Service Experience with Composite Line Insulators: EPRI Perspective
Service Experience with Composite Line Insulators: EPRI Perspective 2013 INMR World Congress September 8-11, 2013, Canada. Andrew, J. Phillips, Director, Transmission, EPRI, USA; Christiaan S. Engelbrecht, Consultant, EPRI, The Netherlands
Introduction Since 2006, some utilities have experienced an increasing number of polymer insulator failures on 115 kV and 138 kV transmission lines. Investigations have shown that these failures can be attributed to high electric fields (E-‐fields) occurring close to, or on the high-‐voltage end fittings of these insulators. These findings suggest, contrary to common practice, that it might be necessary to consider the application of corona (also called grading) rings on polymer insulators on transmission lines with a system voltage below 161 kV. Transmission line reliability can be affected if utilities do not have measures in place to minimize the effect of corona discharges on the rubber material. EPRI utilized their experience and research results to help the affected utilities develop a strategy to address premature aging of polymer insulators on 115 kV and 138 kV transmission lines due to high E-‐fields. This included providing reference information, technical support and recommendations to assess existing insulator populations and to specify polymer insulators for new or replacement units. In this paper an overview is given of these insulator failures and the strategy that was followed to manage the situation.
Technical Background EPRI is credited for being one of the first in identifying high E-‐fields and the resulting discharge activity as an important cause of premature aging of polymer insulators. Based on the results from the multi-‐stress aging chambers and testing at the EPRI lab in Lenox, Massachusetts, this phenomenon was identified as a primary aging mechanism on 230 kV and 500 kV insulators, and appropriate E-‐field limits for polymer were established. The insulator failures at 115 kV and 138 kV suggest that the same phenomena are present on these lower system voltages. Aging of the insulator sections subjected to high localized electric fields is usually the result the stresses associated with one or more of the following types of discharge activity: • • •
Continual corona activity from metallic end-‐fittings or grading rings under dry conditions Discharges due to non-‐uniform wetting of the polymer rubber material Internal discharges: e.g. along the interface between the core and rubber housing material, or within the core itself.
Continual corona activity from the metal end fittings may be energetic enough to directly cause rubber erosion and a loss of galvanization of the metal end fitting. On hydrophobic insulators individual drops or water patches of relatively limited extent may enhance the local E-‐field due to the high permittivity of water (εr = 80) with a factor of up to 12 times. In the high E-‐field regions if the insulator this enhancement may be sufficient to result in corona activity from the edge of the water. Research indicates that it is unlikely that water drop corona alone will result in significant degradation of the polymer housing, as the temperature increases due to this type of corona is minimal. There is however significant evidence to suggest that the chemical by-‐ products of the corona, together with moisture, may result in significant material degradation. In this respect the formation of Nitric acid is considered important. It was found that the pH on the surface of the insulator drops from an initial value of about 7 to 3.4 after 15 minutes of corona activity on a wet insulator surface Error! Reference source not found.. Furthermore it was found that some silicone rubber formulations may be particularly vulnerable to deterioration when exposed to nitric acid. The available evidence suggest that water drop corona may just be the initial phase of the following, more severe, degradation mechanism that affects the long-‐term performance of the insulator. Present understanding of this process is as follows: 1.
2. 3. 4.
5.
6. 7.
Water drop corona in the high E-‐field regions results in localized loss of hydrophobicity. Regions affected have E-‐field magnitudes above the water drop corona onset threshold – see Figure 1. Under wetting conditions, patches of water form in the regions of lower hydrophobicity. These surface water patches are separated from each other by dry regions or bands. Localized arcs form, bridging the gaps between the water patches Error! Reference source not found.. The energy and temperature of these localized arcs are significantly higher than that of water drop corona, stressing the rubber surface further Error! Reference source not found.. Over time, as the affected regions lose hydrophobicity, and completely wet out, the E-‐ field in the adjacent regions is enhanced above the water drop corona onset threshold under wetting conditions. The aging mechanism is then initiated in the previously unaffected regions. In this manner, the region affected is increased. The by-‐products formed by corona in combination with water, notably nitric acid, may be aggressive to the housing resulting in cracks in the material, or corrosion of the end fittings.
Wetting corona activity
Loss of hydrophobicity
Figure 1: Water induced corona activity and the resulting loss of hydrophobicity on a hydrophobic composite insulator.
During wetting conditions, the rubber surface of hydrophilic composite insulators (such as EPDM) is more likely to be covered with patches of water, rather than distinct droplets. Dry regions separate these patches, and due to E-‐field enhancement, sparking may occur between patches. These discharges are more energetic than corona and may degrade the rubber material. Although this activity may also occur away from the high E-‐field region, casual observation in aging tests indicates that it is more prevalent in the high E-‐field regions.
Ultraviolet image
Infrared image
Figure 3: Infrared and ultraviolet images of non-uniform wetting discharge activity on a hydrophilic composite insulator.
Sufficiently high E-‐field magnitudes may result in discharge activity in internal defects – such as voids inclusions and poor bonding between sheath and core. This, in turn, may eventually lead to the failure of the insulator either by destruction of rod by discharge activity or by flash-‐under – see Figure 4 for examples.
Destruction of rod by discharge activity
Flashunder
Figure 4: Examples of insulators that failed due to destruction of rod by discharge activity and flash-under.
Research has shown that not all insulators are equally affected by high electric fields. Important factors that influence the rate and level of degradation are: • • •
The type of rubber and the makeup of the weather shed system The makeup of the end fitting seal The level, location and type of discharge activity, which is determined to a large extent by the E-‐field field along the insulator, the type and intensity of wetting, the presence of contaminants and the level of hydrophobicity of the material.
Service Experience The occurrence of five insulator failures between June 2006 and August 2007 on 115 kV and 138 kV lines prompted three utilities in the United States initiate a study to better understand the aging mechanisms on insulators of this voltage class. As is evident from EPRI’s failure database, see Figure 5, these failures were not isolated incidences, but rather part of an increasing trend of failures reported to EPRI on 115 kV to 138 kV insulators. The data in Figure 5 show that since 1998 on average 7 failures per year were reported to EPRI.
Figure 5: Numbers of 115 kV to 138 kV polymer insulator failures recorded by EPRI.
A breakdown of the failure modes of the 140 failures recorded in the EPRI database for of 115 kV to 138 kV insulators is presented in Figure 6. From this figure it can be seen that the dominant failure modes were stress corrosion cracking (brittle fracture) and flash-‐under. Examples of a stress corrosion failure are shown in Figure 7. A large proportion of these failures were on the same insulator design and on units manufactured between 1993 and 1999.
Figure 6: A breakdown of the failure mode of 115 kV to 138 kV polymer insulator failures in the EPRI failures database.
Figure 7: Example images of the fracture surfaces and one of the failed insulators in-situ.
During the failure investigations it was shown that all these failures could directly be attributed to continual discharge activity from the end fitting under dry conditions. This continual exposure to corona resulted in cracks in the rubber sheath and degradation of the end fitting seal. Once the seal is compromised, moisture can come into contact with the rod, leading to a brittle fracture of the fiberglass rod. Brittle Fracture is a mechanical failure of the fiberglass rod due to acid attack where the fracture exhibit one, or more, smooth, clean planar surfaces, mainly perpendicular to the axis of the fiberglass rod, giving the appearance of the rod being cut – as is shown in Figure 7. As consequence of these failures, utilities were forced to reexamine the use of corona rings (or lack thereof) on 115/138 kV polymer insulators. Utilities, in cooperation with EPRI, have therefore initiated a number of specific activities during in 2007 and 2008 to assess the risk of 115 / 138 kV polymer insulators to premature ageing due to high electric fields. These included: • • •
Daylight Discharge Inspections, Detailed examinations of insulators taken from service, failure investigations and E-‐field Calculations.
It should be noted that these activities focused on the particular insulator design that suffered the failures.
Daylight Discharge Inspections EPRI and 5 utility members together performed daytime discharge inspections on twelve 115 and 138kV transmission lines to determine whether continuous discharge activity is occurring from the end fittings under dry conditions. These inspections were primarily directed towards one particular insulator design, but there were also opportunities to inspect a limited number of other insulator designs. Some examples of corona observations are presented in Figure 8.
Insulator Type A
Insulator Type B
Insulator Type C
Insulator Type D
No Corona Observed
Figure 8: Examples of discharge activity observed from two different designs of insulator.
Conclusions from these inspections are: •
•
• •
Corona discharge activity under dry conditions was observed on the end fittings of the composite insulators installed on all twelve 115 kV and 138 kV transmission lines inspected. Not all insulators on the lines had corona activity though. Corona discharges are more likely to occur on dead-‐end strings and least likely on brace post configuration. This is not completely unexpected as it is known from previous calculations that the E-‐field is generally higher for dead-‐end insulators than it is for suspension units or brace post configurations. To date, corona activity has been observed on three out of the four insulator designs (i.e. different manufacturers) inspected, as shown in Figure 8. In one case daylight corona observations were made before and after the installation of a corona ring. This confirmed that the addition of a ring eliminated corona from the insulator end fitting.
Detailed Inspections EPRI has worked with 5 utilities in evaluating the degradation on over 200 115 kV and 138 kV insulators removed from service. All of these insulators were installed without corona rings and were of the same design. The units were installed between 1994 and 2006. 74 of the insulators removed from service were subjected to a detailed examination comprising a (1) visual inspection, (2) Hydrophobicity measurement, (2) dye penetration test, (3) dissection and in some cases (4) mechanical testing. The remaining units were evaluated only by performing a visual inspection.
Some examples of the degradation observed are presented in Figure 9. In all cases it was found that the most severe degradation was observed in the same areas where dry corona activity was seen during the daylight discharge inspections. On some units it was found that the degradation of the sheath and end fitting seal progressed so far that the rod was exposed to the environment. These latter units are considered as high risk units where failure is considered inevitable.
Loss of hydrophobicity
Degradation of the end fitting seal
Cracking of shed
Cracking of the sheath
Figure 9: Examples of discharge activity observed from two different designs of insulator.
E-field Calculations EPRI performed extensive 3-‐D E-‐field calculations for four utilities at both 115 and 138 kV to obtain a better understanding of the E-‐field distribution that can be expected on 115 and 138 kV insulators, the parameters that influence it and to evaluate some remedial measures. Importantly the E-‐field calculations accounted for the presence of all three phases, and in some cases adjacent circuits, on the transmission structure. The calculations focused on those structures where failures occurred previously or where corona has been observed. These calculations considered both the E-‐field on the end-‐fittings – to indicate the likelihood of dry corona – that along the insulator sheath – to indicate the likelihood for water induced corona. The following conclusions were drawn from the E-‐field calculation results: • • •
Dead-‐end insulators have higher E-‐field magnitudes than suspension insulators Single dead-‐end insulators have higher E-‐field magnitudes than double dead end insulators. The addition of a hot line link results in a slightly higher E-‐field magnitude on the insulator.
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• • •
•
Insulator A
There is a significant difference in the E-‐field levels between different insulator designs – see Figure 10. Small and slender end fittings tend to have higher E-‐fields in the region of the end fitting seal. The shape of the end fitting dictates where the highest field occur and accordingly whether or not the dry corona, if present, will be in contact with the housing material. E-‐field magnitudes exceed the EPRI recommended limits on all designs of 115 kV and 138 kV polymer insulators when installed without corona rings. The addition of 8” corona rings at the live end of the insulator is in most cases sufficient to reduce the E-‐field magnitudes to an acceptable level. The E-‐field modeling results together with the DayCor inspection confirmed that the failures that occurred on 115 kV and 138 kV insulators, and the observed degradation, can be associated with a high E-‐field levels on the insulators. E-‐field limits need to be adjusted downward for insulators installed at high altitude i.e. above 3300 ft (1000 m).
Insulator B
Insulator C
Insulator D
Figure 10: Examples of the E-filed calculated on the insulator end fitting without corona rings. Blue corresponds to the lowest E-field magnitude and Red to the highest. The corona threshold corresponds approximately to orange
Population Assessment In the previous section service experience is presented that suggests very strongly the need for corona rings on 115 kV and 138 kV polymer insulators to protect them from premature ageing due to corona activity. Although this may seem simple, the implications of such a conclusion may be quite extensive, especially if large numbers of these insulators are installed. Utilities are then faced with the difficult task of identifying high-‐risk units, and to decide what the most appropriate, and cost effective remedial actions is to undertake. Fortunately, the deterioration due to corona discharge activity develops slowly, which gives Utilities some time to do a proper condition assessment. EPRI has helped Utilities to develop a population assessment strategy to address premature aging of polymer insulators on 115 kV and 138 kV transmission lines due to high E-‐fields. A key in the development of this strategy is the set of tools developed and maintained by them that includes field guides, failure databases, E-‐field modeling techniques, corona inspection technologies, and relevant accelerated aging test results. An overview of the process is given in Figure 12.
Figure 12: An overview of a strategy to perform a population assessment on polymer insulators.
In addition EPRI has an ongoing a follow-‐up research effort that includes the development of small scale accelerated aging tests specifically to address these concerns.
Conclusions Since 2006 there have been an increasing number of polymer insulator failures recorded on 115 kV and 138 kV transmission lines. These failures were seen in a serious light as they occurred mostly on the more critical dead-‐end insulators that pose a threat to system integrity due to the risk of a downed conductor. Investigation results suggests that these failures are due to high electric fields (E-‐ fields) occurring close to, or on, the high voltage end fittings of these insulators. Consequently corona or grading rings may also be necessary for polymer insulators installed at 115 kV and 138 kV. Higher levels of dry corona activity from the end fittings occurred in-‐service than was expected based on laboratory testing. E-‐field modeling showed two reasons: 1. At 115 kV and 138 kV the close proximity of the nearby phases increases the surface E-‐field magnitudes by a significant amount. 2. Most laboratory testing is done on suspension configurations while the E-‐field magnitudes on dead-‐end and hard angle insulators is higher. Prompted by these developments EPRI initiated a supplemental project to provide participating utilities with the information necessary to develop a strategy to address premature aging of polymer insulators due to high E-‐fields.