Six Utilities Share Their Perspectives on Insulators

April 1, 2010
Trends in the changing landscape of high-voltage insulators are revealed through utility interviews.

The high-voltage transmission system in North America is the result of planning and execution initiated soon after World War II. Ambitious goals, sound engineering and the vertically integrated structure of utilities at that time all contributed to high reliability and good quality of electric power. The high-voltage transmission infrastructure development peaked in the 1970s. From then on until the turn of the century, load growth was not as high as anticipated, resulting in a drastic reduction in transmission activity. Consequently, the system was pushed to its limits, which led to a few large-scale blackouts. The consensus is that the existing system is bursting at its seams, continuing to age and needs refurbishment; at the same time, new lines are needed to handle load growth and transfer massive amounts of power from remote regions to load centers.

Today, several thousand kilometers of transmission lines at voltages from 345 kV ac to 765 kV ac and high-voltage dc lines are either in the planning or construction stages. A catalyst for this renewed interest in transmission line construction is renewable energy. It is clear that in order to reap the benefits of green and clean energy (mostly solar and wind), there is an urgent need to build more lines to transfer power from locations rich in these resources to load centers quite distant from them.

For this upcoming surge of new high-voltage projects and refurbishment of older lines, insulators play a critical and often grossly underestimated role in power delivery. Over many decades, the utility perspective regarding insulation technologies has changed in several ways.

Insulator Types

When the original transmission system was built, the porcelain insulator industry was strong in North America and utilities preferred to use domestic products. Toughened glass insulators were introduced in Europe in the 1950s and gained worldwide acceptance. In the United States, many users adopted the new technology in the 1960s and 1970s, while others were reluctant to use them because of perceived concerns with vandalism. However, the use of glass insulators in the United States continued to expand.

Polymer (also known as composite or nonceramic) insulators were introduced in the 1970s and have been widely used in North America since the 1980s. With the advent of polymers, it seemed the use of glass and porcelain suspension insulators started to decline. Polymers are particularly suited for compact line construction. Such compact lines minimized right-of-way requirements and facilitated the permitting of new transmission corridors in congested and urban areas.

With the growing number of high-voltage lines now reaching their life expectancy, many utilities are turning their attention to the fast-growing population of aging porcelain insulators. Deterioration of porcelain insulators typically stems from impurities or voids in the porcelain dielectric and expansion of the cement in the pin region, which leads to radial cracks in the shell. As internal cracks or punctures in porcelain cannot be visually detected and require tools, the labor-intensive process is expensive and requires special training of the work force.

Supply Chain

Today, there is no domestic supplier of porcelain suspension insulators in North America. However, there are quite a few suppliers of porcelain insulators in several other countries, but most of them have limited or no experience in North America. This naturally has raised concerns among many utilities in North America about the quality and consistency of such productions.

Polymer insulators have been widely used at all voltages but largely in the 230-kV and below range. There are still unresolved issues with degradation, life expectancy and live-line working — all of which are hindering large-scale acceptance at higher voltages. The Electric Power Research Institute (EPRI) recently suggested that composite insulators for voltages in the range of 115 kV to 161 kV may require corona ring, which would not only increase the cost of composites but could create possible confusion as the corona rings offered vary from one manufacturer to another. With respect to toughened glass, not much has been published or discussed in the United States.

Salt River Project, Arizona

Salt River Project (SRP) serves the central and eastern parts of Arizona. Except for small pockets in the eastern parts, which are subject to contamination from the mining industry, SRP's service territory is fairly clean and dry. Its bulk transmission and distribution networks are based largely on porcelain insulators. The utility began to use polymer insulators in the early 1980s and has successfully used them at all voltages. Polymers are favored for line post construction and account for the majority of 69-kV through 230-kV constructions in the last 30 years. The 500-kV ac Mead-Phoenix line, operational since 1990, was one of the first long transmission lines in the country to use silicone rubber composite insulators. The utility's service experience with these has been excellent.

The need for corona rings for composite insulators at 230 kV and higher voltage was recognized in the early 1980s by many users that experience fairly high wet periods in addition to contamination. This was not a concern for SRP; consequently, the first batch of composite insulators installed in the 1980s on several 230-kV lines had no corona ring. These insulators were inspected visually and with a corona camera about 10 years ago and most recently in 2009.

Some 230-kV lines are constructed with polymer insulators and no corona rings, and the insulators are in remarkably good condition. The relatively clean and dry environment in Arizona creates a corona-free setting most of the time, and this contributes greatly to SRP's problem-free experience with all types of insulators. In keeping with industry practice, all 230-kV suspension composite insulators subsequently installed by SRP have a corona ring at the line end, and those installed on 500-kV lines have rings at the line and tower ends.

SRP performs helicopter inspections of its transmission lines annually. Insulators with visual damage are replaced. Like many utilities, SRP trains and equips its linemen to perform line maintenance under energized (live or hot) conditions. Even though most maintenance is done with the lines de-energized, it is considered essential to preserve the ability to work on energized 500-kV lines. Future conditions may make outages unobtainable or unreasonably expensive.

Because there is no industry standard on live-line working with composite insulators and because of the difficulty in getting an outage on its 500-kV lines, which are co-owned by several utilities, SRP decided not to use polymer insulators at 500 kV. After reviewing the service experience of toughened glass insulators, SRP decided to consider them equal to porcelain in bid processes. This has resulted in the installation of toughened glass insulators on a portion of the utility's recent 500-kV line construction. The ease of detection of damaged glass bells was a factor, although not the most important one as its service experience with porcelain has been excellent.

Public Service Electric & Gas, New Jersey

Public Service Electric & Gas (PSE&G) has experienced problems with loss of dielectric strength and punctures on porcelain insulators from some suppliers. Lines with such insulators are being examined individually using a buzzer or electric field probe, but the results are not always reliable.

The utility has used composite insulators extensively on compact lines (line post configuration) up to 69 kV, and the experience has been good. It has experienced degradation (erosion, corona cutting) on some composite suspension insulators at 138 kV. These insulators were installed without a corona ring as is common practice. In one instance, PSE&G was fortunate to remove a composite insulator with part of the fiberglass core exposed before any mechanical failure (brittle fracture) could occur.

In the last five years, the utility has been using toughened glass insulators on new construction and as a replacement of degraded porcelain insulators on 138-kV and higher lines. Since many of these lines are shared with other utilities, PSE&G needs to have the ability to maintain them live; it calls itself a live-line utility. A major factor for using glass was the ease of spotting damaged bells. For example, the utility flies about 6 miles (10 km) per day and inspects roughly 30 towers; in contrast, a ground crew climbing and inspecting averages about three towers per day. In many cases, the entire circuit using glass insulators can be inspected in a single day with helicopters. PSE&G has estimated the maintenance of porcelain insulators can be up to 25 times more than that of glass insulators.

The utility is working to make its specifications for porcelain insulators more stringent than dictated by present ANSI standards, so that only good-quality insulators can be selected.

Pacific Gas and Electric Co., California

Pacific Gas and Electric Co. (PG&E) operates its extra-high-voltage lines at either 230 kV or 500 kV. The primary insulator type used is ceramic or glass. The exceptions are in vandalism-prone locations and areas with high insulator wash cycles, where composite insulators are used. Composite insulators are also used at lower voltages. However, fairly recently, corona cutting and cracks have been found on some 115-kV composite insulators installed without corona rings, which was the normal practice.

PG&E has reduced the use of composite insulators somewhat at all voltages in the last five years. In addition to aging-related issues, the utility has experienced damage by birds, specifically crows.

The utility has approved two offshore suppliers of porcelain insulators and expects several more vying for acceptance. While PG&E does not differentiate between porcelain and glass in the specification, design and installation, it is seeing an increase in the use of toughened glass insulators at all voltages in the 69-kV to 500-kV range. The utility attributes this to better education of the work force and performance characteristics associated with glass insulators.

The utility performs an aerial helicopter inspection annually, wherein insulators with visible damage are noted. A detailed ground inspection is done every five years. Climbing inspections are performed only if triggered by a specific condition.

Xcel Energy, Minnesota

Xcel Energy recently updated its standard designs by voltage. All technologies — porcelain, toughened glass and polymer — may be used for voltages below 69 kV. For 69 kV to 345 kV, polymers are used for suspension, braced and unbraced line post applications. For deadend application in this range and higher voltages, only toughened glass insulators are used. This change was driven by problems encountered with porcelain and early generation polymers.

For example, several porcelain suspension and deadend insulators on 115-kV and 345-kV lines in critical locations failed mechanically, attributable to cement growth. The age of these insulators was in excess of 20 years. As most of the porcelain insulators in the system are of this vintage or older, the utility has instituted a rigorous maintenance procedure where lines are examined regularly by fixed wing, helicopter and foot patrols. Those identified for detailed inspection are worked by linemen from buckets using the buzz technique. Needless to say, this is a very expensive undertaking and adds to the life-cycle cost of porcelain insulators.

Xcel has also experienced failures (brittle fracture) with early generation composites, primarily on 115-kV and 345-kV installations, and is concerned about longevity in 345-kV and higher applications. The utility evaluated life-cycle costs with the three insulator technologies before proceeding with revisions to its design philosophy.

Hydro One, Ontario

Hydro One has excellent experience with all three insulator technologies for lines up to 230 kV. For higher voltages, it uses porcelain and glass, and does not use polymer insulators because issues with live-line working, bird damage, corona and aging have not been fully resolved. Porcelain and glass insulators on Hydro One's system in many places are 60 years or older for some porcelain. The porcelain insulators are tested on a regular basis for punctures and cracks attributed to cement expansion, which have caused primarily mechanical failures of several strings across the high-voltage system.

The utility has success using thermovision equipment, and punctured bells show a temperature difference of up to 10C° (18F°) under damp conditions. In the last two years, Hydro One has examined more than 3000 porcelain strings at 230-kV and 500-kV lines. With a five-man crew, the utility can inspect five towers per day. Indeed, this is a time- and labor-intensive, not to mention expensive, undertaking.

Owing to the ease of visually detecting damaged units on toughened glass insulator strings, Hydro One will be using such insulators on its new construction of 230-kV and 500-kV lines.

NorthWestern Energy, Montana

NorthWestern Energy has been using toughened glass insulators on its 500-kV lines since the 1980s. It has had very good experience with them and will continue this practice on its new construction of a 430-mile (692-km) 500-kV line being built for the Mountain State Transmission Intertie project. The utility performs much of its maintenance under live conditions; it calls itself a live-line-friendly utility. Since most of NorthWestern's lines are in remote locations, routine inspections by helicopter occur four times a year on the 500-kV lines and once per year for all other lines. More detailed inspections are done on a five- to 10-year cycle. The utility has experienced problems due to vandalism in some pockets, but since the damaged glass insulators are easy to spot, it finds that glass is advantageous over other options.

NorthWestern has had good experience with porcelain at 230-kV and lower voltage lines. It inspects these insulators under de-energized conditions. Owing to the relatively dry climate in Montana, the utility has many thousands of porcelain insulators well in excess of 60 years old. Composite insulators are the preferred choice for lines of 115 kV and below. At 161 kV and 230 kV, composites are used on a limited basis for project-specific needs.

Porcelain is still the preferred choice for the bulk transmission lines. NorthWestern has experienced problems with many of the early vintage composite insulators due to corona cutting and moisture ingress. One severe example of this was a 161-kV line built in the early 1990s with composite horizontal line post insulators. The line has only been operated at 69 kV since construction, yet moisture ingress failures, believed to occur during manufacturing, have occurred on the 161-kV insulators, forcing NorthWestern to replace them recently.

Overall Perspective

It seems a shift is occurring in the use of the various insulator technologies for high-voltage lines in the North America. Users pointed out that, for distribution (less than 69 kV), polymers are favored, because they are lightweight, easy to handle and low cost; however, several utilities are limiting the use of polymers at higher voltages. Polymers seem to be established as the technological choice for compact line applications (line posts and braced posts). Maintenance concerns associated with the management of aging porcelain insulators and associated inspection costs are driving some utilities to question the use of porcelain insulators, while life-cycle cost considerations and ease of inspection associated with toughened glass insulators are steering other utilities toward this latter technology.

Clearly, all three insulation technologies are still very much alive, and decisions made with regard to insulation systems for the refurbishment of older lines and the upcoming surge of new high-voltage projects will depend on past experience and the expected performance and life-cycle cost criteria utilities set for the operation of their systems.

Ravi Gorur ([email protected]) is a professor in the school of electrical, computer and energy engineering at Arizona State University, Tempe. He has authored a textbook and more than 150 publications on the subject of outdoor insulators. He is the U.S. representative to CIGRÉ Study Committee D1 (Materials and Emerging Technologies) and is actively involved in various IEEE working groups and task forces related to insulators. Gorur is a fellow of the IEEE.

The purpose of this article is to provide a current review of the trends in insulator technologies through interviews with several utilities, all familiar with and having experience in the three technologies. The utilities selected for soliciting input cover a wide range of geographic and climatic conditions from the U.S. West Coast to the East Coast, including one major Canadian utility. The author gratefully acknowledges input from the following:

  • J. Hunt, Salt River Project
  • G. Giordanella, Public Service Electric and Gas
  • D.H. Shaffner, Pacific Gas and Electric
  • D. Berklund, Xcel Energy
  • H. Crockett, Hydro One
  • T. Pankratz, North Western Energy.

Utility Sources

Electric Power Research Institute

Hydro One

Companies mentioned in this article:

NorthWestern Energy

Pacific Gas and Electric Co.

Public Service Electric & Gas

Salt River Project

Xcel Energy

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