Key Issues for Future of Composite Insulators - - INMR

The electric power industry in China experienced rapid increase since the s and, with recent development of UHV AC and UHV DC lines, there was a surge in electricity generation as well as in the length of the country’s overhead network. Figs. 1 and 2 depict growth in generation and length of overhead transmission lines from to and from to respectively. 

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Development of insulators cannot be viewed separately from development of the power sector as a whole. For example, rapid growth in length of overhead lines and the move to higher voltage levels brought not only a huge increase in demand for insulators but also new and greater requirements in terms of their performance. Because of advantages in regard to superior wet and pollution flashover performance, light weight, high strength to weight ratio, easier transport and installation, resistance to vandalism, etc., application of silicone rubber composite insulators in China realized significant growth. 

Statistics on number of line insulators purchased by the State Grid Corporation of China (SGCC) from Jan to Sept are shown in Fig. 3. This data covers the range 110 kV to kV AC, and ±800 kV DC as well as 70 kN to 550 kN SML (in the case of porcelain, glass and silicone composite insulators) and kN SML for composite insulators. During this period, the SGCC purchased 34.1 million porcelain insulators, 25.3 million glass insulators and about 5.13 million strings of silicone composite insulators. If converted to number of strings to allow for direct comparison, porcelain accounted for approximately 2.48 million strings and glass for about 1.85 million strings. The proportions of porcelain, glass and composite insulator strings purchased were therefore 26%, 20% and 54%, respectively. Moreover, among newly installed insulators, the number of composite insulator strings was more than the sum of the other two types of strings. This confirms that China has become the first country where silicone rubber insulators dominate EHV as well as UHV overhead lines. 

Composite insulators also realized significant increase in usage worldwide and, based on trial applications, now dominate all UHV lines. Moreover, major improvement has been achieved both in their manufacture and testing. Still, given the rapid development of this technology, the key issue for the future of composite insulators is that power utilities remain confident in their expected service life and performance. That means future development of composite insulators (as shown in Fig. 4) will depend on: availability of suitable test methods to verify long-term performance; establishing different requirements when it comes to station insulators; and developing the best materials and maintenance techniques. 

Test Methods & Long Term Performance

Among the technical standards published to ensure performance of composite insulators is IEC , Polymeric HV insulators for indoor and outdoor use – General definitions, test methods and acceptance criteria, whose scope covers polymeric insulators where the insulation body consists of one or more organic materials. Polymeric insulators covered by this standard include both solid and hollow core insulators intended for application on overhead lines or for indoor and outdoor equipment with rated voltage greater than V. Unfortunately, test methods within IEC do not necessarily guarantee satisfactory performance over the full service life of an insulator. For example, some composite insulators that pass the standard tests offer different performance when in operation, even in similar environments. One specific problem is that such tests are not yet sufficient to adequately screen for interface quality, rod quality and quality of the shed-to-housing interface. 

Tests on Rod Material

The present IEC standard only specifies a dye penetration test and a water diffusion test for the rod material. But rod damage in service continues to account for a large proportion of insulator failures, such as brittle fracture and decay-like fracture. For example, as shown in Table 1, rod failure has been a leading cause of service failures, accounting for some 22.3% of all such incidents. This suggests that rod quality is far from satisfactory and that more test methods are needed to guarantee quality and prevent such damage. 

While brittle fracture failure occurs among only a very low proportion of all composite insulators in service, it could result in sudden conductor drop with serious consequences. Usually, insulators so affected fail at low mechanical loads and after only several months or years of service. The fracture surface in such cases is typically flat and smooth, as shown in Fig. 5. 

While brittle fracture has been reported in many countries, from Europe to China, there is still no relevant IEC test. Since the mechanism behind such failure is clearly stress corrosion, such a test has already been developed and adopted in the Chinese electric power industrial standard DL/T 810- (revised in ). Specifically, this standard requires that the FRP rod must be acid proof (i.e. use boron-free glass). Since publication of this standard, there have been no reports of brittle fracture among newly installed composite insulators with acid proof rods. This serves to confirm that specifying such rods eliminates this risk. Decay like fracture is another type of rod failure mechanism. Although incidence of this phenomenon is even less than brittle fracture, the problem is as serious. Affected insulators also fail at low mechanical load after only a few years of service. But in this case the fracture surface is crisp, like dead wood, as in Fig. 6. Moreover, chalking has been seen on the surface of affected insulator sheds and it was found that glass fiber separated from the resin in the rod. In China, this problem has occurred mainly on 500 kV lines and it is worth noting that such failures have increased over the past 10 years. 

The current test in the IEC standards cannot guarantee prevention of decay-like fracture since some rod materials have passed yet subsequently failed in operation. Moreover, the exact mechanism behind these is still not fully clear. Experience suggests that such fractures can be detected before failure using IR imaging to look for a local temperature rise. But this allows only detection. In order to prevent the problem, more screening tests need to be conducted on the rod material. 

Tests on Shed Material

In the IEC standard, tests on the housing/shed consist of 4 parts: hardness test, accelerated weathering test, tracking and erosion test ( h salt fog test); and flammability test. According to experience at the SGCC as well as at the China Southern Power Grid, these tests need improvement. For example, the current IEC standard does not consider hydrophobicity and its transfer. Also, the test method for tracking and erosion should be improved while the multi-stress test does not seem suitable for materials such as silicone rubber. Hydrophobicity and its transfer are the most important properties for HTM (hydrophobicity transfer material) composite insulators but still not mentioned in IEC. In this regard, Tsinghua University has proposed a test method for hydrophobicity and its transfer in the case of silicone rubber insulators and this has been used in China for 15 years now. Put forward in local standard DL/810-, the test is divided into 4 parts: a hydrophobicity test, a loss of hydrophobicity test, a recovery of hydrophobicity test and a transfer of hydrophobicity test. Each has its own test method and acceptance criteria. 

As for the present IEC tracking and erosion test, there are still questions about method and effects. For example, salt spray directed toward the insulator in the h salt fog test seems misleading in terms of the technical requirements actually placed on a composite insulator applied in severe service conditions. A rotating wheel dip test is another option for assessing tracking and erosion performance but unfortunately shows relatively large scatter in results at different laboratories. There is also the issue of testing much larger insulator diameters as is now necessary by ongoing development of composite station insulators. Also, with increasing application of composite insulators on HVDC lines and at converter stations, a tracking and erosion resistance test under DC voltage has been specified in China but is still not clear in IEC. 

To guarantee long-term performance of shed material, an accelerated weathering test has been recommended within IEC. Unfortunately, this has no effect on silicone rubber based on experience to date in China. Specifically, the current test does not sufficiently simulate the effect of non-soluble pollutants and the hydrophobicity change process for silicone rubber material. A modified h test procedure – the THU h test procedure – has therefore been proposed. This test procedure (see Fig. 7) contains two major modifications: 1. replacing the salt fog with mixed contamination fog (NaCl and kieselguhr) and 2. providing sufficient time for hydrophobicity loss and discharge activities in the fog chamber and also sufficient time for hydrophobicity transfer in the UV chamber (as per Fig. 8). 

Tests on Interfaces

Poor interface adhesion or failure of interface coupling in a composite insulator can result in different types of problems, e.g. interface puncture, local temperature rise caused by interface leakage current and eventually decay-like fracture. Moreover, there may also be a relationship between weak interface adhesion with brittle fracture. There is evidence that this may be a growing problem since the interface between rod and shed is always the critical area of a composite insulator. IEC and other standards provide tests for interfaces and connections including the reference dry power frequency test, the pre-stressing and verification test. A steep-front impulse voltage test (kV/μs) is the main test of performance. A limited test cannot guarantee performance of the interface over tens of years of operation outdoors. In fact, failures of the shed–rod interface have been documented going back to a survey in where 203 insulators were found to have failed because of problems in the shed-rod interface (see Table 2). Similar findings were reported in another survey conducted in (see Table 1), where 69 insulators were reported to have failed because of interface breakdown. The interface problem is significant if looked at over the past 30 years. Indeed, a survey in China over this time frame showed similar results. 

The present steep front impulse voltage test according to IEC and IEC does not seem able to guarantee interface quality and this test has therefore been modified in recent years. Applied voltage is changed from kV/ ms to 30 kV/cm and this means a higher requirement for interface performance. A new test method for the interface seems necessary. Among the possibilities is interface resistivity measurement, recently proposed by Tsinghua University and used to test the dielectric property between silicone rubber and FRP rod. 

Low Price & Long-Term Performance

Due to intense competition, the relative market price of silicone rubber insulators versus other types is highly attractive these days. This is especially so in the case of higher voltages. For example, cost comparison between porcelain, glass and composite insulators of from 110 kV to kV AC as well as ±500 kV and ±800 kV DC in China is shown in Figs. 9a & b, respectively. Insulator cost per string is calculated based on application in a general service environment. It can readily be seen that silicone rubber composite insulators are always far less costly than either porcelain or glass insulators and that this cost advantage increases with higher voltage or mechanical level. The cost differential is even greater in the case of DC. 

While a lower acquisition cost is one of the advantages offered by silicone rubber composite insulators, too low a price may suggest possible increased risk of lower quality and inferior long-term performance. Based on Chinese service experience with HTV silicone rubber, some insulators have operated without problem for more than 15 years but many early generation products had to be replaced within a decade. Since number of years in service is now often less than 20 years, this could impact user perceptions and confidence in composite insulators. The new generation of SR composite insulators is expected to operate for longer. But since utilities want to purchase reliable as well as less costly insulators and since manufacturers need to control cost of production, current insulator standards are not sufficient to meet all these interests. 

Modifications to Standards

Modification to test methods in the current standards is urgent but it is also important to first define the technical requirements that must be met. A technical standard has to guide the insulator manufacturer to correctly understand the requirements of outdoor insulation and to avoid any random changes in composition or production process. At the same time, another requirement is to guide the utility procurement process. Quality of composite insulators is determined by material, design and by the manufacturing process. Accordingly, in order to improve performance, tests on material, design and manufacturing may need to be incorporated into future standards. In China, for example, DL/T 810- has been used for 15 years now and marked changes from the first to second generation silicone composite insulators. As mentioned, a stress corrosion test was conducted to prevent brittle facture, while both a hydrophobicity and a hydrophobicity transfer test were defined for HTM materials. Other elements included a tracking and erosion test for HVDC as well as several material tests on the silicone rubber and the FRP rod. Moreover, a steep-front impulse voltage test (30kV/ cm) was modified to meet the requirements of UHV AC and UHV DC in China. 

Different Requirements for Station Insulators

Substations are a major new application area for composite insulators although for the past 20 years their volume and proportion of application was far less than for line insulators. That situation is now changing. While one of the reasons silicone composite insulators are now being used at substations is because of their success on overhead lines, line insulators and station insulators operate under different conditions. The location of line insulators is dispersed along the full length of a line, making monitoring them a challenge. Moreover, because the unit value of a line insulator is relatively low, monitoring all of them for ageing is not regarded as necessary. Similarly, repairing any localized damage found is usually not cost-effective since the connection between insulator and tower is relatively simple and line insulators can be replaced individually or in batches. This makes it possible to rely on sampling some insulators within the population of a line or even some portions of insulators for monitoring and research purposes during service. By contrast, the comparative concentration of station insulators offers an advantage in carrying out all kinds of monitoring. Moreover, because the individual value of a station insulator is high, it is worthwhile developing monitoring techniques and any localized damage found is worth repairing. At the same time, sampling for research during service is almost impossible. A substation insulator is often applied to high voltage equipment so it is typically not convenient to replace. For example, because of different features, station insulators can be divided in two types: Type I – easy to replace; and Type II – difficult to replace. The main example of a Type I insulator is the busbar station post. Type II insulators include GIS bushings, wall bushings, power transformer bushings, hollow insulators for CTs and PTs, and hollow housings for ZnO surge arresters. 

Lifetime Requirement for Station Insulators

For Type II station insulators that are difficult to replace during service, close attention must be paid to service life and long-term performance. For example, serious ageing has already been observed on a wall bushing that has operated for only 15 years (see Fig. 10). A large area with cracks and chalking phenomenon appears on shed surfaces of the portion outdoors. These surface cracks were found mainly in the upper part of the housing (i.e. exposed to sun). Chalking of the silicone rubber appears on the high voltage side. Because of this chalking, the mechanical strength of the surface has decreased significantly. Moreover, in most areas, such as the HV and middle portions, the hydrophobicity classification decreased to HC7 and water on the surface reveals a hydrophilic state. The price of the shed material is much less than that of the wall bushing itself and replacement cost is also much higher than the shed material cost. Because sampling is not possible during service, the ageing process and its various contributing mechanisms are more difficult to determine. This example highlights that, compared with overhead lines, monitoring the ageing performance of composite insulators at substations is even more important. 

Test Methods for Station Insulators

A substation insulator operates under different conditions from one used on an overhead line. Moreover, different station equipment operates under own particular conditions in regard to electric field distribution, bending and torsional rigidity and temperature. It is therefore better to apply different tests to inspect these different insulators and also to set different acceptance criteria for each. 

New Material & Maintenance Techniques

Materials with Super-Hydrophobicity

New super-hydrophobic materials are especially attractive for outdoor insulation and researchers have come up with various methods to create these. For example, Tsinghua University used a laser-ablated template and fluoroalkyl-silane-modified composite coatings to prepare a specific microstructure and nanostructure on a silicone rubber surface (see Fig. 11). 

Fig. 12 shows the results of static contact angle and sliding angle measurements on HTV silicone rubber surfaces with different micro, nano, and micro-nano hierarchically textured surfaces. The static contact angle of water drops on the unaltered HTV silicone rubber sample was 115 ± 0.7° (i.e. classified as hydrophobic). In the case of micro structured HTV silicone rubber surfaces, this increased to 151.1 ± 1.7°, while with sliding angle to 4.1°. Nano-structured HTV silicone rubber surfaces offered a static contact angle of 148.2° and a sliding angle of 4.9°. The micro-nano structured HTV silicone rubber samples yielded the highest static contact angle,153.3°, and a very low sliding angle of 2.7°. A super-hydrophobic silicone rubber shows an excellent water repellency property when water droplets impact it under electric field. The surface can also be used to solve the problem of uneven field distribution due to surface water film and electric field enhancement due to water droplets. Large area such samples have successfully been prepared and it has been found that this type of surface also offers anti-icing as well as self-cleaning properties. Clearly, high volume production of long-lasting, super-hydrophobic surfaces will be an important future development in the field of outdoor insulation. 

Other New Materials

There are also other developments to watch, such as nano-fillers and modification of fillers. These may provide better solutions to improve the shed/sheath of composite insulators or the FRP rod by improving or replacing the fiber or matrix materials. Another promising development is improvement of the critical interface between sheath and rod using new coupling agents or new treatment methods. Other possibilities include self-diagnosing and even self-healing materials. 

Maintenance Based on Non-Contact Monitoring

On-line monitoring represents a huge challenge for a power grid. Development of industrial robots will be a promising way to conduct non-contact monitoring of insulators, such as looking for any localized heating that could be caused by surface leakage current, internal defects or degradation of the housing-rod interface. Currently, a localized temperature rise is considered related mainly to degradation of an interface and a sign of the early stage of decay-like fracture. Non-contact monitoring methods such as IR inspection from helicopters or unmanned aerial vehicles allow such localized heating to be detected so that affected insulators can be replaced in a timely manner, based on level of temperature rise. 

Maintenance Based on Big Data

Information technology will certainly change development of power grids. In the case of composite insulators, two possible properties might meet some of the needs of the future smart grid. The first is large-scale, real-time on-line condition monitoring, both at substations and on overhead lines. A new function could be added to composite insulators, namely obtaining and transmitting data. Another is failure prediction based on big data. Every insulator will need to have its own QR code where all information such as manufacturing and material details, time in operation, maintenance information, etc. will be obtained. With such data, quality maintenance will become digital and failure prediction could be based on big data. 

Conclusions

Use of composite insulator has increased rapidly over the past 30 years. Looking to the future, there are still key issues for continued development of this technology. Currently, test methods and technical standards are not satisfactory and it will be important to make modifications, not only to improve composite insulator quality but also to increase utility confidence when choosing such insulators. Specific test methods and requirements will need to be developed for different types of composite substation insulators. Also, new materials and improved maintenance techniques will both contribute to further development of composite insulators. 

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Service experience is key when it comes to evaluating the level of maturity and reliability of any electro-technical component. While there is typically a great deal of attention devoted to collecting such field experience during the initial years after introduction of a new technology, this is more challenging once products enter the mass production stage. As a result, actual service experience risks being replaced more by rumors and perceptions, sometimes inaccurate.

Given the above, a group of 8 European power companies carried out a research project intended to objectively benchmark the performance of composite insulators. This project included collecting service experience as well as comprehensive testing of insulators, both from storage depots and removed from service. The companies supporting this project included 50Hertz (Germany), Amprion (Germany), APG (Austria), E.ON (Germany), Fingrid (Finland), RTE (France), Statnett (Norway), and Svenska kraftnät (Sweden).

Collection of service experience within this project’s framework formed the basis for this edited contribution to INMR by Dr. Igor Gutman of the Independent Insulation Group (I2G), who coordinated the research. Primary interest was on overhead line insulators but these and substation insulators were analyzed separately because the two arrived in service at different periods. As such, their volumes and experience might be different.

Information on service experience with composite insulators has been comparatively scarce. Five CIGRE-inspired reviews are known to have taken place (the last still not officially published), but the information collected was limited. The main outputs included:

• Number of insulators installed;
• Maximum service period;
• Reliability;
• Typical reason for installation;
• Typical failure modes.

This first CIGRE survey in summarized service experience of composite line insulators at voltages higher than 100 kV, including suspension, tension and line post insulators. The total number installed was estimated as 140,000, and the volume of service experience (number of insulators times number of years) was 831,000. Thus, average service period was 6 years. Vandalism and handling were the main reasons for their application followed by pollution performance.

The insulator component that failed most often was the housing, explained by degradation of the material as was typical for first generation composite insulators. This was followed by failure at the core/housing interface. Reliability of composite insulators was estimated at 11×10-4 per year – an estimation acknowledged to be unrealistically low due to the definition of failure used in the questionnaire. Utilities were asked to define failure as “any condition that led to the removal of insulators from a line”. For example, one utility installed a batch of 350 insulators of the same type and after a few years in service three insulators broke while others showed signs of degradation. Although the remaining insulators still appeared sound, the utility nonetheless decided to remove all 350 and thus reported 350 failures even though only 3 had failed in reality. Considering this, actual reliability was likely 10 to 100 times higher, i.e., 10-4 to 10-5 per year.

The second CIGRE survey was conducted and published in . Again, the survey looked at insulators for voltage levels higher than 100 kV, including suspension, tension, line post insulators and interphase spacers. Total number of insulators installed was estimated at 700,000 and volume of service experience was 4,679,000. Thus, average service period was 7 years.

Separate data from utilities in the United States were included in this survey and provided an average service period of from 14 to 15 years. Again, vandalism and ease of handling were the dominant reasons for their application, followed by use in upgrade/compaction projects, polluted service areas and price. The prevailing failed component now was the core, which might indicate brittle fracture, followed by the core/housing interface. This survey used a different definition of failure, i.e. “an insulator that could not sustain the system voltage or mechanical load”. This is the definition used now. Average reliability of composite insulators was estimated at 10-4 per year.

The third CIGRE-driven estimation of service experience for line insulators was presented in in a chapter included in a Technical Brochure (TB). This data was based mainly on a CIGRE survey together with more recent data provided by EPRI. The prevailing failure modes identified were brittle fracture and flashunder. This TB estimated reliability in the range 10-4 to 10-5 per year and considered mechanical failures to be the dominant failure mode. It should be noted that whereas data for conventional ceramic insulators refer to a consolidated technology representing about 100 years of experience, data for composite insulators included failures associated mainly with the first and second generations of this technology. As such, expected failure rates of presently available composite insulators should be much lower.

The fourth CIGRE review of service experience of line insulators involved WG B2.57 and was finished in . The first draft of the TB did not offer any new information on service experience.

This first and the last items mentioned above in the CIGRE-driven survey on composite hollow core apparatus insulators in were included in the TB. Application of polymeric housings started on an industrial scale only in the early s. Since then, the total quantity reached about half a million in the range 145 kV and above, based on data from . Estimated market volume at the time was more than 50,000 insulators/year. If directly-moulded apparatus housings (e.g. surge arresters, cable terminations and bushings) at voltage levels above 60 kV are also considered, there would probably be one million units in service. Experience collected by this WG was limited but positive, with only minor degradation reported in a few cases.

Questionnaire & Response

Analysis of existing data on service experience led to the conclusion that such information was relatively scarce. A specialized questionnaire was therefore created and distributed to reflect the specific interests of the utilities participating in this project.

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Fig. 1 shows an example of the questionnaire. A slightly more detailed questionnaire was also created and distributed to those utilities willing to contribute more data. These questionnaires were created in collaboration with all participants and the key issues to consider included:

• Compressed questionnaires (maximum 10-15 questions). Otherwise, they would never be answered.
• To be sent only to utilities where the project participants had contacts. Otherwise, probability to get a response would be low.

The questionnaires were distributed to 99 different companies and 53 answers were obtained providing a response rate of 54%. Only one of these 53 companies did not use composite insulators.

Unfortunately, not all large users of composite insulators on a country by country basis responded. Transmission voltage level in this study was defined as ≥110 kV.

Overhead Line Insulators

Total reported overhead line insulators installed at transmission voltages was estimated as 1.9 million while the total number of insulators installed at distribution voltages was estimated at 6.7 million. Thus, a combined total of 8.6 million units. This rather large number represented about 25% of the worldwide population, estimated to be between 30 and 40 million units based on discussions with international experts. Also, the upper limit for total number of composite insulators installed worldwide was verified during interviews with manufacturers.

Application of composite insulators is clearly commonplace with 98% of responding utilities using them. Insulators are used in standard as well as special designs of OHL (i.e., I- and V-strings; interphase spacers, insulated cross-arms, jumper supports and line posts).

Substation Insulators

Experience with some 260,000 composite substation insulators was reported. The total population of such insulators installed worldwide is thought to be between 2 and 3 million. Selection of composite insulators in this application is also common, with 92% of responding utilities using them. These insulators are used in a range of different apparatus, e.g. arresters, instrument transformers, circuit breakers, bushings) and also as station posts.

Maximum Duration in Service

Overhead Line Insulators

Maximum time in service was found to be similar for transmission and distribution voltage classes. Fig. 2 presents the data for both. Average maximum time was 24 years while maximum time was 40 years (i.e. still in service). There was also anecdotal data that several composite line insulators still operating in the Netherlands and Germany have been installed for more than 40 years.

Substation Insulators

Average time in service for substation insulators was 22 years and maximum time was 45 years. Fig. 3 summarizes these results.

Service Experience

Power companies were asked how they evaluate the overall experience with composite insulators. Three levels of answers, created by respondent companies, i.e., positive, mixed or negative were obtained for overhead line insulators and were marked as “+1”, “0” and “-1” respectively. This information is summarized in Fig. 4.

In the case of substation insulators, only two levels of answers were obtained, i.e., positive and neutral, comparable with “mixed” for line insulators. “Neutral” was considered as “smoother”, because it was built mostly on expectations for additional service. These levels were marked as “+1” and “0” respectively (see Fig. 5).

Overhead Line Insulators

Fig. 4 summarizes combined assessed service experience by transmission and distribution companies. For the majority, experience was positive (86%) compared to 4% negative and 10% mixed.

It is interesting to note that those companies who responded as “mixed” or “negative” did not use any pre-qualification procedures in their selection of insulators. Such procedures can be significantly different, from choosing among only a few qualified supplies to analyzing test reports and comparing these to the technical specifications created by the power companies. For example, 72% of utilities that considered that they have had positive experience with composite line insulators regularly used pre-qualification procedures or tenders with follow-up analysis of test reports versus only 28% that did not. It therefore seems worthwhile to apply such pre-qualification procedures.

Substation Insulators

Experience is shown in Fig. 5. For the majority, experience has been positive (94%), with the rest (6%) defined as neutral. By contrast to experience with line insulators, only 25% of those utilities that considered their experience with composite substation insulators as positive were applying pre-qualification procedures.

Reasons for Application

Overhead Line Insulators

The reasons why utilities chose to install composite insulators were left open for them to define and are summarized in Fig. 6. This part of the analysis combined transmission and distribution voltage levels. For each responding utility, one point was given for every specific reason mentioned. Ease of handling was the dominant reason, whereas the traditional reason, i.e. improving pollution performance, came next, followed by price.

Substation Insulators

Fig. 7 summarizes why utilities choose to install composite insulators at substations. The reasons are again created by the power companies questioned and there are fewer than was the case for overhead line insulators. Not surprisingly, safety against explosive failure was by far dominant reason, while easier handling was the second.

Causes of Failure

Overhead Line Insulators

Fig. 8 summarizes causes of failure or failure modes of composite line insulators. Again, analysis of the replies included both transmission and distribution voltage levels. Five types of failure dominated: flashunder, flashover, surface degradation, brittle fracture and damage caused by bird pecking.

In regard to surface degradation (which combines erosion, cracking, etc.), it might be that a utility observing this type of degradation would decide to replace insulators even though the damage was not critical. Thus, it was proposed not to consider this failure mode in the analysis. It was interesting to note that flashover was mentioned among the most common type of failure, especially given that some “experts” have claimed that it is rare if not impossible for composite insulators to flashover in the classical pollution dry-band mode known for ceramic insulators.

It is therefore likely that some utility or service provider staff may not have been able to recognize the difference between ‘flashover’ (i.e. an external breakdown along the surface) and ‘flashunder’ (i.e. an internal breakdown typically in the interface between core and housing). If this is indeed true, the flashunder failure mode was dominant and part of the ‘flashovers’ needed to be added to the cases of ‘flashunder’. In spite of this, number of failures reported would still be low because, as mentioned above, 86% of responding utilities considered their service experience as positive. However, fewer than 20% of utilities were able to present their exact number of failures.

One difficult question was which generation of composite insulators were actually represented in the failures being reported. The questionnaire summarized all data collected, thus conservatively combining experience for all generations of these insulators, presently assumed to be four to five. Actual situations in service are illustrated by examples of comments received from utilities that had used composite insulators for many years:

1. “On one OHL the degradation of specific HTV silicone rubber led to a change of the mechanical properties (brittleness when mechanically stressed) due to a chemical reaction with acids and UV”;
2. “For the current generation issues are very rare and are basically flashovers due to bird-streaming”;
3. “Since we only have the third generation of composite insulators in our network, we have not experienced any failures”;
4. “Flashovers were experienced only for one supplier”;
5. “We observed issues with 20 – 25 years first generation EDPM insulators in the late 80s and early 90s with loss of hydrophobicity and tracking/erosion. But more recent supply of silicone insulators seems to be OK”;
6. “Expected asset life of composite insulators is 40 years; in the heavy contaminated environment near the coast, we replaced a particular brand of composite insulators after 13 years in service after two brittle fracture failures”.

Substation Insulators

Fig. 9 summarizes causes of failure of composite substation insulators. Mechanical issues were the dominant failure mode and it was assumed that these related mostly to station post insulators. Normally, only limited surface degradation was observed on apparatus insulators and it was often a subjective decision by the utility whether or not to replace such insulators.

Reliability

Attempting to calculate reliability in terms of number of failed units per year was complicated. This was because service experience, in terms of aggregate number of insulators installed multiplied by number of years in service should be known, as are the exact number of failures. Thus, in cases where no failures were reported, failure rate was nonetheless assumed to be one failure over the whole service period. Otherwise, aggregate volume of installed insulators was estimated by multiplying 50% of the maximum time in service by number of installed units, since only maximum service time was available.

Overhead Line Insulators

Table 1 presents such an estimation based on limited data from 15 utilities that were used to assess reliability. For visualization purposes, the answers from these utilities were arranged according to a traffic light principle, as GREEN (positive), YELLOW (mixed) and RED (negative). Based on this, the following conclusions were drawn:

• ‘Positive’ experience with composite insulators typically relates to an annual failure rate of 10-5 or less;
• ‘Mixed’ experience typically relates to an annual failure rate of 10-4;
• ‘Negative’ experience typically relates to an annual failure rate of 10-3;
• Average annual failure rate for all data collected in Table 1 was 10-5.

Substation Insulators

Data on failure rates of composite substation insulators is limited because of their relatively short service time compared with line insulators and also because most have operated without failures. Table 2 presents some information for 5 utilities that reported exact number of failures. Aggregate service time of installed insulators was (as for line insulators) taken as half the maximum time in service. Based on this, ‘positive’ experience expressed by a utility typically corresponded to a failure rate of between 10-4 and 10-5. It can be assumed that, with increasing service experience, failure rate will become lower, as demonstrated by the experience of utility D. Given a greater share of new generation composite insulators entering service, reliability would be higher, approaching 10-5 per year.

Use of Grading/Corona Rings

Fig. 9 analyzes the response from utilities that answered the question about application of grading rings. No grading devices were being used for distribution classes (i.e. below 110 kV). For transmission class insulators, general practice has been to use one grading ring (or sometimes only arcing horns) at the HV fitting starting from 110-132 kV and two grading rings (one at each end) starting from 220-275 kV.

Summary

Overhead Line Insulators

This project collected service experience linked to the operation of about 9 million composite insulators installed at transmission and distribution voltage levels. Information was collected using a questionnaire that received responses from about 50 utilities. Average time in service was 24 years (with a maximum of 40 years). Thus, the technology is considered as mature. These insulators were estimated to represent about 25% of the total population worldwide.

Replies received to the main questions formulated by participants in this project, can be summarized as follows:

• Application of composite insulators has become commonplace (confirmed by 98% of answers);
• Insulators are used on standard OHL and in special designs (I- and V-strings; interphase spacers, insulated cross-arms, jumper supports and line posts);
• The dominant reason for application is ease of handling (35%);
• Present service experience is considered as positive, as confirmed by 86% of replies. A large part of those utilities with positive service experience used pre-qualification procedures while utilities with negative or mixed experience typically did not use such procedures. Thus, it seems worthwhile to apply pre-qualification procedures;
• Types of insulator failure experienced were defined by the utilities on their own and not standardized. Therefore, it would be more correct to define them as “observations”. Five dominant types of failure were mentioned: surface degradation, flashunder, flashover, brittle fracture and bird damage from pecking. First commenting surface degradation (combining erosion, cracking, etc.), it might be that a utility observing this type of degradation decided to replace insulators, although this damage was not critical. Thus, it was proposed not to consider this failure type in further evaluation. Flashover is an interesting response because many CIGRE/IEC experts do not believe that classic pollution-driven flashover can take place on composite insulators. Even if it is believed that some ‘flashovers’ were actually ‘flashunders’, some classical surface flashovers should also have occurred. Assuming that a part of ‘flashovers’ really belonged to ‘flashunders’, this would become the single most dominant reason for failure. Subsequently, the ranking might be:

1. flashunder,
2. brittle fracture,
3. flashover, and
4. bird damage (this type of damage may be overrepresented because of the 6 Australian and New Zealand utilities responding to the questionnaire).

•  When considering flashunders as the dominant reason for failure of these insulators, the root cause is poor adhesion in the core/housing interface, allowing for moisture penetration. The moisture penetrates through the rubber housing by diffusion and typically condenses in the core/housing interface or, more rarely, penetrates through improper sealing. Thus, core/housing adhesion and the quality of sealing become two important issues to investigate. It is important to stress that both adhesion and sealing tests are non-standardized tests, i.e. not yet included in IEC standards. Evaluation of quality of adhesion is already recognized and under consideration in the ongoing revisions to IEC and IEC . Development of methods to evaluate the quality of sealing is also underway in a separate project. Too high electric field can accelerate degradation due to poor adhesion of the core and housing and must therefore be controlled. Limits for electric field are also well established and under consideration in revision of IEC .
• For transmission class insulators, general practice is to use one grading ring, or sometimes only an arcing horn at the HV fitting, starting at 110-132 kV. Two grading rings at both ends are applied, starting at 220-275 kV.
• Total service experience and total number of failures summarized in this document provide an average annual failure rate of 10-5, which is in line with the ‘positive’ service experience subjectively expressed by most power utilities.

Substation (Apparatus & Station Post) Insulators

Service experience with 260,000 composite substation insulators was reported by 27 utilities. Total average time in service was 22 years, with a maximum of 45 years. Thus, this technology is also mature. The total number of insulators installed worldwide is estimated at between 2 and 3 million. A summary of important findings is as follows:

• Application of substation composite insulators is commonplace (92% of answers received). These insulators are used both for apparatus and as station posts;
• The dominant reason for use of composite apparatus insulators is safety against risk of explosion (40% of replies);
• Present service experience is considered as positive, as confirmed by 94% of respondents;
• By contrast to experience with composite line insulators, only 25% of these utilities used pre-qualification procedures;
• Types of failure experienced were defined by the utilities themselves and not standardized. Mechanical issues were the dominant failure type (37% of replies). It is assumed that these relate mainly to issues with station post insulators;
• Based on the limited amount of data, it is assumed that positive service experience typically corresponds to an annual failure rate of between 10-4 and 10-5.