Latest Dielectric Fluids Articles

Advancements in Dissolved Gas Analysis: Investigating Failure Cases

Advancements in dissolved gas analysis3 leverage online DGA sensors, AI-driven diagnostics, IEC 60599 models, and predictive maintenance workflows to enhance transformer condition monitoring, fault detection, and reliability through real-time trend analysis and anomaly detection.

What Are Advancements in Dissolved Gas Analysis3?

Modern DGA methods using online sensors, analytics, and standards to improve transformer fault detection.

✅ Online multi-gas sensors enable real-time transformer health insights

✅ AI models apply IEC 60599 ratios for early fault classification

✅ Cloud dashboards support predictive maintenance and compliance

INTRODUTION

Dissolved gas analysis (DGA) provides the early warning radar view of a transformer ﬂeet with a non-intrusive screening process for early identiﬁcation of problematic transformers. Suspicious transformers can be subjected to more invasive and costly physical testing to determine the actual condition and service readiness of the transformer. Three case histories illustrate the usefulness of recent innovations in transformer DGA, especially when there is gas loss. Two of the example transformers failed in service, to the surprise of the utilities responsible for them since they did not exceed conventional DGA limits. In the other case, the utility is urgently looking for a replacement unit based on very concerning DGA results. For these examples we will use some of the techniques presented earlier in this series of articles. We will also introduce some new concepts to be covered in greater detail in later articles of the series. For example, we will use cumulative gas data to compensate partially for gas loss. Gas loss occurs either by leakage or by gas blanket pressure regulation, which releases head space gas to reduce pressure and adds nitrogen to raise pressure. The IEEE C57.104 transformer DGA guide, from 1978 until the latest version in 2019 [1], has never adequately addressed the problem of gas loss, which can delay or prevent limits-based detection of fault gas production. We will also use normalized fault energy indices (NEI), which represent the energy required to generate the observed fault gases from the paper and oil insulation. This will illustrate a new paradigm for DGA interpretation, described brieﬂy in Annex F of IEEE C57.104-2019, that is less focused on gas concentrations in favor of fault energy related to defects, malfunctions, and excessive stress. Rather than display long tables of numbers, we present the DGA data for the examples graphically in the form of three stacked charts for each example. The top chart is for the hydrocarbon gas fault energy index, NEI-HC, representing fault energy aﬀecting the mineral oil. The upper trend line is cumulative NEI-HC, while the lower one is NEI-HC as calculated for each oil sample. Boxes are drawn on the cumulative NEI trend line to highlight time intervals when signiﬁcant fault gas production appears to be happening. The middle chart is for the carbon oxide gas fault energy index, NEI-CO, representing fault energy aﬀecting paper insulation in a similar fashion. The bottom chart is for the CO/CO2 gas concentration ratio as calculated for each oil sample. For background on methodology, see dissolved gas analysis fundamentals for context.

Recent industry coverage of advancements in dissolved gas analysis highlights tools that support this fault energy approach.

Example #1

The transformer in Example #1 had a long NEI-CO gassing event, suggesting gradual thermal degradation of insulating paper. The up and down motion of NEI-CO (bottom line in the NEI-CO chart) is not just noise in the data – it reﬂects fault gas production with gas loss from pressure regulation connected with thermal cycling in a hot climate and a 6-month sampling frequency. The cumulative NEI-HC trend has two distinct gassing events with IEC fault types S and O respectively, indicating thermal fault gas production below 250°C. There are corresponding large increases in the CO/CO2 ratio, suggesting charring of winding paper insulation. The method of interpreting percent changes in the CO/CO2 carbon oxide gas ratio (sometimes inverted as CO2/CO) was worked out by Chris Rutledge and Randy Cox as a way of locating the source of carbon oxide gas production [2, 3]. Large percent increases in CO/CO2 are associated with charring of winding insulation paper. Of course, degradation of winding insulation is of great interest. When this transformer tripped due to turn-to-turn arcing, it was a complete surprise to the utility. The transformer never exceeded IEEE C57.104-2008 gas concentration limits, nor did it exceed the IEEE C57.104-2019 rate of change limits. The Example #1 charts, providing evidence of continual paper degradation with two signiﬁcant episodes of a low range thermal fault aﬀecting winding insulation, would have led an experienced engineer to ﬂag this unit for investigation. The concern would be heightened by the realization that the severity of the problem may have been underestimated due to gas loss. A post-mortem revealed extensive charring of the paper winding insulation. Additional guidance on interpreting the CO/CO2 trend is summarized in CO/CO2 ratio practices for practitioners.

Example #2

The transformer in Example #2 appears to be in very precarious condition, and the utility responsible for it is planning to replace it quickly. The gassing event beginning in 2012 appeared to indicate a T2 hot spot aﬀecting both paper insulation (NEI-CO) and oil (NEI-HC). Gas loss due to pressure regulation is evident from the saw-tooth patterns in NEI-HC and NEI-CO during the event as gases were generated and lost. The cumulative NEI trends show that there was rapid fault gas production, although the true extent of it can’t be known. The percent increase in the CO/CO2 ratio at the time was extreme, suggesting that winding paper was aﬀected. Gaseous evidence of the problem dissipated in subsequent years as gas loss lowered the NEI levels and ﬂattened the cumulative NEI. Recently a new event, classiﬁed as a D1 type fault, or low-energy electrical discharge, has been active, once again aﬀecting the paper as indicated by a simultaneous rise in NEI-CO. The current hypothesis is that the fault starting in 2012 may have charred paper insulation between windings. Weak turn-to-turn discharges started later in 2018. The lack of movement in the CO/CO2 ratio during the most recent NEI event provides no information as to the location of paper involved in the recent event. If the problem is localized charring of winding paper between turns resulting in the onset of electrical sparking, CO and CO2 production would cease after the paper in that area was completely charred. Thus, the lack of recent carbon oxide gas production could be very concerning. Gas concentrations during the 2012 event only reached IEEE status code 2, soon returning back to status code 1 due to gas loss. Damage to the transformer did not magically repair itself, despite a de-escalation to a lower status code. Complementary transformer oil analysis procedures can help corroborate DGA findings during such events.

Improved sampling, screening, and lab controls described in advancements in DGA data quality strengthen trending when gas loss complicates interpretation.

Example #3

The Example #3 transformer had a persistent T2 thermal problem with long, steady NEI-HC and NEI-CO trends. In 2013, the NEI-HC trend accelerated sharply, indicating that something may have changed for the worse. For a while, acetylene production changed the fault type to a D1 electrical discharge. The gases other than acetylene remained below IEEE C57.104-2008 limits. Later the acetylene dissipated as the original trend resumed. The NEI-CO graph indicates that starting in 2013 there was an accelerating rate of change in cumulative NEI-CO leading up to the time of failure. The sawtooth pattern in the measured NEI-CO during that time can be attributed to gas blanket pressure regulation. Just as the unit reached status level 2 by exceeding the IEEE C57.104-2008 heat gas limits, the unit failed. The transformer never reached status level 3 except for the bump in acetylene during the 2013 event. The CO/CO2 ratio did not change much since 2006. It is likely that CO loss via gas blanket pressure regulation was suﬃcient to keep the CO/CO2 ratio relatively constant even though, as the upward trend in NEI-CO indicates, there was signiﬁcant production of carbon oxide gases. Thus, in this case DGA did not provide any indication of whether winding paper insulation was being aﬀected by the T2 and D1 faults. The fact that the transformer failed while NEI-CO was accelerating permits us to suspect that the problem was located in the windings, speciﬁcally on the outer layers where oil can circulate. Understanding oil behavior in transformers clarifies how thermal faults drive hydrocarbon gas trends.

Conclusions
The way of interpreting DGA demonstrated above requires tracking fault energy aﬀecting liquid and solid insulation over the whole history of the transformer. Data management and good data quality are extremely important for early detection and accurate assessment of problems. DGA results for the most recent one or two oil samples are not suﬃcient to detect or diagnose the problems discussed in the above examples. These case histories show that waiting for a 90th percentile outlier in the DGA data is not a dependable method for identifying transformers in trouble. Waiting to see large concentrations or rates of increase of gas in any transformer before reacting is like waiting to read the license plate before getting out of the way of an oncoming car. Gas loss can keep gas levels and rates of change deceptively low, even when there is signiﬁcant production of fault gas. A DGA report is a snapshot of an evolving and dynamic process, like a frame of a movie. To understand the current results properly, it is necessary to consider them in the context of as many past results as possible. The outcome of DGA interpretation is an assessment of whether the transformer appears to be producing fault gas, and if it does, to support further investigation or action by trying to guess the nature of the problem and assess risk. Usually DGA cannot provide a deﬁnite verdict on the transformer’s condition except to say whether or not it is gassing. That is reﬂected in the change of language in IEEE C57.104-2019, which has “status” codes instead of “condition” codes. For reliable information about a transformer’s condition, physical testing is usually required. In future articles, we will discuss the CO/CO2 ratio in more detail. We will also discuss severity assessment for gassing events and hazard factors for quantitative risk assessment. A grounding in fundamental dielectric characteristics also helps connect observed gases to insulation physics.

References.

“IEEE Guide for the interpretation of gases dissolved in mineral oil ﬁlled transformers,” IEEE Std C57.104, editions 1978, 1991, 2008, and 2019.
C. Rutledge and R. Cox, “A comprehensive diagnostic evaluation of power transformers via dissolved gas analysis,” 2016 IEEE/PES Transmission and Distribution Conference and Exposition (T&D), Dallas, TX, 2016, pp. 1-5, doi: 10.1109/TDC.2016.7519996.
R. Cox, ‘“Categorizing Faults in Power Transformers via Dissolved Gas Analysis,” NETA World Journal, Spring 2020, pp. 64–68.

Dielectric Fluid Channel

Transformer Insulating Oil

Transformer Insulating Oil provides dielectric insulation, arc suppression, and cooling for power transformers, improving efficiency, preventing electrical faults, reducing downtime, and ensuring reliable high-voltage system performance in energy distribution networks.

What is Transformer Insulating Oil?

Transformer insulating oil is a vital fluid that plays a crucial role in the reliable and efficient operation of electrical power systems.

✅ Provides electrical insulation and suppresses arcing between components

✅ Dissipates heat to prevent transformer overheating and failure

✅ Protects against moisture, oxidation, and other contaminants

It serves as the lifeblood of power transformers, providing essential insulation, cooling, and arc-quenching properties. A deep understanding of the fluid's characteristics, functions, and maintenance requirements is essential for electrical engineers, technicians, and maintenance professionals to ensure the optimal performance and longevity of these critical components. To learn more about the role of dielectric fluids in transformer insulation and cooling, visit our main page on Dielectric Fluids.

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The essential role of transformer insulating oil in electrical power distribution systems cannot be overstated. This insulating fluid plays a vital role in ensuring transformers' efficiency, safety, and longevity. It is a crucial insulating material that supports electrical stability while also providing thermal management and arc-quenching capabilities. Without it, transformers would face higher risks of failure, overheating, and electrical breakdowns. For insight into cutting-edge techniques for fault detection, see our detailed guide on Advancements in DGA Data Quality.

One of the most critical aspects of this kind of dielectric fluid is its ability to act as an excellent electrical insulating medium. By filling the space around the core and coils, it prevents electrical arcing and ensures a high dielectric strength. This high dielectric strength is essential for maintaining insulation integrity under high-voltage conditions. The breakdown voltage of the insulating fluid must be tested regularly to ensure it retains its insulating properties. Testing procedures, such as dielectric strength testing and dissolved gas analysis (DGA), are used to identify potential issues and help maintain service life. Discover how dissolved gas patterns reveal transformer health in our technical article on Advancements in Dissolved Gas Analysis.

The properties of a dielectric fluid vary depending on its type. Mineral oil remains one of the most widely used types of transformer dielectric fluid due to its affordability, availability, and decent insulating performance. However, it’s not the only option. Synthetic ester oils offer a more sustainable and fire-resistant alternative. These oils have a high fire point, making them safer for use in sensitive environments where fire hazards must be minimized. Silicone-based dielectric fluids, on the other hand, are known for their ability to remain stable at high temperatures, offering an advantage in environments with extreme heat.

Insulation and Cooling

Another critical role of transformer insulating oil is heat dissipation. The design of transformers enables efficient heat transfer, allowing the insulating fluid to absorb and dissipate heat generated by the core and coils. This heat management is crucial for extending the service life. An essential property that supports this function is the pour point of the fluid, which ensures it remains fluid even at low temperatures. Fluid with a low pour point maintain fluidity, ensuring effective heat dissipation in colder climates. Dive deeper into diagnostic gas trends with our exploration of CO/CO₂ Ratio Analysis as an indicator of cellulose insulation degradation.

Arc Quenching and Oxidation Resistance

Regular transformer testing and maintenance are essential to maintaining the effectiveness of dielectric fluids. Filtration and purification are critical to remove contaminants, moisture, and gases that accumulate over time. Oxidation stability is one of the most important factors influencing the service life of the fluid. When oxidation occurs, it can form acids and sludge, which degrade the dielectric fluid's insulating properties and reduce its effectiveness. Regular filtration processes ensure the insulating oil remains pure and retains its excellent electrical insulating capabilities.

Testing and Maintenance

Regular testing and maintenance are essential to maintaining optimal performance and reliability. Dielectric strength testing measures the dielectric fluid's ability to withstand electrical stress, while dissolved gas analysis (DGA) identifies potential faults within the unit by analyzing the gases dissolved. Fluid filtration and purification techniques remove contaminants and moisture, prolonging the dielectric fluid's service life.

Types of Transformer Oil

Various types are available, each with its own specific characteristics. Mineral oil, a traditional choice, is derived from petroleum and offers a balance of performance and cost-effectiveness. However, it is susceptible to fire and environmental concerns. To address these issues, synthetic ester oils have emerged as a superior alternative. These dielectric fluids exhibit excellent fire resistance, high dielectric strength, and superior oxidation stability. They are also environmentally friendly and biodegradable. Silicone oil, another synthetic option, offers exceptional thermal stability and arc-quenching properties, making it suitable for high-temperature applications.

Environmental Impact and Safety

Environmental sustainability has also become a key consideration in the selection and management of dielectric fluid. Traditional mineral oil has environmental drawbacks, such as limited biodegradability and disposal challenges. Biodegradable types, such as synthetic ester oils, are now being used as environmentally friendly alternatives. These dielectric fluids offer the dual benefits of reducing environmental impact and providing high fire resistance. Moreover, responsible recycling and disposal practices for used transformer fluids are mandated by regulatory compliance standards to protect the environment.

Safety is a paramount concern when dealing with dielectric fluid. As the dielectric fluid circulates inside, it’s crucial to understand the risks associated with fire hazards. The flash point of a dielectric fluid is a key indicator of its fire resistance. Dielectric fluids with a high fire point are preferred in applications where fire safety is a priority. Emergency response procedures must also be established in the event of spills or leaks, ensuring that spills are contained quickly to prevent environmental contamination. Additionally, health and safety measures are critical for workers handling dielectric fluid. Direct exposure can pose health risks, requiring protective equipment and following established handling protocols. For additional context on cooling mechanisms and thermal performance, read our article on Transformer Cooling and Dielectric Fluids.

Frequently Asked Questions

What is another name for transformer oil?

Another name is insulating or dielectric fluid. It is also sometimes referred to as dielectric fluid because of its role as a dielectric material that prevents electrical discharges inside. In specific contexts, names like mineral-insulating dielectric fluid or ester-based insulating dielectric fluid may be used to specify the type of oil used.

Can I use transformer oil on my skin?

No, it is not recommended to use dielectric dielectric fluid on your skin. This oil is not designed for human contact and may contain chemical additives, contaminants, or degradation products that can irritate the skin. Prolonged exposure to certain types of mineral oil can pose health risks. Any exposure should be washed off immediately with soap and water for health and safety reasons.

What is the real name of transformer oil?

The real name depends on its composition. Most dielectric fluids are referred to as mineral insulating oil or naphthenic mineral oil. Biodegradable alternatives may be called natural ester insulating dielectric fluid or synthetic ester insulating oil. For example, common mineral oil used is a type of naphthenic oil, while modern, environmentally friendly units may use ester-based oils.

Transformer dielectric fluid is a vital component in electrical power distribution, playing a central role in insulation, cooling, arc quenching, and overall safety. The choice of dielectric fluid—whether mineral, synthetic ester, or silicone—depends on application requirements, safety considerations, and environmental impact. Regular testing, maintenance, and proper disposal methods ensure its continued performance and compliance with regulatory standards. By maintaining oxidation stability and leveraging dielectric fluids with a high fire point, operators can ensure the longevity and safety in various industrial and commercial settings.

Transformer Cooling

Transformer cooling enhances thermal management via oil-immersed and air-cooled systems, radiators, fans, and pumps. Methods like ONAN, ONAF, and OFAF reduce temperature rise, limit insulation aging, and improve efficiency under varying load.

What Is Transformer Cooling?

Transformer cooling removes heat from windings and core via oil or air circulation to control temperature and slow aging.

✅ Common types: ONAN, ONAF, OFAF, OFWF for various ratings.

✅ Components: radiators, fans, oil pumps, heat exchangers.

✅ Benefits: lower temperature rise, higher efficiency, longer life.

A little energy lost in a transformer must be dissipated as heat. Although this energy is but a small portion of the total energy undergoing transformation, it becomes quite large in amount in transformers of larger kVA ratings. To maintain efficiency and life expectancy the transformer's cooling system needs to be operating at peak performance. For dry-type transformers, the ventilation system of the room should be inspected to make sure it is operating efficiently. For forced air-cooled systems, the fan motors should be checked for proper lubrication and operation. Water-cooled systems must be tested for leaks and proper operation of pumps, pressure gauges, temperature gauges and alarm systems.

In liquid-filled designs, the choice and maintenance of oil in transformers directly influence heat removal performance and long-term reliability.

When a liquid coolant is used its dielectric should be tested. Water in the coolant will reduce its dielectric strength and the insulation quality. In cases where the dielectric strength of the coolant is reduced significantly, conducting arcs may develop causing short-circuits when the transformer is energized. A standard oil dielectric test involves applying high voltage to a sample taken from the transformer and recording the voltage at which the oil breaks down. If the average breakdown voltage is less than 20 kilovolts, the oil will need to be filtered until a minimum average breakdown of 25 kilovolts is achieved. Technicians often reference breakdown voltage of oil guidelines to interpret test results and schedule remediation.

Comprehensive transformer oil analysis can reveal moisture ingress, dissolved gases, and particulate contamination before failures occur.

Oil-insulated transformers use mineral oil for cooling. This oil is thin enough to circulate freely and does a good job of providing insulation between the transformer windings and the core. It is however subject to oxidation and if any moisture enters the oil, its insulating value is substantially reduced. In addition, mineral oil is flammable and therefore should not be located near combustible materials indoors or outdoors. In critical applications, selecting a high-quality transformer insulating oil mitigates oxidation, moisture effects, and thermal aging.

These behaviors align with the fundamental dielectric characteristics that govern insulation performance under electrical and thermal stress.

There are several types of transformer oil cooling solutions:

oil air
forced oil
oils water
oil natural
air forced
heated oil
oil forced
natural

In practice, each configuration must be evaluated alongside the properties of the chosen dielectric fluid to balance cooling effectiveness, safety, and service life.

Outdoor liquid-cooled transformers usually use mineral oil, and liquid cooled transformers for inside use are filled with a synthetic liquid that is nonflammable and nonexplosive. Synthetic oil coolants must be handled with care as they sometimes cause skin irritations. One type, askarelinsulated transformers used in past years contained polychlorinated biphenyls (PCBs), which are known to cause cancer. Askarel has been banned by the Environmental Protection Agency and its use as a transformer coolant is being phased out. However, askarel coolants are still found throughout the electrical industry in older transformers and direct contact with them should be avoided. The NEC still contains provisions for installing askarel transformers. The following is a list of the different types of liquid-filled transformers recognized by the NEC:

Facility engineers should review application requirements, fire codes, and material compatibility when selecting oil for transformers to ensure compliance and dependable operation.

Oil-Insulated--uses chemically untreated insulating oil
Askarel—uses nonflammable insulating oil
Less-Flammable Liquid-Insulated--uses reduced flammable insulating oil
Nonflammable Fluid-Insulated--uses noncombustible liquid

Dielectric Fluid Channel

Advancements in Dissolved Gas Analysis Explained

Advancements in dissolved gas analysis2 deliver smarter transformer condition monitoring, predictive maintenance, and fault diagnostics via online sensors, IEC 60599 methods, Duval Triangle analytics, and machine learning for grid reliability.

What Are Advancements in Dissolved Gas Analysis2?

Modern DGA methods using online sensors, IEC standards, and AI to diagnose transformer faults proactively.

✅ Real-time gas monitoring via online chromatographs and sensors

✅ AI and Duval Triangle enhance fault classification accuracy

✅ Standards-based analysis per IEC 60599 supports maintenance

One of the most important steps when looking at DGA data is to decide whether the data support the existence of a fault that is actively breaking down the insulation before you try to use a triangle, pentagon, or gas ratio method to identify a fault type. Otherwise, you are diagnosing random measurement noise, not the transformer. Conventional methods assign limits to each of the gases to detect and assess abnormal gas formation. Formerly it was common practice to add gas concentrations together to get total dissolved combustible gas (TDCG). The hope was to simplify the task of detecting abnormal gas production and interpreting rates of change. This, however, was equivalent to counting U.S. Dollars, Mexican Pesos, Bitcoins, and Canadian Loonies and thinking that the sum represented “value”. To reduce false positives from sensor drift and sampling errors, recent work on advancements in DGA data quality outlines practical controls for sampling, calibration, and trending.

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Chemistry dictates that each gas we observe requires a different amount of energy to break away from the original insulating material. Instead of trying to interpret several individual gas concentrations, why not follow the energy associated with the gassing? The energies required to form the gas can be weighted by the gas concentrations and added up.

For a grounding in principles and typical fault signatures, see this overview of dissolved gas analysis techniques and their diagnostic use.

This idea of using standard heats of formation of fault gases for DGA was worked out in Jakob et al. 2012 and demonstrated to be an improvement compared to TDCG and other gas concentration sums. Soon after that, chemist Fredi Jakob realized that it would be better to create a fault energy index, which he called normalized energy intensity (NEI), to represent the influence of an internal fault on the insulating oil. That idea was presented in Jakob & Dukarm 2015, where it was shown that NEI was very useful for trending fault severity and not partial to any particular fault types. The figure illustrates how trending cumulative NEI simpli.es the detection of suspicious gas production. For additional context on modern interpretation frameworks, review these advancements in dissolved gas analysis that compare energy-based indices with classical ratio methods.

NEI, now renamed NEI-HC, is based on the low molecular weight hydrocarbon gases generated from cracking mineral oil. Another fault energy index, called NEI-CO, is based on the carbon oxide gases formed by pyrolysis of cellulose in paper insulation. The formulas for NEI-HC and NEI-CO are shown in Equations (1) and (2) below. Since each set of gases comes from a different insulation material, you can assess and track which faults are affecting paper, hot metal in the oil, or both. That knowledge can help point to the root cause and better estimate the severity of the problem. When paper degradation is suspected, trends can be corroborated with guidance on the CO/CO2 ratio in DGA to strengthen evidence for thermal versus oxidative effects.

Because NEI-HC derives from oil cracking, selecting and maintaining a high-quality transformer insulating oil is essential for resilient performance under thermal stress.

NEI-HC = 77.7[CH4] + 93.5[C2H6] + 104.1[C2H4] + 278.3[C2H2] / 22400 (1)
NEI-CO = 101.4[CO] + 30.19[CO2] / 22400 (2)

The highest heat of formation for the hydrocarbons is C2H2 and for carbon oxides it is CO. This physically confirms the general intuition that these gases are the most concerning to see in transformer DGA. These concerns underscore why routine transformer oil analysis remains central to risk-based maintenance planning.

You can trend fault energy indices to identify gassing episodes and relate them to external events such as through faults, maintenance work orders, and load changes to help determine what might have triggered the gassing. Also, you can track the cumulative energy over the history of the transformer to counteract effects of gas-loss (see previous article in this series). Interpreting those trends alongside the unit's fundamental dielectric characteristics helps differentiate benign load-related gassing from insulation distress.

Dielectric Fluid Channel

Dissolved Gas Analysis Of Transformer Oil

Dissolved Gas Analysis (DGA) is a key diagnostic tool for transformers, evaluating dissolved gases in insulating oil to identify overheating, arcing, partial discharge, and insulation breakdown. It enables predictive maintenance, improves power system reliability.

What is Dissolved Gas Analysis?

Dissolved Gas Analysis is a diagnostic method that evaluates gases in transformer insulating oil to identify electrical faults and ensure reliable operation.

✅ Detects partial discharge, arcing, and overheating

✅ Guides predictive maintenance and fault prevention

✅ Improves transformer reliability and system safety

DGA is a crucial tool for electrical engineering and maintenance professionals, providing vital insights into the health of transformers and other high-voltage assets. By detecting gases produced during insulation degradation or electrical faults, it offers early warning signs of potential failures. Proactive detection through DGA allows utilities and industries to prevent unplanned outages, extend equipment lifespan, and strengthen system reliability. As a cornerstone of condition-based maintenance, mastering DGA is essential for maintaining high-performance electrical infrastructure. Understanding dissolved gas analysis begins with the role of dielectric fluids, as the composition of transformer oil directly influences gas formation and the accuracy of fault detection.

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Transformer Fault Diagnosis

One of the key applications of DGA is transformer fault diagnosis. Under normal operating conditions, only trace gases form. During faults, such as partial discharge or arcing, heat and stress decompose insulating oil and cellulose, generating gases such as hydrogen, methane, ethane, ethylene, acetylene, carbon monoxide, and carbon dioxide.

Hydrogen (H₂): partial discharges
Methane (CH₄): low-temperature overheating of cellulose
Ethane (C₂H₆) and Ethylene (C₂H₄): higher-temperature thermal faults
Acetylene (C₂H₂): arcing
CO and CO₂: insulation paper degradation

The concentration and ratio of these gases provide a fingerprint of the fault type. Experts can distinguish between thermal faults, partial discharge, and severe arcing, enabling timely maintenance. New research highlights advancements in DGA data quality, improving reliability and reducing errors in transformer fault diagnosis.

Interpretation Methods and Fault Classification

Accurate interpretation is central to DGA. Several methods have been standardized:

Ratio Methods: Rogers and Doernenburg use gas concentration ratios to classify fault types.
Duval Triangle / Pentagon: graphical techniques plotting gas ratios (e.g., H₂:CH₄:C₂H₆) to identify fault zones (partial discharge, low/high thermal faults, arcing).
IEC 60599 and IEEE C57.104 Standards: provide threshold limits, diagnostic ratios, and guidelines for reporting and action.

Example: Using the Duval Triangle, a mixture rich in acetylene indicates arcing, while high ethylene levels suggest a high-temperature thermal fault.

Emerging methods, such as fuzzy logic and expert systems, refine interpretation when faults overlap, thereby enhancing the accuracy of fault detection. AI and machine learning now enhance accuracy, reducing misclassification in complex cases. Engineers applying DGA can benefit from recent advancements in dissolved gas analysis, which refine fault classification methods through better interpretation of gas ratios.

Case Study Example

A 230 kV transformer recorded abnormal gas levels:

H₂ = 750 ppm
CH₄ = 120 ppm
C₂H₆ = 40 ppm
C₂H₄ = 260 ppm
C₂H₂ = 15 ppm
CO = 900 ppm

Interpretation: The high hydrogen, ethylene, and carbon monoxide levels suggest a high-temperature thermal fault with cellulose insulation degradation. Using the Duval Triangle, this case falls into a “thermal fault >700°C” zone. Preventive maintenance avoided catastrophic failure. Specialists often review the CO/CO₂ ratio in dissolved gas analysis, since carbon gases provide unique insights into cellulose insulation degradation.

Predictive Maintenance

Predictive maintenance is another significant advantage of DGA. Since transformers are essential but costly assets, unplanned downtime can be financially devastating. Through DGA, utilities and industrial operators can predict when maintenance is required, rather than reacting to sudden failures. DGA monitors provide real-time tracking of gas concentrations, enabling maintenance teams to act before a minor issue becomes a major outage.

DGA shifts maintenance from a reactive to a predictive approach. By monitoring gas concentration trends, utilities can:

Predict when interventions are needed
Extend transformer service life
Reduce operational costs and outages

Continuous monitoring ensures that problems are addressed before they escalate into system failures. By pairing dissolved gas analysis with condition monitoring in an age of modernization, utilities can transition from reactive repairs to predictive maintenance strategies.

Gas Chromatography

DGA relies on gas chromatography, which separates and quantifies individual gases. A sample of insulating oil is processed to measure the concentrations of hydrogen, methane, ethane, ethylene, acetylene, carbon monoxide, and carbon dioxide in parts per million (ppm). This precision enables consistent results across laboratories and forms the foundation of DGA reporting. Gas concentrations revealed through DGA provide insights that complement power transformer health check programs, ensuring reliable performance of these critical assets.

IEC Standards and Key Gases

International Electrotechnical Commission (IEC) standards play a pivotal role in ensuring consistency and accuracy in dissolved gas analysis. These standards provide guidelines for the collection, handling, and analysis of oil samples, as well as for the interpretation of results. By following IEC standards, utilities and maintenance teams can achieve more reliable and comparable DGA results across different transformers and facilities. This uniformity helps ensure that decisions regarding maintenance and repair are based on accurate, standardized data.

Key gases such as hydrogen, methane, ethane, ethylene, and acetylene are essential to understanding the types of transformer faults. For example, the presence of acetylene often points to arcing, while ethylene and ethane are indicators of high-temperature thermal faults. Hydrogen is commonly associated with partial discharge, while methane is linked to overheating of cellulose insulation. Recognizing the role of these key gases allows technicians to identify specific transformer problems, prioritize maintenance, and avoid costly failures.

International standards ensure consistency.

IEC 60599: guidance on sampling, analysis, and interpretation.
IEEE C57.104: fault classification tables and gas thresholds.

Example gas thresholds (ppm):

Gas	Normal	Caution	Dangerous
Hydrogen (H₂)	<100	100–700	>700
Acetylene (C₂H₂)	<1	1–10	>10
Ethylene (C₂H₄)	<50	50–200	>200

Limitations and Caveats

While powerful, DGA has limits:

Cannot localize the exact fault location
Oil replacement can reset the gas history
Mixed faults produce ambiguous results
Stray gassing may occur at low temperatures
Sampling and handling errors can skew results

DGA should complement other diagnostics, such as dissolved moisture analysis, partial discharge monitoring, or infrared thermography. Dissolved gas analysis also supports the broader maintenance of substation transformers, where continuous monitoring is essential to preventing costly power disruptions.

Real-Time Monitoring

DGA monitors are essential tools for continuous tracking of gas levels in transformer oil. Unlike periodic sampling, DGA monitors operate in real-time, offering immediate insight into any changes in dissolved gases. By continuously observing gas concentrations, operators gain a deeper understanding of the transformer's condition, enabling swift responses to abnormal readings. Continuous tracking helps utilities maintain system reliability and prevent emergency shutdowns.

Online DGA monitors provide continuous tracking of gas levels, feeding data into SCADA and asset management systems. Unlike periodic lab sampling, online systems detect rapid changes, offering:

24/7 protection for critical transformers
Faster fault detection and intervention
Integration with predictive analytics dashboards

Though more costly, real-time systems are invaluable for utilities managing large fleets of high-value transformers.

Advanced Analytics and AI

Recent research applies machine learning and deep learning to improve DGA interpretation. Models such as convolutional neural networks (CNNs), ensemble classifiers, and copula-based correlation methods identify fault patterns with greater accuracy. Studies (2023–2025, Nature, MDPI, arXiv) show AI can detect stray gassing and overlapping fault signatures earlier than classical methods. Combining traditional ratios with AI enhances both precision and reliability.

Frequently Asked Questions

When should transformers be retested with DGA?

Typically, every 6–12 months for routine testing, but more frequently if abnormal gas levels are detected or if online monitors show sudden changes.

How do you choose a DGA monitor?

Consider transformer criticality, cost, required gases, calibration frequency, and SCADA compatibility.

What is the minimum oil sample size?

About 50–100 mL is typically required for laboratory gas chromatography.

What role does cellulose insulation play in gas generation?

Breakdown of cellulose produces CO and CO₂, indicating paper degradation in addition to oil fault gases.

Can DGA predict all failures?

No. While highly effective, it should be combined with other diagnostics for complete transformer condition monitoring.

Advancements in Dissolved Gas Analysis: Data Quality

Advancements in DGA data quality enable precise transformer monitoring, dissolved gas analysis, and predictive maintenance through calibrated sensors, IEC 60599/IEEE C57.104 harmonization, machine-learning analytics, anomaly detection, and IEC 61850-integrated SCADA data integrity.

What Are Advancements in DGA Data Quality?

Enhanced DGA data quality strengthens transformer diagnostics via calibrated sensors, aligned standards, and analytics.

✅ On-line oil monitors with auto-calibration and drift correction

✅ IEC 60599/IEEE C57.104 harmonized thresholds and diagnostics

✅ ML-based anomaly detection and condition-based maintenance

Introduction
There is more to DGA interpretation than comparing the latest gas concentrations to limits in a table or plotting them in a triangle or pentagon to identify the apparent fault type. We have found that the whole DGA history of a transformer must be considered when interpreting its most recent DGA results.
Trend evaluation and accurate assessment of short-term changes require accuracy and low measurement variability of gas data. Data quality problems must be recognized and dealt with before an interpretation is attempted. Below we point out some of the most common data quality issues. For broader context on diagnostics, the primer on dissolved gas analysis outlines core fault signatures, typical gas sources, and interpretation pitfalls.

Understanding how oil and paper behave electrically is foundational, and the summary of fundamental dielectric characteristics helps explain why certain gases trend together over time.

Data management
As a result of the historical importance of DGA data, proper organization and preservation of DGA data are extremely important. In addition to archiving the lab reports, keep the data in tabular form in a database or, for small volumes of data, a spreadsheet. A well-organized database supports sorting and filtering for graphical and statistical analysis.
Use a unique and permanent ID to identify transformers, oil compartments, and the oil sample data belonging to them. Substation and unit number are not a suitable ID, for the same reason that the dentist doesn’t identify you by your department and job title. Large transformer fleets may require company-assigned asset numbers to avoid possible serial number duplication across manufacturers.
Disciplined chain-of-custody practices provide correct IDs of transformers and compartments to be sampled, ensure that oil samples are labeled correctly, and guarantee that analysis results returned by the lab are attributed to the right transformers and oil compartments. Integrating laboratory reports with a structured repository is easier when guided by practical notes on transformer oil analysis data formats and decision thresholds.

For sampling logistics and labeling discipline, operations teams can review guidance on oil in transformers to align maintenance practices with data management goals.

Data inconsistency or inaccuracy
Gas loss that is deliberate, such as by head space pressure regulation or use of a desiccant breather, needs to be accounted for as discussed in our other article [1]. Unintended gas leakage from a transformer – often detectable by a O2/N2 ratio persistently above 0.2 when it should be lower – should be remedied as soon as possible, both to keep DGA effective and to prevent moisture ingress. After oil degassing, it is advisable to exclude samples from DGA interpretation for 6-12 months due to the false upward trends created by diffusion of gases from winding paper into the bulk oil.
Accuracy and repeatability of gas data are only partly up to the laboratory. Unrepresentative oil samples can lead to inconsistent and highly variable gas data regardless of the quality of laboratory measurements. A study by a large USA electric utility [2] shows that using extra care and a moisture / temperature probe to ensure collection of representative oil sample can reduce data variability considerably. The figure (Figure 1) illustrates the effect of moderate variability (±15%) versus high variability (±35%) on the data from a basic S-shaped gassing event.
Moderate variability is experienced with consistently good sampling practice and a good laboratory. High variability is easily attainable if there is a problem with sampling practices. Recent field case studies on advancements in dissolved gas analysis discuss accounting for gas loss, diffusion effects, and sampling bias.

When evaluating short-term changes following maintenance, further techniques described in advancements in DGA interpretation can reduce false alarms by emphasizing trend shape over single-point limits.

The table provides a summary of some common data quality problems. Sections 5.1 and 5.2 of IEEE C57.104-2019 [3] contain a detailed discussion of data quality assessment. For paper-aging diagnostics specifically, insights on the CO/CO2 ratio in DGA clarify when cellulose decomposition is the likely source.

References
[1] “Advancements in Dissolved Gas Analysis: Accounting for Gas Loss,” Electricity Today, March 2020
[2] T. Rhodes, “Using field moisture probes to ensure drawing a representative oil sample,” in 82nd Annual International Doble Client Conference, Doble Engineering Company, March 2015.
[3] “IEEE Guide for the interpretation of gases dissolved in mineral oil filled transformers”, IEEE Std C57.104-2019.

Dielectric Fluid Channel

Oil in Transformers - An Insulating Medium

Oil in transformers plays a critical role as a cooling and insulating medium which directly impacts the efficiency, performance, and lifespan, which are essential components of the power grid. Understanding its properties, maintenance requirements, and failure indicators can help professionals prevent costly outages and enhance grid reliability. Let's explore the key functions of dielectric fluid, common issues such as contamination and aging, and best practices for testing and maintenance, equipping readers with the knowledge to optimize device performance and safety.

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The Dual Function of Transformer Oil

The primary function of transformer-based oils is to provide both insulation and cooling. As the device operates, heat is generated from the core and coils due to electrical losses. Device liquid, typically filled with mineral oil or similar insulating fluid, absorbs this heat and dissipates it efficiently, thus preventing overheating. Moreover, it serves as an insulating material, maintaining the dielectric strength required for safe operation. The high dielectric strength of the liquid prevents electrical arcing or short circuits between components within the device, ensuring that the unit functions reliably. This dual-purpose function of the oil contributes significantly to the device’s ability to operate for extended periods without failure, reducing the risks of overheating and electrical faults.

Electrical insulating materials play a crucial role in maintaining the efficiency and safety of transformers by managing heat from the core and coils. Among the most commonly used materials, paper insulation provides effective thermal and electrical resistance, ensuring stable performance under operational stresses. Solid insulation, such as epoxy or resin-based materials, complements paper insulation by adding structural integrity and resistance to mechanical and thermal degradation. Together, these insulating systems work to optimize heat dissipation and prevent electrical faults, safeguarding equipment longevity and reliability.

Types of Transformer Oils

However, not all device oils are created equal. There are two main types of fluids used in devices: uninhibited oil and inhibited oil. Uninhibited liquid lacks additives that can slow down its natural degradation, making it more prone to breakdown over time. On the other hand, the inhibited liquid is enhanced with oxidation inhibitors that increase its resistance to degradation. This makes the inhibited liquid ideal for modern devices, where long-term stability and performance are crucial. As devices continue to serve in industrial and power distribution systems, the type of fluid used in each unit plays a direct role in its efficiency, lifespan, and overall environmental impact.

The Importance of Regular Testing and Quality Assessment

When it comes to device liquid, regular testing is essential to ensure that it maintains its properties over time. One of the most critical tests conducted is the dielectric breakdown voltage test, which measures thermal conductivity and the liquid's ability to withstand electrical stress without breaking down. This test ensures that the liquid can continue to insulate effectively under high-voltage conditions. Another important analysis is the Dissolved Gas Analysis (DGA), which detects gases dissolved in the liquid. The presence of certain gases can indicate internal faults, such as overheating or arcing, which could lead to a device failure. By performing regular tests, maintenance teams can identify potential issues early and take corrective action before they escalate into significant problems.

Environmental Considerations and the Shift Toward Sustainable Oils

Environmental considerations also come into play when selecting liquid for the device. Traditional mineral oils, while effective, pose certain environmental risks, such as fire risk and potential toxicity in the event of spills. As a result, alternative, environmentally friendly options, such as natural esters, are gaining popularity. These bio-based liquids and dry type transformers are derived from renewable sources and offer better biodegradability, making them a more sustainable option compared to conventional mineral oils. Additionally, their higher flash point reduces the fire risk associated with device operation, further contributing to the safety of electrical installations. However, while natural esters present a promising alternative, their adoption is still growing, and they are not yet as widespread as mineral oils.

Maintenance and Purification of Transformer Oil

As with any fluid used in electrical equipment, device liquid requires periodic maintenance and purification. Over time, device liquid can deteriorate due to oxidation, external contamination, or electrical stress breakdown. To ensure that the liquid retains its properties, purification techniques such as filtration or vacuum treatment are employed. These methods remove contaminants and restore the liquid’s insulating properties, helping to extend the life of the device. By maintaining the quality of the insulating liquid, power companies can avoid costly repairs and ensure that their devices continue to function efficiently for years.

Frequently Asked Questions

Which oil is used in the transformer?

The liquid used in devices is typically a type of mineral oil, which is specifically refined and treated to meet the insulating and cooling requirements of devices. However, natural esters, which are derived from renewable plant sources, are increasingly used as an environmentally friendly alternative. These liquids are selected for their high dielectric strength (the ability to resist electrical breakdown) and their ability to dissipate heat efficiently from the device's internal components.

What is the oil inside a transformer?

Oil filled transformers are dielectric fluid, meaning it does not conduct electricity and serves primarily to insulate the electrical components from each other. This liquid helps prevent electrical arcing and short circuits. In addition to its insulating properties, the insulating oil also acts as a cooling agent, absorbing and dissipating heat generated by the electrical currents passing through the device's core and coils. The liquid helps maintain the device at a safe operating temperature, preventing overheating and damage to the internal components.

How to maintain transformer oil?

To maintain liquid, regular testing is essential to monitor its dielectric strength, moisture content, and dissolved gases, which can indicate internal issues. Filtration and vacuum treatment help purify the liquid by removing contaminants like sludge, moisture, and gases. Monitoring liquid levels is crucial to ensure proper insulation and cooling while addressing leaks or evaporation. Over time, liquid may need to be replaced or upgraded, especially if it has degraded or become contaminated. By following a routine maintenance schedule, including inspections and necessary treatments, device liquid can be kept in optimal condition, ensuring the device operates safely and efficiently.

What happens if there is no oil in a transformer?

If a device runs without liquid or if the liquid level becomes too low, several critical problems can occur. The device would lack the necessary insulation and cooling properties provided by the liquid. Without adequate insulation, electrical arcing could occur, leading to short circuits or even fires. Additionally, the device would overheat because there would be no liquid to absorb and dissipate the heat generated by the electrical currents. Overheating can damage the device’s internal components, reduce its efficiency, and ultimately lead to the complete failure of the device. Therefore, maintaining an adequate liquid level is essential for a device's safe and efficient operation.

Oil in devices plays a critical role in both insulation and cooling, ensuring the efficient operation and longevity of the device. It acts as an insulating fluid, preventing electrical faults by maintaining a high dielectric strength, and absorbs heat generated during operation, preventing overheating. Equipment liquid can be mineral liquid or natural esters, with the latter being an environmentally friendly alternative. Regular maintenance, including testing for dielectric strength, moisture, and dissolved gases, along with purification methods like filtration and vacuum treatment, is necessary to keep the liquid effective. Proper oil management helps extend device lifespan, reduce risks of failure, and ensure safe, reliable operation in electrical systems.