INMR Issue 104 Q2 2014

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to Germany!

Welcome to Bavaria!

Welcome to Munich!

Welcome to our 20

anniversary 2015 INMR WORLD CONGRESS th

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• 120 technical presentations on today’s important topics and service experience with different designs of MV, HV & UHV insulators, surge arresters, bushings and cable accessories

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

• A Product & Technology Exhibition featuring many of the leading suppliers across the globe

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

WORLD CONGRESS

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PERSPECTIVE Pollution: A Problem of the Past‌ or of the Future?

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O

ver the last 20 years, there may have been good reason to believe that pollution has become less and less of a danger affecting the safe operation of power networks. For example, according to statistics discussed on p. 24, pollution was once the single major cause of outages on the Chinese transmission system. These days, pollution flashovers in China are rare due to widespread application of silicone insulators and RTV coatings in high contamination service areas. This same paradigm holds true in other countries as well.

But pollution is increasingly not just a local phenomenon but also a global one.

And its patterns, like the world’s climate, may be changing. If true, that means that it will no longer be sufficient to look only to local contamination sources when estimating the pollution that will be deposited onto insulators over a typical year.

Pollution threats may now be coming from far away.

For example, in early April, London and all southern England experienced their highest pollution levels ever recorded – not from local sources but from thousands of kilometers to the south. The news headlines of the day read: London Smog Caused by Sahara Storm: Motorists Find Cars Covered in Red Dust. Of course, it was not only automobiles but also insulators that suddenly became coated by conductive desert dust. Moreover, the insulators affected probably had not been specified to perform under such a type and level of pollution.

Power networks can be especially vulnerable to climate change patterns inasmuch as deposition of pollutants from distant sources may exceed design criteria when lines or substations were first built. (To see an example of how sudden changes in pollution exposure can be a threat, see article on p. 52.)

Since the impact of changes to the climate and global dust deposition patterns cannot be suddenly reversed, what can be done? The first step lies in better monitoring the levels and types of pollutants deposited onto the power network, even in service areas once regarded as experiencing low contamination. That may eventually require re-drawing pollution maps to give greater weight to recent experience (i.e. as a precursor of what may be to come) than to purely historical data.

Pollution and dust deposition patterns may be on the verge of significant change. The best defense will be information that will allow insulator users time to know how they are being affected and to react accordingly.

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Hebei Xinhua High Voltage Electrical Equipment CO., LTD Rigid composite insulators represent an advanced insulator technology employing high temperature injection molding to ensure consistently high strength, fully sealed designs. This revolutionary technology offers excellent hydrophobic properties and other electrical performance characteristics while also being resistant to damage due to sand, wind, climbing by line workers or bird pecking. These rigid insulators also eliminate all risk of brittle fracture during service.

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Advanced rigid composite insulator Advanced production technology Advanced rigid composite insulating material

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Contents Issue 104 Quarter 2 − 2014 Volume 22 − Number 2

52

Advertisers in This Issue

34

92 4 Perspective Pollution: Mostly a Problem of the Past … or of the Future?

12 Editorial Bad Things Can Happen to Insulators

14 Commentary by Pigini Evolution of HV Testing & Adapting to UHV

16 From the World of Testing Fail Safe Arresters 18 Reporting from CIGRE CIGRE Reference Book on Overhead Lines

22 Transient Thoughts High Voltage Insulation & Rubber Books

24 Scene from China Insulation Failures Affecting

Chinese Transmission Lines

26 Woodworth on Arresters Arrester-Transformer Separation Distance in Substations

Utility Practice & Experience 34 Canadian Power Utility Entering Final Phase of Investment in Network Infrastructure

52 Composite Bushings with RTV Coatings Combat Pollution at Substation in Israel

66 Selective Application of EGLAs on Transmission Lines in Malaysia

76 Insulator Corrosion Problems Affect HVDC Lines in China

Insulators 82 Effect of Volcanic Ash on Outdoor Insulators

92 ABB Invests in Expanded Insulator Production Capabilities (Part 2 of 2)

Arresters 102 Principal Failure Modes for Surge Arresters

Testing 106 Testing for Safety & Risks Affecting Operation of HV Cable Terminations, Bushings & Arresters

Towers 28 Focus On Cable Accessories 112 Developing Composite Paper Insulated Cables & Insulating Cross-Arms for the Environment

30 New Web Site Devoted to HV/HP Laboratory Testing

400 kV Lattice Towers

Maintenance 117 Corona Camera Supplier Extends Product Range

ABB Inside Front Cover 111 Arago Technology Chengdu Electric Power Fittings 64-65 CSL Silicones - SiCoat Outside Back Cover Dalian Composite Insulator DCI 4 & 111 3 Dalian HiVolt Systems Dalian Insulator Group 10-11 Dalian Reliable Industrial 49 Dekuma Rubber & Plastic 30 & 31 Desma Elastomertechnik 5 Dextra Power 3 17 DNV GL KEMA EGU HV Laboratory 49 Glasforms PolyOne 9 Hebei Xinhua HV Electrical Equipment 6-7 Himalayal 15 73 HSP/Trench Bushing Group Hubbell Power Systems Inside Back Cover Hübers Verfahrenstechnik 101 Jinan Meide Casting 79 Mosdorfer 43 41 Motic Electric Nanjing Electric (Group) 37 NORIT Instrument Transformers 5 101 Ofil Systems Omni LPS 50-51 79 Phenix Technologies Pukou Huagao 41 Reinhausen Power Composites 21 SGD La Granja 1 19 Shaanxi Taporel Electrical Insulation Sichuan YiBin Global Group SYGG 32-33 81 STRI TE Connectivity 29 Taizhou Huadong Insulation 71 Trench Test Systems 9 27 Tridelta Überspannungsableiter Wellwin Precision Moulds 101 Wenzhou Tenseng Power Systems 69 Wenzhou Yikun Electric 23 111 WS Industries Yizumi Rubber Machinery Front Cover Zhejiang Fuerte 79 Zhengzhou Jingwei Electric 63 Zhengzhou Xianghe Group Electric 56-57 Zibo Taiguang Electrical Equipment 25

INMR Issue 104 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.

Reproduction of the publication, in whole or in part, without express written permission of the publishers is prohibited. While every effort is made to verify the data and information contained in this publication, the publishers accept no liability, direct or implied, for the accuracy of all information presented.

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Everything a Well-Built Network Needs ….

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And All From One Trusted Source Porcelain Hollow & Solid Core Insulators

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EDITORIAL Bad Things Can Happen to Insulators

What makes the insulator so unique in electrical networks is that it is the only component exposed to the full spectrum of possible service stresses.

Insulators are probably the only components in a power system that find themselves continually exposed to the full spectrum of possible service stresses, any one of which can cause them to fail.

These include: high electric field, pollution, wetting events, corona, temperature swings, mechanical shock, interactions with birds and other wildlife, winds, solar radiation, oil leaks, lightning and switching impulse, biological growths, vibration and vandalism. Into this potentially lethal cocktail of stresses, one also has to factor in several added risks: namely that the insulator is defective during manufacture, has been damaged during handling or was not well specified for its service conditions.

Based on all these dangers, today’s low failure rates for insulators might seem nothing short of miraculous.

But miracles have nothing to do with it. The reliability and durability of modern insulators speaks to how well engineered and manufactured most of them now are.

Still, a lot can go wrong and, given their huge population on electrical networks, even low failure rate is no guarantee that there will not be serious problems. And, whenever something bad happens to an insulator, there will invariably be reliability and cost consequences for the affected power system operator.

In this column, I keep words to a minimum and instead present images from our archive that depict some of the many things that can go wrong with insulators. These images, better than words, illustrate why components that account for only some 5 to 8 percent of the total investment in power infrastructure always deserve a disproportionately high level of scrutiny.

Marvin L. Zimmerman mzimmerman@inmr.com

1. Gun enthusiast in Canada seems to have used these breaker bushings for target practice (photo INMR).

2. Puncture near insulator’s live end in spite of special design featuring excess silicone material at ‘triple point’ (photo courtesy of Ofil Systems).

3. Birds in northeastern Australia have used this line post to exercise powerful beaks (photo courtesy of Powerlink).

4. Defective manufacture has made this 500 kV insulator housing crack (photo INMR).

5. Pin post destroyed by radial cracking of porcelain body (photo courtesy of AltaLink).

6. Birds in Brazil coat glass string in highly conductive excretions (photo courtesy of Cemig).

7. Corroded pin on glass disc operating in contaminated coastal/desert environment (photo courtesy R. Znaidi/STEG).

8. Porcelain housing at polluted 230 kV substation in Ontario shows impact from repeated pollution flashovers (photo INMR).

9. Oil leaking onto RTV-coated transformer housing makes it more vulnerable to pollution accumulation (photo INMR).

10. Corrosion of cap of glass disc at substation on Greek Island of Crete (photo INMR).

11. Example of self-shattering of glass insulators on Danish DC line exposed to heavy maritime pollution (photo INMR).

12. Mechanical fracture of 765 kV composite insulator at coastal thermal power plant in South Korea (photo courtesy of KEPCO).

13. Evidence of severe pollution accumulation on cable termination bushing at Oteranga Bay, at southern tip of North Island in New Zealand (photo INMR).

14. Fractured porcelain long rods in Eastern Europe due to defective cement attaching end fittings (photo courtesy of EGU HV Laboratory).

15. Fracture of 500 kV suspension insulator in China due to excess water penetration into interface between rod and housing (photo INMR).

16. Sheds on silicone line insulators show extensive damage due to onset of brittleness (photo INMR).

17. Tearing of sheds on 750 kV silicone insulators due to high winds in Western China (photo INMR).

18. Explosive failure of porcelain housing results in ejection of sharp projectiles at high velocities (photo INMR).

19. Impact of repeated lightning strikes and flashovers (photo INMR).

20. Bird pecking on sheds of 500 kV composite insulators (photo INMR).

21. Dry band arcing on long rod insulators in Israel (photo courtesy of the late Radu Munteanu, Israel Electric).

22. Biological growth on hollow composite insulator installed in Sweden (photo INMR).

23. Pollution from nearby cement factory overwhelmed these glass strings in Tunisia (photo INMR).

24. Corrosion of metal cap on insulator operating in Florida (photo INMR).

25. Self-shattered glass disc in South Africa (photo INMR).

26. Erosion of sheds on silicone housing of improperly specified insulator in a heavily polluted region of Romania (photo courtesy of Transelectrica).

27. Corrosion and self-shattering of glass insulator in Algeria (photo courtesy of R. Znaidi/Sonelgaz).

28. Severe erosion of rubber along shank of composite insulator (photo courtesy R. Znaidi).

29. Insulators barely visible through thick snow coating (photo courtesy of Hubei Electric Power Corp.).

30. Effects of water penetration into internal interfaces of composite 765 kV insulator (photo courtesy of KEPCO).

31. Pitting and cracking of cement of 115 kV porcelain disc insulator due to excessive corona (photo courtesy of Ofil Systems).

32. Interaction with wildlife has caused explosive failure of housings (photo courtesy of FortisBC).

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High voltage testing has undergone remarkable evolution over the past 100 or so years and new technologies are imposing the need for continuing adaptation.

Looking back at the earliest days of transmission, insulators and electrical equipment were verified using only AC or direct voltage tests. In fact, insulation co-ordination was not given much consideration until some time later, mainly because of lack of information on lightning and the surge strength of apparatus insulation. Instead, rule of thumbs methods were used based on experience and ideas put forward by experts. One of the problems, however, was that HV line insulators verified with these tests began to show weakness in service whenever there was lightning.

Evolving HV Testing Adapts to UHV

The solution was to increase dielectric strength by adding more cap & pin discs to the string.

This helped improve reliability of lines but increased problems at substations such as failure of certain apparatus, especially transformers. There was obviously a need to verify the performance of both the HV insulators and the apparatus from the standpoint of lightning surge and this meant that impulse generators became necessary. The first high impulse voltage test was made

by Peek in 1915 although real progress came only after invention of the impulse generator by Erwin Otto Marx in 1924. The ‘Marx generator’ was able to produce high voltage pulses from a relatively low DC voltage supply.

Of course, it was not easy to define an impulse shape that properly represented the complexity of overvoltage caused by lightning. Indeed, a variety of different shapes were proposed in 1931 by the AIEE in the U.S. These eventually converged toward the 1.5/40 μs impulse selected in ASA C68/1-1953, a standard that tried to take representativeness as well as feasibility into account.

A parallel process occurred in Europe. Synthesis of all these proposals was then made by IEC with an agreement to standardize the 1.5/50 μs impulse shape (IEC 60 Standard 1962).

EHV systems started to be developed in the second half of the 20th century. These soon highlighted another weakness of insulators and apparatus, namely external insulation under severe service conditions such as rain or insulator pollution and wetting. Insulation designed and verified from both the AC (dry and wet) and lightning points of view simply did not offer reliable enough service performance. The role played by switching overvoltage (SO) was then recognized along with the fact that its relative impact increases at higher system voltages. Detailed studies were carried out by power utilities in co-operation with manufacturers in order to analyze the wave shape of switching overvoltage. After much discussion, the double exponential 250/2500 μs impulse was selected as representative for the EHV range and standardized in 1973 as part of a revision of IEC publication 60. This provided methods to verify insulation performance under both dry and wet conditions, using standard rain.

Insulator performance under AC/DC voltage and pollution was also investigated at large test laboratories worldwide. In the process, debate soon arose among advocates of salt fog and those who favored other methods to apply pollution deposits prior to testing. Preliminary test procedures were eventually standardized in the same IEC 60 revision (1973) and later consolidated into specific IEC pollution test standards for AC in 1975 (IEC 507) and for DC only by 1993 (IEC 61245) IEC 60 series (now IEC 60060), whose 3rd edition was issued in 2010, however, soon began to show certain weaknesses when applied to UHV. As a result, CIGRE Working Group D1.36 –“Special requirements for dielectric testing of Ultra High Voltage (UHV) equipment” was created to support IEC during another revision of these Standards.

The following aspects, in particular, were seen as deserving special attention in regard to their applicability under UHV: • The difficulty in generating LI waveforms that met the standards due to the high inductance of large test circuits and also to the increased capacitance of the equipment being tested; • The representativeness under UHV of present standardized LI and SI impulse shapes; • The feasibility of rain tests under existing prescribed tolerances, in view of the large size of test objects and the high voltages being applied; • The applicability of present approaches to atmospheric correction.

The conclusions of this most recent work will soon be the topic of a CIGRE brochure and will form the basis for yet another revision of IEC 60060.

Pigini Commentary

This same type of process will likely never come to a complete end. For example, due to advantages offered, the share of organic polymeric insulation (i.e. materials that can age) is increasing in relation to inorganic ceramic materials, assumed never to age significantly. Up to now, most HV tests are made to assess equipment when new and assume that, as in the case of ceramic insulators, performance will not change significantly during time in service. HV tests may therefore not have the same significance for components made using organic materials.

Indeed, there are numerous cases of insulators with unsatisfactory field experience even though they passed all required type tests when new.

Perhaps one of the biggest challenges still ahead will be successfully defining which HV tests are best able to assess expected long-term performance of organic materials, where insulation properties can evolve over time.

Alberto Pigini pigini@ieee.org

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Modern surge arrester designs utilizing metal-oxide (MO) varistor blocks are generally reliable components with very low failure rates. For example, a survey in INMR estimated this at only about 0.1% per year for distribution arresters while failure rate was even lower for station class arresters.

Since an arrester’s primary function is to protect other equipment under all situations, a slightly higher risk of failure compared to other apparatus would seem acceptable. Indeed, the basic philosophy is that arresters should always fail first and, as such, prevent damage to much more expensive equipment. Still, among both manufacturers and users, it is extremely important to ensure that, if overloaded, arresters will always fail in a ‘safe’ manner (see article on p. 102).

Fail Safe Arresters

In standardization work leading up to IEC 60099-4, great effort was devoted to establishing proper test procedures for short circuit testing of arresters. Such tests verify that pressure from an internal fault arc does not lead to violent shattering or to ejection of varistor fragments outside a prescribed area or to a fire that does not self-extinguish. The goal is to eliminate any safety hazard to personnel and also reduce risk of collateral damage to nearby equipment.

In practical terms, this means that an arrester’s design must be capable of releasing the overpressure as well as the arc plasma as soon as possible, e.g. expelling the arc from the arrester body within only some 1 to 2 ms.

When polymeric arresters were first introduced some 30 years ago, manufacturers were quick to claim superior short-circuit performance compared to traditional arresters with porcelain housings. This was due to the fact that the new arrester designs did not have an enclosed volume of gas nor a brittle housing material. It was therefore assumed that there would never be risk of dangerous scattering of material. With field experience, however, it came to be recognized that certain precautions were still necessary to ensure that there would be no risk of explosive behaviour under short circuit.

Short circuit tests on high voltage arresters present a challenge for two reasons: first of all, very large short circuit power is needed to maintain a fault arc of significant length at rated fault current. A supply voltage not far below the rated arrester voltage is necessary in order to avoid suppression of the test current by the voltage of the fault arc. As a rule of thumb, a housing length greater than 1.5 m and a voltage below 77% of the rated arrester voltage are critical in this regard.

A second challenge in testing is initiation of the fault. Polymeric arresters have little to no space between their housing and the metal oxide blocks (i.e. ‘Type B’ in the standard) and must therefore be pre-failed electrically. This implies pre-conditioning the arrester with a high voltage circuit until conductivity increases to the point where it can conduct a current of up to 30 A. Then, within only 15 minutes, the circuit must be changed over to high current. Such short changeover time is necessary because the arrester blocks must not be allowed time to cool and lose their conductivity at the moment the short circuit is applied. The fast transition and the correct measurement of current from mA (during the pre-failing period) to amperes (in the failing phase) to many tens of kA (in the short-circuit phase) is of prime importance. By contrast, for ‘Type A’ arresters with more than half their volume filled with gas, arc initiation during the test is done by means of a fuse wire in a channel drilled through the blocks.

From the World of Testing

A non-standardized and considerably more severe hazard for arresters is failure in series capacitor banks. In such cases, in addition to the power-frequency fault current, a fast and extremely large current will discharge the capacitor bank through the faulted arrester. This situation was verified at DNV GL KEMA’s laboratories in Chalfont, U.S. using type A arresters with 255 kV protective level intended for use in an 800 kV series capacitor bank. A complete capacitor bank was constructed for the tests, able to supply 450 kA of discharge current at 3 kHz. In a synthetic test circuit, such current is initiated by a triggered spark gap superimposed on a 60 Hz current of up to 32 kA from a large generator. The main challenge during testing was in the voltages induced by the capacitor bank discharge current since, at this discharge level, almost 10 kV is induced in every meter of conductor. Only after complete electrical and physical isolation of the test circuit from the laboratory’s secondary and earthing systems could the voltages induced in laboratory equipment be reduced to acceptable levels.

In this case, the polymer-housed arrester design being tested was able to relieve the thermal arc stresses in a controlled and safe way, with only venting diaphragms and light plastic parts found outside the prescribed enclosure. During standard station arrester tests, application of a fuse wire through the center of the MO blocks leads to fractured resistors and the added capacitor discharge causes complete pulverization of the blocks.

Dr. René Smeets Rene.Smeets@dnvgl.com

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At CIGRE’s Study Committee B2 annual meeting in Reykjavik in 2011, Chairman, Dr. Konstantin Papailiou, proposed that all the knowledge generated over the years within different Working Groups, sessions and symposia in the field of overhead lines should be summarized in a single technical reference book. That is now a reality.

The topic of overhead lines is, of course, very broad and brings together different disciplines.

Therefore, the chapters of the book have had to cover the electrical as well as mechanical aspects of a line’s various components, such as towers, foundations, conductors, insulators and insulator sets. At the same time, current relevant issues, including voltage upgrading, have had to be taken into consideration, as were service aspects such as environmental issues, maintenance requirements, etc.

CIGRE Reference Book on Overhead Lines

Given this, the resulting reference book will consist of about 20 chapters and is expected to be published in time for the CIGRE General Session in Paris, this summer. Reference books for other CIGRE fields such as Substations, High Voltage Equipment, Underground Cables etc. are now also in preparation.

Chapter on Insulators I was nominated as lead author for the chapter focusing on insulators, with support from Dr. Papailiou as chapter author. It has been quite an experience to review the many papers, documents and technical brochures written over more than 30 years. In addition, some 70 direct contributions from within the CIGRE community were considered.

The analysis in the chapter focused on insulators soon became closely linked to a review of standardization work, especially given the fact that many contributions by CIGRE go on to become IEC standards. Differentiation of line insulators in terms of their relative risk for puncture is already well known, i.e. the so-called Class A and Class B insulators (IEC 60383-1) reflecting the long rod and cap & pin principles (see Fig. 1).

While standards for these – IEC (60)075 and (60)087 – were first introduced during the 1950s, they have since been updated and replaced by superior versions. Similarly, the first composite insulator standard was launched in 1992 with IEC (6)1109, based mainly on a CIGRE reference document produced a decade earlier by WG 22.10: Technical basis for minimal requirement for composite insulators, published in ELECTRA. Despite the relative lateness of standardization work for composite insulator technology, today the level of standards available for these insulators is basically equivalent to that for traditional ceramic insulators.

Moreover, insulator test philosophies specially adapted for composite types have been proven valid by service experience. Indeed, conventional ceramic and composite insulators have much different failure modes (see page 13). Still, when reviewing problems from the field, the following have been identified as growing concerns for all technologies: • Growing pressure in the industry to reduce costs; • Incorrect specification given actual service conditions; • Design errors by insulator manufacturers; • Inadequate testing (design, type) to the standards – especially for new types; • Improper handling as well as installation.

Composite insulators seem to be especially sensitive to these potential problems.

Fig. 1: Principles of porcelain long rod (introduced 1955) and cap & pin insulators (introduced 1914).

Reporting from CIGRE

Technical Brochure 545 of CIGRE states that the reliability of today’s generation of composite insulators, manufactured in accordance with the latest technology, strict quality control and full traceability, is on the same level as ceramic insulators. Still, it is important to emphasize that attaining this level of reliability will only succeed if some fundamental rules are followed, as shown for example in Fig. 2, applying to line insulators.

The next chapter discusses the damage limit philosophy as an example of fundamental CIGRE work toward a product standard, (with more examples also provided in this new book).

Damage Limit Philosophy of Post Insulators with Fibre-Reinforced Plastic (FRP) Rod The mechanical behaviour of composite post insulators was extensively investigated by CIGRE WG B2.03, chaired at the time by the late Claude de Tourreil. The aim of their work was to document and better understand this failure mechanism and to provide information on suitable test methods toward a respective product standard.

Continues on page 20

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Between 1996 and 2002, there were three main documents published in this regard in ELECTRA. An important technical step was the adoption of a model for damage limit because the FRP rod is ductile, which explains why there is typically no physical separation of the insulating body in the event of mechanical failure, as in the case of porcelain insulators.

As such, there is no risk of catastrophic line drop for a well designed but failing composite post insulator.

Correct insulator & string design

Quality assurance including proof of insulator & string design

Correct handling & installation on site

• Correct force rating & creepage distance, • Use of housing materials with lasting hydrophobic effect and high erosion & tracking resistance (typically silicone rubber with ATH filler), • Use of low seed boron- free E-glass to prevent brittle fracture, • Correct corona protection of the composite insulator set, including against water droplet corona phenomenon, • Co-ordinated corona & power arc protection, if determined by network parameters.

• Installation of only designtested & type-tested units, or units for which the performance can be interpolated from proven and existing designs.

• Established quality assurance system of the manufacturer e.g. ISO 9001: 2008.

• Offer training especially for teams that install composite insulator sets for the first time.

Fig 2: Factors that can impact reliability of composite line insulators.

This behaviour, also referred to as safe failure mode, applies only for solutions with FRP rods. However, this positive behaviour from the line safety point of view also means that the concept of ‘failure load’ cannot be so clearly defined. In particular, the FRP rod of a post insulator can be damaged before a noticeable change occurs in its bending behaviour. This type of damage, which can be caused by so-called micro-cracks in the FRP material, might not influence short-term performance but can nevertheless reduce expected service life. For example, partial micro-cracks can grow in size and trigger discharges that negatively impact electrical (and ultimately mechanical) strength of the material.

It was therefore seen as important to develop a test methodology to establish the mechanical loads at which this special failure mode starts to form in an insulator’s FRP core rod. The damage limit concept employed in this regard builds on the observation that FRP exhibits measurable creep as soon as it has been subjected to constant load. In the case of composite post insulators subjected to bending loads, this leads to a noticeable increase in maximum deflection over time.

Fig. 3: Damage limit description by creep coefficient over bending stress.

Reporting from CIGRE

To better understand this phenomenon, tests were performed on post insulators at different loads and over several weeks.

The change in deflection, Df, was measured over time, t, and an empirical relationship determined: Df = A log t. The values of the coefficient A established in this manner are plotted in Fig. 3. The inclination of the respective curve changes with (nominal) bending stresses of about 500 MPa, calculated at the point of fixing. In the lower stress range, the FRP rod returns to its initial position after a certain relaxation period. For bending stresses above 500 MPa, however, the creep coefficient A exhibits a non-linear behaviour. This means that greater loads (yet still below the failing load of some 800 MPa) lead to failure of the rod within a few days.

The bending stress that separates these two ranges is then referred to as the damage limit stress.

I hope the above introduction entices INMR readers to look more into this fine book on overhead lines. Having already seen other chapters, I can state that it is indeed a comprehensive document with summaries of long-term as well as current topics. All of you are welcome to contact the book authors for questions or suggestions relating to its next edition.

Dr. Frank Schmuck frank.schmuck@sefag.ch

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Back in high school, the chemistry teacher arranged for us to buy the 51st edition of the ‘Rubber Book’, our affectionate abbreviation for the Chemical Rubber Company Handbook of Chemistry & Physics. This delighted my father, who was distressed at the wear I had inflicted on his copy – the 31st edition with its 2700 ‘fragile’ pages. In those days before internet and calculators, the Rubber Book was a reference for diverse tasks including solving definite integrals, reading out the Golden Ratio to 45 decimal places, finding the melting point and solubility of barium fluosilicate, etc., etc. In 1981, I replaced my copy, worn by years of use, with the 62nd edition. It’s still in good condition, but more used these days as a booster seat for my young granddaughter, who wonders why it’s called a rubber book though made of cardboard and paper.

High Voltage Insulation & Rubber Books

CRC Press played another vital role in my developing career: they published references by two of my mentors: A.R. (Bob) Hileman, originally of Westinghouse, and Farouk A.M. Rizk, for many years at Hydro-Québec’s Institute of Research, IREQ. Hileman’s 1999 book, Insulation Coordination for Power Systems, summarized lecture notes from Westinghouse and Penn State University courses. He wrote this after CIGRE and IEEE had each settled on their own methods to evaluate transmission line lightning performance, in Technical Brochure 63 and Standard 1243 respectively. On first inspection, the two methods seem radically different, yet one of the gems in Hileman’s treatment was to demonstrate how closely the two agreed at the end of the calculation.

Whenever I open his book, it seems to fall open to p. 52, which is a general approach to switching impulse strength. Hileman relies heavily on tables, sketches and empirical expressions for ‘Gap Factors’, which relate fundamental high voltage test lab results for the rod-to-plane flashover to practical geometries, notably the strength of a conductor-to-tower window or conductorto-cross-arm on an outboard phase.

Switching surge flashover strength played an important role in development of EHV and UHV transmission lines, with peak interest about 50 years ago. Tests established at the time that increase in switching surge strength did not scale linearly with increasing distance; in fact one of the most common models, U = 3400 kV/(1 + 8/d) where U is flashover strength (kV) and d is the gap distance (m), suggests that application of any voltage exceeding 3.4 MV will flash over to infinite distance. Within its range of valid application, however, the equation served its engineering purpose of motivating power engineers to find how to reduce switching surge magnitudes instead of building super-sized towers. Modern breakers with pre-insertion resistors, station-class surge arresters and EMTP simulations are among the results.

Switching surge flashover engineering may have been stable since the 1970s. However, our understanding of flashover physics, including arc dynamics and corona, advanced considerably during a golden era of high voltage research at IREQ, which included Dr. Rizk starting in 1972 and his co-author, Giao N. Trinh 4 years earlier. Both have long been recognized as IEEE Fellows and by now might have been expected to be taking life easier. However, their collaboration on a new book, High Voltage Engineering, published by CRC Press this April, condenses many insights from their combined 100 years’ experience into only 773 pages.

Calculation of electric fields describes some specific examples, such as Rogowski and Bruce profile electrodes that can be used to ensure that practitioners understand their sophisticated software in a cylindrically symmetric problem before using it in 3-D. There is extensive treatment of statistics for high voltage testing as well. Inside this chapter, I found a nice discussion on the minimum number of tests (9) and also some new insight into the relationship between 1 minute and 30-minute withstand test results.

The extensive work on electrical breakdown of gases is the best place to find the currents associated with various positive and negative corona modes. The treatment of long air gap breakdown is succinct and relies on the close agreement between Dr. Rizk’s continuous leader inception model and test data in the range of 2 to 20m. A comparison of the models for correcting for absolute humidity in the range of 5 to 15 g/m3 highlights another advantage of Rizk’s physical approach. This model is also highlighted in the treatment of lightning attachment, considering the 100m ‘final jump’ from leader to grounded structure as a class of flashover problem.

Transient Thoughts

INMR readers may turn directly to Chapter 10, High Voltage Insulators. I found a new data point for the ratio of non-soluble deposit density (NSDD) to equivalent salt deposit density (ESDD) of about 5:1, 18% ESDD by weight. I also found a satisfactory explanation for a point that has always bothered me. Dimensional analysis suggests a linear relation of ESDD to wind speed and exposure time, but a velocity-cubed relationship was found near the sea. The answer is that the density of salt particles is proportional to the square of wind speed.

The important role of ac re-ignition in the contamination flashover process is clearly identified.

Dielectric recovery across dry bands was one of Rizk’s contributions from 43 years ago but this aspect is still missed when researchers use dc models to fit ac test results. I also enjoyed a practical focus in the section on high voltage testing and measuring techniques related to the currents and voltages induced in signal cables as well as the effect of large HV divider surge impedance. Congratulations to Drs. Rizk and Trinh on their impressive book.

Dr. William A. Chisholm W.A.Chisholm@ieee.org 22 INMR Q2 Issue 104.indd 22

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A variety of factors can impact the reliable operation of transmission lines. Perhaps most significant among these are meteorological events such as lightning, icing, wind and conditions which wet the pollution accumulated on an insulator’s surface.

For example, overvoltage from lightning strike can cause tripping due to flashover or breakdown of the air gap. Similarly, icing can decrease the electrical strength of insulators with the result that flashover occurs even at normal operating voltage – a process known as icing flashover. Conductor galloping due to ice shedding and melting of iced conductors or due to combinations of icing and strong wind often lead to breakdown of the air gap.

Particularly heavy icing can even cause broken conductors or collapsed towers, resulting in prolonged, widespread outages. Sustained strong winds have also been known to tear sheds on composite insulators, requiring them to be replaced.

Insulation Failures Affecting Chinese Transmission Lines

Over the long service life of insulators, pollutants inevitably accumulate on their surfaces, especially in industrial areas, along highways or near the sea. Under conditions of fog, dew or drizzle, this pollution layer becomes saturated with moisture, dissolving any salts and forming conductive paths. Insulation strength decreases correspondingly and pollution flashover can occur at operating voltage. Under such conditions, all insulators in the area tend to be equally affected and attempts to re-close after line tripping tend to fail.

At higher altitudes, low air pressure causes a decrease in withstand strength of the air gap.

Pollution and icing flashover voltages decrease as well, meaning that lines passing through such areas must allow sufficient additional insulation margin.

Other factors also play a role in problems affecting transmission lines. For example, failure to properly trim trees and bamboo forests under transmission lines in China has sometimes resulted in decreased clearance to ground, leading to air gap discharge. Similarly, large birds releasing streamers onto insulators, construction projects too close to lines and foreign objects such as kites attaching to conductors have all had negative impacts on line performance.

Responding to these many possible hazards affecting insulation on transmission lines requires engineers to take proper remedial measures or to improve line maintenance practices.

For example, pollution flashover used to be the single greatest threat impacting Chinese transmission lines. Indeed, the problem was once so severe that it quickly became the focus of much R&D at utilities, line design institutes, universities and research organizations. The result was that appropriate measures were eventually taken, i.e. application of silicone composite insulators and RTV coatings on porcelain and glass strings. Incidence of such failures then decreased dramatically.

Growth in installed generation capacity and rapid network expansion have been key factors in China’s power market these past 20 years.

At the same time, new ±800 kV and 1000 kV UHV projects have helped improve construction practices in general and also promoted a higher level of engineering competence. Still, climate and the other factors discussed above remain ongoing concerns.

In 2012, average tripping rate for Chinese lines ≥ 66 kV was 0.522/100 km-year while outage rate was 0.08/100 km-year. The main causes of tripping in order of importance were: lightning (59.9%), vandalism (19.8%), icing (5%), birds (4%) and air gap breakdown (4%). Trippings related to pollution flashover, however, occurred only 11 times (0.25%). Not surprisingly, incidence of tripping is seasonal, e.g. rate of lightning related trips increases between June and August. This is also the period when typhoons occur, leading to relatively more problems due to tripping from air gap breakdown.

Scene From China

The main causes of transmission line outages in China during 2012, i.e. where there was unsuccessful re-closing, were: vandalism (40.6%), icing (25.9%), lightning (12.6%), and air gap breakdown (10.6%). Because success in re-closing lightning trips is usually over 90%, while lightening ranks 1st among causes of tripping it is only 3rd when it comes to cause of outages. Vandalism and icing play more significant roles.

To decrease power losses linked to the various types of problems discussed above, different special requirements are applicable to insulators. My next column will be devoted to discussing these measures as well as their results.

Prof. Guan Zhicheng Tsinghua University, Shenzhen Campus guanzc@tsinghua.edu.cn 24 INMR Q2 Issue 104.indd 24

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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

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How far from a transformer can arresters be located yet still ensure an adequate margin of protection? The answer is not so simple and requires some explanation. One rule of thumb is “locate the arrester as close to the transformer bushing as possible”. Indeed, this is what I usually recommend, although it is not always possible – especially at higher system voltages.

At 400 kV and higher voltages, arresters become too large to be easily supported by the transformer’s body and must be mounted on separate pedestals. Such ‘extended’ separation distance is also needed in cases where transformers have to be easily moved for repair. Access roads for this purpose can result in up to 30 m of separation of arrester from transformer.

Arrester − Transformer Separation Distance in Substations

Unfortunately, separation distance (or protective zone) of this magnitude can result in reduced protection when a fast rising surge enters the station from an overhead line at nearly the speed of light. When the surge hits the arrester, voltage is indeed reduced – but not to zero and, at best, to the discharge voltage of the arrester. The resulting surge traveling past the arrester is reflected at the transformer, which can result in voltage doubling if the separation distance is sufficiently great. While in most cases reflected voltage only increases incoming surge by a few percent, it is this traveling wave phenomenon and the associated reflection factor that highlight the importance of separation distance.

Help is offered in IEEE’s Application Guide on Arresters C62.22 and a few words of advice are offered in IEC 60099-5. In C62.22, a formula helps determine the maximum distance at which an arrester can be mounted and still achieve a protection margin of 15%. To illustrate how this formula works in graphical terms from my preferred transient program, ATP, simulation results of a substation with arresters located 1 m (Fig. 2), 15 m (Fig. 3) and 30 m (Fig. 4) from the 500 kV transformer bushing. All other parameters are the same and these numbers were chosen only to demonstrate simple insulation coordination in a substation. The arresters are mounted on a pedestal that results in 5 meters from earth ground to the base with their tops located 1 meter from the incoming line.

Fig. 2

Fig. 3

Fig. 4 Fig. 2: Transient voltages in substation with 1m separation distance.

Fig. 3: Transient voltages in substation with 15 m separation distance.

Fig. 4: Transient voltages in substation with 30 m separation distance.

Fig. 1: Typical arrester-transformer configuration in a HV substation.

As shown in Fig. 2, the voltages at the arrester and transformer are, as expected, identical and peak out at 1326 kV. This leaves a margin of protection of 16% for a 1550 kV BIL transformer, which is the minimum recommended according to IEC and IEEE. The simulation in Fig. 3, with 15 m between arrester and transformer bushing, sees margin of protection reduced to only 8%, which is less than recommended but still not above the transformer’s BIL of 1550 kV.

Woodworth on Arresters

Fig. 4 makes it clear that 30 m separation distance would result in the voltage at the transformer exceeding its withstand level (BIL), meaning that a fast rising surge entering the station in such a case could well cause serious damage. Therefore, if for whatever reason it became necessary for the arrester to be located 30 m from the bushing, a transformer with higher withstand (BIL) would have to be specified.

Separation distance is also a consideration with other equipment in the substation. For example, if a CCVT, CVT, PT or breaker are sited at an end point on a short line, they would experience the same excessive transient voltage as shown in the examples of the transformer. An arrester should therefore ideally also be installed to protect them. Indeed, protecting high value assets against transients is an important part of substation design and placing arresters at the proper distance from the equipment they serve is critical to ensuring adequate protection in each case.

Jonathan Woodworth Jonathan.Woodworth@ArresterWorks.com 26 INMR Q2 Issue 104.indd 26

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Paper-insulated cables have a practical service life of at least 100 years and probably more. That makes them by far the most reliable and longest-lasting components found in an electrical grid. But life expectancy, today, is not the only issue facing power system operators – and perhaps no longer even the key issue.

The reason for this is that the public is becoming increasingly concerned about the risk of pollution to groundwater from hundreds of thousands of kilometres of buried paperinsulated cable as well as their accessories.

To give a qualified answer on risk and on whether such concern is justified, it is necessary to look into the design of such cables and the various chemicals used to impregnate the paper insulation. It is also important to distinguish between cables still in use and those that have been taken out of service yet still lie buried in the ground.

Paper Insulated Cables & the Environment

In fact, there are only a few different possible constructions for all the paper-insulated HV and EHV cable still found on the market. These include: 1. low-pressure, oil filled cable; 2. internal gas-pressured cable; and 3. external gas-pressured cable.

Most of these are single-core cables.

In the MV and LV range, the quantity of paper cable now in the ground, particularly in Europe, is enormous and three core designs are the dominant type. The number of different styles for MV applications is limited basically to the belted cable shown below, the threecore single lead sheath cable, and the so-called Höchstädter (H-type) cable. These cables can also be equipped with an aluminium sheath in place of lead.

In the low voltage range, typical construction is similar to what is shown in the photo but with lower insulation thickness and often as a four-core cable.

The usual impregnation compound for paper cables is oil, especially for extra high voltage applications. The oil also has a parallel use for cooling the conductor. In the event of failure, the cable will be switched off immediately, the location of the fault pinpointed and repair soon begun. In such cases, a low amount of leaked oil is certainly possible.

At the end of life, such HV cables do not usually remain in the ground since the need to install replacement cable as well as the large quantities of copper and lead to be recovered are both good reasons to remove them.

However, some 99 percent of all paper-insulated cable still in the ground (in service or outof-service) consists of MV and LV types. For such cables, the impregnation compound can be either draining or non-draining. In the case of a draining compound, the terminations can be equipped with a mass-feeding reservoir to compensate for pressure differentials due to changes in temperature. The viscosity of this compound enables circulation of a small quantity but only once the cable has reached its maximum operating temperature.

In case of cable failure, leakage will amount to only a few ml of impregnation material.

10 kV belted cable is most common paper-insulated cable worldwide.

Focus On Cable Accessories

Over the past 50 years, there has been growing use of mass impregnated, non-draining compound (MIND) cables. This material is a kind of grease and, even at maximum temperature, cannot become fluid. Therefore, no leakage occurs in the event of failure.

Similarly, in the case of all MV and LV paper-insulated cables that are out of service and at normal soil temperatures, the viscosity of the compound is so high that no draining into the ground is possible. Therefore, all that is required is sealing their ends using a watertight end cap.

Based on the above considerations, it does not seem justified to be concerned about serious adverse environmental effects arising from use of paper-insulated cables.

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

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www.inmrlaboratoryguide.com

New Web Site Devoted to HV/HP Laboratory Testing

A

fter a period marked by overcapacity, consolidation and closures, the business of laboratory testing seems again on firm ground. Demand for testing is growing linked to a global resurgence in building new lines and substations as well as the refurbishment of old networks across Europe and North America. At the same time, as discussed in Alberto Pigini’s Commentary (page 14), the testing field has evolved over the decades and continues to do so even today.

For example, there are emerging new standards and test requirements, especially in the expanding domains of DC and UHV. Over the decades, the typical business model for HV & HP testing laboratories has also changed. For example, if there is any lesson to be learned from the experience of the past decade it is that a test laboratory can no longer survive by serving a narrow base of customers. One has only to look at the sad demise of the British Short Circuit Test Station, once part of mighty engineering giant, Reyrolle – a company that at its peak employed 12,000 people manufacturing switchgear for power stations worldwide. The adjoining Clothier Laboratory opened to much fanfare in 1970 and was at a time the only site of its kind in the UK, carrying out work mainly for Reyrolle and its various successors but also the National Grid and other British network operators. In recent years, as nearby manufacturing of HV apparatus evaporated into almost nothing and with relatively little new local power infrastructure, the facility began losing money even as it needed substantial investment to remain competitive. It barely survived past its 40th anniversary VIP celebration.

Just like in all other segments of the power industry, commercial success in laboratory testing today requires becoming a truly global player, able to respond to the needs of diverse customers across many markets. It is with recognition of this fact that INMR has established a new web site that will help everyone involved in this business. For users of laboratory testing services, inmrlaboratoryguide.com will serve as a convenient one-stop portal to identify all the key laboratories worldwide as well as their various testing capabilities. For testing laboratories, this new web site will help the industry share information and better understand its competitive environment. Please visit: www.inmrlaboratoryguide.com for all your testing information needs.

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UTILITY PRACTICE & EXPERIENCE

Canadian Power Utility Entering Final Phase of Investment in Network Infrastructure AltaLink, the largest electricity transmitter in Canada’s western province of Alberta, operates in a geographically diverse area. Terrain ranges from desert to plains, from foothills to towering mountains – all with a number of additional ‘microterrains’ sandwiched between. There are also a myriad of crisscrossing oil and gas pipelines to contend with.

The unpredictable weather also includes periodic hail, snow blizzards, freezing rain, thunderstorms and even the occasional tornado.

Against this backdrop of varied landscape and highly changeable climate, AltaLink is now nearing completion of what it refers to as ‘the big build’ – its largest ever expenditure on reinforcing a transmission backbone The diverse topography of this service of over 12,000 km of lines and some 280 area together with the northerly location substations. This investment, results in the network experiencing amounting to more than $4 billion over winter temperatures that can drop as a three-year period, focuses on low as -50°C but which also climb to reinforcing the 500 kV, 240 kV and +40°C in summer. Moreover, strong 138 kV systems. It follows a period of westerly winds known as chinooks can mostly stagnant spending during the attain speeds up to 150 km/h and have 1990s, and has been prompted by been known to raise temperatures by demand spurred on by a booming over 20°C in just an hour. natural resources sector.

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In expanding and reinforcing the network, AltaLink engineers face an array of challenges that can adversely impact performance, from conductor galloping to flashovers, from pole fires to occasional vandalism. Also, as in many other places, there are difficulties in obtaining public approvals for new construction and these dictate how some line sections have to be designed.

INMR travels to Calgary to meet project engineers and supervisory staff involved in two of AltaLink’s most important recent investments – the 500 kV Heartland Transmission Project and the ±500 kV Western Alberta Transmission Line (WATL) Project.

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Photo: INMR ©

Problems with conductor galloping in Alberta typically occur in April and May due to critical combinations of ice and wind.

Background

Ask any engineer at AltaLink about the problems facing the overhead network and the reply is almost certain to include the term ‘galloping’. This seems almost a strange destiny if one considers that Alberta is Canada’s ‘wild west’ with its annual Calgary Stampede, cowboy hats and largest indoor stadium known as the Saddledome.

Tyson Harper, a Project Engineer in transmission, explains that galloping problems in Alberta tend to be concentrated during April and May when there is a critical combination of ice forming and high winds. He

Photos: courtesy AltaLink

reports that a family of specially strengthened towers has recently been developed to better cope with these stresses and to improve their ability to handle icing up to a radius of 70 mm. Specifications for related line hardware have also been raised beyond typical ANSI requirements to 300 kN and even higher. Harper also points out that while interphase spacers are installed on some lines, these do not stop galloping but rather prevent the phases from clashing during galloping conditions and thereby reduce related outages.

Example of winds impacting overhead line in Alberta.

Galloping of 240 kV and 500 kV lines has also been dealt with by

Insulators on lines running alongside major roads face contamination from salting during winter.

increased application of self-damping wires, which are lighter than conventional conductors and where the inner core is free to move inside the outer jacket. Tighter stringing and lower structures then become possible.

While Alberta is classified by the Canadian Standards Association as a light pollution area, localized contamination is another issue that affects network performance.

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About 70 percent of line outages at AltaLink are caused not by pole, hardware or conductor failure but rather by problems with insulators.

Quality of work on new lines is supervised by Altalink engineers in Project Engineering Services.

During winter, roads and highways are heavily laden with salt that invariably finds its way onto lines running parallel to thoroughfares.

Insulation is also affected by dust from gravel roads as well as from farming practices such as turning fields and spraying fertilizer. Some

Photos: INMR Š

Towers on new WATL HVDC line are insulated entirely with glass as is 500 kV Heartland line.

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lines, especially those supplying customers in the petrochemical sector, face pockets of even heavier contamination.

Transmission Engineer Shantha Samarawickrama works in Project Engineering Services, a department that provides expertise for the more than 100 ongoing and recently completed projects that have made up AltaLink’s ‘big build’. In this role he is tasked with working with the utility’s various EPC providers to ensure the quality of lines that are constructed. He also provides support to deal with unexpected situations such as when two lines must cross.

Samawickrama explains that while there are standards that govern each aspect of new line construction, utilizing specific contamination studies is still a relatively new practice in Alberta. For example, there is still no overall pollution map of the province that could assist in selecting the most suitable insulator geometry and creepage distance for each region. In the past, adjusting to localized pollution has therefore been done on a more or less empirical basis.

While most of the AltaLink overhead network still relies on porcelain insulation that has dominated for many years, use of toughened glass is now growing. For example, both the new 500 kV Heartland Line and the WATL HVDC line are insulated entirely with glass.

Flashover likely due to lightning strike combined with punctured or defective porcelain discs. Note how arc shifted direction twice as it traveled up string.

According to Sr. Transmission Lines Engineer, Dimitri Georgopoulos, historical records have shown that about 70 per cent of line outages at AltaLink are caused not by pole, hardware or conductor failure but rather by problems with insulators.

“The weakest link always seems to be the insulator,” he remarks.

“For this reason, one of our recent maintenance goals has been to keep records on all our insulators – including location, type, brand and date of manufacture. For example, he reports that many pin as well as string insulators were installed during the 1970s and 80s, when there were widespread problems of poor quality porcelain that suffered from high rates of puncture and cement growth.

While AltaLink has also made use of silicone insulators, this has been mainly for line post retrofits at 69 kV

Photo: courtesy AltaLink

Photos: courtesy AltaLink

Pole top fires triggered by combinations of localized pollution and poorly performing insulators.

Pole top and cross-arm fires are an example of an ongoing problem linked directly to localized contamination combined with poorly performing old porcelain insulation.

39

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500 kV silicone insulators used on slack span entering Ellerslie substation.

same – heavy wet snow that sticks to insulators and becomes the critical wetting event. This leads to tracking but does not usually trip the line until a pole fire has erupted. Glass insulators are now being installed in place of porcelain to reduce prevalence of this problem since they are easier to inspect.

Photos: INMR ©

and 138 kV or where there have been isolated pockets of vandalism.

Silicone insulators are also being used routinely these days on slack spans entering substations since engineers have found that glass or porcelain strings tend to ‘fold up’ under lower mechanical tension. The same has applied for applications where conductors are comparatively light.

Given the localized contamination, AltaLink carries out insulator washing on selected lines. This is done mostly during the summer, either by helicopter or from the ground, and Samarawickrama explains that establishing which lines need to be washed is based on reviewing past problems. “We focus our washing on lines that have higher risk of experiencing flashovers and outages,” he says. “Affected towers are identified and field crews are dispatched to establish what triggered the flashover, whether birds, pollution or vandalism.”

Pole top and cross-arm fires are an example of an ongoing

Recent Projects problem linked directly to localized contamination combined with poorly performing old porcelain insulation.

According to Project Engineer Jason Dwyer, this mostly affects lines running near highways and the underlying cause is often the

“When we put up a new insulator string it must be completely clean and free of road salt that may have fallen onto it and which might lead to tracking from the start.”

Among the most important of the new construction projects at AltaLink has been the 500 kV Heartland Line.

Energized at the end of December last year, it runs some 65 km north from the recently expanded Ellerslie Substation in Edmonton to an entirely new substation called Heartland. From here, part of its projected 6000 MW capacity will be transmitted along 240 kV lines to refineries in Fort McMurray – center of Canada’s huge oil sands development. The Heartland Transmission Project also includes a 54-structure section of 240 kV double circuit lines, energized in November 2013.

Kevin Munroe is an AltaLink field inspector who monitors the quality of work being performed by subcontractors who build new lines or carry out retrofits to the network.

Looking back at the experience with Heartland, he explains that among the biggest hurdles was managing the crossing of over 50 different pipelines along the line’s winding route. Other obstacles were preexisting 138 kV and 240 kV lines

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Heartland line enters Ellerslie Substation. For reliability reasons, 500 kV gas-insulated line was selected in place of busbar or cable alternatives while also allowing for lower incoming 500 kV towers.

Photos: INMR Š

Photos: INMR Š

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Special composite structure (right) was used on pre-existing line to deal with induced currents from overhead conductors of Heartland line.

Photos: INMR Š

Heartland Line section passing through residential area of Edmonton features elegant steel structures for tangent as well as angle towers.

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that had to be passed and where a range of additional engineering challenges had to be met.

For example, at one crossing near a newly built highway interchange there was concern that induced currents from the new 500 kV line might dry out the wood on 240 kV poles located directly below and increase the risk of fire. The solution was to go instead with either fiberglass or steel structures and, because of lead-time issues, the former was eventually adopted.

extensive mechanical testing by the foreign-based supplier and that he is satisfied with the end result.

According to Samarawickrama, AltaLink is now studying expanded application of other families of such non-lattice towers to help in construction of new lines in similar situations.

Munroe notes that construction at AltaLink is done year-around, even during winter when wind chills send temperatures plummeting and powerful wind gusts can ground

To meet aesthetic concerns with low visual impact towers and facilitate obtaining public approvals, a whole new family of single pole structures was developed. Project Engineer Dwyer reports that this work involved

helicopters. To facilitate site access under such conditions, special mats made of rows of linked wooden poles allow passage of incoming heavy equipment to clear snow or to erect towers as well as to mount insulators and line hardware. Conductor stringing is assisted by helicopter.

AltaLink’s new ±500 kV WATL line, now under construction, provides a good example of construction proceeding even under difficult wintery conditions. This ongoing project is insulated with 34 standard profile bells per string for each pole and 7 on the neutral.

Prior to arrival of the helicopters that do the lifting, crews assemble the glass discs on tarpaulins to avoid contact with the ground. Each

Construction in progress on WATL. Helicopter stringing assisted by mechanical device mounted onto dollies.

Photos: courtesy AltaLink

Photos: INMR ©

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Examples of special foundations used on Heartland (top) and screw pile foundation used for WATL. Photos: INMR Š

Strings assembled on tarpaulins, which are then wrapped prior to being hoisted by helicopters.

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All line hardware on WATL and also Heartland line must be certified corona-free.

assembled string is then wrapped to protect it from construction dust until ready to be lifted, at which point the wrapping is removed.

Insulators arriving and stored at the site are also factory-packed in closed boxes to prevent contaminants from being deposited during transport.

Says Munroe, “the key is that when we put the insulator string up it must be completely clean and free of road salt that may have fallen onto it and which might lead to tracking from the start. Washing is relatively expensive, so we want to be sure that every new line starts out with the insulators perfectly clean.”

Corona is another concern from the standpoints of noise as well as the risk of damage to silicone insulators that are now routinely used on slack spans at substation entrances.

Munroe reports that every structure on WATL will be equipped with corona rings up to three meters in diameter, depending on type, and which have been specially designed and tested by the supplier in Europe.

Moreover, all line hardware, including

Photos: INMR ©

All line hardware on WATL, including conductor saddles and spacers, is required to be certified corona-free.

conductor saddles and spacers, is required to be certified corona-free in terms of smooth surfaces with no rough edges. Even a protruding manufacturer name sticker has been known to cause noise.

Munroe reports that this corona-free requirement applies to hardware used on the 500 kV Heartland Line as well and is now even being demanded for new 240 kV lines. He also states that AltaLink’s standard is that all hardware, including the armor rods that help damping and prevent fatigue failures, must be tested for 47

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cold weather shock loading. This is done to ensure that the steel always remains ductile, even at service temperatures down to -50°C. From a maintenance perspective, Munroe notes that it would be normal to inspect a new transmission line such as WATL annually, using various types of patrols. He also explains that additional corona and infrared cameras have recently been purchased to assist in helicopterbased inspections, looking for defects such as nicks in wires or sharp edges that might create corona.

Photos: INMR ©

The various remedial measures to deal with past problems as well as all the investment recently made in new lines seems to have already had an large impact on performance of AltaLink’s overhead network. “There’s no question that our system has improved a great deal compared to 10 years ago,” observes Munroe, whose view is only made more credible by his many years in the business. “AltaLink now has strong reliability,” adds Dwyer, “and we feel that our network performance is impressive, especially if you consider the age of our system as well as the varied geography and difficult climate where it operates.” 

Views of new 500 kV Heartland Substation. Note silicone housed arresters (top) transformers (center) and busbar supports (below).

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UTILITY PRACTICE & EXPERIENCE

Composite Bushings with RTV Coatings Combat Pollution at Substation in Israel

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T

he power system in Israel operates in a sub-tropical as well as desert environment. A long dry season lasts some eight months during which all types of contaminants – from marine to dust to industrial and agricultural – accumulate on insulators. This pollution layer tends to be adhesive and is therefore only partially removed during the four months of rain that follow.

Responding to unacceptably high levels of outages triggered by pollution flashovers during the early to mid 1990s, Israel Electric (IECo) became among the first utilities in the Middle East to research and eventually embrace widespread application of composite line insulators. Today, these represent a large and still growing proportion of the insulators on the overhead network, from 22 kV to 400 kV. Until now, however, there has been hardly any use of composite insulator housings for apparatus such as bushings and transformers. Rather, the preferred countermeasures at substations affected by pollution have included washing and, more recently, application of RTV silicone coatings.

Photo: INMR ©

INMR visits the 170 kV Alon Tabor Substation, in the northern interior, where localized pollution from nearby cooling towers presents a constant challenge. In 2000, this became site of IECo’s first application of silicone-housed GIS bushings. But what makes the installation even more noteworthy is the fact that, as with all porcelain at the substation, these composite insulators have recently also been coated with RTV silicone.

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To help maintenance staff monitor the condition of equipment, Israel Electric relies on teams of specialists who conduct inspections using various diagnostic tools.

As Manager of Substations for Israel’s Northern Region, Amir Rozenstein is responsible for ensuring the reliable operation of a broad range of HV apparatus. “We have quite a mix of equipment at our substations and from many different suppliers,” he says. “That makes it all the more challenging for us to be able to identify and respond to any developing problem before it becomes critical and leads to costly failure.”

In order to assist maintenance staff to monitor the condition of equipment, IECo relies on teams of predicative maintenance specialists (SPDMs) who conduct periodic substation inspections using a variety of diagnostics, including thermal, acoustic, ultraviolet and visual. Findings of any incipient problem are then communicated to Rozenstein who must schedule the appropriate remedial action in a timely manner.

Rozenstein explains that like most power utilities these days, IECo is focused on reducing expenses such as washing in spite of operating in a warm coastal environment marked by plenty of dust. For example, he says that much of the country’s 400 kV system needs to be washed twice a year and, apart from the direct cost, lines and stations typically have to be taken out

Photos: INMR ©

Dust on porcelain long rods in Negev is typical of that impacting many lines in Israel.

Comparison of porcelain insulator strings by day and during onset of early morning wetting by dew.

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Photos: courtesy of Israel Electric

Examples of inspections performed by predictive maintenance specialists. of service in the process since the water used is not demineralized.

One of the strategies to optimize maintenance costs has been to prioritize which lines are in greatest need of washing and at what specific intervals. This task has been accomplished in co-operation with the Transmission Team, based largely on helicopter inspections using infrared and ultraviolet cameras. At the same time, starting from the early 2000s, IECo made a strategic decision to adopt composite designs as the standard for most new insulator purchases since these were expected to require little to no washing.

At substations, dealing with pollution has also shifted progressively away from scheduled washing. However, unlike the case for overhead lines, the transition has been almost entirely toward coatings applied to porcelain insulators rather than use of composite housings.

Rozenstein explains that this process first began more than 20 years ago with silicone grease but has since focused on RTV material due to problems linked to having to change the grease about every 3 years.

RTV coatings were found to remain effective in suppressing leakage current even after 6 years of operation in one of the most severe service environments imaginable.

Photos: INMR ©

The decision to rely heavily on RTV silicone, notes Rozenstein, was based largely on tests conducted at one of the network’s most heavily polluted sites – an open air substation located less than 200 meters from a factory for alkali salts on the Dead Sea (at -427 m also the lowest point on earth). Here, RTV coatings were found to remain effective in suppressing leakage current even after 6 years of operation in one of the most severe service environments imaginable.

Arie Avner, from IECo’s Maintenance Dept., reports that coating porcelain insulators at substations affected by pollution has been ongoing now for over 10 years and

Israel Electric was among first utilities in region to employ composite insulators in polluted areas and for compact lines.

55

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Photos: INMR ©

Composite double strings with shorter arcing distance are increasingly replacing porcelain long rods.

indeed is still underway. “Experience overall has been positive,” he says, “and we have found that coatings solved a lot of the problems we had 15 to 20 years ago.”

Still, the performance of coatings is being monitored closely. In the northern region, for example, Avner explains that inspectors are sent to coated substations at least twice a year – usually before summer and again before winter – at a time of day when humidity levels are high. Their task is to verify coating performance by monitoring partial discharge activity both acoustically and visually. In cases where the coatings are found insufficient to deal with the level of accumulated pollution, washing is conducted at low pressure so as to remove surface dust but not risk causing permanent damage to the coatings.

A widespread problem that affects line insulators at IECo relates to large populations of birds that follow annual migration routes from Siberia to Africa. Avner reports that the locations of unexplained momentary outages with successful re-closing have confirmed that these were typically linked to excrement streamers from these birds. Cover type wildlife protective devices have then been installed on affected towers but apparently

Photos: courtesy of Israel Electric

Examples of early problems at IECo with certain composite insulator designs.

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Photos: INMR ©

RTV silicone coated substation alongside heavy industry area on Dead Sea.

needed removal each year for cleaning. According to Avner, neither noise nor special lighting were successful in discouraging bird perching so other solutions were looked at, including installing platforms away from the insulator assemblies. Another solution has been creating special pools near affected towers where birds can be encouraged to stop instead.

One of the more unusual challenges recently confronted

by Avner and his maintenance team has been at the 170 kV Alon Tabor Substation, site of IECo’s first installation of silicone-housed bushings. Commissioned in 2000, the hybrid GIS station underwent a sudden change in pollution exposure in 2008 due to construction of a nearby gas turbine generation facility.

The cooling towers at this plant employ saline water with high conductivity (estimated as much as 30,000 mS/cm) and which is then blown as a fine spray toward Alon Tabor by strong prevailing winds. This makes the station’s dusty service environment much worse. Indeed, Avner reports that pollution flashovers occurred on an inverted porcelain post insulator supporting the conductor in 2009 and then again in October 2012 on one of the transformer bushings located below it.

These types of problems eventually led his team to grow concerned that the silicone-housed GIS bushings might be ageing prematurely in the aggressive service environment – in spite of the fact that there had not been any flashovers and that nothing unusual had yet

Coated substations are inspected at least twice a year to verify performance of the coatings by monitoring partial discharge activity both acoustically and visually.

RTV-coated surge arresters and bushings at Alon Tabor Substation.

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been reported in their years of operation. Indeed, Avner reports that close-up inspection in March 2012 revealed what appeared to be localized patches of erosion on shed edges and along the trunk near the bottom flange on 2 of the station’s 42 bushings.

Streamers from large migratory birds trigger flashovers of composite insulators and lead to momentary outages on lines.

Note perpendicular perching platforms used to keep birds away from insulators.

Photos: courtesy of Israel Electric

Photos: INMR ©

“We came to the conclusion that droplets of the highly conductive water falling on the bushings were causing tiny pinhole type defects in the silicone housings due to high acidity.”

Says Avner, “based on this, we decided to send one of the units to our R&D laboratory for more thorough investigation. They concluded that droplets of water falling on the bushings might be causing tiny pinholes on some sheds due to the high acidity.” This conclusion, he notes, was reinforced by an unrelated finding from an SPDM team that visited Alon Tabor as part of their usual monitoring duties. Visual inspection using highpowered binoculars revealed that water vapor from the cooling towers was also causing expansion damage to the cement in porcelain string insulators used between towers at the substation.

Avner goes on to state that, to avoid any risk of continuing degradation, a decision was made late in 2012 to apply RTV coatings to the bushings – in spite of their being siliconehoused. He says that applying the

Avner (left) and IECo Transmission Team Head, Alex Levinzon, look toward cooling towers located upwind of Alon Tabor Substation.

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insulator manufacturers may question such a need, suppliers of coatings take a different perspective, seeing addition of RTV material as a tool to enhance the inherent hydrophobicity of composite insulators made from LSR or HTV. Some suppliers point to recent projects where customers have insisted on coating silicone insulators before they were put into service.

Alex Levinzon, Transmission Team Head and also Chairman of the Israel-National Committee at CIGRE, sees the situation at Alon Tabor as a good example of how IECo is modifying its maintenance based on accumulating service experience. “The key goal,” he says, “is to adjust past practices based on new technologies as well as our growing body of field experience. That is how we can succeed to reduce costs while still maintaining the high reliability demanded by customers.”

Inverted station post and bushing (center unit) that flashed over due to construction dust and salt spray from nearby cooling towers.

Levinzon points to new locally developed leakage current monitoring systems already in operation on 161 and 400 kV lines across Israel as an example of how IECo is trying to accomplish the goal of optimized maintenance scheduling. According to Levinzon, these devices

coating was regarded as offering an immediate solution to the pinholes.

Photos: INMR ©

The entire subject of applying RTV coatings to silicone composite insulators still remains an open question since there seems relatively little field experience on which to base any conclusions. While many silicone

Salinity of spray from cooling towers evident from impact on arrester flanges and steel support structure.

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Photos: INMR ©

Close up of RTV-coated GIS bushing (March 2014).

Note: rounded shed indentations near the flange do not appear to be due to erosion but rather to how coating was applied.

Photos: courtesy of Israel Electric

have already proven successful in alerting staff to imminent problems with ceramic insulators that have excessively high levels of contamination. Additional such units are planned for installation on lines equipped with silicone rubber insulators. “We have found that silicone insulators covered with sand sometimes lose their hydrophobicity and self-cleaning ability and flashover during the early morning hours, especially near the seacoast,” says Levinzon. “These devices will alert us whenever there is such a danger and a critical need to wash them.”  Past research at IECo has monitored impact of heavy dust layer on hydrophobicity of silicone insulators.

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UTILITY PRACTICE & EXPERIENCE

Selective Application of EGLAs on Transmission Lines in Malaysia Malaysia’s power system operates in a region of intense lightning activity that adversely impacts performance of certain lines operated by the country’s grid operator, Tenaga Nasional Berhad (TNB). Among the lines most seriously affected by lightning are the 132 kV Kuala Krai to Gua Musang line located in the northeast and the 500 kV Ayer Tawar to Bukit Tarek line which runs along the western coast of the Malay peninsula.

program of selective installation of externally gapped line arresters to reduce the rate of lightning related trippings on these two lines.

Different approaches were applied in each case since the 132 kV line had already been equipped with EGLAs since 2007 yet continued to experience lightning flashovers. By contrast, the 500 kV line was part of an ongoing TNB project to reduce the This article, contributed by Senior Engineer, rate of trippings due to lightning through Iryani Mohamed Rawi, discusses a recent cost-effective installation of line arresters.

Photo: courtesy of TNB

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Background on 132 kV Kuala Krai-Gua Musang (KKRI-GMSG) Line This 113 km double circuit line was commissioned in 1995 and consists of 295 towers. Between 2001 and 2012, it recorded a total of 53 trippings, most of the double circuit type. This translates into a tripping rate of 4.26/100 km-year – considered unacceptably high when compared to TNB’s average for such lines of 1.8/100 km-yr. Acceptable tripping rates for 132 kV lines at most other utilities are reportedly between 1.5 and 2.8/100 km-yr.

Background on 500 kV Ayer Tawar-Bukit Tarek (ATWR-BTRK) Line The 145 km 500 kV ATWR-BTRK line consists of 352 towers and in recent years experienced trippings at a rate of 1.532/100 km-year. This rate was also considered too high, as an acceptable rate in the case of such important lines should be less than 1/100 km-year.

Photo: courtesy of TNB

A study was therefore undertaken with the goal of explaining the seeming ‘ineffectiveness’ of more than 120 line arresters (TLAs) installed on this line between 2007 and 2012. In theory, an increasing population of TLAs should have reduced line flashover rate. Yet, for this line, flashover rate increased.

In both cases, it was regarded as necessary to analyze historical line performance in order to find the best way to reduce nominal tripping rates to more acceptable levels.

Geographic Profiles of Lines The 132 kV KKRI-GMSG line is located in a ‘mixed area’ comprising the town of Kuala Krai, flat land and dense jungle around Gua Musang. A total of 154 towers (52%) are located in flat areas while 139 towers (47%) are in jungle. The remaining two towers are near substations.

In the case of the 500 kV ATWR-BTRK line, 40% of towers are located in hilly areas (i.e. at higher altitudes).

determined for both. Figs. 2 and 3 are charts showing altitude and TFRs for the different tower locations along each.

To better understand soil conditions along the two lines, tower footing resistance (TFR) values were

As evident from Fig. 2, TFR for the 132 kV line is typically higher at lower altitudes and vice versa.

Typical suspension tower on 500 kV ATWR-BTRK line.

Fig. 1: Tower design of 132 kV and 500 kV lines at TNB. (a) 132 kV standard suspension tower, (b) standard 500 kV suspension tower, (c) special phase transposition (TP) towers erected at only five locations.

(a) 132 kV L/LS

(b) 500 kV LS

(c) 500 kV TP 67

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(both single and double circuit variety) as well as respective GFD values for the KKRI-GMSG and ATWR-BTRK lines are presented in Tables 1 and 2.

For the 500 kV ATWR-BTRK line, 19 tripping have been recorded since 2002 which included a double circuit tripping (DCCT) in 2004. It can also be seen that 8 trippings occurred on Circuit 1 while 11 were on Circuit 2.

This results in a tripping rate of 1.532/100 km-year, which is unacceptably high compared to TNB’s overall average of 0.9/100 km-year.

Base of tower on 500 kV ATWR-BTRK line

Fig. 3 shows that TFR values for the 500 kV line increase in higher altitude areas. This usually means very poor lightning performance since the line becomes the main target for lightning.

In the case of both lines, higher GFD was detected in areas with higher altitude (near GMSG for the 132 kV line and around BTRK for the 500 kV line. This only served to worsen lightning performance.

Ground Flash Density

Tripping History

Another important factor considered in reviewing past performance was historical data on lightning activity along the two lines. Ground flash density for both is presented in Figs. 4 & 5 although, due to limited availability of data from the lightning detection system, only several years of information was available for comparison.

Due to high isokeraunic levels in Malaysia, lightning has always been the single major cause of trippings on overhead lines at both transmission and distribution voltages. Fig. 6 depicts the lightning flashovers recorded since 2001 that caused such lines to trip.

According to TNB’s Centralized Tripping Information System, yearly tripping occurrences since 2001

Fig. 2: Tower footing resistance and altitude of 132 kV KKRI-GMSG line.

In 2012, total tripping rate on the 500 kV line was reduced to zero (even though GFD value remained high) because of a major tower footing resistance job exercise carried out along its entire route.

Moreover, because of a special fault location system installed at the time, it became possible to determine the exact site of every line trip (see Fig. 7).

Simulations In conducting insulation coordination studies, it was decided that TFlash software would be used for the 132 kV line and others where there were no special requirements.

For the 500 kV line, however, TFlash, SIGMA SLP, PSCADD and EMTP software were selected to best aid in such areas as selecting which towers were the best to install the TLAs, which would be the proper

Fig. 3: Tower footing resistance and altitude of 500 kV ATWR-BTRK line.

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Fig. 4: GFD map for 132 kV KKRI-GMSG line.

Fig. 5: GFD map for 500 kV ATWR-BTRK line.

No of tripping

phase(s) for each such installation as well as required arrester energy handling. In the case of both lines, only externally gapped line arresters (EGLAs) were specified due to their perceived advantages from the perspective of TNB’s network and service environment.

132 kV KKRI-GMSG Line Using TFlash software, line performance was compared both before and after installation of EGLAs. Results from the overall 11-year service performance study are shown in Fig. 8.

Year

Fig. 6: OHL tripping due to lightning at TNB.

It is clear that, with increasing GFD value, total trip rate of the line increases although there was no data for comparison purposes for 2001-2003 and 2005.

Table 1: 132 kV KKRI-GMSG Tripping & GFD History

Table 2: 500 kV ATWR-BTRK Tripping & GFD History

YEAR

TOTAL

SCCT

DCCT

2001

1

1

2002

5

2003 2004

GFD (Fl/km2-yr)

YEAR

TOTAL

SCCT

DCCT

Lowest

Highest

0

N/A

N/A

2001

0

0

1

2

N/A

N/A

2002

2

3

1

1

N/A

N/A

2003

2

0

1

5

20

2004

2005

18

2

8

N/A

N/A

2006

1

1

0

10

2007

4

0

2

0

GFD (Fl/km2-yr) Lowest

Highest

0

N/A

N/A

2

0

N/A

N/A

0

0

0

N/A

N/A

5

3

1

8

40

2005

1

1

0

N/A

N/A

25

2006

1

1

0

8

32

16

2007

2

2

0

9

24

2

2

0

3

24

2008

7

1

3

4

20

2008

2009

4

2

1

0

20

2009

0

0

0

3

24

2010

0

0

0

0

6

2010

4

4

0

0

10

2011

4

0

2

0

15

2011

2

2

0

6

20

0

8

0

20

2012

4

2

1

TOTAL

53

11

21

2012

0

0

0

TOTAL

19

17

1

Note : Data not available for 2001-2003 and for 2005.

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Figure 8 also shows that, in spite of a growing population of TLAs installed throughout the line, there was no accompanying reduction in tripping rate. This result was unexpected, as more TLAs should have reduced total trip rate and improved line performance.

Fig. 7: 500 kV ATWR-BTRK locations of trippings.

TFlash simulation was also carried out on performance each year i.e. with changing yearly GFD values.

Results showed a similar pattern and correlated with actual data, which means that the simulation was close to the real situation.

500 kV ATWR - BTRK Line TNB had never before installed TLAs at 500 but this line was deemed an exception due to tripping occurrences that were regarded as unusually high and unacceptable.

Moreover, it would normally have been preferred to improve tower footing resistance (TFR) before going with the TLA option due to the relatively high cost of such arresters as well as the difficulty in scheduling a temporary shutdown of such an important line for the purpose of their installation.

However, because this line had a history of high annual tripping,

Fig. 8: 132 kV KKRI-GMSG line performance with maximum GFD value and total TLAs installed.

Fig. 9: TFlash simulation versus actual results.

Typical EGLA installation on 132 kV KKRI-GMSG line.

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Option 4

management decided in favor of EGLAs, but only for the most critical towers with extremely high TFR values. Therefore, different software was used to simulate the line and help in selecting the best tower locations with the goal of optimizing installation so as to best control costs. a. EMTP Software With help from an OEM, a simulation using EMTP software was conducted and the results are show in Table 3.

Table 3: EMTP Simulation for 500 kV ATWR-BTRK Line Case

Option 1

Option 2

Option 3

Installation position of EGLAs

F/o rate (100km-yr)

DCCT

2.92

0.33

0.18

0

SCCT

2.92

1.63

1.28

1.28

The simulation conditions used were: • Footing resistance = 2.2Ω; • GFD = 20 flashes/km2-yr; • EGLA installation rate for Options 2, 3 and 4 = 100% (all towers).

The best installation option involved installing TLAs on all phases of one circuit, which would result in zero DCCT trippings (even though some SCCT tripping would be unavoidable).

Table 4: Sigma SLP Simulation for ATWR-BTRK Line SEC

TOT

BFR

SFFR

Single

Double

1

0.49453

0.432457602

0.062068

0.442434

0.048348

2

0.54375

0.524442624

0.019303

0.462105

0.081641

3

0.34771

0.248930358

0.098786

0.315427

0.024541

4

0.03199

0

0.031992

0.026326

0

5

0.05065

0

0.050659

0.028

0

6

0.03119

0

0.03119

0.019649

0

7

0.02315

7.61064E-05

0.023074

0.01931

0

SUM

1.52302

1.205913609

0.317101

1.313265

0.154545

b. SIGMA SLP Software Using SIGMA SLP, the line was divided into 7 sections, according to maximum GFD value, and results are presented in Table 4.

As can be seen from this simulation, Sections 1 to 3 of the line (i.e. closer to the GMSG area) are more likely to experience lightning flashovers compared to Sections 4 to 7. Therefore, installation of TLAs would ideally be focused in this area although information on which exact towers would still have to be determined using TFlash software.

Simulations were also conducted to compare line performance when different phases are equipped with TLAs. The relative positions of TLAs for the four case studies are shown in Fig. 10.

Results showed that Case 4 resulted in the best overall line performance, followed by Cases 3 and 2.

Fig. 10: Different installation options of TLAs on phases.

c. TFlash Software Seven case studies were conducted using TFlash software and involving different TFR values, different numbers of TLAs per tower, different installations on the phases, etc.

However, the optimal configuration using this simulation was not selected due to cost constraints since achieving the target

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Conclusions In the case of the 132 kV KKRIGMSG line, it was concluded that: 1. the ineffectiveness of the EGLAs already installed on the line was due to their being improperly positioned due to earlier work that relied on incorrect TFR values;

Fig. 11: Examples of incorrect installations of TLAs along 132 kV KKRI-GMSG line.

performance of 0.8Flsh/100 km-yr would require at least 330 TLAs installed on 150 towers.

of previously installed TLAs were not the towers with the highest probabilities of lightning strike. This was because there was no Insulation This was seen as representing too Coordination software available large an investment and therefore it in 2006 to aid in the installation was decided to reduce the number planning process. Moreover, TFR of towers with installed TLAs through values used in previous studies a process of prioritization. The TFR were too low (below 10Ω) due to values, elevations and GFD records incorrect measurement methods and were studied for all 150 towers and, equipment. Examples of wrong TLA in each case, those whose TFR value placements, for example, are shown was greater than 40Ω, elevation in Fig. 11. higher than 100 m (ASL) and GFD more than 16Fl/km²-yr were given Upon completion of the study, the a score. Towers receiving a total final TLA installation configuration score of 3 would then be highlighted for both the 132 kV and the 500 kV as having the highest risk of being line are depicted in Fig. 12. struck by lightning. Based on this ranking process, only 4 towers along the 500 kV line were ultimately selected for installation of TLAs.

2. historical GFD data had not been used to select the best tower locations on which to place EGLAs and installation was based rather on the location of lightning strikes during tripping. Since ground flash density (GFD) values affect line performance, increasing/decreasing GFDs from year to year either increased or decreased the line’s trip rates.

For the 500 kV ATWR-BTRK study the major findings were: 1. In 2012, overall tripping rate was reduced to zero in spite of a high GFD value due to a major TFR reduction job conducted throughout the line; 2. Installing TLAs on all 3 phases would prevent any double circuit tripping (DCCT); 3. Installing TLAs in an L-shaped configuration would reduce the rate of back-flashovers (BFR); 4. Phase transposition towers are relatively more exposed to lightning strike due to positive protection angles. 

In addition, phase transposition towers were also studied and it was found, based on the TFlash simulation, that the outer phases would always have the highest chance of lightning strike. Therefore, 2 out of the 5 such towers on the line located in the region of greatest lightning activity were also selected for TLA installation.

Location of TLAs Results from the TFlash simulation for the 132 kV KKRI-GMSG line clearly showed that the locations

(a) 132 kV L/LS

(b) 500 kV LS

(c) 500 kV TP

Fig. 12: TLA installation configuration on towers.

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UTILITY PRACTICE & EXPERIENCE

Insulator Corrosion Problems Affect HVDC Lines in China

I

n March 2011, problems of electrolytic corrosion on the caps of ceramic cap & pin insulator strings began appearing on the world’s first ±800 kV HVDC line, located in southern China.

This line – known as Chu-Sui – runs across 1200 km of mostly mountainous terrain from the Chuxiong Converter Station in Yunnan Province to Suidong Converter Substation in coastal Guangdong Province.

While this corrosion phenomenon was mostly concentrated on V-string insulators on the line’s negative polarity side, corrosion also appeared to varying extents on the positive pole and particularly at the junction between the pin’s zinc sleeve and the cement.

The article, contributed by Doctoral student Mei Hongwei from the Shenzhen Campus of Tsinghua University, describes the origins of this problem and how it was simulated in order to evaluate its impact on insulator performance.

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Chuxiong (left) and Suidong ± 800 kV Converter Stations at both ends of Chu-Sui line.

Photo: INMR ©

Introduction

HVDC technology is playing an ever-growing role in long distance transmission these days, in China as well as in countries across the globe. The reasons include large power transfer capability, low losses, high stability, reduction in required corridors and low short circuit currents, among other benefits.

While silicone composite insulators have played an important role in many suspension applications on Chinese HVDC and UHVDC lines due to superior pollution performance, the mechanical and electrical characteristics of porcelain V-strings have made them the preferred choice for specific sections of line, such as mountainous areas where icing is a concern. However, an emerging problem in these situations is that the lower side of the V-string insulator can easily be bridged by water during damp or rainy conditions, potentially resulting in electrolytic corrosion on the iron caps.

Indeed, by October 2011 – not long after commissioning – some 20,000 V-string porcelain insulator discs on the negative polarity side of Chu-Sui already showed evidence of electrolytic corrosion on iron caps.

Moreover, by February 2012, V-string porcelain insulator discs were also discovered to have corrosion problems on the negative polarity side of other HVDC lines, including the ±800 kV Fufeng line and the ±500 kV TianGuang, Gao-Zhao and Xing’an lines. Such widespread corrosion of insulator caps was regarded as a serious threat to the safe operation of these important lines and therefore quickly became the topic of much research and investigation.

Corrosion of hardware on DC suspension insulators is certainly not

new and indeed has attracted much attention over the years. For example, I.M. Crabtree in New Zealand (among others) offered an explanation of corrosion phenomena in contaminated service environments and during the 1990s performed tests involving different types of steel pins with and without sacrificial zinc sleeves.

Moreover, V.I. Galanov reported that the anti-corrosion performance of porcelain long rods was superior to that of disc type insulators without zinc sleeves on the pins. Also, an accelerated ageing test conducted at Xi’an Jiaotong University studied the corrosion mechanism and influencing factors for DC support insulator hardware under polluted conditions.

Based on these tests, Wang Xuan reported that electrolytic corrosion of hardware on such insulators could

occur in moist, polluted environments and that the extent of corrosion was related to leakage current, specific types of metal and fabrication technology.

Impact of Service Environment

Porcelain V-string insulators that suffered from electrolytic corrosion on the Chu-Sui UHVDC line showed obvious rust channels on their lower surfaces. There was also evidence of similarly induced corrosion of steel pins on insulators installed on the positive pole.

Table 1 provides statistics on the incidence of the corrosion problem in the two line sections mostly seriously affected.

The geographical environment of these line sections with the most serious corrosion problems is shown in Fig. 2.

Cause of Corrosion

Fig. 1: Schematic of how corrosion can occur on lower side of V-string.

The basic principle behind electrolytic corrosion of hardware on insulators is shown in Figure 3, with the circuit in this case made up of a DC power supply, metallic electrodes and an electrolyte. The metal connected to the positive pole of the power supply undergoes anodic corrosion by losing electrons. The caps of negative polarity insulators and the steel pins of positive polarity insulators are the cathodes and anodes in this electrolytic loop. Ferrous ions formed by oxidation then transform into rust.

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Examples of electrolytic corrosion on caps of DC disc insulators.

Example of electrolytic corrosion on protective zinc sleeve of pin.

Fig. 2: Topological environment of towers #401 to 414 on Chu-Sui line.

Various tests were conducted of the insulators tested fell between electrical resistance as well as of 0.0053 and 0.0113mg/cm2. This possible loss of mechanical strength suggests that surface pollution level due to the corrosion. Results showed has no impact on the electrolytic that insulators with corroded iron corrosion process. caps still satisfied normal operational • ESDD and NSDD levels for Area A requirements. However, one obvious n(with corrosion by-products on the concern with rusted portions along the surface) were higher than for Areas surfaces of porcelain discs was that B and C. these might contribute to more rapid Another topic of concern was that accumulation of pollution. corrosion of steel pins on affected insulators might decrease their To evaluate this risk, three porcelain strength, potentially leading to insulator discs were taken down from mechanical failure. tower #407, located in a line section where the corrosion problem was most prominent. These insulators were then Simulation of Electrolytic divided into three distinct regions (see Corrosion on Insulator Caps The water spray method was used to Fig. 4): Area A which clearly had the by-products of corrosion on their upper simulate the process of electrolytic corrosion on iron caps of porcelain surface; Area B, where there was no string insulators. Here, the creepage evidence of corrosion on the upper surface; and Area C, the lower surface. distance from the lower surface to a portion of the upper surface Test results for pollution accumulation was deliberately short-circuited using conductive wire and a copper in each of these areas are shown in electrode glued to the upper surface Table 2. (see Fig. 5). In order to prevent this The following observations could be electrode from breaking away during made: testing, a sealant was used to fix it in • ESDD levels on Areas B and C of place.

Table 1: Statistical Overview of Electrolytic Corrosion of Porcelain Insulators on Sections of ± 800 kV Chu-Sui Line Region An’ning

Fig. 3: Schematics depicting process of DC electrolytic corrosion.

Qujing

Type

Total Pieces

Corroded Pieces

Percent Corroded

XZP-210

4740

100

2.11%

XZP2-300

5118

375

7.33%

CA-765EZ

980

306

31.22%

XZP-210

12544

4847

38.64%

XZP2-300

19882

16252

81.74%

CA-765EZ

5312

3116

58.66%

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Table 2: Pollution Measurements on Corroded Insulators Along Chu-Sui Line Area A No.

Area B

mg/cm2

ESDD

NSDD mg/cm2

Ratio

1

0.1072

0.1090

2

0.0998

3

0.0513

ESDD

mg/cm2

mg/cm2

NSDD

Ratio

1:1.02

0.0078

0.0697

0.2744

1:2.75

0.0061

0.4802

1:9.36

0.0053

Fig. 4: Division of insulator surfaces to assess pollution accumulation.

Fig. 6: Test method to simulate electrolytic corrosion of pins sees prepared insulator with wrapped copper wire placed into electrolytic tank.

Potential impact of decline in strength of steel pins on insulators.

Area C

Electrolysis was used to simulate the electrolytic corrosion of the test insulators’ steel pins. To begin with, one end of the conductive wire was wrapped over the pin. Then, the pin and wire were totally covered using a sealant. Finally, the prepared insulator was placed into the electrolytic tank for testing (refer to schematic in Fig. 6).

ESDD

NSDD

Ratio

mg/cm2

mg/cm2

1:8.94

0.0113

0.1165

1:10.3

0.0759

1:12.4

0.0079

0.1166

1:14.8

0.0500

1:9.43

0.0083

0.0858

1:10.3

good dielectric performance; • While degree of pollution on the insulator has no obvious impact on the corrosion process, the resulting channel of rust on the surface makes it more vulnerable to pollution accumulation; • The water spray and electrolysis methods are feasible to research the electrochemical corrosion problem on insulator iron caps and steel pins respectively; • Installing zinc rings is an effective measure to prevent electrolytic corrosion of caps. At the same time, increasing the thickness of the zinc sleeve will ensure no corrosion on steel pins. 

Since zinc has superior anti-corrosive properties to steel, it has now been decided that new insulators for such lines should be equipped with a zinc ring which is installed in such a way as to maintain close contact with the iron cap.

In the case of pins, the remedial measure decided upon involved increasing the required thickness of the protective zinc sleeve and improving sealing.

Conclusions

Several conclusions can be drawn from this service experience and the testing conducted into the issue of electrolytic corrosion of hardware on insulators operating on HVDC and UHVDC lines.

Fig. 5: Insulator preparation with spray water method.

• Insulators with corroded iron caps and steel pins still maintained

Installation of zinc ring to prevent electrolytic corrosion on insulator caps.

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INSULATORS

Effect of Volcanic Ash on Outdoor Insulators

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D

uring the eruption of volcanos, power systems across the affected regions become vulnerable to a number of negative impacts and potentially widespread disruptions due to ash-induced flashover of insulators. Still, volcanic ash is not yet specifically being covered within IEC 60815-1. Moreover, in spite of ample anecdotal evidence on the risks, little data has yet been assembled on its electrical properties as well as on its effect on the performance of HV insulators.

This article, contributed by Johnny Wardman of the University of Canterbury (UC) in New Zealand and Igor Gutman of STRI in Sweden, aims to provide more information by summarizing the physical, chemical and electrical properties of volcanic ash in relation to the characteristics of known standard pollutants. It also presents results from an investigation conducted by STRI into the effects of expected fallout in 2010 on HV insulation across Scandinavia.

Finally, there is a review of laboratory experiments at UC that investigated the influence of volcanic ash contamination on performance of three different types of ceramic insulators.

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Introduction

Beyond pyroclastic flows and surges, sector collapses, lahars and ballistic blocks that are among the most destructive effects of volcanic eruptions, ash fall is by far the most widely distributed outcome. Indeed, dispersal of volcanic ash across huge areas can cause large-scale disruption of vital infrastructure, such as occurred with air transport throughout Europe during the recent eruption of Eyjafjallajökull volcano in Iceland. Electrical networks including generation sites, overhead lines and substations can also be exposed and vulnerable to heavy ash contamination.

The process of ‘standardized’ contamination and flashover performance of insulators has been studied for years and is well summarized in a number of CIGRE publications and IEC standards (e.g. IEC 60815-1, 2, 3) that have grouped pollution sources into: desert, coastal, industrial, agricultural and inland. Considering the limited data available for volcanic ash, however, there seems a clear need to characterize its physical, chemical, and electrical properties so as to provide a better understanding of ash-induced flashover.

This article aims to compile information on the electrical properties and pollution severity of volcanic ash and to present results from laboratory trials investigating the environmental and electrical parameters that influence flashover

B

C

voltage of insulators. Critical contamination levels (in terms of ESDD/NSDD) are also identified for insulators operating in service environments at risk of becoming affected by volcanic ash.

Characteristics of Volcanic Ash

The result of explosive eruptions, volcanic ash basically consists of two main components: nonsoluble, pulverized fragments of rock, minerals and glass (SiO2); and soluble salts that develop on the surface of ash particles during ashgas/aerosol interaction within the plume.

The fragmentation of magma generates variously sized particles or pyroclasts that are released into the atmosphere. These may be crystallized lava, glass or crystal fragments and are classified into: ash (particles < 2 mm as shown in Figure 1); lapilli (2-64 mm); and blocks or ‘bombs’ (> 64 mm). Among these, past studies have suggested that volcanic ash is the most problematic size fraction for electrical and other critical infrastructure.

Ash particles ejected from an eruption vent are typically incorporated into an eruption column that can rise tens of kilometres into

B

Photos courtesy of (a) www.reuters.com, (b) NASA Space Observatory).

A

Figure 1: a) Ash particles from 2009 Redoubt eruption in Alaska.

(Image courtesy of Kristi Wallace USGS/Alaska Volcano Observatory). b) & c) 33 kV insulators contaminated by volcanic ash following 2008 Chaiten eruption in Chile.

A

Fig. 2: a) Eruption column at beginning of May 2008 Chaiten eruption in Chile, b) Chaiten eruption produced volcanic plume that was dispersed hundreds of kilometres downwind of volcano into Argentina 84 INMR Q2 Issue 104.indd 84

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the atmosphere (see Figure 2a).

Eruption plumes are then dispersed by prevailing winds and the ash can be deposited hundreds to thousands of kilometres from the volcano depending on wind, ash grain size, ash density and eruption magnitude (as shown in Figure 2b). Dry ash is readily mobilized by wind, and can present a hazard to power systems for days to weeks after the initial fallout.

Even for small volcanic eruptions (i.e. < 0.1 km3 of erupted material), thousands of square kilometres can potentially be impacted by ash fall.

During explosive eruptions, volatile gases, aerosols, and metals adhere to ash particles during interaction within the volcanic plume. Sulphur and halogen gases and associated anions and cations are adsorbed onto ash surfaces and dry to become soluble salts. This eventually leads to formation of thin salt deposits on the ash surface and these attached salts supply a content of ions to an otherwise electrically inert material.

While dry volcanic ash is itself nonconductive, its fine-grained nature allows it to easily retain moisture.

Once the attached soluble salts are thus dissolved, the ash becomes conductive and a hazard for power systems.

Review of Current Knowledge

Existing literature in and interviews with experts from Italy, Japan, and Russia confirm that volcanic ash contamination of power systems can disrupt supply (Table 1).

Table1: Experience During Recent Volcanic Eruptions* Volcano/ Country

Year of Eruption

Tongariro/New Zealand

2012

2 mm wet ash caused no transmission outages.

One outage at 33 kV.

Shinmoe-dake/ Japan

2011

50-80 mm ash received. Impacts avoided by shutting down critical circuits/stations.

Pacaya/Guatemala

2010

Multiple outages at ≤ 69 kV following 20-50 mm ashfall in combination with moderate-heavy rain.

2008

50-100 mm fine grained ash (< 0.1 mm diameter) wetted by light rain caused flashovers at 240 kV; multiple flashovers at 33 kV after 20-300 mm wet ash.

1995/1996

3 mm of wet ash and mud contaminated lines ~15 km to volcano. Multiple flashovers (outages) at 220 kV.

Rabaul/Papua New Guinea

1994

2000-3000 mm ash received in southern suburbs of Rabaul. System de-energized at start of the eruption.

Mt Spurr/U.S.

1992

No outages after 3 mm dry ashfall.

Hudson/Chile

1991

Several outages in Chile Chico ~100 km from volcano with 80-120 mm wet ash.

Redoubt/U.S.

1989

6 mm wet ash caused outages in Twin City area.

Mt. St. Helens/U.S.

1980

6-12 mm ash wetted by light rain initiated 25 reclosed and 25 sustained outages at 69-115 kV.

Chaiten/Chile

Ruapehu/New Zealand

*

Ash thicknesses indicate deposit maximums.

Since several physical and chemical properties of volcanic ash influence its electrical conductivity, many factors can play a role in initiating flashovers (see Figure 3).

Some general findings from literature and service experience include:

Soluble salt content

Moisture content

Weather conditions

Condition of insulator

ASH CONDUCTIVITY

Eruption style

ASH ADHERENCE

Insulator orientation

Bulk density of the ash deposit

Grain size, porosity & composition

FLASHOVER

Impact

Electro-static charge

System operating voltage POWER SYSTEM SPECIFICATIONS

Alternating or direct current

Insulator construction (design & material)

Fig. 3: Schematic illustrates factors contributing to ash-induced insulator flashover.

• Dry ash is non-conductive and effectively removed from insulator surfaces by strong wind (e.g. > 40 km/hr) and heavy rain (e.g. >10 mm/hr). Light wetting conditions such as fog, dew or drizzle, however, are primarily responsible for pollution-related flashovers; • Conductivity of volcanic ash increases with increasing soluble salt load, moisture content and compaction; • Fine-grained ash (e.g. < 0.1 mm in diameter) is most problematic since it has greater adherence to surfaces and higher surface area, giving a higher soluble salt content and thus greater electrical conductivity when moist. However, other research has found that electrical resistivity of volcanic ash is largely independent of grain size.

Of several different ash samples with grain sizes from < 32 μm to 1.4 mm, all exhibited resistivity values < 100 Ωm. This suggests 85

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Table 2: Summary of Chemical Analysis (in % Wt) of Major Elements (Oxides) Sample

SiO2

Fe2O3

Al2O3

SO3

CaO

Na2O

MgO

Industrial Russia (average of 14 sites)

30

25

20

>10

>10

<10

<10

Industrial Iran

8

73

-

-

4

-

3

Volcanic ash Japan (average of 3 samples)

55

10

16

-

7

-

-

Tongariro 2012 (average of 4 samples)

59

8

17

-

5

2

3

Eyjafjallajökull 2010

59

9

15

-

5

5

3

Chaiten 2008

74

2

14

<0.01

2

4

<1

all ash grain sizes (< 2 mm particle diameter) are equally capable of causing ash-induced flashover; • Preliminary estimates suggest ~ 5 mm wet ash thickness is critical.

Assuming a 5 mm thickness and using an approximate ash density of 1.2 g/cm3, the corresponding NSDD level is ~ 600 mg/cm2. This is an exceptionally high amount of contamination and not typical of airborne pollution recognized by IEC 60815-1. In comparison, for example, one of the highest known ESDDs is 12 mg/cm2, recorded in a heavily-polluted industrial area of the former Soviet Union; • According to some research, if ≥ 30% of the insulator surface

(protected creepage distance) remains clean and dry, flashover will not occur.

Electrical Properties

Given the absence of a pollution classification for volcanic ash in IEC 60815-1, there is a need to define the contamination category to which volcanic ash best belongs.

Results from comparing its chemical elements with industrial and chemical pollution are presented in Table 2.

Generally, based on analysis of the distribution of the main oxides, volcanic ash is chemically similar to certain types of industrial pollution.

General insulator knowledge in IEC

60815-1 can therefore be used to analyze its possible influence on the dielectric performance of HV insulation. However, lack of standard pollution severity data has made it necessary to estimate the typical ESDD/NSDD ratio associated with a major volcanic ash fall.

One recent study found that volcanic ash from different eruptions can vary widely in ESDD and NSDD levels (see Figure 4) and that the ESDD of volcanic ash increases in a log-linear fashion with increasing NSDD. This is significant considering the possibility of many tens of millimetres of ash accumulation as a result of only a single eruption.

It is understood that the ESDD/ NSDD method has some inherent limitations in classifying pollution severity of specific types of salts and volcanic ash. As such, a resistivity method was developed to measure the electrical properties of volcanic ash at the first instance of fallout in order to complement ESDD measurements and other pollution monitoring techniques.

Studies at STRI

The April-June 2010 eruption of the Eyjafjallajökull Volcano in Iceland caused disruption of air travel across western and northern Europe. During this time, power companies across the Nordic countries were also unsure of the potential impact on their

Fig. 4: ESDD vs NSDD for 5 volcanic ash samples collected from 5 different eruptions (colours refer to ash thickness): TONG-12 – 6 August 2012 Tongariro (New Zealand); SDKE-11 – 2 February 2011 Shinmoe-dake (Japan); SHIL-09 – 27 November 2009 Soufriere Hills (Montserrat, UK); CHTN-08 – 28 May 2008 Chaiten (Chile); RUAP-96 – 18 June 1996 Ruapehu (New Zealand).

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Eruption of EyjafjallajĂśkull in Iceland.

Fig. 5: Location of DDDG measurements in relation to Iceland.

sites on the west coast of Sweden (Ringhals, located directly on the coast, and Horred 10 km inland).

The DDDG results obtained for An investigation was therefore carried April-May 2010 were then used to evaluate any influence of volcanic out that involved studying service ash pollution by comparing them experience from other eruptions across the globe as well as laboratory with results from other months as well as the previous year (see Figs. testing of volcanic ash samples taken directly from this eruption. The 6a and b). objective was to evaluate the possible Indeed, Fig. 6a shows that there influence of this ash contamination was an increase in pollution on the dielectric strength of outdoor (conductivity) measured at the glass, porcelain or silicone rubber Ringhals site from the northerly insulators. direction over the months from March to May 2010. There was also A first step involved analysis of data an increase in pollution from the from existing airborne pollution monitoring systems. Directional dust west during July 2010. deposit gauge (DDDG) measurements However, irrespective of this apparent according to IEC 60815-1 are performed monthly at two monitoring increase in pollution and Icelandâ&#x20AC;&#x2122;s networks and whether they should be prepared to wash substation and line insulators at short notice.

A

position northwest of the DDDG measurement stations, increases in conductivity at Ringhals during March-July 2010 were likely more due to the influence of the coastal environment (i.e. salt spray contamination). This conclusion is supported by results from the Horred station (Figure 6b), where (1) the amount of pollution collected was consistently lower than measured at Ringhals despite its relatively close proximity to each other and (2) there was no significant increase in pollution from the northerly and westerly directions during the period from March to July 2010. Had large volumes of ash been transported and fallen on Sweden, it is reasonable to assume that both DDDG sites would have detected associated increased levels of pollution.

B

Fig. 6: Results from DDDG measurements at a) Ringhals (left), and b) Horred (right).

Red indicates 2009 data, blue 2010 data.

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Fig. 7: Set-up for resistance measurements.

The next step in the investigation was finding a relationship between ESDD and NSDD for the 2010 Eyjafjallajökull ash (collected from a farm, located approx. 8 km from the volcano). An ash/water solution (40 g/l ash and distilled water) was prepared for analysis and 6 cm x 6 cm glass plates were artificially polluted using the dipping method and left to dry at an angle of 20°.

After drying, ESDD and NSDD were measured regularly over two hours. Using a conservative average of ESDD measurements over this period, it was concluded that a uniform layer of ash with NSDD of 1.0 mg/cm2 corresponded to an ESDD of approx. 0.008 mg/cm2.

The final stage of the investigation involved evaluating the possible effects volcanic ash contamination might have on the hydrophobic recovery of silicone rubber insulators.

Fig. 8: Time dependent variation of resistance.

Normally, the water-repellent surface of composite insulators inhibits the formation of conductive films of water, thereby improving flashover performance under wet and/ or polluted conditions. However, contaminants with high NSDD and a fast accumulation rate (such as volcanic ash) can overwhelm the natural hydrophobicity transfer of silicone oils. A resistance test was therefore undertaken to assess the influence of volcanic ash contamination on the hydrophobic recovery of silicone rubber insulators.

Plates of commercial silicone rubber were pre-conditioned using the Arizona State University method.

40 g/l solutions of Eyjafjallajökull ash/water and kaolin/water (for comparison) were also prepared.

The silicone rubber plates were dipped into either the kaolin or ash

Fig. 9: Schematic of test circuit.

solutions and placed horizontally on a flat surface. Electrodes were then fixed to 2 sides and resistance of the contamination layer calculated by applying 500 V across the plate and measuring associated leakage current (see Figure 7).

Such measurements were taken every 24 hours for 15 days (Fig. 8).

Results suggest the rate of recovery of hydrophobicity is slightly slower for volcanic ash than for kaolin over an elapsed period of time, especially in the case of ash sample #2, which was finer-grained and collected some time after deposition. However, for the first 3-4 days, recovery speed was almost the same for kaolin and for ash sample #1, which was collected within 24 hrs of fallout.

Research at the University of Canterbury

For the past 15 years, a research group led by the University of Canterbury and GNS Science in New Zealand has undertaken a systematic study of the impact of volcanic eruptions on critical infrastructure.

Investigations have found that ash-induced insulator flashover was the most common impact to power systems during and after ash falls.

Given the lack of empirical data on the external factors influencing ash-induced flashovers, a need was identified for a systematic analysis of this topic.

While naturally occurring variations in the properties of volcanic ash might introduce additional effects

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Table 3: Dimensions of Specimen Insulators (Strings) Diameter

Dry arc

Creepage

Material

Shed Profile

Porcelain

Standard

240

617

1026

Glass

Standard

240

526

1035

Glass

Aerodynamic

420

697

1191

mm

A

on the flashover voltage of HV insulators, challenges in collecting pristine, unleached ash in the volumes required for pollution testing make it logistically difficult to obtain freshly fallen ash for such analysis. As such, a ‘pseudo ash’ was bulk-manufactured using a proposed methodology that aimed to replicate the chemical, physical and electrical parameters of freshly fallen ash.

ESDD values of this pseudo ash showed that a 0.15 M NaCl salt solution added to a 3:1 ratio of ash to brine resulted in an ash whose electrical properties are within the bounds of freshly fallen ash (i.e. resistivity values between 100 and 1000 Ωm for uncompacted deposits). This concentration was therefore used as an appropriate dosing agent for subsequent artificial pollution tests.

Rapid flashover tests (presently under consideration by CIGRE WG D1.44) were carried out in the HV laboratory at UC. Three ceramic (porcelain or glass) suspension insulators having different profiles and used commonly across New Zealand’s transmission system were chosen for analysis (Table 3, Figure 10) and each string consisted of 3 insulators.

Standard artificial pollution tests recommend applying pollution by means of spraying, flow-on or dipping techniques. However, considering (1) the importance of retaining soluble surface salts

B

Fig. 10: Profiles for a) standard porcelain, b) standard glass and c) aerodynamic specimen insulators.

C

inherent in freshly fallen volcanic ash and (2) the potential for volcanic ash to be deposited in large quantities (e.g. > 10 mm thicknesses), the pollution layer for these electrical tests was applied using dry pseudo ash.

1. Installing a clean insulator into position for testing;

Four different ash-contamination scenarios were defined and replicated based on depositional patterns described in the literature and observed in the field. Scenarios were selected as representative of the worst-case, with the entire top and bottom surfaces coated as uniformly as possible.

4. Energizing the insulator and maintaining voltage for 2 minutes or until flashover;

Dry ash was applied to the top of insulator weathersheds using a small sieve (diameter 10 cm, mesh size < 0.1 or < 1 mm). For scenarios 3 and 4, dry ash was applied to the bottom surface of weathersheds by first spraying the insulator with a fine mist of water (same water source as used for wetting) and then dusting pre-sieved ash over the surface by hand. Alternating between misting and dusting, a relatively uniform ash layer of 1-2 mm was achieved.

An average ESDD for top/bottom surfaces was then calculated for each scenario.

Very light rain conditions (using an air atomizing nozzle ~ 6 mm/hr with a volume conductivity ~130 μS/cm) were applied for wetting with spray nozzles configured perpendicular to the test insulators. The procedure for voltage tests consisted of:

2. Contaminating the insulator according to the scenario being investigated; 3. Applying light rain for 5 minutes before energization;

5. Assuming no flashover, raising voltage in 5% increments every 2 minutes until flashover; 6. Re-energizing the insulator after flashover at ~ 2.5 steps below the flashover voltage. This sequence was repeated for each scenario with each round of tests ending once flashover voltages decreased to a minimum or until 15 consecutive flashovers were recorded.

To ensure repeatability and reliability, three rounds of tests were performed for each scenario. The average of the lowest flashover and the highest withstand values obtained during the three test rounds was then defined as the Vmin for the scenario.

Results

All insulators flashed over at similar voltages during all scenarios.

However the standard glass insulator exhibited the lowest Vmin, i.e.

12 kV/unit (ESDD/NSDD = 0.4/152 mg/cm2), which is similar to that observed in other studies (11 kV/ unit, ESDD = 0.3-0.6 mg/cm2). See Table 5.

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will still perform relatively well under ashy conditions;

Table 4: Four Different Contamination Scenarios Scenario

Replicated Environment

Wetting rate (mm/hr)

Ash top (mm)

Ash bottom (mm)

Particle size (mm)

1

Moderate pollution, wet environment

6

3

0

< 0.1

2

Moderate pollution, wet environment

6

3

0

<1

3

Heavy pollution, wet environment

6

6

1

< 0.1

4

Heavy pollution, wet environment

6

6

1

<1

The lowest flashover voltages were observed once the top and bottom surfaces of insulator weathersheds were fully covered by ash (i.e. scenarios 3 and 4). This suggests that moderate accumulations of volcanic ash on the tops of insulator sheds (i.e. up to 3 mm as per this study) can still occur without severely reducing dielectric strength, providing the bottom surface remains clean and dry.

show that volcanic ash has a critical ESDD of 0.3 mg/cm2 and a critical NSDD of ~ 50-70 mg/cm2 (or a critical thickness of 1 mm, as shown in Figure 4).

Summary & Conclusions

Chemically similar to certain types of industrial pollution, volcanic ash is composed of non-soluble fragments of rock, minerals and glass (SiO2), whose relative proportions will vary with each volcano and specific eruption and even at different phases Results suggest that, for the pseudo ash used in this study, an NSDD of 1 of any eruption. Soluble surface salts are formed during particle-gas mg/cm2 corresponds to an ESDD of approximately 0.003 mg/cm2 for non- interaction within the plume and uniform top/bottom contamination are the primary determinant of the (i.e. ash accumulates only on the top electrical conductivity (ESDD) of surfaces of the suspension string). volcanic ash.

This value is roughly doubled (0.006 mg/cm2) for uniform contamination, Ash-induced insulator flashover is the which is comparable to the 0.008 most common mode of power system mg/cm2 found during research at component failure during ash falls.

STRI. Limited data on the performance of HV insulation contaminated by volcanic ash resulted in Critical NSDD levels for an insulator investigations on this topic at STRI in service can preliminarily be and UC. The following conclusions estimated based on the pseudo ash ESDD/NSDD relationship and the Vmin could be drawn from these studies: findings from these artificial pollution • The rate of recovery of tests. For example, for a 10-disc standard glass cap & pin string on a hydrophobicity on silicone rubber 145 kV line in an area with medium insulators is slightly lower for site pollution severity (as per IEC volcanic ash in the long-term (15 days in this study) than for 60815-1), providing the required standard reference kaolin. However, reliability of ~ 0.1 outages/100 km/ year requires that flashover voltage of considering the generally superior the string must be 1.5 times higher performance of composite line than the maximum operating voltage, insulators over strings of ceramic i.e. ~ 13 kV per unit. Moreover, using cap & pin insulators, even in the generic flashover performance curves, event of total loss of hydrophobicity results at UC can be converted to it is expected that these insulators

• In general, a significant amount of volcanic ash is needed to cause flashover. Given the performance of specimen insulators during electrical tests at UC, the critical NSDD threshold is estimated to be 50-70 mg/cm2, meaning a critical thickness of ~1 mm (uniform layer on top and bottom surfaces).

This is an unusually high level of contamination compared with other forms of airborne pollution mentioned in IEC 60815-1 and is likely to occur only in areas that receive direct fallout from a volcanic plume; • The amount of ash deposited in any one place within a power network will depend on a range of factors such as eruption size, wind direction and strength, atmospheric conditions, etc. The likelihood of flashover will therefore also be dependent on local conditions (e.g. wind and relative humidity) in addition to insulator material, profile, orientation and condition as well as the conductivity of the ash. 

Table 5: Results for Three Specimen Insulators Scenario

Standard Porcelain

1

2

3

4

<0.1

<1

<0.1

<1

Ave. ESDD mg/cm

0.2

0.2

0.4

0.4

Ave. NSDD mg/cm

49.3 65.9

122

152

46

30

Grain Size mm 2 2

Vmin

kV

98

111

Scenario

Standard Glass

1

2

3

4

Grain Size mm

<0.1

<1

<0.1

<1

Ave. ESDD mg/cm2

0.1

0.1

0.3

0.4

Ave. NSDD

mg/cm2 44.7 59.6

113

142

Vmin

kV

47

36

103

98

Scenario

Aerodynamic Glass

1

2

3

4

<0.1

<1

<0.1

<1

Ave. ESDD mg/cm

0.2

0.2

0.5

0.5

Ave. NSDD mg/cm

74.7 99.7

166

207

46

42

Grain Size mm 2 2

Vmin

kV

98

93

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INSULATORS

ABB

Invests in Expanded Insulator Production Capabilities Part 2 of 2

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T

he steady move into UHV by important electricity markets, including China, India and South Africa, has created a sudden demand for bushings, breakers and other substation equipment rated as high as 1100 kV. At such voltages, composite insulators have demonstrated both performance and cost advantages that have helped make them the technology of choice for many if not most such applications.

Responding to this trend, one of the world’s largest producers of composite hollow core insulators has recently upgraded its production capabilities to handle increasing volumes of very large pieces.

INMR travels to Piteå, Sweden, to visit ABB Composites – likely the world’s northernmost production facility for HV components used in the power industry.

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ABB’s insulator plant in Piteå.

Recognizing a strategic opportunity in an emerging market, ABB made its initial foray into the field of composite hollow insulators during the late 1990s. At the time, manufacturing of the final products was sited within the company’s expansive Swedish facilities in Ludvika, close to manufacturing of related ‘downstream’ apparatus such as bushings and switchgear. Here, FRP tubes produced by affiliate ABB Composites were primed and over-molded with silicone housings using a unique extrusion process. It was not long, however, before it was decided that there was more sense transferring the molding operation to Piteå in order to bring all production steps under one roof.

“Growing interest in UHV projects during the past several years has created a demand for pieces so large that it was obvious changes would have to be made to move them through our workshop.”

ABB Composites, in fact, had already long established itself as a producer of composite insulating materials that, apart from tubes, also included items such as fiberglass loops for cage-type arresters and insulating rods for breakers. All these diverse items had one common

link, namely filament winding, which was regarded as the firm’s core technology in terms of materials and processes.

Photos: INMR ©

General Manager, Markus Holmlund, reports that since insulator production was shifted to Piteå in 2000, ABB Composites has supplied over 100,000 composite hollow insulators from this facility.

Moreover, annual output has been growing steadily to a volume of some 15,000 units, reflecting what he views as a clear trend toward greater use of such housings in place of porcelain – especially for applications in dead tank breakers, arresters and large HVDC bushings.

Holmlund also points out that growing interest in UHV projects during the past several years has created a demand for pieces so large that it was obvious changes would have to be made to move them through the workshop. For example, the filament winding department has been completely re-outfitted with new machinery, replacing all previous equipment. These new machines have been designed to accommodate tubes of 15 meters or more in length and one of their first such applications involved an order for 12 m long bushing insulators for a 1100 kV converter transformer.

Says Holmlund, “while it’s possible to glue pieces together to achieve such long tubes, we feel there could be reason for concern when it comes to electrical and mechanical properties.”

Lars Jonsson, a specialist in bushings at ABB’s Ludvika plant, agrees and claims that while a gluing FRP tubes have long been ABB Composites' main product group but now there is growing demand for very long pieces.

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“Since extrusion sees each shed molded on in a continuous cycle, a lot of effort has been devoted to make this step as efficient as possible to avoid production bottlenecks.”

Photos: INMR ©

Automated winding machine pulls fiberglass rovings through resin before winding them onto mandrel. (top) Winding final protective layer onto tube, to be removed later, is final step before curing.

solution has historically worked well for porcelain housings, the same may not hold true for FRP tubes.

“With porcelain”, he says, “high compressive forces serve to reinforce the epoxy joints. With composite insulators, however, there are no such forces, meaning that weakness might result if the insulators must operate in a very challenging service environment.”

According to R&D Manager, Anders Holmberg, one of the key requirements during winding is maintaining as low a porosity as possible to ensure no partial discharge activity within the tube.

“With these new machines,” claims Holmberg, “we have already succeeded to lower porosity to the point that it is not really feasible to get much better.” Other key requirements during winding are

protection of employees as well as control of possible contamination.

For example, employees approaching a certain distance to the machines must wear special breathing apparatus while all raw materials and tubes are checked to ensure no contaminants, such as flying insects, become trapped.

One of the recent areas of R&D at the Piteå plant has involved finding improved ways to extract the steel mandrel after the tube has been

wound. Holmberg notes that this is an important yet difficult step for very long insulators since the tubes have that much more weight.

Extracting a mandrel without damaging the tube can therefore be difficult and time-consuming.

After winding and curing, tubes are machined to accommodate assembly of flanges, which is accomplished in much the same way across the industry. At this point, the complete outer layer of each tube is routinely peeled off. “This procedure,” 95

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says Holmberg, “guarantees no contamination will be present and also gives us more flexibility when handling the tubes. We know that, whatever happens while moving them through the plant, they will always have a clean surface layer just before start of the molding process.”

Once the outer layer has been removed to yield a fresh surface with no cut fibers, each tube is transferred to an adjoining climatecontrolled chamber where a primer is applied to ensure optimal bonding with the silicone housing along its entire length.

Unique Molding Technology

After winding, the second critical process during manufacture of

(Top) Cured tube ready for machining prior to attachment of flanges. (right) Tube with outer layer peeled off ready to move to climatecontrolled chambers (background). Final cleaning of tube surface before application of primer.

composite hollow insulators involves molding the silicone housing onto the primed tube. In the case of ABB, this is accomplished using a patented helical extrusion technology that sees the rubber material molded directly onto the tube surface, shedby-shed, using a special tool. This process differs substantially from the technique used by most other insulator suppliers, which relies instead on injecting the silicone material into cavities of a long mold, thereby allowing many sheds to be molded on simultaneously. Insulators up to 220 kV and sometimes higher can be molded this way in a single cycle while at higher voltages two or more injection ‘shots’ are typically needed.

Since extrusion sees each shed molded on in a continuous cycle, Product Sales Manager, Roger Sundqvist, explains that a lot of effort had to be devoted to make this step run as efficiently as possible in order to avoid production bottlenecks.

Additional extruder capacity was therefore added in 2011.

“It may appear simple at first glance,” remarks Sundqvist, “but a lot of investment was actually needed to customize both the parts and the process. Once we have the tool, which is unique to the specific profile desired, we can use it for any diameter or shape of tube. Basically, that gives us a fairly complete set of possible insulator geometries.”

Indeed, Sundqvist claims that among the major advantages of this process versus classical injection molding is that it is highly flexible with no need to order expensive molds to achieve different insulator geometries.

“Another advantage”, he explains, “is that tooling does not have to be changed to accommodate conically shaped insulators, which are growing in popularity due to savings from reduced volume of internal insulation.

This also gives us more freedom in design, such as being able to supply customers with unusual items such as tapered station posts.”

Another benefit of the extrusion molding process, adds Holmlund, is the fact that there is no ‘parting line’ caused when the mold inside an injection machine opens to allow removal of the object. “This”, he says, “means a seamless housing across the insulator’s entire length.

Basically, we like to tell customers that our process results in an insulator where there is a one-piece tube and a one-piece housing. There are no joints either in the internal structure or in the silicone.”

Jonsson, from ABB’s bushings unit, provides a user perspective and explains that a seamless housing design is particularly advantageous when thinking over a lifetime of many years service since there is no risk of moisture ingress through seams and joints as the unit ages.

But he also emphasizes that perhaps the ultimate benefit of this molding technology lies in being able to easily

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Polished steel mandrels having lengths up to 12 or more meters can prove difficult to extract efficiently once tube has been wound.

Photos: INMR ©

produce housings with smooth sheds tips having a relatively large radius so that water drips off them instead of creeping underneath. “This ‘drip edge’,” claims Jonsson, “ensures water rolls-off and also increases tear strength. But the main benefit is minimizing electric field and the risk of flashover.” He also remarks that while such a shed design is also

possible with conventional injection molding, it is costly to achieve and therefore not usually seen in practice.

Now that equipment at the plant has been upgraded to allow for the largest dimensions of insulators, current production objectives in Piteå are focused on automating the process.

‘We are not quite there yet,” admits

Holmlund, “but getting close. The goal will be to load the product into a machine and basically press a ‘start’ button, leaving the machine to do everything else.”

Another target is leaner production in order to further reduce lead times. Says Holmlund, “while we can already produce even difficult

“One of the advantages of extrusion versus injection molding is that there is no need to order expensive molds for each possible insulator geometry.”

Continuous extrusion of silicone sheds directly onto tube.

items such as 800 kV DC insulators in less than two days, we are looking to eliminate stocks of semi-finished tubes. That means filament winding could one day be done only to order, allowing us to benefit fully from the flexibility offered by our extrusion process.”

HTV Silicone Housing Material

One of the important features influencing the long-term performance of any composite insulator is the formulation of its housing, with some compositions of silicone claimed to offer superior long-term hydrophobicity versus others. In fact, one of the ongoing debates in the 97 INMR Q2 Issue 104.indd 97

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industry and among customers is how high consistency (HTV) silicone rubber compares in this regard with liquid silicone rubber (LSR).

Holmlund (left) and Holmberg examine tapered 800 kV DC station posts, selected as a maintenance-free solution. With traditional injection molding, such designs would normally require different molds and much time to change them.

Large radius shed tips minimize electric field and also ensure water drips off instead of creeping under sheds.

Ends of helical silicone sheds are machined by robots at time of manufacture to ensure same smooth finish at top and bottom of insulators.

ABB Composites uses only viscous HTV silicone material in its extrusion molding and Holmberg points out that it is important for users to understand that it is not material alone but also shed design that will determine how well an insulator performs. Still, he states that in 2007 ABB’s HTV composition was directly evaluated against LSR, with two identical insulators, but with different housings, tested at the same time in a 1000-hour salt fog chamber. The first was an LSR-housed unit having a typical design with sharp shed tips and a relatively low angle of shed inclination while the second was an HTV silicone insulator with ABB’s greater inclination of sheds and larger shed tips.

According to Holmberg, a chart of findings revealed much less erosion on the helical HTV unit. “LSR has relatively more low molecular weight (LMW) cyclosiloxanes,” he notes looking at the result, “while HTV has relatively more filler. But the key issue is not the overall content of the LMW species but rather ensuring that this content must be sufficient to always allow their migration from the bulk material to the surface. Our research has even suggested that this transfer mechanism may be enhanced by the presence of fillers.”

Holmberg goes on to state that additional research was carried out with the goal of verifying the longterm stability of these LMW siloxanes in the sheds of ABB insulators.

He claims that results confirmed that these key molecular groups regenerate through an equilibrium process in the bulk rubber such that a concentration of about 2% is always maintained. These groups then transfer to the surfaces of sheds at a rate governed by surface conditions and in the amounts needed to maintain hydrophobicity under polluted conditions. According to Holmberg, measurements performed on insulators after 10 years in service showed the same amount of LMW siloxanes in the bulk material as when new, suggesting

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Photos: INMR ©

that hydrophobic properties do not degrade over time. “We do not add silicone oil to our formulation,” he says, “since we feel it is no more than a temporary measure to achieve good hydrophobicity. Rather, what we have aimed for in our housing material is an equilibrium level that remains constant over time and is sufficient.”

Holmberg also answers one of the questions routinely asked by construction and maintenance personnel who handle such insulators in the field, namely what to do if there are minor nicks or tears to a shed caused by handling. He explains that in most cases these do not present a threat to an insulator’s safe operation unless they happen to be in the highly stressed region near the live end. In any case, he suggests using an RTV silicone to fit torn pieces together on site or, in extreme cases, constructing a new shed to fit over the original and curing it with a hot air gun.

Says Holmberg, “we have seen problems when maintenance personnel handle porcelain and silicone insulators in the same way in the field. This can lead to permanent deformation of sheds

“It is important for users to understand that it is not material alone but also shed design that determines how well an insulator performs.” or damage to the surface. These people need to be made aware that they should always follow the manufacturer’s instructions on how to handle apparatus equipped with composite insulators.”

As for cleaning, Holmberg advises that this is necessary only in very severe conditions, in which case manual wiping using a cloth with either water or isopropyl alcohol is usually sufficient. High-pressure water cleaning of composite hollow insulators is neither needed nor

recommended since it can cause lasting mechanical damage.

Looking to the future, General Manager Holmlund sees several challenges ahead, even now that the recent upgrading in capabilities and capacity has been completed. One of these is the fact porcelain producers have managed to lower their costs and now offer very competitive pricing in the marketplace, especially at 145 or 220 kV. This strategy, he says, has slowed the rate of transition from porcelain to composite hollow insulators from what took place between 2000 and 2009. For example, equivalence in cost between porcelain and composite insulators now generally occurs at about 550 kV while above this voltage composites are almost always less costly.

He sees the best response should be to continue to re-examine the production process, not only aiming for leaner production but also to optimize use of costly materials, especially the silicone rubber housing. For example, an 800 kV DC insulator can consist of between 200 and 300 kg of silicone rubber, which he feels is more than actually needed.

Holmberg presents results of comparative salt fog testing of LSR and HTV silicone housed insulators.

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Another area where Holmlund sees potential for cost reduction is by increasing material utilization factors for tubes. “Filament winding is a complex process,” he remarks, “and contamination or defects during winding can result in loss of the entire tube. Still, with our extrusion process, we have already succeeded to lower costs compared to the alternative of injection molding, which we know well from manufacturing experience in other markets. And we feel we get a better product as well.” 

At the same time, he recognizes that achieving such a reduction may mean extruding thinner sheds and this in turn will depend on improved control over the machine. “We are looking at a goal of reducing the silicone content,” he says, “and we already have a good idea how to accomplish this by adapting our formulation as well as process parameters. The ultimate goal, of course, is to decrease costs.”

Applications of ABB insulators in Sweden, South Africa and China.

Photos: INMR ©

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ARRESTERS

rincipal Failure Modes for Surge Arresters

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The failure of an arrester almost always results in a complete short circuit inside its housing.

In most scenarios, failure occurs due to dielectric breakdown, whereby the internal structure has deteriorated to the point where the arrester is unable to withstand applied voltage, whether normal system voltage, temporary power frequency overvoltage (e.g. following external line faults or switching) or lightning or switching surge overvoltages.

Photo: courtesy of FortisBC

Here, arrester failed by external flashover due to contact with wildlife.

Moisture Ingress

Perhaps the most common cause of arrester failure is moisture entering its interior. This implies that the arrester was: • not well designed, or • not properly manufactured, or • damaged by some external force resulting in a compromise to its sealing system.

While the underlying cause in each case may be the same, the way this progresses to eventual failure can vary significantly.

For a hollow core arrester where there is gas space around the column of MOV blocks (typically dry air or nitrogen), even a tiny leak can result in what is referred to as ‘seal pumping’ due to pressure differentials. For example, during the day suns heats the arrester such that the internal pressure increases relative to ambient and outward gas leakage occurs. When the arrester cools

There are a variety of reasons why an arrester might reach such a state. This article, contributed by longtime expert, Michael Comber, discusses the most typical modes by which arresters fail.

at night, this process reverses, with internal pressure dropping below ambient and external air (with all its moisture content) being drawn into the arrester. Such a cycle can repeat itself over many days, months or even years before the moisture inside builds to the point where there is a problem with reduced dielectric integrity.

In a solid core arrester design (with little to no internal gas space) this process will not take place. However leakage can still occur through imperfect end seals. In this case, moisture ingress is more due to ‘wicking’ – a process whereby moisture gradually finds its way down through interfaces between the MOV blocks and the materials in contact with them.

The manner in which dielectric integrity is degraded due to moisture ingress can also vary. The mere presence of moisture, if concentrated only within the gas inside a hollow core arrester, will not have significant impact on dielectric strength. Rather, it is how this moisture interacts with internal surfaces and materials that becomes the issue.

Photo: INMR ©

It has been noted, for example, that moisture related failures of porcelain-housed arresters tend to occur more in the evening than during the heat of day. This is attributed to accumulated moisture condensing on the inside walls of the porcelain when it cools after sunset.

Electrical strength across the wall is then progressively reduced until internal flashover occurs from end to end.

Moisture will typically not condense on the MOV blocks of an energized arrester because these generate enough heat to keep their temperature slightly higher than that of the surrounding gas. However, if the material used to coat or collar the blocks is hygroscopic, it can absorb

Arrester fragments sent for testing to assess cause of failure.

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voltage, Uc, the temperature of the MOV blocks rises only slightly above ambient. A point is then reached where the incremental heat generated is in equilibrium with the heat the arrester dissipates into the surrounding air. This represents the arrester’s normal thermal stability operating condition, depicted by the green dot on curve 1 of Fig. 1. Here, the blue curves represent power losses of the MOV blocks as a function of block temperature and the dark tan line represents the heat that can be dissipated from the arrester assembly, also as a function of block temperature.

Overload on this failed arrester may have come from temporary overvoltage or from a lightning surge but could also have been that moisture ingress was underlying cause. Once shorted internally, fault current built the internal pressure to a level that fractured porcelain housing. Fracture could also have resulted from fault current above the unit’s rating.

moisture thereby causing some blocks to become more conductive on their outer surfaces. This essentially shifts voltage to other blocks and leads to higher conducted currents, external to some blocks but internal to others. Ultimately, the complete stack can no longer withstand the applied voltage. (Note: this scenario can be avoided by ensuring only non-hygroscopic collaring materials, such as glass, are used.)

In the case of solid core arresters, moisture that has wicked into internal interfaces along either a portion or the complete length of the arrester can result in dielectric breakdown and failure.

Temporary Overvoltage (TOV)

Under normal operating conditions, which see the arrester energized at its maximum continuous operating

If the power frequency voltage across the arrester increases (e.g. due to a system disturbance, fault or switching operation), the MOV blocks conduct more current and begin to heat up. As long as the overvoltage is below some critical limit, a new thermally stable operating point will be reached, albeit at a higher MOV block operating temperature, as depicted by the green dot on curve 2. However, should the overvoltage be of sufficient magnitude, the heat generated by the blocks remains greater than the unit can dissipate. A potential thermal runaway situation will then occur, as depicted by curve 3.

Should voltage return to normal (i.e. to the MCOV) before critical block temperature is reached, the arrester will remain thermally stable and will eventually cool to its initial condition, as depicted in Fig. 2. Here, curve A represents the conditions for normal operating voltage (i.e. MCOV) and curve B the conditions for an elevated voltage that can potentially lead to thermal runaway – even though this is avoided because voltage returns to normal before the critical temperature is reached.

On the other hand, if the overvoltage continues beyond the point at which critical MOV block temperature is reached, the temperature of the blocks continues to rise even if voltage returns to MCOV, as depicted in Fig. 3. In such a case (i.e. thermal runaway), the blocks eventually become so conductive that they can no longer support even MCOV and will be short-circuited, resulting in arrester failure.

Ageing of MOV Blocks

In the early days of metal oxide arresters during the mid to late 1970s, MOV blocks from all manufacturers exhibited some degree of ageing, whereby their power dissipation at any given voltage increased slowly, but continuously, over time. The resulting impact on arrester performance would be similar to that described for TOV – namely after some time in service, the power (heat) generated by the blocks would be basically similar to that resulting from a TOV occurring when the blocks were new.

Fig. 1: Thermal response curves for different applied voltages.

As time progressed, the heat generated would be equivalent to that from a higher TOV on blocks in their new condition. Ultimately, the heat generated reached a point where no stable operation could be maintained, as depicted by curve 3 in Fig. 1. The blocks would then experience thermal

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3.3 J/cm3/°C, meaning that they will sustain a temperature rise of about 10°C for every 33 J/cm3 of energy (assuming this energy is input rapidly).

Fig. 2: Potential thermal runaway due to TOV avoided.

If the input of energy is excessive, the resulting temperature rise of the blocks may be such that the arrester is pushed into a thermal runaway condition. For example, with the arrester operating according to curve 1 in Fig. 1, the stable operating temperature will be that depicted by the green dot. If the temperature of the blocks is raised quickly (as a result of energy absorption) so that it becomes higher than depicted by the black dot on the same curve, then the arrester will not recover from this event and go into thermal runaway, as described earlier for a situation of prolonged TOV.

runaway, just as if exposed to a sufficiently high, sustained TOV when in their original new condition.

This ageing characteristic of blocks was recognized early on and was addressed in ANSI/ IEEE as well as IEC test standards by means of accelerated ageing tests. In these tests, sample blocks were subjected to MCOV for 1000h while maintaining block temperature at 115°C and it was considered that this was equivalent to 40 years service at 40°C. If at the end of 1000h the power dissipation was higher than at the start of the test, parameters for other duty tests had to be adjusted to account for this increase. The clear implication was that arresters passing the tests would be good for at least 40 years of service (provided of course that they operated within the specifications).

With subsequent major improvements in processing technology, MOV blocks produced these days exhibit a characteristic whereby power dissipation actually decreases over time at any given voltage. This implies that they become more rather than less thermally stable during service and therefore are unlikely to cause arrester failure due to ageing.

Thermal Runaway from Surge Duty

The surge duty referred to here is that resulting from relatively high current surges due to lightning, switching of long lines or capacitor banks. Some of these may have very high amplitudes but relatively short duration (e.g. lightning surges), while others have much longer duration but with significantly lower amplitude (e.g. switching surges).

Still, all have a charge content that, when passed through an arrester, results in a certain amount of energy absorbed by the blocks. This absorbed energy causes almost immediate adiabatic heating. MOV blocks typically have a specific heat capacity of about

Fig. 3: TOV not removed in time to prevent thermal runaway.

Damage to MOV Blocks From Surge Duty

One manifestation of the energy absorbed by the MOV blocks is rise in their temperature, as discussed above.

However, if the energy is of sufficient magnitude and deposited over a relatively short period of time, the blocks can become irreversibly damaged. For example, the resulting thermo-mechanical shock could cause them to crack into two or more pieces.

In other cases, varistor blocks can be punctured in localized areas, either partially or completely through their body. In yet other cases, a pinhole type failure can occur at the edge of the block, possibly causing material to be removed from its outside surface.

Typically, each such type of damage is accompanied by degradation of the block’s electrical integrity, manifest either by its inability to sustain another energy event without electrical breakdown or by a reduction in its capacity to support normal operating voltage. Both situations can sooner or later result in complete arrester failure.  105

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TESTING

Transformer undergoing repair after explosive failure of HV bushings.

Photo: INMR Š

Testing for Safety & Risks Affecting Operation of HV Cable Terminations, Bushings & Arresters Not long ago, a HV cable termination operating in a Mediterranean country experienced catastrophic failure, sending high velocity porcelain shards in all directions.

The installation happened to be next to a parking lot but fortunately this occurred on a day when it was mostly empty. Otherwise, the event might have proven much more than a repair job for maintenance crews and become a major public relations challenge for the power company affected.

as constant reminders of the explosion risks whenever electrical arcing occurs inside a porcelain-housed component filled with oil or pressurized gas. There are potential risks for polymeric-housed components as well, although of a different nature.

This article, contributed by Uberto Vercellotti and Alberto Sironi of CESI in Italy, addresses the major safety issues that impact test programs for components such as HV cable terminations, surge arresters and bushings.

While cases such as this are comparatively rare, they are far from isolated and serve

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0% Consequences 100%

High Risk

Medium Risk

0%

Failure Probability

Photo: courtesy of CESI

Low Risk

100%

Fig. 1: Risk diagram allows for range of probability and consequence associated with any individual risk and is effective in offering visual image of comparative risks.

Establishing probabilities is the major challenge. (Taken from Electra N. 266 02 2013).

Safety & Risk Assessment at Substations

Table 1: Typical Failure Rates for 380 kV XLPE Cable Systems & 380 kV Overhead Lines

These days, transmission system operators (TSOs) in many countries are searching for solutions to meet growing demand for electrical power.

The only realistic option will be more HV, EHV and UHV AC and DC systems – which means growing populations of cable terminations, bushings and arresters placed into service.

Stringent international regulations are also pushing utilities to rely on testing as one of the most effective means to demonstrate that they are working with due diligence whenever specifying such equipment. This requirement becomes all the more important if one considers the growing numbers of substations and electrical installations located near population centers as well as the accompanying push to reduce substation ‘footprints’. Both trends represent increased risk factors in

Failure Rate (100 component years or 100 circuit km years)

Repair Time [hours]

Overhead Line

0.220

8

Cable

0.133

Termination

0.032

Joint

0.026

600

Values per System (3 phases). Taken from Cigré TB 379

*

terms of danger to public safety as well as the economic consequences of collateral damage should there be a catastrophic failure.

It is therefore increasingly important to look for possible upgrades in technology while also decreasing failures at the early stages of service

Implementation of stringent regulations across the globe is pushing utilities to rely on testing as the best way to demonstrate that they are working with due diligence when selecting HV equipment and technologies.

HV cable termination after internal arc test.

life. The latter can only be achieved through more detailed installation practices in which all critical functions are well defined and where greater attention is paid to the skills required of the workers involved.

According to ISO/IEC Guide 51 safety is “freedom from unacceptable risk”. This can be achieved by reducing risk to some tolerable level that takes into account that there will always be some amount of residual risk, i.e. the risk that remains even after all possible protective measures have been undertaken. This risk is then determined by arriving at some optimal balance between the ideal of absolute safety and the demands met by the product, which includes benefits to the user, suitability for purpose and cost effectiveness.

Safety criteria must be considered first in order to be able to specify the required safety level and to perform the related risk assessment.

One way to do this is to combine all the technical as well as nontechnical (e.g. social and economic) parameters that play a role so as to evaluate failure probability and its consequences. The final risk can then be estimated using the so-called Whitman (Farmer) diagram, shown in Fig. 1. For example, to reduce residual risk and also to lower the cost of the consequences, explosionfree cable terminations and bushings are increasingly being specified.

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projected at high velocities over a wide area. Oil sprayed into the surroundings through the cracked unit can also become ignited by the arc associated with the fault.

In extreme cases, fireballs some five times higher than the transformer itself have been observed following the explosive failure of a bushing.

Photos: INMR ©

Physical protection against explosions and fires involving HV bushings in service are often difficult or even impossible to put in place due to the size and location of the equipment. Whenever a particular type of bushing is regarded as being at unacceptably high risk of such failure, access to the site should be limited, during which time design changes to improve safety can be discussed with the manufacturer.

Because of the considerations discussed above, explosion-free designs of HV bushings – still seen as a comparatively new technology – are increasingly being used to obtain lower risk solutions in applications where substations are located in urban areas with buildings in the vicinity. While testing of explosive behavior may not yet be mandatory, it is increasingly being conducted these days in order to enhance reliability and reduce risk, irrespective of location of the installation.

Surge Arresters Examples of shattering of porcelain housings and oil leak on failed bushings.

HV Cable Terminations

Table 1, taken from a CIGRE Technical Brochure, illustrates rates and consequences of failures of cables and accessories in relation to overhead lines. Here, the major consequence looked at is measured by repair time.

HV metal oxide arresters are generally considered extremely reliable components with very low failure rates. Still, proper selection of a unit’s ratings and characteristics with respect to the electrical, mechanical and environmental stresses is crucial to maintaining this low failure probability.

The risk of failure can therefore never be completely disregarded, especially in places where attention to quality is not overly stringent or where type testing is not universally applied.

At the same time, if a termination that is about to fail happens to be filled with oil, the oil can ignite or be spilled into the environment. In certain cases, a resulting explosion can also damage adjoining apparatus, which means even longer repair times and higher costs – quite apart from the risk of personal injury to whoever happens to be nearby at time of failure. Indeed, one of the compelling reasons to specify explosion-free terminations at the transition from overhead lines to cables is to avoid dispersal of debris from any explosion resulting from overpressure due to internal short circuit.

Failures of bushings are responsible for a significant proportion of all transformer failures and can also be extremely violent. Although often regarded as only accessories, the fact is that bushings are the single major cause (roughly 80%) of all failures and fires involving transformers filled with insulating mineral oil (even though fire actually occurs in less than 15% of all transformer failures).

Failures of bushings can result in the porcelain housing shattering into shards and other fragments that are

Photos: courtesy of CESI

Bushings

HV bushing undergoing internal arc test.

HV termination failure simulation for an internal arc test.

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2. There is the possibility that arrester failure ignites a fire near the installation site. In this case, the risk for a polymer-housed design is greater since the polymeric material and FRP structure can potentially both catch fire. For porcelain designs, the only parts that can ignite are the sulfur cement and O-rings.

3. Possible detachment of the connection between the arrester and the power circuit. This is linked to the risk that connections, which are melted by the burning arc and pulled off by electro-dynamic forces, are projected toward and damage neighboring apparatus. Arrester failure can then evolve into a multi-phase short circuit. In order to avoid this, the top cap and connection must be properly designed to withstand short circuit currents.

Photo: courtesy of CESI

Procedures for Internal Arc Testing

Porcelain-housed 180 kV rated arrester collapses thermally after high current testing.

Potential reasons for surge arrester failure can include: severe energy stresses related to temporary overvoltage phenomena or lightning and switching events; moisture ingress; and ageing of internal parts (Editor: please refer to article on p. 94).

With respect to short circuit performance, two different surge arrester designs have to be considered:

Type A: Designs with internal gas volume

These arresters are either porcelain or polymer-housed with a tube design. Design A type surge arresters are fitted with pressure relief devices at both ends intended to vent any internal overpressure and to transfer the arc to the outside.

Type B: Designs without internal gas volume

These surge arresters are polymer-housed, with either a ‘wrapped’ or ‘cage’ design. In the case of Design B type arresters, any gas generated internally will be expelled directly through the housing. This can take place through a ‘weak point’ intentionally placed there for this purpose (for the wrapped design) or through the space between loops (for the cage design).

Potential risk factors in the case of arrester failures can involve three aspects: 1. In the case of violent shattering, there is the possibility of ejection of housing fragments, resistor blocks or metal fittings and connections. Here, porcelain-housed designs present a greater risk simply because porcelain fragments are inherently more dangerous than soft polymeric fragments.

Testing and certification are important tools to ensure both the safety and reliability of electrical networks. For the reasons discussed above, among the HV components most often submitted to testing for safety reasons are cable terminations, arresters and bushings.

The main difference when it comes to testing these components lies in the applicable situation in respect to the norms. While IEC and IEEE standards already exist for arresters, there are still no international standards available for HV bushings and cable terminations. Rather, technical specifications for these have been prepared by major national utilities, such as Terna, EdF/RTE, etc. while European standards (HD) are also available.

The HD standard, for example, prescribes triggering the internal arc in a termination by drilling a hole in the main insulation. A 1.5 mm2 copper wire then connects to the screen/metal sheath or a piece of metal is connected to the shield/sheath in order to simulate failure. Later, a short circuit current is applied, whose values (kA and seconds) are chosen according to the maximum short circuit current of the circuit where the HV termination is to be installed. In spite of the fact that the scope of this standard is limited to cables and accessories up to 170 kV, the same test modalities are also now being used for higher ratings of terminations as well as for bushings.

Based on experience gained from such tests performed at CESI over past years, it can be stated that an internal arc test on HV terminations and bushings is usually quite onerous for both the power laboratory and the manufacturer involved, since: • test set-up and auxiliary electrical facilities such as power source connections, etc. need to be expressly installed and then dismantled after the test; • demanding protection measures have to be put in place to avoid environmental problems; • ejected parts from violent shattering can damage the test chamber and even the nearby surroundings; • smoke and noise are harmful to test staff and the environment, which, taken together with the high test ratings, may require overnight tests.

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the third phase significantly increases prospective asymmetry factor and enables the required testing performance to be achieved.

Photo: courtesy of CESI

In regard to testing Design B type arresters, the critical issue is the pre-failing process. Here, the resistor blocks have to be electrically pre-failed such that during the following test phase the power arc can be established when energized at test voltage by the power supply. A proper selection of suitable pre-failing test circuits and procedures is crucial to allowing testing of surge arresters with both high rated voltage and high rated current. In fact, for such surge arresters the available test voltage of the power supply is a small percentage of the rated voltage of the unit under test.

Polymeric-housed 72 kV rated arrester catches fire during high current test.

These challenges will only become greater in the future if one considers the increasing market demand for higher values of short circuit current.

As for surge arresters, the ‘classical’ IEC pressure relief test procedure initially developed for gapped silicon carbide porcelain-housed types and then extended to cover metal oxide porcelain-housed designs was found not to be suitable to cover the polymer-housed arresters developed since the 1990s.

A significant revision of testing technique and procedure as well as of the relevant standard itself was therefore necessary to address the problem. This activity was undertaken by TC37 MT4 and the task took several years.

One of the challenges was finding a compromise between the need to represent actual service phenomena as faithfully as possible and the technical limitations as well as costs at existing high power laboratories.

Also, a major change had to be introduced for Design B type arresters in the short circuit preparation phase, i.e. replacing the classical shorting wire placed all along the resistor column by an electrical pre-failing procedure better able to simulate actual service phenomenon. The relevant standard – IEC 60099-4 am1 – was published in May 2006.

One of the problems that had to be faced by laboratories when testing Design A type arresters at rated short circuit current is their increasingly significant high arc resistance as they become longer. This issue, together with reduction of available test voltage due to the high symmetrical current required, can lead to a major reduction of the asymmetry factor achieved during testing. To overcome this, a three-phase test setup has been introduced at CESI. A delayed operation for making

Short circuit testing of HV arresters can also be quite demanding for any high power laboratory, for much the same reasons discussed above for terminations.

These types of issues will only become more relevant as testing involves bigger and bigger units with increasing test currents.

Based on experience gained testing arresters on behalf of several different manufacturers according to the latest IEC standard as well as other applicable national or international standards, the following conclusions can be drawn: 1. Compared to other type tests prescribed for arresters, the short circuit test remains the critical one since the percentage of failing results is considerably higher than for the other tests; 2. Testing at rated current is usually far more important in regard to risk of violent shattering versus testing at reduced or low currents; 3. For polymer-housed arresters, testing at low current is the more critical in regard to the risk of fire ignition; 4. Detachment of the connection between the arrester and the power circuit is a potential problem area, however is still not being adequately considered within the evaluation criteria of present international standards.

Summary & Conclusions

Worldwide demand for power networks will only increase, pushing utilities to install growing populations of HV cable terminations, bushings and surge arresters. At the same time, attention to safety and the environment are also growing. Proper selection of the ratings and characteristics of these components together with high quality levels will be key to reducing the probability of failures even though risk of such events can never be completely disregarded. Therefore, laboratory tests to simulate internal fault will remain a useful tool to help select those products that have safe performance during failure and reduce risk of violent explosion or fire on the network.

Requirements for safety of substation equipment will only become more stringent. As such, it will also become more important to harmonize and standardize testing requests coming from utilities across the globe. 

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Low Cost, Rapid Solutions to Most Line Constraints Arago’s high strength insulating cross-arms allow transmission system operators: • Rapid solutions to conductor clearance issues • Compact towers 25% lower than conventional • Convenient & economical +200% line capacity upgrades

Also looking for interested international supply chain partners

Learn more about the benefits of Arago’s insulating cross-arms, by visiting: www.aragotechnology.com or e-mail David Chambers: d.chambers@aragotechnology.com

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TOWERS

Developing Composite Insulating Cross-Arms for 400 kV Lattice Towers

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O

ngoing development of overhead power infrastructure faces key challenges these days from the perspectives of cost as well as objections by a public that has grown wary of transmission lines.

While cable may offer a solution in terms of visual impact, it comes with a significant construction cost premium. Maintenance and repair is also more expensive and time consuming.

Expanding the power transfer capacity of existing overhead lines is one solution and involves options such as re-conductoring or application of flexible AC transmission systems. Upgrading lines on existing corridors is also an option and can be achieved by modifying towers to handle higher voltages or by mov-

ing from single circuit to double circuit lines. Still, rebuilding lines on existing routes also requires planning consent, which depends on public approval â&#x20AC;&#x201C; just as for new lines. In both cases, making towers as low and unobtrusive as possible helps reduce visual impact and maximize acceptance by affected communities.

Based on these considerations, there has recently been much research devoted to finding new tower designs that utilize composite cross-arms to replace insulators as well as traditional steel cross-arms. Such a single insulating structure could offer benefits, especially for application on lines in urbanized areas. However, an insulating cross-arm solution is neither traditional insulator nor tra-

Photo: courtesy of Arago Technology

ditional cross-arm. That means suitable testing and evaluation must be carefully considered.

This article, contributed by Profs. Simon Rowland and Ian Cotton of the University of Manchester and David Chambers of EPL Composite Solutions in the U.K., describes one such program that focuses on the practical application of such cross-arms on lattice transmission towers.

Tower Configurations & Composite Cross-Arms

A typical twin circuit tower of the type used in the United Kingdom and elsewhere is illustrated in Fig. 1. Here, tower height is effectively determined by factors such as statutory ground clearances, conductor sag, insulator length, conductor-to-conductor separation, conductor-to-tower clearance and lightning shielding requirements.

Depending on system voltage, span length, conductor and service environment, some of these factors become more important than others. In addition, possible blowout conditions (i.e. when an insulator assembly breaches the required air gap from the tower) contribute to determining tower width and also when making for conductor-to-tower calculations.

Among the key benefits of composite cross-arms is that insulator swing under windy conditions is reduced to a minimum and instead determined by metal clamping assemblies. There is also no requirement for additional tower height to accommodate the length of the insulator string itself.

Therefore using composite insulating cross-arms can effectively raise heights of conductors by this same distance, i.e. about 4 m in the case of a 400 kV line. Basically, such a solution can: 113

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Mechanical Requirements

Photo: courtesy of Arago Technology

In normal operation, the higher elements of a cross-arm are in tension and the lower elements in compression (as in Fig. 4). It has also been noted by experts that the fundamental limit to application of such a cross-arm is the compressive strength of its lower member. If this limit is exceeded, the cross-arm will buckle.

Fig. 1: Tower height constraints (bottom left insulator shown blown-out).

Fig. 2. Example of ‘blow out’ on exposed 132 kV tower in U.K.

1. resolve ground clearance problems on existing lines; 2. allow greater sag on existing or new conductors, critical to improving power transfer capacity since it enables conductors to run at highest rated temperatures while still not infringing ground clearances;

3. facilitate voltage upgrading due to improved clearances from towers, especially since risk of blow out is mitigated; 4. permit more compact towers with smaller foundations and therefore reduced costs (see Fig. 3).

Typically the most extreme and limiting situation for design is under broken wire conditions, in which case high asymmetric stresses are experienced in the cross-arm. This is less of a problem for cross-arms designed to be able swing to the side, as seen on compact lines supported by steel poles. Composite insulator cross-arms have therefore become popular for such applications. Still, even in this case, insulators may need to be ‘doubled-up’ to provide sufficient compressive strength (as in Fig. 5). This is because traditional composite insulators are not able to provide sufficient compressive strength since their diameters would have to increase to the point that they become too heavy or too costly to produce.

In cases of steep terrain, galloping or ice shedding, the circumstances whereby a cross-arm is exposed to uplift also has to be considered in line design.

Electrical Requirements

The electrical requirements of insulating cross-arms are essentially equivalent to those of the insulators they are intended to replace, i.e. long, reliable service life under stresses including lightning and switching impulse withstand.

Avoidance of high power-frequency leakage current and flashover events are also basic system requirements.

Fig. 3: Compact tower made possible by composite insulation cross-arms.

Normally the performance of existing lines sets the benchmark for any new products and standards. At the same time, manufacturer specifications exist in regard to insulator performance. Local requirements for insulation coordination (i.e. arcing horns) must also be designed into the cross-arm while corona and RIV testing is also mandatory.

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Image: Bernstorf, R A, ‘Composite Braced Line Post insulators’ INMR World Congress, Seoul, 2011

Fig. 4: Design considerations in composite insulator cross-arms.

The motivation behind composite cross-arms has existed for many years although early designs to replace lattice structures were not deemed practical due to limitations in insulating materials and systems of the day. Indeed, as far back as 1964 it was suggested that the underlying problem of buckling under compression could be solved by using resin rods rigidly bonded by cross-members (as in Fig. 6). The practicality of this solution however was limited by its construction and by the fact that high performance polymers such as silicone rubber were not available for the sheaths and sheds.

In 1971, a fully insulating cross-arm was developed for a lattice tower based on ceramic technology (Fig. 7) but its weight would have required especially robust lattice towers and mechanical considerations also made it impractical.

Testing & Trials of New Design

A new design of cross-arm capable of being deployed on 132 kV, 275 kV and 400 kV lattice towers is shown in Fig. 8.

Fig. 5. 420 kV compact line near Cape Town (braced twin post design).

The cross-arm in this case was installed on four consecutive towers and replaced the middle crossarm of a redundant line. Its basic insulating elements are fabricated from standard pultruded fibreglass

Photos: courtesy of Arago Technology

Concept Realization

Fig. 8: Insulating composite cross-arm on 132 kV tower. and silicone rubber, but of a unique and proprietary construction.

Mechanical Testing & Field Trials Prior to installation, the cross-arm was tested mechanically (without energization) to verify design techniques. In particular, broken wire testing (i.e. highly asymmetric loads as in Fig. 9) as well as ultimate tensile tests were found to satisfy design predictions and confirmed that the cross-arms could indeed withstand normal service requirements.

Over the two-year trial, real-time monitoring took place, including video imaging during prolonged snowy periods. Wind speeds of over 100 miles per hour (160 km/h) were also recorded. Together, these offered excellent data on the reliability of the cross-arm such that it was decided to proceed next to a live trial.

Electrical Testing & Field Trials

Fig. 6: Three-dimensional composite cross-arm first proposed in 1964 (side view above, plan below).

Photos: courtesy of Arago Technology

Image: UK Patent 1,034,224: ‘ Improvements in Electric insulators’ 1966

Electrical modelling using finite element analysis was performed in order to generate full 3-D models of the unit’s complex geometries at the precisions required. In particular, consideration was given to controlling field stress at the highvoltage end of the cross-arm.

Fig. 7: Implementation of two versions of ceramic cross-arm (1971).

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Photo: courtesy of Arago Technology

Standard laboratory tests for insulation systems, including impulse and wet withstand, were completed prior to installation on a live system. This trial, energized at 400 kV system voltage, saw two perpendicular crossarms mounted on a specially constructed lattice tower.

The cross-arms were placed perpendicular to one another to determine if wind direction played any role in electrical performance.

Fig. 9: Testing early version with hydraulic systems replicating broken wire conditions.

Leakage current to ground on each of the four insulating elements of all cross-arms was continuously monitored, allowing all to be compared. This enabled electrical performance of the four traditional tension members to be directly compared with that of the four compression members. In addition, the site was monitored using video cameras that also provided close-ups of all surfaces.

A weather station at the top of the structure allowed real time monitoring of wind speed and direction, RH, precipitation, visibility and solar radiation, i.e. all environmental factors that could affect performance.

Conclusions Photo: courtesy of Arago Technology

Composite insulating cross-arms have been developed as part of a multi-year research and test program. These are intended to replace steel cross-arms and suspended vertical insulator strings on traditional lattice towers, thereby enabling conductors to be attached directly to the cross-arm.

Fig. 10: Example of FEA analysis during cross-arm design.

Major potential benefits to transmission system operators on existing lines include: • retro-fitting towers, with no change in tower dimensions or profile, while allowing up to 150% more capacity due to increased ground and tower clearances; • increasing ground clearance so as to overcome any possible local infringement issues; • greater current carrying capacity of conductors due to increased allowable sag.

• upgrading the voltage of exiting towers, for example taking 132 kV towers to 275 kV.

Photo: courtesy of Arago Technology

In the case of new lines, there would also be benefits of: • cost savings through reduced time for obtaining planning approvals and also due to smaller structures and foundations; • reductions in tower heights (see Table 1). 

Fig. 11: 400 kV test site.

Table 1: Comparison of Traditional Lattice Towers & Those With Composite Insulating Cross-Arms Voltage (kV)

Fig. 12: Example current and weather data from test site.

Traditional Tower Design

Compact Design

Typical Size Reduction*

Height (m)

Width (m)

Height (m)

Width (m)

Height (%)

Width (%)

132

27.8

5.7

24.3

5.6

-12%

-2%

275

34.8

9.2

27.1

9.0

-22%

-2%

400

40.0

12.1

29.8

11.7

-26%

-3%

*Based on the use of a double shield wire and taking a span length of 375m. Tower dimensions calculated using data from various National Grid specifications and BS EN 50341

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MAINTENANCE

Corona Camera Supplier Extends Product Range Mitigating the presence and impact of corona on overhead lines and at substations is among the important tasks confronting power system operators. The reason for this is that, if left unchecked, corona can lead to a variety of problems, including progressive degradation and eventual failure of certain types of insulation.

INMR travels to Israel to meet a supplier of specialized cameras that help maintenance personnel monitor their networks for the presence of corona. Ofil Systems has been offering such equipment since the mid 1990s but has greatly expanded its product range in recent years to meet different inspection protocols and user requirements.

Examples of corona detected on insulators, conductor and busbar.

Photos: courtesy of Ofil Systems

One of the key elements for the build-up of sufficient ionization to trigger the UV emissions associated with corona is some critical level of localized electric field.

Corona in Power Networks

Corona is caused by ionization of gas and subsequent release of light when electrons that have gained energy from a high electric field revert to their original stable state. Since the discharge does not completely bridge the electrodes, it is sometimes referred to as partial discharge.

The reason that the glowing effect is concentrated around the corona source is that insulation provides an effective barrier to further ionization.

Moreover, intensity of the electric field decays rapidly with greater distance and eventually field strength becomes unable to sustain continued ionization. Indeed, one of the requirements for build-up of sufficient ionization to trigger the UV emissions associated with corona is some critical level of localized electric field. If this minimum value is not reached, corona will essentially be absent.

Corona can affect a range of network hardware, equipment and components â&#x20AC;&#x201C; from switchgear to capacitors, from conductors to busbars, from generators to breakers.

When it comes to insulators, corona can originate from end fittings, contamination or from protruding elements such as ice sickles and water drops.

Polymeric materials are more susceptible to degradation from corona due to corrosive substances created when corona is emitted.

Corona ruptures stable oxygen molecules in air to create radicals.

These then combine with molecules to form ozone (O3), which attacks unsaturated bond sites in elastomeric materials such as silicone or EPDM. The end result is usually cracking.

Even tiny amounts of ozone, e.g. in the ppm range, are sufficient to initiate cracking, however the time required for this to occur will depend on material composition.

Ozone also combines with nitrogen in air to produce nitric oxide gas, a major greenhouse contributor. While most elastomers used these days in electrical insulation are formulated to resist ozone attack, they may eventually succumb should its concentration become sufficiently high.

117

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High corona level detected moments before failure of silicone insulator where there was internal damage due to mishandling.

and glass – have much higher resistance to it than do polymeric materials. But this does not mean that these insulators are immune to all possible negative effects, which can include acid and heat attack on the cement used to attach fittings.

technology. According to industry experts, IR cameras find most benefit detecting internal phenomena such as hotspots that are typically current dependent. These suggest a progressive existing problem that needs to be remedied quickly.

Among the questions often asked by maintenance personnel who are responsible for inspecting lines and substations relates to the relative seriousness of any corona activity that may be observed. Is it reason to take immediate action or perhaps only a transient phenomenon posing no long-term threat? The answer depends largely on where the observed corona is taking place.

By contrast, UV inspection for corona is voltage dependent and designed to detect mainly external phenomena affecting the surface of what is being monitored. Such predictive inspections can be performed under virtually any weather conditions, apart from rain, and can help detect problems at an early stage – before they have progressed to the point of serious deterioration.

Photos: courtesy of Ofil Systems

Corona produces oxalic and nitric acids in the presence of water from ambient humidity such as dew, fog or any surface moisture. Depending on the pH of these acids, polymers can then undergo additional degradation.

Corona has even been known to ‘drill’ holes in a material, suggesting that degradation is not due solely to chemical attack. For example, temperatures at the tip of a corona discharge have been found to be high enough to cause ‘evaporation’ of even inorganic materials. There is also danger of mechanical attack to an elastomeric material, much like sandblasting, due to the impact of repeated discharges.

Since degradation due to corona is initiated at the molecular level, inorganic dielectrics with strong chemical bonds – such as porcelain

Polymeric materials are more susceptible to degradation from the UV produced by corona than from UV due to solar radiation, especially if the corona is close to the material.

For example, corona on insulator hardware due to a rough surface may be relatively benign. However corona directly on the insulator itself is a warning that degradation processes may soon be underway.

In spite of the many problems linked to corona, it is not necessarily a given that it will always shorten the expected service life of composite insulators installed on high voltage lines. This is because corona can be greatly mitigated and even eliminated

Another question typically raised is how inspecting for corona relates to thermal analysis using infrared cameras, a well-established complementary inspection

Photo: courtesy of KEPCO

Photo: China State Grid

Photo: courtesy of Ofil Systems

Heat from corona can dry out cement of cap & pin insulators, causing pitting and cracking.

Examples of how sustained corona on polymeric insulators under adverse service conditions can degrade housing and trigger end of life processes.

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(Top) Goldbaum (at right) looks at internal mechanism of one of Ofil’s corona cameras. Assembly of solar blind filters.

through good insulator design and manufacturing. At the same time, need for a corona/field-grading ring will depend not only on voltage level but also on location. For example, insulators operating in areas of heavy contamination, at high altitudes or under prolonged heavy wetting must always be equipped with properlydesigned and correctly-installed corona rings at the line end – ideally even at voltages below 230 kV. That is because if sustained corona activity takes place near a composite insulator’s polymeric housing, its normal life expectancy will almost certainly be reduced.

Photos: INMR ©

Detecting & Assessing Corona Using Cameras

For most practical purposes, corona cannot be seen or heard without the use of specialized equipment.

Therefore, it can go unnoticed and cause progressive degradation of insulation up to the point that failure occurs. “That,” says Ofil Systems CEO, Moshe Goldbaum, “is why the name of the game is not only to detect corona but ideally to do it when still at an early stage.”

In order to detect corona, it is logical to look for the UV radiation it emits and this is where specialized cameras play their role. Most of the light produced by corona has a wavelength shorter than 400 nanometers and therefore falls in the UV range. By contrast, solar radiation lies principally in the visible spectrum (400-700 nm), the shorter wavelengths being filtered by the earth’s ozone layer.

One of the past problems associated with monitoring for the UV from corona has been that the wavelength of the radiation emitted corresponds directly to that of background solar radiation. It is therefore blocked from view during daytime and corona camera manufacturers have had to find ways around this problem.

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optical filters to block out background solar radiation and allow only the radiation emanating from a corona source to be observed. The technology is based on the fact that all UV radiation in the solar blind band (i.e.

240 - 280 nm) is absorbed by the earth’s ozone. It is therefore at this exact range that the solar blind filter enables detection of UV emissions due to corona, even during daylight.

To pinpoint the corona source in relation to the equipment being monitored, a bi-spectral approach is employed. One channel in the camera allows the observer to see the object being studied in the visual spectrum while another channel uses solar blind technology to view only the UV radiation emanating from a corona source. The two signals are then overlapped to generate a composite image of the object and the location of any corona that might be affecting it.

improper installation, loose hardware, contamination, erosion or broken strands on a conductor,” she says.

“Therefore, repetitive inspections allow maintenance staff not only to identify that something may be wrong but also to learn if that problem has progressed over time.”

It is amazing that any single physical phenomenon can trigger so many different modes of degradation – and all at once.

Barzilay also explains that knowing corona inception voltage of whatever object is being monitored also helps network operators determine if the right component has been specified for the application. “In the case of conductors, for example, there is a direct relationship between corona and bad practice,” she observes, “with the radius not matching applied voltage. We often see older transmission lines become noisy with abundant corona. In most cases, the reason is the utility's response to a rise in demand for electricity.”

In recent years, much of the development work at Ofil seems to have been focused on modifying the range of cameras to make them more efficient or more practical for each alternative type of inspection. For example, European Sales Manager, One of the challenges faced by corona Bar Weinstein, reports that cameras camera users is that no recognized have now been developed that international standard yet exists to are specially suited for mounting measure corona intensity. That means in a gimbal for aerial inspection. users must be able to reach their According to Goldbaum, the key These, he says, also combine an IR own conclusions based on results factors when it comes to corona camera, from a partner company, of several inspections. Recognizing cameras are their transmittance and integrated into one basic system. this, Marketing Communications absorbance, two parameters which Other cameras have been specially Manager, Hannah Barzilay, points define the detector's efficiency. A adapted for inspection of railway sensitive corona camera transmits as out that Ofil has developed its own lines and rely on internal software counting technology to inform users many UV photons emanating from to process the many images so as to whether the level of corona detected corona as possible and blocks noise highlight only those locations where is low, medium or high. Says and visible light. there is corona and possible need for Barzilay, “a corona camera is really maintenance. There are also cameras more indication equipment than Sales & Marketing Director, Revital intended for mounting on vehicles measurement equipment. That means or for use in high voltage testing Lazimi, contrasts the benefit of data from thermal inspection using infrared it is always best to compare findings laboratories. against a database of accumulated cameras with ultraviolet inspection information from previous using a corona camera. “Once heat In particular, an expanding range inspections. Moreover, since the is detected inside an electrical of portable cameras has been component,” she explains, “it may be level of corona depends on ambient developed, with the focus on temperature and humidity, successive convenience, comfort, lightweight or too late to save it. Replacement may inspections of the same equipment then be the only option. By contrast, lower cost. These units offer a menu should ideally be conducted under our cameras raise a red flag at an of possible features, including wide similar weather conditions.” early enough stage that maintenance field of view (ideal for monitoring personnel still have time to investigate substations), still images, video more closely. That type of information images and zoom capability. The helps a power utility to save money.” most recent introduction, at only 0.85 kg is claimed to be the lightest Lazimi goes on to explain that corona corona camera in existence and inspection does not always offer a intended mainly for use in indoor ‘black or white’ answer as to whether inspection. Says Lazimi, “we see our or not there is a need to replace a basic business as helping to improve component, such as an insulator. maintenance of power infrastructure.

Rather, it becomes another factor for But inspection processes and maintenance staff to consider when requirements change from one deciding what action may be needed customer to another, so we offer to avoid a failure in the system. users a choice of several options Camera image shows location of “Corona is a sign of some defect, – all with the same basic internal corona source. resulting from issues such as technology.”  120 INMR Q2 Issue 104.indd 120

2014-05-22 1:54 PM