif.
Despite pressures to enhance grid reliability, mobilizing $50 billion to $100 billion for transmission system investment seems like a Herculean task. Faced with regulatory uncertainty and economic malaise, utilities are not well positioned to make such colossal infrastructure investments.
"I suspect I'll have a lot of questions from our clients, saying, 'They want us to invest money in technology to increase reliability, but nobody is giving us the money to do it,'" says Jill Feblowitz, research director with Boston-based AMR Research.
Policy questions aside, the big challenge for the industry in the coming months and years will be figuring out how to improve grid reliability and survivability-without accumulating a Herculean tab.
Weaknesses in the power grid can be narrowed to two general areas-transmission capacity and network control systems. Both of these areas will likely see increased investment in the years to come, but the precise focus of such investments remains to be determined.
Just nine days before the East Coast blackout, EPRI released a report titled Electricity Sector Framework for the Future, resulting from a series of workshops and analyses on the challenges facing the power industry. The report logically emphasized the policy and market barriers that impede the industry's progress, but it also set forth a technological vision-de-force for the power grid.
Specifically, EPRI envisions:
- Digital network control: Real-time, electronic controls would replace the system's existing electromechanical switchgear, enabling faster and more seamless control of the network.
- Integrated power and communications: Merging the power grid with communications networks would create a "dynamic, interactive power system" that would support the real-time exchange of information and power.
- Enhanced meters: Replacing the old metering system with real-time, two-way energy information systems would allow price signals, market information and buyer decisions to flow freely.
- Distributed resources: Incorporating distributed generation sources would improve system reliability and capacity.
- End-use efficiency: Technology advances would raise the efficiency of end-use devices, and improve utilities' ability to control those devices.
Automation comprises the core of EPRI's technology vision. "From our view, the grid has to become more automated," says Luther Dow, director of power delivery and markets at EPRI. "We need to invest more in information technology and new, smarter equipment."
An example of such equipment is FACTS (Flexible AC Transmission Systems) technology, which uses silicon-controlled rectifiers (also called "thyristors")-small, semiconductor-based controllers that can route large power flows much faster than is possible with the electromechanical switches that have dominated the grid's operation for decades. Moreover, embedded processors within the FACTS devices form a distributed computing system that can make coordinated, real-time adjustments to power flows, preventing cascade failures in the event of a transmission overload.
FACTS technology has existed for more than a decade, but few utilities have installed FACTS to date, largely due to the technology's high cost. "We are now working on the third generation of FACTS, to make it smaller, more cost-effective, and faster, using new and different materials," Dow says.
EPRI and others are also developing advanced computer simulation and modeling systems that would help operators to anticipate and assess grid problems and prescribe solutions. "You have to be able to model the system in real time so you can get the data you need to make decisions," Dow says. "Fast simulation is a key part of making the system work."
Indeed, telephone transcriptions released by the House Energy & Commerce Committee revealed that system operators-trying to manage a crisis developing before their eyes-could only guess about the efficacy and possible side effects of the remedies that were available to them on Aug. 14.
"Overall, I can't get a big picture of what's going on," said Don Hunter of the Midwest Independent System Operator (MISO), during a phone call with a First Energy operator. Later, with a Detroit Edison official, Hunter said, "We're kind of taking it as it comes right now. We don't have a lot of information."
EPRI's proposed technology upgrades would provide grid operators with analytic capabilities and real-time controls that, theoretically, could help them prevent a cascade failure like the one that occurred on Aug. 14.
However, as the true causes of the blackout become better understood, the role of advanced information technologies likely will come under close scrutiny. After all, while information systems allowed controllers to recover the system quickly, they also created problems of their own while the blackout was occurring.
"Our computer is giving us fits," said Jerry Snickey, a First Energy operator, during a phone conversation with MISO during the blackout. "We don't even know the status of some of the stuff around us."
First Energy's chairman and CEO, H. Peter Burg, acknowledged during a House Energy and Commerce Committee hearing that the company had problems with its energy management system, which uses SCADA information to provide operators with a view of what's happening on the grid. Further, Joseph L. Welch, chairman of International Transmission Co. in Michigan, testified that communications systems failed to give operators the information they needed during the crisis.
"There were no records or reports of the line outages which were so critical to this event," he said.
If such vital systems can fail to perform at the most important times, the industry might logically be reticent to place its eggs in an even bigger automation basket.
See You in 2025
In fairness, EPRI's framework for the future represents a long-term plan for the power grid, not a short-term fix. "That vision, fully integrated, will take 20 to 25 years to realize," Dow says.
"It is a very big vision. You don't do it all at once."
Implementation would begin on a regional basis, starting with a single control area, for example. But even this incremental approach will take many years. The reason is that much of the technology-particularly the simulation software-doesn't exist yet. Further, an overarching control architecture would present security risks that necessitate especially robust countermeasures.
"In the worst case, computers can be taken over by terrorists and set to confuse the FACTS network to do exactly the wrong thing," says Dr. Bruce McMillin, professor of computer science at the University of Missouri-Rolla. If such problems can be resolved, he says, "we can build and deploy a FACTS network that will be resilient to failure."
Developing such a network may be a worthwhile endeavor, but lawmakers and ratepayers seem likely to demand an immediate solution that keeps the lights burning while the long-term plan develops. Fortunately, short-term solutions might be hiding in the existing hardware.
"With respect to information technology, there is potential that utilities haven't exploited within their own systems," AMR's Feblowitz says. "There are simple things that companies can do to enhance reliability using the technology they have, without investing tens of millions of dollars."
For example, she explains that software vendors already offer tools that analyze data from SCADA systems to identify potential trouble spots. "Also, there may be situations where companies can get greater visibility into the applications that they have, like portal structures with security at each level," she says.
Such portals would allow operators to monitor data coming from tens of thousands of nodes, and to see patterns that might otherwise be invisible. On Aug. 14, "greater visibility across the control areas would have been helpful," she says.
Next time around, such visibility could help operators understand what's happening on a stressed grid, and take appropriate corrective actions before a crisis develops. And only with such understanding can the industry hope to meet the expectations of an increasingly power-hungry and outage-intolerant marketplace.
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