By Steve Blankinship,
The power failure that occurred August 14th, affecting an estimated 50 million persons in the U.S. and large regions of Ontario, Canada, appears to have been caused primarily by deficiencies in the transmission grid rather than generation inadequacies. Nonetheless, there will likely be implications for the generation side of the power industry.
“You can’t separate T&D from generation because they support each other,” notes Bill Closser, director of business development for EPRIsolutions. “Stress on the generating facilities can lead to stress on the T&D system and vice-versa. The assets must be considered together if we are to deliver power effectively.”
Although all particulars of what happened are yet to be determined, Closser notes that a number of power plants along Lake Erie were off line when the failure occurred. “At least four Canadian nuclear units at the Pickering plant on Lake Erie were off line, and in the U.S. Davis Besse nuclear station was off at the time due to regulatory issues,” he says. “That area around Lake Erie is pretty well connected, but because it is a high user of energy, a lot of power was being imported from outside. As a result, parts of the system were heavily loaded. Without a good spinning margin, you don’t have enough reserve margin to ride out a disturbance.”
Because few utilities operate today at the spinning reserve levels once thought prudent, Closser believes there is a real need to look at where plant protection parameters are set to assure they can ride out such disturbances on the grid. When a plant trips off line, it sets up a disturbance around the system. If part of the grid is already taxed, with large amounts of power being moved from one area to another to keep everyone supplied – which appears to have happened on August 14 – the transmission system can be stretched, especially if some of it is as much as 50 years old. “If the plant protection systems aren’t set up right or haven’t been examined and adjusted to meet the current requirements of the transmission system you end up dropping more plants,” says Closser.
Another area of increased concern is power plant switchyards, and EPRIsolutions is currently engaged in a substantial amount of plant switchyard assessment work. “Much of the impetus is coming from the Nuclear Regulatory Commission (NRC),” says Closser. “The NRC is requiring all nuclear plants to carefully examine maintenance on their switchyards because, if you lose a major piece of equipment in the plant due to a malfunction in the switchyard you can shut a plant down. Obviously, trips of such large units can have catastrophic impact on the grid and its customers.”
As of late, the NRC has been pushing utilities to maintain nuclear plant switchyards at the same levels that the plants are maintained. “In the past there was a line drawn where you came off the iso-phase bus from the turbine,” says Closser. “The equipment behind the line was the plant’s responsibility; after that the equipment belonged to the transmission company.” He believes that could be changing for more than just nuclear plants. “There is a tendency for what has worked at the nuclear plants to eventually move over to the fossil side.”
Effects of the August 14 blackout could be observed from space, as in this photo provided bythe National Oceanic and Atmospheric Administration.
The August 14th blackout has also drawn increased attention to distributed generation and the role it can play in assuring energy continuity in the event of grid failure. Dennis Orwig, CEO of Encorp, which provides services and technology for the control and networking of distributed energy, believes U.S. reliance on central power plants and a vulnerable national grid system has led to failure. Once a strong advocate for large centralized power plants, he now believes distributed cogeneration is the answer to many problems.
“Distributed on-site power plants are a more dependable, cost effective and environmentally friendly way to produce electric and thermal power,” says Orwig. “These plants can be used for baseload, peaking or backup.” The immediate solution, he says, is gas-fired reciprocating engines providing both heat and power.
But Steven Taub of Cambridge Energy Research Associates believes heightened interest in distributed generation resulting from the blackout will not be sustainable. “The burst of consumer and business demand for distributed generation will be short-lived, much like the response to the California electricity crisis was in 2000-2001,” says Taub. “It’s a lot like what happens after an earthquake or a big storm. Initially, there’s a lot of interest; people go out and start talking to architects and engineers about these systems. Then, when people learn more about it and the costs involved, some of the interest fades. As time passes, and things get back to normal, they get lulled into a false sense of security.”
Taub notes that, generally speaking, the grid remains more reliable than any single generator. The most sensible thing to do, he believes, is to have central and distributed power plants.
The latest blackout could also lead to greater scrutiny of energy storage technologies, which can inject large quantities of power into the grid to assist in recovering from outages or stabilizing the grid prior to failure. Although some of these technologies are well-proven and relatively widespread, such as pumped storage and thermal storage, others are just gaining commercial traction (Power Engineering, Nov. 2002).
Outage events may provide some unique support for energy storage. During a panel session on the blackout at the IEEE/PES conference in Dallas in September, Carson Taylor, Principal Engineer with the Bonneville Power Administration, described the August 1996 Western U.S. outage in which 30 GW of load tripped off-line. Based on his analysis, Carson is convinced that many generators in no danger of damage tripped off-line, exacerbating the outage. If generation owners like these are unwilling, because of liability concerns, to relax their units’ trip points to cope with future disturbances, greater availability of energy storage solutions could aid in managing future outage situations.
It is still too early to tell how much help energy storage would have been in alleviating this year’s blackout. “I don’t think anyone could argue that it wouldn’t have helped,” said Jason Makansi, Executive Director of the Energy Storage Council. “At the distribution level, high energy flywheels could have responded to frequency fluctuations much faster than traditional responses. For example, PJM holds 1.1 percent of generation for frequency regulation, but response is on the order of minutes. Flywheels and other storage devices at the distribution level can respond in seconds.” On a larger scale, one storage expert has told Makansi that a 600 MW compressed air energy storage (CAES) plant would have stopped the outage dead in its tracks.
The August 14 blackout will undoubtedly bring into focus how perspectives on the blackout differ among utilities, regulators, vendors and customers. “The higher appreciation for the ‘reliability link’ between generation and transmission will drive interest in storage as a way of bridging any gaps,” said Makansi. “And the longer it takes the grid operators – utilities and RTOs – to get their act together, the faster will be the movement to on-site and distributed solutions. Customers with critical load are not going to wait for the next big one to occur.”
Energy storage may be more attractive to utilities than distributed generation because it can actually result in increased sales, but it still faces opposition. “Although utility acceptance is more likely than for distributed generation, the emerging energy storage technologies are not well understood and most are still too expensive,” said Timothy Hennessy, CEO of VRB Power Systems, whose vanadium redox battery system technology is going live at utility installations in Utah and Australia this year. “A true mind-shift in planning is needed. Utilities, by definition, are not meant to test new technologies out in large scale. They use proven products, so we do face a battle on that front. Government mandates would be helpful, but until energy storage is cost-effective, that amounts to bad business practice and I would never advocate it.”
An approach Hennessy favors is a mandated load factor that each utility must achieve. The required load factor would be ramped up each year. Such an approach would force utilities into using energy storage and improve on asset returns – fewer lines, better loaded, with fewer losses.
PacifiCorp, which is installing a 250 kW x 8-hour VRB system in a rural area in southeast Utah in order to defer a more expensive substation and transmission line project, sees a bright future for energy storage. “Energy storage has an important role to play in mitigating power outages,” said Brad Williams, PacifiCorp’s Director of Asset Management. “In the right applications, its ability to provide voltage, VARs and real power support can offer better benefits than traditional solutions.”
In the near-term, Williams expects greater investment and rollout of energy storage solutions, but not by utilities. Outside entities, vendors and other interveners will likely lead the effort. “In the long term, the potential is tremendous,” he said, “particularly if energy storage can successfully be integrated with wind and solar. And fifty years down the line, if distributed generation becomes economic and fuel cells are in every backyard, the utility’s role will be to maintain frequency and voltage and provide peaking power, much of it with energy storage technologies.”