Transformer maintenance has evolved over the past 20 years from a necessary item of expenditure to a strategic tool in the management of electrical transmission and distribution networks. Extreme reliability is demanded of electric power distribution, and even though the failure risk of a transformer and other oil-filled electrical equipment is small, when failures occur, they inevitably lead to high repair costs, long downtime and possible safety risks. Moreover, transformers are too expensive to replace regularly and must be properly maintained to maximize their life expectancy.
By accurately monitoring the condition of the oil, suddenly occurring faults can be discovered in time and outages can potentially be avoided. Furthermore, an efficient approach to maintenance can be adopted and the optimum intervals determined for replacement. Some of the checks are relatively simple: the operation of the gas relays, the operation of the on-load tap-changer, checks on oil leaks, etc. However, breakdown of one of the most crucial elements, the oil paper insulating system, can only reliably be detected by routine oil analysis.
Information Gold Mine
By measuring the physical and chemical properties of oil, in addition to the concentrations of certain dissolved gases, a number of problem conditions associated with either the oil or the transformer can be determined. The following are some common tests performed on electrical insulating oils.
One of the most important functions of a transformer oil is to provide electrical insulation. Any increase in moisture content can reduce the insulating properties of the oil, which may result in dielectric breakdown. This is of particular importance with fluctuating temperatures because, as the transformer cools down, any dissolved water will become free, resulting in poor insulating power and fluid degradation. In addition, many transformers contain cellulose-based paper used as insulation in the windings. Again, excessive moisture content can result in the breakdown of this paper insulation with a resultant loss in performance.
Just like industrial oils, transformer oils are oxidized under the influence of excessive temperature and oxygen, particularly in the presence of small metal particles which act as catalysts, resulting in an increase in Acid Number, due to the formation of carboxylic acids. Further reaction can result in sludge and varnish deposits. In the worst-case scenario, the oil canals become blocked and the transformer is not cooled well, which further exacerbates oil breakdown. Furthermore, an increase in the acidity has a damaging effect on the cellulose paper.
Oil degradation also produces charged by-products, such as acids and hydroperoxides, which tend to reduce the insulating properties of the oil. An increase in Acid Number often goes hand-in-hand with a decrease in dielectric strength and increased moisture content as shown in Figure 1.
The dielectric strength (ASTM D300-00) of a transformer oil is defined as the maximum voltage that can be applied across the fluid without electrical breakdown. Because transformer oils are designed to provide electrical insulation under high electrical fields, any significant reduction in the dielectric strength may indicate that the oil is no longer capable of performing this vital function. Some of the things that can result in a reduction in dielectric strength include polar contaminants, such as water, oil degradation by-products and cellulose paper breakdown.
The power factor (ASTM D924) of an insulating oil is the ratio of true power to apparent power. In a transformer, a high power factor is an indication of significant power loss in the insulating oil, usually as a result of polar contaminants such as water, oxidized oil and cellulose paper degradation.
Gas Analysis (DGA)
Dissolved gas analysis (often referred to as DGA), is used to determine the concentrations of certain gases in the oil such as nitrogen, oxygen, carbon monoxide, carbon dioxide, hydrogen, methane, ethane, ethylene and acetylene (ASTM D3612). The concentrations and relative ratios of these gases can be used to diagnose certain operational problems with the transformer, which may or may not be associated with a change in a physical or chemical property of the insulating oil.
For example, high levels of carbon monoxide relative to the other gases may indicate thermal breakdown of cellulose paper, while high hydrogen, in conjunction with methane may indicate a corona discharge within the transformer. Some of the more common key gas analysis fault conditions can be seen in Figure 2.
Furan derivatives are a measure of the degradation of cellulose paper. When the paper ages, its degree of polymerization reduces, so its mechanical strength decreases. The degree of polymerization can only be determined directly by taking a sample of paper, a very complex operation and almost never performed in practice. However, the degree of polymerization of the paper can be directly related to the concentration of furan derivatives in the oil. Furan derivates are formed as a direct result of the breakdown of the polymeric structure of cellulose paper. The content of furan derivatives is relatively easy to measure in the oil, using HPLC and is thus a way of measuring the aging of the paper.
Just like machinery oil analysis, electrical insulating oil analysis can play a vital role in preventing unscheduled outages in electrical transmission and distribution equipment by determining the condition of the equipment itself, and other vital components including the condition of the oil and the cellulose paper insulation. For all critical oil-filled electrical equipment, including transformers, circuit breakers and voltage regulators, regular, routine oil analysis should be the cornerstone of any PM program.
Transformer Sampling (ASTM D923)
Just like machinery oil analysis, the ability of insulating oil analysis to provide an early warning sign of a problem condition is dependent on the quality of the oil sample that is sent to the lab. A sampling point on any equipment should be identified and clearly labeled for the technician. As with sampling locations in other types of equipment, the same location should be used each time a sample is collected to ensure representative conditions are tested. This point should be located in a place where a live oil sample can be collected rather then in an area where the oil is static.
Fluids with specific gravity greater then 1.0, such as askarels, should be sampled from the top because free water will float. For fluids with a specific gravity less than 1.0, such as mineral-based transformer oils, synthetic fluids and silicone oils, the sample should be taken from the bottom since water will tend to drop to the bottom in these fluids.
There are a number of environmental variables, such as temperature, precipitation, etc., to consider before collecting a sample. The ideal situation for collecting a sample from an electrical apparatus is 95°F (35°C) or higher, zero percent humidity and no wind. Cold conditions, or conditions when relative humidity is in excess of 70 percent, should be avoided, as this will increase moisture in the sample. Collecting a sample during windy conditions is also not recommended because dust and debris enter the clean sample easily and disrupt accurate particle counts. If sampling the oils is unavoidable when the outside temperatures are at or below 32°F (0°C), it should not be tested for water content or any properties that are affected by water such as dielectric breakdown voltage.
For dissolved gas analysis, an elaborate procedure must be followed, including the use of a glass syringe; with strict adherence to sampling protocol to ensure that the concentration of dissolved gases is not influenced in any way by sampling procedure. This procedure is described in detail in ASTM D3613.