003 Outdoor-High-Voltage-Insulators-Book - Compressed - Compressed

W L VOSLOO
R E MACEY
C de TOURREIL
THE PRACTICAL GUIDE TO
OUTDOOR
HIGH VOLTAGE
INSULATORS
Acknowledgements
The authors acknowledge the key role of Eskom Resources and Strategy
Division in funding and supporting the preparation of this book and the
Distribution Insulator Work Group members for their valuable input.
We would like to thank Dr H Schneider for the writing of the foreword, Dr JP

Holtzhausen, Dr S Gubanski, Mr R Stephen, Mr B Meyer and Mr AC Britten
for their technical review and Dr MJ Hurndau for the editing of the text.
We also acknowledge with appreciation, the use of the high voltage laboratory
of the University of Stellenbosch for the production of the video clips, the
drawing of the cartoons by Mr D Foster, the programming of the pollution
calculator by Mr B Hellstrom and the cover photograph supplied by Dr JP
Holtzhausen.
Finally the authors express their gratitude to colleagues in the industry, at IEC
and Cigre, for the many technical exchanges and discussions over the years,
all of which have contributed to their knowledge and understanding of the
subject.
ii
Foreword
It is refreshing to see a book on high voltage insulators that addresses so many issues related
to the reliable operation of power transmission systems in a time when the integrity of grids is
becoming of ever increasing importance. The modern world has at the same time become
highly sophisticated because of advances in technology but nevertheless more intolerant of
even momentary outages in electricity supply, let alone catastrophic failures such as line
droppings where the costs are enormous.
The words “practical guide” in the title are most appropriate because of the wealth of
knowledge presented by the authors from their years of experience with regard to design and
maintenance of operating systems, laboratory testing, and diagnostics of failures. Students
as well as practicing engineers will find the text easy to follow and a worthy reference on so
many subjects not found elsewhere.
The book relies heavily on recommendations made by IEC and simplifies the task of finding
reports and standards on tests and specifications. The short yet concise section on this
subject will be welcomed by anyone who has had to wander through the maze of available
documents related to high voltage insulators without any systematic guide.
What makes this volume unique is the striking use of high quality illustrations for the topics
that are treated. Although detailed verbal descriptions can be very effective to communicate
certain concepts, it is far more efficient to show examples as has been done particularly
extensively in the chapters on failure mechanisms and handling and installation practices.
Knowledge of appropriate handling and installation practices and demonstration of incorrect
techniques are of special significance and have been treated in depth. It is well known that
problems initiated because of inappropriate procedures can lead to disastrous consequences
not only in short time frames but even years later and thus must be avoided. While it is
impossible to imagine all the mistakes that can be made, many suggestions are given to
avoid future difficulties. The short lists of what to do and what not to do on receipt and
storage, transport, on-site handling, installation, and conductor stringing form a very useful
guide for utilities.
The two major flowcharts, one on insulator selection and the other on pollution mitigation
techniques, help the reader understand relatively complex issues by giving visual reminders
of what should be considered in each case. It is noteworthy to mention that the authors tackle
the issue of cost in the section on mitigation, something that often has been neglected but
must be considered before adopting a particular strategy.
Candid statements are made throughout the book to make it a practical guide. For example,
in discussing washing frequency, the authors have the courage to say “accurate forecasting
of potential flashover is impossible”. In my experience this fact has been quite difficult for
many utilities to accept no matter how many arguments are made to support it. Another
example of the very direct approach used in the book involves line fault investigations where
interviews with local utility personnel and residents to obtain information about weather
conditions prevailing at the time of a fault are discussed. The authors warn “Beware, though,
of pre-conceived ideas affecting the feedback. Sweeping statements like ‘the problems
always happen on rainy nights’ need to be checked.” They then cite one case where such
generalizations proved to be false. Having been involved in many fault investigations, my
personal experience is that great care and patience must be used to correctly assess root
causes.
It gives me great pleasure to recommend this book to those who have responsibility for
insulation of high voltage lines and substations, students of high voltage technology, and
consultants who may be called upon to assist utilities in the application of high voltage
insulators.
Dr Herman Schneider
iii
Contents
HOW TO USE THE BOOK xi
1 INTRODUCTION 1
1.1 Historical Overview 1

1.2 The Critical Role of Insulators 2
1.3 Increased Requirements 2
1.4 Future Demand 3
2 INSULATOR TYPES AND CHARACTERISTICS 4
2.1 Insulator Materials 4

2.1.1 Porcelain 4
2.1.2 Toughened glass 5
2.1.3 Epoxy resin 5
2.1.4 Polymer composites 6
2.2 Fundamental Physical Aspects 7
2.2.1 Arcing distance 7
2.2.2 Creepage distance 7
2.2.3 Puncture distance 8
2.2.4 Insulator class 8
2.3 Insulator Types 8
2.3.1 Pin insulator 9
2.3.2 Line post insulator 9
2.3.3 Composite line post insulator 10
2.3.4 Cap-and-pin (disc) insulator 10
2.3.5 Long rod insulator 11
2.3.6 Composite long rod insulator 11
2.3.7 Station post insulator 12
2.3.8 Pedestal post insulator 12
2.3.9 Bushing 13
2.3.10 Apparatus (hollow) insulator 13
2.3.11 Stay (guy) wire insulator 14
2.3.12 Guy strain insulator 14
2.4 Insulator Sheds 15
2.5 Insulator End Fittings 15
iv
3 ELECTRICAL CONSIDERATIONS 17
3.1 Dry and Wet Power Frequency Flashover 17

3.2 Lightning and Switching Impulse Flashover 18
3.3 Power Frequency Pollution Flashover 19
3.3.1 Pollution flashover process 19
3.3.2 Leakage current amplitude and surface resistance 20
3.3.3 Specific creepage distance considerations 22
3.3.4 Profile considerations 24
3.4 Other Electrical Considerations 26
3.4.1 Risk of puncture 26
3.4.2 Corona 26
3.4.3 Resistance to power arc damage 27
3.4.4 Snow and ice flashover 28
3.4.5 Instantaneous or rapid conductive fog flashover 28
3.4.6 Bird streamer flashover 29
3.4.7 Lightning-induced back flashovers 29
3.4.8 Voltage transfer 32
3.4.9 Temporary overvoltages (TOV) 33
4 ENVIRONMENTAL CONSIDERATIONS 34
4.1 Pollution 34
4.1.1 Pre-deposit pollution 34
4.1.2 Instantaneous pollution 35
4.1.3 Pollution sources 35
4.2 Weather 36
4.2.1 Temperature 36
4.2.2 Humidity 36
4.2.3 Rain 37
4.2.4 Fog 37
4.2.5 Wind 37
4.2.6 Solar radiation 37
4.2.7 Ice and snow 38
4.2.8 Lightning 38
4.2.9 Air density 39
v
4.3 Site Severity Assessment 39
4.3.1 Surface pollution deposit technique 39
4.3.1.1 Active pollution – equivalent salt deposit density (ESDD) 40
4.3.1.2 Inert pollution – non-soluble deposit density (NSDD) 41
4.3.2 Directional dust deposit gauge technique 42
4.3.3 Site severity class 44
4.3.3.1 Surface deposit index 44
4.3.3.2 Dust deposit gauge pollution index 45
4.3.4 Other pollution assessment methods 45
4.3.4.1 Localised equivalent salt deposit density (LESDD) 45
4.3.4.2 Surface conductivity hand probe 46
4.3.4.3 Automated insulator pollution monitoring 47
4.3.4.4 Existing insulator performance 48
4.4 Other Environmental Considerations 49
4.4.1 Bird streamers 49
4.4.2 Birds, rodents and termites 50
4.4.3 Soil resistivity 50
4.4.4 Seismic activity 51
4.4.5 Corrosion 51
4.4.6 Vandalism 51
5 MATERIAL CONSIDERATIONS 52
5.1 Porcelain 52
5.1.1 Porcelain manufacture and properties 52
5.1.2 Construction of porcelain insulators 54
5.1.2.1 Cap-and-pin construction 54
5.1.2.2 Long rod insulator construction 56
5.1.2.3 Line and station post insulator construction 56
5.1.2.4 Hollow insulator construction 56
5.2 Glass 56
5.2.1 Glass manufacture and properties 56
5.2.2 Construction of glass insulators 58
5.2.2.1 Cap-and-pin construction 58
5.2.2.2 Post construction 59
5.3 Polymeric Insulators 59
5.3.1 Composite insulators 59
5.3.1.1 Composite insulator core 59
vi
5.3.1.2 Composite insulator housing 60
5.3.1.2.1 Silicone rubbers 61
5.3.1.2.2 EPDM 63
5.3.1.3 Construction of composite insulators 63
5.3.1.3.1 Injection and compression moulding 63
5.3.1.3.2 Extrusion 63
5.3.1.3.3 Un-bonded sheds 64
5.3.1.3.4 Other constructions 64
5.3.2 Resin insulators 64
5.4 Metal Fittings 65
5.4.1 Caps 66
5.4.2 Pins 66
5.4.3 Fittings for porcelain station post insulators 66
5.4.4 Fittings for composite insulators 66
5.4.5 Fittings for hollow porcelain and composite insulators 66
5.5 Relative Pollution Performance 67
6 MECHANICAL CONSIDERATIONS 69
6.1 Tensile Loads 69

6.1.1 Strain insulators 69
6.1.2 Suspension insulators 70
6.1.3 Angle suspension insulators 72
6.1.4 Insulator strength 72
6.1.4.1 Porcelain long rod and glass disc insulators 72
6.1.4.2 Porcelain disc insulators 73
6.1.4.3 Composite long rod insulators 73
6.1.4.4 Buckling loads 77
6.1.4.5 Torsional loads 80
6.2 Cantilever Loads 81
6.2.1 Line post and pin insulators 81
6.2.2 Braced post insulators 84
6.2.3 Station post insulators 88
6.2.3.1 Short circuit loads 88
6.2.3.2 Seismic loads 89
vii
7 FAILURE MECHANISMS 93
7.1 Glass Insulators 93

7.2 Porcelain Insulators 95
7.3 Composite Insulators 97
7.3.1 Housing 97
7.3.2 Core 101
7.3.3 Housing to core interface 104
7.3.4 Housing to end fitting interface 105
7.3.5 End fitting 105
7.4 Resin Insulators 106
8 TESTS AND SPECIFICATIONS 108
8.1 Porcelain and Glass Insulators 108

8.2 Composite Insulators 112
9 INSULATOR SELECTION AND SPECIFICATION 114
9.1 Insulator Type and Material 114

9.1.1 Pollution types and severity 116
9.1.2 Lightning severity 116
9.1.3 Vandalism 116
9.2 Insulator Characteristics 117
9.2.1 Electrical characteristics 117
9.2.2 Mechanical characteristics 118
9.2.3 Physical characteristics 119
9.2.3.1 Insulator length 119
9.2.3.2 Creepage distance 120
9.2.3.3 End fittings 120
9.3 Insulator Selection Chart 123
9.4 Insulator Specification 123
10 HANDLING AND INSTALLATION PRACTICES 125
10.1 Mechanisms of Failure 125

10.2 Factory Preparation 125
10.3 Stores Receipt 126
viii
10.3.1 Visual checks 127
10.3.2 Dimensional checks 127
10.3.3 Other checks 127
10.4 Storage 128
10.5 Transport to Site 128
10.6 On-site Handling 129
10.7 Insulator Installation 130
10.7.1 Specific precautions – line post insulators 131
10.7.2 Specific precautions – long rod insulators 134
10.8 Conductor Stringing 137
10.9 Pre-commissioning Insulator Inspection 139
10.9.2 Ceramic long rod insulators 140
10.9.3 Cap-and-pin disc insulators 140
10.10 Design Considerations 140
10.10.1 Insulator mobility 141
10.10.2 Component selection 141
10.10.3 Accessibility 141
10.10.4 Drawings 141
10.11 Handling Check Lists 142
11 INSPECTION AND ANALYSIS TECHNIQUES 150
11.1 Field Inspection Methods 151

11.1.1 Toughened glass insulators 151
11.1.2 Porcelain insulators 151
11.1.2.1 Single disc resistance measurement 152
11.1.2.2 Single disc voltage measurement 153
11.1.2.3 Measurement of the electric field 153
11.1.3.1 Visual inspection 155
11.1.3.2 Hydrophobicity measurement 156
11.1.3.3 Directional wireless acoustic emission 157
11.1.3.4 Light amplification equipment (night vision camera) 157
11.1.3.5 Infrared thermography 157
11.1.3.6 E-field measurement 159
11.1.3.7 Comments 160
11.2 Field Inspection Sheet 161
11.3 Line Fault Investigation 162
ix
12 POLLUTION MITIGATION TECHNIQUES 164
12.1 Insulator Replacement 164

12.2 Cleaning 164
12.2.1 Hand washing 165
12.2.2 Spray washing 165
12.2.3 Fixed live spray washing systems 167
12.2.4 Dry cleaning 168
12.2.5 Cleaning frequency 168
12.3 Silicone Greasing 168
12.4 Silicone Rubber Coating 170
12.5 Creepage / Shed Extenders 171
12.6 Insulator Upgrading 172
12.7 Mitigation Method Selection 173
12.7.1 Applicability 173
12.7.2 Accessibility 173
12.7.3 Risk 173
12.7.4 Cost 174
12.8 Conclusions 174
DEFINITIONS 176
LIST OF ABBREVIATIONS 183
LIST OF SYMBOLS 185
REFERENCES 190
INDEX 193
x
How to use the book
“The Practical Guide to Outdoor High Voltage Insulators” is intended to

provide an understanding of the factors which dictate the behaviour of
overhead line and substation insulators and to generate an appreciation of the
parameters which have a significant influence on their performance and life.
The Guide is aimed at utility staff and consulting engineers responsible for the
selection, specification, installation and maintenance of insulators. Students
of the subject and engineers-in-training should also benefit from its use.
The emphasis of the book is definitely on the “practical”, and simple

procedures, decision tables, flow charts and inspection sheets are included –
both in the text and on the accompanying CD – to assist those involved in the
design and operation of electrical transmission and distribution systems. The
structure of the book is described below.
Chapter 2 is especially useful to those who are new to the subject, of high
voltage insulators. It serves to define the terminology used and provide basic
information on the various insulator types and materials available. The main
physical attributes which determine the performance of insulators are also
addressed.
In Chapter 3 the electrical aspects to be considered when selecting

insulators, are discussed. It examines the various mechanisms of flashover
and the relationships between the probability of breakdown and the
dimensioning of an insulator.
It is impossible to select a suitable insulator for a particular application unless

the environment in which it is expected to operate is fully understood.
Chapter 4 describes the important ambient conditions that influence insulator
performance and provides techniques for their assessment. Methods to
interpret the climatic data and pollution levels measured, to define a “Site
Severity Class”, are described. This facilitates the selection of an appropriate
insulator for a given area.
With the wide variety of dielectric materials currently being used in the
manufacture of outdoor insulators, their relative characteristics need to be
known to ensure their suitability to the application in question. Chapter 5
examines the properties of various insulator materials and provides
information on their advantages, disadvantages and applicability to the
different insulator types and constructions.
xi
The primary function of overhead line insulators and most substation
insulators is to provide physical support to energised conductors and
equipment. Their mechanical characteristics are thus just as important as
their electrical properties. Chapter 6 describes how the forces imposed on
insulators should be analysed with a view to establishing the minimum
strength requirements.
Knowledge of the ways in which an insulator may fail in service is vital for the
correct selection of a new insulator. It is also important to define appropriate
maintenance procedures and inspection techniques for existing units.
Chapter 7 explores the different mechanisms of failure applicable to the
various insulator types and materials – describing their nature and illustrating
their effects.
Chapter 8 lists the IEC documents relating to the different insulator types
with a view to assisting in the testing of units and in the preparation of
purchasing specifications.
The various electrical, mechanical and environmental factors which determine

the performance of insulators and their vulnerability to failure, as described in
Chapters 2 to 8, are brought together in Chapter 9 which provides a
selection process aimed at ensuring that the insulator type used for a
specific application will yield a long, reliable and maintenance-free service life.
Having made the selection, information on the standard lengths, strengths,
end fittings, etc. applicable to each insulator type, to facilitate the drafting of a
meaningful purchasing specification, is also given.
Many insulator failures experienced in service are not the result of the
incorrect insulator having been used but are caused by the insulator being
damaged before or during its installation. Chapter 10 describes how poor
techniques used in the storage, transport and handling of insulators can
create defects, which may only manifest themselves at a much later date and
precipitate tripping, or even dropping, of the line. Precautions to be taken in
the treatment of insulators are listed and can be incorporated in line erection
contracts and specifications.
A variety of insulator inspection methods is described in Chapter 11. The

merits of the techniques and their applicability to the different insulator types,
materials and constructions are discussed. An Audit Sheet is provided to
assist field staff in the inspection and evaluation of insulators and to determine
appropriate response to their findings.
xii
When a line is suffering from an unacceptable occurrence of phase-to-ground
faults, the quality of the insulators is usually immediately questioned. In order
to determine the appropriate corrective action to be taken, however, it is vital
to establish the precise nature of the faults and their cause. In this regard,
Chapter 11 also describes an investigation procedure designed to identify
the actual breakdown mechanism and, for example, avoid costly re-insulation
programmes being undertaken which may not, in fact, improve the reliability of
the system.
Finally, Chapter 12 addresses what measures may be taken when the

performance of existing insulation in polluted environments is unacceptable.
Replacement of the insulators, particularly in substations, may not be an
option, and some form of maintenance is then necessary. The relative costs
and effectiveness of the various mitigation techniques are described. A flow
chart is also provided to assist in the selection of the optimum form of
corrective action.
The accompanying CD contains an imperial to SI unit conversion calculator,

insulator defect pictures with a short definition sheet, field inspection sheet,
insulator handling and transportation cartoons, a site severity calculator, and
video clips showing various high voltage phenomena such as insulator
pollution flashover.
xiii
Introduction 1
1 INTRODUCTION
“He who measures knows” – Wallace L Vosloo
1.1 Historical Overview
As soon as electricity could be generated in sizable amounts, its use required the means
to transmit this energy. Developing a component that would insulate the live wire from
ground was the initial main challenge. Although almost any solid non-conductive material
can insulate several hundred or a few thousand volts from ground in dry conditions, it was
soon realized that it is difficult to design an effective insulator for use in wet and polluted
conditions.
As shown in Figure 1.1, the early power line insulators, made in the 1880’s, resembled
telegraphic insulators, introduced about half a century earlier. During the following 30
years, many different designs were tried using various basic concepts. These concepts
are still valid today. The solid material must have good mechanical properties, its
dielectric strength must be high and its surface must perform well when electrical
discharges are present. Still better, the surface properties should be able to inhibit as
much as possible the occurrence of such discharges.
(a) (b)
Figure 1.1: Early telegraphic (a) and power line (b) insulators.
Interestingly, many present-day insulators look practically the same as insulators

developed almost a century ago (as shown in Figure 1.2).
Old New
Figure 1.2: Old and new cap-and-pin disc insulators.

Introduction 2
Early in the twentieth century, all insulators were made of porcelain. The development of
high strength porcelain led to the development and use of long rod insulators, an
extension of the Motor insulator first designed in Switzerland. A new technique to toughen
glass led to the introduction of toughened glass insulators in the 1930’s. The first
composite insulators, for which extensive use was made of polymeric materials, appeared
in the late 1960’s. They are of the long rod design, have a better strength-to-weight ratio,
and can be manufactured in longer length than their porcelain counterparts. In fact, the
length of composite insulators is limited mainly by their shipping and handling
requirements.
Courtesy of M Kuhl
Figure 1.3: Early composite insulator.
At first glance, modern insulators, whether cap-and-pin disc, long rod, post or apparatus
type, seem to be simple devices. They are, however, high technology components. It has
taken years of design and material development and refinement to achieve the
exceptionally high level of reliability of some insulators presently commercially available.
For example, the failure rate of high quality correctly dimensioned cap-and-pin insulators
is less than one unit for 10 000 installed units per year.
1.2 The Critical Role of Insulators
Although the cost of the insulators is a relatively small percentage of the cost of building a
new transmission line, failure of this fairly small component can result in serious human
injury and have important economic consequences. Nonetheless, especially over the last
20 to 30 years, market forces have resulted in reduced insulator prices. The cost of a line
insulator relative to the daily wage of a worker in Western society has significantly
decreased over the past 80 years. This may explain why, except for the development of
composite insulators, the basic design and materials used have not changed much over
almost a century.
A consequence resulting from the selection of an insulator of inferior quality or of an

insulator with characteristics not matching the service requirements can be far more than
the cost of its premature replacement. The cost of additional maintenance, application of
pollution performance enhancing coatings or frequent washing all have a significant
economic impact. The repair and the daily cost of the unavailability of an important power
line can reach hundreds of thousands of dollars.
1.3 Increased Requirements
The first overhead lines designed to transmit electrical energy were built in the 1880’s and
1890’s. Until about 1910, the highest operating voltage was between 50 and 66 kV. By
the 1960’s, the operating voltage had increased more than 10-fold. Insulators have had to
meet not only the new electrical stresses demanded by these very high operating voltages
but also the much increased mechanical loads that came with these new lines.
Introduction 3
At about the same time, growth in the world population density and the corresponding
higher industrial and agricultural production increased the amount of pollution imposed on
insulators. This made environmental stress one of the most critical factors to be
considered in the selection of insulators. Moreover, because modern electronic
equipment and apparatus need a quality and a continuity of supply not required
previously, it is imperative that modern insulators have the highest achievable level of
performance.
Courtesy of Eskom
Figure 1.4: A 66 kV power line under construction in 1912.
To ensure the compliance of modern insulators with the requirements of recent electrical
networks, an extensive series of test techniques and standards have been developed by
organizations such as the International Electrotechnical Commission (IEC) using technical
experts coming from both the users and the manufacturers of insulators.
1.4 Future Demands
Industrial development requires a high rate of expansion of the electricity supply network.
Consequently, thousands of kilometres of new high voltage lines and their accompanying
substations are being built or are in the planning stage. All require insulators.
In the already industrially developed parts of the world, many lines and substations have
reached an age that requires their refurbishment. Other lines will have to be upgraded or
uprated. Under the pressure of environmental constraints, existing lines may have to be
replaced by more compact designs. All this will not only require improved insulators, but
also new insulator testing and evaluation techniques, and possibly new selection criteria.
Insulator Types and Characteristics 4
2 INSULATOR TYPES AND CHARACTERISTICS
“A scientist discovers that which exists. An engineer creates that which never was” –
Theodore von Karman
Introduction
This chapter serves to provide an overview of the basic insulator types available including
their fundamental designs, materials, electrical and mechanical characteristics and their
intended applications. Each of these aspects is then explored in more detail in the
subsequent chapters.
2.1 Insulator Materials
Consideration of the properties of the insulating materials to be used is an important part

of the outdoor insulator design process. Not only does the material have to be an
excellent dielectric capable of accommodating high electrical stresses over a long term,
but it must also withstand the, often severe, environmental effects imposed, such as
ultraviolet radiation, contamination and lightning overvoltages. Further, it must possess
sufficient tensile, compressive and cantilever strength to support the loads applied and
maintain its mechanical integrity over the life of the installation in question. A brief
description of the common materials used is given below.
2.1.1 Porcelain
Following the introduction of the first porcelain insulators in the mid 1800’s, it remains the
most widely used material for outdoor insulation today. Electrical porcelain is produced
from clays and inorganic materials which, after firing in a kiln, consists of various oxide
and silicate crystals in a glassy matrix. When fully vitrified by the firing process it is
completely impervious to moisture. The insulators are usually glazed to provide a smooth
surface to inhibit the adherence of contaminants and to facilitate natural washing by the
rain. The glaze also plays a secondary role of forming a compressive outer layer, thus
limiting surface crack formation and increasing the mechanical strength.
The characteristics of porcelain, being a non-homogeneous material produced from

naturally occurring minerals, are largely dependent on the actual properties of the raw
materials used, the processing thereof and the firing cycles adopted. Materials
manufactured at each plant thus differ, and such differences need to be accounted for in
the insulator design. There are, however, standard grades of ceramics, the minimum
characteristics of which are defined in IEC 60672-1: “Specification for ceramic and glass
insulating materials – Part 1: Definitions and Classification”.
The main positive features of porcelain are:
• its inert, inorganic nature making it immune to degradation by environmental factors

such as ultraviolet radiation and aggressive contaminants
• its resistance to damage by surface electrical discharge and leakage current activity
• its ability to be easily formed into a variety of shapes to accommodate many different
applications
• its high compressive strength.
The limitations of porcelain are:
• its brittle nature, making it vulnerable to breakage, chipping and cracking

• for certain insulator types, the possibility of electrical puncture which is extremely
difficult to locate
• its low tensile and cantilever strength-to-weight ratios
• the possibility of cracking and failure by the thermal effects of power arcs.
2.1.2 Toughened glass
In order to meet the mechanical requirements of high voltage insulators, the vast majority
of glass units are of the “toughened” type as opposed to the “annealed” type. The
toughening process involves the accelerated cooling of the insulator surface while the
inner regions cool more slowly. The differential rate of solidification creates a permanent
compressive pre-stressing of the outer layers to effectively prevent the formation of
surface micro-cracks and inhibit crack propagation.
The positive features of glass are:
• its resistance to damage by ultraviolet radiation and other environmental effects

• its high dielectric strength and resistance to electrical puncture
• its tendency to shatter if damaged, thus allowing the ready identification of faulty units
• its good compressive strength.
The limitations of glass are:
• its mechanical characteristics limit its use to only certain applications

• its tendency to shatter thus making it an ideal target for vandals
• its susceptibility to leakage current erosion which can precipitate shattering.
2.1.3 Epoxy resin
Prior to the late 1960’s, when cycloaliphatic resins with silanised silica flour filler were
introduced, epoxy resins were confined to indoor use. The newer units have improved
resistance to the effects of ultraviolet radiation and, being moulded, can be produced in a
wide variety of shapes to meet numerous industry needs. Further, the required metal
fittings can be embedded during the moulding process. Epoxy resin is, however, an
organic material and can suffer from degradation owing to surface partial discharge
activity. This must be carefully considered in the design of insulators intended for use in
highly polluted environments.
The positive features of resins are:
• they can be moulded in many different forms to suit a variety of applications

• integral metalware can be provided, eliminating the need for the attachment of
external fittings.
The limitations of epoxy resins are:
• the possibility of severe leakage current erosion

• possible electrical weakness at the mould line which may lead to material degradation
• for overhead lines, the use of resins is normally limited to medium voltages.
2.1.4 Polymer composites
The term “composite” refers to insulators with a fibreglass core, which provides the
mechanical strength, covered by a housing to protect the core from the environment and
to yield the required electrical characteristics. A wide variety of constructions and
materials are used in the production of composites and thus generalisations of their
characteristics can be misleading.
The two main families of housing materials used today are those which are ethylene
propylene diene monomer (EPDM) based and those which are silicone based. EPDM has
a high mechanical strength and tracking resistance. The silicones, however, have a
higher resistance to ultraviolet degradation and have the unique property of maintaining a
hydrophobic (water repellent) surface even when severely contaminated. They are thus
more popular for use in areas of significant marine and industrial pollution.
With regard to the cores, these comprise continuous, uni-directional glass fibres in a resin
matrix. The resin is usually of the epoxy, polyester or vinyl-ester type, whereas two types
of glass, normal electrical “E” glass or special acid-resistant “E-CR” glass, are used for the
fibres.
The positive features of composite materials are:
• very high tensile strength-to-weight ratio

• improved performance in highly polluted areas (silicone rubber types)
• an unattractive target for vandals and very resistant to projectile damage
• flexibility, providing better seismic capabilities and preventing cascade failure of post
units
• for apparatus bushings, avoidance of damage to surrounding equipment in the event
of explosive failure of equipment.
The limitations of composite materials are:
• subject to leakage current erosion if incorrect material and/or dimensioning used

• possible electrical weakness at the mould line (moulded construction only)
• special care needed in design and manufacture to ensure the elimination of moisture
ingress at interfaces
• deflection under load in certain applications.
2.2 Fundamental Physical Aspects
Together with the properties of the materials used in its construction, the dimensions of
the insulator dictate its electrical and mechanical capabilities. The most fundamental of
dimensions affecting an insulator’s electrical performance are the arcing distance, the
creepage distance and the puncture distance. These are defined below and examined in
more detail in Chapter 3. Most of the definitions are taken from the International
Electrotechnical Commission (IEC) publications.
2.2.1 Arcing distance
Arcing distance is defined as the shortest distance in air, external to the insulator,
between those parts which normally have the operating voltage between them.
Figure 2.1: Insulator arcing distance.
The arcing distance is most important as it largely determines the power frequency and
impulse flashover voltages of the insulator when it is clean. Therefore, in order to meet
the electrical requirements of the system, sufficient arcing distance must be provided. It is
this dimension that usually dictates the physical size of the insulator to be used at a given
voltage level.
2.2.2 Creepage distance
Creepage distance – otherwise referred to as leakage distance – is defined as the

shortest distance, or the sum of the shortest distances, along the contours of the external
surfaces of the insulating parts of an insulator, between those parts which normally have
the operating voltage between them.
Figure 2.2: Insulator creepage (leakage) distance.
Creepage distance is also a critical parameter as it has a large influence on the power
frequency flashover voltage of an insulator when its surfaces are polluted.
This key dimension is often expressed as “Specific Creepage Distance” which is the total
creepage distance divided by the phase-to-phase system highest voltage and thus has
the units mm/kV(Um).
Note: Convention dictates that the phase-to-phase voltage is used even though it is the
phase-to-ground voltage that is actually applied to the insulator. Given this anomaly, it is
important to apply the appropriate factors when comparing specific creepage distance
values for single phase AC and DC systems. To avoid the potential confusion, the IEC
may in the future standardise the expression of specific creepage distance on the basis of
phase-to-ground voltage.
2.2.3 Puncture distance
Puncture distance is defined as the shortest distance through the insulating material
between those parts which normally have the operating voltage between them.
Figure 2.3: Insulator puncture distance.
The provision of adequate puncture distance is vital to ensure that the insulator suffers no
permanent damage when subjected to overvoltages – particularly steep-fronted lightning
impulses.
2.2.4 Insulator class
As defined in IEC 60383 “Insulators for overhead lines with a nominal voltage above
1000V”, insulators are divided into two classes according to their design:
• Class A: An insulator or insulator unit in which the puncture distance through the
solid insulating material is at least equal to half the arcing distance. Class A insulators
are considered to be unpuncturable.
• Class B: An insulator or insulator unit in which the puncture distance through the
solid insulating material is less than half the arcing distance. Class B insulators are
considered to be puncturable.
2.3 Insulator Types
The most common outdoor insulator types are defined below. Typical materials used in
their construction and there common applications are also provided.
2.3.1 Pin insulator
A rigid insulator consisting of an insulating component intended to be mounted rigidly on a

supporting structure by means of a pin passing up inside the insulator. The insulating
component may consist of one or more pieces of insulating material permanently
connected together. The fixing of the insulating component to the pin can either be
separable or permanent.
Insulator Type Pin

Materials Porcelain, Glass, Resin
Class B
Applications Overhead lines up to 50 kV, suspension (intermediate) positions
2.3.2 Line post insulator
A rigid insulator consisting of one or more pieces of insulating material permanently

assembled, usually with a metal base and sometimes a cap, intended to be mounted
rigidly on a supporting structure by means of a central stud or one or more bolts.
Insulator Type Line Post

Materials Porcelain, Glass, Resin
Class A
Applications Overhead lines, suspension (intermediate) positions
2.3.3 Composite line post insulator
A rigid insulator consisting of a load-bearing cylindrical insulating solid core, a housing

and end fittings attached to the to the insulating core.
The three main types of composite insulator construction are:
1. The Individual Shed Type - Here, separate, moulded sheds are slid onto
the core with the interfaces between the sheds and the sheds and the core
being filled with silicone grease. In a variation of this method, moulded
housing sections are slid onto the greased core.
2. The Moulded Type - With this technique, the core is placed in a mould
and the housing material injected to form a one-piece covering. For long
insulators, the moulding may be undertaken in sections.
3. The Sheathed Type - For this type, a continuous rubber sheath is

extruded onto the core. The sheds, of similar material, are then attached
to the sheath by a vulcanisation process.
Insulator Type Composite Line Post

Materials Composite – Fibreglass core, SR or EPR housing
Class A
Applications Overhead lines, suspension (intermediate) positions
2.3.4 Cap-and-pin (disc) insulator
An insulator comprising an insulating part having the form of a disc or bell and fixing
devices consisting of an outside cap and an inside pin attached axially.
Insulator Type Cap-and-pin Disc

Materials Porcelain, Glass
Class B
Applications Overhead lines, suspension and strain positions
2.3.5 Long rod insulator
An insulator comprising an insulating part having a cylindrical core provided with sheds,
and equipped at the ends with external or internal metal fittings.
Insulator Type Long Rod

Materials Porcelain, Resin
Class A
2.3.6 Composite long rod insulator
An insulator made of at least two insulating parts, namely a core and a housing, equipped
with metal end fittings and designed to be used in tension.
As for the line posts, composite long rods can be of “individual shed”, “moulded” or
“sheathed” type of construction.
Insulator Type Composite Long Rod

Materials Composite – Fibreglass core, SR or EPR housing
Class A
2.3.7 Station post insulator
A rigid insulator consisting of one or more pieces of insulating material permanently

assembled and equipped at the ends with external metal fittings intended to be mounted
rigidly on a supporting structure by means of one or more bolts.
Insulator Type Station Post

Materials Porcelain, Glass, Resin, Composite
Class A
Applications Substations, equipment and busbar supports
2.3.8 Pedestal post insulator
A post insulator having two metal parts: a cap partly embracing an insulating component
and a "pedestal" cemented into a recess in the insulating component. The cap normally
has tapped holes and the pedestal a flange with plain holes for attachment by bolts or
screws.
Insulator Type Cap-and-pedestal Post

Materials Porcelain, Glass
Class B
Applications Substations, equipment and busbar supports
2.3.9 Bushing
A device that enables one or several conductors to pass through a partition such as a wall
or a tank, and insulates the conductors from it.
Insulator Type Bushing

Materials Porcelain, Resin, Composite
Class B
Applications Substation apparatus, e.g. transformers
2.3.10 Apparatus (hollow) insulator
Apparatus insulators consist of hollow bodies, open from end to end, intended for use in
electrical equipment. Hollow insulators may be equipped with flanges.
Insulator Type Apparatus

Materials Porcelain, Resin, Composite
Class B
Applications Equipment such as instrument transformers, surge arresters, circuit
breakers, etc.
2.3.11 Stay (guy) wire insulator
An insulator intended to be inserted in stay wires to electrically isolate the lower part of the
stay from the pole top.
Insulator Type Stay Wire, “Johnny Ball”

Materials Porcelain
Class A
Applications Stay/Guy wire insulation
2.3.12 Guy strain insulator
A stay wire insulator as above but designed to provide a high lightning impulse withstand
voltage (BIL).
Insulator Type Guy Strain

Materials Fibreglass, composite
Class A
Applications Stay/Guy wire insulation
2.4 Insulator Sheds
The term “shed” refers to the projections from the core of an insulator intended to increase
the creepage distance. As will be evident from Chapter 3, the shape and geometry of the
sheds play a significant role in the performance of the insulator in the field. In order to
clarify the terminology used in the description of the sheds, the three basic profiles –
“Normal” (also known as “Plain” or “Standard”), “Alternating” and “Under-ribbed” are
illustrated in Figure 2.4.
Figure 2.4: Insulator shed shapes.
Similarly, there are three basic shapes of disc insulator, namely, the “Standard”, “Anti-fog”
and “Aerodynamic” types.
Standard Disc Shed Anti-Fog Disc Shed Aerodynamic Disc Shed
Figure 2. 5: Disc insulator shed shapes.
2.5 Insulator End Fittings
To facilitate attachment of the insulator to the supporting structure, to the conductor or to

other insulators, metal caps are provided. These are usually made from hot dip
galvanised ductile (spheroidal graphite) iron, malleable cast iron or forged steel.
Aluminium alloy is also used in certain applications but, owing to the severe damage
which can be inflicted by power arcs, it is not recommended for the smaller cap sizes such
as those used on composite long rods.
Typical fittings for those insulators designed to support tensile loads, are the Y-clevis,
clevis, tongue, ball, socket and eye, as shown in Figure 2.6.
Figure 2.6: Typical end fittings for long rod insulators.

Cap-and-pin disc types are equipped with either clevis and tongue or ball and socket
connections.
The following standards provide the detailed dimensions and other requirements for the
above fittings:
• IEC 60120: “Dimensions of ball and socket couplings of string insulator units”.
• IEC 60372: “Locking devices for ball and socket couplings of string insulator units:
Dimensions and tests”.
• IEC 60471: “Dimensions of clevis and tongue couplings of string insulator units”.
• ISO 1461: “Metallic coatings – Hot dip galvanised coatings on fabricated ferrous
products – Requirements”.
Typical end fittings for post insulators, which are primarily stressed in cantilever but may
also have to accommodate compressive and torsional loads, are shown in Figure 2.7.
These caps are not as standardised as those above but thread sizes and pitch circle
diameters are specified in the following documents:
• IEC 60720: “Characteristics of line post insulators”.
• IEC 60273: “Characteristics of indoor and outdoor post insulators for systems with
nominal voltages greater than 1000V”.
Figure 2.7: Typical end fittings for post type insulators.

Electrical Considerations 17
3 ELECTRICAL CONSIDERATIONS
“In theory, there is no difference between theory and practice. But, in practice, there is” – Jan van
de Snepscheut
Introduction
The main dielectric used in high-voltage networks is air at atmospheric pressure. Air is a
good insulating material and is self-restoring, provided that the electric stress is kept
below the ionisation threshold. However, as air has no mechanical properties capable of
supporting high voltage conductors, various types of insulators were developed during the
past century to perform the dual task of mechanically supporting and electrically insulating
the lines and equipment. Such a task is particularly complex, bearing in mind the multiple
extreme stresses present: mechanical, electrical and environmental. This chapter focuses
on the electrical considerations that are relevant to the selection of insulators, with
emphasis on minimising the probability of electrical flashovers.
3.1 Dry and Wet Power Frequency Flashover
The insulator must be able to withstand, under both dry or wet conditions, the system
power frequency operating voltage (Un) and overvoltage (Um). The arcing distance
determines both the dry and, to a large extent, the wet power frequency flashover
voltages. Typical withstand curves are shown in Figure 3.1.
2500
Dry Positive Lightning Impulse

2250
2000
1750
Withstand Voltage (kV)
Wet Positive Switching Impulse
1500
Dry Power Frequency

1250
Wet Power Frequency

1000
750
500
250
0
0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500
Arcing Distance (mm)
Figure 3.1: Power frequency and impulse withstand voltages as a function of arcing
distance at sea level and standard atmospheric conditions for U120B cap-
and-pin disc insulator strings.
The required power frequency withstand values for standard system highest voltages are
given in Section 9.2.1, Table 9.2.
3.2 Lightning and Switching Impulse Flashover
The insulator must be able to withstand, without permanent damage, the naturally induced
lightning and the system switching impulse overvoltages.
Figure 3.2: Lightning strikes on power networks.
The arcing distance determines both the dry lightning and wet switching impulse flashover
voltages. Typical withstand curves are shown in Figure 3.1. The required lightning (BIL)
and switching (SIL) impulse withstand values for standard system voltages are given in
Section 9.2.1, Table 9.2.
Lightning impulse flashover is dominant at system voltages below 300 kV, as switching
impulses at these voltage levels are not high enough for flashover.
At system voltages of 300 kV and above, the switching impulse flashover is generally
more critical. The main reason is that for large air gaps the streamer or leader breakdown
mechanism is such that the switching impulse has more time to bridge the gap. Further,
the magnitudes of switching impulses are related to the system voltage, whereas those of
lightning impulses depend mainly on the severity of the lightning and the quality of the
grounding of the towers.
3.3 Power Frequency Pollution Flashover
The power frequency flashover voltage of an insulator can be reduced by an order of

magnitude with a conducting electrolytic pollution layer present on its surface. Thus, the
pollution flashover performance of an insulator has a significant effect on the power
system reliability and it must be able to withstand the pollution conditions to which it is
subjected. However, pollution has very little effect on lightning and switching impulse
flashover levels, and is thus ignored for these conditions. The basic theories behind the
power frequency insulator pollution flashover process are given below.
3.3.1 Pollution flashover process
The mechanism of pollution flashover is mainly determined by the properties of the

insulator surface. If it is hydrophilic, as is generally the case for ceramic and glass
insulators, the surface will wet out completely so that an electrolytic film covers the
insulator. For hydrophobic materials, such as silicone rubber, the water beads into
separate droplets preventing the formation of a continuous conductive layer.
The pollution flashover process for insulators with a hydrophilic surface is described in the
Cigre Electra publication No.64 [1] as follows:
“(a) The insulator becomes coated with a layer of pollution containing soluble salts or
dilute acids or alkalis. If the pollution is deposited as a layer of liquid electrolyte - e.g. salt
spray, stages (c) to (f) may proceed immediately. If the pollution is non-conducting when
dry, some wetting process (stage (b)) is necessary.
(b) The surface of the polluted insulator is wetted either completely or partially by fog,
mist, light rain, sleet or melting snow or ice and the pollution layer becomes conductive.
Heavy rain is a complicating factor: it may wash away the electrolytic components off part
or all of the pollution layer without initiating the other stages in the breakdown process, or
it may - by bridging the gaps between sheds - promote flashover.
(c) Once an energised insulator is covered with a conducting pollution layer, a surface
leakage current flows and its heating effect starts to dry out parts of the pollution layer.
(d) The drying of the pollution layer is always non-uniform and, in places, the conducting
pollution layer becomes broken by dry bands that interrupt the flow of leakage current.
(e) The line-to-earth voltage is then applied across these dry bands, which may only be a
few centimetres wide. It causes air breakdown to occur and the dry bands are bridged by
arcs, which are electrically in series with the resistance of the undried portion of the
pollution layer. A surge of leakage current occurs each time the dry bands on an insulator
spark over.
(f) If the resistance of the undried part of the pollution layer is low enough, the arcs
bridging the dry bands are able to burn continuously and so may extend along the
insulator; thereby spanning more and more of its surface. This in turn decreases the
resistance in series with the arcs, increases the current and permits the arcs to bridge
even more of the insulator surface. Ultimately the insulator is completely spanned and a
line-to-earth fault is established.“
One can summarise the whole process as an interaction between the insulator, pollutants,
wetting conditions, and applied voltage.
Courtesy of Sediver
(a) (b)
Figure 3.3: Dry bands and evaporating steam (a) and flashover (b).
3.3.2 Leakage current amplitude and surface resistance
Leakage current is widely recognised as one of the main parameters for performance
measurement of insulators [2]. It has also been shown that the flashover probability
becomes very high if the insulator leakage current approaches a certain threshold value.
This value has been defined, based on experimental work by Verma et al. [3], as the
amplitude of the leakage current peak of the half cycle immediately preceding flashover
(Imax):
2
 S 
Imax =  CD  in ampere (3.1)
 15.32 
with SCD being the specific creepage distance, given by
L CD
S CD = (3.2)
Um
where,
LCD : total insulator creepage distance, in mm

Um : maximum rms system voltage phase to phase, in kV.
The surface layer resistance is the main factor determining the magnitude of the insulator
leakage current and also whether the insulator will flash over or not.
To determine the surface layer resistance for the idealised case of a uniform electrolytic
pollution layer on an insulator, as described in Section 3.3.1 steps (a) and (b) above, the
following basic formula for the resistance R (MΩ) of a resistive element of length I (mm),
ρ ⋅I
cross sectional area A (mm2) and volume resistivity ρ (MΩ.mm) is used: R =
A
Figure 3.4 Visual representation of the electrolytic pollution layer on an insulator.
With reference to Figure 3.4 the following variables are defined:
Rpol : surface layer resistance of the electrolytic pollution layer, in MΩ

ρpol : volume resistivity of the electrolytic pollution layer, in MΩ.mm
LCD : total insulator creepage distance, in mm
Apol : cross sectional area of the electrolytic pollution layer at position l, in mm2, as
calculated by A pol = π ⋅ D(l) ⋅ hpol , where:
D(l) : diameter of insulator at position l along the insulator creepage path, in mm
hpol : thickness of the uniform electrolytic pollution layer, in mm.
Dividing the surface electrolytic pollution layer into small incremental sections dl along the
ρ ⋅ L CD
insulator creepage path LCD and using the basic formula R = , the resistance dRpol
A
of the incremental section is given by:
ρpol ⋅ dl
dRpol = (3.3)
A pol
ρpol L
dl
Substituting Apol and integrating both sides leads to Rpol =
hpol ∫ π ⋅ D(l)
0
(3.4)
1
Also, σ = (3.5)
ρpol
and σ s = σ ⋅ hpol (3.6)
where,
σ : volume conductivity of the insulator electrolytic pollution layer, in µS/mm

σs : surface conductivity of the insulator electrolytic pollution layer, in µS.
Substitution of (3.5) and (3.6) into (3.4) leads to
F
Rpol = (3.7)
σs
L
dl
where F = ∫ π ⋅ D(l)
0
is defined as the form factor of the insulator. (3.8)
Note: The effects of dry bands and spark/arc resistance are ignored.
When the insulator surface resistance (Rpol) reaches a critical low value, the critical
flashover voltage of the insulator in kV is given by the formula proposed by Rizk and
modified by Holtzhausen [4] as:
k2
 R ⋅ 10 6 
Vc = k 1 ⋅ 10 −3
⋅  c  ⋅ L CD (3.9)
 L CD 
where,
Vc : critical insulator flashover voltage, in kV peak

Rc : critical insulator resistance in MΩ, the critical value Rpol
k1 = 7.6
k2 = 0.35.
It is therefore clear that the power frequency pollution flashover performance of an

insulator is dependent on the surface resistance (Rpol) of the electrolytic pollution layer.
ρ ⋅ L CD
For the sake of simplicity, the basic formula R = is thus used to explain the effects
A
of creepage distance (LCD), volume resistivity (ρ) and the cross sectional area (A) of an
electrolytic pollution layer on the surface resistance of an insulator.
3.3.3 Specific creepage distance considerations
ρ ⋅ L CD
The basic formula R = shows that the insulator surface resistance is directly
A
dependent on the insulator creepage distance LCD. Thus, the power frequency pollution
flashover performance of an insulator will be improved by increasing the insulator
creepage distance.
The specific creepage distances recommended for various pollution severity classes are
given in Table 3.1 (Chapter 4, Section 4.3 shows how to establish the pollution class for a
site). The minimum creepage distance to be provided should be that calculated using
Equation 3.2. Many utilities standardise on one or more of the values of specific creepage
distance given in IEC 60815 (1986): “Guide for the selection of insulators in respect of
polluted conditions”, namely, 16, 20, 25 and 31 mm/kV(Um).
Table 3.1: Recommended specific creepage distances for various pollution severity
classes for both AC and DC.
Minimum Specific Creepage Distance (mm/kV)
AC
Pollution
Severity Class Calculated using system highest voltage of
DC
Um Um 3
(Phase to phase) (Phase to ground)
I Light 16 28 20
II Medium 20 35 24
III Heavy 25 43 31
Heavy
IV 31 54 38
Very
Note 1: Although IEC 60815 states that the AC values in Table 3.1 are applicable only to
ceramic insulators, the same values are generally also used for composite
insulators.
Note 2: Due to electrostatic pollution catch and the absence of zero crossings in the
leakage currents for DC systems, a further multiplication factor of up to 3 is
recommended by some. However, service experience with composite insulators,
as reported in Cigre Electra publication No.161 [5], indicates that no such
correction factor is justified.
When selecting an insulator, the basic profiling rules as recommended in IEC 60815, and
described in Section 3.3.4, must be followed because the quality of the creepage is as
important as its quantity.
For insulators with average diameters of between 300 and 500 mm it is recommended
that the specific creepage distances given in Table 3.1 be increased by 10%, and 20% for
diameters above 500 mm.
When insulators are used as phase-to-phase spacers, the required minimum specific
creepage distances above should be multiplied by 3 .
Sample calculation
It is proposed to erect a 132 kV line in an area of medium pollution severity using U120B
glass cap-and-pin disc insulators. Assuming the parameters given below, how many
discs are required per string?
System highest voltage (Um) = 145 kV

Wet power frequency withstand voltage = 275 kV
Lightning impulse withstand voltage = 650 kV
Disc spacing (s) = 146 mm
Arcing distance per disc (a) = 190 mm
Creepage distance per disc (k) = 295 mm
From Figure 3.1, the required arcing distance of the insulator string is 1200 mm for the
wet power frequency withstand voltage and 1100 mm for the lightning impulse withstand
voltage. Thus, the minimum arcing distance in terms of the electrical values is 1200 mm.
The arcing distance of a disc insulator string = a + (n - 1) s
Thus, 1200 = 190 + (n - 1) x 146
and n = (1200 - 190) + 1 = 7.9 (i.e. 8 discs are required)

146
In terms of pollution severity, as shown in Table 3.1, the specific creepage distance
needed for a medium pollution area is 20 mm/kV (Um).
From equation 3.2, the total creepage distance = 145 x 20 = 2900 mm
Thus, the minimum number of discs = 2900 = 9.8 (i.e. 10 discs are required)
295
Therefore, the insulator string has to comprise 10 discs as dictated by the pollution
severity.
3.3.4 Profile considerations
In addition to the creepage distance, other details of the shed geometry may be specified.
For example, to avoid sheds which are too closely spaced, a minimum shed clearance or
shed spacing-to-projection ratio is often called for. In areas of pre-deposited type
contamination, an aerodynamic shed shape with a smooth underside is preferred. As
illustrated in Figure 3.5 any underribs (a) or even small ridges and grooves (b) serve to
collect airborne contamination. Further, deep underribs inhibit natural washing.
(a) (b)
Figure 3.5: Contaminant collection by shed underribs.

(a) (b) (c)
Figure 3.6: Insulator profile parameters, plain shed (a), alternating shed (b) and ribbed
shed (c).
With reference to Figure 3.6, the insulator profile parameters as defined in IEC60815 are
as follows:
c : shed clearance – the length of the perpendicular to the shed surface to the
outer rib of the shed above
S : shed spacing – the vertical distance between two similar points on successive
sheds
P : shed projection – the maximum shed overhang
δ : the straight air distance between any two points on the shed surface
Iδ : the creepage distance measured between the two points that define δ
Is : the creepage distance measured between the two points that define S
LCD : the total creepage distance of the insulator
Larc : the arcing distance of the insulator
CF : creepage factor = LCD / Larc
PF : profile factor = (2P+S) / Is or (2P1+2P2+S) / Is
The recommended limits for these parameters are tabulated in Table 3.2.
Table 3.2: Recommended IEC 60815 profile parameters limits.
c ≥ 30 mm, or 20 mm when P ≤ 40 mm or Larc ≤ 550 mm
S/P ≥ 0.65 for plain, 0.8 for ribbed
Iδ / δ < 5
P1 – P2 ≥ 15 mm
α > 5°
β > 2°
CF ≤ 3.5 for light to medium or 4 for heavy to very heavy pollution areas
PF > 0.8 for light to medium or 0.7 for heavy to very heavy pollution areas
3.4 Other Electrical Considerations
3.4.1 Risk of puncture
In areas with lightning activity there is a risk of internal puncture of the solid insulator
material, which could result in total insulator failure or nuisance line trips. This risk is
especially high when puncturable Class B insulators are used. It is therefore
recommended that un-puncturable Class A insulators be used for high lightning
environments.
For Class B insulators, a minimum puncture voltage should be specified. Suggested

minimum power frequency puncture values, when tested in accordance with IEC 60383,
are provided in Table 3.3. If impulse puncture values are specified, the minimum ratio of
the puncture voltage to the 50% lightning impulse flashover voltage should be:
For cap-and-pin disc insulators 2,8

For pin insulators 2,0
For long rod insulators 2,3
Table 3.3: Minimum puncture withstand voltages
SYSTEM HIGHEST PUNCTURE WITHSTAND

VOLTAGE, Um (kV r.m.s.) VOLTAGE (kV r.m.s.)
7,2 80
12 95
24 130
36 170
48 210
72,5 290
It should be noted that when porcelain insulators are used in high temperature
applications, such as precipitators, the correct grade of material must be used to prevent
puncturing.
3.4.2 Corona
It should be ensured that the insulator and its associated hardware have a corona
extinction voltage greater than the system highest voltage (Um).
Apart from the emission of acoustic noise and radio and TV interference which may be
environmentally unacceptable, corona also generates ultraviolet radiation, ozone and, in
the presence of moisture, acids, all of which may have an adverse effect on polymeric
insulating materials.
(a)
Courtesy of Eskom
(b)
Courtesy of Eskom
Figure 3.7: Corona present on an insulator end fitting (a) and (b) insulator string
hardware.
Generally, live-end corona rings are used on systems of voltage greater than 200 kV.
Depending on the cap design and string hardware, however, earth end rings, or the
application of rings at lower voltages, may be considered.
3.4.3 Resistance to power arc damage
It should be ensured that the insulator and its associated hardware can withstand a power
arc of the current and duration associated with the system under flashover conditions.
Arcing horns or rings should be used for porcelain long rod insulators to divert the arc
away from the insulating material as the thermal shock could lead to mechanical failure. It
is further recommended that they should not be attached directly to the insulator end
fittings but to the adjacent hardware.
It is difficult and uneconomical to dimension an aluminium end fitting for long rod
insulators to survive the effects of power arcs.
3.4.4 Snow and ice flashover
The insulator-shed spacing should be chosen such that the build-up of snow and ice does
not lead to inter-shed bridging. The power frequency flashover voltage of insulators
covered with snow and ice can be 25 to 35 % lower than that for light pollution conditions.
(a) (b)
Figure 3.8: Insulators covered by ice (a) and snow (b) (Courtesy of Jean-Francois Drapeau - IREQ).
3.4.5 Instantaneous or rapid conductive fog flashover
‘Instantaneous pollution’ refers to a contamination of high conductivity which quickly

deposits on insulator surfaces, resulting in the condition where the insulator changes from
an acceptably clean, low conductive state, to flashover in a short period of time (< 1 hour)
and then returns to a low conductive state when the event has passed.
For ease of understanding instantaneous pollution flashover, the same process as

described in Section 3.3.1 applies. However, as the instantaneous pollution is normally
deposited as a highly conductive layer of liquid electrolyte, e.g. salt spray, salt fog or
industrial acid fog, stages (c) to (f) may happen immediately. In nature, these phases are
not distinct but merge and do not apply to insulators with hydrophobic surfaces. Areas
most at risk are those situated adjacent to chemical plants or close to the coast.
In environments that may experience instantaneous conductive fog conditions (especially

from an industrial source), increasing the creepage distance or altering the profile may not
be effective. In such cases the use of insulators with hydrophobic surfaces should be
considered.
3.4.6 Bird streamer flashover
A particular case of instantaneous pollution flashover is that due to bird streamers. This is
a type of bird excrement which, on release, forms a continuous, highly conductive (20 - 40
kΩ/m) [38] stream of such length that the air gap is sufficiently reduced to cause
flashover. The insulator geometry and characteristics play little or no role here. Thus, in
the event of bird streamer flashover it is recommended that bird guards be installed.
Courtesy of Eskom
Figure 3.9: Bird streamer flashover simulation on a 275 kV tower.
3.4.7 Lightning induced back flashovers
When lightning directly strikes the shield wire or structure in a power network, the insulator
BIL and structure footing resistance determine whether a back flashover will take place.
The tower and shield wire surge impedance, coupling factors, tower geometry, etc. also
need consideration. However, a low footing resistance and the correct choice of BIL are
most important.
The number of expected direct strikes (N) to the shield wire or structure per year can be
calculated using following equation [6]:
( )
N = Ng ⋅ 28 ⋅ H0.6 + W ⋅ L line ⋅ 10 −3 (3.10)
where,
Ng : ground flash density, in strikes per km2 per year

Lline : line length, in km
H : average tower height, in m
W : line width, in m.
For example, based on the calculated number of expected direct strikes per year from
Equation 3.10 and the percentage of direct strikes that will not result in a back flashover
from the graph in Figure 3.10, the BIL and footing resistance can be chosen such that an
acceptable line performance is achieved.
Figure 3.10: Percentage of direct strikes to an experimental 11 kV wood pole line, with
overhead shield and directly coupled earth wire, that will not result in a back
flashover for a given BIL and footing resistance [7].
Figure 3.11: Direct strike to the shield wire and resulting back flashover of insulators.
Table 3.4: Recommended footing resistances for various system voltage levels [8].
System Voltage, Un (kV) Footing Resistance (Ω)
≤ 132 ≤ 20
220 ≤ 30
275 ≤ 30
400 ≤ 40
765 ≤ 50
For all terminal towers the footing resistance should be less than 10 Ω and for the first four
towers from the substation it should be less than 20 Ω.
If an acceptable outage rate due to back flashovers cannot be practically achieved by

improving the insulator BIL and/or footing resistance, the use of line surge arresters can
be considered.
Note: Medium voltage lines (11, 22 and 33 kV) are susceptible to flashovers from
lightning induced surges. Nuisance tripping can be significantly reduced by providing a
BIL of at least 300 kV. This can be achieved by using insulators with a higher BIL or by
increasing the BIL of the structure, for example, by utilising insulated cross arms or, for
wood pole structures, leaving part of the wood path unearthed.
3.4.8 Voltage transfer
Under clean and dry conditions insulators have their highest electrical stress on the live
end, near the end fitting. When the insulator becomes polluted and wetted, the voltage is
resistively distributed over the surface and the electrical stresses are highest in the areas
with the smallest radius of curvature, such as the shed tips. When a dry band forms, most
of the stress is transferred to this region. This is illustrated in Figure 3.12.
Ground potential
Clean and dry Evenly polluted and wet Evenly polluted and wet
with dry band
High Voltage
Figure 3.12: Electric field simulations on insulators: clean and dry; evenly polluted and
wet; and evenly polluted and wet with dry band (Red shows the areas with
the highest electric stresses).
Typical situations in the field where high electrical stresses are present due to voltage
transfer are shown in Figure 3.13 and discussed below:
• Local flashover as a result of ground potential transfer downwards and high voltage
potential transfer upwards, on an insulator string, due to uneven pollution and wetting,
is shown in (a) and (b) respectively. It is thus important, when replacing broken discs
and/or adding new discs to a string, to ensure that the complete string is clean.
• Corona discharges and dry band sparking due to the voltage present over dry bands
on the creepage extenders installed on porcelain transformer bushings are shown in
(c). This further illustrates the problems that may be encountered if the surface
characteristics of the insulator are not uniform.
• Corona discharges due to water drops over the whole length of the insulator are
shown in (d). This indicates that water drop corona is not confined to the live end only.
Installing corona rings will thus not ensure a corona-free insulator.
• Corona discharges and dry band sparking on the insulator sheath and shed on the
ground potential end are shown in (e). It is evident that dry bands can form anywhere
on the insulator surface and may result in localised material ageing.
(a) (b) (c) (d) (e)

Figure 3.13: Examples of voltage transfer.
The above shows that voltage transfer takes place, and could lead to electric field
stresses being present anywhere on the insulator surface.
3.4.9 Temporary overvoltages (TOV)
In networks with a non-earthed neutral, the TOV could be as high as 3 times the normal
system operating voltage, and could last for many hours.
The magnitude and duration of the TOV should be considered, and the Um value changed
accordingly for the selection of insulators.
Environmental Considerations 34
4 ENVIRONMENTAL CONSIDERATIONS
“Natural Science does not simply describe and explain nature; it is part of the interplay between
nature and ourselves; it describes nature as exposed to our method of questioning” – Werner
Heisenberg
Introduction
Environmental conditions affect the performance of high voltage insulators in the following
ways:
• The direction and speed of the wind, precipitation (rain, dew, fog), relative humidity
and the position of pollution sources all determine the final pollution deposit on an
insulator surface. Particles become wind-borne and can be carried over great
distances before fall-out occurs. Salt storms or conductive industrial fogs can also
result in the deposition of a highly conductive electrolytic layer on an insulator surface.
Solar radiation can also heat the insulator surface during the day, helping to prevent
wetting, or heat the atmosphere at sunrise, resulting in the formation of dew. Thus,
the environment drives insulator pollution flashovers.
• Weather parameters, such as ultraviolet solar radiation, can have detrimental effects
(chalking, crazing, and cracking) on the ageing of non-ceramic materials.
• The direction and speed of the wind, temperature, ice and snow loading, and seismic
events can influence the mechanical forces on an insulator.
• Lightning activity, soil resistivity, change in air density, and bird streamers can affect
the insulator flashover performance.
The various environmental considerations are discussed below.
4.1 Pollution
There are two main insulator pollution processes: pre-deposited pollution that
accumulates over time and then needs to be wetted to form a conducting electrolyte, and
instantaneous pollution that is already a conducting electrolyte.
4.1.1 Pre-deposited pollution
Pre-deposited pollution is classified into two main categories: active pollution that forms a
conductive layer, and inert (non-soluble) pollution that forms a binding layer for the
conductive pollution and also contributes to the area available for leakage current flow.
Pre-deposited active pollution is measured in terms of conductivity, and the inert non-
soluble pollution in terms of mass.
4.1.2 Instantaneous pollution
‘Instantaneous pollution’ refers to a contaminant of high conductivity which quickly

deposits on insulator surfaces, resulting in the condition where the insulator changes from
an acceptably clean, low conductive state, to flashover in a short time (< 1 hour) and then
returns to a low conductive state when the event has passed. Salt or conductive industrial
fogs are good examples of sources that lead to instantaneous pollution events.
Instantaneous events can be detected by surface conductance or leakage current
measurements.
4.1.3 Pollution sources
(a) (h) (g)
(b)
(f)
(c)
(d) (e)
Figure 4.1: Typical sources of insulator pollutants: agricultural (a), marine (b), fires (c),
dust and salt roads (d), trucks and motorcar emissions (e), industrial (f),
domestic cooking and heating (g), and birds (h) are shown.
Typical sources of insulator pollutants are:
• Pre-deposit pollution:
Marine: salt and sand

Industrial: chemical emissions and waste products
Agricultural: soil, fertilisers, weed killers and crop burning
Desert: sand and salt
Other: salted roads and bird droppings.
• Instantaneous pollution:
Marine: salt fog

Industrial: acid fog
Agricultural: crop spraying
Desert: coastal fog
Other: bird streamers.
4.2 Weather
Weather conditions such as temperature, humidity, rain, fog, wind, solar radiation, snow
and ice, lightning and air density can affect the ultimate electrical and/or mechanical
performance of high voltage insulators.
4.2.1 Temperature
The ambient temperature plays a role in the wetting of insulators. When an insulator
surface temperature falls below the atmospheric dew point temperature, dew (moisture
condensation) will form on the insulator surface. This phenomenon often occurs in the
early morning hours when the insulator is at a lower temperature than that of the ambient
air, when the ambient temperature of the moist air is heated by the first rays of the sun.
Temperature also has a small effect on the breakdown strength of air. This is taken into
account in Section 4.2.9, where the air density correction for withstand voltage is
discussed.
Ambient temperature has some effect on the insulator loading due to its influence on the
conductor tension.
4.2.2 Humidity
Relative humidity is an indicator of the moisture level in the atmosphere. When the
relative humidity is high (> 75%) there is a good chance that the pollution on an insulator
surface could be wetted. This could then dissolve, forming a conductive electrolytic layer,
and resulting in the flow of leakage currents. High levels of relative humidity for long
periods of time can also lead to the washing off of pollution from an insulator surface.
There is a good correlation between electrical activity and relative humidity. In areas with
constant high humidity, especially when combined with high temperatures, certain
insulator materials can be overstressed, resulting in degradation by hydrolysis.
As a rule of thumb, the withstand voltage of air increases by 0.2% for every 1 g/m3 gain in
absolute humidity. It thus must be appreciated that a high humidity has no direct adverse
effect on the withstand voltage of an insulator, but it is the resultant wetting of the
contaminants on the insulator surface which may cause a pollution flashover.
4.2.3 Rain
Rain, too, wets the surface contaminants to form a conductive layer. Further, acid rain
can increase the conductivity. However, rain can also have the beneficial effect of
washing pollution from an insulator surface. Rain in excess of 10 mm/h can remove up to
90% of the pollution from a ceramic or glass insulator surface. In addition, light rain may
leach out active pollution. A combination of rain and wind is a good natural insulator
cleaner.
4.2.4 Fog
Fog forms as moisture condenses on particles when the temperature of a volume of air
falls below its dew point, caused by the cooling of the ground (radiation fog), or when
warm air moves over a cooler surface (advection fog). If the particles are conductive and
soluble, for example salt, a conductive fog forms.
Fog has an adverse effect on insulator performance by wetting the surface contaminants,
which may lead to flashover before any significant cleaning can occur. Should the fog be
conductive, then flashover can take place in a short period, even if the insulator was
initially clean.
4.2.5 Wind
Wind plays a major role in the transportation and deposition of pollution and moisture on
an insulator surface. The relationship found between salt deposit density (SDD) and wind
shows that the pollution deposit increases with the wind speed to the power three (cubic
relationship) [9]. Pollution deposition on an insulator surface is not uniform but strongly
dependent on the shed shape. Strong winds carrying sand particles or rain may remove
pollution from an insulator surface.
Wind, owing to the pressure it exerts on conductors, influences the mechanical loading on
an insulator.
4.2.6 Solar radiation
Solar radiation plays a significant role in the heating of the ambient air mass. This, in turn,
has an influence on wind speeds and direction, and relative humidity levels. Solar
radiation also heats the insulator surface. As previously stated in Section 4.2.1, if the
insulator surface temperature is below the ambient dew point, wetting of the insulator
surface occurs. During the day solar radiation keeps the insulator surface at a
temperature higher than ambient, resulting in a lower probability of surface wetting. The
high-energy UV-B photons may age polymeric materials [10].
4.2.7 Ice and snow
As discussed in Section 3.4.4, ice and snow can have a detrimental effect on the
flashover performance of insulators. Further, the accumulation of ice and snow on
conductors, as shown in Figure 4.2, increases the mechanical loading on insulators.
Courtesy of Arni Jon Eliasson
Figure 4.2: Ice formed around a conductor.
The icing up of link/disconnect heads, on opening, can result in severe mechanical forces
being applied to the support insulators.
4.2.8 Lightning
Lightning can cause insulator flashover by a direct strike to the phase conductor, shield
wire or structure causing back flashover, or induced overvoltage. As explained in Chapter
3, the insulator must be able to withstand the naturally induced lightning impulses without
puncture or damage from flashover.
Lightning severity must be considered in the selection of insulators. This can be

measured in terms of ground flash density (number of strikes per km2 per year) or, if such
figures are not available, isoceraunic level (number of thunderstorm days per year).
Detailed data may also be available from lightning location systems which give the
position and intensity of the lightning activity.
It should be noted that, in terms of BIL, the effect of pollution on the lightning impulse
flashover voltage is small and not normally considered in the dimensioning of the
insulator.
4.2.9 Air density
Air density changes as a function of altitude, which in turn influences the withstand voltage
of air. The withstand voltage (Va) of air at atmospheric pressure (Pa) and ambient
temperature (t) is given as:
Pa (273 + t 0 )
Va = V0 ⋅ ⋅ (4.1)
P0 (273 + t )
where,
V0 : withstand voltage at standard atmospheric conditions

P0 : standard atmospheric pressure of 101.3 kPa or 760 mm Hg
t0 : standard ambient temperature of 20 °C.
As an approximation, using equation 4.1, the withstand voltage of air decreases by 1% for
every 100 m increase in altitude.
For pollution flashover of insulators, an increase of 1000 m in altitude only decreases the
breakdown voltage by about 2% and can thus be ignored.
4.3 Site Severity Assessment
Site severity assessment, based on the measurement of pollution levels and a study of
the weather conditions, is required to define the environment in which an insulator is
expected to operate. To establish the pollution level either the surface deposit on an
insulator is measured or directional dust deposit gauges are used. Both these methods
are discussed below.
An insulator pollution-monitoring device (IPMD), which caters for both pre-deposited and
instantaneous pollution events, is also introduced as an alternative pollution severity
measurement technique.
4.3.1 Surface pollution deposit technique
The surface pollution deposit technique determines the natural pollution deposit on an
insulator after an interval of time, during which some natural washing may have occurred.
Both the active and inert pollution are measured.
A string of seven cap-and-pin disc insulators is installed at a height of at least 3 m, and

clear of obstructions, at the site to be assessed. The first and last disc in the string are
not tested, but are used to ensure aerodynamic similarity in the string. The active and
inert (non-soluble) pollution values are determined (as described in Section 4.3.1.1 and
Section 4.3.1.2) monthly on disc two, three-monthly on disc three, six-monthly on disc
four, yearly on disc five and two-yearly on disc six. The maximum values obtained during
the test period are used to determine the site severity class.
If the above test procedure cannot be used then a surface pollution deposit measurement
on existing insulators in the network can be made. However, this is more risky as the
measurement is one snapshot in time, and could indicate a lower pollution severity for the
site than is really the case.
4.3.1.1 Active pollution – equivalent salt deposit density (ESDD)
The ESDD value is defined as the equivalent amount of NaCl deposit, in mg/cm2, on the
surface area of an insulator which will have an electrical conductivity equal to that of the
actual deposit dissolved in the same amount of water.
The ESDD technique involves washing of the contaminants from the insulator surface with
distilled water and measuring the conductivity of the solution obtained.
The measurement procedure for a cap-and-pin disc insulator is as follows:
On site...
1. Without touching the glass or porcelain surface, cover the metal cap and pin with
plastic cling wrap.
2. Measure a volume of 500 to 1000 ml of demineralised water of conductivity less than 5

µS/cm and pour into a clean bowl.
3. Place the test insulator on its cap in the water and wash the top surface with gentle
hand strokes. On completion, turn the insulator over and wash the bottom surface.
4. Remove the insulator, gently shaking off any remaining water into the bowl. Pour the
wash water into a labelled container, taking care that all the deposits are transferred
from the bowl and the gloves.
Note:
a) Wear clean surgical gloves to avoid the possibility of contamination.
b) The bowl, container, measuring cylinder, etc. must also be washed well enough to
remove any electrolytes prior to the measurement.
c) The top and bottom surfaces of the cap-and-pin disc insulator can also be treated
separately.
At the measurement location...
1. Swirl or stir the wash water solution until all the soluble salts are dissolved.
2. Measure and record the volume conductivity and temperature of the solution.
3. The ESDD value is obtained from the measurements of the volume conductivity,
solution temperature, and volume of the wash water solution. A conductivity probe
measures the volume conductivity, σt, at the solution temperature ts. If the instrument
used does not automatically compensate for temperature then the measurement must
be corrected to a standard temperature of 20 °C by using the equation [12]:
σ 20 = σ t ⋅ [1 − k t ( t s − 20)] (4.2)
where,
σt : measured volume conductivity, in µS/cm

ts : solution temperature, in °C
σ20 : volume conductivity corrected to 20 °C
kt : temperature constant.
The temperature constant is calculated using the equation:
k t = −3.200 ⋅ 10 −8 ⋅ t s + 1.032 ⋅ 10 −5 ⋅ t s − 8.272 ⋅ 10 −4 ⋅ t s + 3.544 ⋅ 10 −2

3 2
(4.3)
The salinity, Sa (kg/m3), of the solution at 20°C is given as:
S a = (5.7 ⋅ 10 −4 ⋅ σ 20 )1.03 (4.4)
The equivalent salt deposit density (ESDD) in mg/cm2 is given as:
S a ⋅ Vd
ESDD = (4.5)
A ins
where,
Vd : volume of distilled water used, in cm3

Ains : area of washed/sampled insulator, in cm2.
Note:
a) The inert component of the wash water solution can be measured using the method
described in Section 4.3.1.2.
b) For more detailed information on the constituents and/or source of the pollution, the
wash water solution may be sent to a laboratory for comprehensive chemical analysis.
4.3.1.2 Inert pollution – non-soluble deposit density (NSDD)
The NSDD defines the amount of non-soluble, inert pollution deposit per square
centimetre of the insulator surface. The NSDD measurement is normally performed using
the wash water solution obtained from the ESDD measurements. The liquid is filtered
through a pre-dried, clean and weighed filter paper of grade GF/A 1,6 µm or similar, and
the contaminated filter paper is then dried and weighed.
The NSDD value is calculated using:
M2 − M1
NSDD = (4.6)
A ins
where,
NSDD : non-soluble deposit density, in mg/cm2

M1 : weight of dry clean filter paper, in mg
M2 : weight of dry contaminated filter paper, in mg.
4.3.2 Directional dust deposit gauge technique
The dust gauge, as shown in Figure 4.3, comprises four vertical tubes each with a slot
milled in the side - these being so arranged as to face north, south, east and west. A
removable container which collects the deposits blown into the slots is attached to the
bottom of each tube.
These containers are removed at monthly intervals, their contents mixed with 500 ml of
demineralised water and the conductivities of the solutions measured. The pollution index
is defined as the average of the conductivities of the four directions, expressed in µS/cm,
and normalised to a 30-day interval. To facilitate international comparison of results, the
slot size as shown in Figure 4.3 should be used.
Figure 4.3: Directional dust deposit gauges as installed (a), and dimensions (b).
The monthly measurement procedure is as follows:
On site....
1. Remove the four collection jars from the tube ends and close with the lids provided.
2. Record the date of removal on the jar label.
3. Attach four clean jars to the tubes, having completed the label on each jar to indicate
the site, the direction and the date of installation.
At the measurement location...
1. Add 500 ml of demineralised water to each collection jar. The conductivity of the
water must be less than 5 µS/cm. Should the vessel contain rain water, add
demineralised water to make up the volume to 500 ml. If, owing to heavy rainfalls,
there is more than 500 ml in the jar, no additional water is required.
2. Swirl or stir the contents until all the soluble salts are dissolved.
3. Measure the conductivity of the solution - preferably with a conductivity meter which
automatically corrects the reading to 20 °C. If the meter is not compensated to 20 °C,
then measure the temperature of the solution as well.
4. If the volume of the solution is not 500 ml, for example in the case of excessive rain
having accumulated in the jar, measure the actual volume.
5. Calculate the corrected conductivity for each direction – this being the conductivity at
20 °C, expressed in µS/cm, and normalised to a volume of 500 ml and a 30-day
month. The normalised DDG value is calculated using the equation:
Vd 30
DDG = σ 20 ⋅ ⋅ (4.7)
500 D
where,
DDG : directional deposit gauge conductivity, in µS/cm

D : days DDG installed.
If the conductivity reading is not compensated for temperature by the measuring

instrument, the value can be corrected to 20 °C using Equations 4.2 and 4.3.
6. Calculate the Pollution Index (PI) for the month by taking the average of the four
corrected directional conductivities, expressed in µS/cm, i.e.
PI =
(DDGNorth + DDGSouth + DDGEast + DDG West ) (4.8)
4
Note:
a) Some contamination can collect on the inside of the tubes and will be washed into the
collection jars when it rains. The pollution indices for the wet months may therefore
show slightly higher values than those when there was no precipitation. If the
readings are averaged over a period then this makes no difference. However, if very
accurate monthly figures are required, then the internal walls of the tube can be rinsed
off using a squeeze bottle of demineralised water before the collecting jars are
removed for analysis.
b) If an assessment of the non-soluble deposit is required, following the conductivity

measurements, the solutions should be filtered using a funnel and pre-dried and
weighed filter paper of grade GF/A 1,6 µm or similar. The paper should then be dried
and weighed again. The weight difference then represents the Non-Soluble Deposit
(NSD).
c) For more detailed information on the constituents and/or source of the pollution, the
gauge contents may be sent to a laboratory for comprehensive chemical analysis.
4.3.3 Site severity class
The site severity class can be determined from the surface deposit and dust gauge
measurements as described below.
4.3.3.1 Surface deposit index
The surface deposit index is directly given by the ESDD value, calculated as described in
Section 4.3.1.1.
The relationship between the respective pollution severity classes and the surface deposit
index, preferably measured over a period of at least one year, is tabulated in Table 4.1.
Table 4.1: Surface deposit index in relation to severity class.
Surface deposit index, ESDD (mg/cm2) Pollution

(monthly maximum) severity class
< 0.06 I Light

0.06 – 0.12 II Medium
> 0.12 – 0.24 III Heavy
> 0.24 IV Very Heavy
To take into account the influence of the non-soluble contaminants, as a rule of thumb, the
site severity class should be increased by one level if the measured NSDD value is above
2 mg/cm2, or, if not measured, a high NSDD is expected such as encountered in the
vicinity of a cement factory.
4.3.3.2 Dust deposit gauge pollution index
The site severity class can be obtained from the monthly average or the maximum of the
pollution indices measured by the dust gauge.
The relationship between the site severity class and the pollution index, preferably
measured over a period of at least one year, is provided in the Table 4.2.
Table 4.2: Dust deposit gauge pollution index in relation to site severity class.
Dust deposit gauge pollution index, PI (µS/cm) Pollution

(monthly average) (monthly maximum) severity class
0 to 75 0 to 175 I Light
76 to 200 176 to 500 II Medium
201 to 350 501 to 850 III Heavy
> 350 > 850 IV Very Heavy
If weather data for the site in question is available then the dust deposit gauge pollution
index can be adjusted to take into account climatic influences. This is done by multiplying
the pollution index value (PI), as determined in Section 4.3.2 above, by the climatic factor
(Cf).
The climatic factor is given by:
Fd D m
+
Cf = 20 3 (4.9)
2
where,
Fd : number of fog days (≤ 1000 m horizontal visibility) per year

Dm : number of dry months (< 20 mm of precipitation) per year.
To take into account the influence of the non-soluble contaminants, as a rule of thumb, the
site severity class should be increased by one level if a high NSDD is expected such as
encountered in the vicinity of a cement factory.
4.3.4 Other pollution assessment methods
4.3.4.1 Localised equivalent salt deposit density (LESDD)
To obtain an estimate of the severity of a pollution layer on an insulator in service, a

localised ESDD (LESDD) measurement can be undertaken using the method as
discussed in the paper “A novel method to measure the contamination level of insulators –
spot contamination measurement” [11].
Figure 4.4: LESDD sampling tool and associated toolbox with measuring equipment.
The LESDD is calculated using the same equations as those for the ESDD - the only
differences being the surface area tested and the volume of distilled water used.
However, care must be exercised in the interpretation of the results. It must be
appreciated that the ESDD values shown in Table 4.1 relate to the contaminant averaged
over the entire surface of the insulator and not a single small area.
4.3.4.2 Surface conductivity hand probe
The conductivity of a pollution layer on an insulator can be measured using the hand
probe described in IEC 60507 [12]. The hand-held meter is connected to a probe
consisting of two spherical electrodes that are pressed onto the insulator surface. The
test area is slightly wetted with demineralised water to dissolve the pollutant. The surface
conductivity value between 0 and 500 µS is then indicated on the meter. The measured
conductivity is, however, a function of the amount of wetting, which cannot be accurately
controlled.
The hand probe readings usually do not correlate well with ESDD readings or most other
pollution monitoring devices. The probe readings are rather used to compare localised
deposits.
Figure 4.5: IEC surface conductivity hand probe.

4.3.4.3 Automated insulator pollution monitoring
For more detailed and frequent assessment of site conditions instruments have been
designed to automatically determine the severity of the pre-deposited pollution at
selectable intervals and to record instantaneous pollution events. Some also allow the
monitoring of the leakage current amplitudes on in-service insulators.
Typical measurements performed are:
• Insulator surface conductivity under natural pollution and wetting.

• Insulator surface conductivity under natural pollution but with artificial wetting (An
estimated ESDD value may also be calculated for every measurement).
• The leakage current amplitude on in-service insulators.
An alarm could be generated when pre-deposited and instantaneous pollution levels

reach critical values and the data collected may be downloaded via cell modem and
pollution profiles in relation to time displayed.
Figure 4.6: An Insulator Pollution Monitoring Device (IPMD) installed in the field.
Typical results obtained from an in-service IPMD are shown in Figure 4.7.
As both pre-deposited and instantaneous pollution levels are recorded daily, the natural
pollution and wetting events are not averaged out over a month. This eliminates the
possibility of missing singular severe pollution events, as is the case with both the surface
pollution deposit and directional dust deposit gauge methods.
30 Conductivity 0.030
Conductivity
25 0.025
Surface Conductivity (uS)

20 0.020
ESDD (mg/cm )
2
Conductivity (µS)
ESDD (mg/cm2)
ESDD
15 ESDD 0.015
10 0.010
5 0.005
0 0.000
2002/11/18 00:00 2002/11/19 00:00 2002/11/20 00:00 2002/11/21 00:00
Date
Date
Figure 4.7: Typical IPMD field measurement results showing both the surface
conductivity under natural wetting and ESDD under artificially wetted
conditions.
4.3.4.4 Existing insulator performance
The performance of insulators already existing at the site can give valuable information
regarding the severity of the environment. The history of faults on the system and
operational experience should be studied to establish whether pollution may pose a
problem. Some techniques that can be used to assist in the analysis of existing line
behaviour are provided in Section 11.3. The insulators themselves should also be
examined for signs of leakage current activity. Typical signs include evidence of
flashover, erosion of the dielectric material or corrosion of metal fittings.
For example, pin corrosion on disc type insulators, as shown in Figure 4.8, is a good
indicator of significant leakage current activity over the insulator surface and can be taken
as a warning of high pollution severity or under-insulation.
Figure 4.8: Pin corrosion on disc type insulators.

By monitoring the leakage currents on nearby in-service insulators, a good indication of

site severity can be obtained. The comparison of the highest amplitude measured (Ihighest)
with Imax (as calculated from Equation 3.1) shows the likelihood of flashover of the
monitored unit and the specific creepage required for the site.
Sample calculation
Over a period of two years, an Ihighest value of 165 mA peak was measured on a 132 kV
string of ten glass cap and pin discs each of creepage distance 290 mm. Examination of
the insulator pins showed no signs of corrosion. Based on this information, what is the
indicated site severity class ?
System highest voltage (Um) = 145 kV
Creepage distance = 10 x 290 = 2900 mm
From Equation 3.2,
Specific creepage distance = 2900 / 145 = 20 mm/kV
From Equation 3.1,
Imax = (20 / 15.32)2 = 1.704 amps peak
As Ihighest is less than 10% of Imax it is apparent that the existing insulator is coping well with
the environmental conditions. This is supported by the lack of corrosion of the pins.
With reference to Table 3.1, a specific creepage distance of 20 mm/kV is the

recommended value for areas of “Medium” pollution severity. The Severity Class for this
particular site thus appears to be in the “Light” to “Medium” range. A conservative
approach would be to insulate for the latter.
It should be noted that the relationship between the Ihighest / Imax ratio and the probability of
flashover is not linear but exponential. Thus, if Ihighest exceeds 20% of Imax the insulation
should be designed for at least one pollution class higher than the monitored unit.
4.4 Other Environmental Considerations
4.4.1 Bird streamers
In environments where birds such as eagles, herons, geese, cranes, egrets, storks, crows
and buzzards are found, the risk of flashovers due to bird streamers, as discussed in
Section 3.4.6, should be considered.
Courtesy of Eskom
Figure 4.9: Yellow-billed stork streamer in excess of 2.4 meters in length.
4.4.2 Birds, rodents and termites
Birds (for example parrots), rodents and termites can damage polymeric insulators (as
shown in Chapter 7 and Chapter 10). Knowledge of their presence is important for the
storage and installation of insulators.
4.4.3 Soil resistivity
The footing resistance of structures is determined by the soil resistivity and the quality of
the earthing. As discussed in Section 3.4.7, this may have a significant effect on the
probability of back flashover of the insulation. In areas of high soil resistivity, special
measures may have to be taken.
Table 4.3: Typical resistivity of various soil materials [8].
Soil Resistivity
Material Ω⋅m
General average 100
Sea water 0.01 – 1.0
Swampy ground 10 - 100
Dry soil 1000
Pure slate 107
Sandstone 108
4.4.4 Seismic activity
Insulators can be mechanically damaged during earthquakes. Thus, for areas of known
seismic activity, this must be taken into account when selecting insulators. For example,
instead of rigid ceramic station post busbar supports, more flexible composite units may
be preferred. The suitability of an insulator for seismic loading can be assessed using the
calculations described in Section 6.2.3.2.
4.4.5 Corrosion
Highly corrosive environments can adversely affect the life and performance of the end
fittings of insulators. In such environments, non-ferrous fittings may be preferred or
heavier galvanising specified. For disc insulators a sacrificial zinc collar may be specified.
High corrosion rates in an area usually indicate that high levels of pollution can also be
expected.
4.4.6 Vandalism
When installing lines or substations in places where vandalism could be a threat,

insulators of suitable design and material should be selected. Toughened glass discs,
with their inherent mechanical pre-stress, can shatter violently on impact and thus
represent an attractive and satisfying target. They should not therefore be used in areas
known for stone throwing and shooting. Although composite insulators are preferred for
such environments it must be appreciated that any damage inflicted may not be obvious
from the ground and could precipitate failure in the longer term.
Figure 4.10: Gun shot damage to the core of a composite insulator.

Material Considerations 52
5 MATERIAL CONSIDERATIONS
“The ideal engineer is a composite ... He is not a scientist, he is not a mathematician, he

is not a sociologist or a writer; but he may use the knowledge and techniques of any or all
of these disciplines in solving engineering problems” – N W Dougherty
Introduction
The solid dielectric part of practically all modern outdoor insulators is made of porcelain,
glass or polymeric materials. With regard to their basic composition, porcelain and glass
are similar. It is the manufacturing process that leads to the differences in both their
appearance and properties. Polymeric insulators can be divided into composite insulators
and resin insulators. There is much less difference between the characteristics of glass
and porcelain materials than between them and the various polymers used for composite
insulators. The performance of electrical insulators is significantly influenced by the type
of insulating material used in their manufacture. The wetting of an insulator surface has a
critical influence on the insulator pollution performance. It is controlled not only by the
material’s surface properties, such as the surface energy, but also by the bulk properties
such as thermal conductivity.
The insulating part of most insulators is equipped with one or more metallic fittings that
are used to connect the insulator to other components of the electrical system.
5.1 Porcelain
5.1.1 Porcelain manufacture and properties
The porcelain used for the manufacture of insulators is made of three main components:
clay, feldspar and quartz. Quartz may be replaced by alumina to obtain better mechanical
characteristics. If the raw materials are too coarse they are ground to the desired particle
size. This is done either dry or in the presence of water. All the components are
thoroughly mixed using water as a carrier. This mixture, called slip, is filtered to remove
all foreign particles that would affect the high quality of the porcelain necessary for
electrical insulators. The slip can be spray-dried into pellets that have 8% water or less.
Alternatively, it is pressed into cakes that still have 20% water content or more. These
cakes are fed into a vacuum extrusion machine that removes the air and transforms them
into solid or hollow cylinders having the diameter and length required for the manufacture
of the finished product. These cylinders may be pressed into the shape of, for example,
pin insulators or cap-and-pin disc shells, or turned on vertical or horizontal lathes to
produce long rod, line post, station post and hollow insulators.
In the isostatic process (sometimes called a hydrostatic process) semi-dry pellets are
pressed into the shape of the finished insulator. This is achieved by placing the pellets in
a flexible (elastomeric) mould in a pressure chamber. Because of the very high pressure
(several hundred MPa) used, voids are eliminated in the pressed insulators material and,
as dry pellets are used, drying is not required before the firing operation.
A glazing solution is applied onto these “green” porcelain components by dipping, painting
or spraying before they are introduced into the firing kiln. Before firing, grit may be applied
to those parts of the insulator surface where metal fittings will be attached. The glaze
forms a smooth hard layer which not only serves to inhibit the adhesion of pollution but
also adds to the mechanical strength. It should be noted that the glaze is not intended to
act as a moisture barrier – the underlying porcelain is fully vitrified and non-porous and
does not require such protection. Minor chipping of the glaze is thus not detrimental to the
insulator life.
The main characteristics of typical electrical porcelain and glass as per IEC 60672 are
given in Table 5.1.
Table 5.1: Mechanical and Electrical Characteristics of Standard Porcelain and Glass.
Silica Alumina
Toughened Alkali-
Characteristics Porcelain Porcelain
Lime Silica Glass
C110-C112 C120-C130
Specific mass [g/cm3] 2.4 2.6 2.5
Tensile Strength [MPa]
Porcelain unglazed ∗ 30 50 to 70 -
Porcelain glazed ∗ 40 60 to 80 -
Glass annealed ∗ - - 50 to 60
Glass toughened ∗ - - 100 to 120
Bending Strength [MPa]
Porcelain unglazed ∗ 42 to 90 100 to 140 -
Porcelain glazed ∗ 56 to 120 120 to 170 -
Glass toughened ∗ - - 200 to 250
Compressive strength [MPa]
Porcelain unglazed ∗ 280 to 450 400 to 600 -
Porcelain glazed ∗ 380 to 690 500 to 700 -
Glass toughened ∗ - - 700
Fracture impact energy [J] 2 to 3 2.5 to 4 5 to 6
Modulus of elasticity [GPa] 77 107 72
Coefficient. of linear expansion
3 to 6 4 to 7 8 to 9.5
(20 to100°C) [10-6/K]
Thermal conductivity [W/m K] 1 to 2.5 2 to 4 1
Relative permittivity (25°C, 48 to
6 to 7 6 to 7.5 7.3
62 Hz)
Tan δ (25°C, 48 to 62 Hz) [10-3] 10 to 25 15 to 30 15 to 60
Dielectric strength ∗ [kV/cm] 150 to 200 150 to 200 >250
13 12
Volume resistivity (25°C) [Ω.cm] 10 10 1012
∗ These values are indicative, and depend very much on the test specimen and method
used for the measurements.
Glazes can be formulated to fulfil some more specialised functions. For example, semi-
conductive types are applied to the heads of pin insulators to reduce radio interference.
Resistive glazes, covering the entire porcelain surface, can be employed in polluted
environments to provide more reliable performance. These allow the continuous flow of a
small current which serves to warm the insulator surface, inhibiting wetting by
condensation, and also reducing distortion of the voltage distribution, thus preventing dry
band formation. These insulators are very effective in preventing contamination flashover
but the permanent leakage current of about 1mA does represent a significant energy loss.
In tests at the highly polluted Koeberg Insulator Pollution Test Station (KIPTS), the
accumulated charge registered on the resistive glaze insulator was some 5 times higher
than that on the conventionally glazed unit. A further concern is the expected life of the
glaze. Should there be a break in the continuity - for example, degradation at the
glaze/fitting interface - this would represent a permanent dry band, creating severe field
stresses and partial discharges.
Porcelain is a very stable material and immune to degradation by ultraviolet radiation and
leakage current activity. However, the thermal shock of a power arc may cause glaze
damage and cracking of the porcelain.
The quality of porcelain insulators depends not only on the formulation and the quality of
the raw materials used, but also very significantly on how well the manufacturer has
mastered the art of porcelain making. The grain and crystal sizes, the distribution and
size of the pores, and the characteristics of the glaze all depend on both the material
composition and the firing process. Most failures recorded on early porcelain shells, can
be attributed to porosity caused by manufacturing problems. This has been practically
eliminated by modern technology.
Puncture of the porcelain shell may not be externally visible. This mode of failure can be
precipitated instantaneously by steep-fronted lightning surges or have its origin in the
propagation of micro-cracks. Normally, Class A porcelain insulators cannot puncture.
5.1.2 Construction of porcelain insulators
Porcelain is used to make many different types of insulators, such as cap-and-pin

insulators for lines, post insulators for line and substations, and hollow insulators for
apparatus and bushings.
5.1.2.1 Cap-and-pin construction
Figure 5.1 shows a typical cap-and-pin porcelain disc insulator. They are made of four
main parts: the insulating shell, the cap and pin metal fittings and the cement that keeps
the shell and fittings together. The dimensions and mechanical strength ratings are
standardized in IEC 60305 [13]. The metal fittings are described in Section 5.5.
The cement can be either of the portland or alumina type. Coatings are applied to those
surfaces of the metal fittings that will be in contact with the cement, to allow relative
movement and prevent adhesion. These coatings are made of bitumen or polymer
blends. The cement is cured under steam or in water.
Because of the shape of the components of the insulator, the porcelain shell and the
cement work mainly under compression when a tensile load is applied. Shear stresses
are also present. Typical characteristics of alumina and portland cements are shown in
Table 5.2. In some cases fillers such as silica sand or glass fibres are added to the
mixture to decrease contraction of the cement during the curing process.
Cap
Cement
Shell
Pin
Figure 5.1: Typical cap-and-pin porcelain disc insulator.
During the ageing of some compositions of portland cement, free lime may appear. This
lime, and sometimes also, excessive gypsum present in the cement cause it to expand
(cement growth). This generates additional stresses and may be harmful to the integrity
of the insulator shell.
Table 5.2: Properties of some cements.

Alumina Portland Sulphur Lead antimony
Characteristics
cement cement cement cement
Compressive strength
74 45 40 40
(mortar) [MPa]
Coefficient of thermal
expansion (0°C to 40°C) 10 10 20 30
[10-6/K]
Volume resistivity (pure
0.5 10-6 0.05 10-6 Very high Very low
paste) [Ω.cm]
Designed for
Thermal stability Very good Good Good specified temperature
range
Good, but
may be
Corrosion resistance Very good affected by
Good Very good
sulphates
Small,
Expansion caused by function of
None cement
None None
ageing
quality
5.1.2.2 Long rod insulator construction
With the advancement of material technology, ceramics which can accommodate higher
tensile forces were developed. This allowed the design of insulators without having to
convert tensile loads into compressive stresses, as is the case with the cap-and-pin disc
structure. The long rod insulator comprising a solid cylindrical porcelain body with a metal
fitting at each end was thus introduced.
The metal fittings are attached to the end of the porcelain body by means of various types
of cements. In addition to the portland and alumina types, sulphur and lead antimony
cements are also used. Typical characteristics of these are given in Table 5.2.
5.1.2.3 Line and station post insulator construction
A further development in ceramic technology was the ability to fire porcelain bodies of
large cross sections. Solid core line and station post insulators could thus be produced
and, for the latter, largely replaced support insulators which were traditionally made of
separate porcelain pieces joined together, such as the cap and pedestal and multi-cone
types.
Metal fittings are attached to the gritted ends of the porcelain bodies by means of portland
or alumina cements.
5.1.2.4 Hollow insulator construction
The construction of hollow insulators is similar to that of station posts but usually the
critical mechanical stress to be accommodated here is internal pressure. Liquid or gas-
tight seals are often demanded by the application and thus greater attention to the design
and cementing of the end fittings is required. Finer dimensional tolerances may also be
needed, sometimes necessitating machining of the porcelain after firing.
Very large hollow insulators can be made by joining several parts together using epoxy or
glaze.
5.2 Glass
5.2.1 Glass manufacture and properties
Glass is obtained by the gradual solidification, without the formation of crystals, of a

melted mixture of raw materials such as silica, limestone, dolomite, feldspar and soda ash
in specific proportions. Table 5.3 gives the typical composition of standard glasses used
for the manufacture of toughened glass insulators or glass fibres that are used for the
manufacture of composite insulators.
Table 5.3: Composition of some electro-technical glasses, in %.
Bulk application Fibre application

Chemical
Alumina-silica Alumina-silica
composition Alkali Lime Silica
E E-CR
SiO2 ∼ 70 53 to 56 52 to 56
Al2O3 ∼ 2.5 12 to 16 10 to 16
B2O3 - 5 to 9 -
MgO - 0 to 5
∼ 12
CaO 21 to 24 18 to 25
Na2O - -
∼ 15
K2O 1 1
Fe2O3 - 0 to 0.5
TiO2 - 1 0 to 3
F2 - 0 to 1 -
The raw materials, ground to the right particle size, are mixed and then introduced at the
melting end of the furnace on top of an already existing pool of molten glass. The melting
area of the furnace has a temperature of about 1500 °C for type 3 or 4 glass or about
1600 for E glass. Convection in the melt eliminates small gas bubbles and other by-
products of the decomposition of the raw materials. However, this convection also
promotes the abrasion of small particles off the furnace wall. These particles may appear
as inclusions in the insulator shell. The thoroughly homogeneous mixture is then allowed
to pass into the second part of the furnace that has a slightly lower temperature.
The molten glass flows out of the furnace through a feeder at the end of which a
calibrated drop or gob of glass is formed and dropped into the lower part of a heated
mould. The upper part of the mould is forced onto the gob in order to form the insulator
shell. Because the temperature of the glass has decreased, it is now solid and can be
extracted from the mould. The shell is “toughened” by reheating it to a uniform
temperature level that is above the glass transition temperature but below its softening
temperature and then quenched by blowing jets of cold air onto the surface for a few
seconds. Once the shell has regained room temperature, the final distribution of stresses
in the glass ranges from a compression stress on the surface to an internal tension stress
equal to about half the surface compression value.
Thermal shocks are used to identify the shells that have flaws such as inclusions coming
from the furnace walls or are improperly toughened. This involves the rapid heating of the
shells to about 400 °C which causes those parts containing inclusions to shatter. Quickly,
a second thermal shock is applied by dipping the hot shell into a cold water bath. This is
meant to eliminate the improperly toughened shells.
Finally, the discs are optically inspected for flaws and subjected to dimensional checks,
after which they are ready to be fitted with metal parts.
Most glass insulators are made of toughened glass. Nevertheless, some pin-type
insulators and other small insulators that do not require high mechanical strength may be
made with annealed (non-toughened) glass.
The quality of the insulator glass shell, and consequently the performance of the insulator,
depends on the glass formulation and the manufacturing process. Early glass shells
usually failed because of manufacturing problems leading to inclusions in the glass.
Modern technology has practically eliminated this.
The thermal shocks applied to the glass shell during manufacture should eliminate all
inclusions and improper toughening. However, because of a gradual increase in the
stress around an inclusion not detected, the glass shell may shatter in service. Under
normal conditions, the head of the shell cannot be punctured. Small surface imperfections
will not lead to cracks because the surface is under compression.
If a glass shell is broken, upon shattering, the broken pieces of the head of the shell will
be wedged inside the cap. The mechanical strength of this stub will be similar to that of a
sound insulator but the electrical integrity will be lost. In service, such an insulator is
easily detected by a simple visual inspection from the ground or helicopter.
When service conditions involve high levels of pollution, electrical discharges caused by
dry bands will appear on the surface of the glass. If sufficiently strong and of long enough
duration they will erode the surface. If this erosion is deep enough to go through the
toughened layer, it will lead to the shattering of the insulator.
Conduction through glass is mainly ionic in nature. Although not of concern for AC
insulators, with DC this causes ionic migration, a phenomenon highly dependent on the
resistivity and the temperature of the dielectric material. Since the resistivity decreases
with an increase in temperature, thermal run-away can occur. Special formulations of
glass with higher resistivity have thus been developed.
When inclusions exist in the material, ionic migration can also cause the failure of DC
glass insulators. The accumulation of Na+ ions on one side of the inclusion and depletion
of these ions on the other can create mechanical stresses which precipitate complete
shattering of the shell.
5.2.2 Construction of glass insulators
Toughened glass is used mainly for disc insulators, while pin insulators are made with
annealed glass. Toughened glass shells are also used to manufacture station post
insulators but this application is small compared to cap and pin insulators.
5.2.2.1 Cap-and-pin construction
The cap-and-pin toughened glass insulator is similar to the porcelain insulator shown in
Figure 5.1.
5.2.2.2 Post insulators
For post insulators, a number of glass shells are assembled on top of each other and kept
together with cement. The metal fittings are also fastened to the glass shells columns
with cement.
Figure 5.2: Glass (multi-cone) station post insulator (Courtesy of Sediver).
5.3 Polymeric Insulators
IEC 62217 [14] describes standard tests to verify the suitability of the materials used for
polymeric insulators. It divides the insulators into two groups, namely, composite
insulators made of more than one insulating material and resin insulators made of a single
insulating material, usually a filled polymer. Both types are used as long rod, line post,
station post or apparatus insulators. Resin pin-type insulators are also manufactured.
5.3.1 Composite insulators
Composite insulators are made of three main and distinct parts: the core, the housing and
the end fittings. These are discussed below.
5.3.1.1 Composite insulator core
The core is itself a composite material as it is made of fibres imbedded in a resin matrix.
The fibres are made of glass although other insulating fibres can also be used.
For the manufacture of the glass fibres the feeder of the furnace brings the molten glass
to a die with tiny holes through which it flows to form filaments of about 10 µm diameter.
This is done at very high speed. Before they are wound on a cylinder, a sizing is applied
to the filaments to protect them against abrasion and to allow them to bunch together. For
composite insulator applications, the sizing has another important function: its specific
formulation promotes the bonding between the impregnating resin used to manufacture
the insulator core and the glass material of the fibres.
Practically all the cores of composite insulators are made with E or E-CR glass fibres.
The compositions of these two glasses are tabulated in Table 5.3. There is now a
tendency to use E-CR glass fibres because of their better resistance to acid attack. The
preferred impregnating resin is one of several types of bisphenol A epoxy resins. Other
resins such as polyester and vinyl ester are also used. The mechanical characteristics of
the core depend on the relative number of glass fibres, the type of impregnating resin and
the quality of the sizing used. The higher the number of fibres, the better are some of the
mechanical characteristics. The volume percentage of glass fibres is usually about 70%.
The electrical performance depends also on the quality of the impregnation. The solid
rods, and the tubes used for hollow core insulators, are both heterogeneous materials and
their mechanical and electrical characteristics depend on the orientation of the fibres.
Most solid rods are made by pultrusion. This is a continuous process by which any length
of rod can be made. The fibres, coming from bobbins, are submerged in a resin bath and
pulled through a die and curing oven. The now solid rod is cut to the desired length. The
practical limit is dictated by the subsequent handling of the rods during manufacture or the
transportation of the insulators.
The tubes, either cylindrical or conical, used for hollow core insulators are usually made
by the filament winding process. A bunch of fibres is pulled through a resin bath and then
wound back and forth around a mandrel. The winding angle (the angle between the
wound bunch of fibres and the axis of the tube) is set according to the required
mechanical properties of the tube. Practically, it can vary between 25° and 75°. Each
layer of glass fibres increases the thickness of the wall of the tube. Once the desired
thickness is obtained, the mandrel is put into an oven to cure the resin. After curing, the
mandrel is removed and the tube cut to length. In applications where glass fibres can be
attacked by aggressive agents, such as by-products of electric arcs in SF6 gas, a special
protective veil, often made of polyester fibres, is first wound onto the mandrel before
starting the glass fibre winding operation.
5.3.1.2 Composite insulator housing
The fibre-reinforced plastic (FRP) insulator core or tube, being vulnerable to aggressive
agents such as UV radiation, moisture and electrical discharges, is protected by a
polymeric cover called a housing. The electrical performance of the composite insulator
depends mainly on the characteristics and shape of this housing.
Various families of polymers have been used:
• silicone rubbers (SR)

• ethylene propylene diene monomer (EPDM)
• ethylene vinyl acetate (EVA)
• epoxy resin, for example, cycloaliphatic
• high density polyethylene (PE)
• polytetrafluoroethylene (PTFE).
The names of these families of materials are selected on the basis of the main polymer(s)
of their formulations. In order to obtain the desired electrical, mechanical and
environmental characteristics of the housing, it is essential to also incorporate several
additives. Some characteristics of housing materials are given in Table 5.4.
Table 5.4: Properties of selected housing materials.

HTV LSR
Property 1 EPDM 2 Epoxy 2
Silicone 2 Silicone
Dielectric strength [kV/mm] 3 15 17 27 21 - 26
Dielectric constant at 50-60 Hz 3.3 4.0 2.7 4.5
Tan δ at 50-60 Hz 0.02 0.02 0.001 0.02
Volume resistivity [Ω.cm] 5 x 1014 1014 2 x 1015 2 x 1015
Specific gravity ∼ 1.4 1.40 - 1.60 1.10 – 1.14 ∼ 1.9
Arc resistance [s] (ASTM D-149) ∼ 200 ∼ 200 - ∼ 185
Tracking resistance (IEC 60587) High High Low High

180 –
Elongation to rupture [%] 150 – 300 280 - 450 -
230
1
: most of these properties depend on the filler content level
2
: ATH filled
3
: depends on the sample thickness
Presently, for transmission insulators (≥ 220 kV) the preferred housing materials are
various formulations of SR’s and EPDM’s. These, together with EVA’s, are used at the
distribution levels (< 220 kV). Although PTFE has excellent intrinsic properties, the
material is no longer favoured because of the difficulty to bond it to the insulator core and
to bond separate sheds together.
It is not only sufficient for a housing material to have excellent performance when exposed
to service stresses, but it is also very important to incorporate specific additives so that the
formulation has optimum processing properties. Therefore the final formulation is always
a compromise between requirements that are not necessarily compatible.
Various technologies are used to manufacture the insulator housing, such as casting,
extrusion, compression or injection moulding. The housing can be made in one or more
pieces.
5.3.1.2.1 Silicone rubbers
The silicone rubber polydimethylsiloxane (PDMS) comprises an inorganic silicon-oxygen

(Si-O) backbone and organic side groups, usually methyl groups (CH3), attached to the Si
atoms. Vinyl and phenyl side groups can also be present. The chains can be of very
different lengths. The characteristics of silicone rubbers are largely dependent on the
polymer chain lengths and the types of side groups present.
Silicone rubbers can be divided into three distinct categories:
• high temperature vulcanised silicone rubbers (HTV)

• room temperature vulcanised silicone rubbers (RTV 1 or 2)
• liquid silicone rubbers (LSR).
These categories are not only differentiated by their curing temperatures but also by the
pressure at which the vulcanisation is achieved and by the curing agents used. HTV’s
require fairly high pressures and RTV’s pressures close to atmospheric. LSR’s require
medium curing temperatures and pressures.
For all categories, the base silicone compound is mixed with an amount of silica flour to
give it sufficient mechanical strength. A mineral filler, usually alumina trihydrate (ATH) is
also added - up to 60% for certain formulations of HTV’s and RTV’s, or a very low amount
for some RTV’s and LSR’s. Several more additives are introduced such as plasticisers
and colouring agents. Some are required to ease the manufacturing process and also
help to optimise the final characteristics of the rubber. They are specific to the
formulations used by each insulator manufacturer. This clearly indicates that it is not
possible to assign a certain performance level to a SR housing material based only on the
name of the compound. Performance can only be established by comprehensive tests
such as those described in IEC 62217 [14].
Although surface electrical discharges usually produce more erosion on silicone than on
EPDM material surfaces, the fact that silicone surfaces resist uniform wetting makes this
material less susceptible to discharges. This hydrophobic characteristic of silicone is not
a stable property. Under normal service conditions, silicone housing materials are
hydrophobic and water on the surface takes the form of separate drops. The surface,
even if polluted, does not allow leakage current to flow. However, should service
conditions be such that electrical discharges occur, the surface will become hydrophilic.
The hydrophobic property, though, returns when the stress that removed it has
disappeared. The speed at which hydrophobicity is recovered depends on the specific
formulation of the silicone housing material. The hydrophobic characteristic of silicones is
attributed to the presence of low molecular weight PDMS molecules in the formulation as
well as to the specific structure of such molecules.
One may assume that a layer of solid pollution on the surface of a silicone housing
material would cancel the beneficial effect of the material’s hydrophobicity. However, as
illustrated in Figure 5.3, the hydrophobic characteristic of the silicone material is
transferred to the pollution layer. The transfer speed depends on the silicone formulation
and the type and amount of the pollution.
Coarse pollution
Ceramic surface Silicone rubber surface
Fine pollution
Ceramic surface Silicone rubber surface
Figure 5.3: Transfer of hydrophobicity on silicone rubber surface.

5.3.1.2.2 EPDM
The building blocks of EPDM rubber are based on the association of CH, CH2 and CH3
groups. The carbon content of EPDM is therefore significantly higher that that of silicone
rubbers. Consequently, it is critical to include in the formulation agents such as ATH that
will counteract the possibility of having carbon residues on the surface when it is
subjected to electrical arcs.
The tertiary carbon atom in the chain is susceptible to ultraviolet radiation, which can lead
to material degradation (cracking or chalking).
EPDM is a combination of three monomers - ethylene, polypropylene and diene. An early

but now abandoned formulation, EPM, comprised only the first two monomers. In
EPDM’s, the relative quantities and types of each monomer are specific to each
formulation. EPDM’s are usually peroxide cured. All the formulations contain a fairly high
amount of mineral filler, usually ATH. In addition, several additives are introduced such as
plasticisers, UV stabilisers, anti-oxidants and colouring agents. If a small amount of
silicone oil is added, then the formulation is called an alloy. As for SR’s, it is not possible
to assign to a given EPDM formulation a certain performance on the basis of its generic
name alone. This can only be established by comprehensive tests such as those found in
IEC 62217 [14].
5.3.1.3 Construction of composite insulators
Several manufacturing processes are used to apply the housing to an insulator core.
These include injection or compression moulding, extrusion and casting.
5.3.1.3.1 Injection and compression moulding
The housing can be injected over the core in one or several shots. This provides a one-
piece housing directly and chemically bonded to the core and the metal fittings.
Alternatively, the housing can be compression moulded onto the rod. This also results in
a chemical bond to the core but the housing to-end-fitting seal has to be added in a
separate operation.
A minimum number of interfaces is achieved when housings are moulded. Particular care
is however required to ensure that the core is centred and that the mould line does not
represent a pollution trap or suffer from degradation due to material in-homogeneity.
5.3.1.3.2 Extrusion
With this technique, a sheath is extruded onto the core. Sheds, moulded separately, are
then slipped over the sheath and bonded to it. The housing-to-end fitting seal must be
applied in a separate operation.
Such construction allows flexibility of design as the quantity and position of the sheds can
be varied to suit the application without incurring the capital cost of acquiring different
moulds.
5.3.1.3.3 Un-bonded sheds
In this type of construction, single or groups of sheds are moulded separately and then
pushed over the core. The housing is not bonded to the core and the interface is filled
with a grease (usually silicone). The seals between the housing and the end fittings
depend on the pressure between the two, created by the elasticity of the sheds.
Such insulators are simple to produce, but contain many interfaces that lead to the core.
Grease seepage can occur. Because of the hoop stress inherent in the sheds, there is a
possibility of splitting and core exposure.
5.3.1.3.4 Other constructions
The sheds of some hollow core insulators are cast one by one onto the tube. An early
design of composite line insulators also had each RTV shed cast separately over the core.
The housing of another type of hollow composite insulator is moulded over the tube and
part of the end fittings in one or several steps.
Finally, a specifically shaped ribbon of material can be helically wound around the tube
and part of the end fittings to form the housing of a hollow core insulator. This technique
can also be used to make composite post insulators, provided the diameter of the core is
fairly large.
5.3.2 Resin insulators
Resin insulators are made from various types of heavily filled polymeric resins, such as
cycloaliphatic or bisphenol epoxies, polyester or polyurethane. The mineral fillers are
meant to improve the tracking and erosion performance of the formulations. The filler
content is typically 60% to 70%. Colouring agents and other additives may also be
introduced in the formulations. The higher the amount of filler the more difficult it is to cast
or mould the compound into the desired insulator shape. The metal end fittings can be
embedded in the insulation during the moulding operation. A formulation in which the filler
content reaches about 90% has been named a polymer concrete.
There are several types of epoxy resins. Whereas bisphenol epoxies are used for the
manufacture of the core of composite insulators, cycloaliphatic epoxies are more
commonly used for outdoor insulators.
The building blocks of epoxy resins are based on C, CH2 and CH3 molecules and thus the
material has a high carbon content. Due to the presence of esters in the cycloaliphatic
chain, degradation due to hydrolysis can occur. Thus ATH is not normally used as filler,
but silica is preferred.
Cycloaliphatic materials are also susceptible to degradation by ultraviolet radiation, which

results in chalking of the material.
The silicone-based mould release agent normally present on the surface of new epoxy
insulators initially provides them with a hydrophobic surface. In-service, however, this
only lasts for a short period of time.
Owing to the many variations in resin compositions, insulator performance cannot be

assumed from the name of the formulation but has to be evaluated using tests such as
those described in IEC 62217 [14].
5.4 Metal Fittings
The metallic hardware transmits the external load to the insulating part of the insulator. If
this hardware breaks, the supported load will usually fall to the ground. Because of the
long-term mechanical performance required, high quality materials without defects (cracks
or heterogeneity) are needed. Characteristics of the main end fitting materials are given
in Table 5.5.
Table 5.5: Characteristics of end fitting materials.
AISI grade 10 38 C : 0.35 to 0.40
AISI grade 10 45 C : 0.45 to 0.51

US. Alu. Assoc. Grade A 356, T6
ASTM A 536-80 Grade 60-40-18
Medium carbon steel for pins

Medium carbon steel for pins
ASTM A 47-77 Grade 35 210
% Normalized Quenched
% Normalized Quenched
Malleable cast iron
Ductile cast iron
Aluminium alloy
Characteristics
Tensile strength
320 - 380 370 - 420 325 580 800 670 810
[MPa]
Elastic limit
210 - 250 230 - 280 250 330 - 400 620 370 - 450 640
[MPa]
Elongation
8 - 18 17 - 18 10 - 14 18 - 21 12 15 - 17 10
[%]
Modulus of elasticity
140 140 74 200 205 - 210 200 205 - 210
[GPa]
Resilience at
-2
20°C [J cm ] 10 - 12 15 – 17 - - 5 - 5
-2
-40°C [J cm ] 9 - 11 4-6 - - - - -
Coefficient of linear
-6 12 12 21.5 11 11 11 11
expansion [10 ]
Brinell hardness
110 - 145 ≤ 180 100 170 - 190 > 190 90 - 220 > 220
[HB]
5.4.1 Caps
The design and dimensions of insulator caps (mainly socket or clevis type) are specified in
standards (see Chapter 8). They are manufactured using a casting or forging process.
The main materials used are: malleable cast iron, ductile iron and steel. Their
characteristics are given in Table 5.5. Because of their low corrosion resistance, cast iron
and steel must be protected by galvanization. The quality of the galvanising is defined in
IEC and ISO standards. Caps can also be made with cast or forged aluminium alloys.
These are inherently corrosion resistant but, because of their low melting temperatures,
they can be damaged by power arcs unless protected by arcing horns. For insulators
used on HVDC lines, a zinc ring can be fitted at the edge of the cap. This ring acts as a
sacrificial electrode to combat corrosion.
5.4.2 Pins
The design and dimensions of the pins - ball and tongue - are specified in standards (see
Chapter 8). Pins are usually forged, heat-treated, medium carbon steel. Like caps, pins
have to be galvanised in accordance with IEC and ISO requirements.
The biggest concern with regard to metalware when required to operate in highly polluted
conditions is corrosion, particularly of the pin. Spark erosion of the pin near the cement
surface can reduce its diameter to a point where it is sufficiently weakened to drop the
line. Also, swelling of the pin inside the cement can generate internal mechanical
stresses which may cause insulator breakage.
5.4.3 Fittings for porcelain station post insulators
The end fittings of station post insulators are usually made of galvanised, malleable or
ductile iron, the characteristics of which are tabulated in Table 5.5.
5.4.4 Fittings for composite insulators
The metal fittings of composite long rod insulators are usually made of forged steel or
sometimes ductile iron. Some composite long rods, intended for use on distribution lines,
are equipped with aluminium alloy fittings, although it is difficult and uneconomical to
design them to survive power arcs.
The metal fittings of line and station post composite insulators are made of malleable iron,
ductile iron or aluminium alloy (see Table 5.5).
5.4.5 Fittings for hollow porcelain or composite insulators
The metal flanges of hollow porcelain insulators are made of malleable iron, ductile iron or
aluminium. Cast or machined aluminium is the preferred material for the flanges of hollow
composite insulators. For some applications the dimensional and surface tolerances of
the flanges are critical and require accurate machining and attachment.
5.5 Relative Pollution Performance
In polluted areas, the difference in performance between the various insulator materials
becomes most apparent. For example, when contaminated, characteristics such as the
hydrophobicity of silicone rubber housings and the surface heating and grading current of
resistive glazed insulators, serve to reduce the leakage current activity and the risk of
flashover.
Figure 5.4 illustrates the average peak leakage currents recorded over a one-year period
at the Koeberg Insulator Pollution Test Station (KIPTS) on insulators of identical profile but
different material. The test arrangement is shown in Figure 5.5.
50
48
46
Cyclo aliphatic
44
42
A verage P eak Leakage C urrent (mA )
40
38
36
34
32 Porcelain
30
28 EPDM
26
24
22
20 HTV SR
18
16
14
12
10
8
RTV SR coated porcelain
6
4 Resistive Glaze
2
01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00
Time Of D ay
Figure 5.4: Average peak leakage current for various test insulator materials.
Figure 5.5: Insulator material test arrangement at KIPTS.

The relative leakage current activity, expressed as the accumulated electrical charge
flowing over the insulator surface, is shown in Figure 5.6. The values were measured on
insulators of various materials installed on the in-service test tower shown in Figure 5.7.
80
75
EPDM rubber
70
65
60
A cc.Resulting C harge (C )
55
50
45
40
35
Toughened glass
30
25
20
15
10
HTV silicone rubbers
5
0
00:00:00 00:00:00 00:00:00 00:00:00 00:00:00 00:00:00 00:00:00 00:00:00 00:00:00 00:00:00 00:00:00
1999/08/15 1999/09/01 1999/09/15 1999/10/01 1999/10/15 1999/11/01 1999/11/15 1999/12/01 1999/12/15 2000/01/01 2000/01/15
D ate
Figure 5.6: Leakage current activity on in-service insulators of different material.
Figure 5.7: In-service insulator test tower.
From the examples provided above, the significant differences in the performances
experienced, highlights the need to consider the characteristics of the materials in the
insulator selection process.
Mechanical Considerations 69
6 MECHANICAL CONSIDERATIONS
“Engineering is the practice of safe and economic application of the scientific laws governing the
forces and materials of nature by means of organization, design and construction, for the general
benefit of mankind” – S E Lindsay
Introduction
A comprehensive analysis of all the mechanical forces which may be applied to an

overhead line or substation, and to which the insulators may therefore be subjected, is
beyond the scope of this book. This chapter does, however, serve to describe the types
of loads which must be considered, which of these are the most critical for the different
insulator types, and the basic principles of their calculation. The way in which the
mechanical characteristics are specified and the terminology used are also explained.
6.1 Tensile Loads
Long rod and cap-and-pin disc insulators are employed where the applied mechanical
loads place the insulators in tension. When used in strain positions, the force is equal to
the tension in the conductor. In suspension positions, the tensile stress results from the
conductor mass and the wind pressure applied to the conductor. Each of these cases is
examined below.
6.1.1 Strain insulators
The tension which a strain insulator must accommodate represents a continually varying
force as it is directly influenced by the conductor temperature, the wind load on the
conductor and the possible increase in mass of the conductor owing to ice build-up. The
strength of the insulator must be such as to withstand the loads, with an adequate safety
margin, under the worst case conditions.
When an overhead line is constructed, the conductor is tensioned in accordance with a

set of stringing tables specific to each strain section. The tables are based on one or more
stringing criteria – these relate the tension of the conductor to various wind loads, ice
loads and temperatures. The conditions specified typically take the form of “a factor of
safety of X on the conductor strength at a temperature of t, wind pressure of P and radial
ice thickness of q”. From the conditions specified, the highest expected conductor tension
must be established. This may occur, for example, at the minimum temperature or at a
higher temperature with greater wind loads. The expression below provides the
relationship between a given set of conditions and any other set of conditions and can be
used to calculate the maximum conductor tension.
  C1 ⋅ W1 ⋅ L span 
2

T2 ⋅ T2 + C 2 ⋅ (t 2 − t 1 ) + 
2
 − T1  = (C1 ⋅ W2 ⋅ L span )2 (6.1)
  T1  
where,
T1 : conductor tension under condition 1

T2 : conductor tension under condition 2
t1 : conductor temperature under condition 1
t2 : conductor temperature under condition 2
W1 : conductor mass under condition 1
W2 : conductor mass under condition 2
Lspan : span length
and,
E ⋅ A con
C1 =
24
C2 = α t ⋅ E ⋅ A
where,
Acon : cross-sectional area of conductor

E : modulus of elasticity of conductor
αt : linear coefficient of expansion of conductor.
It should be noted that W is the resultant of the conductor mass, ice mass and wind force.
Expression 6.1 can be solved manually by trial and error but, as this is extremely time
consuming, the different operating conditions are usually explored by using software
designed for the calculation of conductor sags and tensions. The maximum tension
calculated for the various site conditions is equal to Ft, the maximum tensile load to which
the insulator is subjected.
6.1.2 Suspension insulators
Suspension insulators must be able to support the mass of the conductor, together with
additional forces resulting from the wind pressure and/or the weight of ice on the
conductor. The vertical load to be supported, Fv , is:
( ( 2
))
Fv = m c + π ⋅ bi ⋅ qice + qice ⋅ dcon ⋅ S m (6.2)
where,
mc : conductor mass per unit length

dcon : conductor diameter
qice : radial ice thickness
bi : ice density
Sm : weight span.
As illustrated in Figure 6.1, the weight span is defined as the horizontal distance between
the lowest point of the conductors on the two spans adjacent to the insulator. The lowest
point is the position at which the tangent to the curve of the sag is horizontal.
Figure 6.1: Weight and wind span.
The horizontal wind load on each conductor, Fh , is:
Fh = Pw ⋅ (dc + 2 ⋅ qi ) ⋅ s f ⋅ gf ⋅ S w (6.3)
where,
Pw : maximum wind pressure

sf : shape factor
gf : gust factor
Sw : wind span.
The shape factor accounts for the more aerodynamic rounded profile of the conductor by
effectively reducing the value of the projected area. Its value varies from designer to
designer and country to country, but is typically around 0.6.
The gust factor is introduced if the specified wind pressure is based on the maximum wind
speed that occurs in a gust. As the front of a gust is not very wide, it is assumed that the
force will not act over the entire span at once and the effect is therefore reduced by a gust
factor. This is also often taken to be 0.6, i.e. it is assumed that the maximum wind speed
acts over 60% of the wind span length.
As shown in Figure 6.1, the wind span equals one half of the sum of the two spans on
either side of the insulator.
The maximum tensile force applied to the suspension insulator, Ft, is thus:
2 2
Ft = Fv + Fh (6.4)
For disc and long rod strings, the application of cantilever loads owing to wind action must
be avoided by allowing these insulators freedom of movement at the crossarm attachment
point. Insulators on the windward side of the tower or pole will thus swing towards the
structure and it must be checked that adequate clearances are maintained. The angle θ
to which the insulator will be deflected from the vertical is:
F 
θ = tan −1  h  (6.5)
 Fv 
6.1.3 Angle suspension insulators
Where the intermediate structures are designed to accommodate small angles of

deviation of the line, an additional horizontal force is introduced as a result of the
conductor tension. This force, Fa , can be expressed as:
γ
Fa = 2 ⋅ Tw ⋅ sin  (6.6)
2
where,
Tw : the conductor tension, without wind, at the temperature at which the maximum
wind speeds are assumed to occur
γ : the angle of deviation of the line.
The wind load, Fw , can then be defined as:
γ
Fw = Pw ⋅ (dc + 2 ⋅ qi ) ⋅ s f ⋅ gf ⋅ S w ⋅ cos  (6.7)
2
The total horizontal force on an insulator, FH , is thus:
FH = Fa + Fw (6.8)
For the larger angles of deviation, the force applied as a result of the conductor tension at
low temperatures may be greater than the force at higher temperatures, where maximum
wind loads are expected. In other words, it must be established whether the worst case
occurs under conditions of minimum temperature or maximum wind speed.
6.1.4 Insulator strength
Having calculated the maximum tensile load, Ft , to be applied, it must be ensured that the
insulator selected can accommodate such load with an adequate safety margin. The
mechanical strengths of insulators are defined in different ways for the different insulator
types and it is important to clearly understand the meaning of the terminology used.
6.1.4.1 Porcelain long rod and glass disc insulators
For porcelain long rods and glass discs, a “mechanical failing load” or “minimum
mechanical failing load” is specified by the manufacturer. This value is usually equal to
the mean breaking force of the metal fittings or the dielectric component, whichever is the
lower, less three standard deviations.
The required minimum mechanical failing load (MFL) of the insulator to be used is:
MFL = Ft ⋅ FOS (6.9)
where FOS is the required factor of safety.

6.1.4.2 Porcelain disc insulators
For porcelain discs, and any other ceramic string insulator units of the Class B type, the
insulator is continuously subjected to power frequency voltage during the mechanical test.
Any internal electrical discharge then serves to indicate that the dielectric component has
failed. The “electromechanical failing load” (EMFL) is defined as the maximum tensile
force reached prior to breakage of the insulating part or the metalware. As above, the
electromechanical strength specified is normally the average value less three standard
deviations.
The required minimum electromechanical failing load of the insulator to be used is:
EMFL = Ft ⋅ FOS (6.10)
where FOS is the specified factor of safety.
6.1.4.3 Composite long rod insulators
It is stated in IEC 61109 of 1992 [15] that the mechanical strength of loaded composite
insulators is not constant but decreases with time – this being due to creep of the core
materials. The curve of the strength as a function of the logarithm of the time of load
application was assumed to be a straight line with a negative slope. Tests were described
to establish the position and slope of the curve – the latter to be less than 8% of the one-
minute failing load per decade of time.
100
90
80
Normalised load (%)
70
Actual Curve
60
50
40
IEC Curve
30
1 10 100 1,000 10,000 100,000 1,000,000 10,000,000 100,000,000
Time (min)
Figure 6.2: Actual load/time curve and IEC 61109 Annex A load/time curve.
Current knowledge of the behaviour of fibreglass rods, however, has shown that the load
versus log time curve is not linear, and that the composite insulator retains nearly all of its
original strength over its entire life. A comparison of the IEC curve and a typical actual
load curve is shown in Figure 6.2. It is apparent that the rod is only damaged when the
load duration is very close to the time of failure. Moreover, the curve becomes asymptotic
to the X-axis at a load of around 65% to 70% of the one-minute failing value. This can be
defined as the damage limit. As in practice most insulators are dimensioned with a factor
of safety of at least 2.0, the damage limit is never exceeded and the duration of load
application has no effect.
The proposed definitions of the loads to be considered and the approach to be adopted
for composite long rod insulator selection, are provided below.
One-minute failing load (Mav):

Mav is the mean arithmetic failing load calculated from at least three measured failure
values.
Specified mechanical load (SML):

SML is the one minute withstand force specified by the manufacturer. A specified
strength curve, provided by the manufacturer, shows those values of load and duration
with less than 10% probability of failure.
Extraordinary mechanical load (EML):

EML is the estimated load that will occur for a total maximum duration of one week over
the entire lifetime of the insulator.
As for porcelain and glass insulators, the minimum strength required for a composite long
rod is:
SML = Ft ⋅ FOS (6.11)
Where no statutory factor of safety needs to be applied, insulators can be selected on the
basis of the “damage limit”. Although the damage limit for a particular insulator may not
be defined, if the EML is less than 60% of the SML then the mechanical characteristics of
the insulator will be adequately catered for and a long-term secure installation realised.
Sample calculations
It is proposed to erect a 132 kV line with a single ACSR conductor and glass disc
insulators in mountainous terrain. The climate is mild but, owing to the altitude, some ice
formation is expected. An ice density of 900 kg/m3 is assumed. The stringing criteria
specified are:
(i) A factor of safety of 2,5 at – 22 °C with no wind or ice loading

(ii) A factor of safety of 2,5 at – 5 °C with 800 Pa wind pressure and 6 mm radial ice
thickness
(iii) A factor of safety of 2,5 at 5 °C with 1460 Pa wind pressure and no ice
(iv) A factor of safety of 5,0 at 15 °C with no wind or ice loading.
Assuming a ruling span of 300 metres, a maximum wind span of 400 metres and weight
span of 450 metres, the required strength of the strain and suspension insulators, with a
factor of safety of 2.5, is to be established.
The characteristics of the conductor are:
Overall diameter 18,13 mm

Total cross-sectional area 194,94 mm2
Mass per unit length 0,73 kg/m
Ultimate tensile strength 69,2 kN
Coefficient of linear expansion 18,43 / °C x 106
Final modulus of elasticity 83400 N / mm2
(a) Strain Insulators
From Equation 6.1, it is seen that the criterion (iv) dictates the stringing tension. The
resultant conductor tensions under the various conditions are:
Temperature Wind Load Ice Thickness Tension – no wind Tension – with wind
(°C) (Pa) (mm) (N) (N)
-22 0 0 18123 N/A
-5 800 6 20998 24308
5 1460 0 14796 20700
15 0 0 13840 N/A
The maximum tension is thus 24.31 kN. The required minimum failing load of the strain
insulators is thus:
MFL = Ft x FOS = 24.31 x 2.5 = 60.8 kN
Disc insulators of 70 kN rating will therefore suffice.
If composite long rods are to be considered, the loads to be applied must be compared to
the insulator’s strength curve, a typical example of which is provided in Figure 6.3.
80
70
60
50
Load (kN)
Specified Strength Curve

40
30
20
Application Curve
10
0
1 10 100 1000 10000 100000 1000000 10000000 100000000
Time (min)
Figure 6.3: SML and application curves for a 70 kN composite long rod.
With reference to Figure 6.3, plotting the 15 °C condition as the Ordinary Mechanical Load
and the – 5 °C condition with wind and ice as the Extraordinary Load, the “Application
Curve” can be drawn. It will be noted that this lies well below the Specified Strength
Curve and provides an adequate safety margin.
(b) Suspension Insulators
It is clear that the maximum load on the suspension strings occurs during either condition
(ii) or (iii). An examination of the forces associated with each of these conditions is
therefore required.
Condition (ii): - 5 °C, 800 Pa wind pressure, 6 mm radial ice thickness
From Equation 6.2,

Vertical load: Fv = [0.73 + π x 900 x (0.0062 + 0.006 x 0.01813)] x 450
= 512.7 kgf
= 512.7 x 9.807 = 5028 N
From Equation 6.3,

Horizontal load: Fh = 800 x (0.01813 + 2 x 0.006) x 0.6 x 0.6 x 400
= 3471 N
From Equation 6.4,

Total tension: Ft = (50282 + 34712)0.5
= 6110 N
Condition (iii): 5 °C, 1460 Pa wind pressure, no ice
From Equation 6.2,

Vertical load: Fv = 0.73 x 450 x 9.807
= 3222 N
From Equation 6.3,

Horizontal load: Fh = 1460 x 0.01813 x 0.6 x 0.6 x 400
= 3812 N
From Equation 6.4,

Total tension: Ft = (32222 + 38122)0.5
= 4991 N
Condition (ii) is therefore the more onerous, and the required minimum failing load of the
suspension insulators is:
MFL = Ft x FOS = 6110 x 2.5 = 15.3 kN
Disc insulators of the minimum standard rating of 40 kN will thus be more than adequate.
Note: In order to keep the insulators identical over the whole line, 70 kN discs may well
be adopted for the suspension positions as well. The larger discs also offer the
advantage that, for a given creepage distance, the string length can be shorter.
(c) Angle Suspension Insulators
What insulator strength is required to accommodate a 7o deviation of the line?
For angle suspension strings, the effect of the conductor tension must be added to the
horizontal force applied by the wind. The two forces should be treated separately, i.e. the
conductor tension used in the calculations should be that at the appropriate temperature
but in still air. With condition (ii) being that of the highest load, the force due to the
conductor tension is,
From Equation 6.6, Fa = 2 x 20998 x sin(7o/2)

= 2564 N
and from Equation 6.7 the wind load is,
Fw = 800 x (0.01813 + 2 x 0.006) x 0.6 x 0.6 x 400 x cos(7o/2)

= 3465 N
giving a horizontal load, from Equation 6.8, of,
FH = 2564 + 3465
= 6029 N
As before, the vertical load is,
Fv = 5028 N
and the total load is,
Ft = (50282 + 60292)0.5
= 7850 N
The increase in load is thus relatively minor and the insulators selected for the suspension
positions will also accommodate small angles.
6.1.4.4 Buckling loads
Composite long rod insulators are designed to accommodate tensile loads only and the
application of bending or compressive stresses must be avoided. In a V-string
suspension configuration, however, if the expected wind pressures are high but the weight
spans small, the leeward insulator may be subjected to compression. If the ratio of wind
span to weight span indicates that this may be the case, the loading of the insulator
should be checked.
The compressive force required to damage a composite long rod is low but a large
deflection can be tolerated before such damage occurs. This is illustrated in Figure 6.4
and Figure 6.5 which show the maximum buckling load that can be supported and the
magnitude of the deflection at such load, respectively. The deflection is specified as the
reduction in distance between the attachment points as a result of the insulator adopting a
bowed shape.
600
500
Compressive Force (N)
400
300
200
100
0
1.5 1.75 2 2.25 2.5 2.75 3 3.25 3.5 3.75 4 4.25
Connecting Length (m)
Figure 6.4: Typical maximum permissible compressive load – 16 mm rod diameter.
2500
2000
Longitudinal Deflection (mm)
1500
1000
500
0
1.5 1.75 2 2.25 2.5 2.75 3 3.25 3.5 3.75 4 4.25
Connecting Length (m)
Figure 6.5: Typical maximum permissible compressive deflection – 16 mm rod diameter.
With a V assembly in which each insulator is angled at 45 degrees, if the wind load equals
the mass supported, the leeward insulator carries no load at all. As the wind force is
further increased, the unit goes into compression. It will then start to bend and the angle
to the vertical of the windward insulator will increase.
To establish whether there is a danger of insulator damage, a simplified, conservative

approach can be taken. This is done by assuming the leeward insulator has no resistance
to buckling and checking that the angle adopted by the windward unit under worst load
conditions does not cause a deflection greater than the maximum permissible value.
Alternatively, the actual loads involved can be analysed and the limiting conditions
established. Examples of these approaches are provided below.
Sample calculation
A structure of a 275 kV line equipped with a twin AAAC conductor is situated in a valley
and has a wind span of 375 metres but a weight span of 200 metres. The maximum
design wind pressure is 1200 Pa. The conductor has a diameter of 18.8 mm and a mass
of 0.58 kg/m. Can insulators of 2.75 m connecting length, with the characteristics shown
in Figure 6.4 and Figure 6.5, be used in a 45 degree V-string configuration?
From Figure 6.5, the maximum permissible deflection for a 2.75 m long insulator is
700mm, the effective length is thus 2050 mm. The geometry of the assembly is then as
shown below from which it can be seen that the limiting angle of the windward string to the
vertical is 90o – 30.2o = 59.8o.
3889
30,2°° 42,4°°
27
50 50
20
Figure 6.6: Limiting deflection of the V-string with 16 mm composite long rods.
From Equation 6.2, the vertical load for the two conductors, Fv, is:
Fv = 2 x 0.58 x 200 x 9.807 = 2275 N
and from Equation 6.3, the horizontal load for the two conductors, Fh, is:
Fh = 2 x 0.0188 x 375 x 1200 x 0.6 x 0.6 = 6091 N
From Equation 6.5, the angle of swing, θ, of the insulator, is thus:
θ = tan-1(6091 / 2275) = 69.5°
As this is greater than the limiting value of 59.8°, o verloading of the leeward insulator can
be expected.
For a more precise analysis, the value of the maximum compression force “C” can be
obtained from Figure 6.4 and the vector diagram of the forces at the limiting condition
drawn, as shown in Figure 6.7.
59,8°°
Fv = 2275 N
Fh
42,4°°
N
107,4°° 5
19
=
C
Figure 6.7: Vector diagram of the forces at the limiting load condition.
From the geometry of Figure 6.7, the maximum horizontal load that can be
accommodated, Fh, is thus:
Fh = 2275 x sin59.8o + 195 x sin107.4o = 4279 N

sin30.2o
From Equation 6.3, the maximum wind pressure that can be tolerated is thus:
Pw = 4279 = 842 N
2 x 0.0188 x 375 x 0.6 x 0.6
6.1.4.5 Torsional Loads
As mentioned previously (Section 5.3.1.1), the cores of composite long rod insulators are
produced with uni-directional, longitudinal glass fibres to accommodate high tensile loads.
However, because of the fibre orientation, their resistance to torsional forces is low.
Typically, the maximum torque that can be applied without permanent damage is 65 Nm
for a 16 mm diameter core and 175 Nm for a core of 24 mm diameter.
The angular deflection before the damage limit is reached, though, is large. The
maximum permissible deflection for a given insulator length is shown in Figure 6.8.
It is evident from Figure 6.8 that the possible torsional loading of a strain insulator in
service owing to, say, the movement of the jumper in windy conditions, should not pose
any problem as the amount of rotation is limited. As described in Section 10.8, however, it
is most important that the units are not twisted during handling, installation and conductor
stringing. In this regard, the probability of damage is considerably increased when a
single strain insulator is used to support a twin conductor bundle. In such cases, the use
of two insulators, either with or without inter-connecting yoke plates, is preferred.
Figure 6.8: Typical damage limits for the twisting of long rod insulators.
6.2 Cantilever Loads
Where the major service load is one of cantilever, i.e. a bending force is applied to the
insulator, then the use of line post, station post or pin insulators is required. The process
to be followed for the selection of these in terms of their mechanical strength is provided
below.
6.2.1 Line post and pin insulators
Cantilever, or bending, loads predominate where pin and line post insulators are used on
intermediate structures of overhead lines. With the insulator in a vertical position, the main
cantilever force is due to the wind load on the conductors. This force, Fh, can be
calculated from Equation 6.3. When used horizontally, the mass of the conductors
represents the critical loading and the calculation of the bending force, Fv, is defined in
Equation 6.2.
For ceramic line posts, the required minimum cantilever failing load is thus:
CFL = Fh ⋅ FOS (6.12)
or,
CFL = Fv ⋅ FOS (6.13)

For composite line posts, a Maximum Design Cantilever Load (MDCL) - the load above
which damage to the core begins to occur and which is thus the ultimate limit for service
loads - is specified by the manufacturer.
With reference to Figure 6.9, the bending moment that a horizontal post experiences in
service may result from the combination of both a vertical (V) and a longitudinal (L) load,
the latter acting along the axis of the conductor owing to a difference in the conductor
tensions on either side of the insulator. In addition, tension (T) or compression (C) forces
from wind loads and/or line deviations may also be present. It must be ensured that the
combination of these loads does not result in a compressive stress in the core greater
than that which is created by the MDCL. By definition, the total maximum bending
moment which may be applied to the insulator is thus:
Mmax = MDCL ⋅ d (6.14)
where d is the distance from the point of application of the load to the top edge of the base
metal fitting.
Figure 6.9: Forces which may act on a horizontal line post insulator.
The method for calculating the maximum moment applied in service as a result of the
vertical, longitudinal, compressive and tensile forces is provided in IEC 61952 [16] and
also given below for convenience.
In the compressive case,
1
 1

 2 E ⋅ I 2   C 
( )  
2
2
Mc =  V + L ⋅ ⋅ tan d ⋅  (6.15)
 C    E ⋅I  
 
and in the tension case,
1
 1

 2 E ⋅ I   T 
( 2
Mt =  V + L ⋅ ) 2

2
 ⋅ tanh d ⋅  E ⋅ I  
 (6.16)
 T   
 
where,
E : longitudinal Young’s modulus

I : moment of inertia of the rod.
When the insulator is designed with an upward angle to the horizontal, α, the formula
above may be used with the following modifications:
V = C’sinα + V’cosα
C = C’cosα + V’sinα
T = T’cosα + V’sinα
where, C’, V’ and T’ are the applied loads.
For practical insulator selection, however, reference should be made to the permissible
load curves provided by the manufacturer, typical examples of which are shown in Figure
6.10 and Figure 6.11. These define the damage limit of the core for any combination of
forces. The various loading conditions associated with the application can thus be plotted
on the chart and checked that they are acceptable.
Figure 6.10: Typical load application curve for a horizontal line post.
Figure 6.11: Typical load application curve for a line post mounted at 15 degrees to the
horizontal.
It should be noted that if a factor of safety of at least 2 is applied to the insulator

manufacturer’s specified cantilever failing load, this will, in most practical cases, yield a
maximum working load inside the damage limit curve. Thus, apart from special cases
with very high horizontal or longitudinal loads, there is little danger of premature failure if
the composite posts are treated in a similar manner to their ceramic counterparts.
Sample calculation
With reference to the example given in Section 6.1.4.3, Figure 6.12 shows the various
load conditions plotted on a manufacturer’s curve for a 132 kV line post of 63 mm core
diameter. Two points are generated for each case as the wind could blow from either
direction, with the Y-axis being the still-air condition. For the angle suspension position,
the line post could be situated on the inside of the angle, thus being in compression, or
the outside of the angle, thus being subjected to a tensile load.
Figure 6.12: Relationship between service loads and insulator strength.
It is evident that the insulator is suitable for the application, including the 7° line deviation,
provided that the longitudinal load does not exceed 3 kN.
6.2.2 Braced post insulators
Where the support of heavy conductor bundles and/or long spans is required, a braced
post arrangement, as illustrated in Figure 6.13, may be necessary. This is particularly true
for the higher voltages where longer insulators are needed to satisfy the electrical
characteristics. The brace removes the cantilever load from the line post. The post must,
however, be able to support the compressive forces created by the horizontal component
of the tension in the brace. Externally applied horizontal loads, such as those due to wind
or a deviation in the line direction, must also be considered in the dimensioning of the
insulators. Clearly, the load condition for the brace insulator is more critical when the
horizontal force is directed away from the pole whereas for the post it is more critical when
the force is directed towards the pole.
Figure 6.13: Combined loads applied to a braced post insulator.
With reference to Figure 6.13, the tensile load in the brace, Pb,, when the horizontal force
is towards the pole, can be expressed as:
V ⋅ cos α − C ⋅ sin α
Pb = (6.17)
sin β
or, when the horizontal force is away from the pole, as:
V ⋅ cos α + T ⋅ sin α
Pb = (6.18)
sin β
For the compressive load in the post, Pp, with the horizontal force towards the pole:
V ⋅ cos(β − α ) + C ⋅ sin(β − α )
Pp = (6.19)
sin β
or, with the horizontal force away from the pole:
V ⋅ cos(β − α ) − T ⋅ sin(β − α )
Pp = (6.20)
sin β
From the loads calculated above, the brace insulator can be selected from the SML
values for long rods and the post from the maximum compressive loads for line posts
specified by the manufacturer.
In cases where longitudinal loads are expected, the analysis becomes far more complex,
and the use of finite element analysis software is warranted. As for the unbraced
condition, however, insulator selection can be made from loading curves provided by the
manufacturer. An example of such a diagram is shown in Figure 6.14.
LOAD APPLICATION CURVES FOR BRACED LINE POST

(15° with Horizontal)
L=2000 mm - Φ =63 mm - σ =400 MPa
Curves established with the finite element software
Longitudinal
80 Loads (kN)
0.01
70 1
2
60 3
4
Vertical Loads in kN
50
40
30
20
10
0
-18 -16 -14 -12 -10 -8 -6 -4 -2 0 2 4 6 8 10 12 14 16 18
Transverse load in kN Compression -->
<-- Tension
Figure 6.14: Typical load application curve for a braced post insulator.
Sample calculation
It is proposed to erect a line equipped with twin ACSR conductors suspended from
composite braced post assemblies. The critical design loads are provided below:
(i) A factor of safety of 2.5 at – 22 °C with no wind or ice loading

(ii) A factor of safety of 2.5 at – 5 °C with 1333 Pa wind pressure and 6mm radial ice
thickness
(iii) A factor of safety of 2.5 at 5 °C with 2433 Pa wind pressure and no ice
(iv) A factor of safety of 5.0 at 15 °C with no wind or ice loading.
Assuming an ice density of 900 kg/m3, a ruling span of 350 metres, a maximum wind span
of 425 metres and weight span of 550 metres, the required strength of the brace
insulators and the acceptability of the line posts are to be established. Further, can line
deviations of 5 and 10 degrees be accommodated?
The characteristics of the conductor are:
Overall diameter 28.62 mm

Total cross-sectional area 484.48 mm2
Mass 1,63 kg/m
Ultimate tensile strength 133 kN
Coefficient of linear expansion 19.91/°C x 106
Final modulus of elasticity 73200 N/mm2.
From Equation 6.1, it is seen that criterion (iv) dictates the stringing tension and the
conductor tensions under the various conditions are:
Temperature Wind Load Ice Thickness Tension – no wind

(°C) (Pa) (mm) (N)
-22 0 0 32134
-5 800 6 29283
5 1460 0 27863
15 0 0 26600
Using Equations 6.2, 6.3, 6.6 and 6.7, the vertical and horizontal loads for the four
conditions are derived. These are tabulated below.
Cond. Vertical Horizontal Loads (N)

Temp. Load No Dev. 5 degree Line Deviation 10 degree Line Deviation
(°C) (N) Wind Wind Tension Total Wind Tension Total
-22 17584 - - 5607 5607 - 11203 11203
-5 23920 16573 16557 5109 21666 16510 10209 26719
5 17584 21310 21290 4861 26151 21229 9714 30943
15 17584 - - 4641 4641 - 9273 9273
From Equation 6.18, assuming a brace angle, β, of 57° and a post angle, α, of 12°, the
tension in the brace insulator, Pb , for the worst case condition of –5 °C and an angle of
deviation of 10°, is as follows:
Pb = 23920 x cos12o + 26719 x sin12o = 34.5 kN

sin57o
For the post, the loads, plotted on the application curve of the insulator in question, are
shown in Figure 6.15. It is evident that the conductors can be accommodated on a
straight line route provided that the longitudinal forces are limited to a value of 2 kN. At a
10 degree line deviation, no longitudinal load can be tolerated.
1: -5°C
2: -5°C, 5° dev.
3: -5°C, 10° dev.
4: -22°C & 15°C
5: 15°C, 5° dev. •1 •2 •3
6: -22°C, 5° dev. 6
7: 15°C, 10° dev. 4 • 5 • 7 ••8 •9 •10•11
8: -22°C, 10° dev.
9: 5°C
10: 5°C, 5° dev.
11: 5°C, 10° dev.
Figure 6.15: Expected maximum loads in relation to the insulator damage limits.
6.2.3 Station post insulators
When selecting support insulators for substations, the weight and wind forces can be
treated in the same way as described for line post insulators. However, in the case of
composite station posts, their deflection under load must also be considered.
The flexibility of polymeric insulators can be beneficial. For example, when used as
tubular busbar supports they may prevent cascade failure under short-circuit conditions.
Moreover, they can withstand far more severe seismic activity than their ceramic
counterparts. When used on isolator switches, however, any deflection may adversely
affect proper mating of the current-carrying contacts. Typical load/deflection curves, for
posts of length L, are shown in Figure 6.16. Should the possible movement at the top of
the post be unacceptable, a unit of higher strength rating or a more rigid hollow-core type
should be used.
450
L = 2000 mm
400
L = 1500 mm
350
300
Deflection (mm)
250
200
150
L = 1000 mm
100
50
L = 500 mm
0
0 1 2 3 4 5 6 7 8 9 10
Cantilever Load (kN)
Figure 6.16: Typical load/deflection curves for a composite post of 64 mm core diameter.
If a composite post is to be used for the support of heavy apparatus, the possibility of
buckling should also be examined. The value of the maximum permissible compressive
force should be obtained from the supplier. Information on the specification and testing of
the compression loading capabilities on station posts will also be provided in the future
IEC Publication 62231 [17].
6.2.3.1 Short circuit loads
For three phase ac systems, the highest load will be realised with a single phase fault.
The resultant force, Fsc, per unit length of busbar, can be approximated by:
2
13.86 ⋅ Irms
Fsc = in N/m (6.21)
Dbus ⋅ 10 7
where,
Irms : the rms current, symmetrical wave, in amps

Dbus : the distance between the busbars, in metres.
It should be noted that a Cigre task force is presently examining the effects of loads
generated by short circuit currents. The work seeks to introduce a new concept – the
Equivalent Static Load (ESL) factor. It is intended that this factor be applied to the
calculated load to obtain an improved estimate of the actual forces involved.
Sample calculation
What is the maximum permissible distance between support post insulators rated at 4 kN
cantilever failing load on a tubular busbar run with a phase spacing of 2,5 metres and a
short circuit current of 20 kA? The required factor of safety under fault conditions is 1,5.
The maximum distance, Sbus, is equal to the permissible load that can be applied to an
individual post, Fp, divided by the short circuit force per metre of busbar length, thus:
Sbus = Fp / Fsc
= 4000 x 2.5 x 107

1.5 13.86 x 200002
= 12 metres
6.2.3.2 Seismic loads
Where substations are situated in areas subject to earthquake activity, the resistance of
the insulators to damage by such events should be checked. A simplified procedure for
the assessment of such resistance can be found in the Cigre publication Electra, No. 140
of February 1992 [18]. It is summarised here for convenience. In this approach, the
substation equipment is modelled by a single degree of freedom system and represented
by two factors, namely, the natural frequency, f, and the damping factor, q.
The natural frequency can be calculated from the following expression:
1 3 ⋅E ⋅I⋅ g 2
f= ⋅  in Hz (6.22)
2 ⋅ π  Wt ⋅ Hcg 3 
where,
E : Young’s modulus, typically 5 x 109 kg/m2 for porcelain

I : moment of inertia of the insulator,
=
π ⋅ D4
for solid core insulators and
(
π ⋅ D 4 − d4 ) for hollow insulators with an
64 64
outside core diameter of D and internal diameter of d
g : acceleration due to gravity, 9.807 m.s-2
Wt : total mass of the equipment
Hcg : height of the centre of gravity of the equipment.
The damping factor, q, for porcelain insulators or structures composed of insulators and
steelwork can be assumed to be 0.03.
10
Damping Factor
Acceleration Magnification Factor, Samf
0.02
0.03
0.05
0.1
0.1 1 10 100
Natural Frequency (Hz)
Figure 6.17: Average response spectrum obtained from a number of recorded

earthquakes.
From the response spectrum chart provided in Figure 6.17, the acceleration magnification
factor, Samf, can be established. The bending moment, Me, which occurs at the bottom of
the insulator is then:
Me = Wt ⋅ S amf ⋅ Hcg ⋅ A 0 ⋅ B1 ⋅ B 2 (6.23)
where,
Samf : Acceleration magnification factor

Ao : The input acceleration on the ground surface specified for the area. If no value
is available, a figure of 0.3G TO 0.5G can be used depending on the local
seismic activity.
B1 : The foundation amplification factor. This can be taken as 1.2 for outdoor
equipment.
B2 : The acceleration magnification for the supporting frame. For a rigid frame that is
not unusually tall, this factor can be taken as 1.0.
The equivalent cantilever force, Fs, is:
Me
Fs = (6.24)
L ins
where Lins is the length of the insulator.

For an insulator of specified cantilever failing load, CFL, the factor of safety is:
CFL
FOS = (6.25)
Fs
If it is considered that the effect of the supporting frame is not negligible, its magnification
factor can be derived in the same manner as for the insulator, neglecting the existence of
the equipment on top. In this case, the damping factor should be taken as 0.02 for welded
structures and as 0.05 for bolted assemblies.
Sample calculation
(a) A station post 1.5 m in length, 127 mm core diameter, weighing 80 kg and of 4 kN
minimum cantilever failing load, supports a line trap 0.7 metres long and weighing 60 kg.
The input acceleration factor for the area is 0.4. What is the factor of safety in the event of
seismic activity?
With the centre of gravity of the 80 kg insulator being at 0.75 m above ground and that for
the 60 kg equipment being at 1.85 m above ground, the total mass of the system, W t, is
140 kg at a height, Hcg, of the centre of gravity of 1.22 metres.
The moment of inertia of the insulator, I, is:
I = π x 0.1274 = 1.277 x 10-5 m4

64
From Equation 6.22, the natural frequency, f, is:
f = (1 / 2π) x [( 3 x 5 x 109 x 1.277 x 10-5 x 9.807 ) / (140 x 1.223)]0.5
= 13.7 Hz
From Figure 6.17, at a damping factor of 0.03, the acceleration magnification factor, Samf,
is 3.6.
From Equation 6.23, the bending moment, Me, is thus:
Me = 140 x 3.6 x 1.22 x 0.4 x 1.2 x 1.0 = 295 kg.m
From Equation 6.24, the cantilever force, Fs, is:
Fs = (295 / 1.5) x 9.807 = 1929 N
and, the factor of safety,
FOS = 4000 / 1929 = 2.1
(b) Calculate the factor of safety of the insulator if it is mounted on a tubular steel support
of 300 mm outside diameter, 290 mm inside diameter and 2 metres high. The mass of the
support is 120 kg and the modulus of elasticity for steel is 2 x 1010 kg/m2.
The moment of inertia of the support, I, is:
I = π x (0.34 – 0.294) = 5.042 x 10-5 m4

64
From Equation 6.22, the natural frequency, f, is:
f = (1 / 2π) x [( 3 x 2 x 1010 x 5.042 x 10-5 x 9.807 ) / (120 x 23)]0.5
= 28 Hz
From Figure 6.17, at a damping factor of 0.02, the acceleration magnification factor, Samf,
is 1.6.
The bending moment on the insulator, Me, is thus:
Me = 140 x 3.6 x 1.22 x 0.4 x 1.2 x 1.6 = 472 kg.m
The cantilever force, Fs, is:
Fs = (472 / 1.5) x 9.807 = 3086 N
and, the factor of safety,
FOS = 4000 / 3086 = 1.3.

Failure Mechanisms 93
7 FAILURE MECHANISMS
“The major difference between a thing that might go wrong and a thing that cannot possibly go
wrong is that when a thing that cannot possibly go wrong goes wrong, it usually turns out to be
impossible to get at and repair” – Douglas Adams
Introduction
Knowledge and understanding of the various failure mechanisms specific to the different
types of insulators is required, not only to facilitate the proper selection of insulators, but
also to correctly programme the maintenance procedure and to select the optimum
inspection techniques.
The modes of failure described in this chapter lead first to the degradation of one or more
properties of the material that may not significantly disturb the function of the insulator. If
service conditions let the mechanism affect the insulator over long periods of time, the
resulting damage will significantly decrease the material performance and may eventually
lead to the failure of the insulator. Failures that can be attributed to damage incurred
during storage, transportation and construction are dealt with in Chapter 10.
Each type of insulator has its specific failure mechanisms. These mechanisms are related
mainly to the materials used for the manufacture of the insulator and also to its design.
Only the main mechanisms will be described in this chapter.
It is worth noting that the way an insulator fails may have very different consequences for
the user. A punctured porcelain or a shattered toughened glass cap-and-pin unit in a
string of three or more insulators does not require to be changed immediately. However,
the mechanical or physical separation of an insulator is likely to drop the conductor and
therefore requires the immediate intervention of the line operator.
It is important to note that although numerous causes of failure are described in this
chapter, insulators are a highly reliable component of electrical networks. Statistics
indicate that whether the insulators are of the glass, ceramic or composite type, a failure
rate of about 1 in 10 000 per annum can be expected. It must be appreciated that the
failure rate of a group of insulators is not only dependent on the quality of their design and
manufacture but also on the ability of the utility to select the correct type for the given
application and service conditions.
7.1 Glass Insulators
Shattering of the glass shell is the dominant failure mechanism for toughened glass
insulators. There are several causes of the shattering - some lie in the bulk of the glass
dielectric whilst others are associated with external agents affecting the shell.
An inclusion left in the glass, not weeded out by the thermal shock tests at the end of the
shell manufacturing process, can cause an insulator to spontaneously shatter. The typical
rate of occurrence is 1 per 10 000 per year. These inclusions originate from impurities in
the raw materials and have escaped removal or from particles that have been leached out
from the wall of the glass furnace. A steep-fronted electrical impulse might puncture the
dielectric although toughened glass insulator manufacturers claim that this cannot
happen.
A second shattering mode associated with the volume properties of the glass dielectric
may be present if the electric stress leads to the thermal run-away of the glass shell.
Practically, this can only happen with insulators used on HVDC lines. The resistivity of
glass decreases when its temperature increases. Under high DC electrical stress, the
shell’s internal electric field is further increased by ionic accumulation due to the ionic
current through the dielectric. The current increases the temperature of the dielectric,
thereby decreasing its resistivity. This allows the current to further increase, finally
leading to thermal runaway and failure of the toughened shell. The process is aggravated
by high ambient temperature. Ionic migration can be decreased sufficiently to avoid
thermal run-away by increasing the resistivity of the glass formulation. If inclusions exist
in the material then the localised accumulation and depletion of ions can create internal
mechanical stresses sufficient to cause shattering of the insulator. Special glass is
therefore used for HVDC applications.
Failure of the glass shell can also be precipitated by localized erosion of the dielectric
surface. Such erosion, usually confined to severely polluted environments, is caused by
electrical discharge activity across dry bands. Being the region of highest leakage current
density, this typically occurs in the vicinity of the pin.
Figure 7.1: Leakage current erosion of a glass disc.
Glass shells can be destroyed by acts of vandalism. The inherent internal mechanical
stress of toughened glass significantly increases its strength but results in violent
shattering when broken. They thus represent a most attractive and satisfying target.
Figure 7.2: Shattering of glass discs by shooting.

It should be noted that breakage of cap-and-pin toughened glass insulators does not
affect their mechanical strength, although the insulator no longer has any electrical
strength. Mechanical separation can, however, be caused by a power arc through a
shattered insulator stub.
Mechanical failure can originate from corrosion of the pin that eventually breaks because
of the resulting excessive stress. Pin corrosion occurs in highly polluted environments
because of dry band arcing around the pin. Metal fitting corrosion may be reduced by the
addition of sacrificial zinc rings or sleeves around the pin and /or the cap.
Figure 7.3: Pin erosion and corrosion from dry band arcing.
Finally, failure can be caused by previous damage incurred during handling and
transportation.
7.2 Porcelain Insulators
For porcelain insulators of the Class B type, a potential mechanism of failure is that of
electrical puncture by a steep-fronted lightning impulse. If the overvoltage increases at a
sufficiently rapid rate, the dielectric strength of the solid insulating material may be
exceeded before the surrounding air has had time to ionise and flashover. For pin
insulators and single disc strings, the subsequent breakdown of the puncture channel may
be intermittent, resulting in nuisance tripping, the cause of which may be difficult to locate.
Where one disc in a string of several units is punctured, no problems may be encountered
as the remaining undamaged insulators are adequate to accommodate the line voltage.
However, should the string flash over for some other reason, e.g. pollution, there is a real
danger that the power arc will pass through the head of the punctured disc, splitting the
cap and causing the conductor to drop.
The electrical strength of porcelain insulators can also be lost by the cracking of the body,
owing to, for example, rough handling or vandalism. For insulators with internally
cemented fittings, cracking can also be precipitated by swelling of the cement, corrosion
of the metal or the application of excessive force during installation. Insulators with
externally cemented caps are not prone to such failures and are thus preferred.
Figure 7.4: Electrically punctured porcelain disc with the cap removed.
A second mode of failure is that of cracking or breakage by thermal stress. Although fired
at a very high temperature, the ceramic materials are susceptible to damage by rapid
thermal changes and uneven heating. Power arcs can cause damage to glazed surfaces
and shed breakage. For porcelain long rods, there is a possibility that the heat of an arc
may crack the shank and precipitate complete mechanical failure. For this reason, it is
important that such insulators are equipped with arc protection devices.
For apparatus that may operate at high temperatures, it must be appreciated that the
dielectric strength of porcelain is reduced when heated. Where significant thermal
elevation is expected, therefore, a ceramic of suitable composition must be used.
In the design of overhead lines utilising porcelain line posts, the possibility of the cascade
failure of many insulators owing to a mechanical impulse load due to, say, the breakage of
the conductor, must be considered. Because of the rigid, brittle nature of the ceramic
material, bendable or collapsible bases are sometimes used to limit the extent of the
damage.
Figure 7.5: Cascade failure of porcelain line posts on a medium voltage line.
As for their glass counterparts, the erosion and ultimate mechanical failure of the pins of
porcelain disc insulators, owing to dry band arcing experienced in severely polluted areas
can cause dropping of the line.
With regard to metal fitting attachment, portland and alumina cements have been widely
used for many years. Apart from swelling problems on some disc insulators, their
reliability is well proven. The experience with sulphur cement is not as good as it can be
removed by melting or burning under the action of electrical discharges and arcs. Lead
antimony is often used for long rod insulators and has displayed excellent performance. It
is critical, however, that the composition of the material is suited to the ambient conditions
to be expected in service. Line drops caused by creep of the alloy and ultimate release of
the insulator caps have been experienced in warmer climates for which the material was
not properly formulated.
Courtesy of Eskom
Figure 7.6: Loss of a long rod cap owing to creep of the lead antimony cement.
7.3 Composite Insulators
The failure of composite insulators can be caused by problems with the insulator housing,
the core, the housing-to-core interface and, occasionally the end fittings. The failure
mechanisms are influenced by the service conditions under which an insulator operates,
and by the design and materials used for the manufacture.
7.3.1 Housing
As the housing has no mechanical function, its failure affects primarily the electrical
performance of the insulator. Nevertheless, housing damage may lead to mechanical
failure of the core before it produces electrical failure of the insulator. The simultaneous
application of the voltage and the environmental stresses on the surface of the housing
may generate electrical discharges which can produce erosion, and on some early
formulations of housing materials, tracking. A tracked path reduces the creepage
distance of the insulator and, if long enough, leads to flashover. Erosion may be severe
enough to puncture sheds, thereby shortening the creepage distance or exposing the
core. Tracking and erosion are material specific. The presence of a mould line situated in
a plane containing the insulator axis may be a preferential erosion site unless the design
and manufacturing method are such that they prevent the problem.
Courtesy of Eskom
Figure 7.7: Erosion of EPDM and silicone rubber housings.
Figure 7.8: Tracking concentrated at the mould line on an EPDM insulator.
Figure 7.9 Punctured EPDM shed.
Tracking and erosion may be aggravated if the housing material is affected by solar
ultraviolet (UV) radiation. This is not the case for silicone housing materials and other
recently developed material formulations that now contain UV stabilizers that make them
less sensitive. When exposed to solar UV radiation, a white powder will appear on the
surface of most filled housing materials, except those that are silicone based. This
powder is the mineral filler left on the surface after the degradation of the polymer
molecules. This has only a small effect on the performance of the housing material.
Formulations not sufficiently UV stabilized, as was the case for early housing materials,
may exhibit significant chalking or even be subjected to crazing or cracking. Crazing or
cracking can be a catalyst for surface electrical discharges that can lead to erosion and,
on early formulations, possibly tracking.
(a) (b)
Figure 7.10: Chalking of EPDM shed material caused by leakage current activity (a) and
ultraviolet radiation (b).
Salt crystal
(for scaling purposes)
Figure 7. 11: Crazing or cracking.
Figure 7.12: Erosion (alligatoring) due to UV, weathering and electrical activity.
Some early housing formulations (epoxies) were adversely affected by hydrolysis, i.e.
their characteristics changed in the presence of water and water vapour.
Courtesy of J Frate
Figure 7.13: Hydrolysis of epoxy housing material.
The characteristics of some ethylene propylene monomer (EPM) and ethylene propylene
diene monomer (EPDM) housing formulations are sensitive to a combination of
mechanical hoop stress, ultraviolet radiation and electrical stresses, resulting in the
splitting of the sheds with time.
Figure 7.14: Splitting of sheds owing to radial mechanical stress.
The housings of composite insulators may be made of individual sheds or of one or more
groups of sheds moulded separately and subsequently put over the core without being
bonded to it. The interface between the core and the housing of such insulators is filled
with silicone grease. With time, this grease may leak out and collect pollution without
causing failure of the insulator. However, the sheds may also move and expose the core,
which could precipitate more serious problems.
Figure 7.15: Exposure of core owing to shed movement.
Housing material may be lost, not only as a result of erosion caused by electrical surface
discharges, but also by physical removal by animals such as birds, rodents and even
termites. Rodents and termites can damage the housing of composite insulators during
storage. Birds have been known to peck on the housings of insulators installed on lines
that were not energized or energized at half the design-rated voltage. Animal damage to
the housing is not a matter of concern as long as it only involves a relatively small number
of sheds, each missing only a few cubic millimetres of material. However, if the damage
is on the shank part of the housing and reaches, or is close to reaching, the core, the
insulator should be discarded.
(a) (b) (c)
Figure 7.16: Shed damage caused by birds (a), rodents (b) and termites (c).
7.3.2 Core
The cores of composite long rod, post insulators and the tube of hollow insulators are
made of glass fibres embedded in a resin matrix.
Degradation of the core of long rod insulators by electrical discharges may lead to their
mechanical failure and therefore to separation. Should the core be exposed because of a
damaged housing, electrical discharges will occur and lead to tracking and erosion of the
surface of the core. If the erosion consumes a sufficient amount of the cross section of
the core, the increased stress in the remaining part will exceed its mechanical strength
and separation will occur.
Should a long rod insulator be subjected to torsion or cantilever load, delamination

(destruction of the bond between the fibres and the resin matrix) of the core will occur,
usually without separation. Depending on the stress level, the delamination can be
localized or go from one end fitting to the other.
Figure 7.17: Electrical failure of a core owing to splitting during line construction.
The failure of the core of line post or station post insulators is usually caused by
exceeding its bending strength. The first evidence of failure is found inside the core, just
at the mouth of the end fitting where the compression stress is highest. It is first the shear
capability of the core that is exceeded. Further stressing causes delamination of the core.
(a) (b)
Figure 7.18: Initial (a) and subsequent (b) damage of a line post core subjected to
excessive bending load.
The tube of a hollow core insulator is subjected to mechanical stresses that are either
caused by an external load or by an internal pressure. Filament wound tubes fail by
delamination if the stress has exceeded the damage limit of the material. If the tube is
under internal pressure, the delaminated zone will allow the pressurised gas or liquid to
escape.
For long rod insulators, the type, magnitude and distribution of the mechanical stresses in
the core between the end fittings is determined by the type and magnitude of the applied
load. The part of the core that is inside the end fittings is subjected to additional stresses
caused by the design and method of attachment of the end fittings. The presence of
these additional stresses explains why failure of the core usually occurs in the vicinity of
the edge of the end fittings.
There is one mechanical failure mode that can occur at loads that are well below the
damage limit level. This type of failure has been called brittle fracture but should better be
named stress corrosion fracture. It occurs when the rod is subjected to an acid and a
tensile force simultaneously. It has happened mainly to tension insulators but has been
recorded on some units in suspension positions as well. Only a few rare cases have been
reported for line post insulators. All the cores that have failed by brittle fracture have been
manufactured using E-type glass fibres. In service, at least part of the core of all such
insulators is subjected to tensile stresses, and if an acid solution is also present, then the
core may fail by brittle fracture. Much speculation as to the origin of the acid can be found
in the literature [19]. One possible external source of acid is acid rain. This implies a
breach in the housing. Another possibility, also requiring housing or seal damage, is the
generation of nitric acid on an exposed part of the core by electrical discharges in moist
air. A different and more recent scenario [20] states that the acid is generated by
moisture reaching a core that has not been correctly cured or whose formulation has
deviated from the required one. In both these cases, hydrolysis of the core matrix creates
an acid that leads, in the presence of a tensile stress, to brittle fracture. Such acids have
been identified on the fracture surface of insulator cores made of epoxy resins that have
failed in a brittle way. It is yet to be proved that this latest theory is the main cause of
brittle fracture.
The appearance of a core that has failed by brittle fracture is characterised by a smooth
and clean fracture surface, perpendicular to the core axis, extending over most of the
cross section. The remaining area, broken in an irregular fashion, represents that part of
the core that could no longer support the applied load and failed in a conventional tensile
mode.
Figure 7.19: Typical fracture of a core by the stress corrosion (brittle fracture) mechanism.
Care must be taken not to confuse brittle fractures with other causes of failure which, at
first sight, may have similar appearance. Assistance with the identification of a brittle
fracture is provided in [21].
All the processes presented thus far to explain brittle fractures require the presence of
water or moisture on the core. It is therefore evident that the first step necessary to
prevent brittle fracture is perfect sealing of the core from the environment.
The first brittle fractures occurred in the 1970’s. Some years later it was established that
cores made with E-CR (corrosion resistant) glass fibres were much less sensitive to acid
attack. Over the last 20 years many insulators have been made with E-CR glass fibre
cores and no failures by brittle fracture have been experienced to date.
7.3.3 Housing to core interface
One of the functions of the housing is to protect the core from the influences of the
environment. In most insulator designs the housing is chemically bonded to the core. A
faulty bond will let electrical discharges occur at the interface. This will lead to tracking of
the core surface and possibly erosion of both the housing and the core. Should the
tracked path extend over a significant part of the core length, this will result in insulator
flashover with local punctures of the housing. Erosion of the housing may happen faster
than the progression of tracking and expose the core to the environment. This will
exacerbate the erosion of the core which may lead to its mechanical failure.
(a) (b)
Figure 7.20: Internal breakdown and fracture of the housing (a) and puncture (b) caused
by tracking up the core/housing interface.
7.3.4 Housing to end fitting interface
Sealing the interface between the housing and the end fitting is critical because moisture
ingress to the core at a location where both the mechanical stress and electrical stress
reach maximum values must be prevented. Electrical discharges in that interface will
erode the housing material and may promote tracking on the rod. Provided other
necessary conditions are fulfilled, ingress of water to the core could lead to its failure by
brittle fracture.
Figure 7. 21: Housing to end fitting interface failure due to erosion.
7.3.5 End fitting
End fittings can be damaged by electric power arcs. Such arcs do not cause significant
damage to the insulator housing but, if not correctly designed or fitted with arc protection
devices, they can melt or evaporate away enough metal that the end fitting can no longer
hold the insulator core. If the damage is severe, separation occurs during or very shortly
after the occurrence of the arc. Aluminium alloy fittings are particularly vulnerable to this
mode of failure. Failure can also happen a few moments later if the heat, generated by
the current passing through the end fitting, is sufficient to soften the core.
Figure 7.22: End fitting damage from power arc.

7.4 Resin Insulators
Epoxy resin insulators are susceptible to chalking by UV solar radiation. The consequent
degradation of the surface adversely affects the performance in polluted environments.
The power frequency wet flashover voltage may also be reduced by as much as 20% [22].
(a) (b)
Figure 7.23: New (a) and naturally aged (b) cycloaliphatic insulators showing chalking
from ultraviolet radiation.
The surface of mineral-filled cycloalyphatic or other resin insulators may track and erode
when subjected for long periods of time to electrical discharges. This can lead to
flashover and failure of the insulator.
Figure 7.24: Erosion of resin insulator surface.
Metal hardware can be embedded in the insulator body during manufacture. It is,
however, difficult to prevent internal mechanical stresses around these fittings. Thermal
cycling during service can cause cracks near these fittings, creating preferential sites for
electrical discharges.
Figure 7.25: Electrical failure due to cracks in the resin at the metal insert.
Resin insulators of the Class B type, e.g. pin insulators, are susceptible to electrical
puncture by steep-fronted lightning impulses.
Figure 7.26: Electrical puncture of a resin pin insulator.
Figure 7.27: Puncture of cycloaliphatic insulators due to steep fronted impulses and the
presence of internal voids.
Tests and Specifications 108
8 TESTS AND SPECIFICATIONS
“Measure what is measurable, and make measurable what is not so” – Galileo Galilei
Introduction
Over the years, many standards, specifications and reports have been compiled to ensure
that the insulators selected by engineers will render the intended service. These
documents contain test descriptions, recommendations and data that allow the users and
the manufacturers to communicate, specify, test, purchase and use insulators. Many
organizations and countries have developed their own standards. This chapter lists the
publications that have been issued by Technical Committee TC 36, “Insulators”, of the
International Electrotechnical Commission (IEC). The IEC mainly issues standards and,
when the subject matter is not yet ripe for a standard, also publishes technical reports and
specifications. IEC publications are revised periodically and re-issued with or without
changes, or they are withdrawn.
Most of the tests listed serve to confirm that the insulators conform to certain standard
quality levels, characteristics and dimensional requirements. Other tests, such as those
described in IEC 60507, are intended to assess the expected in-service performance or
life of the insulators. It must be appreciated that these evaluations are performed under
laboratory conditions which are not always representative of the operating environment. It
may be more meaningful to evaluate the performance under natural conditions in an
outdoor pollution test station [2, 23, 24]. However, these tests take a longer time and, as
yet, there are no internationally recognised test procedures.
8.1 Porcelain and Glass Insulators
Table 8.1 and Table 8.2 list all the IEC Publications that deal with porcelain and glass
insulators for outdoor use. The tables also indicate whether the publications relate to
testing of insulators or to their application.
The tests for porcelain and glass insulators are divided into three categories: type, sample
and routine tests. The type tests are meant to ensure that the characteristics of the
insulator can meet the service requirements that are part of the purchase specification.
The sample tests are required by the user to confirm that the characteristics of the
manufactured insulators are the same as those of the insulator that had passed the type
tests. The routine tests are performed on every insulator manufactured to verify the
uniformity and quality of production. Table 8.3 lists some of the tests described in IEC
60383 for porcelain and glass insulators.
Table 8.1: IEC standards for porcelain and glass insulators.

Line Substation
Cap-and- Long Line
IEC Standard pin rod Post
Post Apparat.
Application
Application
Application
Application
Application
Testing
Testing
Testing
Testing
Testing
60120 - Dimensions of ball and socket couplings of
string insulator units
X X X
60137 - Insulating bushings for alternating voltages
above 1000 V
X X
60168 - Tests on indoor and outdoor post
insulators of ceramic material or glass for systems X
with nominal voltages greater than 1000 V
60233 - Tests on hollow insulators for use in
electrical equipment
X
60273 - Characteristic of indoor and outdoor post
insulators for systems with nominal voltages X
greater than 1000 V
60305 - Insulators for overhead lines with a
nominal voltage above 1000 V - Ceramic or glass
insulator units for a.c. systems - Characteristics of
X
insulator units of the cap and pin type
60372 - Locking devices for ball and socket
couplings of string insulator units - Dimensions and X X X
tests
60383-1 and 2 - Insulators for overhead lines with
a nominal voltage above 1000 V - Part 1: Ceramic
or glass insulator units for a.c. systems -
Definitions, test methods and acceptance criteria X X X
Part 2: Insulator strings and insulator sets for a.c.
systems - Definitions, test methods and
acceptance criteria
nominal voltage above 1 000 V - Ceramic
insulators for a.c. systems - Characteristics of
X
insulator units of the long rod type
60437 - Radio interference test on high-voltage
insulators
X X X X
60471 - Dimensions of clevis and tongue couplings
of string insulator units
X X
60507 - Artificial pollution tests on high-voltage
insulators to be used on a.c. systems
X X X X X
60720 - Characteristics of line post insulators X
62155 – Hollow pressurised and un-pressurised
ceramic and glass insulators for use in electrical X
equipment with rated voltages greater than 1000V
61264 - Ceramic pressurized hollow insulators for
high-voltage switchgear and control gear
X X
nominal voltage above 1000 V - Ceramic or glass
insulator units for d.c. systems - Definitions, test
X X
methods and acceptance criteria
Table 8.2: IEC reports and specifications for porcelain and glass insulators.
Line Substation
Apparatus
Line Post
Cap-and-
Long rod
Post
pin
IEC Report/Specification
Application
Application
Application
Application
Application
Testing
Testing
Testing
Testing
Testing
60438 - Tests and dimensions for high-voltage
d.c. insulators
X X X X
60575 - Thermal-mechanical performance test

and mechanical performance test on string X X
insulator units
60797 - Residual strength of string insulator units

of glass or ceramic material for overhead lines X
after mechanical damage of the dielectric
60815 - Guide for the selection of insulators in

respect of polluted conditions
X X X X X
TR2 61211 - Insulators of ceramic material or

glass for overhead lines with a nominal voltage X X
greater than 1000 V - Puncture testing
61245 - Artificial pollution tests on high-voltage

insulators to be used on d.c. systems
X X X X X
61463 - Bushings - Seismic qualification X
61464 - Insulated bushings - Guide for the

interpretation of dissolved gas analysis (DGA) in
bushings where oil is the impregating medium of
X
the main insulation (generally paper)

nominal voltage above 1000 V - A.C. power arc X X
tests on insulator sets
Table 8.3: Tests for string insulator units (based on IEC 60383).
Long Rod (Class A)

Cap-and-Pin Disc
Line Post
(Class B)
(Class A)
(Class B)
Pin
IEC 60383 Tests
Material: Porcelain – P
Annealed Glass – AG P TG P P AG TG P AG TG
Toughened Glass - TG
Verification of the dimensions X X X X X X X X X
Dry lightning impulse withstand test X X X X X X X X X

Type tests
Wet power frequency withstand test X X X X X X X X X
Electro-mechanical failing load test X
Mechanical failing load test X X X X X X X X
Thermo-mechanical performance test X X X
Verification of the dimensions X X X X X X X X X
Verification of the displacements X X X

1 1 1
Verification of the locking system X X X
Sample tests
Temperature cycle test X X X X X X
Electro-mechanical failing load test X
Mechanical failing load test X X X X X X X X
Thermal shock test X X X
Puncture withstand test X X X X X
Porosity test X X X X
1 1 1 1 1 1
Galvanizing test X X X X X X X X X
Routine tests
Visual inspection X X X X X X X X X
2 2 2
Mechanical test X X X X X X
Electrical test X X X
Note 1 : Where applicable.

Note 2 : Where insulator length is greater than 600 mm.
8.2 Composite Insulators
Table 8.4 lists all the IEC publications that deal with composite insulators for outdoor use.
The tables indicate if the publication relates to testing of insulators or is relevant to their
application.
Table 8.4: IEC standards and reports for composite insulators.
Line Substation
Apparatus
Long rod
Post
Post
IEC Report/Specification
Application
Application
Application
Application
Testing
Testing
Testing
Testing
IEC 61109 * - Composite insulators for a.c.
overhead lines with a nominal voltage greater
than 1000 V - Definitions, test methods and
X
acceptance criteria
61462/TR2 - Composite insulators - Hollow
insulators for use in outdoor and indoor
electrical equipment - Definitions, test methods, X
acceptance criteria and design
recommendations
61466-1 and 2- Composite string insulator
units for overhead lines with a nominal voltage
greater than 1000 V
Part 1: Standard strength classes and end X
fittings
Part 2: Dimensional and electrical
characteristics
61952 - Composite line post insulator for a.c.
overhead lines with a nominal voltage greater
than 1 000 V – Definitions, tests methods and
X
acceptance criteria
62073 ** - Guide to the measurement of

wettability of insulator surfaces
X X X X
62217 ** - Polymeric insulators for indoor and

outdoor use with nominal voltages greater than
1000 V – General definitions, test methods and
X X X X
acceptance criteria
62231 ** - Composite station post insulators for

substations with a.c. voltages greater than
1000 V up to 245 kV - Definitions, test methods
X
and acceptance criteria
* under revision ** in preparation
The tests for composite insulators are divided into four categories: design, type, sample
and routine. As different types of composite insulators can be made with the same
design, for example, with the same housing material and geometry, the testing standards
for these insulators include a further category, namely, design tests. Table 8.5 indicates
in which IEC standard, and clause if relevant, the tests for the different composite
insulators can be found. This table will, however, only be fully applicable when the new
IEC 62217 and 62231 are issued and IEC 61109, 61462 and 61952 have been revised.
Until the first two have been issued, only the publications relevant to the specific insulators
can be used (IEC 62217 and 62231 are close to publication and the revision of IEC
61109, 61462 and 61952 has commenced).
Table 8.5: Tests for composite insulators used for lines or substations as found in IEC
62217**, 61109*, 61952* and 62231**.
IEC Publication (Clause)
IEC Tests Line Substation
Long rod Post Post
Interfaces, connections of metal fittings 62217 62217 62217
Shed and housing material 62217 (9.3) 62217 (9.3) 62217 (9.3)
Hardness (9.3.1) (9.3.1) (9.3.1)
Design Tests
Accelerated weathering (9.3.2) (9.3.2) (9.3.2)

Tracking and erosion (9.3.3) (9.3.3) (9.3.3)
Flammability (9.3.4) (9.3.4) (9.3.4)
Core material 62217 62217 62217
Dye penetration (9.4.1) (9.4.1) (9.4.1)
Water diffusion (9.4.2) (9.4.2) (9.4.2)
Assembled core load tests 61109 (5.2) 61952 (6.3) 62231 (6.3)
Tests
Type
61109 61952 62231

Sample
Tests
61109 61952 62231

Routine
Tests
61109 61952 62231
* under revision, ** in preparation

Insulator Selection and Specification 114
9 INSULATOR SELECTION AND SPECIFICATION
“The joy of engineering is to find a straight line on a double logarithmic diagram” – Thomas Koenig
Introduction
The correct insulator to be used for a particular application is determined by the operating
voltage, the mechanical loads to be supported and the environmental influences, such as
lightning and pollution, to be accommodated. This chapter serves to assist in bringing
together the principles described in the previous chapters in order to facilitate the choice
and/or specification of the optimum insulation.
With particular reference to overhead lines, Figure 9.1 illustrates how the characteristics of
the application and the ambient conditions under which an insulator must operate affect
the various insulator design parameters. For more detailed information, the relationships
indicated are explained in the chapters noted on the diagram.
Figure 9.1: Insulator selection process.
9.1 Insulator Type and Material
The basic insulator types and materials and their suitability to the various applications and
conditions are shown in Table 9.1. Of those insulators that could be technically
acceptable, the preferred types are indicated and should be used whenever possible.
Table 9.1: Insulator application chart.
It is evident from the table that the basic type and material of the insulator is determined
by the operating voltage, the mechanical loading and the environment. Some additional
comments on the environmental aspects to be considered, as listed in columns 9 to 14 of
the table, are provided below.
9.1.1 Pollution type and severity
To properly define the insulation requirements, it is most important to establish the

pollution severity of the site. Lack of consideration of this aspect or vague assumptions
may have a serious impact on system reliability. By using the assessment techniques
described in Chapter 4, the pollution type and class can be defined.
For environments of Pollution Class III and IV, disc strings may be used but the shed
shape and total creepage distance must be adequate to suppress partial discharges
which can precipitate accelerated pin corrosion. Similarly, porcelain and EPR (such as
EPDM, ESP etc) rubber units are acceptable if sufficient creepage distance is provided.
Because of the danger of rapid ageing and surface erosion, however, resin materials are
not recommended. For the most severe areas, silicone rubber posts and long rods of at
least 31 mm/kV specific creepage distance may be the only solution for the prevention of
flashover without the need for regular maintenance. Moreover, if the contamination is of
the instantaneous type, the hydrophobicity of the silicone materials is vital to prevent
breakdown.
9.1.2 Lightning severity
In regions of high lightning activity, overvoltages exceeding the basic impulse level
specified for the insulators are likely to be experienced. In such cases, it is important that
the electrical breakdown takes place in the surrounding air and that no permanent
damage is sustained by the insulator itself.
Although much care is taken in their design, manufacture and testing, Class B insulators,
such as pins and discs, are susceptible to puncture by steep-fronted impulses. Once
damaged in this way, they can cause intermittent faults which are extremely difficult and
costly to locate. Where ceraunic levels are high, therefore, the use of Class A insulators,
such as long rods and line posts, is preferred.
9.1.3 Vandalism
Those sites subject to, or potentially subject to, vandalism need to be identified. In such
areas the use of glass discs should be avoided. Although toughened, they can be broken
by stone throwing, catapults, firearms, etc. Moreover, because of their inherent
mechanical pre-stress, they explode in spectacular fashion on fracture and thus represent
most satisfying targets.
The use of pin insulators is also not advised as cracks may be caused which lead to
electrical breakdown with similar tripping and fault location problems as for lightning
puncture.
Where malicious damage is anticipated, therefore, polymeric composite insulators should

be selected. These have a high impact resistance and, even if damaged, retain
considerable residual strength. Bullet damage which results in core exposure may,
however, cause ultimate long-term failure. The main advantage of composite insulators in
relation to vandalism is that the limited visual effect produced by an impact makes them
an unattractive target.
9.2 Insulator Characteristics
Once the basic insulator type and material have been selected then, based on the results
of the evaluations and calculations given in Chapters 3, 4, 5 and 6, the other
characteristics can be defined. In doing so, standardised values should be specified
wherever possible. These are described below.
9.2.1 Electrical characteristics
Table 9.2: Standard IEC required power frequency and impulse withstand values.
System Highest Power Frequency Lightning Impulse Switching Impulse
Voltage Withstand Voltage Withstand Voltage Withstand Voltage
Um (kV rms) (kV rms) BIL (kV peak) SIL (kV peak)
20 40
7,2 -
20 60
28 60
12 28 75 -
28 95
38 75
17.5 -
38 95
50 95
24 50 125 -
50 145
70 145
36 -
70 170
52 95 250 -
72.5 140 325 -

185 450
123 -
230 550
230 550
145 -
275 650
275 650
170 -
325 750
360 850
245 395 950 -
460 1050
850 750
300 - 950 750/850
1050 850
950 850
362 - 1050 850/950
1175 950
1050 850
1175 850/950
420 -
1300 950/1050
1425 1050
1175 950
1300 950/1050
525 -
1425 1050/1175
1550 1175
1675 1300
1800 1300/1425
765 -
1950 1425/1550
2100 1550
In accordance with the system highest voltage of the installation, the standard electrical
values of the insulator can be selected from Table 9.2. Where more than one impulse
withstand level is indicated for a particular system voltage, the choice of value should be
made by considering the degree of exposure to lightning and switching overvoltages, the
type of system neutral earthing and, where applicable, the type of overvoltage protective
device. Further information in this regard can be found in IEC Publications 60071-1 and
60071-2 [25]. In general, for overhead line insulation, the higher values should be
selected.
9.2.2 Mechanical characteristics
Having determined the required minimum failing load using the calculations described in
Chapter 6, the mechanical rating should be selected from the next highest standard IEC
value. These are provided for reference in Table 9.3.
Table 9.3: Standard IEC mechanical strength ratings.
TENSILE STRENGTH (kN) CANTILEVER STRENGTH (kN)
Cap-and-Pin Long Rod Long Rod Line Post Station Post

Disc (ceramic) (composite) (ceramic) (ceramic)
40 40 40 - 2
- 60 - - 4
70 70 70 - 6
100 100 100 8* 8
120 120 120 - 10
160 160 160 12,5 * 12,5
210 210 210 - 16
- 250 - - 20
300 300 300 - 25
400 400 400 - 31,5
530 530 530 - -

* Lower strengths may be more appropriate for medium voltage systems.
For such lines, values of 4kN and 10kN may be considered.
No international standard strength ratings currently exist for composite line- and station
posts. In most cases, it will be necessary to examine the mechanical capabilities of the
insulator in terms of its ability to accommodate more than one load simultaneously and
hence selection will be based on the examination of combined load curves provided by
the insulator supplier. Further, for station post insulators, the amount of deflection under
load may be more important than the failing load and this may dictate the strength rating
chosen.
9.2.3 Physical characteristics
9.2.3.1 Insulator length
The lengths of post insulators and the connecting lengths of string insulators are normally
determined by the arcing distance that needs to be provided to meet the specified
lightning or switching impulse withstand voltages. In isolated cases, where the ambient
pollution levels are very high, a longer length may be necessary to accommodate the
required creepage distance. A nominal, maximum or minimum connecting length, greater
than that dictated by the BIL or creepage requirements, may, however, be specified by the
user in the following cases:
• to ensure adequate clearances to the structure, to other objects, between phases or

between circuits
• for standardisation purposes to ensure insulator inter-changeability
• in line refurbishment projects to facilitate the direct replacement of existing strings
• to meet maintenance safety regulations, e.g. live-line working clearances.
Table 9.4: Standard IEC insulator lengths.
LINE POST INSULATOR STATION POST

LENGTH (mm) INSULATOR LENGTH (mm)
BIL (kV)
Tie-Top Clamp-Top, Clamp-Top, Outdoor
Type Vertical Horizontal Type
60 - - - 190
75 190 235 255 215
95 222 270 290 255
125 305 350 370 305
150 - - - 355
170 370 420 440 455
200 430 495 515 475
250 510 570 590 560
325 660 710 730 770
450 - - - 1020
550 - - - 1220
650 - - - 1500
750 - - - 1700
Connecting lengths for composite long rods are not specified by the IEC. For ceramic
units, IEC 60433 [26] lists standard types each with a minimum length between metal
parts and a maximum connecting length. The standard coupling lengths or spacings for
cap-and-pin disc insulators are provided in IEC 60305 [13].
International standard lengths for composite line- and station posts have not yet been
stipulated. For ceramic units, these are provided in IEC 60720 [27] and IEC 60273 [28]
respectively. For the sub-transmission voltages only, these are summarised in Table 9.4.
9.2.3.2 Creepage distance
The minimum creepage distance to be provided should be that calculated using the
methods described in Chapter 3. Many utilities standardise on one or more of the values
of specific creepage distance given in IEC 60815 [29], namely, 16, 20, 25 and
31mm/kV(Um).
In addition to the creepage distance, other details of the shed geometry may be specified.
For example, in areas of pre-deposited type contamination, a smooth aerodynamic shed,
free of underside ridges and grooves, may be preferred. To avoid sheds which are too
closely spaced, a minimum shed clearance or shed spacing-to-projection ratio is often
called for. The influence of these parameters is described in Chapter 3.
9.2.3.3 End fittings
String insulator units, such as discs and long rods, are normally provided with either ball
and socket or clevis and tongue end fittings. The detailed dimensions of these are given
in IEC 60120 [30] and IEC 60471 [31] respectively. In addition to these, Y-clevis and eye
connections are sometimes used on composite long rod insulators. The choice of type
may be influenced by:
• the availability or standardisation of the associated string hardware fittings
• the minimisation of hardware fittings required in the string, particularly where

clearances are limited
• the need to maintain full cardanic mobility of the string to prevent the application of
bending loads to long rod insulator types
• to match existing hardware when undertaking insulator replacements
• for ease of maintenance, in particular live-line working.
The size of the fitting used is dictated by the strength rating of the insulator. The standard
sizes are listed, for reference, in Table 9.5.
The end fittings for composite line post insulators are not yet internationally standardised.
For ceramic line posts, however, base mounting thread sizes and tie-top and clamp-top
dimensions are specified in IEC 60720 [27].
Table 9.5: Standard IEC end fitting sizes for string insulator units.
STRENGTH CAP-AND-PIN DISC CERAMIC LONG ROD COMPOSITE LONG ROD

RATING (kN) INSULATORS INSULATORS INSULATORS
(EMFL, Ball and Clevis and Ball and Clevis and Ball and Clevis and
MFL, Socket Tongue Socket Tongue Socket Tongue
SML) IEC 60120 IEC 60471 IEC 60120 IEC 60471 IEC 60120 IEC 60471
40 11 - 11 - 11 -
60 - - 11 13L - -
70 16 16C 16 - 16 13L
100 16 16C 16 19L 16 16L
120 16 16C 16 19L 16 16L
160 20 19C 20 19L 20 19L
210 20 22C 20 22L 20 22L
250 - - - 22L - -
300 24 - 24 25L 24 25L
400 28 - 28 28L 28 28L
530 32 - 32 32L 32 32L
Standard fixing arrangements for ceramic station post insulators are specified in IEC
60273 [28]. Those for the common outdoor post types, for sub-transmission voltages
only, are summarised for information in Table 9.6. It will be noted that, as posts are
mainly loaded in cantilever, the cap and base sizes are related to both the strength and
the length (as dictated by the BIL) of the insulator.
Table 9.6: Standard IEC end fittings for outdoor station post insulators.
CANTILEVER CAP BASE

BIL
STRENGTH
(kV) Pitch Circle No. of Holes & Pitch Circle No. of Holes &
(kN)
Diameter (mm) Diameter (mm) Diameter (mm) Diameter (mm)
60 4 - 10 76 4, tapped M12 76 4, tapped M12
75 4 - 10 76 4, tapped M12 76 4, tapped M12
95 4 - 12,5 76 4, tapped M12 76 4, tapped M12
125 4 - 12,5 76 4, tapped M12 76 4, tapped M12
150 4 - 12,5 76 4, tapped M12 76 4, tapped M12
170 4 - 10 76 4, tapped M12 76 4, tapped M12

12,5 127 4, tapped M16 127 4, tapped M16
200 4 - 10 76 4, tapped M12 76 4, tapped M12

12,5 127 4, tapped M16 127 4, tapped M16
250 4-6 76 or 127 4, M12 or M16 76 or 127 4, M12 or M16

8 - 12,5 127 4, tapped M16 127 4, tapped M16
2 - 12,5 127 4, tapped M16 127 4, tapped M16
325 16 127 4, tapped M16 225 4 x 18mm
20 127 4, tapped M16 254 8 x 18mm
2 127 4, tapped M16 127 4, tapped M16
4-6 127 4, tapped M16 127 or 178 4, M16 or 18mm
450 8 127 4, tapped M16 127 or 200 4, M16 or 18mm
10 127 4, tapped M16 127 or 225 4, M16 or 18mm
12,5 127 4, tapped M16 225 4 x 18mm
16 - 20 127 4, tapped M16 254 8 x 18mm
2 127 4, tapped M16 127 4, tapped M16
4 127 4, tapped M16 127 or 178 4, M16 or 18mm
550 6-8 127 4, tapped M16 127 or 200 4, M16 or 18mm
10 127 4, tapped M16 127 or 225 4, M16 or 18mm
12,5 - 16 127 4, tapped M16 254 8 x 18mm
20 127 4, tapped M16 275 8 x 18mm
2 127 4, tapped M16 127 or 178 4, M16 or 18mm
4-6 127 4, tapped M16 127 or 200 4, M16 or 18mm
650 8 127 or 225 4, M16 or 18mm 127 or 225 4, M16 or 18mm
10 - 12,5 127 or 225 4, M16 or 18mm 254 8 x 18mm
16 225 4 x 18mm 275 8 x 18mm
20 225 4 x 18mm 300 8 x 18mm
2 127 4, tapped M16 127 or 178 4, M16 or 18mm
4 127 4, tapped M16 127 or 200 4, M16 or 18mm
750 6-8 127 or 225 4, M16 or 18mm 127 or 225 4, M16 or 18mm
10 - 12,5 127 or 225 4, M16 or 18mm 254 8 x 18mm
16 225 or 254 4 or 8 x 18mm 275 8 x 18mm
20 225 or 254 4 or 8 x 18mm 300 8 x 18mm
9.3 Insulator Selection Flowchart
The process of selecting an insulator is summarised in the flowchart given in Figure 9.2
(located inside the back cover).
9.4 Insulator Specification
In many cases, the acquisition of insulators is undertaken on the basis of a tendering

process. It is thus necessary for the purchaser to provide a specification for the units
required. With reference to Chapters 3, 4, 5 and 6, which serve to determine the basic
characteristics demanded by the application, and the selection process and standard
values provided in this chapter, the drafting of a meaningful specification should be
possible.
To further assist, the parameters that should be defined in the enquiry document are listed
in Table 9.7. The IEC standards that can be nominated in the specification – in terms of
both the value of the characteristic and the testing thereof – are included. The details of
these standards are provided in Chapter 8. The main factors which influence the
parameters chosen are also provided.
The following abbreviations are used in the table to identify the different insulator types:
D = Disc Insulators
PLR = Porcelain Long Rods
CLR = Composite Long Rods
PLP = Porcelain Line Posts
CLP = Composite Line Posts
B&S = Ball and Socket Couplings
C&T = Clevis and Tongue Couplings
Table 9.7: Tender specification template – overhead line insulators.
INSULATOR INFLUENCED BOOK IEC SPECIFICATION

CHARACTERISTIC BY: REFERENCE VALUE TEST
Sec 2.3, 9.1

INSULATOR TYPE Line Design - -
Tab 9.1
Insulator Type
Ch 5, 7
INSULATOR Pollution Level/Type
Sec 9.1.1, 9.1.3 - -
MATERIAL Vandalism Level
Tab 9.1
Strength/Mass Ratio
PHYSICAL
PROPERTIES:
60305 (D)
Structure Clearances Sec 9.2.3.1
Length 60433 (PLR) -
Electrical Properties Tab 9.4
60720 (PLP)
Sec 3.3.3, 4.3,
Creepage Distance Pollution Severity 60815 -
9.2.3.2
60120 (B&S)
60471 (C&T)
Insulator Type
Sec 2.5, 9.2.3.3 60305 (D)
End Fittings Hardware Standards -
Tab 9.5 60433 (PLR)
Maintenance
60720 (PLP)
61466 (CLR)
Optional:
Shed Shape Pollution Type/Level Sec 3.3.4 60815 -
Shed Profile Pollution Type/Level Sec 3.3.4 60815 -
ELECTRICAL
PROPERTIES:
Power Freq. W/S 60383 (D, PLR)
Ch 3
Lightning Imp. W/S Line Voltage 60071 61109 (CLR)
Tab 9.2
Switching Imp. W/S 61952 (CLP)
Puncture Voltage Lightning Severity Sec 3.4.1, 9.2.1
61211 61211
(Class B units only) Tab 3.3,
Optional:
Power Arc Resist. System Fault Level Sec 3.4.3 61467 61467
Radio Interference Line Voltage Sec 3.4.2 60437 60437
MECHANICAL
PROPERTIES:
60305 (D)
Sec 6.1 60383 (D, PLR)
Tensile Strength Line Design 60433 (PLR)
Tab 9.3 61109 (CLR)
61466 (CLR)
Sec 6.2 60720 (PLP) 60383 (PLP)
Cantilever Strength Line Design
Tab 9.3 61952 (CLP)
Optional:
Residual Strength
- - - 60797 (D)
(Disc units only)
Mechanical
System Highest Voltage Environment
Strength
< 300 kV >= 300 kV Long Rod / Disc Pin / Line Post Station Post
Climatic Data
(Dry Spells) Polution Data
(Fog Days)
Dry Lightning Statutory or Wet Switching
Impulse Withstand Customer Impulse Withstand Strain Suspension Horizontal Vertical
Voltage (BIL) Requirement Voltage
Climatic Factor DDG ESDD
Max Conductor Tension Max Weight Span Max Wind Pressure Max Wind Pressure
Max Weight Span
(Stringing Criteria Max Wind Pressure Max Conductor Tension Short Circuit Forces NSDD
Ice Loading
Min Temperature Ice Loading (Angle Structure only) Max Deflection
Max Wind Pressure
Max Wind Pressure Busbar Mass
Unbalanced Loads
Ice Loading) Seismic Forces
(Fixed Base only)
Graph Max Conductor Tension
Dust Gauge Surface Deposit
kV vs Arcing Distance (Angle Structure only)
Polution Index Index
(with Altitude Correction)
Statutory or
Customer
Statutory or Site Severity
Factor of Safety
Customer Pollution Class
Factor of Safety
Minimum
Arcing Distance Specified Mechanical Load, SML (Composite) Max Design Cantilever Load, MDCL (Composite) Specific Creepage
Min Mechanical Failing Load (Ceramic) Min CantileverFailing Load (Ceramic) Distance
Other Requirements
eg
End Fittings, Material, Connecting Length, Live Line Clearance,
Shed Profile, Corona RIngs, Arcing Horns.
Insulator Type Selected
Figure 9.2: Flowchart of insulator selection procedure.

Handling and Installation Practices 125
10 HANDLING AND INSTALLATION PRACTICES
“Only two things are infinite, the universe and human stupidity, and I'm not sure about the
former” – Albert Einstein
Introduction
Insulators are fairly robust items and, as such, are often treated roughly on the
construction site. This is particularly true for composite insulators, the "unbreakable" and
"vandal-resistant" nature of which has been strongly promoted. However, although they
are flexible and will not chip, crack or shatter like the more brittle glass and ceramic
materials, incorrect loading of the units or damage to the housing can, for example,
precipitate complete mechanical and/or electrical breakdown. Moreover, the damage may
not be clearly visible and, with the consequent mechanisms of failure being time-related,
unexpected fracture can occur after a few years of service.
With an increasing number of line faults being experienced - the cause of which can be
attributed to the improper handling of insulators during transport and/or installation - the
need for more care is apparent. With a view to preventing such failures, this chapter
serves to describe how critical damage can occur on overhead line insulators in the field
and the measures that should be taken to avoid such damage. Typical problems are
illustrated to show the defects that can be introduced by inappropriate treatment and
construction practices, to indicate the possible long-term effects of such defects and to
assist in their identification.
10.1 Mechanisms of Failure
The procedures and precautions described for the handling of composite insulators are
primarily designed to limit the probability that the units are subjected to bending and
torsional forces for which they have not been designed and to prevent exposure of the
cores to moisture by either housing, sheath or end-seal damage. The mechanisms of
failure that can be precipitated by such defects are core delamination and breakage, and
brittle fracture.
With regard to ceramic insulators, an impact may cause cracking of the dielectric material.
For Class A units, this may precipitate mechanical failure, whereas for Class B designs,
electrical puncture may well result.
Detailed descriptions of the potential failure modes are provided in Chapter 7.
10.2 Factory Preparation
Insulators should be packed in wooden crates of sufficient strength to provide adequate

protection of the units in transit. For composite insulators, the walls of the crates should
be solid to prevent the entry of rodents as they can inflict considerable damage to
insulator housings. An example of rodent attack is shown in Figure 10.1.
To avoid breakage of the sheds and housings by the end caps and fittings of adjacent
units, the insulators must be restrained from moving around in the crate by suitable
internal battens. Further, any separate items or accessories packed with the insulators,
such as arcing horns or corona rings, must be properly secured within the crate.
Figure 10.1: Example of rodent attack.
A packing list providing the quantities and type numbers of the insulators contained should
be attached to the outside of the crate and a copy of the manufacturer's handling
instructions should be placed inside.
To facilitate clear identification, each insulator should be indelibly marked with the
manufacturer's name or logo, its complete unique type number, and the production batch
number.
10.3 Stores Receipt
On arrival at the stores, it must first be checked that the quantities and type numbers of
the insulators given on the order, the manufacturer's packing slips and the supplier's
delivery note agree.
Secondly, each crate must be examined for any signs of damage such as breakage due
to dropping, a forklift tine having penetrated the wall or collapse owing to excessive weight
having been packed on top. If damage is evident, the supplier must be advised
immediately and the crate set aside for inspection by the manufacturer's representative,
his insurance assessor and the relevant utility technical and quality assurance personnel.
Each insulator in the crate must be checked to ensure there is no damage to the housing,
the sheds, the end sealing or the metal fittings. Any units found with housing or seal
damage, or cracks in ceramic parts, must be rejected.
Where the crates show no signs of breakage or maltreatment, the extent of the quality
control applied on receipt of the goods could vary with, for example, the voltage of the
insulators, the strategic nature of the project for which they were purchased or the
reputation of the supplier. In some cases, quality assurance personnel prefer to
undertake a small sample inspection only, leaving most of the original packaging
undisturbed for the subsequent transport to site. Inspections could, though, incorporate
some or all of the checks, as appropriate to the insulator type, as described below.
10.3.1 Visual checks
• Confirmation that the type numbers on the insulators agree with those on the order.
• Confirmation that the number of sheds agrees with that on the drawing.
• Confirmation that the end fittings are of the type shown on the drawing and that they
are on the correct ends.
• Confirmation that the end fittings are complete with the required cotter pins, clevis
pins, split pins and washers, as applicable.
• Confirmation that all corona rings or arcing horns have been included where
necessary.
10.3.2 Dimensional checks
• Confirmation that the connecting length agrees with that on the drawing.
• Confirmation that the shed diameter agrees with that on the drawing.
• Confirmation that the core diameter agrees with that on the drawing.
• Confirmation that the clevis and tongue widths and clevis pin diameters are in
accordance with the drawing.
• Confirmation that the ball and socket fittings accept/do not accept the appropriate go
and no-go gauges as defined in the relevant standard, e.g. IEC 60120 [25].
10.3.3 Other checks
• Confirmation of the galvanising quality by measurement with a thickness gauge.

• Confirmation, by means of sampling and laboratory testing, that the shed and housing
material is of the type specified and/or matches approved samples.
Care must be exercised in the unpacking of crates that have internal battens for the
securing and support of each layer of insulators during transport. On removal of these
battens, nails are often left protruding from the internal walls of the crate. These must be
eliminated or bent flat before the insulators are taken out as they can easily damage the
housings and sheds of composite units. An example of this is shown in Figure 10.2.
Figure 10.2: Nails protruding from a crate can lead to insulator damage.
Following inspection, the insulators and other components should be returned to their
original packing and properly secured. On replacement of the lid, it must be ensured that
no nails, staples or other sharp objects can come into contact with the insulators. If the
crates were strapped, they should be re-strapped.
10.4 Storage
The insulators should be stored indoors in their original packing in areas free of standing
water and other contaminants such as oils and petroleum derivatives.
If the insulators have to be un-crated, no additional material must be placed or stored on

top of them. If they are stacked, care must be taken that the metalware does not make
contact with the housings of adjacent units. This is particularly important for composite
line posts which have heavy bases, often with sharp corners. For long rods, storage in
plastic pipes, as shown in Figure 10.3, offers good protection. Alternatively, they can be
hung from suitably designed racks with free-swinging hook, tongue or ball attachments, as
appropriate.
Figure 10.3: Insulators stored in plastic pipes.
Moving, loading and unloading of the crates with a forklift must be undertaken with due
caution.
10.5 Transport to Site
Wherever possible, the insulators should be transported to site in their original, closed
shipping crates.
If only part of a crate requires delivery and the insulators thus need to be removed from
the manufacturer's packing, they must never be transported loosely or without adequate
protection. The placing of other materials on top of insulators in transit must be strictly
prohibited. The insulators must not be tied down or tied together with chains, ropes, etc.
10.6 On-site Handling
On arrival at the construction site, the packaging should again be carefully checked. If
any signs of breakage or rough treatment are evident, each insulator must be examined
for signs of damage. Any unit which is shattered, cracked, shows core exposure or end-
sealing damage should be rejected.
Depending on the degree of inspection undertaken on receipt at the stores, some or all of
the acceptance checks listed in Sections 10.3.1 and 10.3.2 should be repeated on arrival
on site.
The insulators should be kept in their original packaging for as long as possible. They
should be stored in a dry, covered area, with the crates raised off the ground. Lids should
remain sealed to prevent the entrance of rodents. Should rodent damage be noticed,
each insulator must be closely examined for damage to the housing. Insulators exhibiting
minor biting of the periphery of the sheds are possibly still acceptable for installation; but
should be referred to the responsible engineer for a decision on their use.
As per Section 10.3.3, any nails left exposed on removal of the crate lid or internal battens
must be eliminated to prevent injury and/or insulator damage.
Once the insulators have been removed from their crates for delivery to the specific pole
or structure positions, they must be adequately protected. As noted in Section 10.5, they
must not be transported loosely or tied down or tied together with ropes or chains. Under
no circumstances, must material be placed on top of them whilst in transit. The insulators
must be kept away from possible contaminants and abrasive materials.
When left at their point of installation, the insulators become vulnerable to damage from
improper stacking, other equipment and material, vehicles and rodents. The deposit of
insulators in the field where, with construction activities in progress, they can easily be
struck by heavy tools and equipment, stood on and driven into or over, is unacceptable.
They must be adequately protected, placed a sufficient distance from the main areas of
activity and their position clearly marked. Stacking and storage as shown in Figure 10.4
should be avoided. The potential for damage is reduced if the delivery of the insulators to
their installation position is properly planned so as to occur immediately prior to them
being required and they are thus not left lying on the ground for lengthy periods.
Figure 10.4: Poor stacking and storage.

In view of the significant probability of insulator damage during transportation to the pole
position and, perhaps, left lying there for some time, it is recommended that – especially
for composite units - a temporary, re-usable packing system be introduced to provide
protection during transport and short-term storage. Such packing may take the form of a
rigid tube or plastic pipe, or a wrap-on shield. With regard to the latter, as shown in Figure
10.5, these devices are simply fitted and, as they leave the end fittings exposed, can be
left in place until the line construction is complete.
Figure 10.5: Protection devices for insulator storage and installation.
10.7 Insulator Installation
Prior to installation, the insulators should again be thoroughly examined for damage to the
housings, sheds and end seals. Units displaying any chipping of the porcelain or nicks,
cuts or indentations in the polymeric material, must be set aside for expert inspection.
Those with cracks in the ceramic components or exposure of the fibreglass core, however
small, must be discarded.
For composite insulators, units of connecting length less than 2.5 m can be safely lifted by
one person holding the core at a central point. Longer units should be lifted and carried
by two persons holding the insulator about half a metre from each end. As a general rule-
of-thumb, it must be ensured that the angle of deflection on either side of the holding point
is maintained at less than 30° to the horizontal. The insulators must not be dragged along
the ground.
Figure 10.6: Example of strings which have suffered pin bending.

Lifting ropes must be attached to the metal caps of composite insulators and not to the
sheds or rods. Large line post insulators must be carefully raised in a horizontal position,
utilising two slings. Disc insulator assemblies should be lifted by one end only – not in the
middle. Bending loads applied to the pins may cause cracking of the porcelain or, when
the pin is bent, unacceptable mechanical loading of the dielectric material in service. An
example of strings which have suffered pin bending is shown in Figure 10.6.
Before attachment to the pole, it must be checked that the type number printed on the
insulator agrees with that on the structure drawing. Often line posts of much lower
strength rating are specified for jumper support positions and these must not be used as
normal line support insulators. There may also be certain poles designed to
accommodate larger weight spans or line deviations which require posts of higher than
normal cantilever rating. In the case of discs and long rods, there may well be different
strength ratings for the strain and suspension units and they are thus not interchangeable.
It should be noted that, in accordance with IEC Standards 60305 (cap-and-pin discs) [13],
60433 (ceramic long rods) [26] and 61466-1 (composite long rods) [32], insulators of
70kN, 100 kN and 120 kN rating all have 16 mm end fittings. The danger thus often exists
that a unit of inadequate strength may be inadvertently installed. Similarly, the end fittings
of 160 kN and 210 kN insulators are of the same size (20 mm). Correct application of the
insulators on site is vitally important !
Should an insulator be dropped from the structure, it must be very carefully examined for
signs of damage before use. Composite insulators may bounce and show no obvious
defect but internal splitting of the fibreglass core could have occurred. A hairline crack in
a porcelain long rod may precipitate complete failure at a later date. An impact on the pin
of a disc insulator may result in it being bent or, in the case of ceramic units, the shell may
be cracked inside the cap and the electrical integrity lost.
For ease of live-line working, the utility may require insulator socket fittings to be
orientated in a particular direction. For example, for caps equipped with W-clips, the
mouth of the socket should face the structure and, on V-strings, the inside of the V.
Where cotter pins are employed as the locking device, the eye of the pin should face the
structure and the inside of the V-string assemblies.
10.7.1 Specific precautions - line post insulators
Where single steel or concrete pole structures are dressed with horizontal line post
insulators before being lifted into position, it is important that the pole is supported well
above the ground on suitable trestles. If not, any rotation of the pole on lifting may cause
the live end of the post to make contact with the ground and be subjected to a severe
cantilever stress. Further, the position of the sling on the pole must be fixed with a pin or
locating lug and arranged in such a way that it cannot come into contact with, or apply
bending loads to, the insulators.
When fitting horizontal line posts to the pole, it should be noted that the internal curvature
of gain-type bases will probably be of smaller radius than the radius of the pole itself,
leaving a gap between the centre of the base and the pole. This is normal and the base is
expected to rest on the outer edges only. Under no circumstances should it be attempted
- by the over-tightening of the mounting bolts - to deform the base to fit the pole.
Particularly for polymeric units, the posts and their corona rings should not be stood on.
As illustrated in Figure 10.7, owing to the nature and geometry of monopole structures,
horizontal line posts are often walked on and/or used to crawl out to the conductor
attachment point.
Figure 10.7: Unacceptable walking on horizontal line posts.
Housing and shed damage from boots, safety belt buckles and the like is thus common.
To prevent this, suitable working platforms must be mounted on the pole or bucket trucks
used for work on the live end of the insulators. These should be as light as possible but
designed to accommodate the weight of at least two persons. A typical working platform
is shown in Figure 10.8. This unit is equipped with a boom for holding or lifting the
conductor, components, tools and equipment, to prevent excessive loads being applied to
the end of the platform.
Figure 10.8: Typical working platform.

Even when working from a bucket or cage, care must be taken to ensure that the
insulators are not struck or stressed by the equipment. Figure 10.9 illustrates how
adjacent insulators can be damaged when personnel are concentrating on one particular
phase.
Figure 10.9: Adjacent insulators can be damaged.
Ladders, tools, blocks and other equipment must be prevented from coming into contact
with the insulator housings. Particular care needs to be taken on angle suspension poles
where pulling equipment may be employed in close proximity to the insulator to facilitate
conductor attachment.
The practice of throwing a line over composite post insulators to pull other components to
the pole top must not be permitted. This can totally abrade and remove the sheath
exposing the core and precipitating future failure. An example of such sheath damage is
provided in Figure 10.10.
Figure 10.10: Sheath damage due to rope abrasion.

If protective sleeves have been fitted to the insulators, they will serve to prevent shed and
housing damage from most of the hazards present. They should be left in place until
stringing and installation of the conductor accessories is complete.
It should be noted that the keeper pieces of most trunnion clamps are reversible to
facilitate the accommodation of a wide range of conductor sizes. It must thus be ensured
that they are placed the correct way up to suit the conductor type or the conductor plus
armour rod diameter in question.
Steel and concrete poles should be provided with appropriate fittings for the rigid
attachment of climbing ladders, which can serve as a stable base from which to work.
Examples of effective and practical systems are illustrated in Figure 10.11. The insulators
must not be used as anchoring points for tools and safety belts.
Figure 10.11: Climbing ladders.
10.7.2 Specific precautions - long rod insulators
Whilst still on the ground, the insulator and all string hardware should be assembled to
ensure that all parts are compatible and no force is required to connect the various pieces.
On assembling the insulator strings, it must be checked with the drawing that the correct
fittings are being used and applied in the right order and the right way around. Ensure that
the insulator is not upside down. When working with the insulator on the ground, all rocks,
stones or other hard objects which could cause damage must be removed. In rough
terrain, a suitable work surface must be provided.
Care must be taken that no bending loads are applied to the insulators during attachment
of the hardware or lifting of the assemblies to the pole top. The lifting line should be
attached to the earth-end insulator cap or fitting only.
The earth end hardware should be designed to allow the insulator to swing freely in all
directions. Even so, as shackles, for example, can turn sideways and "lock-up", the
attachment to the crossarm must be checked that it is in fact free, before any load or
weight is applied to the insulator string. Figure 10.12 (a) shows a terminal pole where the
hardware does not have vertical mobility. The lower clevis ball is also held horizontally
owing to the orientation of the turnbuckle eye. Any weight applied to this assembly could
result in damage to the insulator and metalware. Figure 10.12 (b) illustrates an insulator
at severe risk of being fractured owing to the lack of hardware mobility. The direct
attachment to the crossarm of porcelain long rods, an example of which is shown in
Figure 10.12 (c), could precipitate cascade failure of many units should conductor
breakage occur. (Note the incorrectly inserted split pin).
(a) (b) (c)
Figure 10.12: Insulator movement restricted.
The practice of throwing a line over the strain insulators to pull other components to the
pole top must not be permitted. This can totally abrade and remove the housing,
exposing the core and precipitating future failure. An example of such damage is shown
in Figure 10.13.
Courtesy of Eskom
Figure 10.13: Housing damage from lifting line.
Ladders, tools, blocks and other equipment must be prevented from coming into contact
with the insulators. If protective sleeves have been fitted, these will serve to prevent shed
and housing damage from most of the hazards present. They should be left in place until
stringing and installation of the conductor accessories are complete.
Figure 10.14: Shed and critical sheath damage on a composite strain insulator.
If corona rings are to be fitted, it must be ensured that these are properly located and the
mounting bolts tightened to the manufacturer's recommended torque. A loose ring lying
on a polymeric insulator can wear through the core and cause the line to drop. An
example of this dangerous situation is shown in Figure 10.15.
Figure 10.15: Loose corona ring.
Insulators and their corona rings must not be stepped or climbed upon. At suspension
positions, hanging ladders attached to the crossarm must be used to gain access to the
live end of the string. For strain strings, the use of a working platform as shown in Figure
10.8 is far preferable to the practice shown in Figure 10.16.
Figure 10.16: Sitting and climbing on insulators during construction.

10.8 Conductor Stringing
During stringing operations it is critically important that the long rod insulators, particularly
of the composite type, are not subjected to bending or torsional loads. A proper stringing
swivel must be used when tensioning the conductor. Further, the conductor must be
rolled off the drums and carefully handled to avoid the formation of loops and twists which
could, on tensioning, apply a torsional force to the insulator. Situations as illustrated in
Figure 10.17 should be avoided.
Figure 10.17: Twisting should be avoided.
If, when strung, the conductor bundle is rotated from its desired position or if the
conductors are twisted, under no circumstances must this be corrected by attempting to
turn the insulator or any of the hardware attached to it. This may cause the insulator to be
subjected to torsional forces. It must be noted that, under tension, ball and socket fittings
will not permit relative movement, any rotational moment will be transferred to the
insulator core.
When tensioning the conductor, the tensioning equipment should be attached to the pole
itself and the operation undertaken with the strain string left well out of the way.
Alternatively, the conductor can be tensioned with only a running-out block attached to the
crossarm. When at the correct sag, the conductor can be marked and lowered to the
ground for cutting and fitting of the compression deadend. The entire assembly and
conductor can then be lifted and attached to the structure. It should be noted that, on
lifting, the load should be taken by the come-along with the string assembly loosely tied to
the pulling cable. There is thus no stress on the insulator. Further, the vibration damper
should be attached to the conductor whilst it is on the ground so that there is no need to
climb out on the insulator after it is in position.
Figure 10.18: Core exposure owing to shed movement during stringing.
If turnbuckles are provided in the assembly for final sag adjustment, it is most important
that the insulator end cap is held and prevented from rotating while the turnbuckle is
tightened or loosened. Under no circumstances must the insulator be allowed to twist.
The correct technique is shown in Figure 10.19.
Holding
Turning
Figure 10.19: Correct turnbuckle adjustment technique.
For vertical suspension strings, it must be ensured that the insulators are able to swing
freely and follow the movement of the running-out blocks without being subjected to any
bending stress.
Where line posts are used at the intermediate positions, jamming of the conductor in the
running-out blocks will result in a high, and possibly damaging, longitudinal cantilever load
being applied to the insulator. It is thus important that all blocks are checked, and
preferably serviced, before the commencement of stringing.
When tensioning the conductor, proper sag charts and the necessary sighting boards
and/or dynamometers must be employed. Figure 10.20 shows damage to line post
insulators caused by inadequate control and measurement of the stringing tension. Here,
the breakage is clearly evident. With lower forces, however, the core of a composite unit
could be cracked and de-laminated internally without any external evidence of the
problem, thus making the line both unreliable and unsafe.
Figure 10.20: Line posts damaged during conductor stringing.
10.9 Pre-commissioning Insulator Inspection
On completion of the construction of a line, it is important that a thorough inspection of the

insulators is undertaken. As the evidence of damage can be dimensionally small, the
examination must be conducted from close quarters with, preferably, the inspector located
at insulator height. Exposure of the core by the action of pulling ropes, as shown in Figure
10.10 and Figure 10.13, for example, always occurs on the upper surfaces and cannot be
seen from the ground.
The following sections list the various potential insulator defects to be borne in mind when
undertaking an inspection prior to the commissioning of a line.
• Damage to the sheath resulting in exposure of the core. (Reference Figure 10.14).
• Splitting of the sheath resulting in exposure of the core.
• For those insulators with sheds that are not bonded to the core, exposure of the core
due to movement of the sheds. (Reference Figure 10.18).
• Damage to the end seals where the rod enters the caps.
• Broken or torn sheds. (Reference Figure 10.14).
• Deformation, discolourations or splits in the sheath which may reflect a corresponding
split in the core, caused by severe cantilever or torsional loading.
• A misalignment of the clevis and tongue end fittings which would indicate that the
insulator has been subjected to, or is being subjected to, a torsional stress.
• Marks on the end caps which indicate that the insulator may have been subjected to
bending, torsional or impact forces.
• Severe deflection of line post insulators - the live end horizontally in line with, or
below, the base attachment point - indicating either damage to the core from, for
example, overloading during stringing, or misapplication of the insulator. (Reference
Figure 10.20).
• Loose bolts, missing split pins, incorrectly applied corona rings, etc. (Reference
Figure 10.15).
• Insulator types in incorrect positions and errors in the string hardware assembly.
10.9.2 Ceramic long rod insulators
• Cracks in the sheds and core.

• Deformation, bending of the end caps.
• Marks on the end caps, indicating that the insulator may have been subjected to
bending, torsional or impact forces.
• Loose bolts, missing split pins, W-clips or cotter pins not fully inserted, incorrectly
applied corona rings or arcing horns, etc. (Reference Figure 10.12 (c)).
• Lack of mobility of the insulator/crossarm attachment assembly. (Reference Figure
10.12 (c)).
10.9.3 Cap-and-pin disc insulators
• Cracks in the porcelain shell.

• Bent pins. (Reference Figure 10.6).
• Loose bolts, missing split pins, W-clips or cotter pins not fully inserted.
10.10 Design Considerations
Although the design of the line cannot fully eliminate the risk of insulator damage on
installation, certain features and considerations incorporated in the design stage can
reduce the probability of failure being experienced on site.
10.10.1 Insulator mobility
The method of attachment of the insulator string to the tower and the composition of the
components in the string assembly must be selected to provide freedom of movement of
the insulator in all directions. If this is not achieved, the chance of exposing the insulator
to cantilever stresses is considerably increased.
The situation illustrated in Figure 10.12 (c), where the clevis cap of a porcelain long rod is
fixed directly to the crossarm, represents extremely poor practice. Apart from the danger
of breakage during installation and stringing, any future conductor breakage will result in a
serious cascade failure of the line.
Care must be taken to ensure that assemblies which appear extremely flexible on paper
are in fact so. For example, clevis fittings and shackles when attached to oval eyes may
have only very limited movement in one direction. Where shackles can be installed either
way around, freedom of movement planned in the design may not be realised in the field.
As shown in Figure 10.12 (a) and (b), swing of the assembly may be prevented by the
width of the landing plate on the crossarm.
10.10.2 Component selection
All hardware components and insulator fittings must couple easily without the need of
force. It must be ensured that the clevis, tongue, ball and socket sizes provided on the
insulator match those of the adjacent hardware.
The use of turnbuckles in strain strings does introduce the possibility that the insulators
are subjected to torsional loads during final sag adjustment.
When specifying line post trunnion clamp sizes, ensure that the armour rod diameters,
where applicable, are accounted for.
10.10.3 Accessibility
For monopole designs, the provision of adequate, stable ladders - or fittings for their
temporary employment - from which to work will reduce the necessity to climb or stand on
the insulators.
10.10.4 Drawings
It is important that the pole and assembly drawings available on the construction site not
only clearly show the make-up of the components in the strings but also display the
insulator type number. This is particularly necessary where, for example, line posts of
different strength ratings are used for line and jumper support positions or different long
rods used at strain and suspension points.
10.11 Handling Check Lists
The main aspects, recommendations and cautionary warnings for the handling of
composite insulators contained in this chapter are summarised in point form on the
following pages. These may be formatted for posting on notice boards, as instruction
sheets for site personnel, for inclusion in, or attachment to, the insulator crates, or as a
supplement to the construction drawings.
Two inspection check lists are provided for use in the stores and on site to confirm that the
correct insulators have been provided and that all the necessary accessories have been
included. It is important that the complete insulator type number appears on the insulator
string assembly drawings for each pole type and configuration to ensure that the various
insulator types on site are applied correctly.
INSULATOR HANDLING GUIDE SHEET 1 of 7
RECEIPT AND STORAGE
On Receipt ...
• Examine the crate for signs of damage.
• Open the crate carefully, ensuring that all tools used are kept well away from the
insulators.
• On removal of the lid and any internal battens, remove or flatten all exposed nails.
• Check that the type numbers on the insulators agree with those on the order and the
packing lists.
• Undertake an examination of a sample or all of the insulators as defined on Inspection

Check List given on Sheet 2.
• Return the insulators to their original crates and re-seal.
If Crates are Damaged ...
• Advise the supplier immediately.
• Visually examine each insulator in the crate in the presence of the supplier, his
insurance agent and the project engineer.
• Reject any insulator with damage to the housing or end seals.
Storage ...
• If possible, store insulators in their original crates.
• Crates should be raised off the ground and stored in an area free of standing water
and contaminants such as oils and petroleum derivatives.
• Crates must be sealed to prevent the entry of rodents.
• If the insulators must be un-crated, they must be hung from suitable racks or provided
with adequate temporary protection such as plastic tubes.
CHECK LIST - STORES RECEIPT
ORDER No : ______________ PROJECT : ________________________
TYPE No : ________________ SUPPLIER : _________ QTY : ________
x
TYPE No. ON INSULATOR :
CRATE IN SOUND CONDITION : Yes / No
NUMBER OF SHEDS :
LIVE-END FITTING TYPE :
LIVE-END FITTING SIZE : mm
ALL PINS, NUTS, ETC. INCLUDED ? Yes / No
EARTH-END FITTING TYPE :
EARTH-END FITTING SIZE : mm
CORONA RINGS INCLUDED ? Yes / No
CONNECTING LENGTH : mm
ALTERNATING SHEDS ? Yes / No
SHED DIAMETER 1 : mm
SHANK DIAMETER : mm
GALVANIZING THICKNESS : µm
SHED MATERIAL TYPE :
IF CRATE DAMAGED :
ALL UNITS EXAMINED ? Yes / No
No. OF UNITS REJECTED :
CRATE APPROVED FOR RELEASE TO SITE
INSPECTED BY : ____________________
DATE : ___________________ SIGNATURE : ____________________

TRANSPORT
• Wherever possible, insulators must be transported in their original crate with the lid in
place.
• Once the insulators are removed from the crate, temporary protective packaging
should be provided.
• Insulators must never be transported loosely or tied together or tied down with chains,
ropes, etc.
• Other material and equipment must never placed on top of insulators in transit.
• On arrival at site, undertake an examination of a sample or all of the insulators as

defined on the Inspection Check List given on Sheet 4.
• If packaging damage is evident, visually examine each insulator.
• Reject any insulator with housing or end-seal damage.
• Transport insulators to the structure position only when immediately required.

CHECK LIST - SITE RECEIPT
ORDER No : ______________ PROJECT : ________________________
TYPE No : ________________ SUPPLIER : _________ QTY : ________
x
TYPE No. ON INSULATOR :
CRATE IN SOUND CONDITION : Yes / No
NUMBER OF SHEDS :
LIVE-END FITTING TYPE :
LIVE-END FITTING SIZE : mm
EARTH-END FITTING TYPE :
EARTH-END FITTING SIZE : mm
CORONA RINGS INCLUDED ? Yes / No
CONNECTING LENGTH : mm
ALTERNATING SHEDS ? Yes / No
SHANK DIAMETER : mm
GALVANIZING THICKNESS : µm
SHED MATERIAL TYPE :
IF CRATE DAMAGED :
ALL UNITS EXAMINED ? Yes / No
No. OF UNITS REJECTED :
CRATE APPROVED FOR RELEASE TO SITE
INSPECTED BY : ____________________
DATE : ___________________ SIGNATURE : ____________________

ON-SITE HANDLING
On Arrival at the Pole Position ...
• Open the crate carefully and remove or flatten all exposed nails that could damage the
insulator housings or cause injury.
• Once removed from the crate, the insulators should be provided with some temporary
protective packaging.
• Insulators must not be left lying where they are in danger of being driven over, stood
on or struck by other components and equipment.
Assembling ...
• Do not place the insulator directly on the ground. Use a protective cover or, at least,
lay the unit on a plastic or canvas sheet.
• Insulators exhibiting damage to the housing or end seals must be rejected and
removed from the site.
• Check that the type number marked on the insulator agrees with that given on the
assembly drawing.
• Check that the insulator is the right way around and that all metal fittings are in the
correct order.
• Check that the fitting sizes and dimensions of adjacent metalware are compatible and
that all components can be coupled without undue force.
• Ensure that all split pins, cotter pins and W-clips are fully inserted and that nuts and
bolts are properly tightened.
INSTALLATION
Installing ...
• Lifting lines must be attached to the caps of composite insulators only and never to the
sheds or housing.
• Where poles are dressed with line posts before being positioned, it must be ensured
that, on lifting of the pole, the insulators do not make contact with the ground.
• All line post mounting bolts must be tightened to the recommended torque.
• Do not step, sit or crawl on the insulators - climbing ladders and work platforms must
be used.
• Where buckets or cages are employed, it must be ensured that at no stage they come
into contact with, or rest on, the insulators.
• Ladders, tools, blocks and other equipment must be kept away from the insulator
sheds and housings.
• Lifting lines must not be thrown over the insulators.
• Ensure that line post trunnion clamp keeper pieces are installed the right way up.
• No bending or torsional loads must be applied to long rod insulators.
• When attached to the pole or crossarm, it must be checked that long rod insulators are
free to swing in all directions.
• Corona rings and arcing horns must be properly fitted and the bolts tightened to the
recommended torque.
CONDUCTOR STRINGING
• Do not use any equipment or stringing procedure that may subject the long rod
insulators to bending or torsional loads.
• When stringing, a proper conductor swivel fitting must be used.
• The conductor must be carefully run out and handled to avoid the formation of loops
and twists.
• Under no circumstances must attempts be made to align or un-twist conductor

bundles by rotating the insulator or the string hardware.
• Ensure that all tensioning equipment is kept well clear of the insulators.
• Long rod insulators must be held and prevented from rotating when turnbuckles in the
string assembly are adjusted.
• Ensure that long rod suspension strings are free to swing and follow the movement of
the running-out blocks without bending.
• To prevent potential damage to line post insulators, all running-out blocks must be
checked and, if necessary, serviced, prior to use.
• The appropriate stringing charts, sighting boards and dynamometers must be

employed to ensure that insulators are not over-stressed.
Inspection and Analysis Techniques 150
11 INSPECTION AND ANALYSIS TECHNIQUES
“In the field of observation, chance favours only the prepared mind” – Louis Pasteur
Introduction
Considerable effort has been devoted in determining reliable means of assessing the
condition of insulators in service. Well-established methods that enjoy a high level of
confidence, and some new ones, are available for conventional glass and porcelain cap-
and-pin insulators. The development of reliable and sensitive assessment methods for
composite insulators is, however, still in progress. In addition to visual examination,
several techniques are now in use but the information obtained is not yet fully satisfactory
[29]. Typically, these involve the measurement or detection of:
• Resistance
• Partial discharge activity
• Radio interference (RI / RIV)
• Acoustic emission
• Electric field distribution
• Corona generation
• Heat.
The inspection methods can be divided into two main categories, those that require
contact with the insulator and those that evaluate the insulator from a distance.
Visual examination, although it requires skilled personnel who are knowledgeable of the
degradation/failure processes of each specific insulator type, is still one of the most
reliable inspection techniques. Although the early stages of some internal degradation
may not be visible from the outside, often external evidence – such as a small puncture in
the housing – may be present to indicate problems within the insulator. Visual inspections
can be undertaken from the ground, the tower, bucket truck or helicopter, but the
technique must permit detailed study and the detection of very small defects.
Figure 11.1: Aerial close-visual inspection.

Where field inspections have detected faulty insulators or indicated that defective units
may be present, samples can be further examined in the laboratory. There are several
techniques that can be used to evaluate the state of a porcelain insulator. However, short
of a careful dissection, it is still difficult to identify a composite insulator with internal
deterioration in the early stages of development.
11.1 Field Inspection Methods
11.1.1 Toughened glass insulators
One of the characteristics of toughened glass insulators is that a defect impairing the
electrical integrity of the glass shells makes them shatter without affecting their
mechanical strength. Thus, with these insulators, only a simple visual patrol is required to
detect electrically defective units on live lines. This can be done from the ground or from
a helicopter flying along the line. A more detailed visual examination is, however, needed
to detect faults such as flash marks, bent and corroded pins, erosion of the glass, missing
split pins and incorrectly inserted locking devices.
Figure 11.2: Flash marks on glass disc insulator.
11.1.2 Porcelain insulators
Since, practically, the solid dielectric of long rod porcelain insulators cannot fail
electrically, they are usually checked visually from the ground or from the tower. A closer
inspection can be undertaken to locate other faults such as flash marks, loose arcing
horns, creep of lead antimony cement, missing split pins and locking devices that are not
correctly inserted.
Defective cap-and-pin porcelain insulators have a lower electrical resistance than sound
insulators. Their resistance may vary from zero to several tens of MΩ. The resistance of
sound insulators is practically infinite when measured with a megohm meter at 1000 V. If
an insulator string contains faulty insulators, the voltage distribution or electric field along
the string will somehow be distorted. From the mechanical viewpoint, faulty insulators
have a lower dominant resonant frequency than sound units. In service, faulty insulators
in a string can be detected by measuring such differences. Available detection methods
are [34]:
a) single disc resistance measurement

b) single disc voltage measurement
c) electrical field measurement.
The detection of faulty insulators by means of RI measurements is not easily performed in

the field as it is difficult to ascertain the origin of the discharges that produce the
interference.
11.1.2.1 Single disc resistance measurement
The integrity of a porcelain disc unit can be checked using a puncture detector such as
the example shown in Figure 11.3. These devices apply a DC voltage of the order of
10kV between the cap and the pin and measure the resultant leakage current. Should
this exceed a critical threshold value, a visible indication and/or audible alarm are
provided.
The instrument is attached to a hot stick and can be operated from the ground, tower or
bucket truck. It can be used on either live or dead lines, strings of one or more discs, and
pin insulators.
If the insulators are polluted under conditions of high humidity the device may give a false
reading as it detects surface leakage currents. If a defect is indicated, its validity can be
checked by placing the electrodes on the insulator surface to establish whether the
current is a result of the pollution or a puncture.
Figure 11.3: Puncture detector.

11.1.2.2 Single disc voltage measurement
A simple fork with two prongs, insulated from each other and separated by a spark gap,
can be used to check the voltage across an insulator unit that is part of a string. One
prong is put in contact with the cap of the insulator and the other in contact with the pin.
When the insulator is sound, a noise will be emitted by the breakdown of the gap. If the
insulator is punctured, there is no voltage to make the gap discharge.
A diagram of a more sophisticated instrument, based on the same principle, is shown in

Figure 11.4.
Figure 11.4: Block diagram and results of the measurement of single disc voltages on a
string of insulators with one defective insulator (Courtesy of Rick Suzuki, NGK).
To the same degree as the single disc resistance measurement method, this technique is
also affected by the ambient conditions, such as humidity and the pollution present on the
surface of the insulators at the time of the measurement.
11.1.2.3 Measurement of the electric field
The detection of defective porcelain cap-and-pin insulators can be based on the variation
of the electrical field measured along the string [35]. The detector, mounted on a sled
which is moved along the insulator string, measures the electric field and records the
results in a data logging module. The data can be downloaded to a portable computer for
display and analysis.
The instrument is based on the principle that faulty insulators in a string are associated
with a lower local electrical field than sound insulators are. It must be appreciated that
this technique is also sensitive to the ambient conditions such as humidity and the
pollution present on the surface of the insulator at the time of the measurement.
Additional information is provided in Section 11.1.3.5.
Courtesy of Guy Riquel, EdF
Figure 11.5: Electric field measuring instrument.
To evaluate the state of composite insulators it is necessary to be aware of the various

degradation processes that may affect them during service. Degradation due to
unacceptable ageing or minor manufacturing defects may lead, with time, to excessive
loss of the insulator’s electrical or mechanical integrity, with potentially harmful
consequences.
Over the last few years, several techniques have shown a reasonably good potential for
the assessment of the state of composite insulators on live lines [29]. They are:
a) visual inspection
b) hydrophobicity assessment
c) directional wireless acoustic detection
d) use of light-amplification devices
e) infrared thermography
f) E-field measurement.
Of these five methods, only the E-field measurement cannot be done from the ground. All
the other techniques may be used from the ground, the tower, a bucket truck or a
helicopter. Measurement of RI to detect defective composite insulators is also impractical.
11.1.3.1 Visual inspection
Visual inspection was the first, and is still the most common, insulator inspection
technique employed by many utilities. As the defects are usually dimensionally small,
visual aids, such as high-power binoculars or telescopes should be used. The inspector
should preferably be as close as safely possible to the insulator and should therefore
operate from the tower, a bucket truck or helicopter.
For a reliable assessment of the state of the insulator, the inspector should be aware of
the design, materials and behaviour of each type of composite insulator and familiar with
their likely modes of failure. Typical deterioration or damages that can be observed are:
• "alligator skin" erosion or roughening of the sheds

• erosion grooves or tracks in the external dielectric material
• electrical puncture of the sheds
• electrical puncture of the covering of the core
• splitting of the sheds and/or sheath
• cracks in the external covering
• damage to the moisture seal at the end fitting
• exposure of the core due to physical damage, cracks, erosion, power arc or shed
movement
• flashover damage to the dielectric material, the seal or the end fittings.
Examples of these faults are shown in Section 7.3.
Although visual inspection is mainly aimed at detecting surface damage, evidence of

internal faults may also be found. Two such cases are illustrated in Figure 11.6.
(a) (b)
Figure 11.6: External indications of internal mechanical damage (a) and electrical
deterioration (b).
In (a) above, de-lamination of the core of a line post insulator owing to overloading
manifests itself by subtle deformation and discolouration of the silicone rubber sheath. In
(b), a small puncture hole in the sheath indicates the commencement of electrical tracking
up the fibreglass core.
These examples serve to emphasise that visual inspections need to be undertaken slowly,
carefully and from close proximity, and that the inspector knows what to look for.
11.1.3.2 Hydrophobicity assessment
As mentioned previously (Section 5.3.1.2.1), the hydrophobicity of insulator surfaces –

particularly those of silicone rubber material – plays an important role in limiting the flow of
leakage current and preventing pollution flashover. The level of hydrophobicity may,
however, change with time owing to, for example, environmental effects, partial discharge
activity or corona. The water repellency can be defined in terms of the contact angle
made between a water droplet and the surface. Such an angle is however difficult to
measure in the field and a simplified method of classifying hydrophobicity was proposed
by STRI and subsequently included in IEC 62073, “Guide to the measurement of
wettability of insulator surfaces”.
The assessment technique involves a comparison of the appearance of the wetted

insulator surface with that of a set of seven sample surfaces ranging from completely
hydrophobic (Wettability Class 1) to completely hydrophilic (Wettability Class 6).
Examples of the different classes (1 to 6) are illustrated for reference in Figure 11.7.
WC 1 (Hydrophobic) WC 2
WC 3 WC 4
WC 5 WC 6 (Hydrophilic)
Figure 11.7 Photographs (natural size) of sample surfaces with wettability class (WC)
from 1 to 6 (courtesy of STRI).
11.1.3.3 Directional wireless acoustic emission
Use can be made of a wireless directional acoustic emission detector to locate discharge
sources. However, insulator defects can only be detected when they cause discharge
activity. Even then, the acoustic method seems to be less sensitive than thermography.
Noise from corona discharges on the adjacent hardware may also be a problem.
11.1.3.4 Light amplification equipment (night vision camera)
The examination of insulators with an image intensifier can indicate the presence of
surface discharge activity. In some cases, small but stable discharges detected with night
vision equipment have been shown to lead to significant erosion of the shed material with
time.
However, it should be noted that most of the energy radiated by the partial discharges lies
in the 300 to 380 nm UV-A band. The human eye and standard light amplification devices
are insensitive in this region. Further, the glass used in commercial lenses does not
transmit this part of the spectrum. For best results, therefore, a special ultra-violet imager
with quartz lenses should be used and the measurements must be taken at night or
possibly dusk or dawn.
Disadvantages of the technique are that the inspection must be undertaken when it is dark
and that discharges must be present at the time of the inspection. Unfortunately, in many
cases, the nature of this type of activity is associated with very specific and sporadic
service conditions. However, surface discharges are more likely to occur when the
insulator surface is humid and this often occurs at dusk or dawn. A new corona detection
camera that can be operated in daylight has been developed [37].
The recent cameras, equipped with a compact video recording system and a good lens,
can locate very small electrical discharges on the surface of insulators and store the visual
information – as shown in Figure 11.8 (b) – along with vocal comments.
11.1.3.5 Infrared thermography
Degradation caused by the action of the electric field on dielectric materials is, in most
cases, associated with heat. Laboratory and field tests to locate defects in composite
insulators using infrared (IR) thermography have yielded good results. Many utilities are
using this technique to inspect their power lines.
Recently developed non-cooled IR cameras are light and easy to use in the field.
Equipped with a suitable telephoto lens, they can locate, from a distance of several
meters, small areas with a temperature elevation of less than 1 K and store the
information for subsequent analysis.
The use of IR cameras that operate in the 8-14 µm band are recommended. At these
wavelengths, the imager is more sensitive in the temperature range of interest and the
effects of solar radiation are minimised.
Figure 11.8 (a) presents the thermal image and the temperature profile of a 400 kV
insulator inspected late at night. Several spots show a temperature elevation of up to
about 12 K. Most of these spots are located along the first 40% of the insulator length
above the live end except for two spots that are in the vicinity of the insulator ground end.
(a) (b)
Figure 11.8: A 400 kV composite insulator observed with an IR camera (a) and light
amplification equipment (b).
Concurrently with the IR observations, the same insulators were inspected with night
vision equipment as shown in Figure 11.8 (b). Electrical discharges are seen along the
length of the insulator. When Figure 11.8 (a) and (b) are compared, one finds that the
locations of the surface discharges coincide with the locations of the warm spots. This is
an indication that it was the surface discharges that the IR measurement had detected
and not some heating that could have been caused by internal degradation. Such
discharges are often sporadic and temporary, and will disappear when the ambient
conditions improve. However, should they remain at the same location along the insulator
for long periods of time, they may affect the integrity of the housing.
If no discharges are visible with the night vision equipment, the warm areas detected by
the thermal imager will indicate internal heating and be of greater concern. This illustrates
the importance of combining the two techniques.
11.1.3.6 E-field measurement
This technique was first developed for the evaluation of strings of porcelain cap-and-pin
insulators (see Section 11.1.2.3). The apparatus has subsequently been adapted for use
with composite insulators. Using this method, the electric field is mapped along the
insulator. At the location of a defect, the electric field will change more or less abruptly.
The carriage of the apparatus, fixed at the end of a sufficiently long insulating stick, must
have dimensions that correspond to the diameter of the sheds of the insulator under test.
As there are many existing insulator types of different diameters, several carriages may
be required. Moving the carriage along the insulator is a fairly delicate operation,
especially in the case of vertical and horizontal insulators. The E-field measurements are
stored in a microprocessor located in the carriage and subsequently downloaded to a
portable computer for display and analysis. Discontinuities in the resultant curve are
indicative of a probable insulator defect.
Live line inspections have shown that the measurements of the E-field along composite
insulators sometimes indicate a possibly defective insulator when, in fact, the insulator is
not damaged. To explain these anomalous results, a series of tests was conducted on a
245 kV insulator removed from a line where the pollution level was very high. Except for
its contaminated surface, the insulator was in sound condition.
Figure 11.9 shows the E-field variation along the polluted insulator when it was dry. The
curve is that of a sound insulator except for the important dip at the energised end. In this
case the large decrease in the field is caused by the presence of the grading ring.
Figure 11.9: E-field along a sound insulator with a dry polluted surface.
Figure 11.10 shows the E-field curves of the same insulator after its surface has been
wetted by condensation in a clean fog chamber and also when the surface has started to
dry but is still slightly humid. The curve of the wet insulator, because of its abrupt slope
changes, is indicative of a highly damaged insulator. The curve corresponding to the
insulator with a slightly humid surface would also indicate some damage.
Figure 11.10: E-field along the same insulator as Figure 11.9 when its surface is wet or
slightly humid.
The curves of Figure 11.9 and Figure 11.10 illustrate the strong influence of the ambient
humidity as it modifies the conductance of the pollution layer deposited on the insulator
housing. This has a drastic effect on the E-field distribution along the insulator, making
interpretation of the results difficult.
11.1.3.7 Comments
Five of the techniques that can be used for the inspection of composite insulators on live
lines have been briefly described and the results obtained with three of them have been
presented. These three techniques have now reached such a high level of sensitivity that
very small changes in temperature, tiny electrical discharges or small changes in the E-
field can be measured. The examples presented above have been selected to show how
difficulty encountered by the operator in interpreting the test results.
When assessing the state of insulators on live lines, it is important to take the ambient
conditions into consideration, especially when using the E-field method which is
particularly sensitive to the level of humidity.
The combination of a detailed visual inspection, infrared thermography and ultraviolet light
amplification observations is the most effective technique currently available for the
evaluation of in-service composite insulators.
11.2 Field inspection sheet
Figure 11.11 is an example of a form that can be used to assist local utility staff in the
visual inspection of insulators and the recording of the results. The layout of the form is
such that the faults are divided into three categories to indicate what level of action needs
to be taken. These are:
• Category 1: The insulators require either urgent replacement or prompt corrective

action.
• Category 2: The insulators show potentially serious defects that require further
expert examination.
• Category 3: The insulators should be monitored for further degradation on an annual
basis.
Figure 11.11: Insulator field inspection sheet.

11.3 Line Fault Investigation
When an unacceptable number of phase-to-ground faults are experienced on an

overhead line, it is natural to suspect that something must be wrong with the insulators.
Particularly where the cause is thought to be pollution related, costly maintenance
procedures, such as live spray washing, are often introduced. Alternatively, a major
financial investment is made to re-insulate the line with units which are thought to be of
more appropriate design for the environmental conditions prevailing. Where the line is of
strategic importance to the network, or where it feeds a large and important customer, the
threat to the system or the potential compensation payable often prompts hasty decisions
to be taken. It is, however, most important that a course of corrective action is only
adopted after a thorough investigation to establish the precise cause of the outages.
A study of the fault statistics, with particular reference to the time-of-day and time-of-year
of their occurrence, represents a good starting point. Lightning-induced flashovers are
more common with afternoon thunderstorm development whereas pollution flashovers
occur more frequently in the early morning hours with the onset of condensation or mists.
Based on the analysis of faults experienced in Florida [38], and South Africa [39], typical
daily distribution curves for the three main causes of flashover are shown in Figure 11.12.
Figure 11.12: Time-of-day flashover occurrence characteristics.

With regard to the fault occurrence in relation to the time of year, lightning activity is
usually restricted to certain months. Pollution flashovers are more likely to be
experienced with the onset of the first fogs and rains after the dry season and the
probability of bird streamer faults increases in spring.
In addition to the outage statistics, local utility personnel and residents can often provide
valuable information, such as on the weather conditions prevailing at the time of the fault.
Beware, though, of pre-conceived ideas affecting the feedback. Sweeping statements like
“the problems always happen on rainy nights” need to be checked.
Following examination of the statistical data and the interviews, the line should be
carefully inspected. This must preferably be undertaken using a close-visual helicopter
technique as the size of the defect precipitating the tripping and/or the evidence remaining
after the trip, may be dimensionally very small. To confirm the cause of the outages and
ensure that the corrective action proposed is, in fact, appropriate, it is vital that the actual
flash marks are located.
The inspection may be supplemented by, for example, the conducting of pollution severity
assessments or, if lightning back-flashover is considered a possibility, tower footing
resistance measurements.
In an investigation conducted on a 132 kV line in a coastal, semi-desert area, [39], the

cause of the frequent tripping was found to be the breakdown of the air gap between the
jumpers and the crossarms at the strain structures. Clearances were below the standard
design value and flashovers were precipitated by streamers from birds sitting on the
crossarms. It had, however, been assumed that the problem was one of marine pollution
and the complete re-insulation of the line was planned. Fortunately, a thorough
investigation - as described above - was undertaken before the purchase was made and
the installation undertaken, as otherwise the large investment would have realised no
improvement in the line performance whatsoever.
Pollution Mitigation Techniques 164
12 POLLUTION MITIGATION TECHNIQUES
“The task is, not so much to see what no one has yet seen; but to think what nobody has yet
thought, about that which everybody sees” – Erwin Schrödinger
Introduction
The main aim of this book is to assist users in the selection of outdoor insulators of an
appropriate type for a particular application with a view to achieving a reliable,
maintenance-free system. Many existing insulators, however, were not adequately
dimensioned for their operating environment (or, for their new changed environment),
resulting in unacceptable performance and the need to take corrective action to prevent
costly outages. This chapter serves to explore the various measures that can be adopted
to reduce the probability of pollution flashover in terms of their applicability, cost and
effectiveness.
12.1 Insulator Replacement
The failure of overhead line insulation in contaminated areas can best be addressed by
the installation of replacement insulators of a design more suited to the ambient
conditions. These replacement insulators may be of increased creepage distance,
improved profile and/or possess superior material characteristics, such as high surface
hydrophobicity. The selection process for these insulators should be the same as that for
a new line although some additional restrictions may apply. For example, the connecting
length may be limited by the existing tower geometry.
With proper evaluation and knowledge of the environmental conditions, the re-insulation of
many critical transmission lines has represented a long-term solution to pollution-related
system outages. Moreover, when compared to alternative maintenance activities, such as
spray washing or greasing, considerable cost benefits have also been realised.
Unfortunately, in substations, insulator replacement is not so easy. Many of the

porcelains form part of the apparatus and cannot be exchanged. Station post units are,
however, readily available and can be installed where flashover has been experienced on
busbar supports, isolating links and the like. Silicone rubber composite posts, especially
where conductive fogs are prevalent, may provide a good solution but their increased
flexibility must be considered in their selection for certain applications.
Where insulator replacement is not practical or feasible, one of the maintenance

techniques described in the following sections must be instituted.
12.2 Cleaning
The most basic approach to solving insulator contamination problems is to clean the
insulator surfaces. This can be done by hand- or spray-washing techniques, conducted
under live or dead conditions, and utilising various types of cleaning materials and
equipment. These techniques are discussed below.
12.2.1 Hand washing
The cleaning of insulators by hand is extremely labour intensive and requires long
outages but can be very effective in removing stubborn deposits. Relatively unskilled staff
can be employed and no special capital equipment is required. It does, however, need to
be undertaken at frequent intervals to maintain a low flashover probability.
Figure 12.1: Hand washing insulators in a 400 kV substation.
Detergents and de-greasing agents can be used but, as most are highly conductive, they
must be thoroughly rinsed from the insulator surfaces prior to re-energisation. Care must
also be exercised in their use as they can represent a safety hazard. The manufacturer’s
instructions must be strictly observed and the appropriate protective clothing worn. Some
solvents can chemically attack cement and galvanised surfaces and the potential for
causing damage to the insulators must be investigated prior to their use. Abrasive
materials must also be used with caution and scratching or roughening of the dielectric
surfaces must be avoided.
12.2.2 Spray washing
Spray washing can be quicker than cleaning by hand but is only effective for soluble
pollutants and those of low adhesion to the insulators. If undertaken live, outages can be
avoided but specialised equipment and a skilled operator are required. The spraying
method and equipment employed are critical to ensure the efficient removal of the
contaminants, the safety of personnel and the security of the system.
With regard to safety, it is important to use an appropriately designed spray nozzle,

operating at the specified pressure, which breaks the jet stream into separate droplets,
thus ensuring adequate electrical resistance between the energised equipment and the
operator. The water must also be of sufficiently low conductivity. The sourcing and
transportation of water of suitable quality, as required for washing, can be a costly
exercise in arid regions. Strict attention must be paid to the proper earthing of the
washing apparatus and the maintenance of adequate clearances. Some guidance in this
regard is provided in Table 12.1.
Table 12.1: Minimum nozzle to live apparatus working distances for given water
pressures and resistivities.
Nominal System Minimum Water Minimum Nozzle Minimum Working
Voltage Resistivity Pressure Distance
(kV) Ω.cm)
(Ω (kPa) (m)
11 2500 2800 2.00
22 2500 2800 2.00
33 2500 2800 2.50
66 2500 2800 3.00
88 2500 2800 3.00
2500 3800 3.50
132
1300 2800 4.10
2500 3800 4.00
220
1300 2800 4.60
2500 3800 4.25
275
1300 2800 4.85
2500 3800 4.70
400
1300 2800 5.55
2500 3800 6.00
765
1300 2800 7.60
The actual spraying technique is critical to avoid precipitating flashovers instead of

preventing them. Whilst cleaning one piece of apparatus, the overspray may wet adjacent
porcelains, creating high leakage currents and possible breakdown. Washing of vertical
insulators must commence at the bottom and proceed upwards otherwise there is a risk
that the dirty water cascading over the still contaminated lower sections will cause a flash.
The uneven wetting that can occur when washing housings of large diameter also poses
some danger. Moreover, the distortion of the stress distribution on devices such as surge
arresters may cause internal breakdown. In some utilities the live washing of such
apparatus is prohibited.
The use of helicopter-mounted spray washing equipment is the most practical method for
cleaning transmission line insulators – especially those traversing inaccessible terrain.
The spray nozzle can be brought closer to the insulator surfaces than it can for ground-
based, hand-held systems, but the washing technique must still be undertaken with care
to avoid initiating an insulator flashover. It must also be appreciated that airborne washing
is costly and, although it may be justified as an emergency procedure, the re-insulation of
the line with more suitably designed units usually offers a far more economical long-term
solution.
Courtesy of Eskom
Figure 12.2: Live spray washing of overhead line insulators from a helicopter.
12.2.3 Fixed live spray washing systems
In some transmission facilities of strategic importance, permanent spray washing systems

are installed. With the significant capital expenditure involved and the high level of
maintenance required to keep them in operation, it is doubtful whether they are cost-
effective.
Moreover, a minor malfunction such as a drop in pressure or blocked nozzle may create a
condition of artificial wetting rather than washing and considerably increase the probability
of flashover. They are thus not recommended.
Courtesy of Eskom
Figure 12.3: Fixed spray washing system installed in a 400 kV yard.

12.2.4 Dry cleaning
In some countries insulator cleaning is achieved by blasting their surfaces with dry,
abrasive material. The material used is usually organic in nature such as ground corn
cobs or walnut shells. It is much more effective than water in removing hard, insoluble
deposits. However, the cleaning agent accumulated in the substation yard constitutes a
fire hazard and needs to be collected and removed.
A similar, but somewhat more expensive, approach, using pellets of dry ice, has recently
been introduced. Also fairly effective for some types of contaminants, its claimed
advantage is that no by-products need to be removed from the site afterwards. However,
when cleaning insulators which have previously been greased, for example, the resultant
spread of the old dirt layer over the ground and apparatus surfaces may present an even
greater environmental and safety challenge.
12.2.5 Cleaning frequency
The biggest problem with any cleaning approach is to establish the optimum timing of the
process. With the multitude of variables affecting insulation performance, accurate
forecasting of potential flashover is impossible. For the pre-deposited type of
contaminants, it would be ideal to wash the insulators towards the end of the dry spell,
prior to the onset of seasonal mists, fogs and rain. However, with the unpredictable
nature of the weather, wetting can occur much earlier than expected, causing widespread
disruption of supply.
The leakage current amplitude is often considered to be the best indicator of the state of
the insulators. However, substantial contaminant layers can build up during the dry
seasons yet have no effect on electrical activity until wetted. Current monitoring
instrumentation will thus not detect the potential danger until it is too late – flashover
occurring within a few minutes of the first fog or rain. Insulator cleaning can thus only be
reliably triggered on the basis of leakage current amplitude if regular wetting occurs
naturally or is artificially induced.
Of course, a washing strategy in areas prone to instantaneous pollution is totally

ineffective. As conductive fogs can take an insulator surface from a clean state to one
that is highly conductive within a few minutes, flashover is possible irrespective of whether
the unit had been recently washed or not. In such environments, therefore, other
mitigation measures must be introduced.
12.3 Silicone Greasing
The application of silicone grease to insulators creates a hydrophobic surface which

inhibits the formation of a continuous, wet, conductive contaminating layer. In addition,
the grease serves to encapsulate the dirt particles, preventing them from going into
solution and electrically isolating them from each other. These two effects provide
protection against pollution flashover for a significantly longer period than can be achieved
by cleaning alone. Further, the water repellency of the grease is beneficial in combating
instantaneous contamination events.
Sprayable products are available but grease is more commonly applied by hand. Care
must be taken to achieve a uniform layer at least 2 mm thick. The bridging of closely-
spaced sheds by lumps of grease must be avoided.
The quality of the grease used is extremely important – some types may have excellent
properties for other applications but are unsuited to high voltage insulator application.
Before a grease is accepted for widespread use it should be thoroughly tested in the field.
If time does not allow this, it should at least be evaluated in the laboratory in terms of its
dielectric strength, water repellency, water run-off angle and encapsulating ability.
With time, as it becomes saturated with solid particulate matter, the grease will begin to
lose its effectiveness. As leakage current activity begins to increase, localised heating
and ultraviolet radiation accelerate the degradation process. White silica channels which
are not hydrophobic are formed, signalling the end of the material’s life. Not only do they
indicate that flashover is imminent but, if the grease is not soon replaced, further current
flow through the layer can cause permanent damage to the insulator substrate.
The life of the grease is determined by the conductivity of the ambient pollution, the
creepage distance and quality of profile of the insulator, and the amount of non-soluble
contamination present to stick to the layer and ultimately overwhelm its encapsulating
capability. The rapid “clogging” of the grease by bulky contaminants such as cement dust
and fly ash makes this mitigation approach unsuitable for such environments.
The replacement of the grease is a costly and unpleasant task. All old material must be
removed prior to the application of the new. This is very labour-intensive and requires
long outages. The insulators and apparatus must be thoroughly cleaned – any grease left
lying on surrounding surfaces represents a slipping hazard to other utility staff. Proper
disposal of the spent material must be exercised. The cost, frequency and nature of the
re-greasing process have resulted in the coating of insulators with RTV silicone rubber
becoming the preferred option.
Figure 12.4: Replacement of silicone grease is a labour-intensive task.

12.4 Silicone Rubber Coating
As for greasing, the coating of insulators with silicone rubber makes them water-repellent
and greatly improves their performance in polluted environments. Further, the
hydrophobicity is imparted to any covering contaminating layer, providing protection for a
long period even under the most adverse conditions. Unlike grease, though, the silicone
rubber surface is not sticky and exhibits the same natural washing ability as a composite
insulator.
The coating is normally sprayed onto the insulators to a thickness of 0,3 to 0,5 mm. The
preparation of the surface is most important – it must be completely clean and free of all
grease. As a coating is often applied in areas where greasing was previously undertaken,
this can be quite a labour intensive and time-consuming job. The effort is however more
than justified, to ensure the permanent adhesion of the coating.
Figure 12.5: RTV Silicone rubber coating of a 533 kV DC bushing.
The coating life, as for grease, is determined by the relationship between the ambient
pollution severity and the creepage distance and quality of the insulator to which it is
applied. It is however significantly longer than that of grease and can exceed 10 years.
The condition of the coating can be simply checked by spraying it with water and
confirming its continued hydrophobicity.
Figure 12.6: Hydrophobicity of a coated insulator after four years service at a site
adjacent to a power station and open cast coal mine.
If re-coating is found to be necessary, the insulator surface can be rubbed with a soft,
mildly abrasive pad to remove any loose material, thoroughly rinsed to wash off any
conductive deposits, and then the new material can be sprayed over the old.
Owing to their beneficial surface characteristics and resistance to degradation by electrical

and climatic stresses, RTV silicone rubber coatings provide long term security against
flashover from both pre-deposited and instantaneous pollutants and are suitable for use in
all types of environment, even those affected by high levels of non-soluble deposits.
12.5 Creepage / Shed Extenders
When faced with the problem of existing insulators that are not suited to the pollution
severity of the site at which they are located, as an alternative to improving their surface
characteristics by greasing or coating, consideration can be given to increasing their
creepage distance. This is normally achieved by the use of shed extenders, these being
polymeric disc-shaped devices which attach to the perimeters of the insulator sheds.
As for new insulator designs, the geometry of the modified profile should still meet the
requirements of IEC 60815, tabulated in Section 3.3.4. For example, if the shed spacing-
to-projection ratio is very low after the extenders have been fitted, the additional creepage
may appear acceptable in terms of quantity but could be of low quality.
The biggest problem with shed extenders, however, is caused by the difference in surface
characteristics between the polymeric material of the extender and the glass or glazed
ceramic of the insulator. With the extenders usually being more hydrophobic, they act as
permanent dry bands, causing severe distortion of the field distribution along the insulator.
The resultant partial discharge activity can precipitate premature flashover and damage
the extenders. The effect is well illustrated in Section 3.4.8, Figure 3.11 (c).
Creepage extenders should not be confused with booster sheds. The latter are designed
to prevent the flashover of insulators of poor profile under conditions of heavy wetting.
12.6 Insulator Upgrading
Insulator upgrading is an engineering process aimed at providing a permanent,

maintenance-free solution to the pollution flashover of substation insulators that cannot
practically be replaced. It involves:
• A detailed audit of every type of insulator in the substation yard recording all their
relevant geometric parameters such as diameter, shed projection, shed spacing and
creepage distance,
• Analysis of the environment in terms of pollution severity and climatic influences - this
may include the use of dust gauge or ESDD measurements and the investigation of
insulator performance history,
• From the above, the establishment of the minimum requirements for the insulators
with regard to creepage distance and profile, and the identification of those units that
do not meet such requirements,
• The design of shed extenders and their placement to bring all units in the yard up to
the required standard,
• Thorough cleaning of the insulators and the fitting of the shed extenders where
necessary,
• Silicone rubber coating of all insulators to improve their performance and to provide
uniform hydrophobic surface characteristics to those units equipped with extenders.
Figure 12.7: The fitting of shed extension pieces prior to coating.

This upgrading method thus represents a more scientific approach to the prevention of
pollution flashover by combining two different mitigation techniques in a controlled manner
to yield significant improvement in security of supply. Moreover, such a combination
eliminates the disadvantages of the two techniques, namely, the limited life of coatings
when applied to very under-dimensioned insulators in severe environments and the critical
stress concentrations arising when extenders are used on their own.
12.7 Mitigation Method Selection
The choice of corrective action to be taken when pollution flashovers are experienced will
be influenced by applicability, accessibility, risk and cost. These factors are examined
below.
12.7.1 Applicability
For various situations the options available may be limited. For example, the preferred
action may be to replace a particularly vulnerable insulator with one of more suitable
design. However, if no such insulator is available this will not be possible. Or, perhaps, if
the lead time to acquire such a replacement is too long, other mitigation measures may
have to be introduced in the interim period.
12.7.2 Accessibility
Often the strategic nature of the installation does not permit long or frequent outages and
only procedures that can be undertaken under live conditions can be considered. Or,
such procedures have to be employed until such time as a major shut-down can be
organised and a more permanent solution adopted.
12.7.3 Risk
It must be appreciated that the various mitigation techniques provide different levels of
protection. Washing provides the least protection as the correct timing is very difficult to
establish. Further, if undertaken live, additional risk is introduced owing to the possibility
of precipitating a breakdown from overspray, etc. In the case of instantaneous events,
washing provides no protection at all.
Greasing offers a lower risk than washing does as its beneficial surface properties serve
to combat flashover between replacements, even when unexpected conditions are
experienced. However, if not renewed timeously, the probability of flashover is increased.
Because of its longer life and inherent hydrophobicity, coating, offers excellent protection
and a lower risk of flashover than grease.
If properly designed, the replacement or upgrading of insulation represents not only the
most permanent solution but also that with the lowest flashover risk.
12.7.4 Cost
Because of the wide variety of insulator types, applications, environments, material prices
and labour charges in different parts of the world, a detailed financial comparison of the
mitigation levels is not practically possible. However, to obtain a general indication of the
relative costs, the case of a 132 kV substation insulated to a level of 20 mm/kV(Um) in a
“heavy” environment, operating over a period of 30 years, was examined.
The maintenance frequencies for the different procedures were assumed to be:
Washing : 0,75 years

Greasing : 1,5 years
Coating : 7,5 years
Upgrading : 15 years
These figures are fairly conservative – coatings in similar circumstances are still
performing well after more than 12 years in service and it is hoped that suitably upgraded
insulators would provide trouble-free operation for more than 20 years.
Taking cleaning as 100%, the relative long-term costs are:
Washing : 100%
Greasing : 810%
Coating : 100%
Upgrading : 110%
It should be noted that the above figures are based on the lower labour rates of
developing countries and also do not include any cost of the supply interruptions whilst the
maintenance is undertaken.
For transmission lines, it has been shown that re-insulation represents only about 20% of
the long-term cost of helicopter live spray washing.
12.8 Conclusions
The merits, risks and costs of the various mitigation measures are summarised in Table
12.2. Figure 12.8 (located inside the back cover) shows a flow chart to indicate which
techniques are appropriate for different insulator types, applications and pollution
conditions. These two diagrams together serve to assist in the selection of corrective
actions which will be both technically acceptable and cost-effective.
Table 12.2: Merits, risks and costs of various mitigation measures.
Mitigation Risk of Relative

Advantages Disadvantages
Method Flashover Cost
High frequency
Effective pollution removal
Washing Long outages
(Dead)
Unskilled labour
Timing problem
High 100%
No capital equipment
Not for instantaneous pollution
High frequency
Timing problem
Not for all types of pollution
Washing Specialised equipment
(Live)
No outage required
Skilled operator
High 100%
Added risk of flashover
Needs low conductivity water
Not for instantaneous pollution
High material cost

Hydrophobic surface High labour cost
Silicone Encapsulates contaminants Long outages
Greasing Good for instantaneous pollution Unpleasant task
Medium 810%
Longer maintenance interval Not for “bulky” contaminants
Insulator damage if left too long
Hydrophobic surface
Silicone Transfers hydrophobicity
Initial material and labour cost
Rubber Good for instantaneous pollution
Skilled applicator
Low 100%
Coating Good for “bulky” contaminants
Long life
Hydrophobic surface
Transfers hydrophobicity
Requires insulator audit
Insulator Increased creepage distance
Upgrading Improved shed profile
Initial material and labour cost Negligible 110%
Skilled designer & applicator
Good for instantaneous pollution
Good for “bulky” contaminants
Identified Pollution
Problem
Overhead Lines Substations
Strung Busbar Insulators Station Posts Apparatus Housings
Porcelain, Glass
Polymeric Insulators Porcelain, Glass, Resin Silicone Rubber Porcelain, Resin
Insulators
Instantaneous Pre - deposit Non - Silicone Rubber Instantaneous Pre - deposit Instantaneous Pre - deposit
Silicone Rubber
Pollution Pollution Pollution Pollution Pollution Pollution
Instantaneous Pre - deposit

Bird Streamer Conductive Fog Bird Streamer All other Pollution Bird Streamer High NSDD Low NSDD High NSDD Low NSDD
Polution Pollution
Install Bird Guards
Clean
Silicone Grease
Silicone Coat
Silicone Coat with

Extenders
Replace Insulator
Figure 12. 8: Flowchart of mitigation techniques.

176
Definitions
Definitions of important terms used in this book are provided below for reference
purposes. Most are taken from the International Electrotechnical Commission (IEC)
publications relating to the specification, dimensioning and testing of high voltage
outdoor insulators.
TERM DEFINITION
Annealed glass Glass which has been treated to eliminate internal stresses.
Shortest distance in air external to the insulator between metallic

Arcing distance parts which normally have the operating voltage between them.
Note: The term “dry arcing distance” is also used.
An insulator comprising an insulating part having the form of a

disc or bell, with or without ribs on its lower surface, and fixing
Cap-and-pin insulator
devices consisting of an outside cap and an inside pin attached
axially.
A coupling consisting of a ball, a socket and a locking device,

Ball and socket coupling
and providing flexibility.
A device that enables one or several conductors to pass through

a partition such as a wall or tank and insulates the conductors
Bushing
from it. The means of attachment (flange or fixing device) to the
partition forms part of the bushing.
A bushing in which a desired voltage grading is obtained by an

Capacitance graded
arrangement of conducting or semi-conducting layers
bushing
incorporated into the bushing material.
The appearance of some particles of the filler of the housing

Chalking
material forming a rough or powdery surface.
A hollow insulator which is used as a housing, for example, the

Chamber insulator
arc extinction chamber of a circuit breaker.
The female part of a clevis and tongue coupling with a U-shaped

opening into which the tongue can be fitted. It contains two holes
Clevis
through which the coupling pin may pass to couple the two
components.
Clevis and tongue A coupling consisting of a clevis, a tongue and a clevis pin and
coupling providing limited flexibility.
A bushing in which the major insulation consists of a

Composite bushing
combination of at least two different insulating materials.
An insulator that consists of at least two insulating parts, namely,

a tube and a housing. The housing may consist either of
individual sheds mounted on the tube, with or without an
Composite hollow
intermediate sheath, or directly applied in one or several pieces
insulator
onto the tube. A composite hollow insulator unit is permanently
equipped with fixing devices or end fittings and is open from end
to end.
177
An insulator made of at least two insulating parts, namely a core

and a housing equipped with metal fittings. It can, for example,
Composite insulator consist either of individual sheds mounted on the core, with or
without an intermediate sheath, or alternatively, of a housing
directly moulded or cast in one or several pieces onto the core.
That part of the tube or core and that part of the fixing devices
Connection zone
which transmit the load between them.
The internal insulating part of a composite insulator designed to

Core of a composite ensure the mechanical characteristics. The core usually consists
insulator of glass fibres which are positioned in a resin-based matrix in
such a manner as to achieve maximum tensile strength.
The part of the metal fitting which transmits the load to the
Coupling
accessories external to the insulator.
The rigid pin which passes through the holes in the clevis and
tongue to couple them together. On one end the coupling pin
Coupling pin
has a stud head; on the other, a security device (e.g. split pin) is
placed to hold the pin in its place.
Crack Any surface fracture of depth greater than 0,1 mm.
Surface micro-fractures of depths approximately 0,01 mm to

Crazing
0,1mm.
The shortest distance, or sum of the shortest distances, along

Creepage distance the surface of an insulator between those parts which normally
have the operating voltage between them.
The limit below which mechanical loads can be applied, at room

Damage limit temperature, without micro-damage to the composite tube or
core.
The displacement of a point on an insulator, measured

Deflection under bending
perpendicularly to its axis, under the effect of a load applied
load
perpendicularly to this axis.
At least the upper limit of differential pressure reached between

Design pressure the interior and exterior of a hollow insulator during operation at
the design temperature.
The highest temperature reached inside a hollow insulator which

Design temperature
can occur under service conditions.
The DC voltage which an insulator withstands dry, under the

Dry DC withstand voltage
prescribed conditions of test.
Dry lightning impulse The lightning impulse voltage which the insulator withstands dry,
withstand voltage under the prescribed conditions of test.
The arithmetic mean value of the measured voltages which

Dry power frequency
cause flashover of a dry insulator, under the prescribed
flashover voltage
conditions of test.
Dry power frequency The power frequency voltage which the insulator withstands dry,
withstand voltage under the prescribed methods of test.
178
Dry switching impulse The switching impulse voltage which the insulator withstands
withstand voltage dry, under the prescribed conditions of test.
Electromechanical failing The maximum load reached when a string insulator unit or a
load rigid insulator is tested under the prescribed conditions of test.
A device forming part of an insulator intended to connect it to a

End fitting
supporting structure, an item of equipment or another insulator.
ESDD is the amount of salt (NaCl) expressed in mg/cm2 that

Equivalent salt deposit would yield the same conductivity as that of the actual deposit
density (ESDD) on the surface of an insulator dissolved in the same amount of
water.
An irreversible and non-conducting degradation of the surface of

Erosion
an insulator that occurs by loss of material.
A disruptive discharge, external to the insulator, connecting

Flashover those parts which normally have the operating voltage between
them.
A factor determined from the insulator dimensions. For graphical

estimation of the form factor, the reciprocal value of the insulator
Form factor
circumference is plotted against the partial creepage distance
measured from the end of the insulator up to the point reckoned.
A bushing in which the space between the inside surface of the

Gas-filled bushing insulating envelope and the solid major insulation is filled with
gas (other than ambient air) at atmospheric pressure or higher.
A bushing in which the major insulation consists of a core wound

from paper or plastic film and subsequently treated and
Gas-impregnated bushing impregnated with gas (other than ambient air) at atmospheric
pressure or higher, the space between the core and the
insulating envelope being filled with the same gas.
A bushing in which the major insulation consists of gas (other

Gas-insulated bushing
than ambient air) at atmospheric pressure or higher.
A glassy surface layer on the insulating part of a ceramic

Glaze
insulator.
Highest voltage for The highest continuous rms value of phase-to-phase voltage for
equipment (Um) which the equipment is designed in respect of its insulation.
The highest value of operating voltage which occurs under

Highest voltage of a
normal operating conditions at any time and at any point in the
system
system.
An insulator which is open from end to end, with or without

Hollow insulator
sheds, including the fixing devices or end fittings.
A hollow post consisting of one unit or an assembly of more

Hollow post insulator units intended to give support to a live part, which is to be
insulated from earth or from another live part.
The external insulating part of a composite insulator which

Housing (of composite provides the necessary creepage distance and protects the core
insulator) or tube from the environment. Any intermediate sheath made of
insulating material is a part of the housing.
179
Hydrolysis due to water penetration in liquid form or as water

Hydrolysis vapour, can take place in the materials of a composite insulator
and lead to electrical and/or mechanical degradation.
Hydrophobic and hydrophilic describe the two extreme levels of

wettability of a surface by water. A hydrophobic surface has low
Hydrophobicity/
surface tension and is water-repellent. The opposite to this is a
Hydrophilicity
hydrophilic surface that has a high surface tension and thus is
wetted by water (in the form of a film).
The peak value of the impulse voltage which the insulator

Impulse puncture
withstands without puncture under the prescribed conditions of
withstand voltage
test.
The selection of the dielectric strength of equipment in relation to

the voltage which can appear on the system for which the
Insulation co-ordination equipment is intended and taking into account the service
environment and the characteristics of the available protective
devices.
A device intended for electrical insulation and mechanical fixing

Insulator of equipment or conductors which are subject to potential
differences.
An assembly of one or more insulator strings suitably connected

Insulator set together, complete with fixing and protective devices as required
in service.
Two or more string insulator units coupled together and intended

Insulator string to give flexible support to overhead line conductors and stressed
mainly in tension.
The surface between the different materials or parts of a

composite insulator. Various interfaces exist in most composite
insulators, e.g.,
Interfaces, of a composite – between glass fibres and impregnating resin
insulator – between filler particles and polymer
– between core and housing
– between sheath and sheds
– between housing, core and metal fittings.
The conductance of the pollution layer multiplied by the form

Layer conductivity
factor, generally expressed in µS.
Leakage current The flow of current over the surface of an insulator.
A rigid insulator consisting of one or more components of

insulating material permanently assembled with a metal base
Line post insulator
and sometimes a cap, intended to be mounted rigidly on a
supporting structure.
A suspension or tension insulator consisting of an approximately

Long rod insulator cylindrical insulating part provided with sheds and equipped at
the ends with external or internal metal fittings.
Maximum mechanical The highest mechanical load which is expected to be applied to

load an insulator in service.
The maximum load reached when an insulator is tested under

Mechanical failing load
the prescribed conditions of test.
180
A device forming part of an insulator intended to connect it to a

Metal fitting supporting structure, a conductor, an item of equipment or
another insulator.
Nominal voltage of a A suitable approximate value of voltage used to designate or

system identify a system.
Non-soluble deposit The amount of non-soluble material in the deposit on a given

density (NSDD) surface of an insulator divided by the area of this surface.

from paper and subsequently treated and impregnated with an
Oil-impregnated paper insulating liquid, generally transformer oil. The core is contained
bushing in an insulating envelope, the space between the core and the
insulating envelope being filled with the same insulating liquid as
that used for impregnation.
A bushing, both ends of which are intended to be in ambient air

Outdoor bushing at atmospheric pressure and exposed to outdoor atmospheric
conditions.
A bushing, one end of which is intended to be in ambient air and

Outdoor immersed exposed to outdoor atmospheric conditions and the other end to
bushing be immersed in an insulating medium other than ambient air,
e.g. oil or gas.
A bushing, both ends of which are intended to be in ambient air

at atmospheric pressure. One end is intended to be exposed
Outdoor-indoor bushing
and the other end not to be exposed to outdoor atmospheric
conditions.
Any voltage between one phase conductor and earth or between

Overvoltage phase conductors having a peak value exceeding the
corresponding peak of the highest voltage for equipment.
A post insulator having two metal parts, a cap partly embracing

the insulating component and a pedestal cemented into a recess
Pedestal post insulator in the insulating component; the cap normally has tapped holes
and the pedestal a flange with plain holes for attachment by
bolts or screws.
A rigid insulator consisting of an insulating component intended

to be mounted rigidly on a supporting structure by means of a
Pin insulator pin passing up inside the insulating component which consists of
one or more pieces of insulating material permanently connected
together.
An insulator whose insulating body consists of one or more

Polymeric insulator organic based materials. Fixing devices may be attached to the
ends of the insulating body.
An insulator intended to give rigid support to a live part which is

Post insulator
to be insulated from earth or from another live part.
That part of the creepage distance on the illuminated side of an

Protected creepage
insulator which would lie in shadow were light projected on to the
distance
insulator at 90° to the longitudinal axis of the insulator.
A disruptive discharge passing through the solid insulating

Puncture material of the insulator which produces a permanent loss of
dielectric strength.
181
The voltage which causes puncture of an insulator under the

Puncture voltage
prescribed conditions of test.
The maximum mechanical load which can be reached when an

Residual mechanical insulator unit, which has had its insulating part mechanically
strength damaged in the prescribed manner, is tested under the
prescribed conditions.

from untreated paper and subsequently impregnated with
Resin-impregnated paper
curable resin. It can be provided with an insulating envelope, in
bushing
which case the intervening space shall be filled with an
insulating liquid or other insulating medium.
A polymeric insulator whose insulating body consists of a solid

Resin insulator shank and sheds protruding from the shank made from only one
organic based housing material (e.g. cycloaliphatic epoxy).
A glaze having a resistivity lower than that of a usual ceramic

Semi-conducting glaze material or glaze so that its surface resistance generally lies in
the range of 104 Ω to 107 Ω
An insulator consisting of one component of insulating material

Shackle insulator and intended to be secured to the structure by means of a
spindle passing through it.
Shank, of a polymeric
The section between two adjacent sheds.
insulator
An insulating part projecting from the core of an insulator

Shed intended to increase the creepage distance. The shed can be
with or without ribs.
An insulator of which the core is solid and composed only of

Solid core insulator
homogeneous insulating material.
The distance between two consecutive points recurring in

Spacing
repetitive positions on an insulator or insulator assembly.
Specified mechanical load The SML is the load specified by the manufacturer which is used
(SML) for mechanical tests.
Standard lightning An impulse voltage having a front time of 1,2 µs and a time to
impulse voltage half-value of 50 µs.
Standard short-duration A sinusoidal voltage with frequency between 48 Hz and 62 Hz

power frequency voltage and duration of 60 seconds.
Standard switching An impulse voltage having a time to crest of 250 µs and a time to
impulse voltage half-value of 2500 µs.
A cap-and-pin insulator or long rod insulator of which the fixing

String insulator unit devices are suitable for flexible attachment to other similar string
insulator units or to connecting accessories.
The male part of a clevis and tongue coupling with a tongue-

shaped extremity which fits into the U-shaped opening of the
Tongue
clevis and which contains a hole through which the coupling pin
may be passed.
182
Glass in which pre-stresses have been created in order to

Toughened glass
improve its mechanical characteristics.
An irreversible degradation by formation of paths starting and

developing on the surface of an insulating material. These paths
Tracking are conductive even under dry conditions. Tracking can occur on
surfaces in contact with air and also on the interfaces between
different insulating materials.
An irreversible degradation consisting of the formation of micro-

channels within the material which can be conducting or non-
Treeing
conducting. These micro-channels can progressively extend
through the bulk of the material until electrical failure occurs.
The internal insulating part of a composite hollow insulator

designed to ensure the mechanical characteristics. The tube is
generally cylindrical or conical but may have other shapes, e.g.
Tube
barrel. The tube is made of resin-impregnated fibres. These
fibres are structured in such a manner as to achieve sufficient
mechanical strength.
Wet power frequency The arithmetic mean of the measured rms voltages which cause
flashover voltage flashover of an insulator under the prescribed conditions of test.
Wet power frequency The rms power frequency voltage which an insulator withstands
withstand voltage wet, under the prescribed conditions of test.
Wet switching impulse The peak switching impulse voltage which an insulator
withstand voltage withstands wet, under the prescribed conditions of test.
Wettability The ability of a surface to be wetted by a liquid, e.g. water.
The wettability or hydrophobicity class is a specified level as

used in the spray method of wettability measurement. Class 1
Wettability class
corresponds to the most hydrophobic surface and Class 7 to the
most wettable.
A piece of zinc metal fused to the base of an insulator pin shank

Zinc collar to protect it from electrolytic corrosion by acting as a sacrificial
electrode.
The rms value of the power frequency voltage which, under the
50% power frequency
prescribed conditions of test, has a 50% probability of producing
flashover voltage
flashover.
The peak value of the lightning impulse voltage which, under the
50% dry lightning impulse
prescribed conditions of test, has a 50% probability of producing
flashover voltage
flashover.
The peak value of the switching impulse voltage which, under

50% wet switching
the prescribed conditions of test, has a 50% probability of
impulse flashover voltage
producing flashover.
183
List of Abbreviations
ABBREVIATION DESCRIPTION
AAAC All aluminium alloy conductor
ACSR Aluminium conductor steel-reinforced
AISI American Iron and Steel Institute
ASTM American Society for Testing and Materials
ATH Alumina trihydrate
B&S Ball-and-socket couplings
BIL Lightning impulse withstand voltage (Basic Insulation Level)
C&T Clevis and tongue couplings
CF Creepage factor
CFL Cantilever failing load
Cigre International Council on Large Electric Systems
CLP Composite line post
CLR Composite long rod
D Disc insulator
DDG Directional deposit gauge
E Electrical glass
E-field Electric field
E-CR Electrical acid-resistant glass
EMFL Electromechanical failing load
EML Extraordinary mechanical load
EPDM Ethylene propylene diene monomer
EPM Ethylene propylene monomer
EPR Ethylene propylene rubber
ESDD Equivalent salt deposit density
ESL Equivalent static load factor
EVA Ethylene vinyl acetate
FOS Factor of safety
FRP Fibre-reinforced plastic
HTV High temperature vulcanised
HVDC High voltage direct current
184
IEC International Electrotechnical Commission

IPMR Insulator pollution monitoring relay
IR Infrared
ISO International Standards Organisation
KIPTS Koeberg Insulator Pollution Test Station
LESDD Localised equivalent salt deposit density
LSR Liquid silicone rubber
Mav One minute failing load
MDCL Maximum design cantilever load
MFL Minimum mechanical failing load
NSDD Non-soluble deposit density
PDMS Polydimethylsiloxane
PE Polyethylene
PF Profile factor
PLP Porcelain line post
PLR Porcelain long rod
PTFE Polytetrafluoroethylene
RI Radio interference
RIV Radio interference voltage
rms Root mean squared
RTV Room temperature vulcanised
SIL Switching impulse withstand voltage (Switching Impulse Level)
SML Specified mechanical load
SR Silicone rubber
TOV Temporary overvoltage
UV Ultraviolet
WC Wettability class
185
List of Symbols
SYMBOL DESCRIPTION
A Cross-sectional area of the electrolytic pollution layer, in mm2
a Arcing distance of one disc insulator
Acon Cross-sectional area of conductor
Ains Washed/sampled area of insulator surface, in cm2
Ao Input acceleration on the ground surface

Apol Cross-sectional area of the electrolytic pollution layer at position l, in mm2
B1 Foundation amplification factor

B2 Acceleration magnification for a supporting frame
bi Ice density
BIL Lightning impulse withstand value, in kV

C Compression force on an insulator
c Shed clearance
C1 Constant
C2 Constant
CF Creepage factor
Cf Climatic factor
CFL Required minimum cantilever failing load
D Number of days that dust gauge collecting jars were installed

Distance from the point of application of the load to the top edge of the base
d
metal fitting of a line post insulator
D(l) Diameter of insulator at position l along the insulator creepage path, in mm
Dbus Distance between the busbars, in m

dc Conductor diameter
DDG Directional deposit gauge conductivity, in µS/cm
Dm Number of dry months (< 20 mm of precipitation) per year
E Modulus of elasticity
EMFL Required minimum electromechanical failing load

186
ESDD Equivalent salt deposit density, in mg/cm2
ESL Equivalent static load factor

F Insulator form factor
f Natural frequency of a system

Fa Horizontal force owing to conductor tension
Fd Number of fog days per year
Fh Wind load on a conductor
FH Total horizontal force on an insulator
Fp Permissible cantilever load of a station post insulator

Fs Equivalent cantilever force
Fsc Short-circuit force per unit length of busbar
Ft Maximum tensile load to which the insulator is subjected
Fv Vertical load to be supported by an insulator
Fw Wind load on an angle suspension insulator

g Acceleration due to gravity
gf Gust factor
H Average tower height, in m
Hcg Height of the centre of gravity of the equipment

hpol Thickness of the uniform electrolytic pollution layer, in mm
I Moment of inertia
Iδ The creepage distance measured between the two points that define δ
Ihighest The highest measured peak amplitude of the leakage current in ampere
Peak amplitude of the leakage current in ampere, a half cycle immediately
Imax
preceding flashover
Irms Short circuit current, rms, symmetrical wave, in amps
Is Creepage distance measured between the two points that define S
k Creepage distance of one disc
k1 Constant = 7.6
k2 Constant = 0.35
kt Temperature constant
187
LCD Total insulator creepage distance, in mm
L Longitudinal load on an insulator
l Length of resistive element
Larc Arcing distance of an insulator
LESDD Localised equivalent salt deposit density, in mg/cm2
Lins Length of a station post insulator

Lline Line length, in km
Lspan Span length
M1 Weight of dry clean filter paper, in mg
M2 Weight of dry contaminated filter paper, in mg
mc Conductor mass per unit length
Mc Compressive force
Me Bending moment on station post insulator

MFL Minimum failing load
Mmax Maximum permissible bending moment
Mt Tensile force
N Number of expected direct strikes to the shield wire or structure per year
n Number of disc insulators in a string
Ng Ground flash density, in strokes to ground per km2 per year
NSDD Non-soluble deposit density, in mg/cm2
P Shed projection – the maximum shed overhang
P1 Shed projection of larger alternating shed
P2 Shed projection of smaller alternating shed
Pa Atmospheric pressure
P0 Standard atmospheric pressure of 101.3 kPa or 760 mmHg
Pb Tensile load on a brace insulator
PF Profile factor
PI Dust deposit gauge pollution index, in µS/cm
Pp Compressive load on a braced line post insulator
Pw Maximum wind pressure

188
q Damping factor
qi Radial ice thickness
R Resistance, in MΩ
Rc Critical insulator resistance in MΩ, the critical value of Rpol
Rpol Surface layer resistance of the electrolytic pollution layer, in MΩ
S Shed spacing
s Spacing of a disc insulator
Sbus Maximum distance between busbar supports

Sa The salinity, in kg/m3 of the solution at 20 °C
Samf Acceleration magnification factor

SCD Specific creepage distance, in mm/kV
sf Shape factor
SIL Switching impulse withstand voltage, in kV

Sm Weight span
Sw Wind span
T Tension force on an insulator
t Air temperature
The conductor tension, without wind, at the temperature at which the maximum
Tw
wind speeds are assumed to occur
t0 Standard ambient temperature of 20 °C
T1 Conductor tension under condition 1
t1 Conductor temperature under condition 1
T2 Conductor tension under condition 2
t2 Conductor temperature under condition 2
ts Solution temperature, in °C
Um Maximum rms system voltage phase to phase, in kV
Un System power frequency operating voltage rms phase to phase, in kV

Va Withstand voltage of air
V Vertical load on an insulator
V0 Withstand voltage at standard atmospheric conditions

189
Vc Critical insulator flashover voltage, in kV
Vd Volume of distilled water used, in cm3
W Line width, in m
Wt Total mass of the equipment
W1 Mass per unit length of conductor under condition 1
W2 Mass per unit length of conductor under condition 2
α Angle of line post insulator to the horizontal
αt Coefficient of linear expansion
β Angle between a line post insulator and its brace insulator
γ Angle of deviation of an overhead line
δ The straight air distance between any two points on the shed surface
θ The angle to which the insulator is deflected from the vertical
ρ Volume resistivity, in MΩ.mm
ρpol Volume resistivity of the electrolytic pollution layer, in MΩ.mm
σ Volume conductivity of the insulator electrolytic pollution layer, in µS/mm
σd Volume conductivity of distilled water used
σs Surface conductivity of the insulator electrolytic pollution layer, in µS
σt Measured volume conductivity, in µS/cm
σ20 Volume conductivity corrected to 20 °C

190
References
[1] CIGRE Working Group 33-04, “The measurement of site pollution severity and
its application to insulator dimensioning for a.c. systems”, Electra No. 64, 1979.
[2] RG Houlgate, “Natural testing of composite insulators at Dungeness insulator

testing station”, Non-ceramic outdoor insulation international workshop, SEE,
Paris, France, April 1993.
[3] MP Verma, H Niklasch, W Heise, G F Luxa, H Lipken, H Schreiber, "The

criterion for the pollution flashover and its application to insulation dimensioning
and control." Cigre Report 33-09, 1978.
[4] JP Holtzhausen, “A critical evaluation of AC pollution flashover models for HV

insulators having hydrophilic surfaces”, PhD Thesis, University of Stellenbosch,
South Africa, 1977.
[5] Electra No. 161, “Service performance of composite insulators used on HVDC
lines”, August 1995.
[6] HJ Geldenhuys, "The effect of lightning on distribution lines", Seminar – “The

lightning protection of distribution lines”, SAIEE and CSIR, August 1989,
Pretoria.
[7] HJ Geldenhuys, "Shielded line performance", Seminar – “The lightning

protection of distribution lines”, SAIEE and CSIR, August 1989, Pretoria.
[8] EPRI, “Transmission Line Reference Book, 345 kV and above”, Second edition,
1987.
[9] Y Mizuno, H Nakamura, K Naito, “Dynamic simulation of risk of flashover of

contaminated ceramic insulators”, IEEE Transactions on Power Delivery, Vol.
12, No. 3, July 1997.
[10] RS Gorur, EA Cherney, JT Burnham, “Outdoor Insulators”, Ravi S Gorur Inc,

Phoenix, Arizona, USA, 1999.
[11] G Besztercey, GG Karady, DL Ruff, “A novel method to measure the

contamination level of insulators – spot contamination measurement”, IEEE
International symposium on electrical insulation, Arlington VA, USA, June 1998.
[12] IEC 60507, “Artificial pollution tests on high-voltage insulators to be used on a.c.
systems”, 1991.
[13] IEC 60305, “Insulators for overhead lines with a nominal voltage above 1000 V -
Ceramic or glass insulator units for a.c. systems - Characteristics of insulator
units of the cap and pin type”, 1995.
[14] IEC 62217, “Polymeric insulators for indoor and outdoor use with a nominal
voltage greater than 1000V – General definitions, test methods and acceptance
criteria”, to be issued.
191
[15] IEC 61109, “Composite insulators for a.c. overhead lines with a nominal voltage
greater than 1000 V – Definitions, test methods and acceptance criteria”, 1992.
[16] IEC 61952, “Composite line post insulator for a.c. overhead lines with a nominal
voltage greater than 1 000 V – Definitions, tests methods and acceptance
criteria”, 2002.
[17] IEC 62231, “Composite Station Post Insulators for Substations with a.c.
voltages greater than 1000 V up to 245 kV - Definitions, test methods and
acceptance criteria”, to be issued.
[18] Electra No. 140, “Enhancement of seismic performances of existing

substations”, February 1992.
[19] F Schmuck, C de Tourreil, “Brittle fracture of composite insulators: an

investigation of their occurrence and failure mechanisms and a risk
assessment”, Cigre 4th Southern Africa Regional Conference, Cape Town,
October 2001.
[20] C de Tourreil, et al, “Brittle fracture of composite insulators: the new explanation
and a field case study”, ISH 2001, paper 5-25, Bangalore, India, August 2001.
[21] Electra No. 143, “Guide for the identification of brittle fracture of composite
insulator FRP rod”, August 1992.
[22] N van der Merwe, “An Investigation into the Qualities of New and Field Aged
Cycloaliphatic Epoxide Insulation in the Republic of South Africa”, Masters
Degree in Engineering Sciences at the University of Stellenbosch, December
2000.
[23] WL Vosloo, JP Holtzhausen, “The Design Principles of On-Line Insulator Test

Stations to be used on Power Distribution and Transmission Networks”
AFRICON96, Stellenbosch, South Africa, 1996.
[24] WL Vosloo, R Swinny, JP Holtzhausen, "Koeberg insulator pollution test station

(KIPTS) - an in-house insulator product ageing test standard", CIGRE 4th
Southern Africa Regional Conference, Cape Town, October 2001.
[25] IEC 60071 "Insulation co-ordination", Part 1: Terms, definitions, principles and
rules (1993), Part 2: Application Guide (1996).
[26] IEC 60433, “Insulators for overhead lines with a nominal voltage above 1 000 V
- Ceramic insulators for a.c. systems - Characteristics of insulator units of the
long rod type”, 1998.
[27] IEC 60720, “Characteristics of line post insulators”, 1981.
[28] IEC 60273, “Characteristic of indoor and outdoor post insulators for systems
with nominal voltages greater than 1000 V”, 1990.
[29] IEC 60815, “Guide for the selection of insulators in respect of polluted
conditions”, 1986.
[30] IEC 60120, “Dimensions of ball and socket couplings of string insulator units”,
1984.
192
[31] IEC 60471, “Dimensions of clevis and tongue couplings of string insulator units”,
1977.
[32] IEC 61466, “Composite string insulator units for overhead lines with a nominal
voltage greater than 1000 V. Part 1: Standard strength classes and end
fittings”, 1997.
[33] Electra No. 169, "Review of "In Service Diagnostic Testing" of Composite
Insulators", December 1996.
[34] C de Tourreil and M. Ishiwari, "Assessment of the State of Insulators on Live

Transmission Lines", Paper P1-04, CIGRE Session 2000, Paris, Aug.-Sept.
2000, pp. 1-6.
[35] GH Vaillancourt et al, “New Live Line Tester For Porcelain Suspension
Insulators on High-Voltage Power Lines”, IEEE Transactions on Power Delivery,
Vol. 9 No. 1, January 1994.
[36] T Kikuchi et al, “Remote Sensing System for Faulty Suspension Insulator Units”,
Proceedings of 5th International Conference on Properties and Applications of
Dielectric Materials, 1997, Seoul, Korea.
[37] WL Vosloo, GR Stolper, P Baker, “Daylight corona discharge observation and

recording system”, 10th International Symposium on High Voltage Engineering
(ISH), Montreal, Canada, September 1997.
[38] JT Burnham, "Bird streamer flashovers on FPL transmission lines", IEEE

Transactions on Power Delivery, Volume 10, No.2, April 1995.
[39] RE Macey and WL Vosloo, “Outages of the Brand-se-Baai 132kV feeder – the
insulator problem that wasn’t”, Cigre 4th Southern Africa Regional Conference,
Cape Town, October 2001.
193
Index
CHAPTER or SECTION
Acceleration magnification factor 6.2.3.2
Accumulated charge 5.1.1, 5.5
Acid 7.3.2
Acoustic emission, detection 11, 11.1.3, 11.1.3.3
Air 3, 4.2.2, 4.2.9
Air density 4.2.9
Alligatoring, Alligator skin 7.3.1, 11.1.3.1
Angle of deviation 6.1.3, 6.2.1
Angle suspension insulators 6.1.3
Arcing distance 2.2, 2.2.1, 3.1, 3.2, 3.3.4, 9.2.3.1
Arcing horns, protection 3.4.3, 5.4.1, 7.2, 10.2, 10.3.1, 10.9.2, 11.1.2
BIL 2.3, 3.2, 3.4.7, 9.2.1, 9.2.3.1, 9.2.3.3
Birds 7.3.1
Bird streamer 3.4.6, 4, 4.4.1, 11.3
Booster shed 12.5
Braced post insulator 6.2.2
Brinell hardness 5.4
Brittle fracture 7.3.2, 7.3.4, 10.1
Bushing 2.3, 8.1
Cap see “End fitting”
Cap-and-pin disc insulator see “Disc insulator”
Cascade failure 2.1.4, 6.2.3, 7.2, 10.10.1
Cement 5.1.2.1, 12.2.1
Alumina 5.1.2.1, 7.2
Characteristics 5.1.2.1
Growth 5.1.2.1, 7.2
Lead antimony 5.1.2.1, 7.2, 11.1.2
Portland 5.1.2.1, 7.2
Properties 5.1.2.1
Sulphur 5.1.2.1, 7.2
Chalking 7.3.1, 7.4
Class
Insulator 2.2.4, 3.4.1, 5.1.1, 6.1.4.2, 7.2, 7.4, 9.1.2, 9.4, 10.1
Pollution severity 3.3.3, 4.3.3, 4.3.3.1, 9.1, 9.1.1
Wettability 11.1.3.2
Cleaning 12.2, 12.2.1, 12.2.5, 12.6
Dry 12.2.4
Climatic factor 4.3.3.2
Coating see “Silicone rubber coating”
Coefficient of linear expansion 5.1.1, 5.4, 6.1.1
Coefficient of thermal expansion 5.1.2.1
194
Composite Insulators 1.1, 2.1.4, 2.3, 5.3.1, 5.3.1.1, 5.4.4, 6.1.4.3, 6.1.4.4,
7.3, 7.3.1, 7.3.2, 8.2, 9.1, 9.2.3.1, 9.2.3.3, 10, 10.1,
10.2, 10.4, 10.7, 10.8, 10.9.1, 11.1.3, 11.1.3.1,
11.1.3.5, 11.1.3.6, 11.1.3.7
Construction 5.3.1.3, 7.3.1
Conductive fog 12.2.5
Conductor stringing 10.8
Conductor tension 6.1.1, 6.1.3
Connecting length 9.2.3.1, 10.3.2, 12.1
Core 2.1.4, 2.3, 5.3.1.1, 6.1.4.5, 6.2.1, 7.3.1, 7.3.2, 7.3.3,
7.3.5, 10.1, 10.3.2, 10.6, 10.7, 10.7.1, 10.7.2, 10.8,
10.9.1, 11.1.3.1
Corona 3.4.2, 3.4.8, 11, 11.1.3.2, 11.1.3.3, 11.1.3.4
Corona ring 10.2, 10.3.1, 10.7.1, 10.7.2, 10.9.1, 10.9.2, 11.1.3.6
Corrosion 4.4.5, 5.4.2, 11.1.1
Cost 1.2, 12.7.4, 12.8
Crack, cracking 7.2, 7.3.1, 7.4, 10, 10.1, 10.3, 10.6, 10.7, 10.8, 10.9.2,
10.9.3, 11.1.3.1
Formation 2.1.1
Propagation 2.1.2
Micro 2.1.2
Crazing 7.3.1
Creepage distance 2.2, 2.2.2, 3.3.2, 3.3.3, 3.3.4, 3.4.5, 7.3.1, 9.1.1,
9.2.3.1, 9.2.3.2, 9.4, 12.1, 12.3, 12.5, 12.6, 12.8
Creepage extenders see “Shed extenders”
Creepage factor 3.3.4
Damage limit 6.1.4.3, 6.1.4.5, 6.2.1, 7.3.2
Damping factor 6.2.3.2
Deflection 2.1.4, 6.1.4.4, , 6.1.4.5, 6.2.3, 9.2.2, 10.7, 10.9.1
Degreasing agent 12.2.1
Delamination 7.3.2, 10.1, 10.8, 11.1.3.1
Detergents 12.2.1
Dielectric constant 5.3.1.2
Dielectric strength 5.1.1, 5.3.1.2, 7.1, 7.2, 12.3
Directional dust deposit gauge 4.3, 4.3.2, 4.3.3.2, 12.6
Disc insulator 1.1, 2.3, 2.4, 4.3.1.1, 5.1.2.1, 6.1.2, 6.1.4.1, 6.1.4.2,
7.1, 7.2, 8.1, 9.1, 9.1.1, 9.1.3, 9.2.2, 9.2.3.1, 9.2.3.3,
10.7, 10.9.2, 11.1.2, 11.1.2.1, 11.1.2.2, 11.1.2.3,
11.1.3.6
Aerodynamic 2.4
Antifog 2.4
Replacement 3.4.8
Standard 2.4
Dissipation factor 5.3.1.2
Dry band 3.3.1, 3.4.8, 5.1.1, 7.1, 7.2, 12.5
Dust gauge see “Directional dust deposit gauge”
Electrical discharge 2.1.1, 5.1.1, 7.1, 7.2, 7.3.1, 7.3.2, 7.3.3, 7.3.4, 7.4,
9.1.1, 11, 11.1.3.2, 11.1.3.4, 11.1.3.5, 11.1.3.7, 12.5
Electric field 3.4.8, 11, 11.1.2, 11.1.2.3, 11.1.3, 11.1.3.5, 11.1.3.6,
11.1.3.7, 12.5
195
End fittings 2.1.3, 2.3, 2.5, 5.4, 5.4.3, 5.4.4, 7.1, 7.3.2, 7.3.4,
7.3.5, 7.4, 9.2.3.3, 9.4, 10.2, 10.3, 10.3.1, 10.7,
10.9.1, 10.9.2, 11.1.3.1
Ball 2.5, 8.1, 9.2.3.3, 10.3.2, 10.8, 10.10.2
Cap 5.4.1, 11.1.2.1, 11.1.2.2
Clevis 2.5, 8.1, 9.2.3.3, 10.3.2, 10.9.1, 10.10.1, 10.10.2
Drop tongue 2.5
Eye 2.5, 9.2.3.3
F-neck 2.5
Flange base 2.5
Gain base 2.5, 10.7.1
Socket 2.5, 8.1, 9.2.3.3, 10.3.2, 10.7, 10.8, 10.10.2
Stud base 2.5
Swivel base 2.5
Tongue 2.5, 8.1, 9.2.3.3, 10.3.2, 10.9.1, 10.10.2
Trunnion 2.5, 10.7.1, 10.10.2
Y-clevis 2.5, 9.2.3.3
EPDM 2.1.4, 5.3.1.2, 5.3.1.2.2, 7.3.1, 9.1
Equivalent salt deposit density 4.3.1.1, 4.3.3.1, 4.3.4.3, 12.6
Erosion 2.1.2, 2.1.3, 2.1.4, 7.1, 7.3.1, 7.3.2, 7.3.3, 7.3.4, 7.4,
9.1.1, 11.1.1, 11.1.3.1, 11.1.3.4
ESDD 4.3.1.1, 4.3.3.1, 4.3.4.3, 12.6
Extrusion 5.3.1.3.2
Factor of safety 6.1.4.1, 6.1.4.2, 6.1.4.3, 6.2.1, , , 6.2.3.2,
Fibreglass 2.1.4, 5.3.1.1
Filament winding 5.3.1.1
Flashover
Back 3.4.7, 4.2.8, 11.3
Bird streamer 3.4.6, 11.3
Impulse 2.2.1, 3.2
Instantaneous 3.4.4
Lightning impulse 3.2, 2.2.3, 11.3
Local 3.4.8
Pollution 3.3, 4.2.9, 11.1.3.2, 11.3, 12, 12.3, 12.6
Power frequency 2.2.1, 3.1, 3.4.4, 7.4
Risk 12.7.3, 12.8
Switching impulse 3.2
Flash mark 11.1.1, 11.1.2, 11.3
Fog 4.2.4, 12.2.5
Footing resistance 3.4.7, 4.4.3, 11.3
Form factor 3.3.2
Foundation amplification factor 6.2.3.2
Galvanising 10.3.3, 12.2.1
Glass 2.3, 5.1.1, 5.2, 5.2.1, 7.1, 9.1, 9.1.3, 10, 11.1.1, 12.5
Composition 5.2.1
Construction 5.2.2
E glass 2.1.4, 5.3.1.1
E-CR glass 2.1.4, 5.3.1.1
Fibres 5.3.1.1, 6.1.4.5, 7.3.2
Manufacture 5.2.1
Properties 5.1.1, 5.2.1
Glaze 2.1.1, 5.1.1
Semi-conducting 5.1.1
Resistive 5.1.1, 5.5
196
Grading ring see “Corona ring”

Grease, greasing see “Silicone grease”
Gust factor 6.1.2
Guy wires 2.3
Handling 10, 10.1, 10.6, 10.11
Hand washing see “Cleaning”
Hollow core insulator 5.3.1.1, 5.3.1.3.4, 5.4.5, 6.2.3, 7.3.2, 8.2
Hollow insulator 2.3, 5.1.2.4, 5.4.5, 8.1
Hoop stress 7.3.1
Housing 2.1.4, 2.3, 5.3.1.2, 7.3.1, 7.3.3, 7.3.5, 10.1, 10.2, 10.3,
10.3.3, 10.4, 10.6, 10.7, 10.7.1, 10.7.2, 11, 11.1.3.5
Hydrolysis 4.2.2, 5.3.2, 7.3.1, 7.3.2
Hydrophilic 3.3.1, 5.3.1.2.1, 11.1.3.2
Hydrophobic, hydrophobicity 2.1.4, 3.3.1, 3.4.5, 5.3.1.2.1, 5.3.2, 5.5, 8.2, 9.1.1,
11.1.3, 11.1.3.2, 12.1, 12.3, 12.4, 12.5, 12.6, 12.7.3,
12.8
Hydrophobicity transfer 5.3.1.2.1, 12.8
Ice 3.4.4, 4, 4.2.7, 6.1.1, 6.1.2
IEC 1.3, 8, 9.2.1, 9.2.2, 9.2.3.1, 9.2.3.2, 9.2.3.3, 9.4
Imax 3.3.2
Image intensifier 11.1.3.4
Infrared 11.1.3, 11.1.3.5, 11.1.3.7
Instantaneous pollution 3.4.5, 4.1, 4.1.2, 4.1.3, 4.3, 4.3.4.3, 9.1, 9.1.1, 12.2.5,
12.3, 12.4, 12.7.3, 12.8
Insulator class 2.2.4, 3.4.1, 5.1.1, 6.1.4.2, 7.2, 7.4, 9.1.2, 9.4, 10.1
Insulator pollution monitoring device 4.3, 4.3.4.3
Insulators
Apparatus 1.1, 2.3, 8.1, 8.2, 9.1
Braced post 6.2.2
Cap-and-pin disc 1.1, 2.3, 2.4, 4.3.1.1, 5.1.2.1, 6.1.2, 6.1.4.1, 6.1.4.2,
7.1, 7.2, 8.1, 9.1, 9.1.1, 9.1.3, 9.2.2, 9.2.3.1, 9.2.3.3,
10.7, 10.9.2, 11.1.2, 11.1.2.1, 11.1.2.2, 11.1.2.3,
11.1.3.6
Composite 1.1, 5.3.1, 5.3.1.1, 5.3.1.3, 5.4.4, 6.1.4.3, 6.1.4.4,
6.1.4.5, 7.3, 8.2, 9.1, 9.2.2, 9.2.3.3, 11.1.3, 11.1.3.1,
11.1.3.5, 11.1.3.6, 11.1.3.7
Guy wire 2.3
Guy strain 2.3
Hollow 2.3, 5.1.2.4, 5.4.5, 8.1
Hollow core 5.3.1.1, 5.3.1.3.4, 5.4.5, 6.2.3, 7.3.2, 8.2
Line post 2.3, 5.1.2.3, 6.2.1, 8.1, 9.1, 9.1.2, 9.2.2, 9.2.3.1,
9.2.3.3, 10.4, 10.7, 10.7.1, 10.8, 10.9.1, 10.10.4,
Long rod 11.1.3.1, 1.1, 2.3, 5.1.2.2, 6.1.2, 6.1.4.1, 7.2, 8.1, 8.2,
9.1, 9.1.2, 9.2.2, 9.2.3.3, 10.7.2, 10.9.2, 10.10.1,
10.10.4, 11.1.2
Motor 1.1
Pedestal post 2.3
Pin 2.3, 6.2.1, 7.4, 9.1, 9.1.3, 11.1.2.1
Post 1.1, 5.2.2.2, 8.1, 8.2
Resin 5.3.2, 7.4, 9.1
Station post 2.3, 5.1.2.3, 5.2.2.2, 5.4.3, 6.2.3, 8.1, 8.2, 9.1, 9.2.2,
9.2.3.1, 9.2.3.3, 12.1
197
Stay wire 2.3

Telegraphic 1.1
International Electrotechnical Commission 1.3
Ionic migration 5.2.1, 7.1
Johnny ball 2.3
Leakage current 2.1.1, 3.3.1, 3.3.2, 4.3.4.3, 4.3.4.4, 5.1.1, 5.5,
11.1.2.1, 11.1.3.2, 12.2.2, 12.2.5, 12.3
Erosion 2.1.2, 2.1.3, 2.1.4, 7.1, 7.3.1, 7.3.2, 7.3.3, 7.3.4, 7.4,
9.1.1, 11.1.1, 11.1.3.1, 11.1.3.4
Leakage distance see “Creepage distance”
Light amplification 11.1.3, 11.1.3.4, 11.1.3.5, 11.1.3.7
Lightning 4.2.8, 9.1, 9.1.1, 9.4
Direct strikes 3.4.7, 4.2.8
Ground flash density 3.4.7, 4.2.8
Induced 3.4.7, 4.2.8
Isoceraunic level 4.2.8, 9.1.2
Line post insulator 2.3, 5.1.2.3, 6.2.1, 8.1, 9.1, 9.1.2, 9.2.2, 9.2.3.1,
9.2.3.3, 10.4, 10.7, 10.7.1, 10.8, 10.9.1, 10.10.4,
11.1.3.1
Load/time curve 6.1.4.3
Loads (Forces)
Application curve 6.2.1, 6.2.2
Buckling 6.1.4.4, 6.2.3
Cantilever (bending) 6.2, 6.2.1, 6.2.3.2, 7.3.2, 9.1, 10.1, 10.7.2, 10.8,
10.9.1, 10.9.2, 10.10.1
Compressive 6.1.4.4, 6.2.1, 6.2.2
Deflection curve 6.2.3
Electromechanical failing 6.1.4.2
Equivalent static 6.2.3.1
Extraordinary mechanical 6.1.4.3
Internal pressure 7.3.2, 9.1
Longitudinal 6.2.1, 6.2.2
Maximum design cantilever 6.2.1
Mechanical 6
Mechanical failing 6.1.4.1
One minute failing 6.1.4.3
Seismic 6.2.3.2, 9.1
Short circuit 6.2.3.1
Specified mechanical 6.1.4.3
Tensile 6.1, 6.1.1, 6.1.2, 6.2.2, 7.3.2, 9.1
Torsional 6.1.4.5, 7.3.2, 10.1, 10.8, 10.9.1, 10.9.2, 10.10.2
Wind 6.1.2, 6.1.3, 6.2.1
Localised ESDD 4.3.4.1
Locking devices 2.5, 8.1, 11.1.1, 11.1.2
Long rod insulator 1.1, 2.3, 5.1.2.2, 6.1.2, 6.1.4.1, 7.2, 8.1, 9.1, 9.1.2,
9.2.2, 9.2.3.3, 10.7.2, 10.9.2, 10.10.1, 10.10.4, 11.1.2
Marking 10.2
Materials 2.1, 5
Alumina trihydrate 5.3.1.2.1, 5.3.1.2.2, 5.3.2
Aluminium alloy 5.4, 5.4.1, 5.4.4, 5.4.5, 7.3.5
Cycloaliphatic resin 2.1.3, 5.3.2, 7.4
Ductile cast iron 5.4, 5.4.1, 5.4.3, 5.4.4, 5.4.5
E glass 2.1.4, 7.3.2
E-CR glass 2.1.4, 7.3.2
EPM 7.3.1, 9.1
Epoxy resin 2.1.3, 5.3.1.1, 5.3.1.2, 7.4
198
Ethylene propylene diene monomer 2.1.4, 5.3.1.2, 5.3.1.2.2, 7.3.1, 9.1, 9.1.1
(EPDM)
Fibreglass 2.1.4
Glass 2.1.2, 2.3, 5.1.1, 5.2, 5.2.1, 5.2.2, 7.1, 9.1, 9.1.3, 10,
11.1.1, 12.5
Glaze 2.1.1, 5.1.1
Malleable cast iron 5.4, 5.4.1, 5.4.3, 5.4.4, 5.4.5
Polyester 2.1.4
Polymeric 2.1.4, 8.2, 9.1.3, 12.5
Polytetrafluoroethylene 5.3.1.2
Porcelain 2.1.1, 2.3, 5.1.1, 7.2, 9.1, 9.1.1, 11.1.2, 11.1.2.1,
11.1.2.3, 11.1.3.6, 12.5
Resin 2.3, 7.4, 9.1, 9.1.1
Silica flour 2.1.3
Silicone rubber 2.1.4, 3.3.1, 3.3.2, 5.3.1.2, 5.3.1.2.1, 5.5, 7.3.1, 9.1,
9.1.1, 11.1.3.2, 12.1, 12.4
Steel 5.4, 5.4.1, 5.4.2, 5.4.4,
Vinyl ester 2.1.4
Metal fittings see “End fittings”
Micro-cracks 2.1.2, 5.1.1
Modulus of elasticity 5.1.1, 5.4, 6.1.1, , 6.2.1, , 6.2.3.2
Moisture ingress 2.1.4, 7.3.2, 7.3.4
Moment of inertia 6.2.1, 6.2.3.2,
Moulding 5.3.1.3.1
Mould line 2.1.3, 2.1.4, 5.3.1.3.1, 7.3.1
Natural frequency 6.2.3.2,
Night vision see “Light amplification”
Non-soluble deposit density 4.3.1.2, 4.3.3.1
Nozzle pressure 12.2.2
NSDD 4.3.1.2, 4.3.3.1
Overvoltage 2.2.3, 3.1, 3.2, 3.4.9, 7.2
Partial discharge see “Electrical discharge”
Pin 5.4.2, 10.7, 10.9.3, 11.1.1, 11.1.2.1, 11.1.2.2
Pin corrosion 4.3.4.4, 7.1, 7.2, 9.1.1
Pollution 1.3, 9.4, 11.1.2.1, 11.1.2.2, 11.1.2.3, 11.1.3.6
Active 4.1.1, 4.3.1, 4.3.1.1
Agricultural 4.1.3
Assessment 4.3, 4.3.1, 4.3.1.1, 4.3.1.2, 4.3.2, 4.3.3, 4.3.3.1,
4.3.3.2, 4.3.4, 4.3.4.1, 4.3.4.2, 4.3.4.3, 4.3.4.4, 11.3
Desert 4.1.3
Industrial 2.1.4, 4, 4.1.3
Inert 4.1.1, 4.3.1, 4.3.1.2
Instantaneous 3.4.5, 4.1, 4.1.2, 4.1.3, 4.3, 4.3.4.3, 9.1, 9.1.1, 12.2.5,
12.3, 12.4, 12.7.3, 12.8
Marine 2.1.4, 4.1.3
Mitigation 12, 12.6, 12.7, 12.7.1, 12.8
Pre-deposited 4.1, 4.1.1, 4.1.3, 4.3, 4.3.4.3, 9.1, 9.2.3.2, 12.2.5, 12.4
Severity 3.3.3, 4.3, 4.3.5, 4.3.5.1, 4.3.5.2, 9.1, 9.1.1, 9.4, 12.6
Sources 4.1.3
Pollution flashover 3.3, 4.2.9, 11.1.3.2, 11.3, 12, 12.3, 12.6
Pollution flashover process 3.3.1, 4.1
Pollution index 4.3.2, 4.3.3.2
199
Pollution layer 3.3.1, 3.3.2

Pollution severity class 3.3.3, 4.3.3, 4.3.3.1, 9.1, 9.1.1
Porcelain 2.1.1, 2.3, 5.1.1, 7.2, 9.1, 9.1.1, 11.1.2, 11.1.2.1,
11.1.2.3, 11.1.3.6, 12.5
Alumina 5.1.1
Glazing 5.1.1
Isostatic 5.1.1
Manufacture 5.1.1
Properties 5.1.1
Silica 5.1.1
Slip 5.1.1
Porosity 5.1.1
Porosity 5.1.1
Power arc 2.1.1, 5.4.1, 7.1, 7.2, 7.3.5, 8.1, 11.1.3.1
Power arc resistance 3.4.3, 9.4
Pre-deposited pollution 4.1, 4.1.1, 4.1.3, 4.3, 4.3.4.3, 9.1, 9.2.3.2, 12.2.5, 12.4
Profile see Shed profile
Profile factor 3.3.4
Pultrusion 5.3.1.1
Puncturable 2.2.4, 3.4.1
Puncture 3.4.1, 2.1.1, 2.1.2, 4.2.8, 5.1.1, 7.1, 7.2, 7.3.1, 7.3.3,
7.4, 8.1, 9.1.2, 9.1.3, 10.1, 11, 11.1.2.1, 11.1.2.2,
11.1.3.1
Puncture detector 11.1.2.1
Puncture distance 2.2, 2.2.3
Radio interference/influence voltage, RIV 8.1, 9.4, 11, 11.1.2, 11.1.3
Rain 4, 4.2.3, 12.2.5
Relative humidity, humidity 4, 4.2.2, 11.1.2.1, 11.1.2.2, 11.1.2.3, 11.1.3.6,
11.1.3.7
Relative permittivity 5.1.1
Resin insulator 5.3.2, 7.4, 9.1
Rodents 7.3.1, 10.2, 10.6
Sacrificial electrode 5.4.1, 7.1
Salt deposit density 4.2.5
Seismic 2.1.4, 4, 4.4.4, 6.2.3, 8.1, 9.1
Shape factor 6.1.2
Shatter, Shattering 2.1.2, 5.2.1, 7.1, 10, 10.6, 11.1.1
Sheath 2.3, 5.3.1.3.2, 10.1, 10.9.1, 11.1.3.1
Shed 2.3, 2.4, 10.2, 10.3, 10.3.1, 10.3.2, 10.3.3, 10.6, 10.7,
10.7.1, 10.7.2, 10.9.1, 10.9.2, 11.1.3.1, 11.1.3.4,
11.1.3.6, 12.3, 12.5
Clearance 3.3.4, 9.2.3.2
Extenders 12.5, 12.6
Projection 3.3.4, 12.6
Spacing 3.3.4, 3.4.4, 12.6
Spacing-to-projection ratio 3.3.4, 9.2.3.2, 12.5
Splitting 7.3.1, 11.1.3.1
Un-bonded 5.3.1.3.3, 7.3.1, 10.9.1
Shed profile 2.4, 3.3.4, 3.4.5, 9.4, 12.1, 12.3, 12.6, 12.8
Aerodynamic 2.4, 3.3.4, 9.2.3.2
Alternating 2.4, 3.3.4
200
Antifog 2.4
Normal 2.4
Plain 2.4, 3.3.4
Standard 2.4
Under-ribbed 2.4, 3.3.4
Shield 10.6
SIL 3.2, 9.2.1
Silicone rubber 2.1.4, 3.3.1, 3.3.2, 5.3.1.2, 5.3.1.2.1, 5.5, 7.3.1, 9.1,
9.1.1 11.1.3.2, 12.1, 12.4
Silicone grease, greasing 7.3.1, 12.1, 12.3, 12.4, 12.5, 12.7.3, 12.7.4, 12.8
Silicone rubber coating 12.3, 12.4, 12.5, 12.6, 12.7.3, 12.7.4, 12.8
Snow 3.4.4, 4, 4.2.7
Solar radiation see “Ultra-violet radiation”
Spark erosion 5.4.2
Specific creepage distance 2.2.2, 3.3.2, 3.3.3, 9.2.3.2
Specifications 8, 9.4
Spray washing, washing 11.3, 12.1, 12.2, 12.2.2, 12.7.3, 12.7.4, 12.8
12.2.3
Fixed systems
SSD 4.2.5
Standards 8
Station post insulator 2.3, 5.1.2.3, 5.2.2.2, 5.4.3, 6.2.3, 8.1, 8.2, 9.1, 9.2.2,
9.2.3.1, 9.2.3.3, 12.1
Stay wires 2.3
Steep-fronted impulse 2.2.3, 5.1.1, 7.1, 7.2, 7.4, 9.1.2
Storage 10.4, 10.6
Strain insulator 6.1.1, 6.1.4.5
Strength
Cantilever 2.1.1, 5.1.1, 9.2.2, 9.2.3.3, 9.4
Compressive 2.1.1, 2.1.2, 5.1.1, 5.1.2.1,
Dielectric 2.1.2
Electromechanical 6.1.4.2, 9.2.3.3
Insulator 6.1.4, 9.2.3.3
Mechanical 6.1.4, 9.2.3.3
Residual 8.1, 9.4
Tensile 2.1.1, 2.1.4, 5.1.1, 5.4, 9.2.2, 9.2.3.3, 9.4
Stress corrosion fracture see “Brittle fracture”
Surface conductivity 3.3.2, 4.3.4.3, 12.3
Hand probe 4.3.4.2
Surface deposit index 4.3.3.1
Surface resistance 3.3.2, 3.3.3
Surge arresters 3.4.7, 12.2.2
Suspension insulators 6.1.2,
Temperature 4.2.1, 11.1.3.5, 11.1.3.7
Temperature elevation 11.1.3.5
Temporary overvoltage 3.4.9
Termites 7.3.1
Tests, testing 8.1, 8.2
Thermal conductivity 5.1.1
201
Thermal cycling 7.4

Thermal run-away 7.1
Thermal shock 3.4.3, 5.1.1, 5.2.1, 7.1
Thermography 11.1.3, 11.1.3.3, 11.1.3.5, 11.1.3.7
Tracking, tracks 7.3.1, 7.3.2, 7.3.3, 7.3.4, 7.4, 11.1.3.1
Tracking resistance 2.1.4, 5.3.1.2
Transport 10.3, 10.5, 10.6
Turnbuckle 10.8, 10.10.2
Ultraviolet imager 11.1.3.4, 11.1.3.7
Ultraviolet radiation 2.1.1, 2.1.2, 2.1.3, 2.1.4, 3.4.2, 4, 4.2.6, 5.1.1,
5.3.1.2.2, 5.3.2, 7.3.1, 7.4, 11.1.3.5, 12.3
Unpuncturable 2.2.4, 3.4.1
Upgrading 12.6, 12.7.3, 12.7.4, 12.8
V-string 6.1.4.4,
Vandalism 4.4.6, 7.1, 7.2, 9.1, 9.1.3, 9.4
Voltage
Corona extinction 3.4.2
Lightning impulse flashover/withstand 2.3, 9.2.1, 9.2.3.1, 9.4
Operating, system 1.3, 3.1, 9.1, 9.2.1, 9.4, 12.2.2
Power frequency flashover/withstand 7.4, 9.2.1, 9.4
Puncture 3.4.1, 9.4
Switching impulse flashover/withstand 3.2, 9.2.1, 9.2.3.1, 9.4
Transfer 3.4.8
Volume conductivity 3.3.2
Volume resistivity 3.3.2, 5.1.1, 5.1.2.1, 5.3.1.2
Washing frequency 12.2.5, 12.8
Water repellent 2.1.4
Water resistivity 12.2.2
Weather 4.2
Weight span 6.1.2, 6.1.4.4, 10.7
Wettability see “Hydrophobicity”
Wettability class 11.1.3.2
Wind 4, 4.2.5, 6.1.1, 6.1.2, 6.1.3, 6.2.1,
Wind span 6.1.2, 6.1.4.4
Working distance 12.2.2
Working platform 10.7.1, 10.7.2
Young’s modulus see “Modulus of Elasticity”
Zinc collar (ring or sleeve) 7.2
about the book . . .
This book is a practical guide for utility staff and consulting engineers responsible for the selection,
installation and maintenance of insulators for outdoor high voltage lines and substations.
Students and engineers in training will also greatly benefit.
Insulator types and their characteristics, electrical, mechanical, material and environmental
considerations, insulator selection, tests and specifications, failure mechanisms, handling and
installation practices, line and substation performance improvement, and pollution mitigation techniques
are all dealt with in detail, with emphasis on practical field application.
Easy to use procedures, guides, decision tables, flowcharts, inspection sheets and software are
included. IEC standards and SI units are used throughout.
Everything you need to know practically about outdoor high voltage insulators . . .
about the authors . . .

Wallace Vosloo (Pr.Eng, NHD, BSc (Physics), PhD (Eng.Sci), MSAIEE, MIEEE)
Dr. Vosloo is Chief Consultant of TSI (Technology Services International), a
division of Eskom Enterprises, South Africa. He is a recognised consultant
in the field high voltage insulators, and has been a keynote presenter on
high voltage insulators at several international conferences, and courses.
He recently obtained his PhD degree in the field of polymeric insulators. He
has received several awards for his expertise in the field of high voltage
insulators, including: Best paper award at the International Symposium for
High Voltage Engineering, Canada; the SAIEE President’s award for his
contributions in the filed of high voltage insulator research; the Eskom
Technology Group’s research project of the year award for the publication
“Insulator Pollution Maintenance Guide”. He is currently an active member
of the Cigre and IEC working groups.
Roy Macey (Pr.Eng, MSc (Eng), SMSAIEE, MIEEE)

Mr. Macey has been involved in the study of the performance,
maintenance, and design of high voltage insulators since 1971. He
established the first energized insulator test stations in South Africa. In
1980 he received an MSc (Eng) degree for his thesis "The Performance of
Outdoor High Voltage Insulation in Polluted Environments". A technical
paper of the same title presented to the SAIEE received the SA Transport
Services award. He has also received a Telemecanique Electrical Design
award and a Shell Design award for his design of 22 kV overhead line
insulators. Roy is a Distinguished Member of Cigre and has represented
South Africa on Study Committee B2 (Overhead lines) and as a member of
Working Group 03 (Insulators).
Claude de Tourreil (M.Eng, PhD (Eng), SMIEEE)

Dr de Tourreil is presently a consultant in the field of insulators. He received
his first engineering degree in Switzerland and subsequently his M.Eng and
PhD degrees from McMaster University and University of Waterloo,
Canada, respectively. He worked for more than 20 years at IREQ, mainly in
the field of composite insulators. He is the author or co-author of about 100
technical papers or presentations. He is a member or chairman (convener)
of several IEC, IEEE and CIGRE Working Groups, all related to insulators.

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W L VOSLOO

THE PRACTICAL GUIDE TO

We would like to thank Dr H Schneider for the writing of the foreword, Dr JP

HOW TO USE THE BOOK xi

1.1 Historical Overview 1

2 INSULATOR TYPES AND CHARACTERISTICS 4

2.1 Insulator Materials 4

3.1 Dry and Wet Power Frequency Flashover 17

6.1 Tensile Loads 69

7.1 Glass Insulators 93

8 TESTS AND SPECIFICATIONS 108

8.1 Porcelain and Glass Insulators 108

9 INSULATOR SELECTION AND SPECIFICATION 114

9.1 Insulator Type and Material 114

10 HANDLING AND INSTALLATION PRACTICES 125

10.1 Mechanisms of Failure 125

11 INSPECTION AND ANALYSIS TECHNIQUES 150

11.1 Field Inspection Methods 151

12.1 Insulator Replacement 164

LIST OF ABBREVIATIONS 183

LIST OF SYMBOLS 185

“The Practical Guide to Outdoor High Voltage Insulators” is intended to

The emphasis of the book is definitely on the “practical”, and simple

In Chapter 3 the electrical aspects to be considered when selecting

It is impossible to select a suitable insulator for a particular application unless

The various electrical, mechanical and environmental factors which determine

A variety of insulator inspection methods is described in Chapter 11. The

Finally, Chapter 12 addresses what measures may be taken when the

The accompanying CD contains an imperial to SI unit conversion calculator,

“He who measures knows” – Wallace L Vosloo

1.1 Historical Overview

Interestingly, many present-day insulators look practically the same as insulators

Figure 1.2: Old and new cap-and-pin disc insulators.

Figure 1.3: Early composite insulator.

1.2 The Critical Role of Insulators

A consequence resulting from the selection of an insulator of inferior quality or of an

1.3 Increased Requirements

Figure 1.4: A 66 kV power line under construction in 1912.

1.4 Future Demands

2 INSULATOR TYPES AND CHARACTERISTICS

2.1 Insulator Materials

Consideration of the properties of the insulating materials to be used is an important part

The characteristics of porcelain, being a non-homogeneous material produced from

The main positive features of porcelain are:

• its inert, inorganic nature making it immune to degradation by environmental factors

The limitations of porcelain are:

• its brittle nature, making it vulnerable to breakage, chipping and cracking

2.1.2 Toughened glass

The positive features of glass are:

• its resistance to damage by ultraviolet radiation and other environmental effects

The limitations of glass are:

• its mechanical characteristics limit its use to only certain applications

2.1.3 Epoxy resin

The positive features of resins are:

• they can be moulded in many different forms to suit a variety of applications

The limitations of epoxy resins are:

• the possibility of severe leakage current erosion

2.1.4 Polymer composites