Latest Dielectric Fluids Articles

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

What Are Advancements in DGA Data Quality?

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

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

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

✅ ML-based anomaly detection and condition-based maintenance

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

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

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

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

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

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

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

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

Related Articles

• Dielectric Fluid Channel

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.

Electrical Transformer Maintenance Training

Substation Maintenance Training

Request a Free Training Quotation

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.

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.

Electrical Transformer Maintenance Training

Substation Maintenance Training

Request a Free Training Quotation

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.

Related Articles

• Utility Transformers Channel

• Industrial Transformers Channel

• What is a Transformer?

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

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

Electrical Transformer Maintenance Training

Substation Maintenance Training

Request a Free Training Quotation

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.

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

Related Articles

• Dielectric Fluid Channel