Latest Dielectric Fluids Articles

Advancements in Dissolved Gas Analysis CO CO2 Ratio optimize transformer diagnostics with machine learning, IEC 60599 interpretation, insulation aging assessment, fault detection, and predictive maintenance for condition monitoring of power transformers.

What Are Advancements in Dissolved Gas Analysis CO/CO2 Ratio for Transformer Diagnostics?

New methods refine CO/CO2 ratio interpretation using ML, online sensors, and IEC 60599 to assess paper aging.

✅ CO/CO2 thresholds aligned with IEC 60599 and IEEE C57.104

✅ Online DGA sensors and digital twins for real-time aging insights

✅ Machine learning models correlate ratios with DP and hot-spot temp

For DGA interpretation, faults identified using hydrocarbon gases are considered more serious if they appear to affect paper insulation. That is made explicit in CIGRE technical brochure 771 [1]. Production of hydrocarbon gases from the oil by electrical or thermal stress does not significantly affect the oil’s function as a coolant or electrical insulator. On the other hand, production of carbon oxide gases from paper insulation raises a concern of paper deterioration. In particular, charring of the paper by a localized hot spot, especially in the windings, can lead to transformer failure.
Recently R. Cox and C. Rutledge have developed a method for judging the location of a fault in paper insulation from the percent change of the CO2/CO carbon oxide gas ratio [2, 3]. In a controlled experiment with a sacrificial transformer and a heating element, they found that direct heating of paper tends to generate more CO than CO2. Case studies of faulty transformers have revealed that a large percent decrease in CO2/CO is associated with charring of winding paper. A moderate percent decrease in the ratio is often associated with paper charring outside of the windings, such as on bushing or tap changer leads. A minor percent decrease or an increase of the ratio (with production of carbon oxide gas) is usually associated with mild bulk overheating of paper insulation rather than a localized hot spot. See Table 1 for details. For readers new to the topic, an overview of dissolved gas analysis principles can clarify how gas ratios inform fault localization.

Complementary context on transformer oil analysis helps explain the baseline behavior of oils under electrical and thermal stress.

We propose on mathematical grounds that the CO/CO2 ratio should be used instead of CO2/CO. With the most serious problem – charring of winding insulation – the CO2/CO ratio approaches zero asymptotically, so that numerical and graphical resolution are worst when the problem is most severe. By contrast, charring of insulating paper causes the CO/CO2 ratio to increase, while decreases are associated with less damaging low temperature bulk overheating. (See Table 1.) The case history portrayed in Figure 1 shows two episodes where CO/CO2 increased sharply in parallel with methane before the transformer failed with extensive charring of winding insulation. When applying ratio-based criteria, attention to DGA data quality practices can reduce misinterpretation from sampling or instrument bias.

Recent industry work on advancements in dissolved gas analysis also discusses trends in ratio visualization relevant to severe paper charring.

This behavior of the carbon oxide gas ratio can generally be explained by chemical principles. Higher temperature and lower oxygen concentration favor the production of CO, while lower temperature and higher oxygen concentration favor CO2 production. The oxygen concentration in the windings tends to be lower than in the more freely circulating oil outside the windings, so a hot spot in the windings produces more CO than one outside the windings.
We conclude with some useful observations. First, stabilization of the gas ratio after a large change is not necessarily a good sign – it may signify that the paper near a hot spot has been consumed. Second, the criteria in Table 1 remain roughly valid even in the presence of gas loss. Since CO is lost to the atmosphere much faster than CO2, the CO/CO2 ratio can only increase if CO is truly being produced faster than CO2. Finally, some carbon oxide ratio changes are not fault related. For example, in transformers that have just been degassed and in transformers immediately after factory heat run testing, the gas ratio may change as gas trapped in oil-soaked paper insulation diffuses into relatively gas-free bulk oil. For context on heat removal and fluid flow, see transformer cooling considerations that influence temperature gradients.

Background on oil in transformers provides additional insight into oxygen availability and gas dissolution dynamics.

References
1. CIGRE TF D1.01/A2.11 and WG D1.32, Advances in DGA Interpretation, CIGRE Technical Brochure 771, July 2019.
2. 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.
3. R. Cox, ‘“Categorizing Faults in Power Transformers via Dissolved Gas Analysis,” NETA World Journal, Spring 2020, pp. 64–68.

For extended reading, summaries of emerging analytical techniques offer broader context for interpreting field DGA patterns.

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• Dielectric Fluid Channel

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

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• Dielectric Fluid Channel

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.

1. “IEEE Guide for the interpretation of gases dissolved in mineral oil filled transformers,” IEEE Std C57.104, editions 1978, 1991, 2008, and 2019.
2.  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.
3.  R. Cox, ‘“Categorizing Faults in Power Transformers via Dissolved Gas Analysis,” NETA World Journal, Spring 2020, pp. 64–68.

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• Dielectric Fluid Channel

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.

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.

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Oil for transformers acts as a vital dielectric fluid, providing insulation, cooling, and arc suppression. By reducing heat buildup and protecting internal components, high-quality transformer oil ensures safe, efficient, and long-lasting performance in distribution systems.

What is Oil for Transformers?

Oil for transformers is a specialized insulating and cooling medium used in electrical transformers. It ensures safe, efficient, and long-lasting operation.

✅ Provides electrical insulation between windings and core

✅ Dissipates heat to prevent overheating and equipment failure

✅ Suppresses arcing and prolongs unit service life

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Substation Maintenance Training

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Oil for transformers plays a critical role as a dielectric fluid, ensuring the safe and efficient operation of electrical transformers. The type of fluid used maintains the integrity of both paper insulation and solid insulation, ensuring efficient performance in fluid-filled electrical systems. As an insulating medium, it not only prevents electrical breakdown but also helps in cooling the equipment by dissipating the heat generated during operation. Equipment liquid, typically mineral-based or synthetic, is designed to offer excellent electrical insulation properties, enhance operational longevity, and protect against faults or failures. This fluid is essential for maintaining the equipment’s performance, safeguarding against short circuits, and improving overall system reliability. In this article, we’ll explore the importance of liquid in equipment, its types, and why it's crucial for both electrical safety and efficiency. Utilities rely on distribution transformers filled with high-quality oil to ensure reliable service across neighborhoods and industrial facilities.

Transformer Oil Comparison Table

Types of Transformer Oil

Equipment is typically filled with mineral liquid, which has been the most commonly used insulating liquid due to its stability, thermal performance, and cost-effectiveness. However, recent advancements have led to the development of alternative liquids, such as natural esters, which offer improved environmental benefits and higher fire points, reducing the risk of fire hazards. These alternative liquids also contain small amounts of fatty acids that enhance their oxidation stability and performance under high temperatures. The construction of transformers includes the careful integration of insulating oil to protect windings and cores from overheating and electrical breakdown.

Electromagnetic Operation and Insulation

The electromagnetic operation of equipment involves the flow of current through windings, which induces magnetic fields and generates heat. Proper cooling and insulation are necessary to maintain the efficiency of this process. The liquid not only aids in cooling but also provides protection to the windings and contacts inside the equipment. Contact configurations within the equipment determine how electrical circuits connect and disconnect, and the insulating properties of the liquid prevent unintended short circuits or failures. The role of transformer insulation is closely tied to oil performance, ensuring both dielectric strength and thermal management.

Different Types of Transformer Oils

Different types of liquid equipment are available, including mineral-based and synthetic alternatives. Mineral liquids have been widely used for decades due to their proven reliability; however, concerns over their environmental impact have led to the adoption of biodegradable options, such as natural esters. These fluids offer a high fire point and enhanced oxidation resistance, making them an attractive choice for applications where fire safety and sustainability are priorities.

Applications of Transformer Oil

The applications of equipment liquid extend beyond just insulation and cooling. It also plays a crucial role in suppressing arcing within the equipment and ensuring the longevity of its components. Over time, however, liquid can degrade due to exposure to high temperatures, moisture, and contaminants. This degradation can compromise its insulating and cooling abilities, making regular oil testing essential. By conducting routine liquid testing, engineers can assess the condition of the liquid, identify contamination, and determine whether it needs to be replaced or treated. High-voltage units, such as power transformers, rely on oil with stable dielectric properties to withstand demanding grid conditions.

Principles of Liquid Operation

The operation principles of the equipment liquid are closely tied to the efficiency of the equipment itself. When the equipment is energized, the liquid absorbs and transfers heat, maintaining a stable operating temperature. Any significant degradation in the liquid’s properties can lead to insulation failure and reduced performance. Ensuring that the liquid maintains its high dielectric strength is crucial for the equipment’s long-term reliability. Modern condition monitoring systems often track transformer oil quality, enabling predictive maintenance and reducing costly outages.

Fire Safety and Flash Point Considerations

Another key property of equipment liquid is its flash point, which determines the temperature at which the liquid can vaporize and ignite. A higher flash point indicates better fire resistance, reducing the risk of fires in electrical substations and industrial settings. Regular monitoring of the liquid’s flash point, along with other relevant properties, is a crucial step in ensuring equipment safety.

Frequently Asked Questions

What is a Dielectric liquid, and why is it used in electrical transformers?

Dielectric liquid is a specially refined mineral liquid used in electrical equipment as an insulating and cooling medium. It helps to insulate the equipment’s internal components, preventing electrical breakdown. Additionally, it dissipates heat generated during operation to keep the equipment at an optimal temperature, ensuring efficiency and preventing damage from overheating. Understanding transformer oil is key to extending equipment life, preventing faults, and maintaining overall system reliability.

What are the different types of oil used in transformers?

The two main types of oil used in equipment are mineral oil and synthetic oil.

• Mineral oil, derived from petroleum, is the most commonly used liquid in equipment due to its excellent insulating properties, cost-effectiveness, and widespread availability. It is further divided into highly refined mineral liquid and less refined options.

• Synthetic oils are man-made liquids designed to perform better at extreme temperatures and provide enhanced thermal stability. They are typically used in situations requiring higher performance or in environments with strict environmental and safety regulations.

How does equipment liquid prevent electrical breakdown?

Equipment liquid prevents electrical breakdown by providing high dielectric strength, which allows the equipment to handle high voltage without risk of failure. The liquid acts as an insulating barrier between electrical components, such as conductors and windings, reducing the chance of short circuits. Its insulating properties ensure that electrical discharges or arcing do not occur, thereby maintaining the equipment's stability.

What is the role of transformer oil in cooling and heat dissipation?

The primary role of equipment liquid in cooling is to absorb the heat generated by the electrical components inside the equipment during operation. The oil circulates through the equipment, transferring heat away from the core and winding. It then releases the heat through the outer surfaces or the radiator system, maintaining an optimal operating temperature to avoid overheating, which could damage internal components and shorten the equipment’s lifespan.

How can transformer oil be tested for quality?

Transformer liquid can be tested for quality using several methods, including:

• Dielectric strength testing to check for the liquid's insulating properties.

• Acidity tests to detect the presence of contaminants that could cause corrosion or degradation.

• Moisture content analysis is performed to ensure the liquid remains free of water, which can reduce its insulation effectiveness.

• Color and appearance tests to identify contaminants, oxidation, or breakdown.

Transformer liquid should be replaced when it shows signs of contamination, degradation, or when its dielectric strength drops below the acceptable level. Regular monitoring and testing can help determine when liquid replacement or filtration is necessary to ensure the continued safe and efficient operation of the equipment.

Oil for transformers serves as an essential insulating and cooling medium in electrical equipment, ensuring optimal performance and longevity. Mineral liquid, the most commonly used type, helps dissipate the heat generated during operation, preventing overheating that could lead to equipment failure. It also provides electrical insulation, preventing short circuits and electrical faults by maintaining the integrity of the equipment's internal components. Additionally, liquid serves as a barrier against moisture and contaminants, further enhancing the reliability and safety of the equipment. Over time, liquid may degrade, requiring periodic monitoring and replacement to maintain its effectiveness.