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.
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 CO&sub2 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.
Hydrogen (H&sub2)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 (CH&sub4) and ethane (C&sub2H&sub6)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 (C&sub2H&sub4)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 (C&sub2H&sub2)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 (CO&sub2)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/CO&sub2 ratio shifts as the fault temperature increases. Very high CO relative to CO&sub2 points to higher-temperature cellulose decomposition.
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 general framework is consistent: concentrations are divided into condition levels that drive different response actions, from continued normal monitoring at Level 1 through immediate investigation and load reduction at Level 4.
Absolute concentration thresholds matter, but rate of change matters more. A transformer at Level 2 concentration that has been stable for three years is a different situation from one at Level 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.
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 straightforward: express each of the three gases as a percentage of the sum of the three, then locate the point on the triangle coordinates.
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.
For routine monitoring on a power transformer in service, annual sampling is the standard starting point. Units at IEEE Level 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.
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.
We perform DGA oil sampling in the field and ship to the lab for analysis, across Florida and the Southeast. Send us your transformer details and we’ll respond within one business day.