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Assessing Transformer Aging Based on Temperature Rise Data


Time:

2026-04-13

 

The three key indicators for assessing transformer aging based on temperature-rise data are: Top-oil temperature rise trend, cumulative effect of winding hot-spot temperatures, and the generation rates of CO₂ and CO gases , which collectively reflect the thermal degradation state of insulating materials.

 

Top-Stage Oil Temperature Rise Trend ‌

 

Long-term monitoring of the top-oil temperature rise (typically limited to 55 K) can detect abnormal heating. If the oil temperature continues to rise under the same load, it indicates a decline in heat dissipation performance, which may be caused by blockage in the oil circuit, sludge deposition, or failure of the cooling system, and indirectly reflects the degree of insulation oil aging.

 

Cumulative Effect of Winding Hot-Spot Temperature ‌

 

The winding temperature is 10–15°C higher than the oil temperature, and the hotspot temperature is the primary cause of insulation aging. According to the “six-degree rule,” for every 6°C increase in temperature, the rate of insulation aging doubles, and the service life is halved. By applying the equivalent-ageing principle to calculate the cumulative thermal damage resulting from temperature fluctuations over the assessment period, the remaining service life can be estimated.

 

Amount of CO₂ and CO gas produced ‌

 

Thermal aging of insulating paper (cellulose) leads to its decomposition, generating CO and CO₂. Studies have shown that when the combined concentration of CO₂ and CO reaches 1.0 mL/g of oil, the degree of polymerization of the insulating paper drops to 30%, which is considered the end point of its service life and can be used for online assessment of the extent of aging.

 

By integrating these three indicators, early warning of transformer aging and lifetime prediction can be achieved.

 

 

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