May Edition

The primary purpose of annual dielectric liquid testing is to identify the condition of the transformer’s insulation system so that it will operate in the sludge-free range.

TRUE

Deterioration and sludge formation are two of the major concerns of transformer owners with regard to liquid insulation. The insulating liquid inside a transformer contains vital information about its health. Regular testing can tell transformer owners what’s happening inside and provide trending data. Annual dielectric liquid testing is the key to keeping costs down with preventative maintenance and a must-have for upholding transformer reliability best practices.

Read more about transformer maintenance best practices in Getting Started with Asset Reliability.

In order to optimize transformer life, you should maintain your solid insulation less than 2% moisture by dry weight (%M/DW).

FALSE

Moisture levels in the solid insulation beyond 0.5% M/DY decrease transformer life. An operating transformer in service for several years should have at most 1.0% M/DY. To achieve maximum reliable life for a transformer, moisture levels should be kept at 0.5% M/DY. Maintaining every transformer in your fleet at or below 0.5% M/DY may not be practical or cost-effective. You may choose to let the moisture level in distribution or non-critical transformers elevate to the 1.0% M/DW range.

Read more about transformer maintenance best practices in Getting Started with Asset Reliability.

By measuring the concentration of a gas in the insulating liquid, it is possible to narrow down what event caused it to form, how severe or recurrent that event was, and whether the transformer is still reliable.

TRUE

Dissolved gas analysis (DGA) is the industry standard for detecting faults in a transformer. New transformer liquid contains small amounts of dissolved combustible gases. Additional dissolved combustible gases form when an abnormal condition exists, which is often attributed to a fault. Often, detecting these gases alone does not point to any specific fault. Rather, you need the specific combination, concentration, change over time, and movement from the baseline test results to truly understand what is happening inside a transformer. DGA testing and accurate interpretation of results are essential for adhering to transformer reliability best practices.

April Edition

If the paper insulation deteriorates from oxidation caused by moisture, heat, and oxygen, an oil cleaning process and moisture reduction program can restore the paper insulation, effectively adding years back to its lifespan.

FALSE

Once the life of the paper is lost, it cannot be restored. It can be slowed or stopped but not reversed. Moisture degradation to the solid insulation causes permanent damage and premature loss of equipment life. Gradual increases in the percent moisture by dry weight of the solid insulation may not threaten immediate failure, but it is slowly deducting years off a transformer’s life.

Read more about the weakest link in your transformer in this month’s featured article.

Furans are a family of organic compounds formed by the degradation of paper insulation. Overheating, oxidation, and degradation by high moisture content contribute to the destruction of insulation and form furanic compounds.

TRUE

The solid insulation in a transformer is made up of paper. Paper is made up of cellulose fibers with a chain-like structure. As the paper ages, the polymer chains have a natural and gradual breakdown. As the chains get smaller (and create furanic compounds in the process), the paper's mechanical strength is also reduced. The temperatures at which breakdown occurs and the presence of abnormally high moisture and oxygen levels determine which furanic compounds are formed.

The moisture content of liquid insulation (the oil) is only a partial indicator of the amount of moisture in a transformer because the paper insulation has 100 times or more affinity for moisture compared to the oil.

TRUE

To maximize the reliable life of a transformer, moisture must be removed from the oil and the paper insulation. The solid insulation, which consists of paper on the coils, cardboard, pressboard, and wood structure, holds as much as 100 times more moisture than the oil. Dehydrating the oil is only temporary. Within weeks of an oil-dehydration procedure, the moisture content will become unacceptable again as moisture trapped in the solid insulation migrates into the oil. Dehydrating the oil doesn’t remove the moisture in the paper unless the moisture was within the top surface layer.

Read more about your transformer’s paper insulation in this month’s featured article.

March Edition

Multi-gas online transformer monitoring provides all the insights of Dissolved Gas Analysis (DGA) at an exponentially greater frequency than manual sampling and laboratory-based DGA.

TRUE

The utility market has embraced multi-gas online transformer monitoring because that equipment provides all the insights of Dissolved Gas Analysis (DGA) at an exponentially greater frequency than manual sampling and laboratory-based DGA, allowing for more sophisticated trend analysis using transformer management software. The increase in frequency means that incipient faults are much more likely to be detected early, and critical transformers are more likely to live longer, healthier, lower-cost lives with a lower risk of premature failure.

Hydrogen accompanies most known transformer faults, making a single-gas online monitor effective for understanding when an issue is developing inside a transformer.

TRUE

If an online condition monitor (single or multi-gas) detects a significant spike in H2, the specifics of the fault can then be determined with a full Dissolved Gas Analysis profile and an array of chemical, mechanical, and electrical testing to reveal the specifics of the fault.

Online condition monitoring that works around the clock to monitor the health of a transformer is an adequate substitute for more precise case-by-case testing.

FALSE

Online condition-based monitoring is not a substitute for more precise case-by-case testing. Gas monitors are tools for measuring changes in the dissolved gases present within transformer oil, so detecting faults early and performing further tests is possible.

February Edition

Bushings, insulators, and lightning (surge) arrester structures in a substation are subject to the same contamination problems that plague transformers and steel coatings because of their electrostatic attraction for airborne contaminants.

TRUE

Since their inception, the problem of transformer bushing and stand-off insulator contamination due to natural deposits (early morning dew, salt fog in coastal areas, and smog) and subsequent industrial pollution has plagued the electrical industry. Such contamination has often resulted in noisy substations, damage to insulating surfaces, partial discharge, tracking flashover, and loss of power.

Combustible gases are generated as a transformer undergoes thermal and electrical stresses over time. The oil and the cellulosic insulating material in a transformer break down due to these stresses to yield gases.

TRUE

The presence and quantity of these individual gases, extracted from the oil and analyzed, reveal the type and degree of the condition responsible for the gas generated. Gas chromatography (GC) is the most accurate method to identify combustible gases. GC involves a qualitative and quantitative analysis of gases dissolved in transformer oil.

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During installation, if a newly installed transformer passes an 8-hour positive pressure test with dry air or nitrogen, there is no need to perform another leak test under vacuum before the unit is ready for final vacuum treatment and filling.

FALSE

No matter how well the transformer performed during the leak test under positive pressure, another leak test must be performed under vacuum to ensure the unit is ready for vacuum treatment. To learn more about transformer selection, installation, and standards, take the upcoming Transformer Management 3 course in March 2023.

January Edition

Sludges tend to form on interior surfaces before they are absorbed into the cellulose fibers of the insulation.

FALSE

Sludges are absorbed into the cellulose fibers of the insulation BEFORE precipitating onto the interior surfaces of the transformer. Once sludge absorbs in the cellulose, the degree of polymerization and tensile strength start to decline, the formation of furanic compounds accelerates, and the cellulose insulation loses its plastic quality. To learn more about how sludge affects transformers, take a training course on transformer maintenance with Electric Power IQ. Click here for information on Transformer Management 1.

Oxidation damage done to oil can almost always be reversed. However, damage done to solid insulation can be slowed or stopped, but not reversed.

TRUE

Damage done to a transformer’s solid insulation cannot be reversed, even though it can be stopped. To learn more about maximizing the life of a transformer, take a training course this year. Click here for the new 2023 Course Catalog. Click here for the 2023 Course Catalog.

Gradual increases in the percent moisture by dry weight of the solid insulation may deduct years off a transformer’s life but pose no threat of immediate failure.

TRUE

Only when solid insulation approaches 4.5% M/DW does the moisture content pose a danger of immediate electrical failure. At or above 4.5% M/DW, a transformer runs the risk of flashover across the insulation at normal and elevated operating temperatures. The moisture absorbed in the insulation will form a conductive path from winding to winding, to the core, or to a ground.

To learn more about failures related to moisture and strengthen your ability to manage a reliable electric power system, take the upcoming live online Transformer Management 1 course in February 2023.