Quality of transformer oil is tested in several stages of its use. Regular control of the oil’s quality is a part of the process of servicing electric equipment. The main parameters of oil and its purity indicate transformer condition.
The ability of the oil to maintain its original properties during operation of electric equipment is referred to as oil stability. If the equipment has not defects and operates without failures, the parameters of new oil change very slowly. New transformer oil has light color and complies with regulations, which define the oil’s dielectric strength and other properties. In use, stability of the oil decreases and notable changes occur, the color changes to dark.
Poor oil quality is indicated by high ash content, increased acidity and presence of low molecular acids. Acidic sludge forms in contaminated oil, which disrupts cellulose insulation and reacts with the metals of the transformer’s internal components.
Oil tests can identify the beginning of oil degradation.
The main physical and chemical properties tested are the oil’s dielectric strength, dissipation factor, flashpoint, color, solid, water and gas content as well as acid number.
Dielectric strength is one of the most important indications of oil stability and this is often the first test performed. It is calculated as an average of five breakthrough achieved in a standard discharger with two electrodes at 2.5 mm distance. Six breakthroughs are achieved in the test and the last five are averaged. If the oil is fresh, the lowest allowable breakthrough voltage is 30 kV. In some transformers, that is as good as needed.
Decreasing dielectric strength indicates contamination of the oil by gas, moisture, cellulose fibers or other particulate matter.
A similar process is used to calculate dissipation factor. The oil’s ability to neutralize energy, prevent breakthroughs and cool the transformer is characterized by the oil’s quality and purity, or acidity. In general, increased dissipation factor means degradation of the oil’s dielectric capabilities.
The color of transformer oil changes from light yellow to cloudy brown under the influence of temperature, contaminants and current. The color is not in itself an indication of any specific problem, but dark color is usually an indication of aged oil.
The presence of solid particles and the acid number of the oil are related. Unsolved materials accumulated in the oil in the form of sludge or suspended particles (fibers, dust, solved paint, metal particles, ash etc) degrade the oil’s dielectric properties and promote oil oxidation. The more particles are present in the oil, the faster the oil ages. The acid number is expressed as milligrams of KOH required to neutralize all acids in a gram of oil and indicates the degree of oil aging. Normal acid number is 0.25 mg KOH/g, while the limit of contaminant content is 515 ppm.
Moisture and gas content in transformer oil is tested thoroughly, because water and air are some of the main “catalysts” of oil aging process.
Moisture content is measured as amount of hydrogen when reacting the oil with calcium hydride in a certain time. Gas content is measured by an absorptiometric analyzer or a chromatographer.
Flashpoint and setting point are indications of general fire safety of the oil and its ability to operate in adverse temperature conditions.
Therefore, the advantages of testing and analyzing transformer oil before starting electric equipment and during regular maintenance, allow to determine the equipment’s efficiency, operation conditions and possibility of malfunctions. If the purity and quality regulations are followed, the facility is safe from failure and downtime of equipment and related repair costs.