INMR Issue 103 Q1 2014 by INMR

to Germany!

Welcome to Bavaria!

Welcometo Munich!

Welcometoour20 anniversary th

2015 INMR WORLD CONGRESS

• 120technicalpresentationson today’s important topics and serviceexperiencewithdifferent designs of MV, HV & UHV insulators,surgearresters,bushings and cable accessories • AProduct&TechnologyExhibitionfeaturingmanyoftheleading suppliers across the globe

WORLD CONGRESS Westin Grand Hotel, Munich, Germany Oct 18-21, 2015

For more information: www.inmrworldcongress.com or email us at: info@inmr.com

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PERSPECTIV

Estimatedshareoflineandsubstation insulator market: 1990-2010.

Gains By Composite Insulator Technology May Soon Plateau

ccording to estimates developed by industry expert, Alberto Pigini, and discussed at the recent 2013 INMR WORLD CONGRESS, the total world market for insulators has seen quite a ‘shake-up’ in recent years. Composite type insulators, once regarded as niche products for ‘extreme’ applications, have now become ‘mainstream’ and represent a significant share of this business. In fact, if one were to project the trend since 1990, it might seem that porcelain and glass may be at risk of soon being displaced.

Yet it is premature to draw any conclusion that glass or porcelain insulators will eventually disappear from power lines and substations. In fact, reading articles in this issue from visits to power companies in such diverse places as Korea, the United States, Saudi Arabia and Norway, one might well conclude that ceramic insulator technologies are still the preferred choice of many transmission system operators. Part of this relates to lingering uncertainties for composite insulators when it comes reliability, safety of live line work and risk of degradation under severe service conditions. Another issue is consistency of quality. Perhaps the greatest risk now being faced by composite insulator technology is that it is typically the first choice of suppliers who are still relatively new to this business and whose accumulated service experience is measured more in years than decades. Porcelain and glass insulators, by contrast, are still being supplied mainly by manufacturers who have been in this field for a very long time. These suppliers therefore have that much greater field experience on which to base their designs and manufacturing quality control processes. What the future will hold in this industry will depend in large part on whether manufacturers of composite insulators will be able to supply consistently high quality products across the globe. Here the old proverb may well apply: a few ‘bad apples’ can spoil the entire barrel.

Coming... intheNextIssueofINMR Thanks to a booming local oil and gas sector, AltaLink, the main grid operator in Alberta, Canada, is now nearing the end of the largest investment program in its history, with from $1.5 to 2 billion having been allocated to new transmission lines and other upgrades to its network.

In the upcoming Q2, 2014 issue, INMR will take readers on an exclusive tour of two of the most prominent of these projects, the Âą 500 kV HVDC WATL line that is nearing the final stages of completion and also the 500 kV AC Heartland Project, which involved a range of design challenges, from a gas-insulated line to special towers developed to assist public approval in a key section of line

Contents

Advertisers in This Issue ABB

Inside Front Cove

Chengdu Electric Power Fittings Works 60-61 CSL Silicones - SiCoat

Outside Back Cover

Dekuma Rubber & Plastic

Issue 103 Quarter 1 − 2014 Volume 22 − Number 1

68-69

Dalian Composite Insulator DCI

4, 99

Dalian HiVolt Systems

Dalian Insulator Group

10-11

Dalian Reliable Industrial

Desma Elastomertechnik

Dextra Power

DNV GL KEMA

EGU HV Laboratory

103

Fivestar HV Testing Equipment

Glasforms PolyOne

HSP/Transform Partner Companies Hubbell Power Systems

Inside Back Cover

Hübers Verfahrenstechnik

Jinan Meide Casting

Motic Electric

NORIT Group

Ofil

4 Perspective 12 Editorial Take a ‘Long View’ When Selecting Insulator Suppliers 14 Commentary by Pigini Selecting Composite Insulators for DC 16 From the World of Testing Shunt Reactor Switching Ambiguity 18 Reporting from CIGRE New Working Groups for CIGRE 20 Transient Thoughts Resources for the Cable vs. Overhead Debate

Omni LPS

46-47

Phenix Technologies

Pukou Huagao

Qingzhou Shi Liwang Electric Technology 65 Reinhausen Power Composites

SGD La Granja

62 New 500 kV Line Allows U.S. Utility to Compare Performance of Alternative Insulators & Hardware

STRI

Taizhou Huadong Insulation

TE Connectivity

72 Practical Applications of Automatic Image Analysis of Overhead Power Lines Insulators 76 German Supplier Looks to Serve Expanding Market for Hollow Composite Insulators 84 New Factory for Composite Insulators Opens in Estonia Bushings 88 ABB Invests to Streamline Bushings Production & Testing Part 1 of 2

24 Woodworth on Arresters Transmission Line Arresters Lower Losses & Increase Reliability

Cable Accessories 100 Testing Cable Terminations Under Polluted Conditions

28 Silicone Technology Review Some Basics of RTV Coatings

103

48 400 kV Supergrid with Modular HVDC System Interconnects Countries of Arabian Gulf

22 Scene from China Characterizing Insulator Pollution Severity Using Surface Conductivity

26 Focus On Cable Accessories Superconducting Cable Technology Ready for Broad Application

Utility Practice & Experience 32 Network on Jeju Island Supports Testing of Power Technologies

Production Equipment 108 German Injection Equipment Manufacturer Adjusts Business Strategy Materials 112 Resolving Problems From Poor Insulation Performance in Desert Environments (Part 3 of 3)

Shaanxi Taporel Electrical Insulation Sichuan YiBin Global Group SYGG

19 30, 31

Trench Test Systems

Tridelta Überspannungsableiter

Uvirco

Wellwin Precision Moulds

Wenzhou Tenseng Power Systems Wenzhou Yikun Electric

1 21

W.S. Industries Yizumi Precision Machinery

5 Front Cover

Zhejiang Fuerte

Zhejiang Zhongrui

Zhengzhou Jingwei Electric

Zhengzhou Xianghe Group Electric

54-55

Zibo Taiguang Electrical Equipment

INMR Issue 103 www.inmr.com ISSN 2290-5472, E-mail: info@inmr.com Editor & Advertising Sales: Marvin L. Zimmerman mzimmerman@inmr.com 1-514-939-9540 中国地区联系方式：余娟女士电话: 135 1001 6825 / juan.inmr@gmail.com

Magazine Design: Cusmano Design and Communication Inc. 1-514-509-0888 corrado@cusmanodesign.com Contents of this publication are protected by international copyrights and treaties. Reproductionofthepublication,inwholeor inpart,withoutexpresswrittenpermissionof thepublishersisprohibited.Whileeveryeffort is made to verify the data and information containedinthispublication,thepublishers accept no liability, direct or implied, for the accuracy of all information presented.

Everything a Well-Built Network Needs …. Composite Long Rod Insulators, Post Insulators & Hollow Core Insulators

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With a tradition of insulator know-how going back to 1915, our newly-built factories are among the most modern anywhere, with efficient production flows and state-of-the-art manufacturing and testing equipment. All this is supported by an experienced engineering and production staff dedicated to maintaining quality all along the line. That means every order is made to the highest standards and also completed ready to ship according to your leadtime requirements. Choose Dalian Insulator Group and benefit from dealing with one trusted source that can reliably meet all your insulator needs. Insulator Hardware & Line Fittings

EDITORIA Take a ‘Long View’ When Selecting Insulator Suppliers

Ask anyone working in the insulator business these days and you’re likely to hear a similar story. Competition is fierce, price levels depressed. An increasing number of suppliers are fighting for a share of this market, especially in the composite insulator segment, and overcapacity is lurking in the porcelain and toughened glass sectors as well. While this may sound like uniformly good news for insulator buyers, it does come with certain potential risks. Insulators, like most other components in a power network, are expected to function reliably for decades. Unreasonably low prices today may lower acquisition costs for grid operators but can impose high costs down the road, especially if the insulator industry has to ratchet quality downward to stay competitive. As an example, the production manager at one insulator manufacturer recently confided that his firm no longer routinely supplies the highest quality materials as part of their insulators. “We give the customer what they’re willing to pay for … but not more,” he admits. That same week, I also happened to meet a quality control engineer working at one of the world’s largest power network operators. He recounted a recent incident involving a shipment of transmission insulators that were delivered by the supplier awarded the tender thanks to lowest price. Apparently, all were delivered 80 mm shorter than the arcing distance specified. It seems hard to imagine that quality control testing would not have revealed such an obvious deficiency long before shipping to the customer and illustrates what can go wrong if low price becomes the main measure for supplier selection. Users and manufacturers both have the same goal when signing a sales contract, namely to equip a new line or substation with insulators that will perform without problem for many years. But there are challenges to this historic paradigm as more and more suppliers find themselves competing on price, not quality. Says one industry observer, “The pressure to survive these days is so high.” What he’s really saying is that unreasonably low price levels may force certain suppliers to take ‘shortcuts’ just to stay in business. The important message: end users must always take a long-term view whenever buying a component that is as strategic to the safe and reliable operation of the power network as is the insulator. That means low price alone should never be the major basis for choosing one supplier over another. Moreover, buyers should also keep in mind the following long-demonstrated axiom. While insulators account for only some 5 to 8 percent of line or substation construction costs, their failure is typically the single biggest factor when it comes to costly unplanned outages and very high maintenance expenses.

Marvin L. Zimmerman mzimmerman@inmr.com

The world’s first DC lines were equipped with basically the same ceramic insulators used for AC. However, experience showed that, after only several years of service, there were problems with unacceptably high rates of puncture of porcelain and shattering of glass discs. In 1992, IEC issued 61235 ed. 1 “Insulators for overhead lines with a nominal voltage above 1000 V – Ceramic or glass insulator units for d.c. systems – Definitions, test methods and acceptance criteria”. Afterwards, high resistivity insulators were developed to conform to the new standard and there was a dramatic improvement in performance.

Selecting Composite Insulators for DC

Looking at composite insulators, while guidance for their selection, including specification of housing material, is available for AC (e.g. IEC TR 62039, IEC 61109, IEC 62231), no similar standard or technical specification is yet available for DC. At the same time, relevant field experience with them is still relatively limited (e.g. only some 20,000 to 30,000 units have been installed in recent years on DC lines worldwide). As such, it is probably too soon to draw any general conclusions about their performance, even if preliminary indications would suggest it has been mostly positive. It should also be noted that the majority of these insulators have been installed in China and therefore have had to meet local Technical Specification DL/T 810-2002 for ± 500 kV DC long rod composite insulators. This specification derives largely from IEC 61235 and, among other things, prescribes specific tests, including: • • • • • •

Verifying minimum required volume resistivity; Verifying impact of ion migration on mechanical performance; Tracking and erosion tests with specific DC requirements; 1000 hour tracking and erosion tests, but with DC parameters; Artificial pollution tests specifically for DC using the solid layer method; Tests to assess hydrophobicity transfer and recovery, within specific limits. The IEC is now working on IEC TS 60815, which aims to define the creepage distance requirements for composite insulators in the case of DC. My view, however, is that in addition to offering guidance for selecting insulators from the standpoint of pollution, other basic guidance must also be given. For example, standards (or specifications or indications) about minimal hydrophobicity requirements are especially important since they form the starting point for selecting insulators from the creepage point of view.

Fig. 1: Hypothetical schematic influence of insulator diameter on required USCD for large composite insulators (USCDD= Cd x USCD with USCD line insulators requirements).

Fig. 2: Hypothetical schematic influence of creepage factor (CF) on required USCD for large composite insulators (USCDD/CF= Cf x Cd x USCD with USCD line insulator requirements).

Pigini Commentary

The present definition of hydrophobicity transfer material (HTM) and nonHTM materials, as in IEC TS 60815, is too qualitative. Indeed, hydrophobicity transfer and recovery time (and thus pollution performance in service) can vary dramatically for different housing materials used in such insulators (e.g. according to relative quantities and grades of silicone and fillers used) even if all are intrinsically HTM. Quoting from a recent column by Prof. Liang Xidong at INMR’s web site: “As of now, there is still no internationally-accepted quantitative test methodology to classify good versus poor hydrophobicity transfer, even though it’s obvious that this can mean substantially different service performance under pollution.” Requirements in regard to hydrophobicity are particularly important when it comes to DC. While in IEC TC 60815 Part 3, the USCD requirements for composite insulators are nearly the same as for ceramic insulators, there is a basic assumption that composite insulators could be used at far lower USCDs. However, this can only be the case if strict requirements are placed on hydrophobicity transfer and recovery (to some extent able to be evaluated by measuring surface wettability, WC). This was illustrated in my most recent column (Q4, 2013) that referred to line insulators with relatively small diameters (about 100 mm average diameter) and relatively low creepage factors (around 3.3). Such requirements become all the more evident if data for relatively small line insulators is extrapolated to large substation insulators with CFs up to 4.5 and diameters up to 1200 mm, as required for UHV and as shown schematically in Figs. 1 and 2. More specific indications about the minimal requirements for DC composite insulators must appear as soon as possible in order to permit broader and more cost-effective application.

Alberto Pigini pigini@ieee.org 14

High power test laboratories have traditionally seen much of their work devoted to verifying the short circuit current breaking capability of circuit breakers. Though designed primarily for breaking high fault currents to prevent major tangible as well as intangible damage to expensive network assets, breakers must also perform a number of additional duties. One of these is inductive load switching. In practice, the most relevant applied inductive loads typically come from shunt reactors that are installed in power systems to absorb reactive power and secure voltage stability. These are connected directly to the line or to the tertiary winding of transformers and are normally switched by the breaker. Because of varying system loads, the need to generate reactive power varies between day and night. Therefore, in contrast to a standard breaker that operates a few times a year to clear a fault current or during system reconfiguration, the breaker here needs to switch the shunt reactor frequently.

Shunt Reactor Switching Ambiguity

Another important difference lies in the magnitude of the currents being switched. Fault currents can be as high as tens of kiloamperes whereas shunt reactor load currents are only a few tens to a few hundred amperes. Although breakers are designed to handle very high fault currents, this much lower current, combined with the frequency of switching operations, can prove a challenge – sometimes even referred to as the ‘breaker’s worst nightmare’. This conclusion is supported by a recent CIGRE survey on reliability, which revealed that the incidence of major failures of high voltage shunt reactor breakers amounted to nearly 2.5 per 100 breaker-years, a rate 10 times higher than for overhead line breakers. The reasons for this are both mechanical, i.e. due to the number of switching operations, and electrical. Since the breaker is prepared for maximum short circuit current, its massive extinguishing power is applied indiscriminately during low current inductive load switching as well and leads to clearance of the arc before its natural current zero. A small ‘chopping current’ then remains trapped in the inductive load and this generates a voltage across the contacts after arc extinction. Because of the 90° phase lag between voltage and current, the voltage reaches a maximum at the moment of current zero. With the chopping current overvoltage added to the natural transient recovery voltage, there becomes a reasonably high probability of breakdown of the contact gap with resulting re-ignition of the arc. All transients in this type of switching duty originate from a single, nearby shunt reactor so that switching transients succeed each other faster than the switching gap can recover. As a result, a closely spaced multitude of re-ignitions are usually observed, creating a sequence of breakdowns from increasing voltage to zero. These very fast transients run into the system equipment in the immediate vicinity of the breaker, notably the transformer winding, which is stressed heavily. In fact, the classical question posed during investigation of many transformer failures is whether the breaker is producing too intense rapid re-ignition transients or whether the transformer winding was not sufficiently insulated against such fast transients. In critical applications, the recommendation to avoid re-ignition is therefore to apply controlled switching, i.e. whereby interruption is delayed to the moment when the contacts have reached enough spacing from each other to withstand the transients. This hazard of re-ignition was recognized in the IEC standard describing shunt reactor switching requirements (IEC 62271-110, updated in 2012). A key feature of this standard is the requirement that, taking such re-ignitions for granted, they are permitted during a single interruption attempt only. New test requirement for shunt reactor switching with breakers having rated voltage below 52 kV are now being introduced. It is the philosophy of the IEC to describe transient recovery voltage (TRV) in terms of voltage wave shape parameters and, as long as these meet standardized values, the test is valid. However, in shunt reactor switching, re-ignition is ubiquitous and governed by high frequency phenomena. This means that small changes in test circuit parameters can produce large differences in results. More specifically, the high frequency currents that start upon re-ignition may or may not be able to be interrupted by the breaker, depending on circuit elements not specified in the standard.

From the World of Testing

This ambiguity is becoming all the more pronounced now that vacuum breaker technology has started to find application at transmission voltages, traditionally the domain of SF6 switching devices and to which present high voltage standards are in fact tailored. Even more than SF6 breakers, vacuum breakers can interact intensively with stray capacitances and inductances found in test circuits. Therefore, results of shunt reactor switching tests of high voltage vacuum breakers may differ among different test laboratories simply because the high frequency effects during interruption are different, even though the main electrical TRV stresses may be identical and accord to the standard. Perhaps, future versions of this standard should describe shunt reactor test circuits in more detail in regard to their high frequency characteristics. This will allow for fairer comparison of test results among different laboratories. Indeed, one such example already exists – the IEC standard on high voltage motor switching that is clearly tailored to vacuum breakers

Dr. René Smeets Rene.Smeets@dnvkema.com 16

A number of CIGRE Working Groups (WG) will now be disbanded and these include WG D1.27 Material Properties for New and Non-Ceramic Insulation and WG B2.21 Insulators. Their successor WGs will deal with subjects that are currently of most interest in the field of transmission lines and equipment, including: HV & UHV levels in AC and DC; better utilization of existing corridors by voltage upgrades; and new solutions such as hybrid lines. These trends demand new developments rather than simple up-scaling and a scientific analysis of the state-of-the-art will be required in terms of material properties as well as suitable test methods. As such, the terms of reference of two new WGs – D1.58 and D1.59 – aimed at material properties of polymeric outdoor insulation were recently confirmed by CIGRE’s Technical Committee Chair. These new WGs will be dedicated to a single topic and their Convener will be Jens Seifert. Those interested to participate should contact their National Committee or Jens directly (jseifert@lappinsulators.de).

New Working Groups for CIGRE

WG D1.58: Evaluation of dynamic hydrophobicity of polymeric insulating materials under AC and DC voltage stress Optimizing polymers will be a complex process and materials with new fillers or surface structures may be required. However, the key properties of any new or modified materials will have to be investigated and existing materials with proven long-term performance might serve as reference points in back-to-back tests. Relevant material properties for non-ceramic outdoor insulation were identified in CIGRE Technical Brochure (TB) 255 published in 2004 and resulted in IEC TR 62039 issued in 2007. Moreover, studies presented in CIGRE TB 442 (2010), have shown that additional study of the dynamic hydrophobic properties of new non-ceramic materials will be needed, especially given recent trends and behaviour under DC voltage stress. The retention and recovery of hydrophobicity are remarkable added values for reliability and performance and IEC 60815-3 states that the correction factor for insulator diameter depends on a housing material showing hydrophobicity transfer mechanism (HTM) – but with no information on how to evaluate this. Further knowledge will be required for the coming revision of IEC TR 62039 “Selection guide for polymeric materials for outdoor use under HV stress”as well as IEC 60815 with the following scope: • Setting suitable test procedures for determining retention and recovery of hydrophobicity under AC and DC voltage stresses; • Referencing earlier studies within WG D1.27 and multiple results from past round robin tests (RRT); • Defining test arrangements, parameters and evaluation criteria for all relevant material groups; • Verifying reproducibility of resulting superior test procedure(s) by more RRTs. WG D1.59: Methods for dielectric characterization of polymeric insulating materials for outdoor applications A related topic will be search for suitable physical, chemical and dielectric diagnostics and tests for new polymeric materials, e.g. one aim is to describe each using a ‘fingerprint’. This continues a topic that was dealt with in WG D1.27 and for which a corresponding TB will soon be published. This new WG will focus on: • Formulating guidelines for precise, reproducible measurements of dielectric properties of polymeric materials used in outdoor applications; • Assessing impact of conduction and polarization phenomena (AC and DC); • Defining test specimen preparation (electrodes, pre-conditioning etc.); • Deducing measurement ranges, both in time and frequency domains, representative for the application; • Exploring, comparing and evaluating selected test methods; • Demonstrating suitability of test methods by international RRTs. Both above WGs will start work early this year and last three years. Results will be published in ELECTRA or in a CIGRE TB. Besides evaluating new and optimized materials, present service experience with composite insulation offers an important pool of knowledge for further developing materials, insulator designs and either maintaining existing standards or issuing new ones. In view of this, a new insulator WG will be formed within B2 and whose terms of reference have been submitted to the TC Chairman: WG B2.57: Survey of operational composite insulator experience & application guide for composite insulators

Reporting from CIGRE

From 1990 to 2000, the findings of two composite insulator surveys plus a survey of performance on HVDC lines were published. Since the extent and application of composite insulators has since increased significantly, submitting a new questionnaire and publishing findings, including for HVDC, will contribute to exchange of information and further material development and standardization. The structure of the new survey will be similar to the previous ones to allow direct comparison and cover >100 kV. Based on results, an application guide will be developed for composite insulators that will also consider the current status of international standards as well as applications not yet covered by standards. This guide will apply to all types of composite line insulators and their electrical as well as mechanical aspects and an important part will be identifying whether gaps exist between existing standards and the state-of-the-art. I will serve as Convener and a call for membership will be launched as soon as the terms of reference are finalized.

Dr. Frank Schmuck frank.schmuck@sefag.ch 18

This has been an unusually severe winter in my home city of Toronto. I look out in awe at snow banks over a meter tall and temperatures have fallen to well below normal. Indeed, winter was bad from the start, with an extreme ice storm, having two separate periods of accumulation: the first for 10 hours on December 21 and the second for 28 hours the next day. Beloved canopies of tree branches snapped or were weighed down by 25 mm of glaze ice accretion. Electrical lines fared little better. Of course, with no electricity, the forced-air furnace in my home shut down and we had to resort to heating the 87-year old house using a combination of sunshine and hot water. Like some 300,000 other customers, there was little to do but bundle up and wait for service to be restored. Later, I was impressed with the efficiency of getting back to normal, especially considering how many branches were shorting out the overhead line on my street alone. In the process, I also learned something from talking with utility foresters during their pre-trimming patrol.

Resources for the Cable vs. Overhead Debate

A ‘danger branch’ on a city-owned tree in front of my house has always sagged close to the various incoming service wires whenever it rains. This branch had actually been evaluated previously for trimming but was left in place because it was classed as healthy. During the course of the ice storm, other branches did snap and fall onto power lines. But not the one I thought would most be a problem. Still, I decided, better move the car. With so much ice, we might have expected problems of bridging and ice flashovers on the local transmission system. Indeed, there was one flashover, shortly after re-energizing a 500 kV line that had been out of service. However there was no repetition of past multiple flashover problems associated with more modest levels of ice accretion in combination with pollution. I attribute this to the cleansing action of rains that occurred only hours before the freezing drizzle arrived. After the storm, there were the usual questions from friends and family. Why are lines not buried? they asked. To which I gave my usual response about the low cost of air as a dielectric, the difficulty of inspecting cables and also making changes in network configuration that would maintain existing reliability. I was able to reply with some confidence because I had just been perusing a series of invited reviews, published throughout 2013, to mark the 50th anniversary of the IEEE Dielectrics and Insulation Society (DEIS). Many of these dealt with insulation issues specific to successful HV cable installations, including their evolution from paper-insulated 400 kV systems in the 1930s to the slow but steady adoption of polymer-insulated AC cables that first appeared in the late 1960s. I looked over all 12 reviews to confirm my (admittedly biased) impression that cable insulation defect management and workmanship remain a ‘work in progress’ and realized that they may represent an excellent added resource for INMR readers. Each review is about 10 pages, published in the IEEE Electrical Insulation Magazine (Vol. 29, No. 1 to 6 and Vol. 30, No. 1) and accessible from the IEEE Xplore web site. The first review in the series, by Prof. Toshikatsu Tanaka and Dr. Takahiro Imai, noted that the concept of mixing composite materials such as mud and straw for building walls is finally mature. The authors distinguished nano-composites from polymeric alloy materials based on the size of the dispersed phase, ranging from 1 to 300 nanometers for the former to from 0.1 to 10 micrometers for the latter. Success with the first commercial nano-composite mixture of clay and nylon was achieved in auto timing belt covers in the 1990s. However, publications in the area of nano-dielectric materials relevant to manufacturers and users of electrical insulators only exploded from 2002 on. The 4th invited review, by Dr. Ed Cherney, noted that polymeric insulators are mature products and viable replacements for ceramic technologies on the basis of their 50-year development period. In common with Tanaka and Imai, he sees a bright future for new polymeric compounds mixed with micro- and nano-scale fillers to improve service life under extreme conditions. Cable insulation has never reached the reduced dimensions and low cost associated with exploiting intrinsic breakdown strength, i.e. on the order of 108 V/m for semiconductors and pure salts such as KCl and NaCl. This large difference between intrinsic and engineering breakdown was reviewed by Dr. Gilbert Teyssedre and Dr. Christian Laurent in the 7th article. Functional stress levels have now exceeded 14 kV/mm for DC cables. Their review complements progress in long-distance DC transmission projects described by Dr. Rongsheng Liu in the 8th paper.

Transient Thoughts

Based on the above, my revised answer regarding moving overhead lines in Toronto underground would now be that it might accompany a shift to local DC networks and other Smart Grid concepts. During the ice storm, many people had power restored for a day or two, only to see it cut off again because tree branches had damaged their service connections. Ad hoc ‘micro-grids’, consisting of extension cords running between neighbors who had power and those who did not, soon formed to soften the impact. If there is another ice storm 30 years from now, I hope to relate the story of the ‘2013 event’ to my great-grandchildren in the comfort provided by a robust, multi-fuel energy storage and supply infrastructure. There is clearly a greater role for cables and arresters in this picture. However I am confident that outdoor insulators and reliable, long-serving overhead lines will also have a place.

Dr. William A. Chisholm W.A.Chisholm@ieee.org 20

The most common parameters to characterize insulator pollution severity are equivalent salt deposit density (ESDD), leakage current and surface conductivity. My past two columns discussed the advantages and disadvantages of relying on ESDD and leakage current. Here, the focus will be on surface conductivity. Based on classical theory regarding flashover of polluted insulators, after partial arcing, the voltage applied at both ends of an insulator has two components: the voltage drop of the arc and the voltage drop of the residual pollution layer resistance. A simplified model describing this process is shown below:

Characterizing Insulator Pollution Severity Using Surface Conductivity

Scene From China 22

Here, U = Ua+Ur, where Ua is the voltage of the partial arc and Ur the voltage of the residual pollution layer resistance. Ua = AxI-n where x is partial arc length, I is leakage current across the insulator surface and A and n are constants to characterize arc features. Moreover, Ur=R(x)I, where R(x) is the resistance of the residual pollution. For insulators with complex geometry, R(x) can be expressed as follows: R(x)= Ln(L-x)/r0 multiplied by 1/πγ In this formula, γ is conductivity of the residual pollution layer, L is insulator leakage distance and r0 is arc root radius of the partial arc. By derivation, the critical condition of pollution flashover, insulator pollution flashover voltage (Uc) can be obtained: Uc=(1+1/n)IcR(xc) R(xc)= Ln(L-xc)/r0 multiplied by 1/πγ where Ic is leakage current at occurrence of critical pollution flashover and Xc is critical arc length. Due to space limitations, I will not dwell on the detailed derivation process for pollution flashover voltage of an insulator. Rather, my focus will be on the key relationship that exists between flashover voltage of a polluted insulator and surface conductivity. From the above, it’s evident that flashover voltage of a polluted insulator and surface conductivity of the pollution layer are directly related. Therefore using the latter parameter to characterize pollution severity on insulators is correct theoretically. In reviewing the advantages and disadvantages of relying on ESDD to evaluate pollution severity on insulators, I noted that, while the test methodology is simple, its major drawback lies in poor correlation with pollution flashover voltage. In this respect, surface conductivity is clearly a superior parameter compared to ESDD. So why is it not being as widely used as ESDD for this purpose? The answer is that the methodology to measure it is relatively complicated. Basically, it relies on applying constant voltage over the entire polluted insulator under conditions of saturated moisture and measuring the leakage current across the surface. Dividing this current by voltage allows surface resistance to be obtained and, based on insulator geometry, surface conductivity can then be calculated. However, while this seems straightforward enough, the crux of the problem lies in the measurement itself. As well known, the pin, cap and porcelain shell of a suspension insulator are not directly connected. Rather, cement and air gaps within the disc represent ‘interruptions’ to the pollution layer and this discontinuity can significantly affect the measurement. To overcome this, a higher test voltage must be applied, which can cause breakdown of the air gap. Moreover, increasing the voltage also leads to other problems since the resulting higher current will quickly dry the pollution layer and affect the measurement result. To avoid the impact of such drying, the current value would have to be measured over a very short time interval. There has been much research conducted on suitable methods for measuring surface conductivity of an insulator and some countries have specified how best to do it. The major guideline in most cases is that, the test voltage must be applied as high as possible yet without triggering pollution flashover of the entire insulator and the duration of applied voltage should be as short as possible, with the goal of completing the measurement within only a few cycles (50 cycles per second). Given this, the requirements placed on measuring instruments and techniques become quite demanding, meaning that test equipment is usually more costly and that results tend to be more scattered (due to the uncertainty from the pollution layer interruption). To overcome this, China’s Tsinghua University has developed a partial surface conductivity measuring device. The principle behind its operation is that there is no need to measure the conductivity of the entire insulator but rather only its partial surface conductivity. The detector is simple and consists of either parallel electrodes that are spaced 2 mm apart or concentric ring electrodes. The measurement voltage is also relatively low and as such avoids drying the pollution layer. Moreover, there is no longer any need for the entire insulator to be saturated with moisture. Rather, it is necessary to only wet the pollution layer near the measurement electrode and this will not affect the condition of the pollution layer during measurement. The device can measure the change of pollution accumulation on the insulator over time and can also measure distribution of pollution on different parts of the insulator surface. This device, which has already been used in test stations with natural pollution accumulation as well as at substations, makes the methodology of measuring partial surface conductivity promising.

Prof. Guan Zhicheng Tsinghua University, Shenzhen Campus guanzc@tsinghua.edu.cn

Product Range: Transmission Line Type: AC: 10 kV~1000 kV DC: 25 kV~1100 kV

Line Post Type: 10 kV~400 kV Station Post Type: 10 kV~230 kV

Given the possible application of line arresters to mitigate the effects of lightning, it strikes me as inexplicable that arresters are not being used more often to reduce momentary lightninginduced outages on transmission lines. I have asked experts to explain why this is the case but most could offer no explanation. Some speculated it was due to concern about arrester failure. I have recently been involved in an economic study funded by the State of New York R&D Association and conducted in partnership with R&D firm, Ceralink, as well as professors at Rensselaer Polytechnic Institute and Cornell University. Our work focused on using arresters in place of shield wires on transmission lines, with the initial goal being to demonstrate that inductive losses due to overhead ground wires could be eliminated by replacing these with arresters. Other possible advantages included reducing overall energy needs. That goal seemed worthy in itself but our team soon realized that the accompanying improvement in reliability offered even greater potential for gain. In the initial study, it was found that the financial benefits from eliminating the OHGW came in two parts: lowering construction costs and preventing induced losses over the lifetime of the line. When considering initial construction costs, the variables included tower type, system voltage, number of circuits, phase configuration, desired protection level and type of arresters used. The table below summarizes findings:

Transmission Line Arresters Lower Losses & Increase Reliability

The second to last column in the Table is the net present value of the savings that would be realized if shield wires were eliminated, assuming a 10% return on investment, 30-year life of the line, power cost of 50 cents per MWHr and 5% annual inflation. The study demonstrated that the savings from reducing losses is not as significant as the reduction in upfront material and construction costs. When combined, savings of using arresters in place of OHGWs ranged from 5% to 8% of the initial total investment – certainly worth thinking about on its own merit.

Typical Savings/Mile When Using Arresters Instead of OHGW* Tower Voltage, Type, # of Shield Wires and Circuits

TotalLineCost/ Mile (USD)

Savings/Mile withNoShield Wire (USD)

Cost/Mile of Arresters (USD)

CapitalSavings (USD)

30 Yr NPV of OHGWPowerLoss Savings (USD)

TotalSavings/ Mile (USD)

115 kV H-Frame 2S 1C

900,000

83,280

31,200

52,080

8,182

60,262

230 kV H-Frame 2S 1C

1,050,000

98,780

55,200

43,580

9,303

52,883

115 kV Steel Pole 2S 2C

1,590,000

131,580

49,600

81,980

46,261

128,241

230 kV Steel Pole 2S 2C

1,890,000

157,580

91,200

66,380

43,724

110,104

115 kV LatticeTower 2S 2C

1,420,000

119,680

49,600

70,080

36,905

106,985

230 kV LatticeTower 2S 2C

1,680,000

142,880

91,200

51,680

43,724

95,404

*Thepermilesavingsbynotinstallingashield wire includes the cost of the wire, the cost of installation as well as reduced tower and foundation costs. The cost of using arresters includes arresters on each phase of each circuit, using Class 3 line arresters on the exposed conductors and Class 1 arresters on theconductorsshieldedbythephaseabove.The spacingselectedwas8towerspermile(1.6km).

But what the calculation does not reveal is that reliability of a line protected by arresters is better than for one that relies on the OHGW. For lines protected by shield wire and having very low tower ground resistance and good insulator BIL, the probability of backflash outage can be as low as 5% of all challenges faced by the line. But if footing resistance is poor and/ or the insulator BIL low, backflash of insulators can account for as much as 20 to 30% of such challenges. With arresters installed on all phases of all towers, however, the probability of outage due to lightning is zero, i.e. arresters applied to all phases on every tower render the line ‘lightning proof’. Moreover, ground resistance is no longer a factor in the reliability equation. Knowing that line arresters eliminate lightning related outages, it might seem that quantifying the benefit of improved reliability would be easy. But this proved not to be true. Assigning a cost value to a transmission line outage is not as easy as for a substation or distribution system since, in the latter cases, the utility incurs a specific cost if equipment fails due to lack of protection. In the case of transmission lines, arresters are preventing insulator flashover, not transformer failure. An insulator flashover may be a system failure, but the insulator is self-healing and most of the time remains undamaged.This fundamental difference means that power system operators do not see any direct cost from a momentary outage that occurs when an insulator flashes over.

Woodworth on Arresters

In fact, the impact of such an outage is borne more by end users than line operators and, since there is no associated direct cost, there is less incentive among operators to eliminate it. Moreover, most end users don’t even realize that the lightning outage could have been avoided. This combination of little financial incentive by power system operators and lack of awareness among end users therefore seems to be preventing greater application of transmission line arresters. The economic benefits of increased reliability cannot easily be quantified without doing an analysis of all the customers served and we have therefore not been able to quantify them. Still, the figures are most probably significant. So a question of system operators, how do you justify the use of transmission line arresters when you use them?

Jonathan Woodworth Jonathan.Woodworth@ArresterWorks.com 24

In recent years, application of high temperature superconductors for medium and high voltage power cables has moved progressively from only the ‘prototype phase’ to initial testing in the field. Use of specialized materials, where the effect of superconductivity starts with a relatively high temperature, makes it possible to employ liquid nitrogen as the coolant. As such, cost-effective industrial operation would now seem virtually ‘around the corner’. Superconducting cables represent an innovative power transfer technology that has the potential to offer numerous benefits, especially for applications in high-density urban environments. These benefits include:

Superconducting Cable Technology Ready for Broader Application

• Increased power density with less space for the cable corridor; • Up to five times greater capacity at the same voltage; • No drying-out of the soil; • Reduced magnetic field; • Reduced need for space for the switchgear at higher voltages; • Capability to limit short circuit current by the cable itself. A range of different power cable and cable accessory designs for this technology have already been developed and tested over the past few years. At the beginning, prototypes consisted of single core as well as three core cables having both cold and warm dielectric (i.e. insulation). The conductor in these cases was a combination of copper wire and superconducting material. However, problems of high magnetic field intensity outside of a single core cable with nominal current between 2 and 3 kA generally dictate concentric cable design. The photo shows the typical construction of modern superconducting medium voltage cable. Beginning from the inside, an inner corrugated steel tube allows cooling by liquid nitrogen and is covered by insulating material. Next are strips of the superconducting material for phase one. Subsequent layers consist of: insulation; phase two; more insulation; phase three; more insulation; and finally an outer copper screen. This complete concentric three-phase cable system is then surrounded by thermal insulation – the so-called cryostat. One of the first applications of a network integration project using superconducting cable was in 2008 at the grid of Long Island Power Authority in New York and involved 138 kV cable. The nominal current of the three 600 m long, single core cables was 2.4 kA and the power transfer capacity was 573 MVA. A very recent and perhaps more interesting solution – installed this past December in the German city of Essen – consists of a one kilometer length of 10 kV three-core coaxial cable with nominal current of 2.31 kA and total power capacity of 40 MVA. The complete system in this case consists of: coaxial cable surrounded by the cryostat; one cable joint; two terminations; one current limiter; and finally the refrigeration system. Presently, superconducting DC and AC cable installations will soon be evaluated as part of a multistage project involving a hybrid overhead line on Jeju Island in Korea (see article on p. 32). Integrated into each termination in the case of the Essen project are several elements, including connectors for all three phases between the cold cable cores; the contact parts at room temperature; and a connection to a refrigeration system. As a result, these terminations are substantial in size, measuring 2.4 m with diameter of 1 m.

Focus On Cable Accessories

Critical to allowing more widespread application of superconducting cable systems of virtually unlimited length will be the availability of suitable straight joints. Such joints would have to be installable in the field and thereby guarantee the possibility to carry out repairs in the case of significant damage or failure. Given the current availability of different coaxial single core as well as three-core superconducting cables for different voltages and also appropriate terminations and joints, all the technical requirements for broad commercial application would appear to be on the verge of being fulfilled.

Professor Klaus-Dieter Haim University of Applied Sciences Zittau/Görlitz, Germany KDHaim@hs-zigr.de 26

SILICONE

Technoolgy Review

Some Basics of RTV Coatings The application of RTV silicone coatings to ceramic insulators in order to increase their performance under pollution is certainly not a new maintenance technology. Yet, while available now for decades, not all power engineers fully understand how it operates and what determines its efficacy. At the same time, given the availability of composite insulators, one might well ask why RTV coatings are still being offered at all. Why do power companies not just specify silicone insulators for service areas where there are serious pollution concerns? The following will help to answer this and other questions:

Why is there a need for RTV coatings?

The simple answer is that the vast majority of existing power installations across the globe – even those built in zones of high contamination – still feature porcelain and glass insulators, most of them put in service many years ago. Depending on how well designed these have been for their operating environment and on the efficacy of natural cleaning by rain or wind, they should require little maintenance beyond periodic inspection. However, there are many situations where substations or lines are built in areas where the pollution exposure has increased over time, due for example to construction of nearby industrial areas and highways. This type of activity can dramatically change the level of pollution affecting a line or substation and something must be done or there will be elevated risk of flashovers. Another consideration promoting continued interest in coatings is the increasing cost of cleaning ceramic insulators installed in highly polluted service areas. With fresh water an increasingly expensive resource and with labor costs of annual washing from truck or helicopter also going up, the relative economic benefit of RTV coatings versus cleaning is growing. Yet another factor behind more and more utilities opting for RTV, according to industry sources, is because it offers the electrical benefits of silicone with the mechanical benefits of ceramics. Finally, not all power utilities are confident in the long-term performance of composite insulators, e.g. in areas with persistently high UV or where bird-pecking is a serious problem or in certain applications, such as tension, where there is a perception that they may be damaged by lines workers carrying out routine maintenance on conductors.

What is the principle behind RTV coating?

A thin layer of RTV material adhering to porcelain and glass insulators vastly increases their pollution withstand since the silicone imparts hydrophobicity to what would otherwise be a hydrophilic surface. Moreover, since the silicone contains low molecular weight (LMW) chains that continually migrate to the surface, the ceramic insulator will remain hydrophobic, even when covered by a layer of pollution.

How long does an RTV coating remain effective?

Coated glass insulators in southern China (left). RTV coating being applied at substation near Sao Paulo, Brazil.

This, of course, is a key question when comparing the relative costs of coating by RTV versus alternatives such as water washing or using silicone grease. There is no ready answer since much will depend on the quality of the coating and how well it has been applied. Fortunately, these variables are both under the control of utility maintenance people. Assuming the RTV silicone material has been well formulated by a competent supplier and is applied by trained personnel under controlled conditions, it is certainly reasonable to expect at least 10 to 12 years of effective service life, possibly even longer. For example, coatings applied in the late 1980s/early 1990s on bushings at a highly polluted 230 kV substation near Hamilton, Ontario are reportedly still in operation.

What is required for effective coating application?

Porcelaincaneventuallybecomecoveredby conductive pollution, just awaiting a wetting event to cause problems.

In the best of cases, RTV coating would be applied under ‘factory conditions’, carefully monitoring thickness. However, this is clearly not possible for substations and therefore the key is good coating practice. This includes cleaning the ceramic insulator surface beforehand for best adhesion. Surface preparation is a critical step and therefore should ideally be monitored closely. Since conventional adhesion tests employed by the coatings industry at large do not work for silicones, other methods such as the cross hatch test or water blast adhesion test must be used. It is also necessary to ensure optimal spray thickness with even coverage so as to avoid uneven voltage distribution developing along the insulator surface under wetting conditions. Too thin or too thick a layer are both sub-optimal. That is why some suppliers of coatings recommend using their own experienced staff to carry out installation.

Do RTV coatings ever need to be cleaned?

Also since the major benefit of the coating bicity, one useful measure of end of life lies in transforming a previously hydrophilic would be permanent loss of hydrophobicity. Generally, no, although much will depend ceramic surface to one that has hydropho- This can easily be monitored by simple hydrophobicity measurements conducted on the type and rate of pollution that accuduring routine station maintenance shutmulates on them. If there is an exceptional downs. End of life can also be monitored event that deposits a great deal of pollution via direct leakage current measurements at one time, cleaning may be advisable since and indirectly via thermal imaging, best hydrophobicitycouldtemporarilybereduced taken during periods of light surface wetor even lost. High pressure washing, howting. Since the goal of the coating is to limit ever, should always be avoided as this can leakage current, indirect thermal imaging damage the coating. Obviously, if RTV coated gives an indication of the presence of surporcelain needed cleaning anywhere near face currents. as frequently as uncoated insulators, there would be much less logic in using them. Monitoring end of life of RTV coatings on overhead line insulators is more challenging. What are the signs of end of life? Removing sample insulators at random from Visual inspection alone may provide obvious different sections of line will provide useful clues as to the condition of the coating, Good hydrophobicity of contaminated especially is there is clear evidence of large information on residual hydrophobicity. ď ¸ RTV coated porcelain. portions flaking off.

These RTV coatings in Canada have completely blackened over time yet still perform.

This coating application appears less than ideal, as some areas of the porcelain are left uncovered.

Condition of this coating in China suggests it is reaching end of useful life.

UTILITY PRACTICE & EXPERIENCE

Networkon Jeju Island SupportsTesting of Power Technologies

Jeju Island, with its balmy weather and picturesque landscape, is the perfect place for Koreans to escape the daily rigors of life in crowded cities such as Seoul, especially during the cold winter months. However, to engineers at Korea Electric Power Corporation (KEPCO), the island has served an entirely different purpose – as a location to assist development and evaluation of power technologies in a relatively controlled environment. For example, in June 2009 Jeju Island was selected for one of the world’s first large-scale smart grid demonstration projects aimed at allowing various technologies in this field to be tested. Similarly, it was chosen as a place to evaluate advanced off-grid energy storage systems based on combinations of renewable energy sources and diesel power generators.

Photos:INMR©

Not so well known yet no less important is the fact that Jeju Island is now also site of an interesting project that involves a hybrid transmission line along with planned phased-in trial installations of superconducting ± 80 kV and 154 kV cables. INMR travels there to report on this as well as other recent projects that connect the circa 1900 sq km island with the Korean peninsula.

Photos:INMR©

± 80 kV hybrid DC line connects through cable and harmonic filters to one of two new HVDC Smart Center converter stations on Jeju Island.

With the potential of carrying great amounts of power along relatively small pathways, superconducting cables offer a promising alternative to conventional overhead lines.

n the face of steadily rising demand for electricity combined with a history of public opposition to new overhead lines, alternative transmission technologies are looked upon with great interest in South Korea. For example, with their potential of carrying great amounts of power along relatively small

pathways, superconducting cables have offered a promising alternative to conventional lines in certain applications. Indeed, following the successful commissioning and testing of such a 22.9 kV superconductor installation near Seoul, KEPCO engineers have begun implementing a three-stage program

that will soon see testing of ± 80 kV and 154 kV superconducting cables on Jeju Island. According to Sr. Manager of Transmission Operation & Maintenance, Hyunmin Park, KEPCO’s interest in superconducting cables goes beyond their being an

The vast majority of KEPCO’s transmission network relies on porcelain cap & pin strings and, in spite of maritime contamination on Jeju Island that requires live washing on an annual basis, these were selected for both AC and DC circuits of the hybrid line as well.

alternative to overhead transmission. Another key factor, he points out, is eliminating the 3 to 5% losses typically encountered on overhead lines at voltages such as 154 kV. Says Park, “unlike the case with ordinary conductors, superconducting cables offer no resistance and that translates into no power losses.” Such cables, he goes on note, while expensive due to the need to maintain internal temperatures of -273°C, can carry as much as 5 GW of power through a pipe having a

Tension tower on hybrid line from HaiLim to GeumAk. (below).

Photos:INMR©

GIS system at GeumAk Converter Station (left).

Photos:INMR©

Application of EGLAs on Jeju Island.

Hee Gwon Kim, Sr. Manager of the Transmission & Substation Team on Jeju Island explains that the program to evaluate superconducting cable will consist of three separate phases. The first has already been in operation for just over a year and involves a hybrid line carrying circuits of 154 kV and ± 80 kV DC on the same towers.

One of two recent failures of 765 kV composite insulators in Korea.

The underhung DC line transfers 30 MW per circuit and runs some 5 kilometers between two converter stations – GeumAk and HaiLim – both specially designed to allow testing of different equipment as well as locally-developed thyristor technology. For example, the two stations are equipped with sets of 17 MVAR double tuned (DTF) and

Photos courtesy KEPCO

diameter of only about 1 meter. This helps make them more costcompetitive while also capable of being deployed using much less space. The ± 80 kV superconductor cable installation planned on Jeju Island will allow testing of this upgrade to the 22.9 kV system presently operating near Seoul.

high pass (HPF) filters on the AC side to limit harmonic distortion. Similarly, a special heat exchange system is in place to ensure effective heat dissipation from the thyristor valves, with fan speed controlled according to temperature of the cooling water. On the AC side, the station is connected to the double circuit 154 kV overhead line by 170 kV, 3000A, 60 Hz rated gas-insulated switchgear that supplies the AC power and also protects the converter transformer and AC filters in the event of faults. Says Kim, “there are basically three sequential steps in our program with the existing hybrid line expected to be modified in 2015 so that one section will consist of superconducting DC cable. Then, in 2017, the overhead DC line will be dismantled and the 154 kV AC line will connect to superconducting AC cable. That’s the project’s ‘final destination’.” Due to a large domestic electronics industry, South Korea has traditionally maintained one of the highest reliability levels in the world. In order to offer uniformly high reliability and power quality in a country with mostly mountainous terrain and some 300 to 400 lightning strikes to transmission lines each year, many overhead lines are equipped with surge arresters. This policy applies as well to the new hybrid line on Jeju Island, where all phases on one of the 154 kV circuits are outfitted with externally gapped line arresters (EGLAs).

Photos courtesy KEPCO

Park explains that the application of line arresters in this case was aimed at meeting the needs of large

External tracking and puncture holes observed along sheath in broken part of insulator. Internal tracking and puncture holes also visible along interfacial surface between rod and weathershed.

Due to a large domestic electronics industry, South Korea has traditionally maintained one of the highest reliability levels in the world.

customers on Jeju Island who are particularly sensitive to even slight voltage dips. He says that the first test of these arresters at 154 kV began some 4 years ago, with broad scale application starting in 2012. Up to now, several failures have been reported although their precise cause has yet to be identified, whether lightning strike or internal defect. “Normally a lightning surge should not destroy these arresters,” remarks Park, “so we have launched an investigation.” Another issue, although comparatively minor, has been cases of bird pecking of the silicone housings of these arresters, a problem that he states no one had anticipated at the time the program was launched.

Park (top left) and Kim examine sections of two generations of ± 250 kV HVDC cable systems from 1996 (left) and 2012 (above).

Park also notes that South Korea’s first installation of EGLAs at 345 kV took place last year and involved a line connecting to a nuclear power plant. Because the policy is that any fault will trigger an immediate shutdown of the facility, every tower of one circuit on this line has been outfitted with line arresters. The vast majority of KEPCO’s transmission network relies on porcelain cap & pin strings and, in spite of maritime contamination on Jeju Island that requires live washing on an annual basis, these were selected for both the AC and DC circuits of the hybrid line as well. According to Park, this decision reflects longstanding conservatism toward composite insulators, especially at the higher voltages. Indeed, he points out that the country’s first pilot project with composite insulators began only some 15 years ago and their application was finally expanded a full decade later, in 2010.

Photos: INMR ©

Schematics of laying of new cable and newer HVDC link to Jeju Island that uses the sea as return.

However, recent failures of 765 kV V-string composite insulators operating in the switchyard of a coastal thermal power plant have apparently served to rekindle past doubts. The failed insulators, from a supplier in Europe, were configured in a 90° angle and had a 400 kg weight attached below their connection point in order to reduce conductor vibration.

Control room at new converter station tracks every vessel that enters into a prescribed zone on either side of HVDC cable links to Jeju Island.

Park reports that the first incident occurred in 2010 and the second in 2012. Subsequent forensic investigation revealed that both failures involved flashunder discharges along the FRP rod resulting in mechanical separation due to fracture. They were later attributed to exposure of the core rod to moisture through punctures in the weathershed material. Park also notes that the root failure mechanism in each case was deemed

Views of DC field at Jeju Island Âą 250 kV converter station.

Photos: INMR ÂŠ

to be excessive E-field concentration resulting in high corona activity along the sheath near the live end fitting. This conclusion, he adds, was supported by the fact that there was no evidence of tracking at the insulators’ ground end.

Photos: INMR ©

Says Park, “continuous corona under wetting events such as fog can be due to inadequate grading ring or end fitting design with resulting excessive E-field on the insulator surface. This triggers accelerated ageing processes that in this case destroyed insulators that had been manufactured in 2004 and in service only since 2005. Control of corona through proper grading ring and end fitting design is the best way to prevent such failures, especially under the type of heavily contaminated service conditions that existed at the affected power plant.”

Views of ± 250 kV valve hall.

A serious incident occurred in 2006 when the anchor of a ship severely damaged the first HVDC link and blacked out the entire island from 24 to 154 minutes.

Apart from these recent high profile failures, another factor limiting growth in application of composite insulators on transmission lines in South Korea, according to Park, is that many lines pass through hilly terrain. This means a relatively high proportion of tension towers. KEPCO engineers are concerned that maintenance workers may damage composite insulators as they cross them to access the conductor. Power to Jeju Island is supplied by two undersea HVDC cables to the Korean peninsula. The first, originating in Haenam, was commissioned in 1996 and now operates at ± 180 kV while the

second, from Jindo, is rated for ± 250 kV and has been in service only since 2012. Park and Kim note that a serious incident occurred in 2006 when the anchor of a ship severely damaged the first HVDC link and blacked out the entire island from 24 to 154 minutes. The damage required lifting, cutting and joining the cable in a costly operation that lasted about 3 months. This experience has resulted in an on-line monitoring system whereby the control room at the island’s new converter station tracks all ship traffic on both sides of the cable links. Any ship that enters a defined ‘red zone’ is given

an immediate radio warning to leave if they remain longer than three minutes inside this narrow band. In spite of a general conservatism toward composite line insulators, the indoor DC field at Jeju Island’s new converter station for the ± 250 kV DC cable link utilizes silicone housed wall bushings, surge arresters, cable terminations and CTs. Yet another area where testing is now underway on Jeju Island involves the application of composite core ACCC conductors, which are now being used in the connection between the ± 80 KV DC line and the cable into the HVDC Smart Center. According to Park, KEPCO’s interest in this type of conductor relates to an incident where a passing ship snapped a lowhanging overhead ACSR conductor on the river in Seoul. Low sag ACCC conductors are seen as one means of avoiding future such accidents. Still, since many transmission lines pass through forested mountains, Park does not foresee broad use for such conductors due to their potential for failure in the event of fire. 

Photos: INMR ©

Test application of ACCC conductor on Jeju Island. 44

UTILITY PRACTICE & EXPERIENCE

400kVSupergrid with Modular HVDC System Interconnects Countries of Arabian Gulf

merican inventor and ardent DC advocate, Thomas Edison, seems destined to have the last laugh. Progress in power electronics and insulation design over recent years have finally helped DC achieve major gains against AC systems which, despite Edison’s efforts, came to dominate electrical transmission across the past century. Indeed, DC technology is more and more the preferred choice for large-scale power projects across the globe. For example, countries such as China, South Africa, Brazil and India, which need to move bulk power to load centers more than 1000 km away,havebeenbuildingorplanningHVDCand,mostrecently, UHV DC‘energy super-highways’, capable of transporting up to 15,000 MW a year. Similarly, HVDC systems are the ideal technology to link asynchronous networks. IntheMiddleEast,theGulfCooperationCouncilInterconnection Authority was established with the goal of bringing a modern Recognizing the need to cope with a steep increase in regional demand for electricity due to population growth as well as spiking construction development & the rapid industrialization activity, members of the Gulf Co-operation Council jointly undertook an ambitious power project under the aegis of a new organization, the Gulf Cooperation Council Interconnection Authority (GCCIA). Its mandate was to implement one of the most important of the various joint efforts among members by interconnecting formerly separate networks extending from Kuwait all the way south to Oman.

interconnection system to the countries of the Arabian Gulf and Gulf of Oman. For the past several years, it has been operating exactly such 400 kV supergrid with a back-to-back HVDC system as well as the Arab world’s first 1800 MW converter station. T&D specialist and INMR Contributor, Raouf Znaidi, travels to the GCCIA to report on the interconnection of the grids of six Gulf nations. He also looks at how the project has been designed to promote dynamic stability among the interconnectedsystemsduringsuddenlossesingeneration.

Fig. 1: ‘Energy highway’ links power systems of neighboring Gulf countries and includes HVDC converter station as well as control center.

Photos courtesy R. Znaidi

GCCIA CEO, Al-Mohaisen (center) and Director of Operations, Al-Shahrani, (left) discuss project with Znaidi.

CEO, Adnan Al-Mohaisen, looks back at the milestone Interconnection Project that was launched in 2006 and commissioned in early 2009. “Our primary objective,” he explains, “was not only to link the electrical networks of six Gulf

countries along double Circuits 1000 km long ‘energy highway’ but also to reduce the generation reserves required by each member. This was accomplished by enhancing a dynamic exchange of power in all cases of generation deficiencies."

“The primary objective was to link the electrical power networks of the Gulf along double circuits ‘energy highway’ and also to reduce the generation reserves needed by each member state.”

For example, Al-Mohaisen reports that, since the system’s initial phase of operation, more than 900 separate incidents have been recorded, ranging from single generator trippings to capacity losses of as much as 3000 MW. Yet all occurred with no serious impact on system security nor with consequent load shedding that adversely affected any of the interconnected systems. At the same time, he emphasizes that, for all these benefits, the project’s vision was not limited only to improving local network efficiency and performance. It was also intended to establish a platform for local electricity trading while at the same time allowing member states to remain up-to-date with the latest technologies in the HVDC field. Explains Al-Mohaisen, “apart from having transformed our interconnected countries into a single energy trading market, we see our future role will expand through ongoing connections with Egypt and from there, using existing North African connections, all the way to Europe. This will help make us a major player in the Middle

Tower filters at Al-Fadhili provide reactive power compensation for the converters and control of harmonic distortion on both 400 kV and 380 kV networks.

COO Al-Ebrahim. Interconnection helps reliability and lowers operating costs for all members.

Eastern electricity market overall.” Al-Mohaisen even foresees the day when the GCCIA can export surplus power to Europe during winter, when local demand is comparatively low, and vice versa during the Gulf’s peak summer months.

“This project,” adds Al-Ebrahim, “not only moved us toward a reliable system interconnection but has also allowed us to lower operating costs for everyone concerned. This was achieved by efficient sharing of reserves between members within what is now already a regionally integrated electricity marketplace. In the process, we were also able to provide members with more flexible solutions to deal with any unexpected losses in generation.”

The investment costs needed to design and build the interconnection were apparently helped by competitive conditions prevailing in the HVDC marketplace during 2005. This allowed the entire project to be delivered at about US$ 1.4 billion. Still, Chief Operating Officer, Ahmed Al-Ebrahim, emphasizes that project design was not based solely on costs

Al-Ebrahim goes on to explain that, unlike the case with most HVDC projects, the new Al-Fadhili Converter Station was designed to remain available in standby mode with its control system continuously monitoring the frequencies of the interconnected grids in order to automatically provide support during system disturbances. Upon detection

Photos courtesy R. Znaidi

"The new Al-Fadhili Converter Station was designed to remain available in standby mode with its control system continuously monitoring the frequencies of the interconnected grids in order to automatically provide support during system disturbances."

but equally on acquiring a state-ofthe-art systems including the HVDC that brought with it the latest in control functionalities and security systems. The end result, he says, has become one of the largest HVDC back-to-back systems in the world.

Table 1: Capacity of Interconnection by GCC Member Capacity (MW) Kuwait

1200

Saudi Arabia

1200

Bahrain

600

Qatar

1200

UAE

1400

Oman

400

Table 2: GCCIA Network by Member Double-Circuit 400 kV Km Lines Kuwait

62.7

Saudi Arabia

716.2

Bahrain

2 x (41 km 400 kV AC submarine cables)

Qatar

UAE

2.97

Oman 50

Fig. 2: Schematic of interconnection for each GCC member state.

Al-Fadhili Converter Station adjoins existing 380 kV substation belonging to Saudi Electricity Company.

of any change in frequency or sudden deficiency from loss of generation in one of the individual systems, the control blocks of 50 & 60 Hz, concept of dynamic reserve power sharing (DRPS) is automatically applied. This dynamic mode is one of the first facility under HVDC in the world. One or two poles, as required, are immediately unblocked to deal with whatever the power shortfall and restore stability to the interconnected systems. This DRPS program is implemented for automatic reserve sharing between 60 Hz and 50 Hz and based on network voltage and frequency control as well as rapid power reversal. Nasser Al-Shahrani, GCCIA’s Director of Operations & Control points out that a number of challenges had to be faced during the project’s planning and construction. Among these was how to most efficiently interconnect asynchronous systems operating mostly in a harsh environment of combined desert and

Table 3: Energy Exchanged Between GCC Members 2009 to 2013 (MWhs) 2009

2010

2011

2012

2013 as of Dec. 28

TotalEnergyExchanged

310,349

293,273

680,325

1,591,577

1,798,447

2000000 1500000 1000000 500000 0

2009

2010

2011

2012

2013

Fig 3: Growth in energy exchanged between GCC members from 2009 to 2013 (in MWhs). marine pollution. “On the one side”, he explains, “the Saudi Electricity Company (SEC) runs its transmission network at 380 kV/60 Hz while the other five power utilities use

400 kV/50 Hz. Based on this, an HVDC interconnection was really the logical choice, as foreseen back in 1982 when professors at King Fahd University of Petroleum & Minerals

GCCIA network and interconnections operate in challenging environment of combined desert and marine pollution.

Photos courtesy R. Znaidi

first proposed the idea of using HVDC lines to link Saudi Arabia with nearby Bahrain.” Ghunan Interconnector Control Centre In addition to the 1800 MW back-to-back HVDC Converter Station located in Al-Fadhili and the other 400 kV substations, a special interconnection control centre was established to the south, at Ghunan, to function as the main ‘nerve center’ of the interconnected network. Here, energy trading and distribution are continuously managed through central communications among all the individual network management systems. Al Shahrani explains that among the ongoing responsibilities of the GCCIA is continually seeking technical enhancements. “We are always examining different strategies and new solutions,” he says, “with the goal of optimizing network security while also enhancing reliability and

performance of the Converter Station and all linked interface stations.” For example, he points out that, in order to enhance system security & performance, the GCCIA recently commissioned a fault recording and wide area monitoring system (WAMS) along with phasor measurement unit (PMU). According to Al-Shahrani, these new techs now provide added benefits to all members by monitoring transient and system disturbances while also performing pre and post fault analysis with realtime display of system parameters at all stations. “So far,” he concludes, “the GCCIA has met its annual targets in maintaining the readiness of the interconnection grid for supporting the member states power systems as well as in increasing its functionalities and system reliability, especially under emergency situations.” To support this assessment, he notes that 2013 witnessed the highest amount of energy exchanged among member

Table 4: Incidents Recorded/Year on Interconnected Network Total Incidents

300 250 200 150 100 50 0

2009

2010

2011

2012

213

179

280

2010

2011

Fig 4: Total incidents/year (2009 to 2012).

2012

states (i.e. a total of almost 1.8 million MWHs). Moreover, a record 280 separate incidents were successfully handled during 2012, avoiding partial or total blackouts on the interconnected networks. Al Fadhili HVDC Converter Station The Al-Fadhili Converter Station is located some 100 km northwest of Dammam in Saudi Arabia and directly adjoins an existing 380 kV substation belonging to the Saudi Electricity Company. Substation Section Head, Abdulla Hasan, and Mike Topping, Head of the HVDC Station, explain that this facility was designed not only to allow for the key connection between the GCCIA’s 400 kV/50 Hz network and the SEC’s 380 kV/60 Hz system but also to offer unique features that would permit dynamic reserve power sharing among all systems in the Arabian Gulf. “Based on this,” says Topping, “our 1800 MW back-to-back station was configured as three separate poles with a nominal rating of 600 MW each and such that up to 1200 MW of active power could readily be transferred between any member.” All three poles were built at the same location and constructed simultaneously, although each can operate independently or in coordinated mode. Full operational control is also available from the main interconnection control center located at Ghunnan. Topping goes on to state that each converter pole is comprised of a valve hall, two 380 kV/97 kV, 60 Hz, 385 MVA converter transformers and two 400 kV/96 kV, 50 HZ, 380 MVA converter transformers – all connected to nearby GIS 53

Bushings on converter transformer as well as all arresters and insulators at Al-Fadhili use porcelain with RTV silicone coatings. substations using XLPE cable as well as 380 kV and 400 kV circuit breakers. “In addition to their main functions,” notes Topping, “the converter transformers also provide galvanic isolation between the AC and DC systems and limit fault currents through the water-cooled thyristor valves. In this regard, the HVDC interconnection functions much like a ‘firewall’ since faults cannot propagate either in the HVDC network or in any of the interconnected AC networks.” As for the valve halls, Topping explains that the rectifier and inverter valves are of suspended design and mounted in special temperature-controlled structures. Given the sensitive nature of the electronics inside and the unusually hot ambient temperatures, combined with the sand storms typical of eastern Saudi Arabia, one challenge for 54

project designers and contractors was assuring high air quality, especially for the thyristor valves.

Given the sensitive nature of electronic components inside and the unusually hot ambient temperatures combined with frequent sand storms, one of the key challenges for project designers and contractors was assuring high air quality, especially for the thyristor valves.

Transformers at converter pole station in Al-Fadhili.

Photos courtesy R. Znaidi

Fig. 5: Schematic overview of Al-Fadhili HVDC Converter Station scheme, comprising three separate 600 MW poles.

The solution involved installing the valve hall air conditioning in a closed circuit, with all ‘top-up’ air filtered before use. Moreover, air pressure inside is always kept slightly positive to prevent ingress of sand or other contaminants. The valves themselves are liquid cooled with de-ionized water and there is parallel cooling for the thyristors to ensure temperatures always remain less than 18°C. Indeed, because of ambient temperatures of as high as 55°C and the scarcity of fresh water, engineers working for the French-based HVDC contractor point out that the cooling equipment for the facility covers the roof of each converter hall and is probably the largest ever installed at such a facility.

GIS station at each converter pole.

Photos courtesy R. Znaidi

Cooling system for valve halls at Al-Fadhili and back-up batteries for protection and control of each pole.

Auxiliary power supplies for the installation are provided from a pair of 34.5 kV/60 Hz lines operated by the Saudi Electricity Company. These feed in via a medium voltage distribution board, with duplicate 34.5 kV/380V transformers at each of the poles. In the event of loss of both, each pole is equipped with a standby diesel generator that can maintain full power transfer capacity. An array of 110 V DC batteries, each with duplicate charger, is provided at each pole for protection and control. External Insulation & Maintenance Given the service environment at Al-Fadhili, combining high UV and frequent sandstorms with heavy desert and marine pollution, GCCIA engineers have opted against use of composite insulators, deciding instead to employ only high-creepage, RTV-coated porcelain. This applies to all instrument transformers, surge arresters, cable terminations and circuit breakers installed at the siteâ&#x20AC;&#x2122;s three AC substations. Similarly, all bushings installed on the 12 converter transformers are also coated with RTV silicone material.

A solution based on RTV coated glass insulators was deemed to be superior in terms of insulation and pollution performance and also more practical for maintenance purposes.

All AC substations at Al-Fadhili feature only RTV coated porcelain insulators.

As for maintenance, there is an annual program that includes dead washing all substations along with removal of sand accumulating near and around filters, breakers and transformers. A regular ground inspection is also scheduled and undertaken by a team of external contractors. According to local staff, apart from audible corona noise, especially on early summer evenings when relative humidity levels climb to 70 percent, the combination of coatings and regular washing have been performing well. 57

Double strings of RTV coated glass discs used on GCCIA’s backbone lines. Photos courtesy R. Znaidi

Table 6: Technical Parameters of Coated Glass Insulators String Orientation

Suspension

Tension

Mechanicalstrength

120 kN

222 kN

Shell diameter

280 mm

320 mm

Creepagedistance

490 mm

560 mm

Spacing

146 mm

175 mm

Insulatorsperstring

Table 7: Outages on GCCIA 400 kV Double Circuit System Year

No. of Outages

Causes

Action Taken

2009

Sub-conductor fell down due total cut strands in Kuwait, Saudi Arabia and Qatar.

Repair the subconductors and improve the conductorvibration damping system.

2010

None Improvethebonding of shield wires to towers found with loose connections (24 locations).

2011

Transient fault of unknown cause. Bad weather near Dammam Airport accompanied with lightning and thunderstorm.

2012

Transient fault of unknowncause.Bad weathernearSalwa.

2013

None

Insulation on incoming and outgoing 400 kV overhead lines into Al-Fadhili has also been designed for the region’s harsh desert environment. Carlito Carrascal, a lines and cable engineer at the site, explains that the insulators used on the system’s ‘backbone’ are also coated with RTV silicone and consist of double strings of 43 glass 120 kN discs for suspension towers and 37 glass 222 kN discs for tension towers. According to IEC 60815, these correspond to a unified specific creepage distance of as high as 87 mm for the suspension insulators. Alaa Rahma, Head of Protection, Control & Telecommunications emphasizes that a solution based on RTV coated glass insulators was deemed superior in terms of insulation and pollution performance and also more practical for inspection and maintenance. So far, there have reportedly been no unplanned outages linked to flashovers on any external insulation or otherwise linked to pollution. In fact, according to Rahma, there have been less than a handful of outages on GCCIA/s lines since 2009, most due to cut strands on sub-conductors. There have also been two weather related transient faults. (see Table 7). Says Rahma, “the performance of insulation on our lines so far seems to have validated going with coated glass as well as over-insulated

suspension and tension strings. This decision is also expected to significantly reduce operating and maintenance costs since there will be no need for maintenance unless absolutely necessary nor are there any plans for live washing on any of the GCCIA’s double circuit 400 kV lines.” The GCCIA’s decision to rely only on over-insulated RTV-coated glass strings for its 400 kV interconnection is not necessarily the insulation philosophy applied by each member on their own overhead networks. For example, many if not most of the 69 kV, 230 kV and 380 kV lines belonging to the SEC and crossing the same service environment of barren land and sand dunes are equipped with composite insulators. 

Table 8: Routine Maintenance on GCCIA Network Activity

Frequency

Ground inspection

Every3monthsforthecompletestructures

Nighttime ground inspection

Once a year

Climbinginspection,includingRTV coating inspection, checking for Onceevery2yearsforcompletestructures contaminationbuildup,corrosionon hardware, etc.

Thermalscanningofconnectorsand Once a year mechanical joints

Preventive maintenance

Duringheaviesttypicaloutageperiod(usually from October to March)

Corrective maintenance

As need arises

Photos courtesy R. Znaidi

Lines at Saudi Electricity Company insulated with silicone composite insulators. 59

UTILITY PRACTICE & EXPERIENCE

New 500 kV Line Allows U.S. Utility to Compare Performance of Alternative Insulators & Hardware

Photos:INMR©

alt River Project, based in Phoenix, Arizona, was among the world’s first utilities to employ composite insulators along the entire route of a major transmission line. Insulation on this line – the 500 kV Mead-Phoenix Project, commissioned in the early 1990s – was designed so that, if necessary, it could one day be converted easily to HVDC for greater power transfer (although this has not yet happened). Silicone composite type insulators were selected at the time since they offered the most economical acquisition cost in relation to equivalent DC versions of glass or porcelain strings. Notwithstanding this long experience with composite insulators, SRP has recently decided in favor of using only glass and porcelain insulators for its latest transmission project – the 150 mile 500 kV Palo Verde-Browning Line. INMR visits the construction site near Phoenix to meet with SRP staff involved in this decision. 63

Photos:INMR©

With expanding need for electricity in several counties surrounding the city of Phoenix, Salt River Project (SRP) has strengthened its network by adding an important new 500/230 kV transmission line serving its key Browning Substation.

Planned to be energized in May, the final section of this mainly double circuit line will allow power to be transmitted here from the Palo Verde Hub – a wholesale electricity market serving Arizona and southern California – and will finally complete a loop that has involved sequential stages and nearly a decade of

public hearings and construction. For example, the eastern portion of this line, running between Browning and Dinosaur Substations, was completed six years ago. Although the new line bears striking similarities to other 500/230 kV lines in the region surrounding Phoenix, there are some important differences. One of these lies in the type of insulators selected. Unlike many other local lines that employ composite insulators, the new line is being equipped with only glass and porcelain strings. According to Michael Voda, Project Engineer for the Palo VerdeBrowning Line, the single major factor influencing selection of insulators for the new line was comparative ease when it comes to live-line working. “We do live line maintenance on most of our 500 kV lines,” says Voda, “so we decided to limit ourselves in this case to glass and porcelain. We consider the two basically equivalent but are not yet comfortable with polymeric insulators for this requirement.”

Voda and Sr. Project Manager for Transmission, Dan Hawkins, explain that the new line was seen as an opportunity to compare the long-term behavior of equivalent insulators and other line accessories. Says Voda, “we purposely mixed up the insulators on this new line and also the supports and dampers so that we could start to accumulate comparative experience with them under the same operating conditions.” One of the biggest challenges for SRP they say relates to replacing components on old lines that have been in operation for at least 30 years. The new line will therefore allow them to evaluate different

“We do live line maintenance on 500 kV so we have chosen to limit ourselves to glass and porcelain. We consider the two basically equivalent in this regard but are not yet comfortable with polymeric insulators for this application.” 66

Photos:INMR©

Other 500/230 kV lines near Phoenix employ composite insulators.

To illustrate, Voda points to the 500 kV Palo Verde-Rudd Line, which was built about 10 years ago by Arizona Public Service but is now operated by SRP. This line is equipped with polymeric insulators and, while he says that there have not yet been any reported problems, current work practices require that any change-out of an insulator on this line must wait for a scheduled outage. Another difference of the new project lies in the line hardware selected For example, 50 miles (80 km) of the line route will see use of rods and clamps while there will be 100 miles (160 km) using armor grip suspension assemblies.

materials within the scope of the same project but without taking on any new risks or overspending on construction and testing. Sr. Principal Engineer, James Hunt, notes that, apart from the opportunity to assess how glass and porcelain insulators will behave in the desert environment around Phoenix, SRP is now focusing on long life expectancy of every line component, sometimes on the order of even 80 to 100 years. “Expecting such a service life,” he remarks, “is not unreasonable in our type of dry, non-corrosive climate.” To illustrate, he points to certain lattice towers in the area, built as long ago as 1924

“We purposely mixed up the insulators on this new line and also supports and dampers so that we could get comparative experience with them under the same operating conditions.”

but that are only now starting to be selectively replaced. Adds Voda, “if you have a choice between two equivalent technologies with about the same construction costs, why not go with the alternative that lasts longer. It’s as simple as that.” He goes on to state that one of his concerns when it comes to polymeric insulators made of organic materials is how these might degrade over the decades under high UV and also under threat of pecking by local birdlife. Indeed, he points to how persistent UV has negatively impacted paint on some tubular structures, which have a shown a tendency to chalk in the Phoenix desert-like climate. Hunt emphasizes that reliability is regarded as having a premium and, with this in mind, glass or porcelain strings are both regarded as especially good choices. “All this,” he says, “is driven by the fact that it is increasingly difficult for us to schedule an outage for

Hunt with range of support rods and inserts awaiting installation.

Photos:INMR©

Single circuit 500 kV lattice suspension towers near Phoenix are typical of Palo Verde-Browning Line and employ porcelain cap & pin strings. 67

Photos:INMR©

Conductor stringing of tubular angle towers on 500/230 kV Pinal Central to Pinal West section of line.

maintenance.” Another factor, he notes is ease of inspection when it comes to glass, which typically involves nothing more than a helicopter flyby to search for any failed units. Most of the new Palo Verde to Browning Line consists of tubular steel poles, including a mix of single-circuit 500 kV and double-circuit 500/230 kV structures. According to Hunt, these types of structures are commonly used for lines passing through urban and suburban areas and are part of the requirements of obtaining public approvals, which he says in this case proved an especially long and arduous process. Another issue, he says, when it came to obtaining the required Certificate of Environmental Compatibility involved use of de-glared (also known as non-specular) conductor. “In our type of environment,” he points out, “getting the conductor to take on a dull appearance would normally take 2 to 3 years.” 68

Glass strings await hoisting onto tower. for polymeric insulators are not great and together probably do not offset the construction advantages of glass, which he mentions include easier handling.

Photos:INMR©

On the work site of the project completing connection of the Palo Verde Hub with Browning, SRP’s Supervisor of Construction Inspection, Jim Green, compares polymeric insulators with the toughened glass, already installed on some poles in that line section. “One factor favoring polymers,” he remarks, “is that, unlike strings of glass discs, these do not need to be stretched.” He estimates that some 50-75 percent more time is needed to complete this operation for glass compared to polymeric insulators.

Another factor is weight. For example, he notes that a typical string of glass insulators can weigh between 800 and 900 lbs (ca. 400 kg), meaning a heavy hoist is required. In the case of polymeric insulators, he states, lighter duty equipment would probably suffice. Still, on balance, he claims that the cost savings in time and equipment

Says Green, “I see risk of mishandling as one of the downsides of polymeric insulators since this can lead to permanent damage. Also, my experience is that glass can also be handled rougher than porcelain. In fact, we have had no issues with broken glass insulators in over 100 miles of towers that I inspected. Moreover, based on my experience, when it comes to maintenance, I prefer to work with glass.” 

Stringing of overhead ground wire and installation of special structures to protect passing highway.

UTILITY PRACTICE & EXPERIENCE

PracticalApplicationsof AutomaticImageAnalysis ofOverheadPowerLines

Power supply, sensor and communications arrangement at WAP test station.

orwegian transmission system operator, Statnett, has a network comprising more

than 10,000 km of overhead lines operating at from 132 kV to 420 kV. For several years now, this TSO has conducted research at a special WAP test facility located near Oslo, where different insulator options, a weather station and special monitoring equipment have been installed, including web cameras and ice load monitors. Recently, the test station has also been used to collect information about the comparative ‘visibility’ of different insulators since this has become an increasingly important parameter in overhead line design in Norway and indeed across Europe.

The main reason for setting up the WAP test station in 2004 was to verify results obtained in the laboratory and to gain field experience in regard to: • Snow and ice coverage on three different insulator types/profiles under various weather conditions; • Swing angles of these insulators, mainly under precipitation or wind; and, • Estimated number and severity of different weather events. Environmental conditions, including temperature, precipitation, ice load and wind speed, were therefore all constantly monitored. In addition, images of the insulators under different weather conditions were taken by web cameras at intervals of every 10 minutes. From these, swing angles, ice coverage and visibility were estimated using newly developed automatic image analysis techniques. Moreover, all these measurements, images and results were

This article, contributed by Sonja Berlijn of Statnett, Igor Gutman of STRI and Irene Gu of the Chalmers University of Technology in Gothenburg, presents novel applications of automatic analysis used in high voltage engineering. These include detecting and measuring snow/ice coverage on insulators, estimating insulator swing angles and computing objective values of how different insulator strings stand out against specific backgrounds. Fig. 1: Example of user interface of WAP website. 72

Fig. 2: Extraction of region of interest (ROI) from each captured image.

(a) Images of 3 different insulators studied

made available to Statnett enigneers in a highly interactive and easy to understand way via a website. Originally, three insulator configurations were selected for analysis: 1. a composite insulator with alternating shed profile, 2. a glass insulator string combining standard and aerodynamic profiles, 3. a string of anti-fog profile glass insulators. Since images of these different insulators were taken over a period of more than 8 years, the huge volume of data required automating the process of determining swing angles as well as levels of ice and snow coverage. Automated Detection of Ice & Snow Coverage In order to automatically estimate the amount of snow and ice coverage, the

(b) Example of extraction of ROI

first step was to locate the insulator in each captured image. The small portion containing the insulator and termed ‘region of interest’ or ROI was therefore extracted from each image. Extracting ROI was not easy since both the position of the insulator in the image and the background change under different weather and lighting conditions. However, a methodology was developed whose details were published in an IEEE paper in 2007. This methodology resulted in an 88.5% success rate in terms of being able to extract ROIs from 3-months’ worth of images collected. Once the ROI was successfully extracted, detecting the snow and ice and analyzing extent of coverage was performed. The insulator is rigid and its size and outer boundaries are fixed and known. This means that any change in profile due to coverage by snow or ice would result in the appearance of additional

edges, usually on the top surface. To determine the snow (or ice) regions from images, the following steps were performed: (a) Detecting extra regions: An edge detector was applied to each ROI image such that each enclosed area surrounded by edge curves formed a region for further evaluation. (b) Finding extra regions above the shells: Snow or ice on insulator shells and other changes such as in background (e.g. local clouds, illuminations and reflections) could all generate new extra regions. Using the existing and saved information of standard disc positions and the ‘ellipse’ shell shape regions as reference, these extra regions were found and subjected to further analysis. Since snow and ice are more likely to accumulate on the top and/or side of insulator discs, only extra regions related to these locations were considered and analyzed.

Fig. 3: Different images of insulators captured by outdoor camera (only areas containing insulator are shown). From left to right: (1) ideal image with sunny clear sky; (2) insulator with reflections from sunlight; (3-5) cloudy where clouds form a non-uniform and fastchanging background; (6-7) blurred images from foggy conditions; (8-10) dark and night images; (11) snow on upper surface; (12) iced insulator (in a laboratory).

Fig. 4: Analysis of snow/ice coverage.

(a) appearance-based analysis

(c) Appearance-based and shape-based analysis: Once all (extra) regions were found, appearance-based and shape-based analysis were applied to determine the snow and ice area (see Fig. 4). After the extra regions were determined, a narrowwidth vertical bar (see red bar in Fig. 5 parallel to the vertical axis of insulator to right,) was placed and swept from the left to the right side of the insulator. This way, the heights of detected snow regions would be identified and accumulated, resulting in evaluation of percentage snow coverage. The automated analysis method was implemented in MATLAB with a graphical user interface. The program has also been converted to a C-program for on-line real time analysis, using images captured remotely. Testing and verification of the program was performed for data accumulated over 3 months (i.e. several thousand images) and results were estimated separately for high quality and low quality images (e.g. poor visibility, weak edges, dark snow in the image). In the case of high quality images, estimation was possible in about 90% of cases while, for poor quality images, the success rate for estimation was reduced to about 70%.

(b) shape-based analysis

Automatic Detection of Swing Angles The application of automatic image analysis in this case involved detection of swing angle, which could then be related to environmental parameters. Due to camera view angle, the angle of an insulator in a captured image may not always align with the image’s vertical axis. Swing angle in this case is therefore defined as the difference between the insulator’s absolute angle in any given image and its ‘reference’ angle from an image captured when there is no wind. This process is shown schematically in Fig. 6. Information on swing angles is collected and stored together with meteorological data to allow subsequent analysis. Automated Evaluation of Insulator ‘Visibility’ At the start of the project, only glass cap & pin and long rod silicone composite insulators were compared in terms of relative visibility, with the less visible option being preferred from the perspective of having less environmental impact. Later, a number of glass cap & pin insulators having different colored RTV coatings were also installed. These later test objects became of interest in terms of future use by Statnett on so-called ‘camouflaged’ lines. This was used for fine-tuning and verification of the automated visibility program. The following steps were performed to develop a program for automated image analysis of comparative visibility: 1. Finding region of interest (ROI) containing tower of interest and three pairs of FG (foreground) and small neighborhood BG (background) areas for the three insulators string options.

Fig. 5: Graphical user interface for the automatic image analysis system that detects and estimates snow/ice coverage on an insulator. 74

2. Using image analysis to compare the FG and BG image areas of each insulator (keeping in mind that the backgrounds for three insulators in measured images are different). This was based on an objective criterion that took into account intensity difference,

contrast difference and sub-band structural difference between FG insulator image and its neighboring BG image.

Fig. 6: Left: Computing swing angle for ROI through cross correlation. Right: drawing outer parallel lines and central line from outer shell boundaries.

Insulators of primary interest for comparative visibility study: olive green RTV, grey RTV and glass.

Example of image where comparative ‘visibility’ of insulators is evaluated. (From left): olive green RTV, grey RTV, uncoated glass.

3. Creating and testing a MATLAB program using more than 100 images taken under different weather conditions and comparing results with subjective findings obtained from human observers. The findings from analysis of the three alternative insulators (each embedded in its own specific background i.e. sky, sky plus trees, and trees), is shown in Fig. 7. Insulator 1 (ins-1) is an olive green RTV coated; insulator 2 (ins-2) is grey RTV coated, and insulator 3 (ins-3) is a green glass insulator. A maximum value of 1.0 indicates least visible insulator (i.e. most similar between the FG and BG), while 0.0 indicates most visible insulator (i.e. least similar between FG and BG). Results were presented here simply to demonstrate that the program can differentiate between the various insulators in their specific background and also that relative visibility values depend on both insulator material, given background and lighting conditions. For example, the three insulators in this case were embedded in very different backgrounds. Based on these images, it can be seen that visibility values obtained based on the objective criterion for insulators against their given backgrounds were consistent with visual perceptions by human observers. For example, the green RTV-coated insulator (ins-1) was judged rather visible against a light sky background while the grey RTV coated insulator (ins-2) placed against a BG containing dark trees and light sky was ‘medium’ visible. It is important to note that final comparison of the relative visibilities of these different insulators options could not be finalized in this case since the insulators did not share the same background in the measured images. Comparisons should ideally be made only when different insulators are embedded against the same background and under the same lighting. Further development of this program can make it possible to extract any insulator or other line component from one original background and to embed it against another background. Also use of color data (i.e. not the grey-scale used in this project) would be desirable for future development. Reflections from sunlight would also have to be taken into account because they can change the relative ‘visibility’ of glass insulators. 

Illustration of steps in insulator visibility analysis from images. From top to bottom: (a) extract ROI (i.e. tower area); (b) estimate vertical axes of insulators (blue/red vertical lines: estimated/ground truth) and estimated connecting point of insulator to the tower (yellow +); (c) estimated FG/BG (red/green box) regions. Automatically estimate visibility values for three insulators shown in bottom line, where V: final visibility, L: luminance difference, C: contrast difference, S: subband structure difference. The larger the value (largest 1.0), the less visible an insulator is compared with its background

Fig. 7: Results of automatic insulator visibility analysis from about 100 images. 75

INSULATORS

German Supplier Looks to Serve Expanding Market for Hollow Composite Insulators 76

ased on data recently developed by INMR Columnist and HV industry expert, Alberto Pigini, the demand for hollow core composite insulators – long mired below industry expectations – finally appears set on a path of exponential growth. Part of the reason for this is growing awareness of the benefits of this technology among end users at power utilities. But another decisive influence is the greatly expanded supplier base, which now includes large-scale production sites both in Europe and in China.

millions

1.5

HV AC COMPOSITE HOUSINGS

1 0.5 0 1985

1990

1995

2000

2005

2010

2015

Installed base of hollow composite insulators: 1985 to 2010

One of these is based in Regensburg, a picturesque Baroque town located in southern Germany and also home to Maschinenfabrik Reinhausen (MR) – one of the world leaders in tap changers with nearly 2900 employees and annual sales of over US$ 800 million. Indeed, composite insulator manufacturer, Reinhausen Power Composites (RPC), originated in 2009 as a spinoff from this industrial giant. INMR visits RPC to report on how production has changed at this business unit since our first visit five years ago.

Recognizing that a growing market was developing for these products, the decision to offer insulators was made in 2006 and, within only four years, some 10,000 pieces had been produced. Output has since grown to between 15,000 and 20,000 units each year and Hauck reports that, by 2012, a total of about 50,000 insulators had already been supplied to customers across the globe. Sales Director, Georg Schütz, explains that the most challenging element in mastering the production technology behind hollow composite Initial step in tube production sees protective polyester layer against SF6 by-products wound onto plated steel mandrels with highly smooth surfaces.

One of the measures of the buoyant growth of insulator production at RPC is that 2013 marked the first year that sales of insulators outpaced those of tubes. insulators involves the tube, which he claims is the ‘heart’ of such an insulator. “While we originally focused on finding outside markets for these,” he says, “it turned out to be the right decision to launch

our own line of insulators since we regard ourselves as one of the premier producers of tubes – both electrically and mechanically.” Production of FRP tubes involves the classical wet filament winding process whereby electrical grade glass fibers pass through a resin bath before being wound onto polished steel mandrels in precisely defined winding angles. Based on these angles and the thickness of winding, a tube can be designed to meet virtually any end user specification in regard to inner pressure as well as bending and torsional loads. RPC’s tubes are offered with typical inside diameters that vary from 28 mm to 1 m. Walking through the production area for tubes, Schütz notes that a new winding machine was recently installed and is directly linked with an adjacent heating chamber where the wound tube undergoes its usual cure cycle. This, he says, was done to allow for a more efficient process

Photos:INMR©

According to Managing Director Jürgen Hauck, the main driver behind RPC’s entry into the insulator business was the firm’s expertise producing FRP tubes that dates back 30 years. These were originally used mainly in tap changer production and in special medical applications but also sold externally to manufacturers of hollow core composite insulators.

Each tube produced is assigned unique code and tracked through production for traceability of raw materials and machine on which it was manufactured.

of this business. Other sectors, however, such as live tank breakers in Europe, lag this trend and still feature the inverse ratio.

Photos:INMR©

One of the recent changes at the plant has been installation of centralized resin processing that now supplies all the various tube-winding machines from a single source. In the past, resin preparation was done individually at each machine but now the process of mixing and de-airing of the epoxy materials is performed automatically and more conveniently at one location. since less handling is required between winding and curing. Two different resin systems are used depending on user specification of the glass transition requirement of the application (i.e. the temperature at which the tube will start to lose its mechanical integrity as a result of heating). Two Tg values are currently offered – 128°C and 156°C. Higher Tg values permit increasing current through the insulator, e.g. from 3000 to 4000A, as dictated by some specialized insulator requirements, such as at wind farms.

Schütz and sales colleague, Mathias Reichenbach state that composite type hollow insulators are gaining steadily in use and estimate that they have now attained an overall market share of between 12 and 15 percent against just over 85 percent for porcelain – once the exclusive material for all hollow HV insulator applications. Indeed, they point out that certain market segments, such as bushings for dead tank breakers in the U.S., have undergone a rapid transition in insulator technology and are now dominated by composite types to the tune of some 80 percent

Schütz explains that there is a need for suppliers to better educate end users on the benefits of composite insulator technology or else the decision on which technology to employ tends to be made solely on the basis of price. This, he notes, almost invariably favors the more economical porcelain, where production overcapacity and intense competition have recently combined to push prices even lower. For example, Hauck remarks that it used to be that 362 kV marked the point at which the acquisition costs of hollow composite insulators and porcelain were about equivalent. While the composite insulator industry has tried hard to lower this ‘cost equivalence voltage’ to 245 kV, recent price pressures on porcelain have worked the other way and, if anything, this voltage level is now moving closer to 500 kV. Given the perceived need for greater education, RPC has established a local academy to better inform users on key issues such as safety, which Schütz believes is still underrated but which he predicts will eventually become a key driver for conversion away from porcelain. 79

Different color of tubes identifies their Tg value.

Another advantage that needs to be promoted, notes Hauck, is the capability for a very fast delivery lead time, which in the case of a standard 500 kV composite insulator can be as little as three days, assuming the flanges are in stock.

All resin used to impregnate glass fibers during tube winding on different machines now originates from a centralized system that mixes and de-airs ingredients.

Photos:INMRÂŠ

Conicallyshaped tubes offer economies downstream in terms of less silicone rubber material and saving insulation media.

In recent years, RPC has introduced conical insulators and apparently these have already found a ready market among manufacturers of bushings for breakers. According to Reichenbach, conically-shaped tubes, while not offering that much reduction in tube materials or winding machine time, do offer economies in usage of less silicone rubber material. There are also savings in terms of smaller top flanges as well as up to 40 percent lower requirements for internal SF6 gas, which in some countries is now being taxed by volume. They also help increase phase-tophase distances, allowing for more compaction of equipment. Another recent development has been FRP flanges, where the typical aluminum flange of the insulator is replaced by one shaped directly from the tubeâ&#x20AC;&#x2122;s resin material. The main advantages here are no need for gluing while also increasing effective arcing distance and eliminating Foucault currents linked to high magnetic fields. Such non-metallic flanges typically offer 80 percent of the mechanical strength of an aluminum flange and are therefore more suitable for the top end, which experiences lower mechanical loads. A new line of post insulators, filled with SF6 or N2, has also recently

in a special bath after which they are heated and attached to the tube using a special shrink fit process. The tube is then subjected to a series of routine tests to measure bending and tightness as well as internal pressure performance.

Conical tube designs, FRP flanges and embedded optical fibers are among newest developments at RPC.

Photos:INMR©

Other recent product developments include post insulators, such as these supports for HVDC reactor.

been introduced for various HVDC applications. These feature internal sensors for easier monitoring of internal gas pressure and are available either in one or two pieces, depending on transport constraints. The goal, says Schütz, was to supply a light weight insulator ideally suited for seismic areas. Yet another innovation for RPC is integrated optical fibers, available either through the tube with maintenance free internal fillers or placed directly

between the tube and the overmolded silicone housing. Hollow composite insulators are manufactured in Regensburg in a process involving 16 different steps, from tube winding and curing through to cutting, turning and finally machining ends before flanges are glued on. This gluing operation is considered a key core technology and very sensitive. Essentially, the flanges are cleaned ultrasonically

Cutting tubes performed using diamond-tipped saws.

Schütz emphasizes the importance of testing by pointing out that each year over 10,000 individual tests are performed on tubes and their components. For example, samples of tube material recovered after cutting are subjected to flashover tests in oil from 75 kV to 150 kV. The goal is to check for any problems with the fibers or the impregnation process. “These tests 81

Tubes with assembled flanges are ready for final stages of manufacture. Tests on tube material ensure no problem in fibers or impregnation process.

yield a curve,” says Schütz, “and allow us to make sure nothing is going on in production that we are not aware of.”

The resulting small partial discharge activity may not cause immediate failure, but over 10 or 15 years of service can eventually erode through and reduce lifetime of the insulator. That is why we always have to focus on achieving a perfect bond and even better than that specified in the standards.”

The tubes with flanges attached are then transferred to the final production steps, which take place in an adjacent hall and begin with application of a chemical primer in one of two special chambers. This is done to ensure maximum bonding between the liquid silicone rubber housing and the tube.

Molding of the liquid silicone rubber (LSR) housing is done in a series of injection shots onto the primered tube. The partially molded tube is then ready for another application of primer before each successive shot. Schütz explains that this production area has been designed to permit handling of even very long tubes

Says Schütz, “most users are familiar with the concept of hydrophobicity of sheds but do not know that silicone rubber also permits water vapor to diffuse through the material. If there is not a perfect bond of the silicone to the tube, moisture can become trapped beneath the housing and condense.

Photos:INMR©

Tubes are primered in a chamber before undergoing molding in a sequence of injection shots in adjoining clamping machines.

and also to allow for easy expansion as production volumes grow in the future. Three of the five clamping units are monitored by two workers and devoted exclusively to high volume

items such as 145 kV bushings for dead tank breakers, 72 kV transformer bushings and 170 kV cable terminations. The remaining two machines are then used mostly for higher voltage units, typically produced in smaller quantities. Each insulator is then given a marking which provides all the information about its manufacturing history, including specific machine on which it was molded, name of the worker, batch number of the LSR and primer and even ambient humidity in the production area. Experts in composite insulators sometimes debate over the relative merits of LSR material versus the alternative more viscous and less costly HTV silicone rubber. Schütz and Reichenbach claim that users typically show no consistent preference for one material over the other but they take the view that, since LSR has higher silicone rubber content, this will mean faster recovery in cases where hydrophobicity is temporarily lost.

Testing performed on FRP samples with sprayed on primer to measure resulting bond strength with silicone housing material.

Photos:INMR©

Looking to the future, Managing Director Hauck strikes an optimistic tone. He points to recent sales growth to customers outside of MR and notes that 2013 marked the first year that sales of insulators actually outpaced those of tubes. To meet this trend, he says that present insulator capacity can easily be ramped up by 30 percent in the existing facilities and, once required, virtually double if the molding hall building is expanded modularly as per its original design concept. Says Hauck, “we have developed our own production system whereby the entire process – from design to manufacturing to shipping – is all under our control. Now, the goal is to continue to put out our message of German quality which we see as another of our unique selling points.” 

Final inspection and cleaning of finished insulator is last step before packing and shipping.

INSULATORS

NewFactoryfor CompositeInsulators OpensinEstonia

The medieval Old Town in Estonia’s capital, Tallinn, is designated a UNESCO World Heritage Site.

stonia is small geographically but with a history that dates back to before the Bronze Age. Sandwiched between Finland to the north and Eastern Europe to the south, it has just over a million inhabitants, most engaged in the services sector – probably not the type of place where one might expect to find a new factory devoted to produc-

ing the latest generation of composite insulators. Yet since this past November, tiny Estonia has joined the select ranks of countries that have an internationally focused domestic insulator industry.

Tallinn features participation by investors from within Russia, including the Global Insulator Group and Yuzhnouralsky Insulators and Fittings.

INMR was invited to attend the new Estonia has styled itself as a gateway plant’s official opening in late November between East and West and indeed the of last year and reports on its facilities GIG Polymer plant in the capital city of and product range.

hile new to the field, GIG Polymer has set out an ambitious product program that it hopes will give it rapid access to most sectors within the worldwide insulator market. For example, it is one of only few suppliers in the industry that have chosen to offer both liquid silicone rubber (LSR) and high temperature vulcanized (HTV) rubber materials as housings – each specialized to serve different insulator applications.

Photos:INMR©

GIG Polymer plant will use both composite insulator material technologies, LSR and HTV, with correspondingly different product profiles and molding equipment. 85

The LSR range will concentrate mainly on items such as suspension insulators from 220 kV to 765 kV, interphase spacers, DC line insulators and both post and other substation apparatus insulators. The HTV product range, by contrast, will focus on suspension insulators up to 154 kV as well as railway insulators and small posts up to 36 kV. During the technical tour of the new plant, GIG Polymer production specialists outlined some of the key distinctions in its manufacturing

Design of LSR suspension insulators.

GIG Polymer is one of only few suppliers in the industry worldwide to offer both liquid silicone rubber (LSR) and high temperature vulcanized (HTV) rubber as shed material, each focused on different insulator applications. Dosing system for LSR insulator production and evidence of air bubblesbeingremoved under vacuum from silicone raw material.

Photos:INMR©

GIG President, Denis Tasakov, addresses guests at opening ceremonies. “New plant incorporates input from leading specialists in polymeric insulator research, testing and development.”

equipment and philosophy. For example, insulators up to 500 kV will now be able to be manufactured in a single injection cycle so as to avoid any joints in the housing from successive molding operations. According to management, until now such single-stage molding of solid core insulators had been utilized only up to maximum of 220 kV. This limit has apparently now been increased to 500 kV. The major benefits include reduced production time, with pieces as long as 4.5 m able to be cast in a single step. Another aspect of LSR insulator production at the new plant that was highlighted during the opening tour was investment in a Germandesigned vacuum mixing and dosing system that aims to effectively remove any air that may have remained inside the LSR material in barrels coming from the supplier.

In-house testing of all incoming core rods and silicone shed material.

Mold, being cleaned after injection cycle, engineered to allow inclined sheds to be easily removable and also to permit flexibility in meeting any specified creepage or shed spacing.

This is claimed to ensure that no air bubbles can ever enter the mold cavity and become trapped inside the sheath and weathersheds. Yet another point of differentiation at the new Tallinn factory, according to production staff, is the design of special molds intended to ensure a high degree of surface smoothness of insulator housings. The goal here, they say, is to assure maximum self-cleaning so as to reduce accumulation of unwanted conductive surface deposits. The presence of such deposits can lead to risk of onset of degradation from phenomena such as tracking and erosion.

These molds have also been engineered to allow for inclined sheds, intended to maintain dry zones during wetting events and thereby reduce discharge phenomena in service. Such shed designs are recognized as beneficial from a performance point of view but have sometimes presented production problems in terms of ease of removal from the mold cavity after curing.

Photos:INMRÂŠ

Finally, all insulators from the new plant will be equipped with end fittings specially designed to reduce electric field concentration on sheds and also to divert arcs away from the housing so as to prevent puncture in the event of external flashover. ď ¸

Fittings measured for dimensional accuracy before being heated to increase efficiency of crimping process. 87

BUSHINGS

ABB

Invests to Streamline Bushings Production & Testing Part 1 of 2

f one looks at recent developments in the area of bushings, what is perhaps most striking is not any revolution in design but rather the dramatic change in the voltage range across which these components are finding application. Today, 800 kV DC bushings – once viewed as a manufacturing marvel – have become almost commonplace while engineers are already busy producing and type testing units for 1100 kV DC. These developments are driven primarily by requirements in China and India, two markets whose need for long distance transmission are pushing development of DC to ever higher voltages. The experience in these countries is then being transferred to Brazil, South Africa and other growth markets and may well find application one day in mature markets such as the U.S. or Europe. INMR travels to Ludvika, Sweden, to visit one of the world’s largest bushing production facilities and also nerve center of ABB’s developments of UHV AC and DC bushings.

One of the first things one hears these days when it comes to bushings is how the recent move to DC and UHV have combined to change the entire landscape of the industry. These trends have impacted virtually every aspect of the business, from design to production to testing. For example, testing bushings for HVDC applications is much more demanding and time-consuming than for AC due to the need to allow for time effects and charge distribution to build up around the bushing. There is also a significantly longer test schedule, which sees the DC part added to what is required under AC voltage. That means total test time is typically measured in hours, not minutes as with standard AC bushings.

Photos:INMR©

Move to HVDC and UHV has affected bushing production as well as requirements for service performance.

Lars Jonsson is Sr. Specialist at ABB and also Convener of IEC’s Maintenance Team for bushings. He and General Manager Thomas Wennberg point to a number of distinct changes over the past decade. “While oil-impregnated paper (OIP) technology is still

there is a requirement to reduce mechanical stress on bushings for such applications. This is most easily accomplished through decreasing overall weight by replacing both the oil and the porcelain using dry-type RIP designs equipped with silicone housings. For example, Jonsson

“Changing customer needs and requirements have impacted how suppliers must organize their operations for more efficient logistics to produce and handle larger products while still controlling costs and meeting shorter delivery times.” Thomas Andersson, an industry veteran who is now Senior Vice President of ABB’s Components Division, observes “while the overall bushings market has been basically flat in terms of sales, what has changed are customer needs and requirements. These in turn have impacted how suppliers must organize their operations for more efficient logistics to produce and handle larger products while still controlling costs and meeting shorter delivery times.” 90

dominant for HVDC applications,” says Jonsson, “the trend is clearly toward oil free converter halls and therefore to resin impregnated (RIP) styles. There is also a growing hybrid technology combining both technologies that is aimed at reducing the amount of oil and therefore the consequences of any leakage problem.” Jonsson adds that many converter stations happen to be located in areas with high seismic activity and

mentions a full-scale seismic test to the highest standard in existence today involving a 550kV dry bushing and where it remained totally intact. According to Andersson, RIP bushing styles now account for between 25 and 30 percent of the total HV bushings market by volume and, given their typically higher price, between 35 and 40 percent in terms of value. These estimates represent quite a shift toward RIP technology since the early 1990s, when such bushings

“With dry type bushing insulation there is an absolute temperature limit in service… if that limit is exceeded, there can be a drastic change in behavior.”

contrast, with dry type insulation there is no possibility of such cooling, meaning there is an absolute and critical temperature limit during service. If that limit is exceeded, there can be a dramatic change in behavior. Not all power utilities are fully aware of this and sometimes keep loading their RIP bushings, such as during emergency situations.” Says Wennberg, “the issue of heat dissipation is in fact one of the reasons we continue to recommend OIP bushings for HVDC applications where there is a high current load.”

Jonsson examines UHV bushing scheduled for testing.

were regarded mainly as niche items and accounted for only some 10 to 15 percent of the business. At the same time, Jonsson cautions that, while RIP bushing technology has definitely grown in popularity and is available at even UHV levels, it

does come with certain disadvantages. One of these is greater difficulty dissipating the heat generated from high current applications. “OIP style bushings feature constant circulation and thereby allow for convective cooling,” he explains. “By

Jonsson and R&D Manager, Roger Hedlund, believe that present standards are “somewhat generous” in regard to the heating limits allowed for bushings. Therefore, they state that ABB has devoted considerable testing to establish precisely what the limit should be in each case and then taken a conservative approach in their design of dry bushings to be certain they will always be far from reaching it. Hedlund remarks that internal heating in a bushing under high current load can vary depending on type of conductor as well as temperature of oil in the transformer.

Oilimpregnation of 52-170 kV bushings done on an assembly line.

â&#x20AC;&#x153;The new winding machine is all about increasing production volumes, especially for UHV bushing, where sales are growing fast and where we now have to ramp up production to treat these as high volume products.â&#x20AC;?

Optimizing each production step for HV and UHV bushings seen as key to ensuring good production logistics to meet customer delivery lead time expectations.

As such he believes that it is best to capture these parameters using intelligent monitoring systems. However, while some countries such as Brazil have shown a lot of interest and are apparently investing in such systems, Jonsson points out that there are still not many customers who specify them. Among the obstacles, he thinks, are that monitoring systems need longterm software support and that the

Wound cores must be dried in special chambers and then protected from absorbing additional moisture from environment. Photos:INMRÂŠ

with accurately positioned capacitive foil inserts, is wound around the conductor. Although CNC machines for precise winding of the core have been available now for many years, the main suppliers have continued to focus on trying to optimize this equipment in every way possible.

New machine aims to significantly improve productivity of core winding.

expected lifetimes for electronics and transformers are very different. Apart from changing application requirements, another of the key issues affecting bushing suppliers is tightening delivery lead times. Wennberg notes, for example, that market expectations now are that both OIP and RIP bushings for 500 kV are to be delivered in only about 10 weeks. Given the usual bottlenecks when it comes to testing and ordering large porcelain housings for these units, great emphasis is being placed on

finding ways to accelerate key production processes. In the bushings business, one of the most effective areas to accomplish this goal is during the winding of the core, which represents the first strategic step during manufacture. Here, the kraft paper insulation,

Photos:INMRÂŠ

Mixing and de-airing installation for cast resin and vertical curing chambers. 94

For example, in order to meet a bushingâ&#x20AC;&#x2122;s tan delta requirements, it is essential to remove virtually all moisture from the paper before impregnation of the wound core in either oil or epoxy resin. Much of this accomplished during winding using various technologies such as irradiation.

The most recent technological innovation on the factory floor in Ludvika is a new generation of winding machine that is claimed to offer a leap forward in reducing production times for very large bushings. At the time of INMR’s visit, the machine had already successfully wound an 800 kV AC transformer bushing core but was still being finetuned. Says Jonsson, “it is difficult and time-consuming to remove moisture after winding, especially in the case of very big core diameters, since internal moisture always has to exit in an axial direction. So we have focused instead on taking as much out as possible during winding. At the same time, this new machine is all about increasing our capacity, especially for UHV bushings, where sales are growing fast and where we have to ramp up output to handle them as high volume products.” Hedlund explains that apart from the benefit of enhanced drying capability, the new winding machine, which can be used for both OIP and RIP cores, greatly increases productivity. This is achieved by winding the capacitive foil in a single step along the entire length of the core versus in strips as in the machine it was built to replace. “The design of any bushing determines the accurate positioning required of the foil,” he says. “With the earlier machine, there was also enhanced drying but a lot of operator skill was needed to control the placement of foil over such a length. The productivity gain from this new technology versus the earlier strip winding method is at least an order of magnitude, especially for the biggest cores such as for 800 kV DC.”

Photos:INMR©

After winding and drying of the core, the next strategic step in manufacturing sees impregnation of the core in either mineral oil or in a cast resin body. The drier the core,

Production steps for smaller RIP style bushings with molded on silicone housings see impregnation by resin followed by machining and coating of core. 95

Testing done for any leakage between core and tube conductor before machined resin body hoisted and inserted into flange.

the easier it will be to impregnate and, more importantly, the better will be its tan delta performance.

Partial discharge activity or an elevated dissipation factor will reveal problems such as a core that has air inclusions or that has not been sufficiently dried. Hedlund points out that this area used to represent a production bottleneck but has improved

considerably in recent years, not only expanding in scale but also seeing improvement in quality of materials and better processes. The result, he says, is that only about 1 percent of cured cores are now being rejected for quality reasons, versus about 5 times that rate several years ago. Says Hedlund, â&#x20AC;&#x153;RIP technology requires

Photos:INMRÂŠ

An RIP body is composed mainly of bis-phenol A epoxy, hardener and a catalyst intended to accelerate their chemical reaction. These ingredients are processed in a special installation that removes all air while also ensuring a precise mixing ratio of the components. Curing of the body under heat then takes place inside vertical cylindrical vessels that accommodate a single unit or can handle a batch simultaneously, depending on size. Cycle times take one week or longer, depending on core dimensions and the key consideration is avoiding formation of internal voids or cracks.

Old style OIP oil to gas bushings (right) involve more complex design with separate expansion chamber and require monitoring versus comparable RIP types. 96

HV lab located directly within manufacturing area assists productivity.

a lot of competence and knowledge of epoxy. The key to success lies in understanding the process and its key parameters.” Hedlund also notes that certain new techniques have been developed and employed during the pre-impregnation process to shorten total impregnation time. In the case of dry bushings manufactured in Ludvika, these come equipped only with silicone housings. For the lower transmission voltages, the rubber is molded directly onto the core before having the resin mixture pumped into the body enclosed in a paper tube, followed by curing. The winding mandrel is then pulled out and the tube removed before the cured core is machined to the shape and tolerances required for the flange and ‘O’ ring. The last step sees the core given a protective black coating after which the flange is attached and tightness testing is performed. Larger RIP bushings for higher voltages see the machined resin core fitted inside a hollow composite insulator and the internal gap filled to a certain pressure with a proprietary compressible two-component gel. This gel serves as dielectric filler between core and external housing. Testing is the last and sometimes most time consuming single element of bushing production, especially for HVDC units. ABB’s facility in Ludvika has adjusted to this reality 98

by incorporating five separate test laboratories in one plant. Two are built to allow testing for UHV and situated at opposite ends of the building to eliminate need to transport very large bushings across the length of the factory floor. Three additional labs are equipped for voltages below 800 kV including one that is directly adjacent to the main production area and carries out routine tests such as voltage withstand and measurements of capacitance, dissipation factor and partial discharge. Says Jonsson, “it is quite unique in our industry to have such a lab located almost inside the workshop. Yet, although it is so close, it is equipped with efficient filters that eliminate disturbances from the surroundings.” Walking through the Ludvika facility, Jonsson surveys the many large bushings all around him. “These are the types of bushings we are delivering every week now,” he remarks “but that would have been a rarity only a few years ago. Such units would also have required a very long winding time with our old machinery. But, with better equipment and processes, we have succeeded to shorten that considerably.” Photos:INMR©

Adds Hedlund, “a lot of investment has been made here over the past years in test laboratories as well as in our UHV bushings manufacturing section that offers additional drying chambers and impregnation vessels. A good measure of this is that, although ABB supplies bushings from a number of plants throughout the world, output from this facility has quadrupled over the past two decades.” Part 2 of this article will take readers to the world’s most northerly insulator factory and perhaps also the northernmost manufacturing site of any HV component. INMR visits and reports on ABB’s hollow core composite production facility located in Piteå, Sweden, only a short drive from the Arctic Circle. 

CABLE ACCESSORIES

Testing Cable Terminations Under Polluted Conditions Cables and their accessories are an integral part of power networks and, whenever there is a transition to them from either overhead lines or busbars, the ends are sealed using terminations. Terminations are of different construction depending on whether the application is medium or high voltage. In both cases, however, care must be taken in regard to pollution withstand since they are an interface with the service environment. While a pollution test has already been standardized for MV terminations, no similar standard yet exists for HV terminations. This article, contributed by Heiko Jahn and Wolfgang Manzke of test institution, FGH Engineering & Test in Germany, reviews existing standards as well as some of the important factors when it comes to testing terminations for pollution performance.

100

â&#x20AC;˘ a salt fog test in the case of outdoor terminations.

Figure 1: Selected standards for testing medium and high voltage cable accessories.

For MV terminations, a test with respect to pollution behaviour has been standardized (Clause 13 of IEC 61442). Depending on application, this test is either:

With increasing nominal voltage, terminations become larger and therefore installation is often made in discrete steps with the various elements installed individually. Housings can be either hollow porcelains or, as increasingly being used, hollow composite insulators with different silicone rubber material.

â&#x20AC;˘ a humidity test for indoor terminations; or

For glass and porcelain insulators, pollution tests have been

increased stresses placed on the accessories.

Photos:INMRÂŠ

Figure 1 provides an overview of the various IEC and CENELEC standards used for testing medium and high voltage cable accessories. It is worthwhile noting that this assortment of standards only defines minimum requirements to satisfy the quality demands of power utilities. Some users have chosen to issue their own test specifications, based on these standards but with

MV terminations are directly installed onto cable ends, either with all components integrated into a single piece or with the individual elements (i.e. field grading, heat-shrinkable tube, weathersheds) installed separately. Due to their relatively limited size, the weight of medium voltage terminations is typically low enough that no additional mechanical support is required.

Housings of HV terminations employ either porcelain or composite insulators. 101

The only standardized test procedure for hollow composite insulators is the tracking and erosion test, but this is a test of only the housing material, not of pollution performance.

Photos:INMRÂŠ

standardized in IEC 60507 for AC and IEC/TS 61245 for DC. In both cases, however, the scope of the standards does not include terminations as the test object. While a cable termination can basically be regarded as a bushing, meaning that both applicable standards can apply, care has to be taken to avoid internal breakdown. Composite insulators are excluded from the scope of the standards referred to above since the test procedures were developed for hydrophilic surfaces and hydrophobic silicone results in certain unwanted effects. As a result, the only standardized test procedure for hollow composite insulators is the tracking and erosion test according to IEC 62217, which is really a test of the housing material and not of pollution performance. Therefore, when it comes to HV terminations equipped with composite insulators, either a test procedure has to be agreed upon between manufacturer and user or some specification from the purchaser must be made available. Tests that have been carried out in this regard are described below:

MV terminations have established standards when it comes to pollution testing. 102

Humidity & Salt Fog Tests on MV Terminations To ensure appropriate behavior, a humidity test was introduced for indoor cable terminations and a salt fog test for outdoor terminations.

Table 1: Test Conditions for Humidity & Salt Fog Tests Termination

Outdoor

Indoor

Test duration

1000 h

300 h

(1600 ± 200) mS/m

(70 ± 10) mS/m

Water conductivity Test voltage

1.25 U0

Over current trip-out Temperature

(1.0 ± 0.1) A r.m.s. for 50 ms – 250 ms Ambient

Acceptance criteria

Nofailure,noflashover,notmorethan3trip-outs,notracking,no erosiondeeperthan2mmor50%ofthematerialthickness,no rupture, no breakdown of the insulating material.

Fog generator

Roomhumidifierornozzleswithdropletsize10µmfor80%of the droplets

Precipitation

Flow rate of (0.4 ± 0.1) l/(h · m³)

Test chamber

Corrosionproof,moisturetight,observationwindows,drainfor wastewater,pressureless,nowaterdrippingtothespecimens. Flow rate meter.

Request to voltage supply

At load current of 250 mA voltage drop ≤ 5%.

Example of salt fog test chamber and installed terminations.

The main differences lie in test duration and conductivity of the saline water. The relevant humidity and salt fog test conditions are defined in IEC 61442 (see Table 1). A corrosion-proof test chamber with inclined roof is essential to avoid any influence from water that might drip down onto the test object. Moreover, the circuit feeding the test has to provide low impedance to ensure only a small voltage drop at high test currents. When testing 3-phase cable accessories with spreader caps, the voltage must also be supplied 3-phase so as to correctly test the whole termination system. Medium voltage terminations are often installed with significant mechanical strain on the cable. As such, in cases where tracking affects the edge of the termination or erosion becomes too deep, the material may rupture and there will be moisture ingress. Eventually, the termination may fail. The various conditions specified can sometimes require significant time and effort to build up the test circuit. Moreover, since such a test lasts up to 1000 hours, most customers require that it yield extended information beyond simply ‘pass or fail’. For example, while only over current detection is required by the standard, today’s test systems also provide for long-term measurement of leakage current. From such a curve, it is possible to establish if there has been a loss of hydrophobicity; the stress on the cable termination can also be estimated. With today’s systems, an oscillogram is available should any over current situation occur (see Figure 2). This allows the possibility to carry out additional investigations should there be failure. With currently available technology, the test bays can even be observed by remote access to the measuring system and test engineers informed about events by mobile phone or e-mail. This ensures that there will be only minimal delay should there be any unexpected interruption to the test.

Figure 2: Long-term current recording (top) and flashover current oscillogram. 104

Salt Fog & Solid Layer Tests on HV Porcelain Terminations

In any case, the standard can be understood to test the termination under service conditions – exactly as proposed for components such as wall bushings. Here, a short cable loop must be prepared and the termination to be tested is installed at one end. The other end must also be sealed, either with another termination of at least the same pollution withstand or using a GIS plug and compartment. In the latter case, the test assembly is easier to handle and re-locate within the laboratory. IEC 60507 (for AC tests) and IEC/ TS 61245 (for DC tests) describe essentially the same test procedure with the difference being mainly in test voltage. Before the test is started, a decision is made whether the solid layer method or salt fog method is to be applied. While results in both cases are generally recognized as being equivalent, there is a tendency toward salt fog testing to simulate service conditions in coastal areas. The solid layer method, by contrast, is usually preferred to simulate stresses in regions where solid pollution layers of dust, sand etc. can build up on the termination. Table 2 shows essential details of the test requirements for the salt fog method and Table 3 for the solid layer method.

Photos:INMR©

While for MV terminations pollution behaviour is tested using the procedure discussed above, no such methodology is requested by the standards in the case of HV terminations. For those terminations equipped with a porcelain housing, IEC 60507 (AC tests) or IEC/TS 61245 (DC tests) can be applied. But since cable terminations are not specifically mentioned in these standards, it seems left open how the test set-up should be prepared.

Pollution performance of porcelain-housed terminations can be tested using either salt fog or solid layer methods.

Table 2: Test Conditions for Salt Fog Tests Standard Test Method Preconditioning process Test duration

IEC 60507

IEC/TS 61245

Salt Fog Method

Upanddownmethodundersaltfog Upanddownmethodundersaltfog stress to cause 8 flashovers on the stresstocause8flashoversonthe insulator surface insulator surface, AC or DC 3 consecutive 1-hour withstand tests

Salinity Test voltage Acceptancecriterion

2.5 - 224 kg/m³ up to 600 kV AC phase to earth

up to ± 600 kV DC

No flashover, if one flashover occurs, a fourth 1-hour withstand test shall be passed

Temperature

5°C - 40°C

Fog generator

Two spray columns with salt fog nozzles

Nozzlesairpressure / water flow rate

700 ± 35 kPa / 0.5 ± 0.05 dm³/min

Requesttovoltage Resistance/reactance ratio ≥ 0,1; supply capacitivecurrent/short-circuitcurrent ratio = 0,001 - 0,1; Short circuit currentdependingonthetestobject

Cable end sealed with GIS compartment.

Ripple factor ≤ 3 % @ 100 mA; resistiveloadrelativevoltagedrop ≤10%;relativevoltageovershoot ≤ 10 %

Cableendsealedwithsecondtermination.

Pollution Tests on HV Composite Terminations Since non-ceramic insulators are now increasingly being used on power grids worldwide, there is an important need to test their behaviour under polluted conditions. At the moment, however, the only IEC test for hollow composite insulators used in cable terminations is the tracking and erosion test, according to IEC 62217/IEC 61462.

Cable terminations in salt fog chamber with different kinds of cable end sealing. 105

Unfortunately this is not a full-scale test and therefore does not consider the influence of length or of field grading on the termination. Rather, the only result is information about the housing material and quality of design. In any case, information about pollution withstand behaviour is essential, even if the new composite insulators are hydrophobic at the start. Typical requests for testing these types of cable terminations include:

Photos:INMR©

• Tests according to the standards used for porcelain insulators (i.e. IEC 60507 (1991-04) Ed. 2.0, IEC/TS 61245 (1993-10) Ed.1.0) including pre-conditioning for salt fog testing, regardless of their exclusion from the scope of existing standards; • Tests according to the standards for porcelain insulators but without pre-conditioning for salt fog tests, again even though these are outside of present standards; • Tests according to whatever specifications are set by the buyer. From the above, there are obvious problems in the case of composite insulators exposed to the same standard pollution test conditions used for porcelain. For example, where there is salt fog testing, the standard mandates pre-conditioning consisting of 8 flashovers. This, of course, will reduce the hydrophobicity of a composite housing given the impact of electrical discharges. As such, the test does not properly reflect normal behaviour in service but rather only a ‘worst case’ scenario.

Application of compositehoused HV terminations has been growing worldwide.

The problem with solid layer testing is similar. Since the artificial pollution layer cannot be applied to a silicone rubber surface, it is necessary to ‘overpower’ the hydrophobicity by covering the surface with kaolin powder, done by rubbing the surface with a cotton cloth and the powder or using a brush. Afterwards, the composite insulator surface behaves much like porcelain. Again, such a test does not reflect normal behaviour in service but rather only the worst case. To arrive at an acceptable solution, given the above, it seems that the best way for test laboratories now is to follow whatever specifications

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Since test voltage is equal to U0 (phase-to-ground voltage), the termination is not so heavily stressed as by application of repeated flashovers. On the other hand, experience has shown that the insulator of the termination does not remain hydrophobic over the entire test period. As such, this procedure seems to offer a good compromise.

Table 3: Test Conditions for Solid Layer Tests Standard

IEC 60507

IEC/TS 61245

Test Method

Solid Layer Method

Suspension

Mixture of Kaolin or Kieselguhr, MixtureofKaolin,tapwaterandsodium tap water and sodium chloride, for chloride Kieselguhranadditionalsilicondioxide

Test duration

3consecutivewithstandtestswithdurationdependingontheleakagecurrent curve, max. 100 minutes

Salt deposit density (SDD)

Kaolin:usuallybetween0.025to0.4 Usually between 0.012 to 0.4 mg/cm² mg/cm²Kieselguhr:usuallybetween 0.0176 to 0.2 mg/cm²

Test voltage

No limitation, 0.5 m per 100 kV clearance to any earthed object

Acceptance criterion

No flashover, if one flashover occurs, a fourth 1-hour withstand test shall be passed

Temperature

Temperature rise during withstand test shall not exceed 15K

Fog generator

Steam fog generator

Fog intensity

To reach the maximum layer conductivity between 20 and 40 minutes,usually0.05±0.01kg/hper cubicmetreoftestchambervolume

Summary

While the pollution withstand performance of MV cable terminations is part of the standard according to IEC 61442, no such test is yet defined for HV terminations. For those terminations with porcelain housings, existing test standards IEC 60507 and IEC 61245 can be applied. Still, care has to be taken to avoid internal dielectric breakdown.

The rise time of the layer conductivity between 15 and 70 minutes, usually 0.05 ± 0.01 kg/h per cubic metre of test chamber volume

For terminations equipped with composite housings, these test standards are not applicable since composite insulators are excluded from the scope of existing standards. Therefore, existing procedures have to be somehow modified or the tests carried out according to specifications set by the purchaser. Revisions to the pollution test standards are in process but composite insulators are apparently still not included in their scope and will have to await a future new standard. 

Request to Resistance/reactance ratio ≥0.1, Ripple factor ≤ 3 % @ 100 mA, resistive voltage supply capacitivecurrent/short-circuitcurrent loadrelativevoltagedrop≤10%,relative ratio = 0.001 to 0.1. Short circuit voltage overshoot ≤10 % current depending on test object

Salt fog test method with all parameters according IEC 60507 but with important modifications that include: a) Preconditioning with 80% of test voltage over a period of 3 hours without interruption; b)12 subsequent 1-hour withstand tests, at 100% test voltage, with the requirement that at least 8 tests must be passed without flashover or breakdown. Photos:INMR©

are required by the purchaser of the composite-housed termination. At least this guarantees acceptance of the results by the cable system’s end user. An example of such a specification is UX LK208, used by Italian grid operator, Terna, and which proposes the following procedure for testing terminations equipped with composite insulators:

Existing standards do not yet adequately cover composite-housed HV terminations. 107

PRODUCTION

German Injection Equipment Manufacturer Adjusts Business Strategy Not long ago, suppliers of rubber injection machinery looked at the electrical components industry as little more than a novel niche market. However, since the mid 1990s and the boom in electrical products made by rubber injection that perspective has changed. Today, the market for molded medium and high voltage polymeric components is huge and expanding. Not surprisingly, injection equipment manufacturers have

therefore begun targeting this sector with customized solutions intended to satisfy the diverse needs when it comes to producing these types of items. Among the worldâ&#x20AC;&#x2122;s first suppliers to offer molding machinery for HV electrical components is based in southern Germany, near its border with Switzerland. INMR visits Desma Elastomertechnik to report on its strategy for serving the electrical products sector.

Photos:INMRÂŠ

ne of the factors governing success in the rubber injection equipment industry is understanding how customers utilize this equipment and in what business environment. When it comes to molded electrical products such as composite insulators, polymeric arresters or cable accessories, foremost among customer requirements nowadays is optimizing machine utilization in the face of continuing cost pressures and relatively small production lot sizes.

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Schmid surveys Desma machine installed at new insulator factory.

Photos:INMR©

“What customers want most these days is production methods that offer them flexibility to adjust quickly to meet different item quantities as well as the different designs demanded by the market.”

HTV silicone material being fed into molding machine.

“Users of rubber injection equipment in the electrical sector,” notes Harald Schmid, “tend to work with much smaller quantities than industries such as autos. They also do not want to produce for stock. That means they are always searching for an ideal balance between productivity and flexibility.” As Desma’s Sales Manager for some two decades now, Schmid has witnessed firsthand how the electrical products industry has evolved from

One of the areas requiring greatest know-how in injection molding is managing the risk that unwanted curing may take place inside the nozzles delivering incoming raw material.

the earliest days of molding items such as insulators and arresters in the mid 1980s and early 90s. In fact, he began his career working on the shop floor and knows most details of how this equipment is produced. Says Schmid, “what customers want most today is production methods that offer them flexibility to adjust to meet different item quantities and designs as demanded by the market. That means they usually do not want to invest in a production system that is too specific for one product group. Ideally, they also prefer to avoid having to change molds frequently.” He points, for example, to accessories such as cable boots as an item where large power utility customers often have their own demands, each requiring a somewhat different design. “We are all Europe,” he remarks, “but at times it seems everyone is ‘cooking their own soup’, using their own norms.” Indeed, because of the large variation in cable accessory designs across many Western countries and the lack of common standards, he predicts a bright future for machine suppliers best able to meet the different needs of the sector. This situation is one reason why Desma is increasingly concentrating

on serving the cable accessory industry. Another factor, notes Schmid, is that this sector generally requires more complex manufacturing technologies than items such as insulators, meaning that competing equipment suppliers are not evaluated mainly on price. “We have been re-focusing ourselves,” he says, “where there is demand for the highest level of technology and customized engineering in the molding machine.” To illustrate, Schmid states that special needs when it comes to molding cable accessories also place greater demands on auxiliary equipment such as dosing units. These demands include achieving higher dosing pressures to enhance process stability and also allow easier changeover of barrels of the silicone rubber material. “In the cable accessory business,” he explains, “mixing of components is critical. Sometimes that means that two or even three static mixers are needed. This in turn requires more pressure from the machine or else the dosing may proceed too slowly and the injection unit will not fill properly during the product’s cure cycle.” Schmid goes on say that this is one reason why more customers now prefer volumetric dosing with an 109

High pressure, closed loop systems are used for articles each having a maximum volume of about 50 liters of material. Such systems, he says, generally offer lower reject rates but require greater investment at the start. Adjusting cable connector mold parting Another factor promoting Desma’s line significantly increased productivity renewed focus on offering higher of same molding machine. level of technology and engineering support, according to Schmid, is that suppliers of molded electrical components increasingly depend on it. “Many of our customers do not electronically controlled pump stroke have their own in-house specialists to ensure perfect 50/50 mixing. “If when it comes to production startthis does not happen,” he notes, up,” he says. “That means they need “some residue may remain in one of outside expertise in finding the best the barrels when the other is already way to manufacture an item after it empty. That leads to wastage of an has been designed by their product expensive material.” development department. That’s where we feel they can rely on firms According to Schmid, pressures such as ourselves.” on the injection units in some of Desma’s new molding machines Schmid picks up a cable connector have been increased from 2000 to from a machine in the company 3500 bar to allow more efficient showroom to illustrate how a molding delivery of HTV or EPDM rubber equipment supplier can help meet material into the mold cavity. “We the needs of its customers. In this need this added power,” he explains, “since there is friction energy to create during injection in order to bring heated silicone or EPDM over heated metal.” He also emphasize The mold must be that one of the areas requiring carefully handled, greatest know-how in the injection molding operation is managing the since most damage risk that unwanted curing may take tends to take place inside the nozzles delivering place during mold the raw material. “To avoid this,” he says, “you have to control both the changeover. speed and the pressure since it is a complete ‘closed loop’ process.”

case, he says, close co-operation with the connector manufacturer resulted in a more than doubling of machine output only by a slight change in the design of the mold parting line. Schmid also emphasizes the important role played by the mold itself and explains why too frequent mold changing should generally be avoided. “There is actually a lot of intelligence and software built into every mold,” he remarks. “As both a machine manufacturer and also a mold supplier, we work with customers to develop each mold for reduced machine downtime and increased productivity. For example, working with molds that contain different cavities can save a manufacturer hours in mold changing, cleaning and heating time.” A typical mold in the European market is expected to last some 15 years, compared to about a 20 to 25 year lifetime for a typical rubber injection machine. In order to attain such a service life, however, the mold must always be carefully handled, since most damage tends to take place during cleaning or mold changeover. Schmid notes that most customers do not have their own in-house mold service and rather send these back for repair or periodic maintenance to ensure they are always in good condition. Looking to the future, Schmid indicates that Desma will continue to follow its basic product concept

Photos:INMR©

Typical molds are expected to last 15 years in Europe.

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Photos:INMRÂŠ

Software allows development of molds that enhance both productivity and quality.

whereby some 90 percent of a typical molding machine relies on standardized components. These components can then be mixed to meet different customer needs, for example adding a sliding system for better access for insert feeding and easier de-molding or where the items being molded are multicomponents such as conductive parts with over-molded silicone.

Worker removes finished item after molding cycle.

He also predicts that future developments in molding of electrical components such as cable accessories will probably include automation systems downstream with the goal of reducing reject rates by eliminating any influence from the worker. Since items are still warm as they exit the mold, they are more at risk of damage due to any improper handling. As example, he points to a recent project, where molded cable accessories are planned to be removed using robots in order that the entire operation be fully controllable. ď ¸

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Resolving Problems From Poor Insulation Performance in Desert Environments (Part 3 of 3) In heavily polluted areas of Oman or Eastern Saudi Arabia, operating experience has demonstrated that, even with 40 mm/kV creepage distance, ceramic fog type insulators do not offer satisfactory contamination performance and must be washed regularly to reduce contamination flashovers. While it is widely assumed that silicone insulators can operate at lower USCD values than either porcelain or glass, this has not always been found to be the case in such environments. Rather, there is concern that use of reduced leakage distance insulators in heavily contaminated areas may lead to a shorter service life. For example, one study of failures has suggested that leakage current during

Alternative Polymeric Insulator Materials for Desert Environments Silicone Rubber UV can damage polymers by breaking the C-C bond that forms their molecular backbone. At lower wavelengths of 300 nm, the energy released by solar radiation is around 398 kJ/mole while the energy needed to rupture the bond is 348 kJ/mole

periods when hydrophobicity is temporarily lost (e.g. during dawn when damp pollution is present) can accelerate ageing and even trigger failure. It should also be emphasized that, when it comes to polymeric insulation, performance is not simply a function of the base polymer but also depends on several other factors. Poor quality fillers, for example, play a key role in increased tracking and reduced erosion resistance. This last in a 3 part series of articles contributed by British consultant, Brian Wareing, reviews investigations he conducted into poorly performing insulation in demanding desert environments.

at normal ambient temperatures. This explains why many polymers require the addition of UV inhibitors to ensure long-term stability. The Si-O backbone bond in silicone rubber, by contrast, requires 445 kJ/mole to be broken and is the chief reason silicone inherently performs better under UV exposure than do most other polymers. Still, there are other bonds in silicone polymers that can suffer UV damage,

so it is not totally exempt from degradation. In desert areas, where temperatures can even exceed 50째C, for example, silicones can suffer some degradation, leaving behind a residue of conductive carbon that reduces tracking resistance. The low surface energy of polymers, compared with porcelain, is one reason why these materials retain hydrophobic properties. Silicone

Fig. 1: Unbonded cross-arms with tracking evident from top and between.

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has about half the surface energy of materials such as EPR, EPDM and epoxy and this explains its superior hydrophobicity. This property, however, can be adversely affected by prolonged exposure to moisture and explains why silicone often performs poorly during continuous salt fog tests. Silicone rubber is best suited for environments that, while polluted, experience frequent rainfall since the material recovers its â&#x20AC;&#x2DC;as-newâ&#x20AC;&#x2122; properties quickly after a pollution incident. This process occurs by re-orientation of the polymer chain and by migration of material from the bulk polymer to the surface by natural diffusion. However, lack of rain, as in the desert, makes the performance of silicone uncertain. Polyolefins Many polymeric chains are chopped up by UV, especially where there is some defect in the chain due to manufacturing. Thermoplastic polyolefins such as polyethylene (PE), polyvinyl chloride (PVC) and ethylene vinyl acetate (EVA) that are free of defects can actually have an outdoor life of many years before they degrade. But such plastic materials must usually be stabilized with a mixture of UV screens for performance outdoors. Carbon black, for instance, is used in some insulated overhead line conductor sheaths while antioxidants can slow down damage to the polymer chain due to pollution and electrical activity. Carbon black, however, at 3% content can encourage tracking and so other UV inhibitors combined with low carbon black content (<0.5%) are currently used on covered conductor lines in Oman. Similarly, UV absorbers work by reemitting energy from sunlight. Pure polyethylene has no absorption bands in the UV spectrum so, in principle, could last forever. EPDM Certain epoxy resins and the propylene part of EPDM rubber both have a well-deserved reputation of being vulnerable to UV. In the absence of information on specific formulation, a silicone would therefore always be a better choice, especially if exposure to high UV

Fig. 2: Unbonded steelwork allows tracking to occur on pole at both cross-arm and cross-strut.

Fig. 3: Localized severe tracking on pole that does not have bonded stays.

Fig. 4: Cross-arm support in the Al-Ashkharah area of Oman. 113

Fig. 5: Corrosion of pole-mounted transformer in Oman.

was the main decision criterion. This has been borne out by numerous examples of EPDM products suffering severe tracking in the deserts of Gulf countries such as Oman.

Bonding and Pole Fires

As discussed at length in Part 1 of this article, polluted insulators allow tracking currents that travel between phases or to earth. With stay wires and in the absence of flashover, the existence of such currents is normally not a problem. However, lack of bonding of cross-arms or stay wires can result in the current over the insulators also tracking over the pole, leading to carbon tracks and eventually to the wood igniting. Bonding to Cross-arms Figure 1 shows a typical unearthed pole formerly used in the Omani desert network and where not all

Fig. 6: Cross-arms can become so corroded that steel supports fail and bend under normal line tension.

steelwork has been bonded. Here, a balancing stay wire has been bonded to the lower but not to the upper cross-arm. As a result, unbalanced leakage currents over the polluted porcelain insulators travel to the top cross-arm and from there move down the pole to the lower cross-arm and over the stay insulator to ground. These tracking currents over the pole section can cause â&#x20AC;&#x2DC;tree-likeâ&#x20AC;&#x2122; tracks, laying down carbon and giving future tracking currents a lower impedance path â&#x20AC;&#x201C; thereby only increasing the risk. The insets in this photo show tracks from the pole bolt area of the top cross-arm down both sides of the pole. There is therefore a heightened risk of pole fires in this area. Fortunately, such tracks are easy to identify when line inspection personnel know what to look for and remedial measures can be taken pro-actively.

Fig. 7: Repaired conductors and rusted insulator fittings. 114

Bonding all Steelwork Figure 2 shows an unearthed pole that has not had all the steel work bonded. As a result there is evidence of tracking from the upper cross-arm and also from the support crossstrut, that cannot be bonded as it is too close to the ground and could present a danger to personnel from floating voltages. In such cases, it is advisable that all steelwork be bonded and also earthed. Bonding to Stay Wires Figure 3 shows a pole where there is no bonding between the stay wires on either the pole or the cross-arm. Unbalanced currents flowing over the insulators will raise the voltage of the electrically floating crossarm insulator. These currents then look for the easiest path to earth, down the bonded stay, across the stay insulator and into the ground.

Fig. 8: Example of corrosion on insulator.

However, when bonding is not present, these currents must flow along the pole to reach the stay wire. Figure 1 showed that, when there is a relatively long distance between electrically floating cross-arms, these currents spread out and â&#x20AC;&#x2DC;tree-likeâ&#x20AC;&#x2122; tracks appear. However, when the distance along the pole is short, as illustrated in Fig. 3, the tracking can be concentrated and deep. This increases risk of pole top fires but is easily resolved by bonding all steelwork.

Fig. 9: Insulators mounted directly onto concrete poles.

Importance of Insulator Quality & Specification Problems due to poor or non-existent bonding all arise from application of insulators that are not appropriate for local service conditions. It can be difficult to detect poor bonding but the result of a combination of poorly performing polluted insulators and poor bonding is that pole tracking starts â&#x20AC;&#x201C; the first step in pole fires.

Corrosion & Environmental Problems

A further problem in the deserts of the Arabian Gulf and especially in the southeast of Oman has been corrosion of steel in cross-arms, transformers and conductors. This in turn has a direct bearing on insulator specification as it influences choice of materials for end fittings. Corrosion in this area is due to calcium salts from the desert and sodium salts from the Gulf in combination with high UV, high temperatures, NOx from corona discharges and SOx from vehicle

Problems due to poor or non-existent bonding all arise from application of insulators that are not appropriate for local service conditions

Fig. 10: Example of poorly installed arc protection device. 115

diesel fumes. In many cases, the steel cores of ACSR conductors corrode away, leading to large conductor sags and the deaths of camels, goats and anything else that happens to pass nearby, including local residents. In such a corrosive environment, the galvanizing on fittings of polymeric insulators can easily be damaged, even with low levels of fault current at the contact points with connecting hardware. There will then be a reduction in their mechanical strength, with possible line drop and other safety hazards. Given this, most insulators at 132 kV in the area now incorporate a sacrificial ring for power arc protection. The arc initiation point, or roots, attach onto the ring thereby avoiding power being dissipated by the arc at the end fitting. However, some utilities do not install these devices correctly with the ring sometimes being fitted behind the insulator crimp, thereby leaving it exposed to damage. The solution currently being employed essentially removes all galvanized steel from the regionâ&#x20AC;&#x2122;s medium voltage network. Steelwork on insulators is replaced with aluminium or stainless steel and cross-arms replaced by installed insulators directly mounted onto

Fig. 12: 33 kV interphase spacer in position.

concrete poles. Indeed, concrete poles are now being widely used on medium voltage networks in Oman. Initially imported from Germany, a joint venture has resulted in these now being locally produced.

Application of Spacers Between 33 kV Circuits The Gulf States have a dense network of 33 kV lines to feed the regionâ&#x20AC;&#x2122;s many oil wells. Sometimes these lines are less than a meter apart and, given frequent high desert winds, faults due to clashing have been a serious problem. To remedy this, a Canadian-based line contractor and insulator manufacturer recently co-operated with another firm in applying live line techniques to install spacers between such lines, enabling the problem to be solved with no loss in oil production. The insulators used here were silicone type and met all specific creepage distance requirements for this service environment. ď ¸ Fig. 13: Crossing lines with interphase spacers installed.

Fig. 11: Live line installation of the interphase spacers. 116