DGA: The Blood Test Your Transformer Should Pass Before Shipment

Two transformers. Same factory. Same test report. One will fail.

Consider a procurement scenario: two pad-mounted transformers, identical specifications—1000 kVA, 13.8 kV primary, 480 V secondary. Both pass routine electrical tests. Winding resistance within tolerance. Ratio deviation under 0.3%. Insulation resistance above 2000 MΩ. Both manufacturers provide FAT reports stamped "APPROVED."

One transformer operates without incident for a decade. The other develops a winding hot spot within eighteen months. The oil darkens. The insulation degrades. The unit is decommissioned years before its design life.

The difference between these two transformers was visible on the day they left the factory. It was recorded in a test that only one of the two manufacturers performed.

That test is dissolved gas analysis—DGA.

What DGA measures, and why it matters before the transformer is energized

A transformer in operation produces gases. The insulating oil is a hydrocarbon mixture. When the oil or the solid insulation is subjected to thermal or electrical stress, chemical bonds break. The fragments recombine into small gas molecules that dissolve in the oil.

The type of stress determines which gases appear:

Each fault type leaves a distinct gas signature. A hot spot in the core generates a different gas profile than a partial discharge site. An internal arc—even a brief one during testing—leaves acetylene in the oil. Acetylene does not disappear. It does not "settle out." It remains dissolved, detectable, and damning.

The scenario: when "passed all routine tests" hides a problem

Imagine a transformer that passes its applied voltage test—but during the test, a small internal discharge occurs at a weak point in the insulation. The discharge is too small to cause immediate failure. The electrical measurements look normal. The unit is stamped "passed" and shipped.

Six months later, that discharge site has grown. The insulation around it is carbonized. The partial discharge activity has intensified. The transformer is still operating—but the oil now contains dissolved acetylene at concentrations that were not there at the factory.

Here is the critical point: if DGA had been performed at the factory as part of the FAT protocol, the acetylene would have been detected before shipment. The unit could have been rejected, investigated, or rebuilt. Instead, the defect was exported to the project site, where it became a warranty claim, a production loss, and a procurement manager's problem.

This is not hypothetical. IEC 60599 and IEEE C57.104 exist precisely because the industry has learned, over decades, that electrical tests alone are insufficient. The gases tell a story that the electrical measurements cannot.

What the standards say

IEC 60599 provides interpretation guidelines for dissolved gas analysis in mineral oil-filled equipment. It defines typical gas concentration ranges for healthy transformers and identifies concentration thresholds that warrant investigation.

IEEE C57.104 complements this with a classification system based on total dissolved combustible gas (TDCG) levels and individual gas concentrations. Condition 1 indicates normal operation. Condition 4 indicates a level of gas generation that requires immediate action.

For a new transformer at the factory, the expectation is straightforward: gas concentrations should be at or near baseline levels. Hydrogen may be slightly elevated if the oil was freshly processed—degassing takes time. But acetylene should normally be absent in a new transformer. Not dismissed as "probably normal" without investigation. Not accepted without a written engineering explanation.

The presence of any acetylene (C₂H₂) in a new transformer indicates that arcing has occurred inside the unit. The arc may have been small. It may have lasted milliseconds. But it happened. And the only responsible course of action is to investigate before accepting the unit.

What to ask for in your RFQ

DGA is not on every factory's standard test list. It requires a gas chromatograph—equipment that not every production line maintains. It adds cost and time. Some manufacturers will offer to perform it if the buyer requests it. Others will resist, arguing that it is unnecessary for new equipment.

From the buyer's perspective, the calculus is different. The cost of adding DGA to a procurement specification is typically a few hundred dollars per unit—sometimes less if the manufacturer already has the equipment. The cost of discovering a latent defect after the transformer is installed: tens of thousands of dollars in downtime, replacement, and contractual penalties.

The question to ask is not "does your factory perform DGA?" The question is: "will you include a complete dissolved gas analysis—with numerical values for H₂, CH₄, C₂H₆, C₂H₄, C₂H₂, CO, and CO₂—in the FAT report for each unit in my order?"

If the answer is no, ask why.

If the answer is yes, check the acetylene line before signing.

The gas that should never appear

There is a straightforward rule that every procurement manager can apply without becoming a DGA expert: acetylene (C₂H₂) in a new transformer equals investigation required. Not "monitor and see." Not "probably nothing." Investigation.

The physics is unambiguous: acetylene forms at temperatures above 700°C. The only thing inside a transformer that reaches 700°C is an electric arc. An arc inside a new transformer means something went wrong—during assembly, during testing, or during factory handling. Whatever the cause, the buyer deserves to know before accepting the unit.

DGA cannot predict every transformer failure. No single test can. But DGA can detect the most catastrophic failure mechanism—internal arcing—before the transformer is energized, before it is shipped, before the purchase order is closed. That alone justifies its inclusion in every procurement specification.

The next article in this series examines partial discharge—the defect that DGA can hint at but cannot directly measure.

References: IEC 60599 (Mineral oil-impregnated electrical equipment in service — Guide to the interpretation of dissolved and free gases analysis). IEEE C57.104 (IEEE Guide for the Interpretation of Gases Generated in Mineral Oil-Immersed Transformers). Gas formation temperatures: H₂ from PD/corona, CH₄/C₂H₆ from low-temperature thermal faults (<300°C), C₂H₄ from high-temperature thermal faults (>300°C), C₂H₂ from arcing (>700°C). CO and CO₂ from cellulose thermal degradation. Acetylene stability in mineral oil: once dissolved, C₂H₂ does not naturally dissipate or recombine under normal operating conditions.

Related Transformer Failure and Procurement Guides

• What Kills a Transformer: The Procurement Failure Physics Hub
• Partial Discharge: The Silent Defect Hiding in Your FAT Report
• Moisture: Why Water Destroys Transformer Insulation Faster Than Overload
• Short-Circuit Withstand: The Test Most RFQs Forget
• Insulation Aging: Why Two Identical Transformers Age at Different Speeds
• Technical Library: Insulation Testing for Transformer Procurement
• Technical Library: Partial Discharge Detection Methods
• Technical Library: Transformer Insulation Aging Mechanisms

Procurement Action

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