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This post was last edited by yuchenchf on 2017-3-28 at 17:07. The performance parameters of transformer oil are tested, and its quality is assessed in accordance with **power industry standards**, relevant standards, or international standards. The details are as follows: 1. Acid value: The acidic substances present in the oil increase its electrical conductivity and reduce its insulating properties. At higher operating temperatures (above 80°C), these substances can also cause aging and corrosion of solid fiber insulating materials, thereby shortening the service life of the equipment. Since the acid value in oil reflects the aging condition of the oil, strengthening the monitoring of the acid value is important for taking appropriate maintenance measures. 2. Moisture: Moisture is one of the key factors affecting the insulation aging of transformer equipment. An increase in water content in transformer oil and insulating materials directly leads to a decline in insulation performance and accelerates the aging of the oil, affecting the reliability and service life of the equipment. Strict monitoring of moisture is an essential test item to ensure the safe operation of the equipment. 3. Closed-cup flash point: The flash point is an essential parameter for monitoring operating oil. A decrease in flash point indicates the presence of volatile flammable gases in the oil ； These flammable gases are often generated as a result of local overheating of electrical equipment and arc discharge, which causes the insulating oil to undergo thermal pyrolysis at high temperatures. Flame point testing can help detect equipment failures in a timely manner. For newly filled equipment as well as transformer oil that has been overhauled, determining its flash point can also help prevent or detect the presence of oils containing light fractions, thereby ensuring the safe operation of the equipment. 4. Corrosive sulfur: The presence of corrosive sulfur in transformer insulating oil can pose a risk of reduced insulation performance in the transformer. 5. pH value (water-soluble acids): In the initial stages of oxidation, transformer oil tends to produce low-molecular-weight organic acids such as formic acid and acetic acid. Since these acids are highly water-soluble, an increase in their concentration in the oil (i.e., a decrease in the pH value), combined with the presence of water in the oil, can cause corrosion of solid insulating materials and metals. This, in turn, reduces the insulation properties of electrical equipment and shortens its service life. 6. Volume resistivity: The volume resistivity of transformer oil, just like the dielectric loss factor, can be used to determine the degree of aging and contamination of the transformer oil. Water, contaminating impurities, and acidic products in the oil can all contribute to a decrease in resistivity. 7. Sludge: This method is used to detect the sludge deposits that are still in a dissolved or colloidal state in the operating oil; these deposits can be precipitated out of the oil when heptane is added. Due to the different solubilities of sludge in new oil and aged oil, when new oil mixes with aged oil, the sludge precipitates out. The deposition of this sludge affects the heat dissipation capabilities of the equipment; it also causes severe corrosion of solid insulating materials and metals, leading to a decline in insulation performance, which poses significant risks. Therefore, when oils are mixed in a ratio of more than 5%, it is necessary to conduct tests to detect the precipitation of sludge. 8. Breakdown voltage: The breakdown voltage of transformer oil is used to assess its ability to withstand extreme electrical stresses, and it represents an important monitoring parameter. Generally, this value depends on the degree of contamination, but high levels of moisture or the presence of impurity particles in the oil have a significant impact on the breakdown voltage. 9. Dielectric loss factor: The dielectric loss factor is highly sensitive to determining the degree of aging and contamination of transformer oil. New oil contains few polar impurities, so its dielectric loss factor is also very low, generally in the range of only 0.01% to 0.1% ； However, when oil aging occurs due to oxidation or overheating, or when other impurities are mixed in, the amount of polar impurities and charged colloidal substances generated increases gradually, and as a result, the dielectric loss factor also rises. Even when there are very few aging products in the oil and they cannot be detected by chemical methods, the dielectric loss factor can already be clearly identified. Therefore, the determination of the dielectric loss factor is a common method for the inspection and monitoring of transformer oil, and it holds special significance. 10. Interfacial tension: The measurement of the interfacial tension between oil and water is an effective indirect method for detecting soluble polar impurities in the oil that result from aging. During the initial stage of aging, the change in interfacial tension is quite rapid; by the middle stage of aging, this rate of change slows down. Moreover, the formation of sludge increases significantly; therefore, this method can also provide a reliable assessment of the trend in sludge generation. 11. Gas content: The gas content in transformer oil refers to the total amount of gases dissolved in the insulating oil. During the operation of a transformer, gases dissolved in the oil are released to form bubbles, which accumulate within or on the surface of the insulating paper layers. This can lead to partial discharges, posing a threat to the safe operation of the equipment. 12. Content of gas components in oil: Combustible gases in oil are generally generated due to local overheating or discharge decomposition of the equipment. If the causes of the generation of flammable gases are not identified and eliminated in a timely manner, it poses a serious threat to the safe operation of the equipment. Therefore, using gas chromatography to determine the gas components in oil is highly effective in eliminating latent faults in transformers. This test is an essential part of the monitoring of transformer oil during operation. 13. Furfural content: The furfural content method is a convenient and practical approach for monitoring the insulation aging of oil-immersed transformers. The logarithm of the mass concentration of furfural in the oil shows a good linear relationship with the degree of polymerization of cellulose, which indicates the degree of aging of the insulating paper. 14. Particle size in oil: As power transformers continue to evolve towards ultra-high voltage and larger capacity, the requirements for 500 kV transformer oil are also increasing. Solid particle impurities have a significant impact on the electrical properties of the oil. To ensure the safe operation of ultra-high voltage transformers, it is necessary to monitor particulate impurities. 15. Oxidation stability: The oxidation stability test of transformer oil is an important method for evaluating its service life. Due to the good oxidation stability of domestic oils and the addition of antioxidants, this test is usually performed only on new oils. However, for imported oils, especially those without antioxidants, this test should be carried out not only on new oils but also after several years of operation, in order to take appropriate maintenance measures and extend their service life. 16. Freezing point: Based on the climate conditions in our country, transformer oil is classified into different grades according to its low-temperature performance. For example, the grades 10, 25, and 45 refer to freezing points of -10, -25, and -45°C respectively. Therefore, the determination of the freezing point is necessary for the acceptance of new oils and the mixing of oils of different grades. 17. Appearance: Examine the appearance of the operating oil; insoluble sludge, fibers, and dirt can be detected in it. In routine tests, a record of this item should be kept. 18. Color: New transformer oil is generally colorless or pale yellow; its color gradually deepens over time as it is in use, but under normal conditions this change occurs at a slow pace. If the color of the oil darkens sharply, it is necessary to investigate whether there has been overloading or overheating of the equipment. If all other relevant characteristic test items meet the requirements, it can continue to operate, but enhanced monitoring should be implemented. .