These can also be referred to as the “Oil Screen Package”. The standard oil screen package consists of acid, IFT, D877 dielectric, color, specific gravity, and visual inspection (appearance and sediment). The D1816 dielectric is reported in the “Liquid Screen” section of the report even though it is separate from the standard oil screen package.

Date:

This is the draw date for the sample.

Acid:

Also referred to as acid number or neutralization number. Our standard test method is a manual titration, ASTM D974.

When oil oxidizes and ages in service, some of the oxidation decay products that are formed are acidic in nature, meaning that they will react with and be neutralized by a base (alkaline) material. The standard method uses potassium hydroxide (KOH) to react with the acidic compounds in the oil. The amount of KOH needed to react with all of the acidic compounds is noted by a color change of an indicator included in the oil/reagent mixture. As acid number increases for in service oil, it is a representative and direct measure of how much the oil has oxidized. Acid number is reported as milligrams KOH per gram of sample (mg KOH/g).

Classification of Neutralization Number results for transformer oil is as follows:

Questionable or unacceptable results indicate that the oil has oxidized. A first test in the QU or UN range, or a sudden change exceeding the acceptable limit of 0.05 mg KOH/g, should be confirmed by a retest. Otherwise, if the acid number value is the result of a visible trend in the results over time or if a QU or UN value is confirmed by retest, the oil and the equipment should be hot oil cleaned.

IFT:

Materials that do not mix readily, such as water and transformer oil, form a surface or interface when they are brought into contact with each other. This interface between oil and water is a real barrier. It requires a measurable amount of force to move an object from the water up into the oil floating on top. The strength of the barrier between oil and water is the interfacial tension, usually abbreviated as IFT.

Clean, new, and well-refined transformer oil has a relatively high IFT, measured and reported as millinewtons per meter (or as dynes per centimeter, an essentially equivalent unit). As the oil ages and oxidizes, the polar compounds that are formed by the oxidation weaken the interface, reducing the interfacial tension. This occurs because the polar molecules are partially soluble in both the oil and in the water; so individual molecules are oriented along the interface.

New, highly refined oil is generally in the range of 45 to 50 mN/m for IFT. When installed in new equipment, the IFT of new oil will be reduced by about 5 to 10 mN/m as the oil picks up contamination from the inside of the new equipment. IFT will then gradually trend downward as the oil ages. IFT is also a very representative and direct measure of the degree of aging and oxidation of transformer oil.

The classification for interfacial tension results is as follows:

As with acid number, questionable or unacceptable results indicate that the oil has oxidized. A first test in the QU or UN range, or a sudden change decreasing the value below the acceptable limit of 32 mN/m should be confirmed by a retest. Otherwise, if the acid number value is the result of a visible trend in the results over time or if a QU or UN value is confirmed by retest, the oil and the equipment should be hot oil cleaned.

D877:

There are two ASTM standard methods for dielectric breakdown voltage of insulating liquids, D877 and D1816. The D877 method measures the breakdown voltage using a test cell that has two flat disk electrodes spaced 0.10 inches apart. The test cell is filled, and the electrical potential between the two disk electrodes is steadily increased by 3,000 volts every second until there is a discharge between the electrodes, indicating that the dielectric strength of the oil between the electrodes has been exceeded.

The purpose of performing dielectric breakdown voltage determinations is to evaluate the oil's ability to withstand electrical stress. Contamination of the oil due to such things as fibers from the solid insulation, conductive particles, contamination by foreign matter, dirt, and water can affect dielectric breakdown voltage. The utility of the D877 test is limited because the test is not sensitive to moisture unless the moisture content exceeds 60% of the saturation level, and it is not measurably sensitive to oxidation products in service aged insulating oil.

The value from a D877 determination still has meaning, however, and is a valid tool as long as the limitations and relative insensitivity of the test are acknowledged. The D877 method will indicate the presence of some types of contamination in mineral oil filled transformers. Also, it is useful for equipment other than transformers that typically exhibit higher moisture content or where there may be metal particles present and for equipment filled with fluids other than mineral oil.

Classification of dielectric breakdown voltage results using the D877 method is as follows:

A QU or UN D877 value should be investigated to determine the cause and correct the condition, if appropriate.

D1816:

This standard method of measuring dielectric breakdown voltage uses spherical VDE (Verband Deutscher Elektrotechniker) electrodes. The method is run at one of two gap settings, either 1 millimeter (0.04 inches) or 2 millimeters (0.08 inches). The D1816 method for determining dielectric breakdown voltage is more sensitive to moisture and is also sensitive to polar compounds such as oil oxidation products. Sensitivity to some particles, particularly insulation fibers, is much more consistent with this method.

Because of the greater sensitivity, the rate of voltage rise is lower – 500 volts per second. Also, the D1816 test cell has a motor driven agitator. This agitator runs during the test to cause the oil to flow between the electrodes, carrying suspended particles into the gap between the VDE spheres where they can affect the breakdown voltage.

The classification for D1816 dielectric breakdown voltage results depends on the primary voltage class of the equipment and is as follows, for the two gap settings (dielectric breakdown voltages are in kilovolts):

Subject to the limitations and cautions described below, a QU or UN D1816 value should be investigated to determine the cause, and correct the condition, if appropriate.

In addition to being sensitive to moisture, particles, and contamination, the D1816 dielectric breakdown voltage method is also sensitive to the presence of dissolved gases. This limits the usefulness of this method also, although it is more widely applicable than the D877 method. A “good” D1816 result indicates that there is nothing seriously wrong with the dielectric breakdown strength of the oil. A “bad” D1816 result, however, does not always indicate that there is something wrong with the oil. Acceptable levels of the other materials to which the test is sensitive can be detected along with a normal amount of dissolved gas to depress the D1816 result so that it is no longer in the acceptable range.

Depending on the D1816 to provide meaningful results for smaller industrial and distribution class equipment that is gas blanketed is usually not terribly useful. Frequently, the D1816 results indicate there may be problems with the dielectric breakdown voltage when those problems are not real. Even for higher voltage classes, or larger equipment where dissolved gas levels are much reduced and where the D1816 may be recommended as a routine monitoring test, care must be taken when interpreting D1816 results to ensure that resources are not expended to chase down problems that do not exist except as a peculiarity of the test method.

Color:

ASTM Standard Method D1524 is a method for visual examination of electrical insulating oils in the field that includes estimation of the ASTM color. ASTM Standard Method D1500 is a laboratory determination for ASTM color. Results from the two methods are very similar, but not identical. Typically, the results are close enough to being equivalent that the difference does not affect any management decisions concerning the oil and the equipment, so it is largely a matter of convenience concerning which method to use.

The color of new transformer oil is very low, typically less than 0.5. As the oil ages and oxidizes, it gets darker. Contamination may also cause a rapid change in color.

Taken by itself, color has little meaning. “Bad” oil can be lightly colored, while dark oil can still be of like new quality in all other respects. Poor color of the oil rarely affects the performance of the oil in service. Further, reclaimed oil that meets or exceeds all other performance and quality criteria may still be somewhat dark in color.

Classification of color results is as follows:

An unacceptable result or a large change from one year to the next is normally investigated as to cause.

Specific Gravity:

Specific gravity is also (and more accurately) known as relative density. It is a physical property of the insulating oil and is simply the ratio of the mass of a specific volume of the oil to the mass of the same volume of water at the same temperature.

Naphthenic transformer oil has a relative density between 0.84 and 0.91. Most oils that are actually in service fall into a narrower range of about 0.86 to 0.89. Values lower than 0.84 typically indicate that the oil is a paraffinic oil, and some synthetic oils, particularly the synthetic isoparaffinic oils, also fall in this range. Values over 0.91 indicate contamination by higher density materials, and a normal “suspect” for such contamination is PCBs.

The classification for relative density is as follows:

Relative density is a calculated ratio and has no specific units of measurement.

Relative density usually does not change as the oil is in-service because aging and oxidation have little effect. Values outside of the acceptable range or significant changes between normal monitoring intervals are of concern, and the cause should be identified.

Visual and Sediment:

Our standard method of doing a visual examination of oil is ASTM D1524. The oil sample is visually checked for cloudiness, turbidity, suspended particles, visible sediment or sludge, carbon, free water, or anything that is not clear, homogeneous transformer oil.

“Clear” is the only acceptable value for Visual, and “None” is the only acceptable value for Sediment. Cloudiness or turbidity indicates suspended water droplets, carbon, or sludge. Visible carbon indicates that there has been arcing in the equipment.

Any conditions other than acceptable values for both should be investigated further, and may require other diagnostic tests such as dissolved gas analysis, ICP analysis for dissolved metals, or particles and filming compounds analysis.

Date:

This is the draw date for the sample.

5H2F:

5-hydroxymethyl-2-furaldehyde content in ppb, in micrograms 5H2F per kilogram sample – ug/kg.

2FOL:

2-furyl alcohol content in ppb, ug/kg.

2FAL:

2-furaldehyde content in ppb, ug/kg.

2ACF:

2-acetyl furan content in ppb, ug/kg.

5M2F:

5-methyl-2-furaldehyde content in ppb, ug/kg.

Total:

The total content of these five furanic compounds in ppb, ug/kg.

Recommendation:

This includes a service recommendation (typically, a recommended retest interval or other recommendation such as “investigate”) for the most recent set of furan test data. Also, there is a standard paragraph with an interpretation or diagnosis for the most recent set of furan data.

Both parts of the recommendation are assigned during review of the data by a laboratory supervisor and are specific to a given set of results.

Calculated DP:

The furan results are used to calculate an average expected DP for the paper in the equipment. The calculation is dependent upon whether the transformer insulation is made up of thermally upgraded paper or not.

Est. Life Remaining:

The calculated DP is used to estimate the percentage of the solid insulation life that remains.

The solid insulation in a transformer is made up of paper. Paper is made up of cellulose fibers. Cellulose is a polymer formed from glucose molecules. When the paper is brand new, before it has been installed in a transformer and factory dried, the average cellulose polymer chain is 1000 to 1200 glucose molecules long. Installation and drying breaks down the cellulose a little bit, so that new paper in a new transformer has slightly shorter polymer chains – about 800 to 1000 glucose molecules long. We call the average cellulose chain length the “Degree of Polymerization” (DP) of the paper. As the paper ages, there is a natural and gradual breakdown of the polymer chains. As the chains get shorter, the mechanical strength of the paper is also reduced.

DP of the paper has a direct relationship to the mechanical strength (tensile strength) of the paper. When DP has been reduced by aging to 200, the paper is so weak that any stress will disrupt the paper and lead to failure. This is the practical definition of the end of reliable life for the solid insulation and therefore the end of life for the equipment.

When the cellulose chain breaks and two shorter chains are formed, the breakdown process “kicks out” one or more of the glucose molecules and also creates some water, carbon monoxide, and carbon dioxide. The glucose molecule changes chemically during this process and forms a compound containing a furan ring.

The change in furan content – the amount of furanic compounds generated during the testing interval – is the most important parameter for determining whether there is an active fault in the equipment that needs to be addressed. For a first analysis, where there is no past history – or where the past history is so old as to be virtually meaningless – we use the following standards for interpreting results:

In addition to our AC, QU, and UN ranges, we consider very high levels to be of more immediate concern. Levels over 1000 ppb indicate severe, irreversible damage to the solid insulation. We consider this to be the start of the “danger zone” because we start to see transformer failures in the range of 1000 to 1500 ppb total furans. We typically do not recommend reclaiming or other oil maintenance procedures for transformers where the total furan content is in this range. End of reliable life for a transformer with thermally upgraded insulation that has aged gradually, without hot spots, is approximately 2800 ppb total furans.

Dissolved gas analysis is a critical test for monitoring the mechanical and electrical operation of electrical equipment. It is particularly useful for diagnosing fault conditions and operational problems with transformers and load tap changers.

Date:

This is the draw date for the sample.

Hydrogen:

Hydrogen (H2) content in parts per million (ppm) by volume, microlitres H 2 per litre of sample – uL/L.

Oxygen:

Oxygen (O2) content in parts per million (ppm) by volume – uL/L.

Nitrogen:

Nitrogen (N2) content in parts per million (ppm) by volume – uL/L.

Methane:

Methane (CH4) content in parts per million (ppm) by volume – uL/L.

Carbon monoxide:

Carbon monoxide (CO) content in parts per million (ppm) by volume – uL/L.

Carbon dioxide:

Carbon dioxide (CO2) content in parts per million (ppm) by volume – uL/L.

Ethane:

Ethane (C2H6) content in parts per million (ppm) by volume – uL/L.

Ethylene:

Ethylene (C2H4) content in parts per million (ppm) by volume – uL/L.

Acetylene:

Acetylene (C2H2) content in parts per million (ppm) by volume – uL/L.

Total Combustible:

The sum of concentrations for the six combustible gases – hydrogen, methane, carbon monoxide, ethane, ethylene, and acetylene – in parts per million (ppm) by volume – uL/L.

Total Gas:

The sum of concentrations for all nine gases – the combustible gases plus oxygen, nitrogen, and carbon dioxide – in parts per million (ppm) by volume – uL/L.

Recommendation:

This includes a service recommendation (typically, a recommended retest interval or other recommendation such as “investigate”) for the most recent set of gas-in-oil test data. Also, there is a standard paragraph with an interpretation or diagnosis for the most recent set of dissolved gas data.

Both parts of the recommendation are assigned during review of the data by a laboratory supervisor and are specific to a given set of results.

Fault conditions generate gases dissolved in the oil. Gases from the atmosphere also dissolved in the oil. The dissolved gas data can be interpreted using specific qualitative and quantitative tools to confirm normal operation of the equipment or to diagnose that a fault condition exists.

Quantitative tools such as key gas analysis and quantitative tools such as ratio methods of interpretation have high reliability for diagnosing the type of abnormal condition present – faults such as arcing, sparking, partial discharge, general overheating, and hot spot overheating. Changes in the gas profile and in the concentrations of the individual gases are extremely important to providing an appropriate diagnosis and recommendation.

The industry standard for interpreting dissolved gas analysis results is ANSI/IEEE Standard C57.104: Guide for the Interpretation of Gases Generated in Oil-Immersed Transformers. Our interpretations and recommendations are based in large part upon this standard, modified somewhat to incorporate our experience and database developed over the past thirty years.