Understanding Your Test Results

One of the most important functions of oil in a transformer is to protect the paper (solid insulation).  As oil ages, it loses its ability to protect the paper from degradation.  Aging also weakens the oil’s ability to act as a cooling medium and provide dielectric strength – ultimately protecting the transformer from failure.  Through the aging process, chemical by-products build up in the oil and the paper, creating acid by-products and sludge. These decay products begin to affect the oil’s protective qualities almost immediately after they form, they begin to break down the molecular structure of the solid insulation.

Testing the transformer oil is imperative in evaluating the condition of the oil and the paper, identifying the proper time to perform maintenance, and is critical in the prevention of unplanned outages. Establishing a routine testing interval for each piece of equipment is not only one of the most effective preventative maintenance practices, but also the most cost-effective prerequisite in maintaining a reliable system.

The following definitions, along with the recommendations that we provide with your test results, will help you better understand the benefits of each test and how they are used to determine the condition of your transformer.  Please don’t hesitate to call if you need more information…330.630.7000; or refer directly to the Transformer Dashboard for extended definitions and recommendations for your particular results.

Interfacial Tension (IFT)

Standard Test Method for Interfacial Tension of Oil against Water by the Ring Method, ASTM D971

The Interfacial Tension (IFT) test detects small amounts of dissolved polar contaminants and products of oxidation in electrical insulating fluids. The test is done by measuring the surface tension at the interface between the liquid sample and distilled water. The water and the polar contaminants in the fluid are attracted to each other and meet at the interface between the fluid and water. The insulating fluid side of the interface becomes more polar (more water-like), and this will cause the interfacial tension to decrease at the interface. This test will provide an indication of the sludge precursors in the fluid long before any sludge will precipitate from the fluid. Acids formed by oxidation will also have a large effect on the IFT value, and acids are necessary for the formation of sludge.

ASTM D 3487 sets a minimum of 40 mN/m for new mineral oil for use in electrical apparatus. For in-service equipment, SDMyers Inc. considers mineral oil with an IFT ≥ 32 mN/m Acceptable (AC). The IFT is considered Questionable (QU) when the IFT drops below 32 mN/m, but is at least 28 mN/m. Oil reclamation is recommended when the IFT enters the Questionable range. (Oil reclamation is also recommended when the acid number enters its Questionable range.) At this point, the oil contains enough sludge precursors and acids to be of concern – sludge deposits are likely just starting to form in the paper insulation. The acid test will determine corresponding acid levels (ASTM D 974). Various external contaminants, like cleaning solvents for example, can cause a low IFT without seeing an increase in acid. Values of IFT < 28 mN/m are considered Unacceptable (UN). At this point, the oil has formed significant sludge and is damaging the paper insulation, if no external contamination is an issue. Oil reclamation is recommended.

Dielectric Breakdown Voltage (Disk Electrodes)

Standard Test Method for Dielectric Breakdown Voltage Using Disk Electrodes, ASTM D877

Dielectric Breakdown Voltage is an electrical property of new fluid. The measurement of Dielectric Breakdown Voltage has application both to the function of new fluid and to its purity. The D877 method has two flat disk electrodes with sharp edges spaced 0.10 inches (approximately 2.54 mm) apart. D877 has limited use to measure water contamination in oil because it is not sensitive to moisture at saturation below about 60%. It is sensitive to contamination by some other materials and to the presence of particles in addition to high moisture levels. It does not do a good job of detecting oxidation decay products.

D877 use has been reexamined by many of the standards organizations (IEEE has virtually eliminated it as a test for transformer oil in the draft revision of the acceptance and maintenance guide for mineral oil), but the test is still useful enough to justify its inclusion in both a program for accepting new fluids and for evaluating fluid in service. For new mineral oil as received from a supplier, a typical specification value is a minimum of 30 kV. For evaluating in-service fluids, low values indicate contamination by very high moisture levels, contamination from outside sources, or presence of conductive particles.

Dielectric Breakdown Voltage (VDE Electrodes)

Standard Test Method Dielectric Breakdown Voltage Using VDE Electrodes, ASTMD1816

Dielectric Breakdown Voltage is an electrical property of new fluids. The measurement of Dielectric Breakdown Voltage has application both to the function of new fluids and to its purity. The D1816 method has been used by many standards organizations to replace the D877 method as both a new fluid test and as an in-service fluid test because the VDE electrodes more closely resemble the geometry of conductors inside operating electrical equipment and because the test is much more sensitive to moisture and to cellulose particles. There are two possible gap settings for the electrodes: 1 mm (approximately 0.04 inches) and 2 mm (approximately 0.08 inches). Typical specification values for new mineral oil as received from a supplier are a minimum of 20 kV for a 1 mm gap and a minimum of 35 kV for a 2 mm gap. For new fluid installed in new equipment and for in-service fluid, the acceptable values depend on the voltage class of the equipment. A difficulty with the method is that it is also sensitive to dissolved gases, which may not present any sort of operational problem at levels that affect the test. So, while an acceptable D1816 value can be interpreted as an indication of normal operation, a questionable or unacceptable value may not automatically be interpreted as a definite sign that something is wrong; further investigation is needed.

Color

Color is a physical property of the fluid. As a new mineral oil test, a very low color is an indication of highly refined oil and is a relative measure of the purity of the oil. A typical new oil value for color is less than 0.5 on the ASTM scale. As in-service fluid ages and is oxidized, color typically increases, and the fluid darkens, visibly. Care must be taken in interpreting color results for in-service oil because there can be relatively light colored oils that are unacceptable for continued use and there are some darker oils that continue to provide acceptable service. Maintenance decisions are rarely made based strictly on color, but an unacceptable color may indicate the need to more closely evaluate other test results that apply to oxidation of the oil.

For fluids other than transformer oil, there are both quantitative and qualitative determinations of color available. Frequently, we find it is most useful for fluids such as Askarel and Silicone fluid to provide a qualitative description of the color.

Specific Gravity (Relative Density)

Standard Practice for Density, Relative Density (Specific Gravity), or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method, ASTM D1298

Relative density (more commonly, specific gravity) is a direct comparison of the density (mass per volume) of an insulating liquid to water. Water has a specific gravity of 1.000; transformer mineral oil is lighter than water, so the specific gravity is less than one. A typical specification for new oil is 0.84 to 0.91. This is a test of a physical property that relates to the oil’s composition and function. Specific gravity directly affects heat transfer. Specific gravity of oil is affected by the length and structure of the hydrocarbons in the oil. Mixtures of hydrocarbons that perform as transformer dielectric liquids typically have specific gravity within a relatively narrow range.

Specific gravity is a new oil test that is also used for in-service oil. Specific gravity of oil should not change because of aging. Significant changes while in-service are an indication that the oil has been contaminated.  Other dielectric fluids have different ranges for Relative Density (Specific Gravity). The test is used for all types of new and in-service insulating liquids.

Visual Examination

Standard Test Method for Visual Examination of Used Electrical Insulating Oils, ASTM D1524

Visual examination (D1524) on either new oil or in-service oil is a pass-fail test that looks for any foreign conditions or material in the sample. The “passing grade”, whether for new fluid or in-service fluid, is some variation of “clear and bright” – no evidence of suspended particles, cloudiness, turbidity, sediment, or any condition resulting from any contamination by solids or free water.

Oxidation Inhibitor Content (DBPC)

Standard Test Method for 2,6-Ditertiary Butyl Para-Cresol and 2,6-Ditertiary Butyl Phenol in Insulating Oil by Infrared Absorption, ASTM D2668

This test measures the two compounds used as added oxidation inhibitors and reports the total content of the two compounds as total oxidation inhibitor. This is a test of the chemical properties of the fluid. The test is performed on both new oil – for acceptance testing – and as a maintenance and monitoring test on in-service oil. New oil is typically characterized as being either Type I (uninhibited), with a maximum inhibitor content of 0.08 weight percent, or Type II (inhibited), with a maximum inhibitor content of 0.30 weight percent. An appropriate specification range for acceptance of inhibited oil is 0.20 to 0.30 weight percent inhibitor.

For in-service oil, inhibitor should be replenished if the inhibitor content decreases to below 0.1% by weight. Under normal circumstances, mineral oil dielectric fluid will not generally oxidize if the inhibitor content is properly maintained.

Liquid Power Factor

Standard Test Method for Dissipation Factor (or Power Factor) and Relative Permittivity (Dielectric Constant), ASTM D924

Dissipation Factor, or Liquid Power Factor, is a measure of the dielectric losses in an insulating liquid when used in an alternating current electric field. Dissipation factor and liquid power factor are not exactly equivalent, but vary by less than one part in a thousand up to a value of approximately 5% for the liquid power factor. They are essentially interchangeable for the values that are likely to be encountered in operating electrical equipment. Liquid power factor is an electrical property of the fluid, and relates both to the function of the fluid and to its purity. Highly refined oil, free from contamination, has a very low liquid power factor. Moisture, oxidation, and contamination all serve to increase the liquid power factor. For new oil as received from a supplier, typical specification values for liquid power factor are ≤ 0.050% when measured at 25 °C and 0.30% when measured at 100 °C. Liquid power factor is a particularly useful in-service tool for testing and monitoring oil because the test is sensitive to moisture, oxidation of the oil, and contamination from outside sources. Frequently, the pattern of increase for the 25 °C and 100 °C values can be used to identify specific conditions of concern.

Karl Fischer Moisture (KF)

Standard Test Method for Water in Insulating Liquids by Coulometric Karl Fischer Titration. ASTM D1533

Water content is a chemical property of new fluid related to its purity. New mineral oil leaves the refining process with very low water content, but can pick up additional moisture during storage, transfer to delivery containers or vehicles, transportation, and installation. A typical specification value for new oil, as received from the supplier, is a maximum of 25 ppm moisture. When new oil is installed in new equipment, it is typically processed through filters, heat, and vacuum. A typical specification value for new oil leaving the processor to be filled into new equipment is a maximum of 10 ppm moisture.

Once the oil has been installed in the equipment, the moisture content of the oil in ppm no longer tells the complete story. More important values from an operational and maintenance standpoint are the percent saturation of the oil and the percent moisture by dry weight of the solid insulation. These are calculated using the moisture content of the oil in ppm and the temperature of the oil at time of sampling. A typical specification for % moisture by dry weight for a new unit, prior to energizing is 0.5%.

As an in-service oil test, moisture content is a critical parameter. Again, the critical values are the % saturation and the % moisture by dry weight calculated from the oil temperature and the moisture content in ppm reported by the Karl Fischer Titration.

For fluids other than mineral oil dielectric fluid and for oil-filled equipment other than transformers, % saturation and % moisture by dry weight are not calculated. Evaluation of moisture results using ppm values and our established criteria provide a superior basis for management decisions in these cases.

Furanic Compounds (FUR)

Standard Test Method for Furanic Compounds in Electrical Insulating Liquids by High Performance Liquid Chromatography (HPLC), ASTM D5837

Analysis for furanic compounds (2-furaldehyde and several derivatives) in the insulating liquid is a test of chemical properties. Furanic compounds are typically only present as a result of paper degradation. It is an optional test of the composition of new oil. On rare occasions, furanic compounds may be present in new oil as a result of the refining process. Since furanic compounds analysis is a diagnostic test for degradation of the cellulosic insulation, new fluid should have a negligible furanic compound content. New fluid in a new transformer should be baseline tested and should have less than 20 ppb (μg/kg) of furanic compounds. Any increase in furanic compounds content and particularly the presence of any furanic compound other than 2-furaldehyde (2FAL), is an indication that the paper is being damaged by heat, moisture, electrical stress, or oxidation.

Dissolved Gas Analysis (DGA)

Standard Test Method for Analysis of Gases Dissolved in Electrical Insulating Oil by Gas Chromatography, ASTM D3612

The primary use of dissolved gas analysis (DGA) is as a routine monitoring insulating fluid test for electrical equipment. Incipient fault conditions – disruptions in the normal electrical and mechanical operation of electrical equipment – cause the fluid to break down, generating combustible gases. The profile of those gases can be interpreted to diagnose whether fault conditions exist, and how severe those faults may be. DGA is also used to determine the concentration of dissolved atmospheric gases (oxygen, nitrogen, and carbon dioxide) so that the operation of preservation systems such as conservators, continuous nitrogen systems, and nitrogen blankets can be evaluated.

Gas content of new fluid installed in equipment is frequently run. Appropriate operation of new equipment may require extremely low gas content in the newly installed oil – a typical specification value is 0.5% (5000 ppm) by volume of total gas dissolved in the oil. There are several methods for running this (ASTM D831, D1827, D2945), but a complete DGA by method D3612 gives a more useful result. Not only does the test quantify the total gas in ppm (the conversion to % can be easily done), it also tells which gases are present and in what quantities. DGA is also performed on samples drawn during factory heat runs (and sometimes during factory electrical testing) to monitor the integrity of newly manufactured units. Similarly, most installations of new, large transformers require close monitoring by DGA during the first days, weeks, and months of operation.

Dissolved Metals (ICP)

Dissolved Metals by ICP, Standard Test Method for Determination of Elements in Insulating Oils by Inductively Coupled Plasma Atomic Emission Spectroscopy (ICP-AES, ASTM D7151)

Dissolved copper and other metals act as catalysts to promote oxidation and also serve to elevate liquid power factor to unacceptable levels. Dissolved metals in sufficient quantity to promote aging of the oil can be removed by reclamation. Dissolved metals analysis is also useful to help diagnose fault conditions such as severe overheating or arcing/sparking indicated by other tests such as dissolved gas analysis. Dissolved metals analysis is sometimes performed on new fluids to evaluate whether refining or storage practices are resulting in elevated dissolved metals levels being introduced into the system. Since dissolved metals levels are generally measurable with brand new transformers, once energized, and tend to decrease to “none detected” levels before gradually increasing due to aging or jumping due to fault conditions, the recommendation for in-service oil is to baseline test units and then test every few years to evaluate gradual increases in metals. If dissolved metals content is to be used to help identify a transformer fault, the abnormal dissolved gas analysis will trigger a recommendation to perform metals analysis. Standard procedure is to test samples routinely for copper, iron, and aluminum, although many others can be run if conditions indicate a need.

Polychlorinated Biphenyls (PCB) Content

Standard Test Method for Analysis of Polychlorinated Biphenyls in Insulating Liquids by Gas Chromatography, ASTM D4059

SDMI’s classification of PCB test results is based on federal (US EPA) regulations. State or local environmental agencies may have different or more stringent requirements. Please check with your state or local agencies to determine the regulations that apply to you.

Federal PCB regulations (40 CFR 761.3) define three classifications for transformers and other electrical equipment based on the PCB content:

• PCB – Transformers and electrical equipment that contain PCBs 500 ppm (mg/kg) or greater.
• PCB-Contaminated – Transformers and electrical equipment that contain PCBs 50 ppm or greater, but less than 500 ppm.
• Non-PCB – Transformers and electrical equipment that contain PCBs less than 50 ppm.