In our previous articles about insulating liquids, “Dielectric Liquids – Key to Reliability and Predictive Maintenance” and “Insulating Liquids – The Lifeblood of Transformer Reliability,” we underscored the crucial role of insulating liquids in maintaining transformer functionality, longevity, and reliability. These liquids, described as the lifeblood of transformers, play a pivotal role not only in insulating and cooling, but also in protecting solid insulation and serving as a diagnostic tool. When used as a diagnostic tool, the liquid can provide insights into the current condition of the transformer and can inform predictive and preventive maintenance decision-making. Performing analytical testing on dielectric liquids is a proven method of monitoring transformer condition and detecting changes within the transformer that can reveal where maintenance can be performed to prevent unplanned outages and extend the reliable life of the transformer by adopting a predictive maintenance approach.

Advanced Analytical Testing for Reliability Centered Maintenace

The decision to adopt a predictive maintenance strategy over a reactive one is pivotal to ensuring the long term reliability and operational continuity of transformers. Reactive maintenance, by its nature, waits for failure before action is taken. While straightforward in concept, this approach exposes transformers to significant risk. An unexpected failure can result in prolonged outages, expensive emergency repairs, and potentially severe damage to surrounding systems. The consequences extend beyond equipment – unplanned power loss can jeopardize personnel safety and disrupt critical operations.

In contrast, predictive maintenance is a proactive methodology that uses operational insights, systematic data collection, and analytical interpretation to assess transformer condition. By identifying trends and anomalies in diagnostic data, this approach enables timely interventions that prevent failures before they occur. It transforms maintenance from a reactive chore into a strategic tool that helps keep your team safe, reduces costs, safeguards uptime, and extends the reliable life of the transformer.

Building upon these foundational insights, we turn our attention to five advanced diagnostic tests that can further enhance transformer reliability: Liquid Power Factor, Furan analysis, Metals-in-oil analysis, Inhibitor content, and PCB analysis. Each test provides critical data that informs predictive maintenance strategies, helping operators avoid unexpected failures and prolong the life of the transformer.

Liquid Power Factor (Dissipation Factor) Testing

Liquid Power Factor (LPF) testing per ASTM D924 measures the dielectric losses that occur when an insulating liquid is subjected to an alternating electric field. It quantifies how much energy is wasted as heat rather than performing its insulating function. A low liquid power factor indicates a clean, healthy liquid with minimal losses, while an elevated liquid power factor often signals issues such as moisture ingress, oxidation, or contamination that can compromise the reliability of the transformer. New transformer oil typically shows a low power factor (<0.05% at 25 °C). Many adverse conditions that affect insulating liquids, such as aging, chemical degradation, or environmental contamination, tend to impact LPF. This makes it a useful diagnostic tool for reliability, as it can directly identify issues, as well as help corroborate potential issues identified by other testing.

The test is typically performed at 25 °C and 100 °C for mineral oils to provide insight into the baseline liquid quality and its behavior under thermal stress. For natural esters, the test is generally performed only at 25 °C, as the results at 100 °C are not diagnostically significant since the results at 25 °C and 100 °C are correlated – combined with natural esters’ generally higher inherent dissipation factor, there is little value in testing at both temperatures.

Monitoring LPF trends over time is an important part of predictive maintenance in order to help catch early signs of liquid degradation. By responding to changes in LPF values early, asset owners can assess the condition and find the most cost effective way to protect transformers – LPF values can be restored by oil processing, so once the root cause of increased LPF values is corrected, the liquid can be restored to like-new condition.

Furan Analysis

Solid insulation is often referred to as “the life of the transformer” due to its critical functions as an insulator and in providing mechanical strength inside the transformer. The paper will naturally break down as it ages, and conditions inside the transformer such as heat, moisture, or fault conditions can accelerate this breakdown, causing direct damage to the paper. As the solid insulation ages or is damaged, its mechanical strength deteriorates and, crucially, this degradation is irreversible. This means it is critical to protect the solid insulation in order to extend the reliable life of a transformer.

Much of the testing performed on dielectric liquid determines characteristics of the dielectric liquid itself, and how that relates to conditions inside a transformer. In the resulting diagnostics, a great deal of focus is on the potential impact of conditions on the solid insulation – in DGA we use the carbon oxides to see if paper may be involved, in moisture analysis we are concerned if moisture is present that can lead to formation of acids, and in determining acid number we are looking for evidence that acids that can harm the paper have developed in the transformer. Furan analysis is unique in that it quantifies the breakdown of the solid insulation (often referred to as “the paper”), which provides a way to characterize aging or damage to the paper.

As the paper breaks down, compounds called furans are formed – these can be quantified via a method called High Performance Liquid Chromatography (HPLC) described in ASTM method D5837. There are five furans that can be characterized: 2FAL, 5H2F, 2FOL, 2ACF, and 5M2F. These furans are used to determine the degree of mechanical strength reduction, as the furan quantities are related to the tensile strength of the solid insulation. New mineral oil should have very low amounts of furans, if any. Establishing a baseline of furans is an important part of a reliability program designed to protect the solid insulation and extend the reliable life of the transformer. Watching the trend of furan counts over time provides insight into the condition of the paper, and provides a means to determine if the paper is aging prematurely or has been damaged, which would reduce the life of the transformer. Understanding the condition of the solid insulation is critical to making informed reliability decisions on transformers, as the solid insulation must be protected to maximize the life of the transformer.

In the event that service is performed on a transformer, note that oil processing typically removes furans while reclaiming the oil to like-new condition. In this situation, it is critical to establish a new baseline of furans after oil processing – while the liquid test results should show a decrease in furans count, this process does not restore the mechanical strength of the solid insulation! As new furan test data becomes available, it should be considered that new furan counts are additive to pre-processing results in order to estimate the total mechanical strength of the solid insulation.

When used as a diagnostics tool, the liquid can provide insights into the current condition of the transformer and can inform predictive and preventive maintenance decision-making.

Metals-in-Oil Analysis

Metals-in-oil analysis, which is determined by Inductively Coupled Plasma (ICP) spectroscopy per ASTM method D7151, identifies trace metals like copper, iron, and aluminum in transformer oil. This method analyzes a liquid sample by exciting it in plasma and detecting the emitted light at element-specific wavelengths to quantify the amount of the metals in the sample. For new or clean oil, it is common to see no metals in the analysis.

Metals that are dissolved in oil are often due to overheating, arcing, corrosion, or wear conditions in a transformer. Metals can come from multiple sources, such as copper or aluminum from windings, internal connections, tap changers, leads, shielding, and grounding components. Traces of iron may come from the core assembly, structural components, and other internal hardware. As with most tests, it is important to establish a baseline value of metals in a transformer, in order to trend and detect changes over time.

Preforming analytical testing on dielectric liquids is a proven method of monitoring transformer condition and detecting changes withing the transformer that can reveal where maintenace can be performed to prevent unplanned outages and extend the reliable life of the transformer.

Inhibitor Content

Inhibitors are antioxidants added to transformer oil that serve to slow oxidative degradation, significantly extending the oil’s service life by slowing the aging process and helping to prevent the formation of acids that can harm the solid insulation. Oxidation of the transformer oil can lead to loss of dielectric strength and the formation of acids that can damage solid insulation. Inhibited transformer oil typically contains about 0.3% – 0.5% of inhibitor by weight.

Over time, these inhibitors are consumed, leaving the transformer susceptible to accelerated oil degradation and potentially reducing transformer reliability. Depleted inhibitor is often an early indicator that maintenance may be required on the transformer – under normal conditions, the oil will generally not begin to age substantially due to oxidation if sufficient inhibitor is present in the liquid. Accordingly, it is common to test for inhibitor content during routine testing.

Mineral oil-based transformer dielectric liquids can be tested to determine the inhibitor content by ASTM method D2668 using Fourier Transform Infrared (FTIR) spectroscopy. Once inhibitor levels drop below 0.1% by weight, the oil does not have sufficient inhibitor to provide protection against oxidation, and it is recommended to re-inhibit the oil. It is recommended that even if a transformer has a preservation system, such as an active nitrogen system or conservator tank with a diaphragm, maintaining inhibitor in the oil provides additional protection in case the preservation system fails.

PBC Analysis

Polychlorinated Biphenyls (PCBs) are synthetic chlorinated hydrocarbons that were used as dielectric liquids until their ban in the late 1970s. As dielectric liquids, PCBs were widely adopted for use in transformers due to their excellent insulating properties, exceptional stability, and non flammable nature. Despite the benefits compared to other dielectrics, it was discovered that PCBs have significant and long-lasting environmental and health impacts, leading to the creation of regulatory compliance requirements in the US Code of Federal Regulations (CFR) that must be followed. Testing for PCBs is useful to ensure compliance with the federal regulations, as well as to be prepared in the event that service is necessary on a transformer to make repairs.

PCBs can be quantified by Gas Chromatography following ASTM method D4059 (alternate methods are also available from the EPA, NIST, and AOAC). The common PCBs are Aroclors 1242, 1254, and 1260 though other, less common Aroclors may also be quantified using this method as well. New transformers should not have any PCBs detected. If PCBs are found, a transformer is characterized as “Non-PCB” if fewer than 50 ppm of PCBs are detected. Between 50 and 499 ppm PCBs, a transformer is classified as “PCB-Contaminated”, and at 500 ppm PCBs and above, a transformer is classified as “PCB”. Note, there is no “PCB-Contaminated” classification for PCBs outside a transformer – PCB liquids outside a transformer (e.g. stored in drums for disposal) are either “Non-PCB” at <50ppm, or “PCB” at 50 ppm and above.

Despite decades of regulation, some transformers are still filled with PCB liquids, and trace amounts of PCBs can be found in some transformers due to contamination. PCB compounds are persistent and toxic, and so it is crucial to understand if transformers have any PCBs and to plan accordingly. Extraordinary care must be taken to ensure compliance with federal and local environmental regulations, and owners must have appropriate measures in place to manage these hazardous materials. This ensures transformers can be managed appropriately, transformer owners are prepared in the case of emergency, and sites can be maintained without introduction of environmental risks, protecting the equipment and the surrounding ecosystem.

Conclusion

Throughout our series of articles, including “Insulating Liquids: The Lifeblood of Transformer Reliability” and “Dielectric Liquid: A Key to Reliability and Predictive Maintenance,” we have consistently emphasized the importance of insulating liquids in maintaining transformer health. These liquids serve not only as dielectric and thermal conductors but also as critical diagnostic tools that help operators make informed decisions about maintenance and reliability.

The five advanced diagnostic tests explored in this article build upon that foundation by providing more specific, actionable insights into the condition of the transformer and maintaining environmental compliance. These tools allow operators to transform test data into meaningful, predictive insights. This focus on data-driven maintenance strategies aligns with the predictive maintenance framework we’ve discussed across the series.

By regularly testing and monitoring these liquids, transformer owners can extend the reliable life of their electrical power system, reduce the risk of unplanned failures, optimize maintenace scedules, and ulimately ensure more consistent, reliable operations.

As highlighted in the previous articles, insulating liquids are much like the blood in a human body – they provide essential functions for normal operation and can reveal a wealth of information about internal conditions. By regularly testing and monitoring these liquids, transformer owners can extend the reliable life of their electrical power system, reduce the risk of unplanned failures, optimize maintenance schedules, and ultimately ensure more consistent, reliable operations.

At SDMyers, we are committed to providing comprehensive testing and expert diagnostic services to support your transformer maintenance and reliability needs. Our advanced diagnostic solutions are designed to help you enhance reliability and longevity, keeping your critical power systems running smoothly, and helping you extend the reliable life of your electrical power system.