The presence of trace amounts of water in transformer oil can occur during transportation, storage, and use, either due to external factors or the oxidation of the oil itself. This water exists in three states: 1) free water; 2) extremely fine particles dissolved in water; and 3) it accelerates the aging of insulating fibers. Since the molecules of insulating fibers are glucose (C6H12O6) molecules, water entering these fibers reduces their attraction, causing them to hydrolyze into lower molecular weight substances, thus reducing the fiber's mechanical strength and degree of polymerization.
Currently, power transformers are not only among the most important and expensive pieces of equipment in the power system, but also among the equipment that causes the most power system accidents. Before a sudden fault occurs, the deterioration of the insulation and latent faults in the transformer will produce a series of effects and information such as light, electricity, sound, heat, and chemical changes under the influence of the operating voltage. Therefore, both domestically and internationally, preventive maintenance based on preventive testing is carried out regularly, and predictive maintenance strategies based on online monitoring are being studied to monitor and diagnose latent faults or defects in real time or at regular intervals [1-4]. The content of trace water in the transformer insulating oil is also a parameter for determining the insulation quality of the transformer. Transformer online intelligent diagnostic equipment can automatically collect and analyze the content of trace water in the oil and determine the cause of the fault, provide solutions, and enable users to solve the hidden dangers in the transformer in a timely manner to prevent accidents.
1. The state and hazards of trace amounts of water in transformer oil
During transportation, storage, and use, water may enter the transformer from the outside or be produced by the oxidation of the oil itself. The produced water may exist in the following states:
First, there is free water. This is mostly moisture that has invaded from the outside and does not easily combine with water without stirring. It does not affect the breakdown voltage of the oil, but it is still unacceptable, indicating that there may be dissolved water in the oil, and it should be dealt with immediately.
Secondly, extremely fine particles dissolve in water. These particles typically enter the oil from the air, drastically reducing the oil's breakdown voltage. This increases dielectric loss, necessitating vacuum oil filtration.
Thirdly, emulsified water. Poor oil refining, oil aging due to long-term operation, or oil contamination by emulsions can all reduce the interfacial tension between oil and water. If oil and water mix together, an emulsion is formed. Adding a demulsifier is necessary.
Its hazards include: First, it reduces the breakdown voltage of the oil. The breakdown voltage drops significantly from 100-200 mg/kg to 1.0 kV. Fiber impurities in the oil easily absorb moisture, forming conductive "bridges" between the electrodes under the influence of an electric field, thus making it prone to breakdown.
Secondly, it increases the dielectric loss factor. Suspended emulsified water has the greatest impact, causing uneven distribution. Thirdly, it accelerates the aging of insulating fibers. The molecules of insulating fibers are glucose (C6H12O6) molecules. When water enters the fiber molecules, it reduces their attraction, causing them to hydrolyze into low-molecular-weight substances, reducing the fiber's mechanical strength and degree of polymerization. Experiments have shown that at 120℃, for every doubling of water content in insulating fibers, the fiber's mechanical strength decreases by half. As the temperature rises, the water content in the oil increases, while the water content in the fibers decreases; conversely, as the temperature decreases, the opposite occurs. Therefore, it is essential to monitor the trace amounts of water in the oil to monitor the aging of the insulating fibers. Fourthly, water enhances the corrosive ability of organic acids, accelerating the corrosion of metal components. In conclusion, the higher the water content in the oil, the faster the aging of the oil itself, the aging of equipment insulation, and the corrosion of metal components. Monitoring the water content in the oil, especially the dissolved water content, is crucial.
2. Test method for trace amounts of water in transformer insulating oil
Assessing the moisture content of insulation materials is a crucial factor in ensuring transformer reliability and lifespan. The moisture content in insulating oil is constantly changing, which can adversely affect its quality. Furthermore, most of the moisture is distributed within the insulating paper. Moisture affects the dielectric breakdown strength of both solid and liquid insulation materials, and influences the aging rate of cellulose insulation materials and the tendency for bubble formation during overload.
Ambient temperature, load, aging, leakage, and other factors cause continuous changes in humidity. Therefore, continuous monitoring and diagnosis are necessary as transformer temperature cyclically changes. This is especially important for transformers under overload or peak load. The total humidity in a transformer insulation system is determined by the moisture content in cellulose and liquid. The humidity relationship between insulating paper and insulating oil depends only on temperature. As temperature increases, the solubility of water in the insulating oil (the water-holding capacity of the solution) increases, and moisture transfers from the insulating paper to the insulating oil.
This process reverses as the temperature decreases, but the rate at which moisture flows from the liquid medium to the solid insulating material is quite slow. Therefore, the moisture content of the insulating oil is higher during cooling than during heating. Thus, to accurately determine the humidity distribution within a transformer, it is essential to know the equipment's position within its thermal cycle. To understand the true humidity of the insulating paper by monitoring the moisture content in the liquid medium, the transformer must be under relatively stable temperature conditions.
The relative saturation of moisture in insulating oil needs to be standardized because the humidity in insulating oil is closely related to temperature changes, and there is a certain temperature gradient in the transformer main box (usually the temperature at the top of the box is higher than at the bottom). To achieve standardization, expert system analysis needs to infer the percentage of relative saturation at the bottom. This can be obtained by using the temperature reported by sensors and their sampling locations.
This analysis assumes the transformer top temperature is 10°C higher than the bottom temperature. If sampling points are used at locations other than the top or bottom, the temperature deviation must be specified. Based on the relative humidity saturation and the specific measurement temperature, the expert system will calculate the insulation paper humidity as a percentage of relative saturation. It is important to note that this calculation is based on information from only a single measurement and may not reflect the true humidity concentration of the insulation paper, especially after the transformer has just experienced a drastic temperature change.
If the expert system determines that the transformer is in a balanced state (the insulating paper neither releases nor absorbs moisture), a second relative saturation percentage is calculated. This saturation is the average of the most recent 30 relative saturation percentage measurements taken when the transformer is in a balanced state. The previously recorded temperature and variations determine the criteria for determining whether balance exists. There are four available alarms. Humidity alarms are displayed with "P" as the first character. The second character is a number from 0 to 3. A P0 alarm indicates a sensor malfunction. A P1 alarm indicates that no analysis was performed. P1, P2, and P3 alarms all depend on the relative saturation percentage. Alarm conditions: 1. The relative saturation percentage of the insulating oil moisture is ≥50% but <75%; 2. The relative saturation percentage of the insulating oil moisture is ≥75%.
