The march of technology, the urgent call for greater grid investment, and a painful recent past have caught up with the utilities industry.
The history of widespread blackouts remains fresh. This August will mark the third anniversary of the summer 2003 Northeast Blackout, bringing back memories of fear, chaos, and costly fixes. The California energy crisis paralyzed much of the state, and forced a reconsideration of energy industry deregulation.
The causes, we know in hindsight, were myriad, but the threat of blackouts remains, of course. Most threats are localized, but still would be costly to repair, and would be a severe inconvenience for customers.
Transformer failure late last year at an American Electric Power (AEP) substation in Ohio led to a widespread outage affecting approximately 35,000 of the utility’s customers. Preliminary investigations indicated that a three-phase internal fault triggered the incident.
All customers were back in service within 27 hours, but the event “really was a catastrophic failure” according to AEP Ohio spokesperson Doug Flowers. “Scheduled maintenance had taken place on a regular basis since the 1990s. There was no indication this sort of catastrophic failure would occur. Our transformer failure rate is just 0.5 percent over five years.”
After the transformer fire, AEP identified similar vintage equipment in other substations in the Columbus, Ohio, area and did a “thorough inspection” of the equipment in addition to regularly scheduled inspections. “In essence, some of our processes changed,” Flowers said.
One key area of preventative maintenance for utilities is the transformer, many of which are decades old. Representing approximately $200 billion in investment, these units—which currently number approximately 100,000—can’t be replaced overnight.
What keeps larger transformers from failing? One answer: DGA, or dissolved gas analysis. In short, DGA provides utilities with a snapshot of what’s happening in a transformer by studying gases that dissolve in transformer oil.
The Institute of Electrical and Electronics Engineers Inc. recommends once-a-year DGA for large transformers for most applications, but the tool is diagnostic, thereby indicating a problem but not its source. Fixing the problem is another matter, even for those transformers monitored more frequently due to through-faults.
Earlier detection of potential problems is one way to avoid costly fixes later. Adding urgency: An estimated 1,500 large-transformer failures are anticipated in 2006.1 But only now are utilities beginning to re-evaluate their earlier approach to transformer maintenance.
“No question, reticence is an obstacle we have to overcome,” says Bart Tichelman, CEO of Serveron Corp., which offers online monitoring products for transformers.
Backed by an initiative with industry heavyweight Siemens, and buoyed by more than a dozen utilities that have signed on to the new Serveron-backed voluntary standards for transformer maintenance, the company is positioned to capitalize on the industry’s need to take a closer look at its aging infrastructure.
In early May, several utilities agreed to voluntary standards for installing remote monitoring systems on new transformers, and for retrofitting existing units in the field. Serveron’s latest system, the Transformer Monitor Model TM8, works with the new standard to measure the presence of numerous gases that may indicate an impending problem.
“[The new standard] enables [utilities] to stretch their limited capital expenditure, operation, and maintenance budgets while preventing avoidable power outages and their attendant problems,” Tichelman says. Serveron says the constant monitoring of these transformers—which range in price from $1 million to $6 million (and sometimes more)—reveals whether utilities need to shut down, repair, or replace the transformers.
Catastrophic transformer failure is exactly what Lewis Shaw seeks to avoid. Shaw’s choice for Brunswick EMC, an electric co-op in North Carolina, is GE Energy’s Hydran monitoring device, which continuously monitors transformer insulating fluid, dissolved gases, and moisture. “A catastrophic failure would be a nightmare,” says Shaw, manager of engineering at the co-op. “The collateral costs of clean-up and repair are just so prohibitive. Not to mention the cost of transformer replacement.”
More than 20,000 of the company’s Hydran monitoring units are installed worldwide, continuously measuring hydrogen, carbon monoxide, and other key fault gases. Hydro-Quebec has one of the biggest installed bases of the units, while Manitoba Hydro was one of the earliest adopters of the technology. “Some of the largest utilities in the United States also were early adopters, and continue to use this technology,” says Brian Sparling, principal application specialist at GE Energy.
“Normally, these are very reliable machines,” Sparling says. “Some of them last 40 or 50 years. They’re still in service. The failure rate is about 1 to 2 percent per year, so 98 percent of the time, the transformer is behaving normally. But failures are random in nature. You cannot predict when something is going to go wrong. The virtue of our device is you can remotely communicate with it. The engineers can observe how quickly the gases are increasing in real time. That’s the benefit of continuous monitoring.”
The Hydran M2, introduced in the fall of 2003, added the ability to measure moisture and other critical signals to the Hydran line. If the transformer is wet, the Hydran M2 takes the various sensory inputs and computes the information, alerting the maintenance engineers that the unit needs to be dried out.
“Moisture inside the tank is the worst enemy of the transformer,” Sparling says. “Oil only holds 1 percent of the total water inside the tank. Ninety-nine percent of the moisture is held inside the solid insulation, which is essentially paper. That’s the killer of the transformer. If that gets excessively wet, the aging rate [of the transformer] increases exponentially, so your transformer isn’t going to ‘live’ as long. It also can lead to something no dissolved combustible gas detector will pick up: ‘bubbling,’ where moisture bubbles off the vapor insulation on the conductors of the transformer. That will lead to an immediate failure.”
Although the new Serveron standard is voluntary, it’s already being implemented at Arizona Public Service (APS). “[The new standard] gives us better transformer condition knowledge than previous methods, and the technology and software are reliable,” says Jan Bennett, APS vice president of customer service. The company is a long-term customer of Serveron’s, incorporating its technology as early as the summer of 2002.
“A number of major IOUs here in the United States” also have adapted Serveron’s engineering standards, said Serveron’s vice president of marketing, Steve Jennings, but as of press time, only APS was willing to go on the record.
In related news, Siemens Power Transmission and Distribution is rolling out an asset-management system that includes Serveron technology, while Siemens Venture Capital gave the technology a vote of confidence by participating in a recent round of Serveron fundraising. “We see [online monitoring] as an obvious and necessary way to increase utility grid reliability while reducing maintenance costs and deferring capital expenditures,” says Todd Jaquez-Fissori, an investment partner with Siemens Venture Capital.
Other venture investors include Perseus 2000 LLC—currently the largest investor—Ventures West Management LLC, El Dorado Investment Co., Nth Power LLC, Cascadia Pacific Management, and Oregon Life Sciences LLC.
1. Serveron estimates.