Quality Assurance: Methods of Transformer Oil Testing

The performance characteristics of transformer insulating oil are monitored and tested at several stages during its service life.  Regular monitoring of the oil’s quality and condition is a part of the process of servicing electric power equipment. The condition of the oil, its purity and contamination level will greatly help in indicating the condition of the transformer’s solid insulation.  It is therefore, essential to the life of the transformer to periodically monitor the condition of the insulating oil.  The heart of the transformer is the solid insulation, but the insulating oil is the life blood of the transformer.  Without the life blood, the heart will die.

The ability of insulating oil to maintain its original performance characteristics during long term operation of electric equipment is referred to as “oil stability.”  If the electric power equipment has no defects and operates in accordance with design and expectations, the performance characteristics of new oil will change and degrade slower.  When new, transformer oil has a very light color and complies with performance standards that include dielectric strength and other important characteristics.  During the course of the oil’s service life, the stability of the oil decreases and visible changes occur and oil’s color slowly becomes darker and darker.

Contaminated oil usually has a high ash content, increased acidity and presence of low molecular acids.  Acidic sludge forms in contaminated oil and aggressively attacks the cellulose insulation and reacts with the metals of the transformer’s other internal components.

Timely oil monitoring and oil analysis programs can identify when the oil needs to be changed or serviced through an oil purification and/or oil regeneration process.  Servicing the oil before it becomes aggressive against the solid insulation is the key to extending the service life of your transformers.

The main physical and chemical properties tested are the oil’s dielectric strength, dissipation factor, flashpoint, color, amount of solid particulate matter, water content, gas content and the oil’s acid number.

Dielectric strength is one of the most important indications of oil stability and this is often the first test performed.  The “dielectric breakdown test” is calculated as an average of five breakthroughs achieved in a standard discharger with two electrodes submersed in the oil at 2.5 mm distance from each other.  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 meets the minimum operating standard.

Decreasing dielectric strength is caused by contamination of the oil by gas, moisture, cellulose fibers or other particulate matter.

A similar process is used to calculate the oil’s “dissipation factor.”  It is the the oil’s ability to neutralize energy, prevent breakthroughs and cool the transformer.   It is a characteristic of the oil’s quality and purity and acidity.  In general, an 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 electric current.  The color is not in itself an indication of any specific problem, but a dark color is usually an indication of aged and/or contaminated oil.

The presence of solid particles in the oil and the acid number of the oil are two related oil purity characteristics.  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 that 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.  A normal and acceptable acid number is 0.25 mg KOH/g, while the limit of contaminant content is 515 parts per million (ppm).

Moisture and gas content in transformer oil must be tested for thoroughly.  Water and gases are very damaging to your transformer insulation system and are two main cause of the oxidation process and oil aging process.

Moisture and water content is measured as amount of hydrogen when reacting the oil with calcium hydride in a certain period of time.  Gas content is measured by an absorptiometric analyzer or a chromatographer.

The oil’s flashpoint and the oil’s setting point are two indications of the general fire safety of the oil and the oil’s ability to operate in adverse temperature conditions both hot and cold.

The are distinct advantages of testing and analyzing transformer oil before starting your electric power equipment and during scheduled maintenance events.  Oil testing allows the operator to determine the equipment’s operating efficiency, conditions and the possibility of future malfunctions.  If the purity and quality standards are followed, the equipment will be less likely to experience failures and downtime and unscheduled maintenance and repair costs.

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