Transformer Dissolved Gas Analysis: Key Fault Gases and What They Mean

Every internal fault developing in a transformer, thermal or electrical, produces gases. Those gases dissolve into the oil and accumulate over time. DGA extracts those gases from an oil sample and identifies them. The result is a window into what is happening inside a sealed tank without opening it, and it typically shows problems months before they become failures.

What is DGA and why do fault gases form?

DGA extracts the gases dissolved in a transformer oil sample and identifies them. Those gases form because heat and electrical stress break down the oil and the paper insulation, and each fault type produces its own mix of gases in its own proportions.

Transformer oil and cellulose insulation (paper and pressboard) decompose when exposed to heat or electrical stress. The decomposition products are hydrocarbon gases and carbon oxides that dissolve into the surrounding oil. The specific gases that form, and in what proportions, depend on the type and severity of the fault producing them.

Low-temperature thermal decomposition of oil produces methane and ethane. Higher temperatures produce ethylene. Very high temperatures, those associated with arcing, produce acetylene. Carbon monoxide and carbon dioxide come from decomposition of the paper and pressboard, which means elevated CO and CO₂ point specifically to insulation deterioration rather than oil decomposition. Hydrogen forms from a range of fault types, from partial discharge at low levels to severe arcing at high levels, and is often the first gas to rise above background when something is developing inside the tank.

What are the key fault gases in DGA?

Seven gases carry most of the diagnostic weight: hydrogen, methane, ethane, ethylene, acetylene, carbon monoxide, and carbon dioxide. Hydrogen points to partial discharge. Methane and ethane point to low-temperature thermal faults in oil. Ethylene points to hotter thermal faults. Acetylene means arcing. Carbon monoxide and carbon dioxide mean the paper insulation is degrading, not just the oil.

Hydrogen (H₂) is produced by partial discharge and by low-level electrical activity. It is the most sensitive early indicator of developing problems. Rising hydrogen without proportional increases in the hydrocarbon gases points toward partial discharge rather than thermal faults.

Methane (CH₄) and ethane (C₂H₆) are produced by low-to-moderate thermal decomposition of oil. Their presence at elevated levels indicates a thermal fault at temperatures generally below 300°C, a hot spot in oil, a circulating current path, or an overloaded connection that is cooking the surrounding oil.

Ethylene (C₂H₄) forms at higher temperatures, generally above 300°C. Significant ethylene alongside methane and ethane points to a more severe thermal fault, a core hot spot, a high-resistance joint carrying significant current, or a core lamination fault creating eddy current heating.

Acetylene (C₂H₂) requires very high temperatures to form and is the signature gas for arcing. Any detectable acetylene in a main tank sample, even small amounts, is significant and warrants immediate follow-up. Acetylene does not form from thermal faults alone; its presence means electrical discharge at high energy levels is occurring somewhere inside the tank.

Carbon monoxide (CO) and carbon dioxide (CO₂) indicate paper and pressboard degradation. Elevated CO alongside hydrocarbon gases confirms that the fault is affecting the solid insulation, not just the oil. The CO/CO₂ ratio shifts as the fault temperature increases. Very high CO relative to CO₂ points to higher-temperature cellulose decomposition.

What do the IEEE and IEC DGA thresholds mean?

IEEE C57.104 and IEC 60599 both provide concentration thresholds and interpretation methods for DGA results. The exact numbers differ between the two standards and are revised periodically, so the values in the current edition of C57.104 govern for U.S. utility practice. The current 2019 edition sorts each gas result into one of three DGA Status levels set by population percentiles (roughly the 90th and 95th): Status 1 is normal, Status 2 warrants increased monitoring, and Status 3 signals a possible active fault that calls for investigation. The response depends on the status together with the rate of gas generation and the fault type the gas ratios point to, not on a single fixed table value. This replaced the older four-condition, TDCG-based scheme from the 2008 edition.

Absolute concentration thresholds matter, but rate of change matters more. A transformer at Status 2 concentration that has been stable for three years is a different situation from one at Status 2 that has doubled in six months. Trending is why DGA sampling must run on a consistent schedule with results from each sample compared against the previous history, not evaluated in isolation.

How does the Duval Triangle identify a fault?

The Duval Triangle is a graphical fault identification method that uses the relative proportions of methane, ethylene, and acetylene to classify the fault type. A point is plotted on a triangular diagram based on the percentage of each gas in the total of the three, and the region of the triangle where the point falls corresponds to a fault category: partial discharge, low-energy discharge, high-energy discharge, thermal fault at low temperature, thermal fault at moderate temperature, or thermal fault at high temperature.

The Triangle handles mixed or boundary cases better than simple ratio methods because multiple data points plotted over time show a trajectory. A point that starts in the thermal fault region and moves toward the high-energy discharge region over successive samples indicates a fault that is escalating in severity, not just persisting at the same level.

Most oil laboratories include a Duval Triangle plot in their DGA reports. If yours does not, the calculation is simple: express each of the three gases as a percentage of the sum of the three, then locate the point on the triangle coordinates.

How often should you sample transformer oil for DGA?

Annually, for a power transformer in routine service. Sample more often on units at DGA Status 2 or above, on units that have taken a through-fault, and on any unit showing acetylene. The sample itself has to be taken correctly or the frequency does not matter.

DGA results are only as good as the sample. Improper sampling introduces air, which dilutes the dissolved gas content and produces a misleading result. The sample must be taken from the bottom valve of the transformer (gases concentrate in the oil, not at the top) using a glass syringe or purpose-built sampling vessel that excludes atmospheric air. The sample must be shipped to the lab promptly, dissolved gases can escape from a poorly sealed sample container over time.

Units at IEEE Status 2 or above should be sampled more frequently, quarterly or monthly depending on the concentration levels and rate of change. Units that have recently experienced a through-fault event or that show any acetylene should be sampled immediately after the event and then again within weeks to establish whether the gas levels are stable or rising.

Keep the LTC oil separate from the main tank oil. The LTC compartment has its own oil that sees arc gases from normal tap change operation. A DGA on LTC oil is interpreted against different baselines than main tank oil, acetylene in LTC oil at low levels is expected; the same level in main tank oil is not.

What should you do about an abnormal DGA result?

Confirm it with a second sample, then correlate it with load history, thermal records, power factor history, and any through-fault or lightning event that lines up with the onset of gas generation. Act on the fault type and the rate of change, not on a single number.

An abnormal DGA result does not automatically mean an emergency. It means the transformer needs attention. The first step is to confirm the result is not a sampling artifact, a repeat sample from the same port, properly taken, is the check. If the second sample confirms the first, the data is real.

The next step is to correlate the DGA result with other available data: load history, thermal records, power factor test history, and any events such as through-faults or lightning that may have coincided with the onset of gas generation. A thermal fault that appears in DGA alongside a known overload event is a different situation from a thermal fault that appears in a unit that has been running at light load with clean history.

From there, the decision tree branches based on fault type and severity: increase monitoring frequency, reduce load, schedule an outage for internal inspection, or in the case of rapidly rising acetylene, consider emergency de-energization. The laboratory report and the guidance in IEEE C57.104 walk through those decision points. The value of having clean historical data is that it makes those decisions faster and more confident, you are reading a trend, not trying to interpret a single data point without context.