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Home / Technical Articles / 15 hypothesis responsible for the aging of composite insulators
15 hypothesis responsible for aging of composite insulators
15 hypothesis responsible for aging of composite insulators (on photo: Composite insulator with integrated fiber-optic cable for transpower by

Major causes of aging in composite insulators

Most technical work concentrates on the aging of nonceramic insulators and the development of test methods that simulate the aging process. Transmission lines operate in a polluted atmosphere.

Inevitably, insulators will become polluted after several months in operation. Fog and dew cause wetting and produce uneven voltage distribution, which results in surface discharge. Observations of transmission lines at night by a light magnifier show that surface discharge occurs in nearly every line in wet conditions.

UV radiation and surface discharge cause some level of deterioration after long-term operation.

These are the major causes of aging in composite insulators which also lead to the uncertainty of an insulator’s life span. If the deterioration process is slow, the insulator can perform well for a long period of time.

This is true of most locations in the U.S. and Canada.

However, in areas closer to the ocean or areas polluted by industry, deterioration may be accelerated and insulator failure may occur after a few years of exposure. Surveys indicate that some insulators operate well for 18–20 years and others fail after a few months.

An analysis of laboratory data and literature surveys permit the formulation of the following aging hypothesis:

1. Wind drives dust and other pollutants into the composite insulator’s water-repellent surface. The combined effects of mechanical forces and UV radiation produces slight erosion of the surface, increasing surface roughness and permitting the slow buildup of contamination.

2. Diffusion drives polymers out of the bulk skirt material and embeds the contamination. A thin layer of polymer will cover the contamination, assuring that the surface maintains hydrophobicity.

3. High humidity, fog, dew, or light rain produce droplets on the hydrophobic insulator surface. Droplets may roll down from steeper areas. In other areas, contaminants diffuse through the thin polymer layer and droplets become conductive.

4. Contamination between the droplets is wetted slowly by the migration of water into the dry contaminant. This generates a high resistance layer and changes the leakage current from capacitive to resistive.

5. The uneven distribution and wetting of the contaminant produces an uneven voltage stress distribution along the surface. Corona discharge starts around the droplets at the high stress areas. Additional discharge may occur between the droplets.

6. The discharge consumes the thin polymer layer around the droplets and destroys hydrophobicity.

7. The deterioration of surface hydrophobicity results in dispersion of droplets and the formation of a continuous conductive layer in the high stress areas. This increases leakage current.

8. Leakage current produces heating, which initiates local dry band formation.

9. At this stage, the surface consists of dry regions, highly resistant conducting surfaces, and hydro- phobic surfaces with conducting droplets. The voltage stress distribution will be uneven on this surface.

10. Uneven voltage distribution produces arcing and discharges between the different dry bands.These cause further surface deterioration, loss of hydrophobicity, and the extension of the dry areas.

11. Discharge and local arcing produces surface erosion, which ages the insulator’s surface.

12. A change in the weather, such as the sun rising, reduces the wetting. As the insulator dries, the discharge diminishes.

13. The insulator will regain hydrophobicity if the discharge-free dry period is long enough.Typically, silicon rubber insulators require 6–8 h; EPDM insulators require 12–15 h to regain hydrophobicity.

14. Repetition of the described procedure produces erosion on the surface. Surface roughness increases and contamination accumulation accelerates aging.

15. Erosion is due to discharge-initiated chemical reactions and a rise in local temperature. Surface temperature measurements, by temperature indicating point, show local hot-spot temperatures between 260°C and 400°C during heavy discharge.

ABB Composite Insulators – Design for reliable performance

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The presented hypothesis is supported by the observation that the insulator life spans in dry areas are longer than in areas with a wetter climate.

Increasing contamination levels reduce an insulator’s life span. The hypothesis is also supported by observed beneficial effects of corona rings on insulator life.

DeTourreil et al. (1990) reported that aging reduces the insulator’s contamination flashover voltage. Different types of insulators were exposed to light natural contamination for 36–42 months at two different sites. The flashover voltage of these insulators was measured using the “quick flashover salt fog” technique, before and after the natural aging. The quick flashover salt fog procedure subjects the insulators to salt fog (80 kg/m3 salinity). The insulators are energized and flashed over 5–10 times. Flashover was obtained by increasing the voltage in 3% steps every 5 min from 90% of the estimated flashover value until flashover.

The insulators were washed, without scrubbing, before the salt fog test.

The results show that flashover voltage on the new insulators was around 210 kV and the aged insulators flashed over around 184–188 kV. The few years of exposure to light contamination caused a 10–15% reduction of salt fog flashover voltage.

Natural aging and a follow-up laboratory investigation indicated significant differences between the performance of insulators made by different manufacturers. Natural aging caused severe damage on some insulators and no damage at all on others.

Reference: George G. Karady and R.G. Farmer – Insulators and Accessories

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Edvard Csanyi

Electrical engineer, programmer and founder of EEP. Highly specialized for design of LV/MV switchgears and LV high power busbar trunking (<6300A) in power substations, commercial buildings and industry facilities. Professional in AutoCAD programming.

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