Predicting Failure: Furan Testing of Transformers

Memphis Light, Gas & Water (MLGW) in Memphis, Tenn., is one of the largest three-service public power utilities in the nation.

Jan 1st, 2012
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By Jason Simon

Memphis Light, Gas & Water (MLGW) in Memphis, Tenn., is one of the largest three-service public power utilities in the nation. MLGW serves more than 420,000 electrical customers, 314,000 natural gas customers and 255,000 water customers in the Memphis and Shelby County area.

Within MLGW, the substation and transmission engineering department is responsible for the design and maintenance of 62 substations and 618 circuit miles of transmission lines in the service territory. The department designs and manages all substation and transmission projects and is composed of civil, mechanical and electrical engineers.

A look at the transformer during the scrapping process shows the condition.

MLGW has more than 180 substation power transformers in its electric system. The ratings of these transformers include 161 kV/115 kV, 90 MVA base; 161 kV/23 kV, 36 MVA base; 161 kV/12.47 kV, 25 MVA base; 115 kV/12.47 kV, 25 MVA base; and 23 kV/12.47 kV, 15 MVA base. The average transformer age is approximately 40 years old; some are up to 71 years old.

MLGW’s transformer department performs many diagnostic transformer tests. In the past, dissolved gas analysis has been the best predictive, noninvasive test for potential failures. Recently, MLGW has added furan analysis to its diagnostic tests.

The paper around the leads appears to be burned.

The Furan Analysis Process

Furan analysis shows the condition of the paper insulation with an oil sample. Over time, the cellulose insulating material will experience degradation. An aromatic compound is produced during this degradation called furan. Testing is performed for five furans:

• 5H2F (5-hydroxymethl – 2-furaldehyde)—oxidation;
• 2FOL (2-furfurol)—high moisture;
• 2FAL (2-furaldehyde)—overheating, old fault;
• 2ACF (2-acetylfuran)—rare, lightning; and
• 5M2F (5-methyl – 2-furaldehyde)—local, severe overheat.

Furan results are used to determine an average expected degree of polymerization for the paper in the equipment. The calculated degree of polymerization is used to estimate percentage of solid insulation life remaining inside the transformer.

A look at the coils.

The amount of 2-furaldehyde in oil is usually the most prominent indicator of paper decomposition, which is figured in the following manner:

1. The solid insulation in a transformer is made up of kraft paper.
2. Kraft paper is made up of cellulose fibers.
3. Cellulose is a polymer formed from glucose molecules.

New kraft paper has an average cellulose polymer chain that is 1,000 glucose molecules to 1,200 glucose molecules long. The manufacturing and transformer drying process breaks down the cellulose. New paper in a new transformer, therefore, has shorter polymer chains—from 800 glucose molecules to 1,000 glucose molecules long.

Notice all the particulates and paper residue.

Over time, there is a natural and steady breakdown of the polymer chains. As the polymer chains get shorter, the mechanical strength of the paper is reduced. The degree of paper polymerization has a direct correlation to the paper’s tensile strength. When the degree of polymerization has fallen to around 200, the paper is so weak that any stress will lead to failure. When the cellulose chain splits and two shorter chains are formed, the breakdown process forces out one or more of the glucose molecules. The breakdown also creates water, carbon monoxide and carbon dioxide. The glucose molecule chemically changes during this event and creates a compound containing a furan ring. Furans are measured in parts per billion. The life of the paper insulation is typically the life of the transformer.

The paper appears to have almost burned off in this photo.

MLGW Testing

MLGW began to test each of its transformers for furans in 2009. The results produced a good baseline.

A 40-year-old transformer showed a degree of polymerization of 260 in early 2010 during testing, with estimated remaining life at 19 percent. The transformer was immediately taken offline and internally inspected to identify any problems. When personnel investigated the interior of the tank, there was significant degradation of the paper insulation. The paper insulation actually disintegrated when touched by personnel. The transformer also appeared burned to the naked eye.

More discoloration of insulating material.

Results from the dissolved gas analysis sample, however, did not reveal any irregularities with the transformer. There was no significant increase in any of the gases that would typically confirm a problem. Without the furan analysis, therefore, the problem might have gone undetected until there was a catastrophic in-service failure. This transformer problem was discovered, fortunately, and the transformer was replaced before the summer load of 2010.

Finding and mitigating the problem before an in-service failure helped prevent extensive damage to surrounding equipment, unplanned customer outages or an explosion. Testing for furans has shown to be a valuable tool when trying to predict the end of a transformer’s life.

Burn marks on the core steel.

About the author: Jason Simon is MLGW’s supervisor of substation and transmission engineering. He has worked at MLGW for more than 12 years.

Remote Monitoring Helps With Transformer Maintenance

Remote monitoring and communication capabilities allow utilities to conduct predictive maintenance of transformers, which means conducting maintenance only when a parameter starts deviating from a pre-set standard.

Daniel Lambert of Vizimax, a Montreal, Canada-based company that offers remote monitoring and control systems for public utilities and the industrial and private sectors, notes that remote management is being widely embraced, especially as operators need the maintenance function to be more profitable.

“It is similar to today’s cars that tell you when to change your oil or conduct other maintenance based on your specific driving habits,” Lambert said. “Rather than changing your oil at 6,000-mile intervals, electronic sensors can determine if you do mainly city or highway driving and signal the need for an oil change accordingly. That basic principle has been adapted for use in monitoring transformers.”

Many transformer manufacturers are recognizing this growing demand for online transformer monitoring products and diagnostic services, and investing in building them, especially for step-up transmission, high-voltage transformers.

In addition to monitoring vital statistics such as temperature, pressure and vacuum levels, there has also been a growing interest in conducting dissolved gas analysis (DGA) of the oil in transformers. With DGA, samples are taken of the oil’s exhaust gases to determine if any events have occurred that might be detrimental to the transformer and reduce its life. Both industrial transformer users and utilities are setting up these planned sampling programs using online devices that can monitor the oil for quality.

According to Mike Dickinson of Oregon-based Pacific Crest Transformers, this can greatly improve reliability because users will know in advance when something has to be replaced rather than risk enduring an unscheduled outage.

“Transformers in place are already using various smart devices for load switching. In the 21st century, the move will be towards monitoring systems that promote transformer reliability. Ensuring reliability on the grid by replacing equipment before it fails and anticipating upcoming problems is what transformer manufacturers will be focusing on,” Dickinson said.

The newest technology for remote monitoring of transformers includes a combination of a remote terminal unit, a programmable language controller, a gateway (a network node equipped for interfacing with another network that uses different protocols) and a protocol converter. The complete monitoring system is usually placed in service by a system integrator or a power manufacturer.

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