What Are the Causes of Transformer Aging?

Transformer aging is mainly caused by improper operation during service, which leads to excessive power loss and frequent equipment failures. Below is a summary of common loss-related issues encountered during transformer production and operation:

I. Prevent Overload Operation by Transformer Manufacturers

Most transformers adopt Class A insulating materials with a maximum allowable temperature of 105°C. The core and windings reach the highest temperature inside the transformer, followed by the top-layer oil, while the bottom-layer oil maintains the lowest temperature. The measured average winding temperature is about 10°C lower than the hot-spot temperature, hence the specified limit of 85°C for top oil temperature. (When the temperature rises from 85°C to 95°C, the oil oxidation rate doubles.)

Relationship between temperature and temperature rise: Allowable temperature = Allowable temperature rise + 40°C. If the ambient air temperature exceeds 40°C, full-load operation is prohibited. It is generally recognized that oil-immersed transformers can achieve a normal service life of approximately 20 years when the maximum winding insulation temperature stays between 95°C and 98°C.

If the temperature reaches 105°C, the service life drops to roughly 7 years; at 125°C, the service life is only about 2 years. Long-term safe operation of transformers can only be guaranteed if the top oil temperature and temperature rise never exceed rated limits.

Overload operation accelerates irreversible aging and shortens transformer service life. For example, in 1996, a power supply bureau conducted chromatographic analysis of insulating oil and found excessive total hydrocarbon content in seven 110–220 kV transformers caused by local overheating. The seven overheated transformers were immediately put under load limitation to avoid further local overheating faults.

II. Prevent Sudden Short Circuits at Transformer Terminals

Power systems feature large capacity, and short-circuit currents at load-side terminals are substantial, resulting in a high risk of transformer damage. The following measures are implemented to ensure safe transformer operation:

1. Modify the neutral grounding mode of the 10 kV system. Urban areas contain extensive cable circuits, so the 10 kV neutral point is grounded via a 16 Ω resistor. After resistor grounding, the resistor discharges accumulated charge in the half-cycle after arc extinction during single-phase grounding, suppresses oscillation energy, reduces zero-sequence potential, slows the rising rate of recovery voltage, and drastically cuts the amplitude and occurrence probability of overvoltage.

2. Suburban areas have more overhead lines; automatically tuned arc suppression coils are installed at the 10 kV neutral point of substations. Adjusting the 10 kV neutral grounding mode eliminates the risk of single-phase faults evolving into three-phase short circuits, preventing transformer burnout from three-phase short circuits at terminals.

3. Fully enclosed enhanced-insulation vacuum switchgears are adopted for 10 kV substation equipment. All newly built substations are equipped with fully enclosed vacuum switchgears. For older substations, insulation wrapping is applied to transformer 10 kV outgoing lines and high-voltage room busbars. Power grids nationwide promote oil-free and full-condition upgrading of 10 kV switchgears to strengthen equipment insulation.

4. Improve operating environments of 10 kV power distribution rooms via full enclosure, dehumidification, regular cleaning, and air conditioning installation for critical distribution rooms.

5. Install line zinc oxide surge arresters and distribution explosion-proof zinc oxide surge arresters to lower system overvoltage levels. Accelerate distribution network renovation to optimize operating conditions and reduce short-circuit failure rates.

III. Adopt Fully Sealed Transformers

Fully sealed transformers isolate transformer oil from air to slow oil oxidation. For non-fully sealed transformers, strengthen maintenance of sealing capsules and implement nitrogen filling treatment.

Partial discharge refers to localized discharges between electrodes that do not form a complete conductive breakdown path. It arises from inherent defects inside equipment insulation or manufacturing flaws, causing repeated breakdown and extinction under high electric field strength.

Manifestations include gas breakdown inside insulation, partial breakdown of solid or liquid dielectrics in small regions, or localized discharge triggered by concentrated electric field strength at edges and sharp corners of metal surfaces. Continuous partial discharge under operating voltage creates cumulative degradation effects: weak discharges gradually deteriorate the dielectric properties of insulation, expand internal defects, and eventually lead to complete insulation breakdown.