BY Teresa Hansen, Editor in Chief
Power interruptions cost U.S. utility customers some $80 billion annually and nearly a third are caused by equipment failure, a Lawrence Berkeley National Laboratory (LBNL) study, “Understanding the Cost of Power Interruptions to U.S. Electricity Consumers,” found. The utility industry considers equipment failure unavoidable, but new outage-avoidance technology could change that.
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For smaller rural co-ops and municipalities, after-hours power outages can burden small service work forces and create after-hours inconvenience for customer and worker alike.
For large, investor-owned utilities (IOUs) with more employees and sometimes 24-hour manpower, the primary issue is the strategic location of the outage. IOU’s focus primarily on the critical issues of outage duration and the number of customers affected by the outage, which impact public utility commission (PUC) indices of SAIFI (system average interruption frequency index), SAIDI (system average interruption duration index) and MAIFI (momentary average interruption frequency index).
Nevertheless, co-ops, municipalities and large IOUs all would benefit by reducing unplanned outages. In addition to saving customers and utilities money, mitigating power outages improves customer satisfaction, which is especially important for cooperatives and municipalities that typically serve small to midsized communities. Their employees live and work within the communities and are close to customers, said Jeff Pogue, commercial and industrial (C&I) account engineer for Wabash Valley Power Association (WVPA), an Indianapolis-based generation and transmission cooperative that provides wholesale electricity to 28 distribution cooperatives in Indiana, Illinois, Michigan and Missouri.
“Co-ops are very concerned with reliability,” Pogue said. “Making their customers happy is a high priority.”
While many factors could diminish customer satisfaction, power loss is chief among them. The LBNL study, funded by a U.S. Department of Energy (DOE) after August 2003’s blackout in the United States and Canada, also revealed that 32 percent of power outages are caused by vegetation and tree interference, 31 percent by equipment failure, 19 percent by miscellaneous causes and the remaining 18 percent by animals (see Table 1).
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According to the data in Table 1, just more than half of outages can potentially be avoided with proper vegetation management and animal control programs. Currently, most utilities have programs in place for trees and animals, but equipment failure is a different story. Making up 31 percent of all outages and costing customers as much as $22 billion annually, these problems have been deemed unavoidable by most utilities. That’s because there has been no effective way to predict equipment failure prior to a power outage. “Run to failure” is the accepted industry practice–with an emphasis on minimizing outage duration.
Because utilities normally can’t predict equipment failure, they find themselves amid a significant number of unplanned outages–one outage for approximately every two miles of overhead line, according to the LBNL study. However, a new technology may offer an alternative to traditional run-to-failure practices.
More than 90 North American power distribution utilities including IOUs, cooperatives and municipalities have used Exacter Inc.’s outage-avoidance technology since its 2007 introduction, said Exacter CEO John Lauletta. The technology identifies faulty line equipment before failure without false positives, according to field reports based on Exacter surveys of more than 1.5 million overhead distribution poles across more than 50,000 miles of line. It’s the largest utility industry study of failing equipment of its kind, Lauletta said.
The premise of Exacter technology is identifying the precursors of equipment failure.
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“Before a piece of equipment actually fails and causes an outage, it begins to emit a failure signature, an emission, caused by material failure, which results in an arc source,” said Lauletta. “Exacter’s technology locates the equipment that emits these failure signals.”
The real issue currently is how best to apply the technology, said Lauletta. Utility managers and engineers need to ask themselves: How do we want to use the data? Do we want to improve worst performing circuits? Do we want to focus on equipment near strategic substations and feeders? Is our priority a smooth smart grid AMI startup? Or, do we want a systematic way to reduce outages and improve customer satisfaction?
Cooperatives Survey Overhead Equipment
WVPA has provided the technology as a service to its member cooperatives since March 2008.
“We believe the technology and program will help co-ops improve performance, which will make customers happier,” Pogue said.
WVPA management believes improved performance will be important to member cooperatives’ C&I customers and could attract new C&I customers, Pogue said.
“(Improved reliability) will allow WVPA to sell more electricity, and it will also add customers and revenue to the member cooperatives,” he said.
WVPA’s 28 member cooperatives own 42,915 miles of distribution lines. To date, 29,725 miles of distribution lines have been surveyed by 23 members; five cooperatives have not yet surveyed their lines. Four of the remaining five will use WVPA’s Exacter systems. The remaining cooperative purchased its own Exacter system and will begin its deployment soon, Pogue said.
WVPA began the program with two Exacter systems, but that number quickly grew to six.
“Word that these units were available spread like wildfire among the co-ops, and it wasn’t long until we needed more units,” Pogue said. “Everyone who used the units was happy with the performance and data, so the others were anxious to get started, too.”
The system mounts in any moving vehicle and identifies arc source emissions (noise) from transformers and other overhead line equipment as the vehicle drives through an area. There’s no requirement to stop at specific poles or point the system at a transformer to pick up the reading. The technology identifies problems and provides GPS location of arcing equipment.
When a given area is surveyed, Exacter processes the data and identifies failure signatures from the overhead equipment. Effective transformer monitoring requires the company to monitor the transformer and components linked to it, such as lightning arrestors, cutouts and insulators. Should a failure occur with a lightning arrestor, the transformer is left vulnerable.
Participating cooperatives then use other diagnostic technology such as infrared cameras to pinpoint where faulty equipment resides. Personnel usually must to survey only two or three poles in a pinpointed area to identify the faulty component.
For many customers, Exacter provides the system, vehicles and manpower to conduct a turnkey survey. In the case of the WVPA member cooperatives, however, each cooperative provides its own vehicles and drivers, Pogue said.
It takes a cooperative at least five weeks to complete a study. Each circuit or route must be driven over five consecutive weeks. Most cooperatives take six to nine weeks to complete a survey because they cannot cover all of their lines in a week, Pogue said.
“Conducting the survey means that one person and one vehicle cannot be used for other work during at least five weeks, and with most co-ops, longer than that,” he said. “The good thing is that the survey can be performed by retirees, people who have been injured and cannot perform their regular duties or personnel who have extra time.”
All co-ops that used the technology found some faulty equipment on their lines. Some identified major problems and repaired them before equipment failed or caused an unplanned, extended outage. Some repairs required the co-ops to interrupt service, but the outages were planned, managed and shorter than if they were unplanned.
Some co-ops found few problems confirming a well maintained system, Pogue said.
“It gave them a warm and fuzzy feeling, knowing their systems were better than they thought,” he said.
American Municipal Power (AMP)-Ohio Corp. generates, transmits and distributes electricity to 126 member communities in Ohio, Michigan, Pennsylvania and West Virginia. It is making the technology available to its member communities in a program similar to WVPA’s.
“We are trying to help our member communities increase reliability and reduce outages,” said Michelle Palmer, AMP-Ohio’s director of technical services.
In 2005, the American Public Power Association introduced the Reliable Public Power Provider program, also called RP3, to recognize utilities’ efforts to keep the lights on.
“We think by offering this product, we are supporting the program and helping our member communities meet the program’s goals,” Palmer said.
Municipals pride themselves on responding quickly to outages and service interruptions, Palmer said. They don’t like to run their equipment to failure, and they don’t keep track of the worst-performing circuits because they think every circuit should perform well.
“We see the Exacter unit as another tool in the handbag to help our member communities meet their reliability goals,” she said.
Unlike WVPA, AMP uses one Exacter system and offers it at a discounted rate. Palmer said the fee has affected the number of communities that have participated. To date, 14 have used the unit to survey all of their lines and circuits. Some communities have used it more than once. Many that have used it are midsized with about 5,000 customers. Some found significant issues, and others found insignificant issues, but faulty equipment was discovered in all cases, Palmer said.
Portland General Electric (PGE), an IOU with a roughly 4,000-square-mile service territory and 814,000 retail customers, also used the Exacter technology, but not to the extent that WVPA and AMP used it. Because most IOUs have many more miles of distribution system than cooperativess and municipalities, it is not feasible for them to survey all their lines. They, instead, tend to focus on key areas where an outage would disrupt a C&I customer or a large number of residential customers. IOUs typically are more strategic about which lines they survey.
PGE tested the Exacter technology in a 100-mile pilot program. Jim Johnston, a standards and reliability engineer for PGE, said reliability is a top priority for PGE, but the test results were a “mixed bag.”
“We’re always looking for cost-effective new tools that can help us meet customers expectations for reliability,” Johnston said. “However, some of the components that Exacter technology identified as problematic could not be verified in our lab to be defective or faulty.”
Lauletta confirmed that equipment creating arc source emissions in the field sometimes does not arc under laboratory conditions.
PGE employees removed from the system the components Exacter identified as problematic and tested them in the company’s internal lab. In one instance where lab testing verified that a component was faulty and likely to fail, PGE probably avoided a major outage.
“A failure of this component would have taken out a feeder and caused a major disruption, so in this case the technology allowed us to avert a major problem,” Johnston said.
The lab verified another device identified by Exacter technology as problematic and likely to fail, but a failure of the device would not have created a major problem, and Johnston said it would not have been necessary or cost effective to replace it before failure.
“Some components can be run to failure because a failure would not cause a major event,” Johnston said.
The pilot test worked well, according to Johnston, in detecting faulty horizontal post porcelain 115kV insulators which had been problematic for PGE. The technology picked up signals from three of these insulators. PGE technicians removed them from the system and tested them in its internal lab. but results were inconclusive. PGE took the insulators to Bonneville Power Administration’s mechanical testing lab, where two failed above their ultimate rating and one–the noisiest insulator during the test–failed below its ultimate rating. .
The 100-mile pilot was not a large enough sample to determine if the technology would be useful, Johnston said. Another pilot would be helpful, but other system reliability investments have prioirity for funding this year, he said.
“One hundred miles is just a drop in the bucket,” Johnston said. “I would like to do another sampling when we have the opportunity because the first was too small and the results were inconclusive.”
As more utilities use and evaluate this technology, the run-to-failure approach to equipment-induced power outages may no longer be the only solution.