As part of a complete preventive maintenance program, periodic oil analysis will monitor the condition of power transformers and detect problems before they reach serious proportions.

Power transformers are a vital link in the transmission and distribution of electrical power. In fact, almost every business, whether industrial or commercial, relies on transformers for its electric power supply. Since it's extremely important to keep them working, a preventive maintenance plan is essential.

A study by Hartford Steam Boiler over a period of 20 years indicates that 13% of all transformer failures were caused by inadequate maintenance. This number is significant, considering the study found that the average age of a transformer at the time of failure was only slightly more than 11 years; transformers are expected to last 25 to 30 years.

Since transformers have few, if any moving parts, it's easy to acquire an "out of sight, out of mind" mentality. However, as the above study points out, this attitude can prove costly in the long run. Instituting a planned maintenance program can greatly reduce the number of unexpected power interruptions caused by transformer failure. This program should include temperature, oil level, and gas pressure checks; operational checks on accessories such as fans, pumps, and load tap changers; and visual checks for cracked or leaking bushings. More importantly, these tests should be performed on a regularly scheduled basis because periodic testing and inspection provide trend information and permit repairs and other remedial action to be budgeted on a timely basis.

Why test insulating fluid?

One major element of a transformer maintenance program is periodic testing of insulating fluid. It should be performed in conjunction with the other routine maintenance functions mentioned above.

The insulating oil in a power transformer performs two major functions. First, it serves as electrical insulation to withstand the high voltages present inside the transformer. Second, it functions as a heat transfer medium to dissipate heat generated within the transformer windings. Thus, the oil must maintain good electrical properties while resisting thermal degradation and oxidation.

Most power transformers are filled with mineral oil refined to achieve the desired electrical and chemical properties. Some transformers, particularly indoor units, are filled with a synthetic fluid, such as silicon, R-temp, or Askarel (PCB fluid).

There are several benefits to conducting periodic analyses of a transformer's insulating fluid. First, the tests will indicate the interior condition of the transformer. Any sludge that is present within the transformer can be detected and effectively removed before it can proceed into the windings and other interior surfaces of the transformer. Eliminating sludge prolongs transformer life.

Another advantage of oil testing is the prevention of unscheduled outages. If problems are detected early enough, corrective action can be scheduled when disruption of electrical service will be minimal. A manufacturing facility for instance, can schedule servicing during shutdowns, when other maintenance functions are planned. Commercial locations may consider holidays and weekends for planned maintenance.

Finally, because transformer oil breaks down in a predictable fashion, periodic testing will prove helpful in determining any trends. This allows comparisons between normal and abnormal rates of deterioration. Although one set of test data will indicate the presence of contaminants, it will not enable accurate analysis of any trends that are developing.

How is testing done?

To measure the quality of insulating oil and establish a benchmark for the degree of deterioration, several tests are used. Samples of the fluid can be drawn while the transformer is in normal operation through drain valves or sampling ports. The following list describes some of the most common laboratory tests, and references the appropriate ASTM method.

Dielectric breakdown. (ASTM D877, D1816) Dielectric breakdown is the minimum voltage at which electrical flashover occurs in an oil. It's a measure of the ability of an oil to withstand electrical stress at power frequencies without failure. A low value for the dielectric breakdown voltage generally indicates the presence of contaminants, such as water, dirt, or other conducting particles in the oil.

Neutralization number. (ASTM D974) The neutralization number of an oil is a measure of the amount of acidic or alkaline materials present. As an oil ages in service, the acidity and, therefore, the neutralization number increases. A used oil having a high neutralization number indicates the oil is either oxidized or contaminated with materials such as varnish, paint, or other foreign matter. A negative neutralization number results from an alkaline contaminant in the oil.

Interfacial tension. (ASTM D971) The interfacial tension of an oil is the force, in dynes per centimeter, required to rupture the oil film existing at an oil-water interface. When certain contaminants such as soaps, paints, varnishes, and oxidation products are present in the oil, the film strength of the oil is weakened; thus less force is required to rupture the oil film. For oils in service, a decreasing value indicates the accumulation of contaminants, oxidation products, or both. It's a precursor of the presence of objectionable oxidation products that may attack the insulation and interfere with the cooling of the transformer windings.

Specific gravity. (ASTM D1298) The specific gravity (relative density) of an oil is the ratio of the weights of equal volumes of oil and water. A high specific gravity indicates the oil's ability to suspend water. In extremely cold climates, specific gravity can be used to determine whether ice, resulting from freezing of water in oil-filled apparatus, will float on the oil. Such a condition possibly may result in flashover of conductors extending above the oil level.

Water content. (ASTM D1315; D1533) This test measures the concentration of water contained within the oil. A low water content is necessary to obtain and maintain acceptable electrical strength and low dielectric losses in insulation systems.

Color. (ASTM D1500) This test compares the actual color of the oil to an established spectrum of colors. Expressed numerically from 0 to 5, a high color number indicates contamination caused by carbon or the deterioration of either insulation material or the oil.

Visual examination. (ASTM D1524) An oil sample is visually examined by passing a beam of light through it to determine transparency and identify foreign matters. Poor transparency, cloudiness, or the observation of particles indicate contamination, such as moisture, sludge, or other foreign matter.

Power factor. (ASTM D924) Power factor indicates the dielectric loss of an oil. A high power factor is an indication of the presence of contamination or deterioration products such as moisture, carbon, or other conducting matter, metal soaps, and products of oxidation.

Flash point. (ASTM D92) The flash point is the minimum temperature at which heated oil gives off sufficient vapor to form a flammable mixture with air. It is an indicator of the volatility of the oil.

Pour point. (ASTM D97) The pour point is the lowest temperature at which the oil will flow. A low pour point is important, particularly in cold climates, to ensure that the oil will circulate and serve its purpose as an insulating and cooling medium.

Corrosive sulfur. (ASTM D1275) This test detects the presence of objectionable quantities of elemental and thermally unstable sulfur-bearing compounds in an oil. When present, these compounds can cause corrosion of certain transformer metals, such as copper and silver.

Viscosity. (ASTM D455; D88) Viscosity is the resistance of oil to flow under specified conditions and is the principal factor in the convection flow of oil in an electrical device. It influences heat transfer and, consequently, the temperature rise in apparatus.

Dissolved gas analysis. All liquid-filled transformers generate gases during normal operation. When a transformer begins to function abnormally, the rate of gas production increases. Analyzing these gases and their rate of production is another valuable laboratory tool for evaluating the condition of an operating transformer.

The most accurate method of analyzing dissolved gas in a transformer is using gas chromatography. The gases dissolved in the oil are extracted from a sample and analyzed by a gas chromatograph. This method identifies the individual gases present and also the quantitative amounts. Several key gases are attributed to certain fault conditions that generated them. These are shown in the table below.

Condition

Overheating

Corona

Arcing

Overheated

Listing of fault conditions and the resulting generation of gases.

Interpreting the results from a gas chromatograph depends upon the total quantity of the combustible gases, the quantity of each individual gas, and the rate of increase. However, the interpretation of a dissolved gas test is not an exact science.

Since normal operation causes the formation of certain gases, simply determining the presence of gases within the oil should not cause alarm. What is important is the rate and amount of gases generated. As in other tests, gas analysis should be conducted on a regular basis to indicate trends or changes in results.