Isophase bus, discussed in the previous article, connects generators covered in this issue’s first two articles to step-up transformers, the subject here. Paul Griffin, VP, Doble Engineering Co, has shared his extensive knowledge of transformers at several user-group meetings over the last few years. Most recently, he presented at the 2015 7F Users Group meeting in Denver on “Asset Health Review of Transformer Fleets—Monitoring, Assessment, and Visualization” which is accessible by registered owner/operators in the forum section of the Power Users Group website.

Griffin began by offering the following reasons, among others, for ongoing tracking of transformer health and trending of O&M data:

• Allows identification of problems in the early stages when they can still be managed.

• Provides a ranking from normal to identify which issues require immediate attention.

• Identifies units requiring further study to better understand risks and prioritize actions. This (1) reduces the risk of unplanned outages and, in the extreme, catastrophic failure, (2) improves reliability/availability; (3) supports strategic planning for spares, and (4) saves money.

The speaker offered a couple of slides on what data should be collected to assure a valid health assessment and when/how to gather that information. Next, he explained how the data were crunched to formulate an “Overall Transformer Condition Code” and what the numerical ranking from 1 (unacceptable) to 5 (excellent) means for each unit in the fleet. Example: A “2,” described as poor, means a problem is likely and the unit should be paid attention in the very near future.

The Overall Transformer Condition Code, Griffin continued, is comprised of sectional codes, each weighted according to the importance of those tests to the overall health of the transformer. A summary of the various sectional codes follows:

Oil Code represents transformer condition considering oil test data only. Tests include these:

• Dissolved gas analysis (DGA) to determine overall transformer health and ageing of the solid insulation. The three gases used as key indicators are methane, ethylene, and acetylene.                

• Water content to determine insulation system dryness.

• Furanic compounds formed by the degradation of solid insulation during periods of high thermal and/or electrical stress.

• Dielectric breakdown.

• Interfacial tension, neutralization number, and color—all indicators of oil ageing.

Electrical Code represents transformer condition considering electrical test data only.

Here’s what is tracked:

• Overall power factor helps determine insulation condition and identify tracking and contamination.

• Overall capacitance offers insights into any mechanical changes.

• Bushing power factor and capacitance helps determine insulation condition, tracking, contamination, and shorted capacitive layers.

• Bushing hot collar warns of contamination.

• Core insulation resistance is another measure of insulation deterioration.

• Winding resistance is indicative of loose connections, poor connections from contamination, mechanical issues, and shorted conductors.

• Arrester insulation condition warns of moisture ingress and contamination.

• Tracking exciting current can help identify problems in the magnetic circuit as well as shorted turns.

• Leakage reactance helps identify mechanical changes and winding deformation.

• Sweep-frequency response analysis is used to identify mechanical changes, winding deformation, winding movement, and shorted turns.

Mechanical Code relies on the three following tests to help determine the mechanical integrity of the transformer:

• Leakage reactance, to warn of mechanical changes and winding deformation.

• Sweep-frequency response analysis to identify mechanical changes, winding deformation, and winding movement.

• Main insulation capacitance also is indicative of mechanical changes and winding deformation.

Ageing Code is based on insulation condition relative to transformer age. The lower the numerical value, the faster the insulation is ageing.

DGA Code is based on an evaluation of combustible and atmospheric gases (not carbon-oxide gases)—including their concentrations, rates of generation, and trends.

Paper Ageing Code is based on an evaluation of the carbon-oxide gases and the furanic compounds. Concentrations, production rates, and trends all are factored into the analysis.

Oil Quality Code is based on an evaluation of oil ageing and considers acidity, interfacial tension, power factor and specific gravity. Dielectric breakdown, sediment, and visual analysis also are considered.

Moisture Code is based on the concentration of water in oil. Water can be removed with proper treatment.

Other information collected and evaluated includes the following:

• Visual field service. Transformer condition is assessed during a visual inspection. Verification of good physical and operating conditions is necessary for an accurate health assessment. Components of top interest include the tank, cooling system, and control and protective devices.

• Operating and loading history, which impact paper ageing and serviceability.

• Fault and short-circuit history. This includes the number, magnitude, and duration of the short circuits. Transformer internal faults and component faults, such as bushing and arrester failures, should be included in the analysis.

• Maintenance and repair history and the impact on transformer health of corrective work done.

Wrapping up, Griffin recommended use of continuous online monitoring and diagnostics to the extent possible. Information gathered will prove invaluable, he said, if problems are detected and technical support is involved in the necessary analyses.