Svenska kraftnät (Svk) is the transmission system operator in Sweden, with about 200 substations at 220 and 400 kV. Most were built several decades ago, and many will now need to be refurbished or replaced due to changes in demand with the ongoing energy transition.

Over the past 20 years, for safety considerations, composite insulators have been used exclusively for all apparatus at Svk substations. Moreover, in one 7-year period, only composite station post insulators were installed but with no special requirements during procurement other than material. More than 1000 composite station post insulators have been put into service spread over 30 substations and most were not equipped with grading ring protective devices when first installed. A significant number have since begun to show evidence of deterioration and internal damage.

Research was therefore initiated to replace these insulators with porcelain equivalents or to employ other countermeasures in cases where this was not feasible. The project included annual inspection of all composite station post insulators to continually assess status of the installed fleet during the replacement period. The goal was to prevent unexpected outages as well as to help prioritize the exchange program. These inspections revealed premature ageing from excessive electric field as well as quality issues such as poor adhesion between core rod and housing material.

This edited contribution to INMR by Peter Sidenvall of I2G, Pernilla Sahlén and Ebba Björk at Svk and Bertil Bartholdsson of Norconsult, focuses on this inspection program and the resulting status assessment

Inspections

Inspections were conducted on an annual basis at 400 kV substations and once every second year at 220 kV substations. Most took place during two monthly periods: September to November and February to April. This was to limit too much heating from the sun and to avoid snow- or ice-covered insulators. Ideally, inspections should all have been performed during cloudy weather and without precipitation, but that was not always possible. Classification of visual defects observed was made based on the CIGRE Guide, the STRI Guide and the EPRI Guide, although none of were followed strictly.

Three different inspections techniques were used: visual, infrared (IR) and ultraviolet (UV). These techniques operate in different regions of the electromagnetic spectrum (as shown in Fig. 1) and allow the inspector/operator to “see” extensive information within each respective spectrum. Diagnostic techniques discussed are in regard to CIGRE’s Guide for Assessment and the EPRI Yellow Book. For all, it was deemed important to have large, sensitive sensors and lenses with long focal length due to the relatively large distance between camera and the insulators being inspected.

1. Visual
Visual inspection reveals basic deterioration such as biological growths (leading to localized loss of hydrophobicity), installation errors, handling damage or lack of quality control. It can also reveal corrosion and traces of electrical activity in the vicinity of the end fitting. Where severe internal damage exists, there will be traces from electrical activity further down the insulator and in the worst cases punctures and cracks (see Figs. 2 & 3).

Moreover, several examples were found of inadequate quality control during installation and during manufacture of certain products (see Figs. 5 & 6.) While these are not necessarily restricted only to composite type insulators, they are still important within the overall assessment.

2. IR
Infrared inspections reveal apparent heat on the surface of an insulator. If the weather is cloudy and the insulator has been well dimensioned, it should have a homogeneous temperature profile along its entire length. In most cases, however, there will be a slight temperature rise in the vicinity of end fittings due to:

• Reflections and/or radiation from busbar and other nearby structures;
• Dielectric losses in the housing material due to high electric field (these will be more significant under humid conditions);
• Heating from continuous corona activity from the end fitting – if poorly field graded;
• Dry band and discharge activity due to pollution.

Inspections in sunny weather can be challenging to interpret since any heat from internal damage will be masked by significant heating from the sun (tens of °C). Moreover, during sunny conditions, any internal damage is not always fully active since such areas may dry out. As a result, it is always recommended to inspect insulators on their shaded side.

Dielectric losses can reach slightly less than 10°C in extreme cases but are normally only a few °C. Heating from corona activity from end fitting towards the housing material can reach up to about 5°C while water induced corona on the housing surface is detected as only slight heating, generally below 1°C. Dry band activity can heat the surface of the housing from a few °C, up to as much as 20°C. Fig. 7 shows examples from IR inspection.

It is important to note that heat transfer is slow. A good insulator from the dielectric perspective is also usually a good insulator from the thermal perspective. Thus, any internal heat source may not appear as hot on the surface of the housing as internal damage might suggest it should. Still, any internal defect close to the housing, at the observer’s side, will generally show more than 5°C of heating (in extreme cases up to approximately 100°C). Moreover, internal heating may not show on all sides of the insulator in the case of larger diameter station posts. Figs. 8 & 9 provide two examples.

It is also important to emphasize that absolute heating is not necessarily relevant to fully understanding the severity of internal damage. Position of the heating is more important when it comes to providing information on the length of the insulator that has been compromised.

It should also be noted that wind and precipitation can have a strong cooling effect on the surface of insulators. Together with the low heat transfer within insulating materials, it becomes possible to entirely miss internal defects under such conditions. Thus, it is important to take note of any slight changes in temperature – even less than 1 degree Celsius. With this in mind, it is easier to understand the importance of keeping temperature gradient within a narrow band.

3. UV

UV inspection can reveal poor electric field grading and pinpoint corona sources. Typically, these might be outliers such as bolts or sharp edges. But in the case of 400 kV insulators without protective devices, there is expected to be continuous corona activity from the end fitting.

In addition, such inspection indicates if any internal damage is present in an insulator which will lead to a conductive path and a change in electric field distribution along the unit. If electric field exceeds the electric withstand strength of air (approx. 2.4 kVRMS/mm) discharges will be initiated. If discharges appear somewhere along the surface away from the end fitting, electric field grading will be affected by a conductive layer. Figs. 10 & 11 offer examples from UV inspection.

Daylight UV-cameras only detect discharges directed towards the lens. This means that any defect positioned on the opposite side of the insulator from the viewing point will not be seen. This also means that any threshold of a discharge counter is not useful due to lack of knowing that all discharges of interest are directed towards the camera. Rather, the counter should only be used as offering an indicative measurement. In most cases, internal damage is not conductive enough to cause external discharges, and it will therefore not be detected. Any changed pattern of discharges is also an indication (see Fig. 12).

4. Combined Analysis

Based on findings from these inspection methods, further analysis and comparison should be performed. If there is an indication of an internal heat source, it is important to try to learn more. Changing viewing angle is the first thing to be done when a heated surface is found since this will reveal more information. It should also be compared against photos to reveal if any traces of damage on the surface can be correlated with the heated surface. Finally, it should also be compared with UV images.

An example of combined analysis is given by the left photograph in Fig. 12 where an indication of a change in electric field grading is given by the low intensity of corona discharges compared with neighbouring phases. Looking at IR images of the same insulator, another indication of internal damage is shown (to the left in Fig. 9).

Finally, looking at the insulator from the opposite side and from a greater distance, the internal defect becomes more distinct (the right in Fig. 9). In this case, it would not have been possible to draw the conclusion that there was severe internal damage within the insulator by looking only at the first UV or IR images. Such systematic analysis needs to be done for each indication of internal damage that is detected.

Status Assessment

Since this large-scale project includes tens of substations and approximately 1000 insulators, it was important to make continuous status assessments. These were made based on findings from visual, IR and UV inspection, and lastly on combined analysis from all.
The status assessment is performed using a traffic light principle whereby four colours are used indicating:

• Green – insulator seems fine;
• Yellow – no damage or deterioration but some countermeasure is needed, most commonly due to poor electric field grading;
• Orange – light damage or deterioration on insulator that will require some countermeasures and follow up inspection;
• Red – internal damage and need for insulator replacement.

Examples of such status assessments are shown in Fig. 13.

Looking at Fig. 13, the insulator with green assessment is hydrophobic on the surface of the housing, the grading ring appears to be properly positioned, and no deterioration is visible. The insulator with the yellow assessment has no grading ring and there is slight visible deterioration on the housing. The insulator with the orange assessment also has no grading ring while corrosion on the end fitting is starting to compromise the integrity of sealing. The insulator with the red assessment has no grading ring and traces from severe discharge activity are seen at some distance from the end fitting.

Once the status assessment for any individual substation has been completed, this is implemented into a substation layout to best prioritize replacement of station posts (see Fig. 14). This is performed for each substation where composite station posts have been installed.

All substations will be listed with their overall population of station posts as well as the latest status assessment for each (shown in Table 1). It should be noted that a “red” insulator might have damage reaching between 3% and 35%, resulting in urgency to remove it from service.

Table 1 reveals a pattern whereby more insulators become “orange” and “red” at 400 kV substations rather than “yellow” and “orange” as at 220 kV substations, even after similar times in service. This is due to excessive electric field on composite insulators, leading to premature ageing. Implementation of electric field strength limits, as in IEC 61109, is important but it is also important to apply this to other composite insulator standards.

Countermeasures

As stated, it has been decided to replace all composite station post insulators with porcelain types. Still, there are cases where this will not be possible due to foundations or metal stands that cannot withstand the increased of load from porcelain. Thus, some post insulators will be subject to other countermeasures.

Fig. 15 offer one such example where the insulators have grading rings installed but these have been poorly designed leading to excessively high electric field strength along and within the posts. However, since no severe deterioration has yet occurred, these insulators are considered still fit for purpose. The ring will be repositioned to reduce electric field strength, and the insulator kept in service for the reminder of its expected lifetime.

An example of re-designing the grading ring on a 400 kV insulator is shown in Fig. 16, where the ring has been moved 80 mm downwards to reduce maximum electric field strength along and within the insulator by approximately 35%.

Another example is where a 220 kV substation will be rebuilt in 5 to 10 years, and existing composite post insulators will therefore remain in service until refurbishment. Making matters more complex in this case, there are two manufacturers and designs of the insulators, SCL, etc. On some of these insulators, deterioration has already appeared such as peeling of the sealing and corrosion on the end fitting. Still, such deterioration processes are in the early stage, and it will take time for this minor damage to evolve into more severe damage. Nonetheless, to lessen risk, it has been decided to introduce grading rings onto these insulators with one ring style to provide protection for both insulator designs. Simulations were performed and it was found that maximum electric field strength along both insulators was reduced by about 70% with the ring installed. Fig. 17 illustrates these simulations.

Finally, a few substations will be left as is. From the inspection perspective, the composite station posts at these stations appear healthy after slightly more than 10 years’ service. However, since there was never any documentation from testing nor presence by utility personnel during factory acceptance tests, there remains a risk that the quality of these insulators is inadequate. These substations will therefore be further inspected every few years throughout their remaining technical lifetime.

Conclusions

There have been several lessons from this project. If concentrating on insulators, the most important is having an up-to-date specification when purchasing and installing composite insulators. The additional cost and effort required during insulator procurement will easily be exceeded by the need for continuous inspections if quality is not what was expected.

From the inspection point of view, a lesson for all camera operators is that all findings are only indications. They still will need to be verified from other angles, sensors, etc. to be fully understood. When looking at station post insulators, the large majority of internal damage develops on only one side, meaning that inspections from one direction might not be sufficient.

Many cases where internal damage has developed and propagated along insulators have been identified and continuously measured. This experience has added new insight into propagation rate of these types of damage. It has also provided insight into how excessive electric field will breakdown not only dielectric materials but also the galvanized layer of end fittings.

There are several examples in how best to identify and assess different types of IR and UV images. Hopefully, these will expand knowledge in diagnostics for composite insulators. They also show that damage propagation is in general a slow process, meaning that a utility should have sufficient time between identifying damaged insulators and replacing them.

As a utility, it may be easy to rely too much on manufacturers. Several important documents have been published over the past 15 years regarding electric field criteria for composite insulators. Yet there are still numerous examples of insulators being installed that have inadequate electric field grading. An up-to-date technical specification is important to ensure adequate quality of insulators.

Finally, inspections have shown the importance of following up the status of installations as well as of rigorous quality control of incoming materials.

References
[1] M. Radosavljevic, I. Gutman, C. Ahlholm, P. Sidenvall: “Ageing and deterioration of composite post insulators exposed to high electric field in 220 kV and 400 kV switchyards in Swedish network”, 2017 CIGRE SC B3 Colloquium, Recife, Brazil, 18-20 September 2017.
[2] P. Sidenvall, A. Sandoval, A. Taheri, J. Remelin: ”New competencies and diagnostic methods needed for the application of composite insulators in substations”, Cigre Session Paris, B3-10795, 25-30 August 2024, France.
[3] CIGRE WG B2.21: “Guide for the assessment of Composite Insulators in the Laboratory after their Removal from Service”, CIGRE TB 481, December 2011.
[4] STRI Guide: “Guide for Visual Identification of Deterioration & Damages on Suspension Composite Insulators”, STRI Guide 5, 2005.
[5] EPRI field guide: “Visual inspections of polymer insulators”, ID 3002005627, 2015.
[6] CIGRE WG B2.21: “Assessment of in-service Composite Insulators by using Diagnostics Tools”, CIGRE TB 545, August 2013.
[7] EPRI Yellow book: “Overhead Transmission Inspection and Assessment Guidelines – 2006”, ID 1012310, 4th edition, November 2006.
[8] IEC Standard: “Insulators for overhead lines – Composite suspension and tension insulators with AC voltage greater than 1 000 V and DC voltage greater than 1 500 V – Definitions, test methods and acceptance criteria”, IEC 61109 Ed. 3, 2025.
[9] A.J. Philips, A.J. Maxwell, C.S. Engelbrecht, I. Gutman: “Electric Field Limits for the Design of Grading Rings for Composite Line Insulators”, IEEE Transactions on Power Delivery, Vol. 30, No. 3, June 2015, p.p. 1110-1118.
[10] I. Gutman, P. Sidenvall: “Optimal Dimensioning of Corona/Grading Rings for Composite Insulators: Calculations & Verification by Testing”, INMR World Congress, Munich, Germany, 18-21 October 2015.
[11] P. Sidenvall, et al.: ”Limits of electric field for composite insulators: state-of-the-art and recent investigations of overhead line insulators purchased by power utilities”, CIGRE Science & Engineering, N. 24, February 2022.
[12] P. Sidenvall, F. Lehretz: “Key factors for reliable results in E-field simulations of OHTL insulators”, CIGRE Symposium, paper 10265, September 29 – October 3, Montreal, Canada, 2025.