Discharge faults pose a critical threat to the insulation system of oil-immersed self-cooled transformers, as insulation integrity is the core of transformer safety. Two primary mechanisms drive this damage:
First, discharge processes generate high-energy particles that directly bombard the transformer’s insulation materials (such as insulating oil, paper, and cardboard). This continuous mechanical impact erodes the insulation structure at a microscopic level, creating cracks, thinning layers, and eventual breakdown. Over time, the insulation’s ability to withstand voltage declines, increasing the risk of short circuits.
Second, electrical discharges react with the surrounding air and oil, producing ozone (O₃) and nitrogen oxides (NOₓ). These reactive chemical substances exhibit strong corrosive properties: ozone oxidizes the organic components of insulating materials, causing them to become brittle and prone to cracking, while nitrogen oxides react with moisture in the environment to form acidic compounds. These acids further degrade insulation materials and corrode metal parts adjacent to the insulation system. Additionally, discharges release localized heat, leading to thermal aging of insulation—accelerating material decomposition and reducing its service life.
Partial discharge refers to unstable, localized electrical discharges that occur at the edges of cavities or gaps within the transformer’s insulation structure under voltage stress. Unlike full-scale short circuits, partial discharges do not bridge the entire insulation gap but are confined to specific areas. The root cause of this fault often lies in trapped gas within the transformer oil or insulation cavities. Gas has a lower dielectric constant compared to solid insulation materials (e.g., insulating paper) and transformer oil, resulting in uneven electric field distribution within the insulation system. When the electric field strength in the gas-filled gaps exceeds the gas’s breakdown voltage, partial discharge is initiated.
While the energy intensity of a single partial discharge is relatively low, long-term, repeated discharges accumulate damage. Over time, the continuous bombardment of high-energy particles, chemical corrosion from discharge byproducts, and localized heating gradually degrade the insulation around the discharge site. If left unaddressed, this process can lead to insulation breakdown, turning a seemingly minor issue into a severe safety hazard that compromises the transformer’s entire operation.
Insulation damage is one of the most prevalent faults in oil-immersed self-cooled transformers, with four key contributing factors:
- Moisture Infiltration During Installation: During transformer installation or maintenance, if the oil tank is not fully sealed or the oil filling process is incomplete, air enters the system. Moisture in the air condenses and accumulates around insulation components (e.g., windings and bushings). Water is a strong conductor, and its presence significantly reduces the insulation’s dielectric strength, making it susceptible to breakdown under normal operating voltages.
- Inadequate Drying of Insulation Materials: Shortened manufacturing cycles may lead to insufficient drying of insulating paper and cardboard before assembly. These moisture-absorbing materials gradually release trapped moisture during operation, especially under load-induced heating. This moisture diffusion lowers the insulation performance of low-voltage windings, increasing DC leakage current and raising the risk of insulation failure.
- Poor Sealing Design or Deterioration: Over time, seals (such as gaskets and O-rings) may degrade due to aging, temperature cycles, or mechanical wear. Poor sealing allows external moisture and contaminants to penetrate the transformer, directly affecting the insulation system’s integrity. This issue is particularly prominent in outdoor transformers exposed to rain, humidity, and dust.
- Gas Generation from Insulation Degradation: During long-term operation, solid insulation materials (e.g., cellulose-based paper) or stainless steel components may decompose under thermal or electrical stress, producing gases such as hydrogen (H₂) and carbon monoxide (CO). High concentrations of these gases in transformer oil indicate ongoing insulation degradation. Manufacturers must consider gas adsorption and emission during the design and production phases to prevent gas accumulation from exacerbating insulation issues.
To mitigate the above faults and enhance transformer reliability, the following industry-proven solutions are recommended for manufacturers and operators:
When constructing new substations or deploying transformers, high and low-voltage fuses must be installed in strict compliance with national and industry specifications. Fuses act as the first line of defense against overloads and short circuits, preventing excessive current from damaging the transformer’s windings and insulation. If a fuse is blown or stolen during operation, immediate replacement with a correctly rated fuse is mandatory—using improper or substandard fuses can lead to catastrophic failures.
Fuse rating configuration directly impacts protection effectiveness. For transformers with a capacity exceeding 100kVA, fuses rated at 2.0 to 3.0 times the transformer’s rated current are recommended to accommodate occasional overloads while ensuring rapid tripping during severe faults. For transformers with a capacity of 100kVA or less, fuses rated at 1.5 to 2.0 times the rated current are sufficient, as smaller transformers have lower thermal capacity and require more sensitive protection.
Regular power load measurements are critical, especially during peak demand periods (e.g., summer air conditioning use or winter heating seasons). Use clamp-on ammeters to conduct real-time load testing at least once per peak period, and adjust the load distribution across phases to avoid unbalanced operation. Three-phase load imbalance can cause excessive current in individual windings, leading to overheating, insulation aging, and reduced transformer efficiency.
Tap changers are used to regulate the transformer’s output voltage. For 10kV transformers, if the low-voltage side voltage falls within the range of -10% to +7% of the rated voltage, adjustment is generally unnecessary. When voltage adjustment is required, qualified test technicians must perform trial adjustments first. This involves verifying the tap changer’s mechanical operation, checking for contact resistance, and ensuring the voltage stabilizes at the desired level before formal operation. Improper tap changer adjustment can cause voltage fluctuations or internal arcing.
Periodically monitor the three-phase current of the transformer to ensure it remains balanced and within the rated current range. If significant imbalance (exceeding 15% of the rated current) is detected, take immediate action—such as redistributing single-phase loads—to restore balance. Prolonged unbalanced operation not only degrades insulation but also increases energy losses and may damage other power system components.
Lightning strikes are a major cause of transformer insulation breakdown. Before the arrival of each thunderstorm season, all surge arresters installed on distribution transformers must be sent to professional testing institutions for comprehensive inspections. This includes testing insulation resistance, discharge voltage, and leakage current. Only arresters that pass all tests should be reinstalled to ensure they can effectively divert lightning-induced overvoltages and protect the transformer.
Before putting a new or maintained transformer into operation, the following tests must be completed:
- Load Duration Test: Conduct a load test for the specified duration (typically 30 minutes) to verify thermal stability and insulation performance under operating conditions.
- Tap Changer Operation Test: Switch the tap changer three times sequentially to ensure smooth mechanical movement and reliable contact.
- Test Button Verification: Press the built-in test button three times to confirm the protective devices (e.g., residual current protectors) function normally.
- Ground Resistance Test: Perform three consecutive ground resistance measurements—each result must be ≤4Ω to ensure effective grounding and fault current diversion.
Regularly clean dirt, dust, and corrosive substances from the surface of transformer bushings. Dirt accumulation can cause surface leakage current or flashover, especially in humid environments. Inspect bushings for flash marks, cracks, or oil seepage—any defects require immediate replacement. Additionally, check the grounding system: ensure the grounding lead is intact (no broken strands, desoldering, or fractures) and measure the grounding resistance at least twice a year to maintain compliance with ≤4Ω standards.
Oil leakage is a common fault that can lead to insulation degradation and overheating (since oil acts as both an insulator and coolant). Common leakage points include flange connections, oil tank welds, and seal joints. To address this:
- Conduct regular visual inspections to identify leakage sources—pay special attention to areas prone to vibration or thermal expansion.
- For minor leaks, replace worn seals or tighten bolts; for severe leaks (e.g., weld cracks), empty the oil, repair the defect, and re-test for tightness.
- Analyze the oil quality regularly (e.g., moisture content, dielectric strength, and dissolved gas analysis) to detect early signs of insulation degradation caused by leakage.
By implementing these targeted fault analysis and solution strategies, oil-immersed self-cooled transformer operators can significantly reduce the risk of malfunctions, extend equipment service life, and ensure the stable, reliable operation of the entire power system. Manufacturers and maintenance teams should prioritize preventive maintenance and scientific fault diagnosis to minimize downtime and optimize grid performance.
