Dissolved Gas Analysis in Transformer Oil for Fault Detection

Introduction

The oil and fiber insulation materials in a transformer are affected by water, oxygen, heat, and catalytic effects of copper and iron during operation, leading to aging and decomposition. The resulting gases are mostly dissolved in the oil, but the rate of gas production is relatively slow. However, when an initial fault or new fault condition exists inside the transformer, the rate and amount of gas production become significant, and most initial defects will show early signs. Therefore, analyzing the gases produced by the transformer can detect faults.

As the transformer operates for a longer period, it may develop initial faults, and some combustible gases in the oil are precursors to internal faults. These combustible gases can lower the flash point of the transformer oil, leading to early faults.

Types of Gases in Transformer Oil

Gas chromatography is a practical method for analyzing combustible gases in transformer oil. The method includes degassing and measurement processes. Mineral oil is composed of approximately 2871 kinds of liquid hydrocarbons, and usually, only nine gases are identified: hydrogen (H2), oxygen (O2), nitrogen (N2), methane (CH4), carbon monoxide (CO), ethane (C2H6), carbon dioxide (CO2), ethylene (C2H4), and acetylene (C2H2). These gases are separated from the oil and analyzed to determine their presence and quantity, which can reflect the type and severity of faults. The main gases produced during normal aging of the oil are CO and CO2. When local discharge occurs in the oil (e.g., gas bubble breakdown), the main gases produced are H2 and CH4.

Judging Faults in Electrical Equipment

Five characteristic gases are used to judge the nature of faults in electrical equipment:

1. C2H2/C2H4 ≤ 0.1, 0.1 < CH4/H2 < 1, C2H4/C2H6 < 1: Normal aging of the transformer.
2. C2H2/C2H4 ≤ 0.1, CH4/H2 < 0.1, 0.1 < C2H4/C2H6 < 1: Low-energy density local discharge (e.g., discharge in gas-filled voids).
3. 0.1 < C2H2/C2H4 < 1, CH4/H2 < 0.1, 0.1 < C2H4/C2H6 < 1: High-energy density local discharge (excluding discharge in gas-filled voids), leading to solid insulation discharge.
4. 1 < C2H2/C2H4 < 3, 0.1 < CH4/H2 < 1, C2H4/C2H6 > 3: Power frequency continuous discharge, coil-to-coil or coil-to-ground oil breakdown.
5. C2H2/C2H4 ≈ 3, 0.1 < CH4/H2 < 1, C2H4/C2H6 ≈ 3: Low-energy density discharge, with increasing spark discharge intensity.
6. C2H2/C2H4 ≤ 0.1, 0.1 < CH4/H2 < 1, 1 < C2H4/C2H6 < 3: Thermal fault below 150°C, with gases mainly from solid insulation material decomposition.
7. C2H2/C2H4 ≤ 0.1, 1 < CH4/H2 < 3, C2H4/C2H6 < 1: Low-temperature thermal fault below 300°C.
8. C2H2/C2H4 ≤ 0.1, 1 < CH4/H2 < 3, 1 < C2H4/C2H6 < 3: Medium-temperature thermal fault between 300°C and 700°C.
9. C2H2/C2H4 ≤ 0.1, 1 < CH4/H2 < 3, C2H4/C2H6 > 3: High-temperature thermal fault above 700°C.

Handling Internal Faults

When an internal fault occurs:

1. Take oil samples and observe any suspended particles or odor.
2. Examine the development trend of the fault, including the rate of gas production related to the energy consumption, location, and temperature of the fault point.
3. Use the three-ratio method to judge the type of fault when an internal fault is suspected.
4. Compare the analysis results of the gas sample from the gas relay with the oil sample.