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The breakdown voltage (BDV) of oil refers to the point at which insulating oil loses its dielectric strength and begins to conduct electricity, potentially leading to failure in electrical systems. In systems like transformers, insulating oil plays a critical role in preventing electrical discharges by providing both insulation and cooling. A BDV test is essential for evaluating the quality and effectiveness of the oil. The higher the BDV, the better the oil can resist electrical breakdown, ensuring the safety and efficiency of the system.

What is the breakdown voltage of oil, and why is it important in electrical systems?

The breakdown voltage (BDV) of oil is the maximum voltage at which the insulating properties of the oil fail, causing it to conduct electricity. This is critical in systems like transformers, where transformer oil is used as an insulator. If the BDV of the oil is low, it can lead to electrical failures, short circuits, and equipment damage. Testing and maintaining the BDV ensures that the oil can effectively insulate electrical components and prevent catastrophic breakdowns.

How is the breakdown voltage of oil measured, and what are the typical test methods?

The breakdown voltage test is performed by placing an oil sample between two electrodes immersed in the oil at a specific distance, known as the specific gap. A gradually increasing voltage is applied until the oil fails and allows current to flow between the electrodes. The voltage at which this occurs is recorded as the BDV. This test is crucial in assessing the dielectric strength of the oil. The BDV test is typically conducted according to industry standards to ensure accurate and reliable results.

What factors affect the breakdown voltage of insulating oil?

Several factors can affect the breakdown voltage of insulating oil. Conducting impurities, such as moisture, dust, and other contaminants, can significantly lower the BDV of the oil. Over time, oil exposed to high temperatures, oxidation, and electrical stress can degrade, reducing its dielectric properties. Additionally, the presence of gases dissolved in the oil, as well as the condition of the oil's molecular structure, can affect its ability to insulate. Proper maintenance and regular testing help ensure that these factors are kept in check.

What are the typical breakdown voltage values for transformer oil?

The typical breakdown voltage values for transformer oil range from 30 kV to 60 kV, depending on the quality of the oil and its use in the transformer. New transformer oil generally has a higher BDV, while older, degraded oil can have a significantly lower value. Industry standards set minimum acceptable BDV values to ensure that the oil can maintain its insulating properties under operating conditions. Regular testing is necessary to monitor the oil’s performance and ensure it meets the required specifications.

How can the breakdown voltage of oil be improved or maintained?

Maintaining and improving the breakdown voltage of insulating oil involves regular testing and filtration. Removing conducting impurities such as moisture and dissolved gases can help increase the BDV. Proper storage and handling of the oil are also critical in preventing contamination. In some cases, reconditioning the oil by removing contaminants and restoring its dielectric properties can extend its useful life. Periodic BDV tests ensure that the oil continues to meet the necessary dielectric standards, safeguarding the electrical system from potential failure.

The breakdown voltage (BDV) of oil is a key parameter in maintaining the safety and efficiency of electrical equipment, particularly in transformers. By regularly testing and ensuring that the oil retains its dielectric strength, engineers can prevent costly electrical failures and extend the lifespan of the equipment. Proper maintenance and testing of transformer oil through BDV tests are essential to keeping systems operating safely and effectively.

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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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.

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.

Related Articles

• Dielectric Fluid Channel

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):

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.

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• Industrial Transformers Channel

• What is a Transformer?

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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Fundamental dielectric characteristics describe permittivity, dielectric constant, polarization, loss tangent, conductivity, and frequency response, guiding material selection, insulating performance, impedance behavior, and electric field interactions across applications in electronics, power systems, and RF design.

What Are Fundamental Dielectric Characteristics?

Material metrics like permittivity, loss tangent, and polarization that govern insulating behavior under electric fields

✅ Determines energy storage via permittivity and dielectric constant

✅ Quantifies dissipation with loss tangent and conductivity

✅ Captures frequency response, polarization, and dielectric breakdown

1. Introduction
For many years synthetic ester fluids were seen as specialist materials, only for use in unusual transformers, such as those in rolling stock, offshore installations and steel plants where fire safety was a prime consideration. However, in more recent times users are realizing that ester-based liquids could offer a more mainstream alternative to mineral oil and although these fluids are more expensive the overall project costs can be lower when taking into account factors such as reduced fire protection. In some space-constrained urban environments ester-based liquids may even become the preferred option, with the flammability and potential environmental impact of mineral oil making the design of modern installations extremely challenging. This type of situation has been seen with the latest 400kV projects incorporating synthetic ester fluids. For context, readers can review the fundamentals of dielectric fluids to understand how base chemistry influences flammability and environmental performance.

2. Standard AC Breakdown Testing
Standard test methods for assessing breakdown voltage of liquids typically employ small electrode gaps, of the order of ≤2.54mm. The electrode configuration can vary from spherical, through VDE type “mushroom” electrodes to disc electrodes. This type of testing is primarily used to give an evaluation of the cleanliness of a liquid since it gives very limited information about the actual dielectric performance. It can be seen by comparing the results in Table 1 that all the different types of liquids to be discussed in this paper give very similar results for a given electrode arrangement in this type of testing. Clarifying the definition of breakdown voltage in insulating oil helps interpret these short-gap results.

This could lead to the conclusion that all these liquids are equal in their dielectric performance, or that given a good result in the AC breakdown test one liquid is in some way superior to another. However, the true picture is more complex, since the electrical stress distribution is influenced by many factors such as electrode geometry, distance and materials types. Another key factor in the dielectric behavior is the wave shape of the applied voltage. AC voltage in the form of a clean sine wave is usually expected at frequencies of 50-60Hz depending on the geographical location. However, this is rarely the case with harmonics and other distortions of the pure waveform. In addition the prevalence of surges on the network must be accounted for; in testing this is usually characterized by two different types of event, either lightning surge or switching surge and there are standard waveforms established to test these.

In practice, understanding how oil in transformers behaves under distorted waveforms informs appropriate test selection.

So any dielectric system in a transformer must withstand AC conditions, switching impulse and lightning impulse, as well as chopped lightning impulse if this is specified. There may also be a requirement to withstand DC fields in some special cases and this adds an extra level of complexity.

When considering a new dielectric medium, therefore, all these aspects need to be tested and in the beginning researchers will look to comparisons with existing materials of known behavior to assess likely changes. As stated previously in terms of short gap AC behavior ester-based liquids are very similar to mineral oil and this gives some confidence that they can be used. For distribution class equipment up to 33kV the change to ester has required little in the way of detailed electrical design evaluation, since the electrical margins are large due to the need for excess solid insulation to provide mechanical strength. However as the voltage level rises there is less electrical margin and the need for routine impulse testing, both of which mean that greater steps are needed to evaluate design. So to begin using ester-based liquids in power class transformers there is a need to check impulse behavior over similarly short gaps to the AC tests, and this is where see some differences start to emerge.

Complementary programs of transformer oil analysis can track moisture, particles, and aging markers that strongly influence PD and impulse withstand.

3. Impulse Strength of Short Electrode Gaps
There are standard methods for measuring impulse breakdown with the ASTM D3300 being one popular method. The electrode arrangement for this test can be either needle to sphere, or sphere to sphere. In the first instance researchers started work with small electrode gaps employing a sphere-sphere set up, such as the example in Fig 1. utilized by the University of Manchester.

Fig.1. Arrangement for short gap impulse tests

In their testing, a number of different methods were applied for stepping up the test voltage, following the recommendations in different standards. This showed a lower impulse breakdown strength for the ester liquids and Fig 2. shows a summary of the results, with the maximum difference in breakdown voltage being of the order of 20%. In this case the mineral oil tested was Nynas Nytro Gemini X, the synthetic ester M&I Materials MIDEL 7131 and natural ester Cargill Envirotemp FR3. These observations are consistent with broader properties of transformer insulating oil related to ionization, space charge, and pre-breakdown dynamics.

Fig. 2. Results of impulse breakdown testing to various methods

4. Partial Discharge Inception
To further understand the mechanism behind the different behavior that was observed, researchers started looking at very divergent arrangements, for example a sharp needle of tip radius 6.5µm and sphere of radius 12.5mm, as this allows observation of phenomena in a liquid with manageable voltage levels.[3] This allowed the study of partial discharge inception, when the liquid begins to yield to the electrical field. When the researchers subjected this arrangement to AC they discovered that the PDIV of ester-based liquids with a gap of 50mm is actually very close to that of mineral oil.

In fact in the case of natural ester a higher PDIV was found than in mineral oil. This suggested that the reason for the difference in impulse breakdown behavior does not lie in discharge inception, although some different behavior was found in this study, especially in polarity, between mineral oil and esters. Mineral oil exhibits a very strong tendency to PD only in the positive half cycle of the AC waveform, i.e. when the needle is at a positive polarity. In the negative half cycle the required voltage to form PD is much higher than that of the PDIV. In the ester-based liquids the situation is somewhat different; PD was found in the negative half cycle at much closer voltages to the positive half cycle PDIV, as shown Fig. 3.

Fig. 3. PDIV in positive (left hand chart) and negative (right hand chart) half cycles

This indicated that the electrical behavior is not the same between the liquid types. It also throws up questions around the way mineral oil filled transformers are tested, i.e. is only testing with negative impulse a valid practice?

5. Streamer Propagation Behavior
The similarity in PDIV between esters and mineral oil required a closer look at propagation of electrical discharges. The next important step was then to look at the discharge channels in the liquids, known as streamers. This involved the combined techniques of electric measurement and visual imaging to detect how streamers form in liquids and how they propagate. Much of this work was conducted in parallel in different research institutions,where the same conclusion was drawn. Streamer propagation in esters is different to mineral oil, especially under very divergent fields, such as those the researchers were using. The key conclusion from this was a difference in so-called acceleration voltage when streamers move from slow mode propagation to fast mode.

In order for a flashover to occur it is necessary for the electrical current to find a path from one electrode to another and in liquids this occurs within a gaseous channel, known as a streamer. This channel will only propagate through the fluid if it has sufficient field strength to provide motive force and sufficient time. When considering AC behavior the time is relatively long, whereas under impulse conditions the time is extremely short. The standard wave shape for lightning impulse has a rise time of 1.2µs and fall time of 50µs to reach 50% of maximum. This means that the peak electrical field is only present for a matter of micro-seconds and in order to get propagation from one electrode to another, especially over longer oil gaps, the discharge must attain a high velocity. Streamers can be characterized by four different modes, as shown in Fig. 4.

Fig. 4. Streamer velocities and modes

The principle behind the connection between streamer mode and breakdown can be demonstrated with a simplified example. Taking a gap size of 50mm, if it is assumed that the liquid is only subjected to the voltage necessary to sustain propagation for 5µs then the streamer will need to attain a velocity of 10km/s or in other words be of Mode 3-4 to bridge the gap and cause a breakdown. Otherwise the streamer will only be characterised as a partial discharge. The transition from Mode 1/2 to Mode 3/4 can be characterised as the acceleration voltage.

A variety of researchers have looked at the acceleration voltage principle with esters and all agree that this is one area where these liquids differ from mineral oil. The charts in Fig. 5. show the behavior when the electrode system is extremely divergent, with esters having a substantially lower acceleration voltage than mineral oil, especially under positive polarity.

Fig. 5. Acceleration voltage under Positive polarity and Negative polarity at 50mm spacing

6. Testing with More Realistic Electrode Arrangements
Although this difference in acceleration voltage would appear to prevent the use of esters at higher voltages as the electrode arrangement becomes less divergent, inception begins to become more important for the withstand level. This supports the findings of researchers who have studied the behavior with varying levels of divergence in the electrodes, from homogenous through to highly divergent.

When thinking about the design of real world equipment and transformers for transmission levels, the more homogeneous case actually represents the majority of the configurations to be considered. Needle to plate type situations are avoided as part of good design and manufacturing, as it is known that these are electrically weak and prone to producing discharges. Consequently, criteria for selecting oil for transformers should consider field uniformity, surge exposure, and insulation geometry as well as fire safety.

Research looking at impulse behavior under more realistic arrangements has focussed on tap changer contacts, since these represent a more divergent part of power transformer designs. In this case the arrangement shown in Fig. 6. was used and the results obtained under impulse conditions showed very little difference between ester and mineral oil.

Fig. 6. Tap changer contacts used for natural ester evaluation

Fig. 7. shows the Weibull distribution for results obtained in this arrangement. This gives some confidence that even though the situation with a needle and plate looks unfavourable, as soon as the configuration starts to reflect the real world situation, the difference between esters and mineral oil becomes much smaller.

Fig. 7. Weibull distribution of lightning impulse breakdown under positive polarity

7. Laboratory Testing of Creepage Discharge and Flashover
Another area where divergence becomes important is over long creepage paths, where there is effectively a concentrated area of electrical field at one end, with a very long distance to the lower potential. A popular form of arrangement for testing creepage behavior is the so-called Weidmann set up, of a paper-wrapped or bare conductor in contact with a pressboard barrier, as shown in Fig 8.

Fig. 8. Weidmann electrode arrangement

When this type of arrangement has been tested over gap sizes up to 35mm it has been found that esters give similar flashover results to mineral oil, as shown in Table 3. The difference between the liquids in this arrangement is small - not even as large as that found in small oil gaps. This suggests that even though design modification may be necessary, there is not the very large difference that might be assumed if the acceleration voltage in extremely divergent set up was used.

8. Testing in Prototype Transformers
Another area where more focus may be required with an ester based liquid is over very long creepage paths far beyond the distances tested with the Weidmann arrangement, since the fundamental investigations indicate that propagation is key. Experience from real transformer prototypes has shown that failure modes over extremely long paths support the faster propagation model. Researchers from Brazil found that when testing a single phase 245kV prototype transformer, in natural ester, designed to mineral oil rules, the natural ester failed at 100% of Basic Insulation Level (BIL) rating, when tested with lightning impulse along a long gap discharge path, as shown in Fig.
3. This unit had an HV winding with a center connection coil.

Fig. 9. Model of winding showing discharge path

The designers of this transformer noted that although they experienced this failure it does not prevent the use of esters at higher voltage. However, there may need to be more design margin and closer attention paid to peak stress areas and long creepage paths. Thermal design and transformer cooling also affect viscosity and bubble formation, which in turn impact dielectric margins at high stress.

This is a theme that is often mentioned in the industry when discussing ester-based liquids and the necessary design changes. It is important to note that a growing number of manufacturers have carried out their own research in addition to the published works; to date there are a number of transformers successfully operating at 400kV+ with esters. There are also many other projects in development, and the expectation is that in the coming years esters will move from a being a product used in niche applications to one deployed in mainstream installations.

9. Conclusions
Over the last fifteen years a great deal of research has been conducted into understanding the electrical behavior of ester-based liquids, under a range of different conditions. This has been driven by a desire for safer, more environmentally friendly transformers.

The laboratory based test arrangements with extremely divergent fields indicate a difference in the streamer propagation behavior between esters and mineral oil, which may mean designers need to pay attention to certain portions of the dielectric structure. Evaluations with more realistic electrode arrangements indicate that although there is a difference in behavior, this will not prevent the use of esters at higher voltages. The experience in real world applications, where esters are now utilized for power transformers for 400kV+ also supports this assertion.

The key aspects for designers when considering ester-based liquids are to design a discharge-free transformer; extra margin may be needed over long creepage paths and in divergent arrangements to compensate for the higher probability of propagation. This could be summarized by saying that with mineral oil, discharges may occur, without flashover, but in ester there is a higher probability of discharge becoming breakdown.

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