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Watching and Waiting: A Blueprint for Transformer Maintenance

How online monitoring can prevent costly failures.

Fortnightly Magazine - July 2006

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.

Not Getting Any Younger

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.

New Standard

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.

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