The 13 Dissolved Gases in Transformer Oil: Essential Indicators in Condition-Based and Predictive Maintenance of Power Transformers

Power transformers are pivotal components in the electrical grid, ensuring the safe and efficient transmission of electrical energy over vast distances. Among the many maintenance practices ensuring the longevity and reliability of transformers, Dissolved Gas Analysis (DGA) plays a critical role. 

DGA is employed to assess the condition of the transformer by analyzing gases dissolved in its insulating oil, often providing early warning signs of potential faults. 

This analysis is integral to both condition-based maintenance (CBM) and predictive maintenance strategies. 

By focusing on 13 key dissolved gases, operators can make informed decisions about transformer health, preventing catastrophic failures and optimizing operational life.

The Role of DGA in Transformer Maintenance

Transformer oil serves multiple purposes: cooling, insulation, and protection of transformer components from oxidation. 

However, the operation of transformers, especially under stress or faults, can lead to the breakdown of the insulating oil and solid insulation (such as paper). 

When these materials degrade, they produce gases that dissolve in the oil. Each gas provides insight into the type of fault, its severity, and the necessary maintenance actions.

DGA measures the concentration of dissolved gases and, through established diagnostic techniques such as Rogers ratios or Duval triangles, identifies potential internal issues. 

Monitoring these dissolved gases over time enables predictive maintenance by forecasting emerging issues, while condition-based maintenance optimizes intervention times, minimizing unnecessary downtime.

The 13 Dissolved Gases: Indicators of Transformer Health

1. Hydrogen (H₂): Hydrogen is produced by partial discharge (PD), a low-energy electrical fault often caused by localized insulation failure. Even though PD does not initially cause significant damage, prolonged activity can weaken insulation, leading to more serious issues such as arcing or overheating. A spike in hydrogen levels is an early indicator of PD.
2. Methane (CH₄): Methane is typically generated under low-energy arcing or corona discharges. Its presence, often in combination with other gases like hydrogen, points to early-stage thermal or electrical faults in the transformer insulation system.
3. Ethane (C₂H₆): Ethane is a result of overheating at temperatures below 300°C. Although its concentration is lower than gases associated with more severe faults, ethane provides a clear signal of oil degradation, particularly in its early stages.
4. Ethylene (C₂H₄): Produced at higher temperatures (300-700°C), ethylene is associated with thermal faults in the transformer oil. It is commonly found in transformers experiencing high levels of overheating, which can severely compromise oil and insulation integrity if left unchecked.
5. Acetylene (C₂H₂): Acetylene is a critical indicator of high-energy arcing faults. Its presence is alarming because arcing can generate extreme temperatures that degrade insulation, metal components, and oil. The detection of acetylene requires immediate attention, as it indicates a serious and potentially dangerous condition within the transformer.
6. Carbon Monoxide (CO): Carbon monoxide is primarily generated by the decomposition of the cellulose-based solid insulation in transformers (such as paper). Elevated CO levels suggest that overheating or localized hotspots are affecting the solid insulation, which can lead to transformer failure if left unresolved.
7. Carbon Dioxide (CO₂): Like carbon monoxide, carbon dioxide is a byproduct of solid insulation degradation, though it is often produced in larger quantities. A significant rise in CO₂ levels, particularly when coupled with CO, indicates thermal damage to the paper insulation. The ratio of CO to CO₂ is often used to differentiate between normal aging and critical thermal deterioration.
8. Nitrogen (N₂): Although not a byproduct of oil degradation, nitrogen levels are monitored because they can indicate air ingress into the transformer, which compromises the oil's insulating properties. The detection of nitrogen is typically linked to external factors such as leaks or poor sealing of the transformer tank.
9. Oxygen (O₂): Like nitrogen, oxygen is monitored to detect air ingress. Oxygen accelerates oil degradation through oxidation, leading to sludge formation and reduced insulation effectiveness. High levels of oxygen in the oil are a sign of compromised oil quality or leaks, necessitating action to prevent further contamination.
10. Propane (C₃H₈): Propane is generated under low-temperature thermal conditions, similar to ethane. Its presence, though less common, points to minor overheating or degradation of oil and insulation at moderate temperatures.
11. Propylene (C₃H₆): Propylene, much like ethylene, is an indicator of thermal faults. It is typically produced at temperatures exceeding 700°C. While it is detected in much smaller amounts, propylene provides additional confirmation of extreme overheating or arcing in the transformer oil.
12. Propadiene (C₃H₄): Propadiene is produced under conditions of severe overheating and arcing, which can occur in faulted transformers. Its detection, particularly alongside other gases indicative of arcing or thermal stress, suggests potential imminent failure.
13. Propyne (C₃H₄): Propyne is associated with high-temperature conditions and severe electrical faults. It is produced during the decomposition of oil and insulation materials, indicating significant stress within the transformer. Elevated levels of propyne can serve as a warning of critical thermal events or arcing.

Application in Condition-Based and Predictive Maintenance

The analysis of these 13 gases is central to both condition-based and predictive maintenance strategies in power transformers. 

In condition-based maintenance, real-time or periodic DGA testing allows maintenance teams to identify emerging problems before they cause transformer failure. 

By evaluating the concentration and ratio of key gases, maintenance decisions are based on the actual condition of the transformer, optimizing repair schedules and reducing unnecessary interventions.

Predictive maintenance, on the other hand, leverages DGA data over time to forecast future transformer performance. 

Through trend analysis and predictive modeling, potential failures can be predicted with greater accuracy. Operators can schedule maintenance before a fault reaches a critical stage, ensuring the transformer remains operational with minimal downtime.

The role of DGA in these maintenance strategies cannot be overstated. As the demand for energy continues to rise and power transformers operate under increasing load conditions, advanced monitoring techniques such as DGA provide the insight needed to maintain grid reliability and safety.

Conclusion

The 13 dissolved gases in transformer oil offer an unparalleled view into the internal health of power transformers. 

By understanding the nature of these gases and their relation to various fault conditions, utilities and maintenance teams can implement effective condition-based and predictive maintenance programs. 

In an era where energy infrastructure reliability is paramount, DGA ensures that transformers operate efficiently, safely, and with minimal risk of failure. 

Through ongoing analysis and maintenance practices, transformers can achieve extended service life while preventing costly and dangerous breakdowns.