Transformer Oil Quality

Transformer Oil Quality

Oil quality is a term to encompass a set of chemical and physical properties describing the condition of the insulating oil. Specifying and purchasing oil has a long list of test requirements. But the focus of Key Element 2 are seven tests. The results of these tests give great insight to the internal condition of the transformer and are typically part of the annual maintenance program. These test results are aggerated and produce the second element for the Transformer Health Index. This helps Engineers and Subject Matter Experts (SME) know where to focus the resources of the maintenance and test crews. 

The insulation system is constantly under attack from three enemies (oxygen, heat, and moisture). When moisture and oxygen enter the transformer, it causes the oil and paper insulation system to begin the breakdown process. As the transformer undergoes more stress such as overloading or the deterioration of the seals in the oil preservation system, there is ever-increasing damage to the oil and paper insulation system. The breakdown produces acids, metal soaps, sludge, and other polar compounds. If left unchecked, the insulation system enters a death spiral. This can be prevented by keeping an eye on the results from the oil quality test.

At the utility, the process begins by taking an oil quality sample in a new high density polyethene (HDPE) plastic opaque 1-liter bottle. Utilities have proven, with data and experience, that new HDPE plastic opaque bottles are better than glass bottles that may break. These samples are sent to the lab where the oil properties are tested using ASTM or IEC standardized methods. Routine samples typically include seven tests and only one bottle is required per transformer for all seven tests.  

The seven routine oil quality test yield the subcomponents for Key Element 2. They are as follows: Moisture in Oil, Dielectric Breakdown, Power Factor, Interfacial Tension, Neutralization Number or Total Acid Number, Color, Inhibitor Content. These tests are covered in the ASTM and IEC standards.

1) Moisture in oil measures the weight of the moisture divided by the weight of the oil. The results are reported in ppm. It is very important to know the temperature of the oil sample when it is collected to determine the relative saturation. 

Moisture has a long-term effect that deteriorates the paper and a short-term effect that can cause a flashover in the insulation system under certain conditions. This is because 99% of the moisture is found in the paper. As the transformer heats up, a small amount of moisture slowly migrates from the paper to the oil. Even 0.5% change in the moisture of the paper will cause a major change in the amount of moisture in the oil. Fortunately, the ability of the oil increases, thus the relative saturation stays relatively constant as long as the heating and cooling are slow. The relative saturation is important because a higher saturation percentage causes a lower dielectric breakdown voltage. Also, if the relative saturation is greater than 100%, water will precipitate out of the oil as free water and fall toward the bottom [6]. The water on its way to the bottom may fall across an area of high electrical stress, which would cause a flashover in the transformer. This is most likely to happen on transformers with a high moisture content based on the oil-saturation numbers and if the load drops suddenly such that the transformer oil cools quickly. 

2) Dielectric breakdown measures the AC voltage at which the oil fails electrically. The results are reported in kilovolts (kV).

A test cell is a better representation of the internals of a transformer compared to the test cell described in the cell. The test cell for the ASTM D1816 has a stirrer that keeps the oil circulating much like oil pumps or the convection heating of the oil by the core and coils. Also, the test probes do not have sharp edges emulating the inside of a transformer.  

A test cell is a better representation of an oil circuit breaker or a tap changer compartment where the oil is not circulating because of convection or pumps.

3) A Power factor measures the dielectric losses in the oil by taking the cosine of the phase angle of the applied voltage and resulting current. Power factor results are reported in percent and is routinely measured with the oil heated. 

Dissipation is similar to power factor where the leakage current through the oil measures the contaminants such as moisture, oxidation products and varnishes.

4) Interfacial tension (IFT) measures the presence of soluble contaminants and oxidation byproducts. Interfacial tension is reported in dynes/cm or mN/M.

5) Neutralization Number (NN) or Acid Number measures the amount of potassium hydroxide required to neutralize the acid in one gram of oil. NN is expressed in mg KOH/g. 

6) A Color compares the oil color to a series of color standards. Color is reported as a number ranging from 0 to 5 where 0 is almost clear and 5 is dark brown. Darkening of the color is associated contamination of the oil. In most cases the contamination is assumed to be related to oil deterioration but the IFT and NN results are needed to confirm the color results.

7) A Most mineral oil-filled transformers contain 2,6-ditertiarybutyl para-cresol (DBPC) or 2,6-ditertiary-butyl phenol (DBP) which acts as an oxidation inhibitor. It can be compared with a human taking anti-oxidant vitamins. The oxidation inhibitor declines over time as it performs it job to protect the oil.