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7:35 pm
February 9, 2017
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Manage Transformer Failure Risks

The aging transformer population and higher-than-expected failure rate of newer replacement units are two factors driving a unification of strategy in the maintenance of these critical assets.

The aging transformer population and higher-than-expected failure rate of newer replacement units are two factors driving a unification of strategy in the maintenance of these critical assets.

Keeping transformers healthy is key to electrical-system reliability.

By Jane Alexander, Managing Editor

Getting transformer experts to agree can be especially difficult, according to Alan M. Ross of Tallmadge, OH-based S.D. Myers Inc. (sdmyers.com). On some points, however, they sing the same song:

• Most will acknowledge that not all transformer failures are alike.

• They’ll also agree that the insulation or paper is the primary limiting factor in transformer life.

Although industrial operations typically use power to produce something of value, risks associated with the loss of that power can be misunderstood and, frequently, ignored. Risk, though, comes in many different forms.

In the case of transformers, the insurance industry typically quantifies the risk of failure as the cost to replace the equipment. Yet, as Ross noted, the loss of production capacity, i.e., business interruption, is usually much higher than the cost of transformer replacement. He offered the following advice for managing such risks, starting with why transformers fail in the first place.

A maintenance technician winds new paper-coated copper winding around a transformer’s core. Aging, deteriorating paper can cause these units to fail.

A maintenance technician winds new paper-coated copper winding around a transformer’s core. Aging, deteriorating paper can cause these units to fail.

Paper, the weakest link

Many transformer failures happen after an incident, such as a lightning strike or a failure down line from the equipment. Such anomalies can be characterized as electrical, mechanical, or thermal, but, for the most part, they are separate from the condition of the unit. These may be root-cause failures, but they neglect a significant contributing factor, the condition of the unit. An overloaded transformer, with well-maintained dielectric fluid, which is not already weakened by poor maintenance, is much less likely to fail than an overloaded transformer that has not been maintained.

While there are instances in which transformers fail without warning, personnel should be able to anticipate most failures. Deteriorating paper and oil will develop acids that damage the paper insulation. Faults and overheating will emit gases that can lead to a better diagnosis of the unit’s condition. Moisture content is a significant predictor of failure.

The best measure of paper aging, Ross said, is furan analysis. As paper ages, it releases furan gases that are incredibly good indicators of the aging of the paper. The Department of Defense, Reliability Information Analysis Center (RiAC) states, “Furans are a family of organic compounds formed by degradation of paper insulation. Overheating, oxidation, and degradation from high moisture content contribute to the destruction of insulation and form furanic compounds. Changes in furans between dissolve(d)-gas-analysis tests are more important than individual numbers.”

A technician samples oil from a 2,000 KVA transformer. Coupling a quality sample with a reliable field inspection will provide a clear maintenance profile for this unit.

A technician samples oil from a 2,000 KVA transformer. Coupling a quality sample with a reliable field inspection will provide a clear maintenance profile for this unit.

The issue of gas

Gases dissolved in the transformer oil are formed by normal operation and aging, and by anomalies. By analyzing the volume, types, proportions, and rate of dissolved-gas production, Ross stated that maintenance personnel can get a good picture of what has happened or what is happening inside the unit. Because these gases can reveal transformer faults, they are known as “fault gases.” Gases are produced by oxidation, vaporization, insulation decomposition, oil breakdown, and electrolytic action.

Ross noted that while it’s becoming increasingly common to install DGA (dissolved-gas analysis) monitors on primary units within a substation or, in the case of steel production, the furnace units, those monitors will probably only detect the presence of certain gases. Performing DGA on an oil sample will indicate the amount of gas and, with frequent testing, its rate of change. “From that data,” he said, “knowledge is developed, meaning the cause of the increased gas is determined. In extreme cases, the analysis will indicate a potential catastrophic failure. In most cases it will indicate a weakening of the overall condition of the unit and the need to avoid overheating or higher loading.”

Life extension

Over time, transformer-health management has been approached in different ways, by many different industry sectors. Today, ensuring the reliability of this critical equipment is becoming a universal concern. The motivating factors behind the unification of strategy on transformer maintenance and, in turn, life extension, have been driven by some common factors that include the aging population of these assets and a higher-than-expected failure rate from newer replacement units.

Ross added that the general population of aging electrical-power equipment (given the peak in infrastructure building in the 1960s and 70s) points to increased potential for failures over the next decade. Prior to site personnel spending time developing impact assessments, reaction plans, and condition assessments, however, he encourages them to first focus on life-extension initiatives, that make necessary testing and preventive-maintenance practices as a priority.

Preventive-maintenance plans

Any good preventive-maintenance (PM) plan will start with an assessment of the condition of the unit(s). However, while most transformer-oil-testing labs in the U.S. are high quality and dependable, the weakest link in that testing process is often the sampling itself. Contaminated sampling leads to invalid test results or worse, false negatives. When the sampling process is coupled with a reliable field inspection, the knowledge gleaned from that sample is more predictive of potential failure. It also leads to a clear maintenance profile for the unit.

“Too often,” observed Ross, “transformer maintenance has focused on cleaning the oil, based on good inspection and sampling information. But cleaning the oil may not clean the paper. Moisture is a perfect example.”

The fact is, there is usually much more moisture in the paper than in the oil. Processing the oil to remove the moisture is a temporary fix. Within days or weeks, moisture will leach out of the paper and into the oil, leading to a high Karl Fisher (the proscribed test for moisture) reading. The same holds true for acid buildup in the oil and paper.

Ross sums up his five best practices for transformer maintenance as:

Oil Testing: Perform on a regular basis with corresponding maintenance-assessment reporting.

Electrical Testing: Perform on critical units and when an oil-testing result indicates a need for additional evaluation (standardized testing required).

Mechanical Inspections: Check for oil level and properly functioning gages, bushings, fans, radiators, and connections.

Thermography (IR): While most companies provide an annual IR scan of their entire system, there is a great advantage in conducting an annual routine IR inspection at the time of the oil test. The combined information can lead to specifics about faults, loose connections or potential bushing failure.

Monitoring for gases: Fault gases can lead to catastrophic failure, which goes well beyond a simple unplanned outage. Monitoring for these gases provides an early-warning system. Since hydrogen is usually always present in gases, a cost-effective monitoring solution may well consist of a single gas monitor augmented by a robust follow-up oil-testing program.

For Ross, the goal is abundantly clear. “While we may not get every transformer expert to agree on everything,” he said, “there is universal agreement that a healthy and robust electrical system starts with the heart of the system, the transformer.” MT

Ignore Transformer PMs at Your Peril

Tallmadge, OH-based S.D. Myers’ Alan Ross believes the widespread disregard for preventive maintenance of transformers stems from the fact that this equipment has been too trustworthy for too long.

“Transformers have been overbuilt in the past, and many have gone beyond their useful life,” he explained. “Still, they continue to hum along behind the substation fence. With the onset of computer modeling for transformer design, the specifications began to be met without overbuilding the transformer. In short, we have been spoiled and have become complacent.”

According to Ross, today’s transformers are built with much less margin for error than those of the past. That’s a big problem. “If we take the same approach to reliability based on our past experiences,” he lamented, “we are most likely going to see more unplanned outages and downtime from transformer failures than ever before.”

Owner/operators should be doing everything possible and economically feasible to extend the life of electrical transformers, he continued. “Even a company with only one unit is at risk if its data center runs off that unit. How long could most of us go if our data and/or ERP systems were shut down for a couple of weeks? Consider the call from your CEO in that event.”

Alan M. Ross is vice president of reliability for S.D. Myers Inc., Tallmadge, OH. For more information on managing electrical transformers, visit sdmyers.com.

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