EPRI Insulator Reference Book
The Violet Book—2021
3002022036
11762887
11762887
EPRI Insulator Reference Book
The Violet Book—2021
3002022036
Technical Update, November 2021
EPRI Project Manager
T. Shaw
EPRI
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800.313.3774  650.855.2121  askepri@epri.com  www.epri.com
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DISCLAIMER OF WARRANTIES AND LIMITATION OF LIABILITIES
THIS DOCUMENT WAS PREPARED BY THE ORGANIZATION(S) NAMED BELOW AS AN ACCOUNT OF
WORK SPONSORED OR COSPONSORED BY THE ELECTRIC POWER RESEARCH INSTITUTE, INC. (EPRI).
NEITHER EPRI, ANY MEMBER OF EPRI, ANY COSPONSOR, THE ORGANIZATION(S) BELOW, NOR ANY
PERSON ACTING ON BEHALF OF ANY OF THEM:
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IMPLY ITS ENDORSEMENT, RECOMMENDATION, OR FAVORING BY EPRI.
THE FOLLOWING ORGANIZATIONS PREPARED THIS REPORT:
The Electric Power Research Institute (EPRI)
Engelbrecht Consulting B.V
EACH Engineering
SedAfrica
This is an EPRI Technical Update report. A Technical Update report is intended as an informal report of
continuing research, a meeting, or a topical study. It is not a final EPRI technical report.
NOTE
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© 2021 Electric Power Research Institute (EPRI), Inc. All rights reserved. Electric Power Research
Institute and EPRI are registered marks of the Electric Power Research Institute, Inc. in the U.S. and
worldwide.
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ACKNOWLEDGMENTS
The Electric Power Research Institute (EPRI) prepared this report.
Principal Investigators
A. Phillips
F. Bologna
D. Childs
G. Gela
T. Shaw
The following organizations, under contract to the Electric Power Research Institute (EPRI),
contributed to this report:
Engelbrecht Consulting B.V.
Catharinadaal 84
Ede, 6715KD
The Netherlands
Principal Investigator:
C. S. Engelbrecht
EACH Engineering
68 Bridle Path
RR3 Guelph, ON N1H6H9
Canada
Principal Investigator:
E. Cherney
SedAfrica
P.O. Box 25055
Edelweiss, Springs, 1577
South Africa
Principal Investigator
T. Buhler
This report describes research sponsored by EPRI
This publication is a corporate document that should be cited in the literature in the following
manner:
EPRI Insulator Reference Book: The Violet Book—2021. EPRI, Palo Alto, CA: 2021.
3002022036.
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ABSTRACT
High voltage insulators are an essential part of the power delivery system and ensure the reliable
and safe transmission of electricity from generating stations to substations where the voltage is
reduced and distributed to commercial and residential consumers. Insulators provide the
mechanical means by which high voltage wires are suspended from transmission structures while
also providing the required electrical insulation.
When insulators fail either in their mechanical role or their electrical role, system outages occur
plus additional equipment and structure damage. Reducing the risk of failure through proper
installation, inspection, and assessment practices is the focus of ongoing research and utility
engineer training.
EPRI has been researching transmission line insulators for more than 20 years and has developed
many guides and references highlighting how insulators are made, selected, applied, and
maintained. Utility engineers would need to know which report to search through to find answer
related to each subject. EPRI developed this reference book to be a single reference book that
organizes this information into common sections so utility engineers can find all the information
on insulators in a single location.
Keywords
Insulator
Maintenance
Polymer
Porcelain
Specification
Testing
Toughened glass
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CONTENTS
ABSTRACT ..................................................................................................................................V
1 FRONT MATTER .................................................................................................................... 1-1
Background to This Reference Book ................................................................................... 1-1
Overview EPRI Research into Insulators ............................................................................. 1-2
Organization of This Reference Book .................................................................................. 1-4
2 INSULATOR TECHNOLOGY ................................................................................................. 2-1
Historical Perspective........................................................................................................... 2-1
General Insulator Terms and Classification ......................................................................... 2-3
Insulator Classification ................................................................................................... 2-3
Parameters that Characterize Insulators ........................................................................ 2-5
Ceramic and Glass Suspension Disc Insulators ................................................................ 2-17
Overview and Terminology .......................................................................................... 2-17
Dielectric Shell ............................................................................................................. 2-20
Cement ......................................................................................................................... 2-24
Metallic Fittings ............................................................................................................ 2-25
Mechanical Design ....................................................................................................... 2-30
Electrical Design .......................................................................................................... 2-31
Manufacturing of Porcelain Suspension Insulators ...................................................... 2-33
Manufacturing Toughened Glass Suspension Insulators ............................................. 2-39
Polymer Insulators ............................................................................................................. 2-50
Overview and Terminology .......................................................................................... 2-50
Core Rod ...................................................................................................................... 2-54
Metallic Fittings ............................................................................................................ 2-56
Polymer Housing .......................................................................................................... 2-58
Housing – Core Interface ............................................................................................. 2-61
End Fitting Seal ............................................................................................................ 2-62
E-Field Grading Devices .............................................................................................. 2-65
References ......................................................................................................................... 2-67
3 ELECTRICAL PERFORMANCE OF INSULATORS .............................................................. 3-1
Lightning Impulse Flashover Strength of Line Insulation ..................................................... 3-1
Defining the Lightning Impulse Strength of Insulation .................................................... 3-1
Critical Flashover Strength of the Line Insulation ........................................................... 3-3
Electrical Performance of Insulators and Air Gaps Under AC Voltage ................................ 3-6
Introduction .................................................................................................................... 3-6
Dry AC Flashover Strength of Air Gaps and Insulators .................................................. 3-6
Wet AC Flashover Strength of Air Gaps and Insulators ................................................. 3-9
Contamination Flashover Performance of Insulators ......................................................... 3-12
Introduction .................................................................................................................. 3-12
Buildup of Contaminants on Insulator Surfaces ........................................................... 3-16
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Wetting Processes ....................................................................................................... 3-20
Discharge Activity and Development of Flashover ....................................................... 3-22
Contamination Flashover Strength of Insulators .......................................................... 3-30
Performance of Insulators in Freezing Conditions ............................................................. 3-46
Introduction .................................................................................................................. 3-46
Clean- and Cold-Fog Test Results ............................................................................... 3-47
Icing Test Results ......................................................................................................... 3-49
Snow Test Results ....................................................................................................... 3-52
References ......................................................................................................................... 3-53
4 LONG-TERM PERFORMANCE OF INSULATORS ............................................................... 4-1
Introduction .......................................................................................................................... 4-1
Ceramic and Glass Suspension Disc Insulators .................................................................. 4-1
Overview ........................................................................................................................ 4-1
Dielectric Shell ............................................................................................................... 4-2
Cement ........................................................................................................................... 4-9
Metallic Fittings (Cap and Pin) ..................................................................................... 4-11
Failure Modes of Glass Disc Insulators ........................................................................ 4-12
Failure Modes of Porcelain Disc Insulators .................................................................. 4-15
Polymer Insulators ............................................................................................................. 4-18
The Core ...................................................................................................................... 4-20
The End Fittings ........................................................................................................... 4-25
The End Fitting Seals ................................................................................................... 4-28
The Housing ................................................................................................................. 4-30
The Housing – Core Interface ...................................................................................... 4-37
Summary of Failures .................................................................................................... 4-37
References ......................................................................................................................... 4-40
5 ELECTRICAL DESIGN AND SELECTION OF INSULATORS .............................................. 5-1
Design Methodology ............................................................................................................ 5-1
Define Acceptable Performance .................................................................................... 5-1
Characterization of Stresses .......................................................................................... 5-4
Select Insulation Strength .............................................................................................. 5-6
Evaluate Line Performance ............................................................................................ 5-7
Apply Stress Mitigation or Strength Enhancement ......................................................... 5-9
Finalization of Design ................................................................................................... 5-10
Verification of Characteristics ....................................................................................... 5-10
Selection and Dimensioning Insulators .............................................................................. 5-11
Dry Power Frequency Flashover Voltage .................................................................... 5-11
Basic Impulse Insulation Level ..................................................................................... 5-11
Switching Surge ........................................................................................................... 5-12
Contamination .............................................................................................................. 5-12
Characterizing the Environment and its Severity ......................................................... 5-14
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Choice of Material ........................................................................................................ 5-20
Choice of Profile ........................................................................................................... 5-29
The Insulator Dimensioning Process ........................................................................... 5-34
Guidelines for Limiting the Effect of E-Fields on Insulators................................................ 5-51
E-Field Distribution on Polymer Insulators ................................................................... 5-51
E-Field Distribution on Glass and Porcelain Insulators ................................................ 5-67
Other Considerations ......................................................................................................... 5-68
Corrosive Environments ............................................................................................... 5-68
High Temperature Conductor Applications .................................................................. 5-69
Protection Against Power Arc Damage ........................................................................ 5-69
References ......................................................................................................................... 5-69
6 MECHANICAL DESIGN AND SELECTION OF INSULATORS ............................................ 6-1
Introduction .......................................................................................................................... 6-1
Minimum Mechanical Failing Load Rating ........................................................................... 6-1
Description of Testing .................................................................................................... 6-2
References ........................................................................................................................... 6-3
7 SPECIFICATION OF INSULATORS ...................................................................................... 7-1
Introduction .......................................................................................................................... 7-1
Role of Specification and Standards .............................................................................. 7-2
Problem Statement ........................................................................................................ 7-3
Industry Concerns .......................................................................................................... 7-4
Specification of Ceramic and Glass Insulators..................................................................... 7-4
Introduction .................................................................................................................... 7-4
Design/Type Tests in the Standards .............................................................................. 7-7
Quality Conformance/Sample Tests in Standards ....................................................... 7-17
Routine Tests in Standards .......................................................................................... 7-21
Example Specification .................................................................................................. 7-22
Specification of Polymer Insulators .................................................................................... 7-26
Introduction .................................................................................................................. 7-26
Design/Prototype Tests in the Standards ..................................................................... 7-35
Design/Type Tests in the Standards ............................................................................ 7-49
Quality Conformance/Sample Tests in Standards ....................................................... 7-52
Routine Tests in Standards .......................................................................................... 7-53
Non-Standard Tests ..................................................................................................... 7-54
Considerations for Specification ................................................................................... 7-63
Example Specification .................................................................................................. 7-87
References ....................................................................................................................... 7-111
8 APPLICATION........................................................................................................................ 8-1
Introduction .......................................................................................................................... 8-1
Handling and Storage .......................................................................................................... 8-1
Handling and Storage .................................................................................................... 8-2
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On-Site Storage Practices .............................................................................................. 8-4
On-Site Handling Practices ............................................................................................ 8-6
Installation Practices ...................................................................................................... 8-8
Procedures ................................................................................................................... 8-12
Live Working ...................................................................................................................... 8-15
Introduction .................................................................................................................. 8-15
Minimum Approach Distance Concept ......................................................................... 8-16
Protective Gaps for Overvoltage Limitation .................................................................. 8-18
Changeout of Porcelain or Glass to Polymer Insulators............................................... 8-19
Changeout of Polymer Insulator and Replacement with Polymer Insulator ................. 8-25
Considerations for Compact Configurations................................................................. 8-25
References ......................................................................................................................... 8-27
9 IMPACT OF BIRDS ON INSULATOR PERFORMANCE....................................................... 9-1
Introduction .......................................................................................................................... 9-1
Bird Contacts........................................................................................................................ 9-2
Nesting Material Contact ...................................................................................................... 9-3
Soiling of Insulators .............................................................................................................. 9-3
Bird Streamers ..................................................................................................................... 9-6
Damages Caused by Birds .................................................................................................. 9-6
Characteristics of Bird Related Outages .............................................................................. 9-7
Mitigation Techniques-Description, Pros, Cons, and Issues ................................................ 9-8
Preventing Bird Contact Outages ................................................................................... 9-8
Preventing Bird Streamer Flashovers ............................................................................ 9-9
Preventing Bird Contamination Flashovers .................................................................. 9-11
Discouraging Nesting In and On Transmission Structures........................................... 9-12
Choosing Appropriate Counter Measures .................................................................... 9-13
References ......................................................................................................................... 9-14
10 INSPECTION AND ASSESSMENT ................................................................................... 10-1
Introduction ........................................................................................................................ 10-1
Inspection and Assessment of Polymer Insulators ............................................................ 10-1
Visual Inspection .......................................................................................................... 10-2
Discharge Observations ............................................................................................... 10-6
Electric Field Measurement ........................................................................................ 10-19
Inspection Techniques ..................................................................................................... 10-22
Condition Assessment ..................................................................................................... 10-23
High Risk of Failure .................................................................................................... 10-24
Conditions that in the Future May Result in a High Risk of Failure ............................ 10-24
Conditions that May Result in Premature Aging ........................................................ 10-24
Information Gained from and Decisions Based on Inspection Results ...................... 10-25
Approach to Evaluating Existing Populations of Polymer Insulators .......................... 10-26
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Inspection and Assessment of Porcelain and Glass Insulators ....................................... 10-36
Introduction ................................................................................................................ 10-36
Visual Inspection ........................................................................................................ 10-36
Discharge Observations ............................................................................................. 10-39
Electric Field Measurement ........................................................................................ 10-45
Future Technique: EPRI’S Vibration Response Instrument ....................................... 10-47
Approach to Assessing a Population of Porcelain Suspension Insulators ................. 10-48
References ....................................................................................................................... 10-54
A METHODS FOR CONTAMINATION SITE SEVERITY ASSESSMENT ............................... A-1
Environmental Severity Measurement ................................................................................ A-1
Air Pollution Sampling ................................................................................................... A-1
Directional Dust Deposit Gauge .................................................................................... A-1
Equivalent Salt Deposit Density and Non-Soluble Deposit Density .............................. A-6
Surface Conductance .................................................................................................. A-19
Insulator Performance Measurement ................................................................................ A-24
Insulator Flashover Stress .......................................................................................... A-24
Leakage Current Monitoring ........................................................................................ A-26
Summary ........................................................................................................................... A-38
References ........................................................................................................................ A-41
B REQUIREMENTS FOR E-FIELD MODELLING ................................................................... B-1
Introduction ......................................................................................................................... B-1
Building up a Model............................................................................................................. B-1
Where Should the E-Field Be Calculated............................................................................ B-2
Evaluation of the Results .................................................................................................... B-3
References .......................................................................................................................... B-3
C HIGH-VOLTAGE CORONA TEST METHOD FOR POLYMER INSULATORS ................... C-1
Introduction ......................................................................................................................... C-1
Test Setup ........................................................................................................................... C-1
Test Protocol ....................................................................................................................... C-2
Evaluation ........................................................................................................................... C-2
References .......................................................................................................................... C-2
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LIST OF FIGURES
Figure 1-1 Transmission line insulators are exposed to various environmental stresses .......... 1-1
Figure 1-2 Testing to determine critical lengths of defects in polymer insulators above
which live line work should not be performed ...................................................................... 1-3
Figure 2-1 Example of vintage porcelain insulators still in use after over 70 years of
service. ................................................................................................................................. 2-1
Figure 2-2 Number of utilities that apply polymer insulators at each voltage level, as well
as the number of utilities that have transmission lines at each voltage level. The line
indicates the results as a percentage................................................................................... 2-3
Figure 2-3 General overview of insulator types used on transmission overhead lines. ............. 2-4
Figure 2-4 General classification of insulators as Class A or B. ................................................ 2-4
Figure 2-5 Definition of section length. ...................................................................................... 2-5
Figure 2-6 Definition of dry arc distance. ................................................................................... 2-6
Figure 2-7 Definition of strike distance in comparison to dry arc distance and section
length. I-string on the left and V-string on the right. ............................................................. 2-6
Figure 2-8 Definition of leakage distance. .................................................................................. 2-7
Figure 2-9 Protected leakage, or creepage, distance. ............................................................... 2-8
Figure 2-10 Definition of form factor. ......................................................................................... 2-8
Figure 2-11 Insulator measurements. ........................................................................................ 2-9
Figure 2-12 Examples of a hydrophobic and a hydrophilic polymer surface. .......................... 2-12
Figure 2-13 Definition of the static contact angle. .................................................................... 2-14
Figure 2-14 Measuring height and radius of a drop. ................................................................ 2-15
Figure 2-15 Contact angle on an inclined surface. .................................................................. 2-15
Figure 2-16 Standard pictures of the different STRI hydrophobicity classifications. HC7,
a completely wetted surface, is not shown......................................................................... 2-17
Figure 2-17 Components of a ceramic (porcelain) disc insulator. ............................................ 2-18
Figure 2-18 Components of a toughened glass disc insulator. ................................................ 2-18
Figure 2-19 Scanning Electron Micrograph at X1000 magnification showing microcracks
around a large filler particle ................................................................................................ 2-21
Figure 2-20 Sanding layer on the head of a porcelain shell ..................................................... 2-23
Figure 2-21 Cured alumina cement used on a toughened glass insulator ............................... 2-25
Figure 2-22 An example of a cotter key made of phosphor bronze ......................................... 2-26
Figure 2-23 An example of a cap used for a toughened glass insulator .................................. 2-27
Figure 2-24 Examples of insulator pins with and without a sacrificial Zinc sleeve ................... 2-27
Figure 2-25 A close up view of the pin cavity area showing the positioning of the Zinc
sleeve with respect to the cement filling............................................................................. 2-28
Figure 2-26 Examples of various end fitting connection types ................................................. 2-29
Figure 2-27 Mechanical stresses in the suspension insulator resulting from insulator load .... 2-30
Figure 2-28 Corrugations molded into the head of a glass shell .............................................. 2-31
Figure 2-29 Principal dimensions that determine the electrical performance of the
insulator.............................................................................................................................. 2-32
Figure 2-30 Examples of a glass and porcelain anti-fog insulator—notice the deep
under-ribs ........................................................................................................................... 2-32
Figure 2-31 Stages in the manufacture of porcelain shell of suspension insulators. ............... 2-34
Figure 2-32 Illustration of Spacers used in assembly .............................................................. 2-38
Figure 2-33 Examples of different Color Glass ........................................................................ 2-40
Figure 2-34 Glass Shell Manufacturing Process Including “Toughening” ................................ 2-40
Figure 2-35 Examples of Plunger and Mold References on the Glass Shell ........................... 2-41
Figure 2-36 Examples of “Trees” Caused by Thermal Cracks in the Molding Equipment ....... 2-42
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Figure 2-37 Example of Poor Toughening ............................................................................... 2-43
Figure 2-38 Examples of defects that can be identified by visual inspection ........................... 2-45
Figure 2-39 Example of a Platform Fracture Pattern Caused by an Inclusion ......................... 2-47
Figure 2-40 An example of an insulator with a bitumen coating of the cement. ...................... 2-49
Figure 2-41 The pin cavity design of the insulator influences RIV. The shape,
depth (d) and cavity width (s) are important parameters.................................................... 2-49
Figure 2-42 Examples of the markings on an end cap of a toughened glass insulator ........... 2-50
Figure 2-43 The basic components of a composite suspension insulator. ............................. 2-51
Figure 2-44 The basic components of a composite line post insulator. .................................. 2-51
Figure 2-45 A cut-away drawing of a composite insulator showing its core. ........................... 2-54
Figure 2-46 SEM image showing the resin fiber matrix. .......................................................... 2-55
Figure 2-47 The relationship between core diameter and the specified Mechanical
Strength for composite longrod insulators.......................................................................... 2-55
Figure 2-48 The relationship between insulator length, core diameter and the Maximum
design Cantilever load for NGK composite line post insulators. ........................................ 2-56
Figure 2-49 A cut-away drawing of a composite insulator showing its end fittings. ................. 2-56
Figure 2-50 Examples of different end fitting types. ................................................................. 2-57
Figure 2-51 Dissection of different end fittings/rod attachment methods ................................. 2-58
Figure 2-52 A cut-away drawing of a composite insulator showing the housing. .................... 2-59
Figure 2-53 Chemical building block of an EPDM rubber. ....................................................... 2-59
Figure 2-54 Chemical building block of silicone rubber] .......................................................... 2-60
Figure 2-55 A cut-away drawing of a composite insulator showing the housing and
weathershed system. ......................................................................................................... 2-61
Figure 2-56 Different methods of constructing composite insulators ....................................... 2-62
Figure 2-57 A cut-away drawing of a composite insulator showing its end fitting seals........... 2-63
Figure 2-58 Examples of approaches to end fitting seals. ....................................................... 2-64
Figure 2-59 Examples of E-field grading devices. ................................................................... 2-66
Figure 2-60 Examples of corona rings provided by different manufacturers for a range of
applications. Both split ring and horseshoe types are shown. Note the different
attachment mechanisms. ................................................................................................... 2-67
Figure 3-1 Definition of a fast-front transient overvoltage .......................................................... 3-1
Figure 3-2 Definition of the parameters characterizing the Lightning Impulse as per IEEE
Standard 4............................................................................................................................ 3-1
Figure 3-3 Probability for flashover in disruptive discharge tests as a function of the
applied voltage. .................................................................................................................... 3-2
Figure 3-4 Flashover paths for a I, and V-string configuration. .................................................. 3-3
Figure 3-5 Breakdown strength gradient of Rod-Plane gaps under lightning impulse and
standard atmospheric conditions. ........................................................................................ 3-4
Figure 3-6 AC flashover strength of air gaps. ............................................................................ 3-7
Figure 3-7 AC flashover gradient of rod-rod and rod plane gaps under dry conditions.
Note that the rod-plane data is represented by a ban. ......................................................... 3-7
Figure 3-8 Wet rms AC flashover voltage of various shapes of cap-and-pin insulator
strings [29].......................................................................................................................... 3-10
Figure 3-9 Wet rms AC flashover voltage of a silicone rubber insulator. ................................. 3-10
Figure 3-10 Correction factor for rate-of-rain on the AC flashover strength of I-strings. .......... 3-11
Figure 3-11 Correction factor for rainfall resistivity on the ac flashover strength of
insulators. ........................................................................................................................... 3-11
Figure 3-12 Relationship between ac wet flashover and rain conductivity for hydrophobic
and hydrophilic polymer insulators. .................................................................................... 3-12
Figure 3-13 Pollution deposit by aerodynamic action. ............................................................. 3-17
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Figure 3-14 Photographs showing typical particle distribution on aerodynamically
contaminated insulators. Note the concentration of the contaminants in areas of
turbulence, as indicated by the arrows............................................................................... 3-17
Figure 3-15 Airflow around a disc insulator .............................................................................. 3-19
Figure 3-16 Typical steps and their associated voltage distribution, in the discharge
development of contaminated insulators............................................................................ 3-23
Figure 3-17 Example of dynamic surface impedance of standard insulators.
(Salt-deposit density = 0.07 mg/cm2; kaolin = 40 g/l.) Applied voltage per 5¾ in.
(146 mm) disc = 6.3 kV. ..................................................................................................... 3-24
Figure 3-18 Voltage distribution measured from grounded cap before onset of
scintillation for different values of surface impedance magnitude. ..................................... 3-24
Figure 3-19 Typical measurement results of the dynamic voltage distribution on a disc
type insulator under various levels of leakage current. ...................................................... 3-25
Figure 3-20 Equivalent circuit for voltage distribution along contaminated insulator string. .... 3-26
Figure 3-21 Schematic diagram of typical discharge activity on artificially polluted
insulators, as observed during natural wetting conditions.................................................. 3-27
Figure 3-22 Withstand ac contamination performance of standard types of disc insulator
based on the results from Salt-Fog and the Solid-Layer tests. .......................................... 3-31
Figure 3-23 Flashover voltage of antifog insulators in relation to that of a standard-shape
disc. .................................................................................................................................... 3-32
Figure 3-24 Performance of post insulators. ............................................................................ 3-34
Figure 3-25 Influence of the amount of non-soluble material on the contamination
withstand voltage of disc and longrod insulators [39]......................................................... 3-35
Figure 3-26 Influence of various salts in the contamination layer on the insulator fog
withstand voltage. .............................................................................................................. 3-35
Figure 3-27 General effect of inter-skirt breakdown on the creepage distance
requirement of antifog insulators. ....................................................................................... 3-36
Figure 3-28 Discharge development on a porcelain longrod insulator under natural
wetting conditions............................................................................................................... 3-37
Figure 3-29 Results of ac natural contamination tests compared with clean-fog tests. ........... 3-38
Figure 3-30 Long-string efficiency for ac energization as a function of line-to-ground
voltage. Range of ESDD 0.01-0.04 mg/cm2. IEEE insulators (146 mm spacing, 254
mm diameter, and ratio leakage to spacing 2.1). ............................................................... 3-39
Figure 3-31 Long-string efficiency for ac energization as a function of line-to-earth
voltage. Range of ESDD 0.02-0.04 mg/cm2. Antifog insulators (220 mm spacing, 420
mm diameter, and ratio leakage to spacing 3.3). ............................................................... 3-39
Figure 3-32 Flashover voltage over the leakage distance, as a function of the
hydrophobicity class, as determined by modified Clean-Fog tests .................................... 3-42
Figure 3-33 Comparison of the flashover stress of a hydrophobic silicone rubber
insulator [96] to that of a standard-shape disc insulator..................................................... 3-43
Figure 3-34 Cold switch-on flashover voltage as a function of string length. ........................... 3-46
Figure 3-35 Cold-Fog and Clean-Fog flashover strength, kV of line-to-ground voltage per
meter of leakage distance, decreases nonlinearly with increasing pollution level. ............ 3-48
Figure 3-36 Examples of natural ice accretion on various types of transmission line
insulator.............................................................................................................................. 3-49
Figure 3-37 Relation between withstand voltage (line to ground) and icing stress product
for ice, snow, and cold fog accretion. ................................................................................. 3-50
Figure 4-1 Scanning Electron Micrograph at 1000X Showing Microcracks Between an
Alumina Particle and the Glassy Phase in a Porcelain Disc Insulator ................................. 4-2
Figure 4-2 Example of corona discharges between the metal cap and the porcelain shell
of a disc insulator. ................................................................................................................ 4-4
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Figure 4-3 Example of a donut failure of a porcelain insulator ................................................... 4-4
Figure 4-4 On right, an image of corona activity on the first bell of a 765-kV insulator
string with no grading devices installed and on left, corona activity surrounding the
pin of a porcelain insulator disc under dry conditions. ......................................................... 4-5
Figure 4-5 Example Showing an Extreme Loss of Pin- hole Cement in a Porcelain
Suspension Insulator by Corona Discharge That Was Simulated in the Laboratory to
Deter- mine the Loss of Mechanical and Electrical Strength ............................................... 4-5
Figure 4-6 Example of glass disc erosion .................................................................................. 4-6
Figure 4-7 Steep impulse flashover and puncture characteristic of porcelain disc
insulators .............................................................................................................................. 4-7
Figure 4-8 Examples of an incomplete and completed localized puncture or worm hole .......... 4-7
Figure 4-9 Example of Glazing Damage Caused by Power Arc ................................................ 4-8
Figure 4-10 Example of the Flaking of the Glass Disk Surface after a Power Arc ..................... 4-9
Figure 4-11 Example of cement cracking as a result of cement expansion caused by the
absorption of water............................................................................................................... 4-9
Figure 4-12 Example showing loss of pin-cavity cement in a porcelain suspension
Insulator ............................................................................................................................. 4-10
Figure 4-13 Examples of extreme pin corrosion due to electrolysis ........................................ 4-11
Figure 4-14 Corrugated Metal Collar around the Pin (Cookie Cutter) ...................................... 4-12
Figure 4-15 Example of Stub Following Shattering of the Glass Shell, and a cut-through
view showing the compact trapped particles of glass in the cap ........................................ 4-14
Figure 4-16 Example of Stub Maintaining Mechanical Load Following Shattering of the
Dielectric Shell ................................................................................................................... 4-14
Figure 4-17 Example of External Arcing of Glass Stub ............................................................ 4-15
Figure 4-18 Examples of electrically failed insulator units. ...................................................... 4-15
Figure 4-19 Example of a radial crack. .................................................................................... 4-16
Figure 4-20 Example of a mechanical separated pin ............................................................... 4-17
Figure 4-21: Example of a mechanically failed insulator. ......................................................... 4-17
Figure 4-22 An example of a burst porcelain disc due to fault current passing through an
internal puncture ................................................................................................................ 4-18
Figure 4-23 Occurrence of different failure modes on actual in-service composite
insulators as captured in the EPRI failure database. Note Lapp refers to one
particular insulator make which is no longer marketed. ..................................................... 4-20
Figure 4-24 Tracking along the housing—core interface of a composite insulator. ................. 4-21
Figure 4-25 Unit that failed due to destruction of the rod by discharge activity........................ 4-21
Figure 4-26 A flashunder and associated features. ................................................................. 4-22
Figure 4-27 Brittle fracture. Note the several separate flat transverse fracture planes and
the “broomstick.” ................................................................................................................ 4-23
Figure 4-28 Mechanically failed rod due to manufacturing defect. .......................................... 4-24
Figure 4-29 Unit that has failed due to decomposition of the epoxy cone. .............................. 4-25
Figure 4-30 An example of moderate end fitting corrosion. ..................................................... 4-26
Figure 4-31 Examples of damage to end fittings due to power arcs. ....................................... 4-26
Figure 4-32 Examples E-field calculations performed for various end fitting designs
(EPRI). Blue corresponds to the lowest E-field magnitude and Red to the highest.
The corona threshold corresponds approximately to orange. ............................................ 4-27
Figure 4-33 A schematic representation of how the E-field design of the end fitting may
impact the performance of other insulator components. .................................................... 4-27
Figure 4-34 Examples of deterioration and damage to the end fitting seal. ............................. 4-30
Figure 4-35 Corona activity from energized end fittings. ......................................................... 4-31
Figure 4-36 Material degradation caused by continual dry corona activity from energized
end fittings. ......................................................................................................................... 4-32
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Figure 4-37 Results of finite elements modeling, showing enhancement of the E-field
surrounding a water drop on the surface of a composite insulator. ................................... 4-32
Figure 4-38 Image intensifier image showing corona activity wetting activity. ......................... 4-33
Figure 4-39 Photos illustrating localized loss of hydrophobicity in the aging chamber and
on an insulator removed from service. ............................................................................... 4-33
Figure 4-40 Localized arcing activity observed on a 230-kV silicone rubber insulator. The
observed activity was correlated with localized loss of hydrophobicity in the high field
region. ................................................................................................................................ 4-35
Figure 4-41 Infrared and ultraviolet images of dry-band arcing activity on a composite
insulator [35]....................................................................................................................... 4-35
Figure 4-42 Examples of erosion and tracking along mold lines. ............................................ 4-36
Figure 4-43 Example of superficial power arc damage on a polymer insulator ....................... 4-36
Figure 4-44 Failure mode distribution from EPRI failure database. ......................................... 4-38
Figure 4-45 Age of failures. ...................................................................................................... 4-39
Figure 5-1 Overview of the steps making up the insulation coordination methodology. ............ 5-1
Figure 5-2 Overview of the aspects that need to be considered when defining the
required line performance. ................................................................................................... 5-2
Figure 5-3 Evaluation of risk for flashover using a statistical design process. ........................... 5-9
Figure 5-4 Typical evidence of contamination related problems .............................................. 5-16
Figure 5-5 An overview of some site assessment techniques ................................................. 5-18
Figure 5-6 Typical variation in dustfall near urban industrial area of Hamilton, Ontario........... 5-20
Figure 5-7 Summary of results obtained by different organizations with respect to the
end fitting temperature of an insulator for different conductor temperatures. Ambient
temperature in all cases was between 20 and 25°C. ......................................................... 5-24
Figure 5-8 Examples of rodent and bird damage to polymer insulators. ................................. 5-26
Figure 5-9 A Comparison of the Leakage Distance per Unit Length for four Toughened
Glass Suspension Insulator Profiles .................................................................................. 5-30
Figure 5-10 Photograph and drawing of a Standard Profile Insulator ...................................... 5-31
Figure 5-11 Photograph and drawing of a Fog Profile Insulator .............................................. 5-31
Figure 5-12 Photograph and drawing of an Aerodynamic Profile Insulator ............................. 5-32
Figure 5-13 Photograph and drawing of a Fog-bowl Profile insulator ...................................... 5-33
Figure 5-14 Typical examples of polymeric insulator profiles .................................................. 5-33
Figure 5-15 Stress-strength concept for the calculation of the risk of flashover with
respect to polluted conditions............................................................................................. 5-36
Figure 5-16 Graphical illustration of the deterministic approach. ............................................. 5-37
Figure 5-17 Example of the distribution of Site severity Data (ESDD) data from six sites,
plotted on Log-Normal probability paper ............................................................................ 5-39
Figure 5-18 Three-dimensional representation of the probability for flashover during
critical wetting as a function of the voltage stress across the insulator and the
pollution severity level. ....................................................................................................... 5-40
Figure 5-19 Test results of flashover probability of 14 I-strings. ............................................. 5-41
Figure 5-20 Relationship between flashover voltage of a single string and multiple
strings, for 10% standard deviation. ................................................................................... 5-41
Figure 5-21 Typical range of a safety factor for transmission-line insulators. .......................... 5-44
Figure 5-22 Time variation of ESDD measurements at a coastal site. .................................... 5-47
Figure 5-23 Typical results from pollution site severity measurements and the fitted
lognormal distribution. ........................................................................................................ 5-47
Figure 5-24 Insulator flashover characteristic as derived through laboratory tests. The
standard deviation is assumed to be 8%. .......................................................................... 5-48
Figure 5-25 Derivation of the insulator flashover probability as a function of
contamination severity. ...................................................................................................... 5-49
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Figure 5-26 Derived probability for flashover characteristic for one and 120 insulators. ......... 5-49
Figure 5-27 Calculating the risk of flashover from the site severity and the insulator
flashover characteristic. ..................................................................................................... 5-50
Figure 5-28 Design curve for a typical standard-shape disc insulator for three different
levels of the risk of flashover. ............................................................................................. 5-51
Figure 5-29 Shaded plot of the E-field distribution on the surface of a polymer insulator
and the equipotential lines in the air surrounding the unit. The E-field magnitude is
indicated in grayscale, with white being the highest and black the lowest. ........................ 5-52
Figure 5-30 Example of the normalized E-field magnitude within the fiberglass rod of a
suspension I-string 115-kV polymer insulator determined using three-dimensional
finite elements modeling. The axial measurement line starts at the energized end
fitting and ends at the grounded end fitting. ....................................................................... 5-53
Figure 5-31 E-field profile measured along a suspension 500-kV V-sting polymer
insulator using a field probe. The unit has a corona ring in place on both the live and
grounded ends. .................................................................................................................. 5-53
Figure 5-32 Maximum E-field magnitudes (rms) on the sheath sections of polymer
insulators modeled as a function of system voltage. (All models account only for the
presence of a single phase ................................................................................................ 5-60
Figure 5-33 A 138 kV single circuit 3-phase transmission line and two single phase test
setups................................................................................................................................. 5-64
Figure 5-34 The E-field on a suspension insulator end fitting on a 3-phase line compared
with two single phase setups. (Energized end on left and grounded end on right) ............ 5-65
Figure 5-35 The E-field on a suspension insulator sheath on a 3-phase line compared
with two single phase setups. (Energized end on left and grounded end on right) ............ 5-65
Figure 5-36 Top: Images of corona activity on the first bell of a 765-kV insulator string
with no grading devices installed. Bottom: Corona activity surrounding the pin of a
porcelain insulator disc under dry conditions. .................................................................... 5-68
Figure 6-1 Test plan for porcelain and glass insulators ............................................................. 6-2
Figure 6-2 Example test load for thermal-mechanical cycling ................................................... 6-3
Figure 6-3 Mechanical load rate of increase for M&E testing .................................................... 6-4
Figure 6-4 Bell Breaks ............................................................................................................... 6-4
Figure 6-5 Cap Breaks or Cap Breaks followed by Bell Breaks ................................................. 6-4
Figure 6-6 Pin Breaks or Pin Breaks followed by Bell Breaks ................................................... 6-4
Figure 6-7 Pin Pullout ................................................................................................................ 6-5
Figure 6-8 Cap from Bell Separation ......................................................................................... 6-5
Figure 6-9 Mechanical strength of insulators tested by EPRI .................................................... 6-2
Figure 6-10 The normal probability curve of example test results ............................................. 6-3
Figure 7-1 Example of double grading ring application illustrating the problem of not
properly resolving the line of responsibility for assembly and insulator design. ................. 7-28
Figure 7-2 The reference document hierarchy for the IEC 61109, showing the complexity
that may arise..................................................................................................................... 7-32
Figure 7-3 A cut-away drawing of a composite insulator showing its different interfaces. ....... 7-37
Figure 7-4 A schematic representation of the tests on interfaces and connection of metal
fittings (ANSI and IEC only). .............................................................................................. 7-38
Figure 7-5 A schematic representation of the tests on interfaces and connection of metal
fittings (CSA). ..................................................................................................................... 7-39
Figure 7-6 A cut-away drawing of a composite insulator showing its core............................... 7-40
Figure 7-7 A cut-away drawing of a composite insulator showing its core and end fittings. .... 7-41
Figure 7-8 An Illustration of the three types of load-time strength mentioned in the
present ANSI, IEC and CSA standards for composite suspension insulators. .................. 7-43
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Figure 7-9 The load time strength relationship that forms the basis of the present
IEC61109 standard. ........................................................................................................... 7-44
Figure 7-10 A schematic representation of the load time strength relationship as is
indicated by experimental evidence. .................................................................................. 7-45
Figure 7-11 A schematic representation of the load time strength relationship as is
indicated by experimental evidence. .................................................................................. 7-46
Figure 7-12 A cut-away drawing of a composite insulator showing its housing. ...................... 7-46
Figure 7-13 The aging cycle for the CIGRÉ 5000-hour test. .................................................... 7-48
Figure 7-14 The assumed load time strength used by the IEC for composite insulators. ........ 7-52
Figure 7-15 Three-tier testing approach .................................................................................. 7-55
Figure 7-16 Test setup for the sheath corona exposure test. .................................................. 7-56
Figure 7-17 Test setup for the corona from end fitting exposure test. ..................................... 7-56
Figure 7-18 Aging cycle for the IEC/CIGRE 5000-h test. ......................................................... 7-57
Figure 7-19 Aging cycle of the ENEL 5000-h test. ................................................................... 7-58
Figure 7-20 Aging cycle for the EPRI summer/winter cycle test. ............................................. 7-58
Figure 7-21 Aging cycle for EPRI test to simulate “Deserts with a Distinctly Cold
Season.” ............................................................................................................................. 7-59
Figure 7-22 EPRI 500-kV accelerated aging test. .................................................................... 7-59
Figure 7-23 Aging cycle for EPRI test to simulate a warm temperate climate. ........................ 7-60
Figure 7-24 Some of the insulators installed in 230-kV accelerated aging chamber. .............. 7-60
Figure 7-25 Aging cycle for FGH 500-h test. ........................................................................... 7-61
Figure 7-26 Overall view of test rig used for evaluating the end fitting seal and the
mechanical performance of the insulator. .......................................................................... 7-62
Figure 7-27 Test to evaluate mechanical performance. ........................................................... 7-63
Figure 7-28 An example of an insulator where the core is not centered in the housing. ......... 7-71
Figure 7-29 Pole Assembly. ................................................................................................... 7-107
Figure 7-30 Phase Wire Davit Arm Detail .............................................................................. 7-108
Figure 7-31 Ground Wire Davit Arm Detail ............................................................................ 7-109
Figure 7-32 Insulator – Energized End Detail ........................................................................ 7-110
Figure 8-1 Weathered regular lumber placed outdoors. ............................................................ 8-3
Figure 8-2 An example of over stacking. ................................................................................... 8-3
Figure 8-3 Example of incorrect stacking. .................................................................................. 8-3
Figure 8-4 Insulators stored in PVC pipes. ................................................................................ 8-3
Figure 8-5 Insulators stored using hooks. .................................................................................. 8-3
Figure 8-6 Rubber material eaten by rodents. ........................................................................... 8-3
Figure 8-7 Damage to insulators due to puncturing of a crate by forklift blades. ....................... 8-5
Figure 8-8 Use of PVC tubes in a truck. .................................................................................... 8-5
Figure 8-9 Insulators left in the dirt and driven over. .................................................................. 8-5
Figure 8-10 Damage caused by nails. ....................................................................................... 8-5
Figure 8-11 Incorrect method for removing polymers from plastic sheaths. .............................. 8-6
Figure 8-12 Correct method for removing polymers from plastic sheaths. ................................ 8-6
Figure 8-13 Insulator dragged on ground: incorrect handling. ................................................... 8-7
Figure 8-14 Insulator used as a support: incorrect handling. ..................................................... 8-7
Figure 8-15 Incorrect carrying procedure. .................................................................................. 8-7
Figure 8-16 Correct carrying procedure. .................................................................................... 8-7
Figure 8-17 Correct attachment point: attached to end fitting. ................................................... 8-7
Figure 8-18 Incorrect attachment point: attached to polymer housing. ...................................... 8-7
Figure 8-19 Corona rings assembled on a ground sheet. .......................................................... 8-9
Figure 8-20 An example of a plastic protective sleeve fitted with velcro straps. ........................ 8-9
Figure 8-21 Incorrect rope attachment point. ............................................................................. 8-9
Figure 8-22 Correct method for lifting line post insulators. ........................................................ 8-9
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Figure 8-23 Correct method: rope tied on top and bottom. ...................................................... 8-11
Figure 8-24 Incorrect method: rope tied on to rubber insulator, collision into structure. .......... 8-11
Figure 8-25 Bucket striking and placing a load on the insulator. ............................................. 8-11
Figure 8-26 Damage to insulator by rope. ............................................................................... 8-11
Figure 8-27 Damage to the insulator by the safety belt and boots should be avoided. ........... 8-11
Figure 8-28 Climbing on the end fitting or grading ring. ........................................................... 8-13
Figure 8-29 Insulator used for an anchor point. ....................................................................... 8-13
Figure 8-30 Ground end fitting has locked causing the insulator to bend. ............................... 8-13
Figure 8-31 Dead end insulator being twisted to fit jumper (incorrect method). ...................... 8-13
Figure 8-32 Workers installing a PPAG on a 500 kV structure. ............................................... 8-19
Figure 8-33 Lifting a polymer insulator without a cradle. ......................................................... 8-22
Figure 8-34 Because the grading ring does not fit in the cradle, the polymer insulator is
flexed.................................................................................................................................. 8-22
Figure 8-35 Problems of dissimilar connection lengths: The polymer insulator is longer
than the strain sticks used for the ceramic string. .............................................................. 8-23
Figure 8-36 Danger of damage to polymer insulator by sharp tools. ....................................... 8-23
Figure 8-37 Possible mechanical interference caused by the grading ring and difficulty of
access with tools. ............................................................................................................... 8-23
Figure 8-38 Close-up photograph showing that the recommended 11-ft. 4-in. cradle
sticks are too long. ............................................................................................................. 8-27
Figure 9-1 Bird related flashovers on transmission lines. .......................................................... 9-1
Figure 9-2 Bird related damages on transmission insulators and structures. ............................ 9-2
Figure 9-3 Example of a snake causing an outage. The snake was probably out to catch
a bird. ................................................................................................................................... 9-3
Figure 9-4 Examples of stork nests on overhead lines in Portugal. ........................................... 9-3
Figure 9-5 Bird excrement on a post and disc insulator. ............................................................ 9-4
Figure 9-6 A large roost of starlings on an overhead line. ......................................................... 9-5
Figure 9-7 Examples of pole top fires associated with bird nesting activity. .............................. 9-5
Figure 9-8 Vultures on a 275 kV line. Note the bird diverter that prevents the birds from
perching in critical area directly above the center phase. .................................................... 9-6
Figure 9-9 Damage inflicted on composite insulators by birds. ................................................. 9-7
Figure 9-10 A triangular bird guard. ........................................................................................... 9-9
Figure 9-11 Kaddas Insulator/Cover Cover in Trial on 50 Structures in Nevada. ...................... 9-9
Figure 9-12 Wire type perch preventer. ................................................................................... 9-10
Figure 9-13 The use of perch preventers to discourage birds to sit in critical areas of the
tower. ................................................................................................................................. 9-10
Figure 9-14: Different kinds of insulator shield that can be used to limit the buildup of bird
excrement on insulators. .................................................................................................... 9-11
Figure 10-1 Binoculars used for inspection. ............................................................................. 10-4
Figure 10-2 Spotting scope used for inspections. .................................................................... 10-5
Figure 10-3 The digital SLR camera used for inspections. ...................................................... 10-5
Figure 10-4 Example page from the EPRI visual inspection guide. ......................................... 10-6
Figure 10-5 Conditions That May Cause Discharge Activity .................................................... 10-8
Figure 10-6 Spectral irradiance of corona and solar energy. ................................................. 10-10
Figure 10-7 Examples of UV Viewing Devices....................................................................... 10-11
Figure 10-8 Example page from the EPRI Daytime Discharge Inspection guide................... 10-13
Figure 10-9 Infrared imaging system used for inspection. ..................................................... 10-16
Figure 10-10 Example page from the EPRI Infra-Red Inspection guide. ............................... 10-16
Figure 10-11 A parabolic microphone that can be used to pinpoint sources of acoustic
emissions. ........................................................................................................................ 10-17
Figure 10-12 Inspecting an NCI for defects by measuring the E-field. .................................. 10-19
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Figure 10-13 E-field profiles measured along one good and one defective NCI. The
defect can be seen in the distortion in the E-field between 80 and 100 sheds. ............... 10-20
Figure 10-14 The new insulator tester being used to test a polymer suspension insulator
on the line......................................................................................................................... 10-21
Figure 10-15 Close-up view of the insulator tester showing tester status and condition
indicator lights. ................................................................................................................. 10-21
Figure 10-16 EPRI polymer post insulator test units. ............................................................. 10-22
Figure 10-17 Prototype of the EPRI crawling insulator robot. ................................................ 10-22
Figure 10-18 Example of increase in E-field magnitude on the sheath surfaces as a
function of phase spacing for a vertical suspension configuration. .................................. 10-28
Figure 10-19 Predicted annual wetting hours for polymer insulators in the United States..... 10-29
Figure 10-20 Example of Spotting Scope with High Magnification ........................................ 10-38
Figure 10-21 Examples of UV Viewing Technologies ............................................................ 10-40
Figure 10-22 Summary of Conditions That Can Be Detected with Daytime UV Imaging ...... 10-41
Figure 10-23 Summary of Conditions that Cannot Be Detected Using Daylight UV
Imaging ............................................................................................................................ 10-42
Figure 10-24 Moderate Heating on a Shorted Disc at the Live End ...................................... 10-42
Figure 10-25 Example of an Infrared Camera Used for Inspection........................................ 10-43
Figure 10-26 A Parabolic Microphone That Can Be Used to Pinpoint Sources of Acoustic
Emissions ......................................................................................................................... 10-43
Figure 10-27 Example of a Buzz Test .................................................................................... 10-45
Figure 10-28 Inspecting for Defects by Measuring the E- Field on a Porcelain Insulator
String ................................................................................................................................ 10-46
Figure 10-29 E-Field Profiles Measured Along Porcelain Insulator Strings ........................... 10-46
Figure 10-30 Basic Concept of the Vibration Response Instrument ...................................... 10-47
Figure 10-31 Three Criteria Defining Defective String Test Methods ..................................... 10-50
Figure A-1 Directional dust deposit gauges .............................................................................. A-2
Figure A-2 Relation between the monthly directional dust deposit gauge index (soluble)
and the site pollution severity. ............................................................................................. A-5
Figure A-3 A seven-disc insulator string and typical disc insulators as used for
ESDD/NSDD measurements .............................................................................................. A-7
Figure A-4 A station or longrod insulator as used for ESDD/NSDD measurements ................. A-8
Figure A-5 A standard shape insulator ................................................................................... A-10
Figure A-6 Schematic diagram illustrating the separate ESDD/NSDD measurement of
the insulator top and bottom surfaces ............................................................................... A-12
Figure A-7 ESDD measurement of the insulator bottom surface ............................................ A-13
Figure A-8 The time variation of ESDD measurements at a coastal site ................................ A-16
Figure A-9 Typical results from contamination site severity measurements and the fitted
lognormal distribution ........................................................................................................ A-16
Figure A-10 Solid-type contamination: Relation between ESDD/NSDD and the site
pollution severity for standard-shape disc-type insulator. ................................................. A-18
Figure A-11 Solid-type contamination: Relation between ESDD/NSDD and the site
pollution severity for standard longrod type insulator. ....................................................... A-18
Figure A-12 Definition of form factor ....................................................................................... A-20
Figure A-13 A surface conductance measurement on a silicone rubber insulator .................. A-21
Figure A-14 Arrangement and dimensions of the IEC hand probe electrodes ....................... A-22
Figure A-15 Measurement points for disc insulators ............................................................... A-22
Figure A-16 An example of a system for the automated measurement of the insulator
surface conductivity........................................................................................................... A-23
Figure A-17 A graphical illustration of the layer conductivity limits used in different
countries............................................................................................................................ A-24
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Figure A-18 Application of explosive fuses to determine the minimum insulator flashover
stress................................................................................................................................. A-25
Figure A-19 Examples of ways to measure leakage current on insulator strings and
substation equipment (left: disc insulators; right: equipment insulator)............................. A-27
Figure A-20 An example of a captured leakage current surge. Whole current surge.
Detail of the current relative to the applied voltage. .......................................................... A-29
Figure A-21 An example of the peak leakage currents recorded during a wetting event
on four insulators. The numbered curves each represents a different insulator being
monitored. ......................................................................................................................... A-29
Figure A-22 An example of retrieved bin counts on a leakage current monitor which is
polled every five months. .................................................................................................. A-29
Figure A-23 An example of retrieved bin counts on a leakage current monitor which is
polled every ten minutes. .................................................................................................. A-30
Figure A-24 Relationship between leakage current and the contamination severity as
determined through laboratory testing .............................................................................. A-30
Figure A-25 The determination of the site equivalent severity through leakage current
measurements .................................................................................................................. A-32
Figure A-26 The determination of the risk for a contamination flashover through leakage
current measurements ...................................................................................................... A-32
Figure A-27 Examples of different leakage current monitor installations at test sites ............. A-35
Figure A-28 Example of alarm mnemonic of a substation bay with leakage current RF
sensors.............................................................................................................................. A-36
Figure A-29 Example of the data obtained from an installation of the leakage current RF
sensors.............................................................................................................................. A-38
Figure B-1 Location of the calculation profile on the insulator end fitting. ................................. B-2
Figure B-2 Location of the calculation profile on the sheath of the insulator. ........................... B-3
Figure B-3 Comparison of the calculated E-field with the EPRI limit. ....................................... B-3
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LIST OF TABLES
Table 2-1 Calculated parameters for the insulator shown in Figure 4.2-12. .............................. 2-9
Table 2-2 Relationship between the Hydrophobicity Class (HC) and Contact Angle............... 2-16
Table 2-3 Insulator terminology used in standards and the industry ....................................... 2-52
Table 3-1 Average Gradient to Ground, at Mid-span, as a Function of Transmission-Line
Voltage ................................................................................................................................. 3-9
Table 3-2 Key Processes of the Contamination Flashover Process ........................................ 3-14
Table 3-3 Photos of the Typical Discharge Patterns That May Be Observed During the
Zones Defined in Figure 4.4-9............................................................................................ 3-28
Table 3-4 Experimental Parameters for the Withstand Curves Presented in Figure 3-22 ....... 3-32
Table 3-5 Geometrical and Mechanical Characteristics of the Insulator Units Tested at
Project UHV ....................................................................................................................... 3-33
Table 3-6 Commonly Used Guidelines for the Selection of Creepage Distance Based on
ESDD Measurements ........................................................................................................ 3-36
Table 3-7 Comparison of 50% Flashover Strength and Long-String Efficiency for
Different String Configurations (ESDD = 0.02 mg/cm2) ..................................................... 3-40
Table 3-8 50% Cold Switch-on Flashover Voltage of Conventional and Semiconducting
Glaze Insulators ................................................................................................................. 3-45
Table 3-9 Specific Leakage Distance for Clean-Fog and Cold-Fog Conditions ....................... 3-48
Table 5-1 Overview of the Standardized Approach of Classifying Voltage stresses on
Transmission Lines .............................................................................................................. 5-5
Table 5-2 Contamination Site severity classification and sample descriptions of typical
environments...................................................................................................................... 5-17
Table 5-3 Advantages and Disadvantages Associated with Different Insulator
Technologies ...................................................................................................................... 5-21
Table 5-4 IEC and ANSI Guidelines for the Selection of Leakage Distance for Different
Site Severity Classes ......................................................................................................... 5-35
Table 5-5 A comparison of the deterministic and statistical approaches to dimensioning. ...... 5-38
Table 5-6 In summary the EPRI recommendations on Electric field limits for Polymer
Insulators............................................................................................................................ 5-55
Table 5-7 Generic Recommendations for Corona Rings. ........................................................ 5-57
Table 5-8 Comparison of Generic Recommendations Obtained for Four Different
Insulator Designs ............................................................................................................... 5-59
Table 5-9 Calculated maximum E-field on the polymer insulators in the configurations
shown in Figure 5-33.......................................................................................................... 5-66
Table 5-10 Required test voltages for the configurations considered. ..................................... 5-66
Table 7-1 Comparison of the Terminology used in ANSI, IEC and CSA to describe the
various types of test. ............................................................................................................ 7-3
Table 7-2 List of ANSI Standards Applicable to Porcelain and Toughened Glass
Insulators.............................................................................................................................. 7-5
Table 7-3 List of IEC Standards Applicable to Porcelain and Toughened Glass Insulators ...... 7-6
Table 7-4 List of CSA Standards Applicable to Porcelain and Toughened Glass
Insulators.............................................................................................................................. 7-6
Table 7-5 Cross Reference of Terms used in the Various Standards ....................................... 7-7
Table 7-6 Cross Reference of Design Tests in various Standards ............................................ 7-8
Table 7-7 Comparison of Standard atmospheric conditions and artificial rain ......................... 7-10
Table 7-8 Cross Reference of Conformance Tests ................................................................. 7-17
Table 7-9 Cross Reference of Routine Tests ........................................................................... 7-21
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Table 7-10 ANSI standards and IEEE Guides Covering AC Transmission Line
Composite Insulators. ........................................................................................................ 7-30
Table 7-11 IEC Standards and Reports related to Composite Insulators ................................ 7-30
Table 7-12 Comparison of the properties used by ANSI, IEC and CSA to define an
insulator design concept. ................................................................................................... 7-36
Table 7-13 The definition of important mechanical characteristics as used in the
standards. .......................................................................................................................... 7-42
Table 7-14 Comparison of the definition of an insulator type according to ANSI,
IEC and CSA. ..................................................................................................................... 7-49
Table 7-15 Comparison of the type tests according to ANSI, IEC and CSA. ........................... 7-51
Table 7-16 Comparison of the sample tests according to ANSI, IEC and CSA. ...................... 7-53
Table 7-17 Comparison of the routine tests according to ANSI, IEC and CSA........................ 7-54
Table 7-18 A summary of the information that can be helpful when considering
requirements for the insulator core. ................................................................................... 7-64
Table 7-19 A summary of the information that can be helpful when considering
requirements for the end fittings......................................................................................... 7-67
Table 7-20 A summary of the information that can be helpful when considering
requirements for the end fitting seal. .................................................................................. 7-68
Table 7-21 A summary of the information that can be helpful when considering
requirements for the housing. ............................................................................................ 7-70
Table 7-22 The site severity classification and sample descriptions of typical
environments...................................................................................................................... 7-75
Table 7-23 A summary of the information that can be helpful when considering
requirements for the housing. ............................................................................................ 7-76
Table 7-24 A comparison of different methods of attaching the housing to the core. .............. 7-77
Table 7-25 In summary the EPRI recommendations on Electric field limits for Polymer
Insulators............................................................................................................................ 7-78
Table 7-26 A summary of the information that can be helpful when considering
requirements for the housing. ............................................................................................ 7-83
Table 8-1 MAD values, recommended tools and connection lengths. ..................................... 8-26
Table 10-1 Risk of unit being degraded by an unacceptable level of discharge activity. ....... 10-31
Table 10-2 Setting and understaning severity ratings for corona inspections........................ 10-33
Table 10-3 Summary of Visual Inspection ............................................................................. 10-37
Table 10-4 An Example of the Maximum Number of Allowable Electrically Shorted Units
in a String Under Which Live Work May Still Be Performed ............................................. 10-50
Table A-1 Typical measuring intervals to determine maximum ESDD/NSDD values ............... A-7
Table A-2 Surface area for a number of typical glass insulator disc types ............................... A-9
Table A-3 Calculated creepage distance and surface area for the standard disc insulator
in Figure A-5...................................................................................................................... A-10
Table A-4 Calculated creepage distance and form factor for the standard disc insulator in
Figure A-5 ......................................................................................................................... A-20
Table A-5 Factor describing the relationship between surface conductivity and ESDD ......... A-21
Table A-6 Classification of site severity based on surface conductance measurements ....... A-23
Table A-7 Site severity classification according to the insulator flashover stress method ...... A-26
Table A-8 EPRI’s Standardized bin ranges used on the leakage current sensors ................. A-34
Table A-9 EPRI’s criteria for generating alarms for insulator maintenance ............................ A-35
Table A-10 A summary of the advantages and disadvantages associated with each site
assessment method .......................................................................................................... A-39
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1
FRONT MATTER
Background to This Reference Book
High voltage insulators are an essential part of the power delivery system and ensure the reliable
and safe transmission of electricity from generating stations to substations where the voltage is
reduced and distributed to commercial and residential consumers. Insulators provide the
mechanical means by which high voltage wires are suspended from transmission structures while
also providing the required electrical insulation. They are, therefore, exposed to a variety of
mechanical, electrical, and environmental stresses that may negatively impact their performance
and life expectancy - Figure 1-1. Through monitoring the performance of in-service insulators
and researching their fundamental characteristics, much can be learned about how to use them
effectively and when to replace them.
Figure 1-1
Transmission line insulators are exposed to various environmental stresses
EPRI has a long history of performing research on all types of insulator with a view of better
understanding of the mechanisms and factors that govern their long- and short-term performance
and so, identify measures which can be taken to improve performance and prolong life
expectancy. With this unique portfolio of research, EPRI has accumulated a vast knowledge on
insulators and now actively strives to disseminate this knowledge to members through the many
published reports, tools, and guidelines. Most of these products are aimed at providing actionable
information and guidance which can be helpful when selecting, dimensioning, and managing
insulator populations. Still many users may struggle to quickly find relevant research reports
when conducting their day-to-day tasks. Additionally, some earlier reports which contain
important results may no longer be easily accessible.
11762887
1-1
As a way of improving accessibility to important research results, EPRI has a set of reference
books which cover a wide range of important topics relevant to overhead and underground
transmission. The aim with these books is to collect all relevant information on a particular
subject in one handy reference. All these books rely on information gained through research and
testing at the EPRI Laboratories, active engagement with EPRI members and by participating in
(inter)national technical committees.
With this Insulator Reference Book, EPRI aims to give utility engineers a comprehensive
resource on all aspects of high voltage insulators. Although the present edition focuses primarily
on the electrical aspects of high voltage insulators, future editions will also include an in-depth
treatment of the mechanical aspects of insulator design as more research results become
available. The first edition of this book basically comprised out of a collection of key EPRI
research reports that address different aspects of all types of insulator which includes insulator
design, application, and maintenance. With the present edition, a process is started whereby the
material from the various reference reports is recompiled and integrated to limit the amount of
repetition while also making it easy to find information.
For 2018 the reference book was restructured, and an outline was published. Since then,
Chapters 1 to 3 was updated in 2019 and in 2020 Chapters 4 and 5 have been added. In 2021
Chapters 7 and 8 have been re-edited and Chapters 9 and 10 were added. Chapter 6 has been
started and research on mechanical performance of insulators progresses, the chapter content will
be expanded.
Overview EPRI Research into Insulators
In broad terms EPRI research into insulators is structured to several themes that reflect, in part,
the life cycle of insulators:
•
•
•
•
•
Selection and procurement
Dimensioning
Inspection and assessment
Fleet management
Failure and degradation modes
Projects that fall under “selection and procurement” are aimed at identifying or developing
suitable tests that can be included in technical specifications to ensure the quality of the
purchased insulators. In many cases the (inter)national standards only include requirements to
ensure a basic functional insulator, which are usually not selective enough to also ensure
insulators of high quality. EPRI research projects aim to fill this gap and projects in this category
include:
•
•
•
Accelerated aging testing of 230 kV and 138 kV insulators
Development of small-scale polymer insulator tests to evaluate the insulator performance
under wet corona conditions
Steep-front testing of porcelain and glass insulators
11762887
1-2
•
•
•
Identifying laboratory tests for qualifying advanced and RTV insulator coatings
Investigating aging of polymer insulators under HVDC energization
Tests to define the mechanical loading capability of polymer post insulators
The category “dimensioning” covers the development of procedures for the selection,
dimensioning and application of insulators to overhead lines and substations. This not only
includes methods to ensure that the correct insulators are applied, but it also includes measures
that may be taken, such as E-field grading, to provide a good operating environment for the
insulators to ensure their longevity. Many of these procedures are also made available as
software tools. This includes the following projects:
•
•
•
•
Formalizing procedures for dimensioning insulators with respect to contaminated
environments
Review insulation coordination practices for HVDC overhead lines
Developing specification requirements for corona testing of HVDC insulators and associated
hardware
Development of tools for designing e-field grading for polymer and disc insulator strings
(ICE)
Research projects covering “inspection and assessment” are aimed at identifying, or developing,
tools and techniques for assessing the heath of in-service insulators. This also includes the
defining acceptance criteria. Projects in this area include:
•
•
•
•
Development of a remote inspection tool for porcelain insulators
Development of application guidelines for the live-line working non-ceramic insulator
(LWNCI) tool
Development of an overhead transmission line inspection robot
Performing testing to determine critical lengths of defects in polymer insulators above which
live line work should not be performed (see Figure 1-2).
Figure 1-2
Testing to determine critical lengths of defects in polymer insulators above which live line work
should not be performed
11762887
1-3
Under “fleet management” falls all projects that aim to provide tools or information that will
help utilities when managing their insulator assets. Research project that falls in this category
are:
•
•
Investigations to better understand brittle fractures on guy wire insulators
Lightning impulse tests on typical line insulator configurations to better understand the
strength of polymer insulators under fast front overvoltages.
The last category, “failure and degradation modes”, includes research projects that collect and
trend insulator failures as well as the development the tools that support the collection of service
data. This includes:
•
•
•
•
•
Populating and maintaining an insulator failures database to track insulator failures an
provide the possibility to generate detailed failure statistics
Development of a software tool (Polymer Insulator Population Assessment - PIPA) to
facilitate utilities when doing a population assessment of polymer insulators.
Maintaining a polymer insulator vintage guide to help utilities identify insulator types when
performing population assessments
Performing stress tests on Porcelain and Glass to provide a basis for population assessments
Performing multi-stress tests on porcelain and glass insulator stubs to better understand the
residual strength of broken insulators
EPRI also publishes a series of guides that members can use to identify, assess and managing
insulator populations.
Organization of This Reference Book
This book is organized primarily as a reference book which will allow readers to easily find the
information they are looking for, while preserving a logical sequence to introducing insulators
and insulator technology to people new to this subject. As for other books, the audience profile
can be identified as follows:
•
•
•
•
Experienced users who need to have access to the latest research results when dimensioning,
specifying or maintaining insulator populations and who may need to defend their decisions
or are considering novel insulator applications.
Students who are unfamiliar with insulators and their application to overhead power systems
and are looking for an introduction to this subject.
Utilities that want to preserve institutional knowledge and have easy access to past EPRI
research.
Other interested parties, such as utility commissions, who may need technical background to
make informed decisions. Although this book is not primarily intended for this group, it is
recognized that this audience may rely on EPRI reference books as a valuable resource.
11762887
1-4
With this target audience in mind, the material in this book primarily organized as an application
guideline. In this respect, there are two tasks over the life cycle of insulators that need to be
considered:
•
•
Selection, dimensioning and procurement of insulators
Managing the insulator population
It is further recognized that the environmental, electrical and mechanical stresses to which
insulators will be subjected to, are common to all types of insulator and that the users will use
this input to select the most appropriate insulator technology. Thus, it was decided to present the
information in five distinct parts, to cover the different stages of the insulator life cycle. Each
part starts with the aspects common to all insulator types, which is then followed by more
detailed sections dealing with the particulars of each insulator type.
The parts can briefly be described as follows:
•
•
•
•
•
•
•
Part 1: This part of the book gives the background to this book and explains its organization.
Part 2: All fundamental information on insulators is collected in Part 2. This is mostly
reference information that will form a basis for the other Parts. It provides a historical
perspective on the development of insulators; explains the technical terms commonly used
to describe or define insulators and then continues with separate sections to describe the
manufacturing and characteristics of ceramic and glass and Polymer Insulators.
Part 3: The electrical performance of insulators and insulator sets are discussed in Part 3.
Separate chapters cover respectively the short- and long-term performance of insulators.
The part dealing with the short-term performance focuses solely on the functional electrical
flashover performance of insulators which includes all types of stress—from lightning and
switching impulse down to the AC flashover performance including that under contaminated
conditions.
Part 4: Aging aspects (i.e., deterioration and failure modes) of the insulator are discussed in
the sections dealing with the long-term performance of insulators. This section includes
many photographic examples and also explains the underlying mechanisms at work.
Part 5: This is the first of the "application" parts, which deals with all electrical aspects
related to the selection, dimensioning, acquisition and installation of insulators. After an
introductory chapter, this part deals with the electrical design and selection insulators which
includes sections explaining how to assess the work environment of the insulator, how to
choose the insulating material, and finally, it also introduces methods to dimension the
insulators. In future this section will also include guidance on the mechanical design and
selection of insulators when EPRI work on this subject is concluded. The part continues with
a detailed section explaining the need to grade the E-field along insulators and introduce
recommended limits which would, when applied, prolong the expected service life of the
insulators. Grading methods and tools to calculate the E-Field are also introduced.
Part 6: The second and future "application" parts, will deal with all mechanical aspects
related to the selection, dimensioning, acquisition and installation of insulators.
Part 7: Insulator specification and the standards that underpin it, are discussed this section.
11762887
1-5
•
•
•
Part 8: This “application” part, provides guidelines and tools for managing insulator
populations. It starts with a practical guide on the handling storage and installation of
insulators focusing mostly on polymer insulators which are vulnerable to such damage.
This is followed by a section dealing with considerations when replacing insulators using
live line techniques. Live line work itself and its procedures are only discussed superficially
to provide context as there are other more detailed EPRI references available that deal
specifically with this topic.
Part 9: Is a freestanding chapter dealing with special topic of bird interactions with
transmission lines and its impact on the short- and long-term performance of the insulators.
It also discusses various ways to mitigate the effects of such bird interactions.
Part 10: In this section the attention turns to condition assessment of in-service insulators.
Methods for in-service inspections are described and guidance on best practices is provided.
This section also includes a discussion on how this information can be used to do population
assessments.
Several appendixes are included to provide detail on methods and tools applicable to insulators.
The content of this book is primarily a compilation of EPRI research, which is augmented with
information from other industry resources as necessary. Important EPRI research reports
incorporated in this book includes:
•
•
•
•
•
•
•
•
Chapter 4 of the EPRI AC Transmission Line Reference Book – 200 kV and above, Third
Edition. EPRI, Palo Alto, CA: 2005. 1011974.
Application Guide for Transmission Line Non-Ceramic Insulators. EPRI, Palo Alto, CA:
1998. TR-111566.
Guidance on the Selection, Specification, and Procurement of Composite Insulators for
Transmission Lines: A review of Standards and the Latest Research Results and Service
Experience. EPRI, Palo Alto, CA: 2008. 1015920.
Guidance on the Selection, Technical Specification, and Procurement of Porcelain and
Toughened Glass Suspension Insulators for AC Transmission Lines. EPRI, Palo Alto, CA:
2011. 1021745.
Sections 8.8, 8.9 and 14.6 of the Overhead Transmission Inspection and Assessment
Guidelines – 2011. EPRI, Palo Alto, CA: 2011. 1021744.
Application of Corona Rings on 115/138 kV Polymer Transmission Line Insulators: Existing
Populations and New Applications. EPRI, Palo Alto, CA: 2008. 1015917.
Contaminated Outdoor High Voltage Insulators: A Practical Maintenance Guide. EPRI, Palo
Alto, CA: 2017. 3002010208.
Storing Transporting and Installing Polymer Insulators: A Practical Guide. EPRI, Palo Alto,
CA: 2007. 1013901.
11762887
1-6
2
INSULATOR TECHNOLOGY
Historical Perspective
The manufacture, design, and application of electrical insulators have posed a challenge to
engineers since the beginnings of power transmission. The first insulators were developed for
telegraph lines around 1835 [1]. These insulators were made mostly of annealed glass, or “drypressed” porcelain [2]. With the advent of power transmission in 1882, the telegraph insulators
were initially scaled-up for use at higher voltages and mechanical loadings (Figure 2-1).
Figure 2-1
Example of vintage porcelain insulators still in use after over 70 years of service.
The higher demands associated with power transmission soon revealed serious shortcomings in
both the materials and designs available at the time. For example, dry-press porcelain insulators
suffered from punctures due to the porosity of the material. This vulnerability spurred the
development of wet-process porcelain (1896), and soon thereafter the use of a vacuum extrusion
process to eliminate air from the porcelain insulating body, thereby obtaining a vitreous
porcelain that is essentially the same as used in modern applications [2]. Glass has also
undergone considerable developments in the choice of ground materials and, importantly,
the introduction of toughening in the 1930s [1] [3].
Another challenge was to develop insulator designs strong enough to withstand the mechanical
loads that insulators are subjected to on transmission lines. Traditional insulating materials
(i.e., porcelain and glass) are much stronger under compression than under tension loads.
Consequently, many insulator types were devised to place the dielectric material directly under
compression. Examples of such insulators include pin insulators, which are direct descendants
of the telegraph insulator; pedestal post insulators, which were introduced around 1910; and line
11762887
2-1
post insulators, which were introduced in 1940 [1]. However, these types became impractical for
application to higher system voltages where the longer insulators needed at these voltages may
be subjected to high cantilever forces, which would require heavy insulators. Consequently,
these types of insulator are generally limited to distribution and transmission lines below 220 kV.
A key development was the introduction of the first successful disc insulators in 1909 (porcelain)
and 1930 (glass) [1] [3]. The design of these insulators is such that the dielectric is under
compression, while the insulator, as a whole, is under tension. This resulted insulator designs
with a high strength-to-weight ratio, which enabled, together with the introduction of longrod
insulators in the 1920s, the creation of the long suspension insulator strings required for EHV
and UHV systems.
The first polymer longrod insulator designs were developed during the 1960s, with the first test
installations realized during the 1970s [4]. The first polymer post insulators became available in
the early 1980s. The advantages of polymer insulators included their light weight, resistance to
vandalism, small profile, and in some cases improved contamination performance [5] [6] [7] [8].
History shows that the development of insulator designs and manufacturing technology has been
a process of trial and error rather than an orderly progression, and this trend continues to this
day. Although the designs and manufacturing methods used for porcelain and glass insulators
stabilized in the 1950s and 1960s, developments are still ongoing in terms of optimizing designs,
materials used, and manufacturing processes to keep pace with an increasingly competitive
market. Insulators from reputable manufacturers, however, have a proven track record in terms
of reliability and a long service life and are, therefore, still widely used at all voltage levels.
The development history of polymer insulators is no different. Initial designs were plagued by
many problems, especially related to material-aging effects. However, through a continual
development, which continues to this day, big advances were made in terms of their reliability,
especially during the 1980s and 1990s, so that polymer insulators are now considered a mature
product with most manufacturers having stable designs. This is underlined by the increasing use
of polymer insulators worldwide. In 2017, a polling of 35 American utilities showed that 23 of
them used polymer insulators, while figures obtained from four of the major manufacturers
indicated that more than 20 million polymer transmission-class insulator units had been sold in
the United States alone.
Results from an EPRI survey, presented in Figure 2-2, shows a trend of fewer utilities applying
polymer insulators at higher system voltages. About 60% of the polled utilities apply polymer
insulators at the 69–138 kV level, while only a few utilities apply polymer insulators at 345 and
500 kV. The percentage of utilities applying polymer insulators at 765 kV increases again,
because only two utilities have this system voltage, and one of them applies polymer insulators.
11762887
2-2
35
Number of Utilities
80
Count of Utilities using polymer insulators at Voltage Level
Count of Utilities with Voltage Level
% Use of Polymer Insulators
70
30
60
25
50
20
40
15
30
10
20
5
10
0
69
115
138
161
230
345
500
765
Percentage use of Polymer Insulators
40
0
Voltage Levels [kV]
Figure 2-2
Number of utilities that apply polymer insulators at each voltage level, as well as the number of
utilities that have transmission lines at each voltage level. The line indicates the results as a
percentage.
National (ANSI) and international (IEC) standards have followed the developments and usage
trends of the different insulator technologies with standards now in circulation for all types of
insulator. For glass and ceramic insulators, the standards have been available for many years and
are no longer subjected to large revisions. The standards applicable to polymer insulators [9] [10]
[11] [12] [13] [14] [15] [16] [17] are reaching maturity but are still subject to further
development in response to experiences from service.
General Insulator Terms and Classification
Insulator Classification
The IEC identifies insulators according to the material from which the insulating body is
manufactured. Specifications are therefore produced for either glass and ceramic, or polymer
insulators. Polymer insulators can again be subdivided into resin and composite insulator types.
Strictly speaking, all modern polymer insulators used on transmission lines should be identified
as “composite” according to the IEC definition. In the industry, however, several terms are used
interchangeably, which includes terms such as composite, polymer, nonceramic insulators, or
NCI. For the purposes of this Reference Book, the term “polymer insulator” will be used.
Resin insulators are not used at transmission voltage levels and are, hence, not further discussed
in this chapter. For each of these general types of insulator, various designs exist, as illustrated in
Figure 2-3.
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2-3
Figure 2-3
General overview of insulator types used on transmission overhead lines.
ANSI/IEEE standards use a slightly different naming convention from the IEC. For example,
what the IEC calls a “cap and pin” insulator, ANSI calls a “suspension disc.” Figure 2-3,
therefore, lists both IEC and ANSI terms, with the IEC term first. This chapter uses the ANSI
naming convention.
The standards recognize two classes of insulators according to the possibility of internal puncture
(see Figure 2-4) [18]. For Class “A” insulators, the length of the shortest possible puncture is at
least equal to half the external arcing distance. These insulators are regarded as puncture proof.
Class “B” insulators, on the other hand, have a shortest puncture path that is less than half the
external arcing distance. These insulators are regarded as “puncturable.”
Figure 2-4
General classification of insulators as Class A (left) or B (right).
11762887
2-4
Parameters that Characterize Insulators
In this section several parameters that define insulator are given for additional definitions, see
IEEE Standard Dictionary of Electrical and Electronic Terms, ANSI/IEEE Std 100 [19].
Dimensional Parameters
Several parameters have been defined to characterize insulator shape and dimensions. This
section defines the most often used parameters.
•
Section length. The section length (also known as connecting length or axial length) refers to
the shortest distance between fixing points of the live and grounded (earthed) hardware,
ignoring the presence of any stress control rings, but including intermediate metal parts along
the length of the insulator (see Figure 2-5).
a) Disc insulator string
b) Longrod insulator
Figure 2-5
Definition of section length.
•
Dry arc distance. The shortest distance in the air external to the insulator between those
parts that normally have the operating voltage between them. The dry arc distances of
various types of insulator configurations are illustrated in Figure 2-6. Note that insulator
hardware such as corona rings, conductor shoes will influence the dry arc distance, as shown
in Figure 2-6 (c). This dimension is usually dictated by the desired lightning or switching
impulse withstand strength.
11762887
2-5
a) Disc insulator string
b) Longrod insulator without grading ring
c) Longrod insulator with grading ring
Figure 2-6
Definition of dry arc distance.
•
Strike distance. The strike distance is the shortest distance from the energized hardware to
the grounded hardware or structure (see Figure 2-7). The strike distance may correspond to
the dry arc distance.
Figure 2-7
Definition of strike distance in comparison to dry arc distance and section length. I-string on the
left and V-string on the right.
11762887
2-6
•
Leakage (or creepage) distance. The shortest distance over the insulator surface between
the end-fittings is the leakage distance, as shown in Figure 2-8. For a string of insulators, it is
the sum of the leakage distances of the constituent units but excluding the intermediate
metallic fittings. The leakage distance is also called creepage distance in some countries. The
leakage distance is usually determined by the required contamination performance of the
insulator.
Since a linear relationship exists between the contamination flashover strength and leakage
distance, the concept of specific leakage distance is commonly used. In the first edition of
IEC publication 60815 [20], the “specific creepage distance” was defined as the leakage
distance divided by the phase-to-phase value of the maximum voltage for the equipment. For
this definition, it was assumed that the insulation was installed between phase and ground,
which is not always the case. To overcome this deficiency, IEC introduced the “unified
specific creepage distance” concept [21], which is the leakage distance divided by the
maximum operating voltage across the insulator. For the same pollution class, the unified
specific creepage distance is √3 times the specific creepage distance. Both are usually
expressed in mm/kV.
a) Disc insulator string
b) Longrod insulator
Figure 2-8
Definition of leakage distance.
•
Protected leakage (or creepage) distance. This parameter is the part of the leakage distance
that is not easily accessible to natural cleaning. As shown in Figure 2-9, it is defined as the
part of the creepage distance on the illuminated side of the insulator that would lie in shadow
if light were projected on to the insulator at 90° (or 45° in special cases) to the longitudinal
axis of the insulator.
11762887
2-7
Figure 2-9
Protected leakage, or creepage, distance.
•
Form factor. The form factor, Kf, gives the relationship between the resistivity of a surface
layer and the overall resistance of that same surface. This dimensionless ratio is calculated by
the integral of the reciprocal value of the insulator circumference along the length of the
leakage path (L) (see Equation 2-1 and Figure 2-10).
𝑲𝑲𝒇𝒇 =
𝟏𝟏 𝑳𝑳 𝒅𝒅𝒅𝒅
∫
𝟐𝟐𝟐𝟐 𝟎𝟎 𝒓𝒓(𝒍𝒍)
Eq. 2-1
Figure 2-10
Definition of form factor.
•
Surface area. When Equivalent Salt Deposit Density measurements are being performed, it
is necessary to know the surface area of the insulator over which the measurement is
performed. Evaluating the integral of the insulator circumference along the length of the
leakage path (L) gives the surface area, as shown in Equation 2-2.
𝑲𝑲𝒇𝒇 =
𝟏𝟏
𝑳𝑳 𝒅𝒅𝒅𝒅
∫
𝟐𝟐𝟐𝟐 𝟎𝟎
Eq. 2-2
𝒓𝒓(𝒍𝒍)
The insulator parameters can be obtained from the manufacturer or by using a scan of the
insulator profile and a numerical evaluation of the surface integrals. Figure 2-11 and Table 2-1
show an example for a typical disc insulator used in multiple disc strings on many transmission
lines.
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2-8
Distance from bottom (mm)
80
60
40
20
0
0
20
40
60
80
100
120
140
Radius (mm)
Figure 2-11
Insulator measurements.
Table 2-1
Calculated parameters for the insulator shown in Figure 4.2-12.
Top
Bottom
Total
--
--
146
Leakage distance (mm)
125.18
214.46
339.64
Surface area (cm2)
746.95
1151.44
1898.39
0.24
0.46
0.70
Section length (mm)
Form factor
For the example above, the 146-mm (5¾ in.) spacing from cap to pin of the insulator, multiplied
by the number of insulators in the string, gives a close estimate of the dry arc distance of the
insulator. The sum of the top-surface and bottom-surface leakage distances (340 mm, [13.4 in.]),
multiplied by the number of insulators, gives the overall leakage distance. If 25 of the insulators
shown in Figure 2-11 are used, the dry arc distance will be about 3.65 m (143.75 in.), and the
leakage distance will be 8.5 m (335 in.).
Mechanical Characteristics
The mechanical characteristics of an insulator is defined in terms of the following parameters as
applicable:
•
•
Suspension insulators:
- Specified Mechanical Load (SML). The SML is the minimum tensile mechanical
failing load of the composite suspension insulator under short time testing. It is up to
manufacturers to determine the SML of an insulator.
- Routine Test Load (RTL): This is the level of mechanical tensile load which all
assembled insulators are subjected to during the routine mechanical test. The RTL is
defined as 50% of the SML.
Composite Line Post insulators:
- Specified Tensile Load (STL). The STL is the minimum tensile mechanical failing load
of the composite line post insulator under short time testing. It is up to manufacturers to
determine the STL of an insulator.
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2-9
Specified Cantilever Load (SCL). The SCL is the cantilever mechanical load which the
insulator can withstand under specified conditions. It is up to manufacturers to determine
the SCL of an insulator.
- Minimum Design Cantilever Load (MDCL) or Reference Cantilever Load (RCL).
MDCL or RCL is the load level above which damage to the core begins. It is therefore
the ultimate level for service loads. The manufacturer specifies the MDCL and its
direction.
Other Mechanical Characteristics:
- Combined Mechanical and Electrical Strength (ANSI) or Electromechanical
Strength (IEC) (Disc insulators only) – The maximum tension load at which the
insulator fails to perform its function either electrically or mechanically, when performed
under specified conditions of test, and when voltage and mechanical stresses are applied
simultaneously.
- Mechanical Impact strength (Disc insulators only) – The impact that the shell of an
insulator can withstand under specified conditions without failing a momentary flashover
test.
- M&E strength (Disc insulators only) – Abbreviation for combined mechanical and
electrical strength.
- Thermal Mechanical Strength – The tension load that the insulator can withstand for a
specified number of thermal cycles and time as confirmed by a subsequent M&E or
Electromechanical strength test.
- Time-load Withstand Strength – The tension load that the insulator can withstand for a
specified duration of time without failing a subsequent flashover test.
- Tension Proof or Routine Test Load – The tension load that is applied to the insulator
at the time of manufacture as a guarantee of its mechanical strength.
- Ultimate Mechanical Strength – The tension load that is applied to the insulator to
demonstrate its maximum mechanical strength and at which physical separation of the
insulator occurs releasing mechanical load.
-
•
Electrical Characteristics
The electrical characteristics of an insulator is defined in terms of the following parameters as
applicable:
•
•
•
Flashover Voltage – The voltage at which an electrical discharge, or flashover, occurs over
the external part of an insulator between hardware ends.
Standard Lightning Impulse Voltage – A unidirectional transient voltage that rises to a
peak value with a rise time of 1.5 microseconds and then falls more slowly to zero having a
time to 50 percent of the peak value in 50 microseconds and whose characteristics are
defined in IEEE Std 4 and IEC 60060-3.
Standard Switching Impulse Voltage – A unidirectional transient voltage that rises to a
peak value with a rise time of 250 microseconds and then falls more slowly to zero having a
time to 50 percent of the peak value in 2500 microseconds and whose characteristics are
defined in IEEE Std 4 and IEC 60060-3.
11762887
2-10
•
•
•
•
•
•
•
•
•
•
•
•
Critical flashover voltage (CFO), which is the crest value of an impulse wave that, when
applied under standard conditions, causes flashover on 50% of the total number of impulse
applications. This applies to both positive and negative polarity impulses.
Basic insulation level (BIL) is the electrical strength of insulation expressed in terms of the
crest value of a standard impulse under standard atmospheric conditions. BIL may be
expressed as either statistical (10% flashover probability) or conventional (withstands a
specified number of impulse applications). The statistical BIL is applied to self-restoring
insulation, and the conventional, to non-self-restoring insulation.
Impulse Withstand Voltage – which is the crest value of an impulse wave that, when
applied under standard conditions, causes flashover on 10% of the total number of impulse
applications. This applies to both positive and negative polarity impulses.
Low Frequency – Low frequency in insulator standards refers to any frequency between 15
and 100 hertz, but power frequency of 50 or 60 hertz is most common. In this guide, low
frequency refers to the power frequency of 50 or 60 Hz.
Low Frequency Flashover Voltage – The rms value of the power frequency voltage that
causes a flashover of an insulator under specified conditions of test.
Low-Frequency Dry Flashover Voltage – The low frequency flashover voltage of an
insulator under specified dry conditions of test.
Low-Frequency Wet Flashover Voltage – The low frequency flashover voltage of an
insulator under specified artificial rain conditions of test.
Low-Frequency Puncture Voltage – The rms value of power frequency voltage that causes
puncture of the shell under specified conditions of test.
Puncture – Puncture refers to the dielectric breakdown of the insulator dielectric. On
porcelain insulators this is sometimes identified as a pin-cavity.
Puncture under oil Voltage – The rms value of the power frequency voltage that causes
puncture of the insulator dielectric while the insulator is immersed in oil whose purpose is to
suppress external flashover.
Radio Influence voltage – The voltage measured in microvolts from corona on insulators
when measured under specified conditions of test, and at 1000 kHz, which is a measure of
the quietness of an insulator in generating radio interference.
Steep-front-of-wave – A unidirectional transient voltage that rises to a peak value with
steepness on the front between 1000 and 4000 kV per microsecond for testing the dielectric
strength of the porcelain/glass dielectric in the interval of time before flashover of the
insulator occurs.
Surface Properties
One of the most important surface characteristics of an insulator is how it interacts with water on
its surface. This is described by the concept of surface wetting which describes how well a liquid
adheres to a surface. The wetting of a surface is determined by the relationship between the
cohesion forces in the liquid and the adhesion forces between the liquid and the surface. If the
adhesion is stronger than the cohesion then the liquid will spread over the surface and if the
cohesion is stronger, then the liquid will contract to form droplets on the surface. The degree of
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wetting is normally described in terms of hydrophobicity or water repellency. A surface that is
easily wettable is called hydrophilic and one that is not is hydrophobic. Examples of a
hydrophobic and a hydrophilic insulator are provided in Figure 2-12.
a) A hydrophobic surface (i.e., high hydrophobicity).
b) A hydrophilic surface (i.e., low hydrophobicity)
Figure 2-12
Examples of a hydrophobic and a hydrophilic polymer surface.
Important characteristics of a surface that determines its degree of wetting on a surface are
Surface energy and surface roughness [22].
In material science the surface energy is defined as the amount of work per unit area which is
necessary (J/m2) to create a new surface. For liquids, the surface energy of liquids may also be
expressed as Surface Tension (N/m) which is dimensionally equivalent. Materials with a
relatively high surface energy, such as most metals, glasses and ceramics are easily wettable and
thus hydrophilic, while materials with a relative low surface energy—such as polymer materials
like silicone rubber—would be water repellent, or hydrophobic.
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Another important surface property that determines its wettability is surface roughness. For
surfaces where the liquid penetrates the surface roughness it is found that increased surface
roughness will enhance the wettability for hydrophilic surfaces, and it will also enhance the
water repellency of hydrophobic surfaces. [22]
Hydrophobic Materials
Hydrophobic surfaces have a low surface energy, which causes water to bead when coming into
contact with it. In contamination conditions, this characteristic provides an advantage because it
inhibits the formation of a continuous water layer on such a surface. This quality, in turn, reduces
leakage currents and the likelihood for flashover.
Hydrophobic surfaces are normally associated with polymer insulators and, more specifically,
with silicone rubber (SIR) insulators. Certain formulations containing low- molecular-weight
silicone (LMWS) chains have the added advantage that, through the migration of LMWS,
hydrophobicity may be transferred to the pollution layer, making it hydrophobic as well [23],
[24]. Materials with this ability is named hydrophobicity-Transfer materials or HTM [26].
However, conditions exist when these materials might temporarily or permanently lose their
hydrophobicity. This loss occurs normally during either prolonged wetting events or under longterm discharge activity.
Hydrophilic Materials
A hydrophilic surface is characterized by a high surface tension that causes water to form a thin
film on the surface. In polluted conditions the surface conductance of the insulator increases
during wetting conditions, allowing increased leakage currents across the surface of the insulator.
Under critical contamination and wetting conditions, the conductivity may become high enough
to result in flashover [27].
Glass and porcelain insulators are the best examples of insulators that have a hydrophilic surface.
Polymer insulators that are typically classified as hydrophilic are those with a housing of
ethylene propylene rubbers (EPR). Since these materials cannot transfer to the pollution layer
they are identifies as non-hydrophobicity transfer materials or Non-HTM [26]. It may be noted
that in some cases silicone additives have been added to EPR material to give it hydrophobic
properties for better performance in contaminated environments.
Categorization of Hydrophobicity
The hydrophobicity of a material is a dynamic property that may change over time as the
material responds to the stresses it is subjected to. In most cases, stressing results in a loss of
hydrophobicity that may be permanent or temporary. Because of this dynamic nature, it may be
necessary to perform regular evaluations to monitor its condition. These evaluations may be done
by any of the following three methods, which are fully standardized and described in IEC
Technical Specification 62073 [28]:
•
•
•
Measuring the contact angle between the surface of the insulator and a water drop.
Measuring the surface tension of the insulator housing.
Comparing a section of wetted surface material against images of standard wetted surfaces.
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Measurement of the Contact Angle
An indication of the surface wetting properties of a given material may be obtained by placing a
water drop on a flat section of the material and measuring the static contact angle, θC, as defined
in Figure 2-13. Although θC is usually defined as the contact angle, some publications refer to the
outside angle (i.e., 180 - θC) as the contact angle.
Figure 2-13
Definition of the static contact angle.
The static contact angle is related to the surface tension—and therefore the degree of
hydrophobicity—if the solid material is perfectly smooth and homogeneous. This relationship is
given by the so-called Young’s equation [29].
𝜸𝑺𝑮
𝜸𝑺𝑳
𝜸𝑳𝑮 𝑪𝑶𝑺 𝜽𝑪
Eq. 2-3
Where:
γSG is the solid-gas surface tension
γSL is the solid-liquid surface tension
γLG is the liquid-gas surface tension
θC is the contact angle
If the contact angle, θc, is larger than 90o then the surface is tending hydrophobic and for angles
smaller than 90o the surface is tending hydrophilic. This means that larger angles indicate a
higher level of surface hydrophobicity.
Since the surfaces of polymer insulators are generally not homogeneous or smooth, the static
contact angles do not conform scientifically with Young’s equation, which limits the accuracy
by which this method can be used to determine the wettability of the insulator surface [29]. For
most rough hydrophilic surfaces, it will be found that the contact angle is smaller than on a
smooth surface and on hydrophobic surfaces the contact angle is larger [30]. Despite this
shortcoming, this method is still considered as a practical alternative to determine the ability of
the polymer to repel water.
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Several permutations of the contact angle method have been devised to improve its accuracy and
practical applicability. For example, these permutations take account of the effect of temperature
and gravity. Some of the most commonly used alternatives are:
1. A small water drop on the material surface is viewed through a stereoscopic microscope. If
the water drop is small (≈ 0.001 ml), the effect of gravitational forces can be neglected. By
measuring the height of the drop and the radius at the base of the drop, as seen in Figure
2-14, the contact angle θC can be calculated by the formula shown in Equation 2-4 [31].
𝜽𝜽
𝒕𝒕𝒕𝒕𝒕𝒕 � 𝑪𝑪� =
Where:
𝟐𝟐
𝒉𝒉
Eq. 2-4
𝒓𝒓
θC is contact angle.
h is drop height.
r is radius at the base of the drop.
These measurements are usually performed at specific temperatures after the drop has been
allowed to settle for a predetermined length of time.
Figure 2-14
Measuring height and radius of a drop.
2. Also for this method, a small water drop on the material surface is viewed through a
stereoscopic microscope or a high-powered lens. An image is captured using either analog or
digital methods (i.e., photograph or video digitizer). A line tangent to the water drop surface
is projected, and the contact angle is measured as shown in Figure 2-14. If the image is
digitized, automated software measurements are available to make this measurement [32].
3. A small water drop is placed on an inclined section of material, and the receding θr and
advancing θa contact angles are measured as shown in Figure 2-15. The mean surface tension
may then be calculated by subtracting θr from θa [29].
Figure 2-15
Contact angle on an inclined surface.
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Other methods not considered here include the use of a goniometer and extrapolation from
digitized images to measure the contact angle.
Measurement of the Surface Tension
IEC 62073 [28] describes a method whereby the surface tension of an insulator is measured by
spraying the surface with a range of organic liquid mixtures with predefined surface tension. An
indication of the surface tension is obtained by measuring the time the sprayed-on liquid takes to
break into distinct droplets. The surface tension of the insulator surface is lower than that of the
liquid if the time to break up is less than 2 seconds. Different liquid mixtures are sprayed on until
one is found with a breakup time that is closest to 2 seconds. The surface tension of this liquid is
indicative of that of the insulator.
Classification Against Standard Samples
A simple and practical approach to classify the hydrophobicity of insulators has been developed
[33]. This method is used extensively in the industry and has been adopted by the IEC [28]. With
this method, a common spray bottle is used to spray the area of interest with a fine mist of
uncontaminated water from a distance of between 10 and 25 cm for a duration of 20–30 s.
Within 10 s after the completion of the spraying, the wetted surface is inspected and categorized
according to standardized photographs and descriptions.
While the results are somewhat subjective, they are considered adequate in most situations.
Seven hydrophobicity classes (HC) are defined, ranging from 1, which is completely
hydrophobic, to 7, which is completely hydrophilic. These classes are described in Table 2-2,
and the corresponding photos are presented in Figure 2-16 [33].
Table 2-2
Relationship between the Hydrophobicity Class (HC) and Contact Angle [33]
HC
Description
1
Only discrete droplets are formed. ϴC > 80 degrees for most of the droplets
2
Only discrete droplets are formed. 50 < ϴC < 80 degrees for most of the droplets
3
Only discrete droplets are formed. 20 < ϴC < 50 degrees for most of the droplets. Usually they
are no longer circular.
4
Both discrete droplets and wetted traces form the water runnels are observed (i.e., ϴC = 0).
Completely wetted areas < 2 cm2. Together they cover <90% of the tested area.
5
Some completely wetted areas > 2 cm2, which cover <90% of the tested area.
6
Wetted areas cover >90%, i.e., small unwetted areas (spots/traces) are still observed
7
Continuous water film over the whole tested area.
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HC1
HC2
HC3
HC4
HC5
HC6
Figure 2-16
Standard pictures of the different STRI hydrophobicity classifications [33]. HC7, a completely
wetted surface, is not shown.
Ceramic and Glass Suspension Disc Insulators
Overview and Terminology
A suspension insulator, which is sometimes referred to as a “disk insulator” or “bell” is defined
by ANSI C29.1 as an insulator with attached metal parts having means for non-rigidly
supporting electric conductors [34]. In the IEC standards this insulator type is identified as “cap
and pin insulator” [35], but this term in conflict with ANSI C29.1 in which “cap and pin”
identifies a different kind of insulator (see Figure 2-3).
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Figure 2-17
Components of a ceramic (porcelain) disc insulator.
Figure 2-18
Components of a toughened glass disc insulator.
Figure 2-17 and Figure 2-18 shows the components of a porcelain and glass suspension disc
insulators respectively [37] [1]. They consist of a dielectric shell which is cemented between a
cap and pin metal end-fittings. The end-fittings are normally a malleable or ductile cast iron cap
and a forged steel pin, both hot-dip galvanized. The internal shape of the cap and the shape of the
pin head is designed so that the dielectric material is placed under compression under normal
loading conditions. The dielectric material of modern insulators is either made of electrical
porcelain or toughened glass, which both offer very high dielectric and mechanical strengths.
Portland type III or alumina cement is used to fix the metal end fittings to the dielectric shell.
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The following terms are commonly used to describe components of porcelain or glass insulators:
•
•
•
•
•
•
•
•
•
•
•
Bituminous Coating/Varnish - The protective coating that is applied to the pin and to the
inside of the cap that is in contact with the cement.
Cement – The grout that is used to attach the hardware to the shell of the insulator.
- Neat Cement – Insulator grout consisting of cement and water without filler.
- Mortar – Insulator grout consisting of cement, filler and water.
- Portland Cement – The type of cement used in porcelain insulators.
- Aluminous Cement – The type of cement used in both toughened glass and porcelain
insulators.
Cotter Key – A key resembling a hairpin, inserted in the cap of an insulator, and positioned
between the ball and socket of two consecutive units, for ensuring inadvertent disengagement
during operation or handling of a string of insulators.
Floc (Toughened Glass Only) – A partially conductive layer resembling felt that is applied to
the outer ridge of the cap on a toughened glass insulator.
Glaze (Porcelain Only) – The glass-like layer that covers the fired porcelain shell whose
purpose is to provide a smooth surface and to add strength to the porcelain shell.
Hardware – The metal parts cemented to the shell of a suspension insulator for supporting a
conductor from a structure or another conductor.
- Pin – The bottom metal part of an insulator that is cemented to the shell for attaching the
insulator to conductors or structures.
o Ball – The term that describes the shape of the lower part of the pin.
o Tongue – The term that describes the shape of the lower part of the pin.
• Cap – The top metal part of an insulator that is cemented to the shell for attaching the
insulator to conductors or structures.
o Socket – The cavity in the cap of an insulator to accommodate the ball of another
unit.
o Clevis – The term that describes the type of connection on the cap of an insulator to
accommodate the tongue of another unit.
Head – The portion of the shell in which the hardware is cemented to.
Petticoat – A term used to describe the lower part of the porcelain or toughened glass shell
and synonymous with ribs.
Pin-cavity – The cavity in the shell of an insulator for cementing of the pin.
Ribs – The lower section of a shell that resembles a corrugated section of an insulator and is
synonymous with petticoat.
Sand (Porcelain Only) – A coarsely ground fired porcelain that is applied at the time of
glazing to the inside of the pin-cavity and the outside of the head of a porcelain insulator
whose purpose is to form a key for the cement.
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•
•
•
Sand Band (Porcelain Only) – The region in which sand has been applied to a porcelain shell
and in contact with cement.
Shell – A single fired porcelain or toughened glass member, without cement or hardware,
intended to form a part of a suspension insulator.
Skirt – The term that sometimes is used to describe the portion of the shell that extends
beyond the cap of an insulator.
Dielectric Shell
The dielectric shell in a suspension insulator has the dual function of providing the necessary
electrical insulation and to carry, mechanically, the line loads that the insulator must support.
Both porcelain and toughened glass are mechanically strongest in compression, and the design of
the insulator utilizes this characteristic property as illustrated in Figure 2-27. Electrically, along
with withstanding the normal power frequency line voltage, the porcelain or toughened glass
shell must be capable of withstanding the various system surges from lightning impulses to
switching surges, without puncture while being subjected to steady state and transient
mechanical loads, under a wide range of ambient temperatures.
Electrical Porcelain
Electrical-grade porcelain comprises quartz or alumina filler particles that are embedded in a
glassy matrix which is produced by the reaction between the clays and flux. These porcelains are
classified into types that are characterized by the dominant filler that is present. In many
respects, these types are analogous to ordinary concrete, in which the filler plays the same role as
aggregate or stone in concrete. Although there are at least six or seven types of porcelains that
are used for electrical insulators, there are only three types in common use for suspension
insulators and these are quartz, alumina and cristobalite.
Porcelain shells have a glazed surface that provides a smooth surface and places the porcelain
under compression to further enhance its mechanical strength.
Quartz Porcelain
Microscopic examination of quartz porcelain shows discrete particles of quartz filler in the
glassy matrix phase. The composition of the matrix and the particle size of the quartz filler are
important in the mechanical and electrical strengths of the porcelain. As the thermal expansions
of the quartz and the matrix are quite different, microcracks are often seen around the filler
particles, for example as can be seen in Figure 2-19. These cracks are also dependent on the
particle size of the quartz. Quartz porcelain is sometimes referred to as siliceous porcelain, which
has the lowest mechanical strength of the porcelains, requires a lower firing temperature and has,
therefore, lowest in cost to produce of the three types. It is generally used for low strength
suspension insulators, for example insulators with a 15,000 lb (66.7 kN) M&E strength.
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Figure 2-19
Scanning Electron Micrograph at X1000 magnification showing microcracks around a large filler
particle
Alumina Porcelain
Analogous to quartz porcelain, alumina porcelain has alumina as the dominant filler embedded in
the glassy matrix phase. However, since the thermal expansion coefficients of the alumina filler
and the glassy phase are closer, aluminous porcelain is considerably stronger than the siliceous
porcelain. Alumina porcelain requires a firing temperature somewhat higher than quartz, and is,
therefore, more expensive. As such it is used for the higher strength suspension insulators, for
example insulators with 25,000 lb (111 kN) M&E strength rating and higher.
Cristobalite Porcelain
Cristobalite is a higher order form of quartz, in that it has the same chemical composition of
quartz, but it has a different crystal lattice structure. For this phase to form in porcelain, it is
necessary that the quartz filler be pulverized to a very fine grain size. When fired at a
temperature comparable to alumina porcelain, this polymorph of quartz develops. The glassy
matrix phase also has a slightly different composition to that of normal quartz porcelain, which
yields a porcelain slip that is more difficult to work with, consequently requiring a greater
process control, particularly in the forming stage. In this type of porcelain, the cristobalite
particles are subjected to a compressive force that develops in the glassy phase. Thus, the
formation of microcracks between the cristobalite particles and the glassy phase are inhibited and
are therefore not present. Cristobalite is characterized by a significantly higher strength than
either quartz or alumina porcelain, but is much more expensive to produce, and consequently
offered by only a few suppliers.
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Glazing
All porcelain suspension insulators are glazed which provides a smooth, glassy surface of
uniform color. Chocolate brown and Munsell grey are the most common colors; the latter is a
pale blue, which is intended to match a slightly overcast sky. However, in addition to color, glaze
has two other important functions:
1. The glaze increases the strength of the porcelain as the glaze formulation is selected to have a
lower thermal expansion than the porcelain body, so that in the fired porcelain the glaze is in
compression. This increases the tensile strength of the porcelain by about 25 percent over an
unglazed porcelain body.
2. Contaminants do not adhere readily to the smooth surface provided by the glaze and are
therefore more easily removed by rain or maintenance washing.
Resistive glaze, or RG, insulators are porcelain post insulators that have a semiconductive glaze
in place of the normal insulating glaze. The conductivity of the glaze is imparted by an antimony
doped tin oxide, which is part of the glaze composition. The dopant is adjusted to provide
approximately 1.0 mA of leakage current through the glaze and a power dissipation of
approximately 10 watts per unit. The RG insulators perform in three ways:
1. By making the potential distribution over the string more uniform due to resistive grading
swamping out the stray capacitive effects of normal suspension insulator capacitive grading.
2. Provides heating of the surface layer to ward off moisture condensation.
3. Permits the potential grading of the dry areas on an insulator surface thereby preventing dry
band arcing.
These three advantages have the net effect of significantly improving the operation of line
insulation in contaminated conditions. However, it must be noted that constant wetting, as for
example very near to the seacoast, these insulators may not perform as intended. In addition,
their life may be very limited in these regions as corrosion of the glaze, particularly at the
hardware ends may open up. In addition, in regions where the contaminant is highly conductive,
thermal runaway of the glaze has been known to occur, causing the shell to shatter, or puncture.
RG insulators are not standardized and only are only available as post insulators with standard
profiles. Manufacturers can adjust the resistivity of the glaze, thereby providing custom
insulators for problem areas. The economic justification for these insulators needs to factor in the
cost of the additional energy losses as a fully insulated line can cost as much as $1000/mile/year
at 115 kV.
Sanding
Sanding refers to a granular material, or grit, that is applied to a porcelain shell and coated with a
glazing slip. It is attached to the porcelain by the glaze after firing – See Figure 2-20. This grit is
applied to the inside and outer portions of the insulator head in contact with the cement to
provide a “key” between the porcelain shell and cement. Without this key, pullout of the pin and
pull-off of the cap would occur when the insulator is tensioned. The grit that is normally used is
granular fired porcelain having a lower thermal expansion than that of the body. The size and
thermal expansion coefficient of the grit have a significant effect on the mechanical performance
of the insulator.
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Figure 2-20
Sanding layer on the head of a porcelain shell
Toughened Glass
For AC insulators Soda lime glass is used for the manufacturing to the dielectric shell. It
comprises of the following: [38]:
•
•
•
Silica (SiO) – 65-75 %
CaO +MgO – 9-12%
Na2O +K2O – 12–18%
Glass is an amorphous solid of which the molecules are trapped in different levels of disorder
depending on how fast the cooling took place. Fast cooling results in a lower density glass than
when it is cooled slowly. This characteristic is exploited to make toughened glass which has a
high mechanical strength. Important temperatures for electrical grade glass [1]:
•
•
•
•
•
Fully melted state >1800°C
Gob temperature 800-900°C, viscous fluid
Solidify 740-780°C
Equalization ≈ 720°C
Lower limit for toughening process ≈ 400°C
The processing involves melting the raw materials in a furnace, which is followed by pressing of
the glass shell in metal molds. The shells are then toughened by heating, which is followed by
rapid cooling of the glass surface. When cooling down, the outer surface contracts and solidifies
into a low-density glass, which places the surface under compression. The slower cooling of the
interior causes it to contract into a high-density glass, which places it under tension against the
solidified surface. The resulting stress pattern provide the dielectric element with a high
mechanical strength.
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Cement
Cementing is a misnomer as cement is not an adhesive material, but it is an effective grout for
filling the gap between the dielectric shell and the hardware. Because of the design of the
insulator the cement is required to bear the full mechanical loading of the insulator and as such
must have a high compressive strength. The cement fulfills, therefore, an important function in a
suspension insulator, but this aspect was often underappreciated, resulting in many problems. For
example, on porcelain insulators the delayed hydration expansion of the cement with time
introduced hoop stresses resulting in cracking of the porcelain shell.
Porcelain insulator manufacturers traditionally used Portland Type III and only used aluminous
cements when higher strength units are needed. Glass insulator manufacturers typically only use
aluminous cement.
During the 1950s, several manufactures recognized the cement expansion problem in porcelain
suspension insulators and introduced cement mortar, which is simply Portland cement, silica
sand and water. The relatively stiff and volume-stable sand restrains and reduces the volume
changes that occur in the paste (Portland cement and water) portion. This also reduces the initial
shrinkage that takes place as the cement cures, thereby preventing cracks from forming in the
cement as it cures. However, controlling the mixing of the mortar is an added process in the
manufacture of porcelain insulators and one that most manufacturers have since avoided in favor
of neat cement. Neat cement is simply Portland Type III or aluminous cement and water and is
nowadays preferred by the manufacturers because of its faster rate of strength gain, thus
requiring less time between assembly and proof-strength testing, which speeds up the
manufacturing process.
Portland Cement
Portland cement cures at an exponential rate taking about 30 days to cure completely and to
attain its full strength, which is much too long a period before proof testing can be done which is
followed by crating for shipment. However, the cure can be accelerated by keeping the cement
moist for one or two days. Therefore, most manufacturers will store the assembled insulators in a
steam cabinet or in a water bath for several days. A few manufacturers have implemented
conveyor belts in a water bath and the assembled units are placed on the belt to be removed at
the end of the travel after one or two days for proof testing. By heating the water, curing can be
made to accelerate so that the proof test can be performed after a few hours.
Portland cement is known to expand with time, a mechanism referred to as delayed hydration
expansion. In modern cements, this expansion occurs mainly due to periclase (MgO) and with
moisture forming brucite (Mg(OH)2) [17]. A secondary expansion occurs due to the formation of
ettringite from excess gypsum and moisture. A small percentage of gypsum is ground together
with Portland cement to control the setting properties and optimize its strength development.
Magnesium is an impurity in the raw materials to make Portland cement. ASTM C 150 places a
limit on the total MgO and gypsum contents [18] and on the expansion as determined by an
autoclave test outlined in ASTM C151 [19]. However, the expansion limit in ASTM C150 has
been established by the construction industry, which has gradually lowered the expansion limit
over years of use, but it has been shown to be much too high for porcelain suspension insulators.
ANSI recognized this shortcoming and in 1988, an expansion limit to the cement for porcelain
suspension insulators was introduced into ANSI C29.2.
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Aluminous Cement
Aluminous cement, which is also known as Ciment Fondu, from the French who first introduced
it, has been traditionally used in the manufacture of toughened glass suspension insulators (see
Figure 2-21), and is used by few manufacturers of porcelain insulators. Aluminous cement has
several advantages:
•
•
•
Alumina cement is a quick curing cement (working life 20 minutes) which allows for short
curing times, and quicker feedback on the quality of the assembly process as the routine
testing can be done relatively quickly after insulator assembly. The cement is cured in a
warm water bath for some hours.
Alumina cement has a similar coefficient of expansion (10.0x10-6 mm/mm/°C) than the steel
pin (11.7x10-6 mm/mm/°C), malleable cast iron cap (11.5x10-6 mm/mm/°C) and the glass
disc (9.1x10-6 mm/mm/°C), which results in a good thermal mechanical characteristics of
the insulator [39].
Alumina cement does not expand, to the same degree as Portland cement (i.e., normal
building cement), when curing. The insulator dielectric shell is therefore not subjected to
hoop stresses as a result of delayed hydration expansion.
The main disadvantage of this alumina cement is the slightly higher cost. Mortar compositions
are sometimes used to reduce cost.
Figure 2-21
Cured alumina cement used on a toughened glass insulator
Metallic Fittings
The metal components cemented to the porcelain or toughened glass shell provides a means of
attaching insulators to structures and conductors. They also provide a means of transmitting
mechanical loads.
To meet these functions, the metal hardware must be of adequate strength, have dimensional
accuracy for interchangeability, and resistant to atmospheric conditions.
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Cotter Keys
A cotter key is inserted into a hole in the cap between the ball and the socket of coupled
suspension insulators to prevent unintentional uncoupling during service or handling. The keys
are formed into a shape that resembles a hairpin, from hard drawn wire, having the shape of the
letter D, with the rounded part of the wire on the outside of the formed shape, and with a hump
formed on one leg of the pin, and near to the loop in the pin (see Figure 2-22).
Cotter Key
Figure 2-22
An example of a cotter key made of phosphor bronze
Various materials are permitted in the standards, but stainless steel is the most common but
phosphor bronze is also used. The split end of the cotter key is inserted into the hole from the
outside of the cap so that the hump passes through the hole, developing a positive locking of the
key. The split end of the cotter key is separated with a tool, so that the ends of the key splay in
opposite directions underneath the ball. The various standards specify the force that must be
applied to both insert and remove the key.
Cap
Both black heart malleable cast iron and ductile cast iron are used for the caps of suspension
insulators. The characteristics of black heart malleable iron that makes it suitable for insulators
are its excellent cast ability, high fatigue limit, and good resistance against impact loads. Ductile
cast iron not only has strengths comparable to that of steel, but it also has cast ability comparable
to black heart malleable iron. An example of a typical cap used for a glass insulator is shown in
Figure 2-23.
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Flock
Figure 2-23
An example of a cap used for a toughened glass insulator
Casting and forging are done in the traditional manner, and casting and forging seams are ground
down prior to galvanizing. The metal cap is galvanized for protection against corrosion. The
galvanizing thickness is typically 85μm (3 x 10-3 in) but in some cases manufacturers offer a
greater thickness for application in severe environmental conditions. The shape and dimensions
of the cap determined by the head of the dielectric shell. The proportion of cap size is determined
by the required mechanical strength and material used. Malleable iron material has good strength
and resilience at low temperatures. This is an important feature for in-service cyclic mechanical
loading and varying weather conditions.
Pin
Pins are made of forged carbon- or high-tensile steels. They are heat treated to provide strength
and ductility and hot dipped galvanized for protection against corrosion. The galvanizing
thickness is typically 85μm but in some cases, manufacturers offer a greater thickness for
application in severe environmental conditions. Following galvanizing, a “varnish” coating
of bitumen is applied to the pin at end cemented into the porcelain or toughened glass shell
(Figure 2-24). The coating smooths the galvanized surface to prevent the cement from shearing,
thereby providing good contact between pin and cement and stops chemical reaction between
wet cement and galvanized pin.
Varnish/coating
Sacrificial Zinc Sleeve
Figure 2-24
Examples of insulator pins with and without a sacrificial Zinc sleeve
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Sacrificial Zinc Sleeve
For highly contaminated environments, the galvanizing on the pin may corrode over time and
lose mechanical strength due to in-service electrical discharge activity. To prevent this, insulator
manufacturers cast a Zinc sleeve on the pin as shown in Figure 2-24. Due to its position (see
Figure 2-25) and mass of material, the collar acts as a sacrificial anode and protects the pin
against galvanic action. The zinc sleeve must be of high quality (purity of no less than 99.8 %)
[40].
Sacrificial Zinc Sleeve
Figure 2-25
A close up view of the pin cavity area showing the positioning of the Zinc sleeve with respect to
the cement filling
Connections
The traditional designs for the suspension insulator have been a clevis cap and tongue pin or a
socket cap and ball pin, the latter being more common today. The dimensions of the socket on
the cap and the ball on the pin are specified in the various standards, for example ANSI C29.2,
and a go-no go type of gauge is used to check for compliance with the standards. The coupling
between successive insulators is also specified. This standardization has allowed complete
interchangeability between the various suppliers. The other dimensions of the cap and pin are not
standardized and the various suppliers have attempted to optimize the strengths at the lowest
cost. A variety of cap and pin shapes is shown in Figure 2-26.
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a)
Ball and socket
b)
Clevis and tongue
Figure 2-26
Examples of various end fitting connection types
Coatings
The inner part of the cap and the portion of the pin that is in contact with the cement (see Figure
2-24) are coated with a bituminous layer. The coating is normally prepared from coal tar that has
been dissolved in a solvent such as naphtha, resembling a paint, which is applied by spraying or
dipping. The main function of this layer is to prevent galvanic action from taking place between
the galvanized layer and the cement, as Portland cements in use are highly alkaline.
However, this layer is also considered to have a secondary role, and that is to distribute the
mechanical loading between the cap and the cement, particularly when roughness in the
galvanized layer or an excessive casting seam has not been completely ground off are present
and may develop localized stresses in the porcelain. Mechanical tests at temperatures near or
below the brittle point of the bitumen support this mechanism, and the loss of petroleum fluid
with time in the coating is a recognized mechanism of aging.
A third role that is of minor importance is to act as a thermal relief barrier compensating for
differences in the thermal coefficients of expansion between the hardware and the porcelain or
glass dielectric.
Glass Only: The outer ridge of caps for toughened glass insulators are coated with a partially
conductive layer that resembles felt called floc (Figure 2-23). This layer reduces the air gap
between the cap and the glass dielectric preventing corona discharge, which is the source of RIV,
and prevents continuous discharges that may cause shattering of the glass shell.
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Mechanical Design
Both porcelain and toughened glass have a high compressive strength, which is approximately
10 times higher than their tensile strength. The head of the suspension insulators is therefore
designed to take advantage of this property.
Porcelain
Glass
Figure 2-27
Mechanical stresses in the suspension insulator resulting from insulator load
Figure 2-27 illustrates the mechanical stress across the shell when the insulator is loaded in
tension. The top end of the pin and the bottom part of the cap has conical shapes which faces
in opposite directions. This puts the interfaces of pin to cement and cement to cap under
compression. Due to the lateral separation of the main load bearing surfaces, this stress is not
purely compressive but is resolved into compressive and tensile components. An optimum
strength can be achieved with a design that minimize the tensile stress component and which
avoids stress concentrations in the head. This is achieved by optimizing the shape and orientation
of the conical load bearing surfaces through a finite element analysis of the stress that develops
in the shell.
It may be noted that the orientation of the interfaces between the dielectric shell and cement are
not parallel to the load bearing surfaces which means that they will be subjected to a shear stress.
In porcelain, pullout would occur if not for the sand layer that is fired into the porcelain glaze in
the main load bearing area of the shell (see Figure 2-20). Therefore, in a porcelain insulator, the
type and particle size of the sand is an important consideration in the design.
In toughened glass, this is prevented by the corrugations which are molded into shell (see Figure
2-28). In this case the cross section of the glass head and the design of the corrugations are
important design considerations.
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Figure 2-28
Corrugations molded into the head of a glass shell
Under loading, also the cement grout is subjected to large compressive forces and its selection is
an important consideration to ensure that it has sufficient strength is compatible with the other
materials used. Other important considerations are the type of metals used for the hardware, the
cross section of the cap and the diameter of the pin.
Considering firstly that both porcelain and toughened glass very brittle that do not yield under a
mechanical load, yet they are used in conjunction with metal hardware that will yield under the
same mechanical load. Second, the coefficients of thermal expansion of either porcelain or
toughened glass are very much different from the metal hardware and yet they are used together.
Porcelain and toughened glass are strongest under a compressive load and weakest under a
tension load, yet in the design, the shell is subjected to both compressive and tension stresses. In
addition, porcelain or toughened glass does not tolerate mechanical impact loads very well. The
shell and metal hardware are held together by cement grout, which is also a very brittle material,
with still a very different coefficient of thermal expansion. Yet, the design has been quite
successful when considering the differences in the material characteristics and has been able to
operate reliably over the temperature range of -60 to +60°C (-76 to +140°F).
Electrical Design
The external dimensions of the dielectric shell and its shape are the main parameters that
determine the external flashover performance of the insulator. These are shown and identified in
Figure 2-29.
•
•
External flashover strength (both power frequency and impulse) is determined by the dry arc
distance of the insulator (Figure 2-6). The dry arc distance is to a large extent determined by
the overall diameter of the insulator shell.
The next parameter is applicable to porcelain insulators only. The thickness of the shell,
particularly in the upper part of the head of the insulator, governs the puncture strength, both
under impulse and power frequency. As the stress across the head of an insulator is greatest
in the region shown in Figure 2-29, the radius of curvature of the head needs particular
attention, as this is where electrical punctures normally occur. After the mechanical strength
considerations have been met, the thickness of the shell is selected to pass the puncture under
oil test.
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•
The flashover performance under contaminated conditions is governed by both the leakage
and dry arcing distance. These distances are adjusted by the actual shape and diameter of the
shell. Care should be taken not to fit too much leakage distance on the insulator unit as it is
found the effectiveness of the leakage distance tend to degrade as the creepage factor (i.e.,
ratio of the leakage distance over the distance) is increased. The level of protective creepage
distance on the insulator determines to a large extent how effectively the insulator will be
wetted and naturally cleaned. In operating regions where fog is a factor in the wetting of
insulators, the protected leakage distance should be increased, which is done by increasing
the depth of the ribs as shown in Figure 2-30.
Figure 2-29
Principal dimensions that determine the electrical performance of the insulator (Note: puncture
paths apply to porcelain only)
Figure 2-30
Examples of a glass and porcelain anti-fog insulator—notice the deep under-ribs
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Manufacturing of Porcelain Suspension Insulators
Porcelain suspension insulators is manufactured in six stages as shown in Figure 2-31. These
stages can be summarized as follows:
1. The mixing of the raw materials with water forming a paste or slip which allows the raw
ingredients to be pumped to the processing stage.
2. The processing stage where water is removed from the slip in a filter press and forming moist
clay. Air is removed under vacuum and then the clay is sliced into the required size for
forming.
3. The forming stage where the clay is pressed into the required shape, allowed to dry, glazed
and the sand band applied.
4. The firing stage where the clayware is converted to vitrified porcelain.
5. The assembly stage where the hardware is cemented to the shell.
6. The testing stage where the proof test is done, and the insulators are crated for shipment.
The steps described above corresponds to the so-called wet process. Different processes may be
followed to form the raw porcelain into the insulator shell, which is steps 2 and 3 described
above. Broadly, a distinction is made between a wet- and dry-processes, which—
unsurprisingly—refers to the amount of water present in the porcelain clay when the shells are
formed. Since the wet process is more common, it is described here.
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Figure 2-31
Stages in the manufacture of porcelain shell of suspension insulators.
Mixing of the Raw Materials
The raw materials used in the manufacture of porcelain are obtained from natural deposits found
in various parts of the world. The three essential materials that go into forming electrical
porcelains are clays, fluxes, and fillers [37]. In a typical porcelain formulation, a mixture of
various clays is needed to obtain the necessary plasticity and yet control the workability so that a
wide variety of shapes and sizes of insulators can be produced. At the start of process, the raw
materials are:
•
•
Weighed
Mixed using water
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•
•
•
Screened
Separated of undesirable material, which is usually iron
Stored in cisterns fitted with paddles that keeps the mixture in constant motion, thereby
preventing settling
At this point, the clay mixture is referred to as clay slip, or simply slip.
Forming Moist Clay Wads
According to the wet-process method, the moist clay is prepared by pumping the slip from the
storage cisterns into filter presses where, under pressure, excess water is removed, yielding a
moist clay slab of a shape resembling a pancake. These pancakes are then conveyed to an
extruder, called a pugmill, where additional mixing and blending of the clay takes place under
vacuum, to remove air and moisture. A cylinder of moist clay is extruded from the pugmill, and
sliced, yielding wads of moist clay of the required volume for the forming of the insulator shells.
Forming Stage
Molding of the dielectric shell: The moist clay wads are dropped into individual plaster molds
that resemble flowerpots, with the inside shape of the mold corresponding to the outside shape of
the shell of an insulator, and these molds are conveyed to the forming stage. A polished chrome
plated steel form in the shape of the lower portion of the insulator shell is the plunging head that
forms the lower part of the shell. The plunging head is heated, lubricated by a spray of oil, and
rotated at a low speed. The head is hydraulically plunged into the wad of clay in the plaster mold,
thereby pushing and compressing the clay into the shape of the shell. Plaster molds are used as
not only are they inexpensive, and easily formed into the required shell shapes, but are also
sufficiently strong to withstand the plunging force, and they are unique as the plaster absorbs
moisture from the formed shell. Plunging of insulator shapes that have deep ribs, for example
fog-type insulators, require strict control of the plasticity of the clay to avoid cracks in the ribs of
molded shell. In addition, sharp radius of curvatures in the shell design is avoided as they lead to
a high scrap rate. In addition, a double plunge is avoided as this produces folds in the inside
corners of the head which very often leads to electrical puncture of the insulator.
Drying: The remaining moisture contained in the shells (now referred to as clayware) is
removed in controlled humidity conditions in driers. These operate on a specified temperaturetime cycle that is related to the size and complexity of the clayware. In a continuous process, the
clayware is slowly conveyed through a tunnel-like drier while in a batch process, the clayware is
stacked onto carts and wheeled into a temperature and humidity-controlled chamber. As an
additional quality control measure, the residual moisture content of sample clay pieces of
representative cross section is measured before the clayware in a drier is released for further
processing. When sufficiently dry, the clayware is removed from the molds, visually inspected
for cracks, trimmed of excess clay from the forming stage, and then conveyed for glazing.
Damaged shells are recycled by allowing them to dry, pulverizing them into clay powder, and
adding the powder to the clay slip in the cisterns.
Glazing: Feldspar is the dominant composition of insulator glaze and with the addition of fine
clays, suitable metallic oxides for color, or semiconducting properties, and an organic binder, the
mixture is wet ground to a very fine paste and water is added to form a slip. The composition is
selected to have flow characteristics at the firing temperature of the clayware to develop a
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smooth surface on the porcelain shells. In glazing, the individual shells are placed on supports
with rubber bladders that inflate, filling the pin-cavity, thereby securing the shell for glazing. The
shell, while conveyed, is rotated and dipped into a vat containing the glaze slip, which is
prevented from settling by constant circulation. On emerging from the vat, the rotation of the
shell prevents the glaze slip from slumping and drying is rapid as the clayware absorbs moisture
from the glaze slip.
Sanding: Fired porcelain in granular form (or grit) is applied to the outside of the head and to the
inside of the pin-cavity, onto the porcelain surface in contact with the cement, as key to lock the
hardware in place after cementing. This material is referred to as sand and the area on which the
sand has been applied is referred to as the sand band. While conveyed to the kiln, a glaze slip of
a slightly different composition is sprayed onto the sand band areas, which is followed by a spray
application of the sand. The sand adheres to the moist glaze. The glaze dries rapidly, holding the
sand in place for firing. Excess sand in the pin-cavity drops out when the shell is inverted.
Firing
Preparation: The heads of the clayware shells are coated with a wax, which are then placed,
head down, on the refractory lining of the kiln cars. During firing, the waxed layer burns off and
prevents the shells from sticking to the refractory. Layers of clayware are formed on the kiln car
using sheets of refractory that is supported by high temperature refractory material and built up
to the maximum height of the kiln. When completely loaded, ceramic cones are strategically
placed intermixed with the shells, which allows for a visual indication as to the combined effect
of temperature and time, or total heat input during firing, which is referred to as the “soak”. This
allows for a visual indication as to the proper soak for vitrification (formation of glassy phase
binding the various fillers) of the clayware. In addition, sample bars are fired for laboratory tests
of mechanical strength and microscopic examination of the fired porcelain.
Firing: Most manufacturers fire insulators in a continuous tunnel kiln in which the cars are
slowly conveyed through the kiln having temperature zones of a profile that allows for gradual
heating to the maximum temperature, a period of soak, and gradual cooling. The kilns are
normally gas-fired operating with oxidizing atmospheres and maximum temperatures of about
1200°C (2192°F) and the total time from start to finish is in the range of 48 hours. The kilns are
fully instrumented and have automatic controls monitoring temperature, flame adjustment, and
controlling the speed at which the kiln cars are conveyed through the kiln. On emerging from the
tunnel kiln, the fired ware is allowed to cool to a temperature where they can be safely handled
and the cones are inspected for proper soak.
Porosity Test: A few fired shells are removed particularly from regions where the cones show a
total heat input or soak that may be on the low side, which is usually from the center of the
stacks, where shells are shielded from direct heat input. These shells are broken and the pieces
subjected to a test for porosity, normally in accordance to Section 5.4 of ANSI C29.1. The test
bars are subjected to a four-point bending test for mechanical strength and microscopically
viewed for proper structure of the fired porcelain.
Electrical Test: The fired shells are removed from the kiln cars, visually inspected, and placed
one-by-one on vertically orientated steel pipe electrodes that are on a conveyer. The shells are
conveyed to the high voltage test area where each shell is subjected to a damped high frequency
voltage test, having a frequency between 100 and 200 kHz, and at a voltage high enough for
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flashover. Each shell is subjected to intense arcing for 3 to 5 seconds. The use of high frequency
has been standardized, as high frequency voltage is more effective in culling out shells with
cracks and penetration of high frequency current in the cracks, creating heat, often causes the
shells to explode. Punctured shells are removed from the conveyor and the rest are conveyed to
the assembly area.
Hydraulic test: Some manufacturers perform a hydraulic test on the shells prior to assembly.
By culling out shells that fail at the low end of the normal distribution of strength, the failure
distribution of assembled units is shifted higher, thereby improving the overall reliability of the
insulators.
Assembly of the Insulator
Preparation of the Metal End-Fittings:
In a separate area, the galvanization of the hardware, is inspected for uniformity and tested for
proper thickness. After inspection, the inner part of the cap, and the portion of the pin that is in
contact with the cement, are coated with the bituminous paint. The pins are normally dipped, and
the caps are sprayed or hand painted. This paint is usually prepared from cold tar, or bitumen,
which is dissolved in a solvent, such as VM&P naphtha, and the coating is applied to protect the
galvanized hardware from corrosion from the alkalis in the cement. A secondary function of the
coating is to aid in uniformly distributing mechanical load to the shell, thereby ensuring high
mechanical strength, particularly in the long term as drying of the layer is known to affect aging.
Manufacturers consider the type of bitumen and the thickness of the application a trade secret.
Assembly:
In the assembly of the cap to the shell, a spacing gauge is first placed onto the head of the shell.
This spacer will control how far the porcelain shell is inserted into the metal cap and helps keep
the shell centered in the cap. An example is illustrated in Figure 2-32. A controlled quantity of
cement is dispensed into the cap and the shell is then inserted into the cap, displacing the cement.
The shell is pushed into the cap until the spacer and the metal cap meet.
Similarly, a controlled quantity of cement is dispensed into the pin-cavity of the insulator and the
pin is inserted. Again, a spacer is used, as illustrated in Figure 2-32, to ensure the proper depth of
insertion and alignment with respect to the shell. Some designs use a cork or felt spacer between
the top of the pin and the porcelain. The cork or felt provides proper spacing and shock
absorption. The insulator is then vibrated so that the cement compacts and excess air escapes.
The spacers are then removed, and the insulators are conveyed for curing of the cement.
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Figure 2-32
Illustration of Spacers used in assembly
Cement Curing:
Curing is done either in a steam room or by submersing the insulators under water. In a large
operation, the insulators are slowly conveyed though a vat filled with water, which is often
situated under the floor. The curing time depends on the type of cement that is used: for Portland
cement a minimum of about 48 hours is typically required, and for aluminous cements a
considerably shorter curing is needed.
Routine Tests:
Routine tests are tests that are done on each unit produced. The electrical routine test is a
mandatory test in all standards, but it done on the shells before assembly, sometimes in
combination with a hydraulic test to cull defective shells before assembly (see section on firing).
After assembly, a visual inspection, and a mechanical proof test is performed as described in
applicable standards.
Visual Inspection: As a final inspection, each unit is visually examined for defects prior to proof
testing, which is the final stage before crating and shipment. This is necessary as most
manufacturing facilities are not completely automated and considerable handling of the shells
and units takes place, with possible damage to the glaze due to impact. In addition, the
cementing operation needs to be checked.
Proof Test: The mechanical proof test is the most important test on a unit before crating; this is
the strength that is guaranteed by the manufacturer at the time of shipment. This test is
performed on each unit produced. For this test, strings are sometimes assembled to the length to
be crated, which is usually 6 or 7 units, the cotter keys inserted, and the string is mechanically
loaded in tension to 50 % of the rated strength and in accordance to the applicable standard. The
load is then removed, and the units are stamped as “proof tested” and then crated. A better way
of proof testing is to apply the load to individual units, which checks the extension of each
individual unit rather than a string of units, should movement occur during loading.
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Manufacturing Toughened Glass Suspension Insulators
Similar to porcelain insulators, the process to manufacture glass suspension insulators comprises
six stages:
1.
2.
3.
4.
5.
6.
The mixing of the raw materials
Production of the glass
Molding
Toughening
The assembly stage where the hardware is cemented to the shell
Routine testing and the insulators are crated for shipment
Mixing of the Raw Materials
The glass utilized for suspension insulators must have a very high dielectric and mechanical
strength. This can only be achieved with a very high quality of glass made from the highest
quality of raw materials which include [1]:
•
•
•
•
•
•
Silica sand
Limestone
Dolomite
Feldspar
Salt cake (sodium sulphate)
Anthracite (for coloring)
Regular batch sampling and chemical analyses ensures the quality of the raw materials. In this
respect it is important to ensure the raw materials are free of impurities which could form as
inclusions (i.e., foreign particles suspended in the glass). Inclusions negatively affect both the
electrical and mechanical strength of the glass.
For DC insulators a completely different composition is required due to the entirely different
electrical stresses. Due to the unipolar nature of the voltage stress on the insulator a glass with a
very high resistivity is used to prevent electrolysis of the ions contained in the glass.
Glass insulators are manufactured in different colors or hues of glass, some examples are shown
in Figure 2-33. Colors can range from white to green and in some cases originate from the same
manufacturer. The color of glass insulators is due to the type of oxides used during manufacture
and nothing to do with its mechanical or electrical characteristics. Therefore, the color has no
significance or impact on operational performance or longevity.
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Figure 2-33
Examples of different Color Glass
Production of the Glass
The manufacturing process of the glass dielectric shell is illustrated in Figure 2-34 [41].
Melted Glass
>2500oF
(>1300oC)
Cooling inside
the feeder
~2000oF
(~1100oC)
Controlled Air Blast
Cooling
1000oF (530oC)
Furnace
Pressed into shape
Filling the cast
iron mold
Figure 2-34
Glass Shell Manufacturing Process Including “Toughening”
The raw materials are mixed and introduced into the “melting end” of the furnace which is in the
form of a long flat tank (about 1 m deep) filled with already molten glass. The temperature in
this part of the oven is approximately 1500°C (2700°F), which is high enough that the viscosity
of the glass low enough to allow for flow which allows impurities and bubbles to float to the
surface. The infeed of raw material sets up a natural flow of the glass from the melting end to the
conditioning side of the furnace where it exits the furnace and is delivered to a feeder, or
dispensing unit.
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The furnace technology must be of the highest standard to ensure a good quality of glass. Typical
characteristics of a good furnace would include:
•
•
•
•
Good refractory material
Good temperature control
Control on batch materials and mix ratio
Good conditioning zone
Molding of the Glass Shell
In the feeder, or dispensing unit, the glass is cooled to a temperature of approximately 1100°C
(2000°F) until it becomes workable. The insulator glass shell is formed by pressing a measured
quantity of molten glass into a steel or cast-iron mold and allowed to solidify sufficiently to
permit removal from the mold without deformation.
For traceability, each mold and plunger should have a reference number, which should be clearly
seen on every glass disk. The mold is normally given a number that would appear on the skirt.
The plunger will usually have a number appearing on the glass between the outer edge and the
first rib. Besides providing information on the molds, useful information on the production run
sequence in the year is also provided. Examples are shown in Figure 1-82.
Figure 2-35
Examples of Plunger and Mold References on the Glass Shell
Molds and plungers are normally lubricated with a mold release agent with a mold release agent
that is inclined to build up a layer of slag after time (typically a few weeks), and because of this
the equipment must be removed and cleaned at regular intervals. Failure to clean the equipment
could result in the slag build-up flaking off, which will leave undesired patterns on the glass
disks that could negatively affect the self-cleaning properties of the insulator in service.
The molding equipment requires regular examination to prevent thermal cracks on the glass
shell, especially around the neck-end of the mold. Should these cracks extent to beyond the
radius, which is covered by the insulator cap, they become referred to as “trees” which would
also increase the possibilities of contamination build-up. In high quality manufacturing, shells
with such treeing are rejected during visual examination of the shells after molding. An example
of “treeing” is shown in Figure 2-36.
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Figure 2-36
Examples of “Trees” Caused by Thermal Cracks in the Molding Equipment
During molding and as part of the design, load surfaces, or corrugations, are formed on the glass
head and in the pin cavity. Changes to the load surface can occur if the plunger is removed too
quickly and:
•
•
•
The cavity collapses before it can be cooled
The plunger grooves have not been machined to drawing and were not picked up during
acceptance inspection before going onto the production line
The plunger peg is damaged in service or removed during a manufacturing type change
The Toughening Process
Once the glass shell is removed from the mold, there are very large differentiations of
temperature throughout the glass shell. It is, therefore, transferred to a kiln for the equalization
process to ensure that the glass shell is at a uniform temperature of about 720–740°C, which is
just below the plastic phase. Directly after the equalization process the glass disc is transferred to
the toughening process. During this time the glass shell is twirled around while subjected to
controlled jets of cold air. This leads to the rapid cooling of the outer glass layer while the
internal temperature remains relatively high. When cooling down the outer surface contracts and
solidifies placing the internal part under compression. Further cooling of the interior allows it to
contract to form a high-density glass which is under a tension stress. This stress pattern is
essential to achieve the desired mechanical and dielectric strengths.
Toughening Tests:
“Toughening Tests” should be carried out periodically during this part of the process on random
samples. Manufacturers use different methods to check the toughening. One common method to
test the toughening is by fitting a shell with bigger fittings and breaking the glass by pulling on
reinforced fittings. This provides the ultimate mechanical strength of the glass, and indirectly an
indication of the toughening, for a given type of insulator.
Another well-proven method is to cover the top surface of the shell and head with gum paper.
The shell is then fractured by punching the top of the head with a sharp pointed rod, taking care
to cover the insulator before fracturing to prevent injury due glass fragments.
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Uneven toughening
(Variation of small and
large fracture cubes)
Figure 2-37
Example of Poor Toughening (Inconsistent sizes of Cubes)
The toughening pattern is examined as shown in Figure 2-37; this should provide very consistent
small fracture cubes:
•
•
The skirt should break in fragments of a consistent size in a 360-degree distribution.
Particular attention should be given to the entire head area, as this is where the concentrated
dielectric stress will occur. The head, which is also the mechanically stressed region, requires
a strong toughening and the fragments in this area should therefore be smaller.
Poor toughening can be caused by the following:
•
•
•
•
Poor temperature distribution of the shell prior to toughening.
Inadequate air pressure during toughening.
Air pressure pipe vents incorrectly sized or blocked.
The delayed transfer of the insulator from the equalizing stage to the toughening process
(interruption of process).
It is quite normal to experience bursting of some insulators during the toughening process. This
is purely automatic rejection of any glass shell, which may have some fault or impurity within
the tension zone. On very rare occasions during toughening or when carrying out the toughening
test, the glass head will shatter leaving the shed intact or vice versa. This is referred to as an
“Anomalous Fracture” and is known to occur in-service. Possible causes are:
•
•
Tolerances in the mold neck as well as the plunger area.
Improper airflow from the cooling nozzles (called toughening air pipe holes).
The reason for this can be related to either the combination of mold and plunger and/or
toughening. This highlights the importance of mold and plunger reference numbers.
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Glass Shell Inspection:
It is imperative that every glass disk is visually examined for any faults following toughening.
The following are unacceptable defects:
•
•
•
•
•
•
•
Any small bubble in the glass head or neck area – Figure 2-38 (a).
Any small tree in the glass disk – Figure 2-38 (a).
Any grizzle in the glass disk; grizzle is a cluster of very small cracks in line or shaped similar
to a honeycomb, normally found in the head or neck area – Figure 2-38 (b).
Any fin on the edges of the glass disk; A fin is created by a bad interface between mold and
plunger or at the “mold split,” to open and remove the shell. Molten glass pushes its way into
these crevices to cause fin – Figure 2-38 (c).
Any irregularities which appear on the top of the glass shed, e.g., flow-lines roughness or
impressions due to flaking of old mold lubricants – Figure 2-38 (d).
Any fine cracks at the plunger vent holes. This will appear on the glass rib and is due to dirt
or poor lubrication or handling damages. The vent holes on the glass can be felt and seen
evenly spaced along the top of the insulator ribs.
No flakes on the glass area.
Manufacturers should record every hour’s production enabling the operators to be aware of the
types and the extent of faults occurring.
Any visible inclusion, bubbles or un-melted refractory material, is referred to as a “seed”. For a
quick check on the ability to be able to toughen the glass, manufacturers perform a “seed count”.
This is done by inspecting production line glass. The “bubble content” is typically defined by an
index:
𝑸𝑸 = 𝒏𝒏 × 𝑲𝑲
Eq. 2-5
Where:
n = number of bubbles visible by the naked eye under good light. The size of the seed does
not matter as long as it is visible.
𝐾𝐾 = 100 ∙ 𝑆𝑆 ∙ 𝐷𝐷 ∙ 𝑅𝑅
S = square area under observation and should be 1cm2, 4cm2 or 16cm2 (0.16 in2, 0.62 in2, or
2.48 in2) S is in cm2
D = thickness of glass being considered. This is usually taken where the glass thickness
remains constant (section of the skirt). D is in cm.
R = Density of glass. R is in g/cm3
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Air bubble
Treeing
a)
Examples of a Bubble and Treeing
b)
Example of “Grizzle”
c)
Example of a Fin Caused by Poor Interface
between Mold and Plunger
d)
Example of Surface Roughness Caused by Dirty
Mold
Figure 2-38
Examples of defects that can be identified by visual inspection
The criterion commonly used is Q < 200 and corresponds to a calculation performed on 100 g of
glass. This is why the number 100 appears in the equation. The higher the seed count, the higher
the probability of glass bursting during the toughening process or later.
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Thermal Tests
All insulators are subjected to “Thermal Shock” tests. These tests are necessary to verify two
aspects of the glass shells:
•
•
Up-Shock test: The insulators move through a controlled temperature oven on a conveyor
belt. During this time the insulator is heated rapidly (i.e., a steep temperature rise) from about
room temperature (when it enters the oven) to a temperature which is above approximately
450°C. This up-shock test is intended to weed out insulators that contain inclusions in high
mechanical stress areas.
This is followed by the down-shock during which the insulator is initially cooled down to a
temperature of approximately 120°C and maintained for a short while on the conveyor. When
the disc leaves the oven, it is dropped into cold water, which has a temperature difference of
least 100°C to the latter part of the oven. The down-shock is intended to weed out insulators
with faulty toughening which may exist. In some cases, it may be necessary to have a
refrigeration system installed to maintain a constant temperature of the water trough.
One useful check of how well the manufacturer controls the quality of the glass pressing and
toughening process is to note how many insulators shatter during the toughening process and
thermal cycle test (a typical failure rate is about 1-2%). Discs that fail at this time are ones that
contain either seeds or inclusions in areas with high mechanical stress levels. The fact that there
are a few failures serves as a rough indication that the toughening process is done properly. On
the other hand, if the number of failures is too high (i.e., in the order of more than 5%) it could
serve as indication that the quality of the glass is low (i.e., contain inclusions or too many seeds).
The spontaneous shattering of a glass disc normally results from some form of inclusion, which
results into a facture pattern identified as “platform or fracture mirrors”. It is possible to search
the glass fragments (if all are available) for the location of the shattering inception point which
can be identified as a platform with radial fracture lines around it. With the use of a microscope,
it will show a very small and perfectly round platform or ring; lodged in the center of the
platform will be the cause of the bursting (Figure 2-39). This could be one of many reasons,
more common are un-melted silica or material from the furnace walls. It is important for
manufacturers to collect and record as many of these platforms on a daily basis for quality
control purposes, as the causes may originate from the raw materials or the incorrect mix of such.
The thermal shock tests are in some cases not able to purge all weak insulators which could
result in a high initial shattering rate of the insulators. As a remedy, some suppliers, specifically
those struggling with glass quality, are known to leave the glass shells in a store yard for several
months before assembly in order to provide time for this so-called “self-purging”. It is important
to note that in state-of-the-art manufacturing, such elimination of potentially defective glass
shells is performed through deterministic tests on the production line, rather than going through a
wishful natural selection and elimination in the yard.
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Figure 2-39
Example of a Platform Fracture Pattern Caused by an Inclusion
Assembly of the Insulator
Visual Inspection of Glass Shells:
Prior to the insulator shells going into stock and awaiting assembly they are usually inspected
visually, and every batch be recorded and marked. Record keeping is important for both final
assembly and for traceability when installed in-service.
Inspection of Incoming Fittings and Cement:
On receipt of consignments of the insulator caps, pins, thru-pins and washers, manufacturers
should carry out sampling tests in accordance with factory control methods or appropriate
standards.
Galvanizing tests should be done to determine the thickness and uniformity of the coating. Caps
should be inspected to identify any possible cold cracks. Some manufacturers use either ring
testing (striking the bell cap) or eddy current inspection techniques to detect cold cracks. Visual
examinations to gauge and test for cold cracks are normally carried out on the complete
consignment.
Tensile tests should also be done on new deliveries of caps and pins. All caps and pins should be
appropriately marked to identify the manufacturer; reference codes to minimum failing
load/M&E rating, heat numbers etc. to allow for traceability.
Tests to verify the cap or pin material should also be carried out at regular intervals to assure that
the correct grade of metals is being supplied and locking devices should be checked against the
respective specifications and ejection test done on the cotter key/locking device as described in
IEC 60372.
Cement tests are typically carried out at random on all consignments received. Samples are
mixed and prepared similar to the assembly requirements; cured and tested for mechanical
strength. Doubtful results should be re-sampled, and any further failures would require more
investigation or complete rejection.
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Galvanized fittings are typically stored indoors to prevent “white rust” forming.
Insulator Assembly:
Following the manufacture, the insulators are assembled by cementing the cap and pin to the
glass shell, but assembly methods vary depending on the manufacturer. Typically, a measured
amount of cement is dispensed in the cap and the glass disc cavity. The insulator is then
assembled under high frequency vibrations to ensure that the cap and pin is seated properly and
that there are no cavities in the cement. Typically, manufacturers only use Alumina cement.
Some specific points of the insulator assembly are:
•
•
•
•
•
•
It is important to axially align the cap and pin precisely to obtain the highest mechanical
strength. For this purpose, the insulator pin is supported by a ring which rests on the inner
glass under-rib to ensure that the alignment is maintained while the cement cures.
The glass disc should not be in direct contact with the metal end fittings. Such a contact
could result in a stress concentration and reduced mechanical strength. Some manufacturers
utilize a rubber gasket between the glass disc and the cap while others uses a nylon flocking
material (see Figure 2-23), which also prevents RI and corona issues.
Some manufacturers include a paper or cork shock absorbing cushion avoid direct glass-tometal contact. The bitumen covering on the pin (See Figure 2-24) may also double as a shock
absorbing cushion on the cone of the pin, in which case the shock absorbing cushion is no
longer needed.
The load bearing surfaces of the glass and cap should be parallel.
The dispensing the correct amount of the cement to the pin cavity is more important than
having the correct amount in the cap. Excess cement in the cap will overflow, and can be
wiped away when the glass head is pressed down into the cap—this may also serve as
indication that there is enough cement in the cap to fill it completely. Excess cement in the
pin cavity cannot easily be removed and a too high cement level may increase level of RIV.
The mechanical strength of the insulator is negatively affected if too little cement is
dispensed and the RIV level will also be negatively affected.
Some manufacturers also apply a bitumen coating to the cement surface or around the
exposed pin to protect the cement from environmental affect and probably to hide a multitude
of faults, such as bubbles or cracks. An example is shown in Figure 2-40. It should however
be noted that this coating is not particularly strong mechanically and it will deteriorate as the
insulator ages, which may result in higher RIV levels on old insulator units.
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Figure 2-40
An example of an insulator with a bitumen coating of the cement.
The quality of the cement and the pin cavity design of the insulator may influence the RIV
performance of the insulator. The pertains to the shape as well as distances “s” and “d”, as shown
in Figure 2-41.
Pin cavity
Pin
s
d
Glass shell
Cap
Bitumen
coating on pin
Cement
Figure 2-41
The pin cavity design of the insulator influences RIV. The shape, depth (d) and cavity width (s) are
important parameters.
Cement curing is normally carried out under wet conditions over a time depending on the cement
and the strength required and the temperature of the curing.
Routine Tests:
Insulators are then submitted for routine mechanical testing. This is done on every insulator and
the mechanical strength applied is in accordance with the specified specification. The load (50%
ultimate mechanical strength) is held for a specified time (typically 3 seconds), released and each
insulator then fitted with the required locking device. Tests are typically done directly after
assembly when using a hot cement curing process. For assembly processes that cannot reach
high strengths rapidly this test would be done later.
Before the insulators are crated, they should pass through a final visual inspection to eliminate
any flakes, chips or assembly faults.
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At some point during the assembly, the insulators should each be marked recording the following
information for traceability: The ideal way to mark every insulator after assembly for traceability
is typically a bar-coded reference that should give all the necessary details, including:
•
•
•
Date of assembly
Minimum failing load/M&E strength
Manufacturer’s name or symbol/trademark
Caps should have the markings according to relevant standard, including strength class,
production date, and identification of the factory where the unit was assembled. Example of end
cap markings are provided in Figure 2-42.
Figure 2-42
Examples of the markings on an end cap of a toughened glass insulator
Polymer Insulators
Overview and Terminology
A polymer insulator is also identified as a composite insulator in the standards. It is defined as an
insulator whose insulating body consists of two or more organic based materials. It has a load
bearing solid or tubular—in the case of equipment insulators—insulating core, which is covered
by a polymeric housing. Metal end fittings are attached to the core.
A schematic drawing of a composite suspension insulator is presented in Figure 2-43 and that of
a composite line post insulator in Figure 2-44. These figures identify the different constituent
components. Unfortunately, the standards do not always use the same terminology and this
differs also to some extent to that generally used in the industry. Table 2-3 presents a summary
of the terminology used in the standards, (i.e., ANSI, IEC and CSA) and those used by the
industry. For this report terms and definitions have been selected to correspond as far as possible
to that used in the standards, but in some cases different terms have been preferred for the sake
of being more descriptive.
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Grounded end
Shed
Energized end
Sheath
Connection
point
End fitting
End fitting seal
Core
Grading rings
Housing
Figure 2-43
The basic components of a composite suspension insulator.
Energized end
End fitting
Connection
point
Grounded end
Shed
Core
Sheath
Housing
End fitting seal
Figure 2-44
The basic components of a composite line post insulator.
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Table 2-3
Insulator terminology used in standards and the industry
This report
Composite
Insulator
ANSI
Composite
Insulator
Connection
between end fitting
and rod
CSA
IEC
Composite
Insulator
Composite
Insulator
Non-ceramic
insulator, NCI,
Polymer
Insulator,
Synthetic
Insulator
Connection Zone
Connection
Zone
Crimp,
swage
Connection to
Attached Fittings
Coupling Zone
Coupling
Coupling
Core
Core
Core
Core
End Fitting
End Fitting
Metal Fitting/
End Fitting
Metal Fitting
End Fitting seal
Interface
Interface
Interface
Energized end
Grading ring
Industry Terms
FRP (fiber
reinforced
plastic) Rod,
GRP (glass
reinforced
pultruded) Rod,
fiberglass rod
"Triple Point"
Live End, High
Voltage End
Corona Ring
Grading Ring
Grading Ring
Grounded End
Earthed End,
Tower End
Housing
Housing
Housing
Housing
Weathershed
System
Sheath
Sheath
Sheath
Sheath
Shank, "Core"
Shed
Weathersheds
Shed
Shed
Interfaces
"Interfaces:
1: Fibers to resin;
2: Filler particles
to polymer;
3: Core to
housing,
4: Weathershed
to weathershed
5: Weathershed
to sheath;
6: Housing to end
fittings
7: Core to end
fittings"
"Interfaces:
1: Fibers to resin;
2: Filler particles
to polymer;
3: Core to
housing,
4: Parts of
housing
(between sheds
or sheath to
sheds);
5: Housing to core
to metal fitting"
"Interfaces:
1: Fibers to
resin;
2: Core to
housing,
3: Parts of
housing
(between
sheds or
sheath to
sheds);
4: Housing to
core to metal
fitting"
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The definitions presented here are adopted from those in the standards:
•
•
•
•
•
•
The core of a composite insulator is the internal insulating load bearing part. It is designed so
that the insulator conforms to the mechanical characteristics required of it. The core of a
composite insulator is usually a Resin Bonded Glass Fiber (RBGF 1) rod that comprises
axially aligned glass fibers positioned in a resin-based matrix.
The housing is the external insulating part of the composite insulator that provides the
necessary creepage distance and protects the core from the environment. The housing may be
equipped with a number of sheds, with or without an intermediate sheath.
- The sheds (or weathersheds) is that part of housing material that projects from the
insulator body. Its function is to increase the creepage distance of the insulator and to
break the flow of water under rain conditions. Sheds may be formed with or without
under-ribs.
- The sheath is that part of the housing located between sheds. The IEC uses in their latest
documents also the terms “trunk” or “shank”.
The metal end fitting is the part of an insulator that is intended to attach it to a supporting
structure, or to a conductor. Its function is to transmit the mechanical load from the
connection points, where the line hardware is attached, to the insulator core.
There exist a number of interfaces in any composite insulator design. These are defined as
any of the contact points between the component materials of the insulator. The most
important interfaces in a composite insulator are those between:
- Glass fibers and the impregnating resin of the core.
- The core and end fittings
- The core and housing
- The housing and end fittings (it is also known as the end fitting seal);
- The various parts of the housing, e.g., between sheds, or between sheath and sheds;
- In the filler particles to the polymer in the housing material.
On transmission voltage levels, composite insulators may be fitted with one or more grading
(or corona) rings. These are used to grade the E-field (i.e., Electric field) along the insulator
length to avoid corona discharges and aging that may result from it.
In certain cases, the use of arcing horns on composite insulators are warranted. Its function
is to divert electrical power arcs away from the insulator to prevent arc damage to the
housing and end fittings. Arcing horns may be incorporated into the grading ring design.
1 The term “fiber reinforced plastic” (FRP) is also frequently used, but in the material science circles this is usually associated
with plastics reinforced with short glass strands. This report adopts the use of RBGF.
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Core Rod
The core, or the internal insulating part, (see Figure 2-45) of a composite insulator comprises a
Resin Bonded Glass Fiber (RBGF) rod. It is also frequently referred to as a “fiber reinforced
plastic” (FRP) rod, but in the material science this is usually associated with plastics reinforced
with short glass strands. In this report the term RBGF will be used.
The core forms the heart of the insulator, it carries not only the mechanical load of the insulator,
but it also needs to withstand the full voltage that is applied across the insulator. In terms of its
long-term performance, the core should be chemically stable so that its electrical and mechanical
properties do not change over time.
Core
Figure 2-45
A cut-away drawing of a composite insulator showing its core.
Electrically, the rod is a good insulator as long as it is dry and uncontaminated. Internal
discharge activity may also be initiated by moisture and/or contaminants that have penetrated the
housing or large defects such as voids and cracks within the core itself.
Longrod or suspension insulators: On suspension composite insulators for overhead lines the
core is designed to carry mainly tension loads thus its capability to carry compression, torsion, or
bending (cantilever) loads is limited. This has led in the past to a number of failures due to bad
installation or handling practices.
Line post insulators: The cores of line post insulators are much thicker than their longrod
counterparts in order to withstand the complex mechanical loading that it is subjected to. These
insulators have therefore a much better capability to carry compression and cantilever loads.
The core consists of axially aligned glass-fibers that are imbedded by a pultrusion, or direct pull,
process into a resin matrix. It is important that the fibers are distributed evenly through the core
and that they are not twisted in any way to achieve maximum mechanical strength.
The glass fibers are typically 5 to 25 μm in diameter and make up 75–80% of the total weight of
the rod [42]. There are two types of glass fibers in general use, historically E-type fibers were
most often used, but in later years more manufacturers offer corrosion-resistant fibers.
“Corrosion resistant” refers to the ability of the glass fibers to resist stress corrosion cracking
(brittle fracture), which is discussed in Chapter 3 [43]. This acid resistance is obtained by
reducing the boron content in the fibers. A hydrolysis-resistant resin—epoxy, vinyl-ester, or
polyester based—is used as the resin matrix. Figure 2-46 is a scanning electron microscope
(SEM) image of a core cross section, showing the fibers and resin. Some manufacturers produce
a translucent rod, which they claim, provides for easier inspection and quality control during the
manufacturing process.
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Fibers
Resin
Figure 2-46
SEM image showing the resin fiber matrix.
Composite insulators derive their mechanical strength from the core; there is thus a direct
relationship between the strength of the rod and its diameter. This relationship, based on
catalogue data, is shown in Figure 2-47.
Specified Mechanical Load (kip)
100
80
60
40
20
0
0
5
10
15
20
25
30
35
40
Rod diameter (mm)
Figure 2-47
The relationship between core diameter and the specified Mechanical Strength for composite
longrod insulators (data taken from insulator catalogs).
A similar relationship holds for line post insulators, but in this case the diameter of the insulator
is related to the maximum permissible bending stress in the core. This, in turn is a function of the
maximum design cantilever load and the insulator length. The relationship between core
diameter, insulator length and Maximum Design Cantilever Load (MDCL) is illustrated in
Figure 2-48 for one make of composite line post.
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Maximum Design Cantilever load (lbs)
6000
5000
88 mm
4000
Rod diameter
3000
76 mm
63 mm
2000
44 mm
1000
0
0
500
1000
1500
2000
2500
3000
3500
Length of insulator (mm)
Figure 2-48
The relationship between insulator length, core diameter and the Maximum design Cantilever load
for NGK composite line post insulators. (Data taken from the NGK insulator catalog.)
Metallic Fittings
The metal end fittings provide the mechanism by which the fiberglass rod is attached to the
structure and conductor hardware (see Figure 2-49). Its main purpose is to transfer the
mechanical forces from the insulator rod to the attached hardware of the tower, or conductor
structures. Additionally, the end fitting design should incorporate features to grade the electrical
field around it to protect vulnerable parts such as the end fitting seal and the polymer housing.
Depending on the presence of grading rings or arcing devices, it may also be necessary to design
the end fitting to carry fault current in the event of a flashover across the insulator.
End fitting
End fitting
Figure 2-49
A cut-away drawing of a composite insulator showing its end fittings.
End fittings for composite insulators that are used on the transmission network are made of hotdipped, galvanized, forged steel or ductile iron. The use of aluminum for this purpose is limited
to insulators for distribution systems since the melting point of aluminum is lower than the arc
root temperature of a power arc [42]. A range of connection methods are available that can be
fitted to longrod insulators. Some of the most often used include socket, ball, oval eye, and Y
clevis. Examples are shown in Figure 2-50.
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a)
Oval - Eye
b)
Y- Clevis
c)
Ball
Figure 2-50
Examples of different end fitting types.
Various methods of fixing the end fitting to the core have been used in the past as is shown in
Figure 2-51. These are:
•
•
•
Crimped, or swaged, end fitting
Epoxy wedge end fitting
Metal wedge end fitting
Today most manufacturers affix the end fitting onto the rod by a compression process or by
heating the end fitting and utilizing a shrink fit. This is because the stress concentrations inherent
in the other designs can be avoided by grading the compressive forces during fitting attachment.
However, care needs to be taken to avoid over-compressing during manufacture, resulting in
stress concentrations and possibly rod fracture. Care also needs to be taken to avoid undercompression, resulting in a mechanically weak insulator that may fail due to pull out [44]. Most
manufacturers use a carefully controlled or calibrated process to avoid the above-mentioned
problems. Some of the techniques used to improve the end fitting core interface are:
•
•
•
Reduction of the stress in the core by a graded crimping process.
The use of acoustic techniques to determine when the optimal crimping pressure is reached.
Using a calibrated crimping press that will only release when the optimal crimping pressure
is reached.
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a)
Crimped (swaged) end fitting
b)
Metal wedge end fitting
c)
Epoxy wedge end fitting
Figure 2-51
Dissection of different end fittings/rod attachment methods (note: most insulators in service are
of crimped, or swaged, end fitting design) [48].
Polymer Housing
The function of the polymer housing (see Figure 2-52) is to hermetically seal the rod from the
environment, and to provide sufficient creepage distance to withstand both environmental and
electrical stresses to which the insulator may be subjected. The housing typically comprises
sheds and sheath (shank) sections. In the North America the term “weathershed system” is also
used to refer to the housing.
For transmission-line composite insulators, the housing may be based on either an ethylene
propylene rubber (EPR) or a silicone rubber (SIR). Although the use of such a broad
classification is generally used, the composition of these materials may vary considerably from
one manufacturer to another. Some manufacturers even provide combinations of materials which
is known as an “alloy”. Furthermore, the manufacturing process utilized affects the long-term
performance of the rubber material. Therefore, one must be careful in making assumptions about
the performance of a particular type of housing material based solely on the family of rubbers
from which it comes.
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Weathershed system
Shed
Sheath
Housing
Figure 2-52
A cut-away drawing of a composite insulator showing the housing.
Ethylene Propylene Rubber:
There are several types of EP rubbers. The first generation of composite insulator rubbers
utilized ethylene and propylene monomers (EPM). Today most EP rubber insulators are made
from three monomers: ethylene, propylene, and diene (EPDM). Some manufacturers also add
small amounts of silicone polymer and indicate this by naming the material an “alloy” [37].
Various additives are added to the polymer compositions to improve performance and satisfy
manufacturing processes. For example:
•
•
•
•
Inorganic powders such as Aluminumtrihydrate (ATH) are added to improve resistance to
discharges, arcing, and tracking.
UV stabilizing agents such as zinc oxide or titanium oxide are used.
Cross-linking agents, such as dicumyl peroxide, may be used for vulcanizing.
Chemicals are also added to obtain the required color.
The chemical structure of EP rubbers consists of a backbone of organic carbon molecules, and
the side chain consists of hydrocarbon elements, as shown in Figure 2-53. The carbon content in
EPDM is considerably higher than in silicone-based rubbers, and therefore, it is critical that it is
prevented from degrading, as the by-products are more likely to be carbon. Carbon can form a
conductive path or track. To increase the tracking resistance, EPDM rubbers have large
quantities of inorganic fillers—e.g., ATH [37]. One of the methods by which ATH increases
tracking resistance is by forming moisture, which, in turn, cools the discharge activity [45].
CH3
(CH2 - CH2)
(CH - CH2)
(CH - CH2)
CH2
CH = CH - CH3
Figure 2-53
Chemical building block of an EPDM rubber.
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EP-based rubbers have been shown to have good resistance to degradation due to surface
discharges and have performed well in many applications. Furthermore, EPDM usually have a
higher tear resistance than silicone rubbers [37]. On the other hand, EPR surfaces wet out more
easily, which permits a greater level of leakage current activity and a reduced flashover
performance under contaminated conditions. Even so, leakage current and the associated
discharge activity generally do not degrade EPR materials as significantly as silicone-based
units. This is only a consideration when units are installed in environments where contamination
is a concern. It should further be mentioned that EPR-based materials often show hydrophobic
properties initially, but this may deteriorate significantly with exposure to the environment.
Silicone Rubber (SIR):
Three broad categories of silicone rubber that are used for insulation:
•
•
•
High Temperature Vulcanizing (HTV), also known as High Temperature Cured Rubber
(HCR)
Room temperature cured vulcanizing (RTV)
Liquid silicone rubber (LSR), also referred to as Liquid Injection Molding (LIM)
Most transmission-line applications today utilize HTV or LSR rubbers.
The chemical building block for silicone rubber is shown in Figure 2-54. It consists of an
inorganic silicon-oxygen (Si-O) backbone and two organic side chains attached to the silicon
atom. A methyl group (CH3) is most often utilized for high-voltage applications, but other
organic groups, such as phenyl or vinyl, may also be used.
CH3
CH3
O
Si
O
CH3
Si
O
CH3
Figure 2-54
Chemical building block of silicone rubber [37]
Aluminumtrihydrate (ATH) or silica is added to improve resistance to discharges, arcing, and
tracking. The proportion of filler compounds to silicone rubber and the form in which they are
added is an ongoing area of research [45].
Silicone rubbers are characterized by having a low surface energy that results in highly
hydrophobic surfaces. This property is considered important because it prevents the insulator
surface from becoming completely wet, thereby suppressing leakage currents under
contaminated conditions. Consequently, silicone rubber insulators generally offer a high
contamination withstand and good aging properties, if they retain their hydrophobicity.
Additionally, silicone rubbers have a unique property whereby lightweight silicone molecules
migrate into the contamination layer, resulting in a transfer of hydrophobicity. There are,
however, conditions during which the silicone rubber may temporarily lose its hydrophobic
properties. If the insulator is subjected to significant levels of discharge activity during this time,
the result may be a significant degradation of the rubber material and in extreme cases the
exposure of the core rod [46] [47].
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Housing – Core Interface
The housing- core interface is shown in Figure 2-55.
Core – housing
interface
Figure 2-55
A cut-away drawing of a composite insulator showing the housing and weathershed system.
Some common methods for attaching the housing to the core are illustrated graphically and with
photos in Figure 2-56.
Briefly they can be described as follows:
•
•
•
•
Sliding individual or multiple shed/sheath units over the rod with an active silicone gel
interface between the rod and rubber – Figure 2-56 (a).
High temperature vulcanizing a tubular sheath of rubber to the rod to form the sheath.
Individual sheds are then vulcanized to the outside of the sheath – Figure 2-56 (b).
One-shot compression molding the rubber weathershed system onto the rod – Figure 2-56 (a).
One–shot, high–temperature, and pressure molding of the rubber weathershed system onto
the rod.
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Rod
Rubber
Silicone Gel
a)
Single or multiple shed units slipped over rod with a silicone gel interface
b)
Tubular sheath of rubber vulcanized to rod with individual sheds vulcanized to outside of rubber sheath.
Rubber Weathershed system
Rod
c)
One shot molding
Figure 2-56
Different methods of constructing composite insulators (note photographs of dissections of
actual insulators)
End Fitting Seal
One of the most vulnerable regions of a composite insulator is the interface between the end
fitting, polymer housing, and the core rod, known as the end fitting seal (see Figure 2-57). Its
function is to prevent moisture or contamination from penetrating to the RBGF rod, an event that
may precipitate a failure.
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End fitting seals
Figure 2-57
A cut-away drawing of a composite insulator showing its end fitting seals.
End fitting seals may be made in several ways, including [48]:
a)
b)
c)
d)
e)
Single or double O-rings – Figure 2-58 (a).
Direct bonding of the rubber weathershed system to the metal end fitting – Figure 2-58 (b).
A compression seal between the polymer housing and the metal end fitting – Figure 2-58 (c).
A metal connection piece between polymer housing and the metal end fitting – Figure 2-58 (d).
An external or internal sealant applied in the interfacial region. In some cases, a so-called
metastable sealant is utilized, which is one that does not fully cure and remains “tacky.” This
allows for different coefficients of expansion between the materials used in the sealing
interface – Figure 2-58 (e and f).
Some designs incorporate more than one of the above sealing methods.
11762887
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a)
O-Ring with sealant
b)
Direct molding
c)
Compression
d)
Labyrinth with active sealant
e)
Meta-stable sealant
f)
Compression with outer sealant
Figure 2-58
Examples of approaches to end fitting seals.
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E-Field Grading Devices
Research and service experience have shown that the E-field (E-field) within the rubber and rod
material, as well as in the air close to the surface of a composite insulator, needs to be controlled
because it affects both the long- and short-term performance [46] [47] [49] [50] [52] [53] [54]. It
needs to be controlled in the following regions [49] [55] [56] [57]:
•
•
•
Within the rubber and rod material
On the surface of the metal end fittings, hardware, and grading rings
On the surface of the polymer housing
Manufacturers use one or more of the following three methods may be used to achieve a proper
E-field grading:
•
•
•
The dimensioning and geometry design of the metal end fitting
Attached E-field grading devices (often made of aluminum)
Attachment of corona ring(s) at the high- and low-voltage ends (also called grading rings)
These methods are illustrated in Figure 2-59. Depending on the manufacturer and insulator
application, one or all the above may be utilized.
In their simplest form, corona rings are toroidal devices that are positioned along the insulator to
grade the E-field. In practice the rings are often half and open-ended rings to facilitate
installation and to save on materials used. Figure 2-60 shows some example ring configurations.
Corona rings are attached to the insulator end fittings using a variety of methods, depending on
the insulator manufacturer. Some manufacturers have attempted to design attachment methods
that prevent rings being incorrectly attached by field crews with varying success. Rings are not
interchangeable between manufacturers due to difference attachment methods and end fitting
designs.
11762887
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a)
Dimensions and geometry of end fitting used to
grade E-field. Note large and curved end fitting.
b)
E-field grading devices permanently attached to
end fitting. Note large dimensions and curved
edges. (Manufacturer-specific)
c)
E-field grading devices permanently embedded into
the housing. Note large dimensions and curved
edges. (Manufacturer-specific)
d)
E-field grading devices incorporated into end fitting
seal design. Note large dimensions and curved
edges. (Manufacturer-specific)
e)
Corona (grading) ring(s) attached at energized end and grounded ends of insulator. (Not all applications)
Figure 2-59
Examples of E-field grading devices.
11762887
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Figure 2-60
Examples of corona rings provided by different manufacturers for a range of applications. Both
split ring and horseshoe types are shown. Note the different attachment mechanisms.
References
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[3]
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[4]
Hall. J. 1993. “History and Bibliography of Polymeric Insulators for Outdoor
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[9]
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ANSI. 2013a. American National Standard for Composite Insulators—Transmission Line
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ANSI. 2013b. American National Standard for Composite Insulators—Transmission
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ANSI. 2018. American National Standard for Electrical Power Insulators—Test
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IEC. 2008b. “Insulators for overhead lines - Composite suspension and tension insulators
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[14]
IEC. 2012. “Polymeric insulators for indoor and outdoor use with a nominal voltage > 1
000 V – General definitions, test methods and acceptance criteria”. IEC International
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[15]
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greater than 1 000 V - Part 2: Dimensional and electrical characteristics.” IEC
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[17]
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[18]
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1: Ceramic or Glass Insulator Units for a.c. Systems - Definitions, Test Methods and
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"The Authoritative Dictionary of IEEE Standards Terms," Institute of Electrical and
Electronics Engineers, Inc., 3 Park Avenue, New York, NY, 10016-5997, USA, IEEE
100 - Seventh Edition, Dec.2000.
[20]
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[21]
IEC. 2008c. “Selection and Dimensioning of High-voltage Insulators for Polluted
Conditions - Part 1: Definitions, Information and General Principles.” IEC Technical
Specification 60815-1.
[22]
CIGRE 2015, Coatings for Protecting Overhead Power Network Equipment in Winter
Conditions, Technical Brochure 631, Study Committee B2, Working Group B2.44.
[23]
Kindersberger, J. and M. Kuhl. 1989. “Effect of Hydrophobicity on Insulator
Performance.” Paper No. 12.01. 6th International Symposium on High Voltage
Engineering. New Orleans, LA. August.
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[24]
Shaowu, W., L. Xidong, G. Zhicheng, and W. Xun. 2000a “Hydrophobicity Transfer
Properties of Silicone Rubber Contaminated by Different Kinds of Pollutants.” CEIDP.
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IEC. 2008d. “Selection and Dimensioning of High-voltage Insulators for Polluted
Conditions - Part 2: Ceramic and glass insulators for a.c. systems.” IEC Technical
Specification 60815-2.
[26]
IEC. 2008e. “Selection and Dimensioning of High-voltage Insulators for Polluted
Conditions - Part 3: Polymer insulators for a.c. systems” IEC Technical Specification
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[27]
IEEE. 1979. Working Group on Insulator Contamination, Lightning and Insulator
Subcommittee. “Application of Insulators in a Contaminated Environment.” IEEE
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Pp. 1676-1695.
[28]
IEC. 2016. “Guidance on the measurement of hydrophobicity of insulator surfaces.” IEC
International Standard 62073.
[29]
Pigini A. and A. Tomba. 1993. “Set Up of a Method to Evaluate the Surface
Hydrophobicity of Insulators.” Paper No. 41.03. Presented at the Eighth International
Symposium on High Voltage Engineering. Yokohama, Japan. August.
[30]
Wenzel R. N. 1963, “Resistance of solid surfaces to wetting by water”, Industrial and
engineering chemistry 28 (1936) 988.
[31]
Souheng, W. 1982. Polymer Interface and Adhesion. Marcel Dekker.
[32]
University of Oslo. 1998. Drop: A Program System for Interfacial Tension Measurements
by Image Analysis. University of Oslo. Oslo, Norway.
[33]
STRI. 1992. Hydrophobicity Classification Guide. STRI Guide 1. 92/1.
[34]
ANSI. 1988. "American National Standard for Electrical Power Insulators - Test
Methods," American National Standards Institute, 1430 Broadway, New York, NY
10018, C29.1-1988, Aug.1988.
[35]
IEC. 1995a. "Insulators for overhead lines with a nominal voltage above 1 000 V -,"
International Electrotechnical Commission, IEC 60305:1995, Dec.1995.
[36]
IEC. 1993. "Insulators for overhead lines with a nominal voltage above 1 000 V -,"
International Electrotechnical Commission, IEC 60383-1:1993, Apr.1993.
[37]
Gorur R., E. Cherney, and J. Burnham. 1999. Outdoor Insulators. Ravi S. Gorur Inc.
Phoenix, AZ.
[38]
Dumora D. Parraud R. “Reliability of toughened glass insulator on HVAC and HVDC
transmission lines: design improvements, field experience and maintenance” CBIP
International Conference Recent Trends in Maintenance Technologies of EHV
Transmission Lines, New Dehli, April 2002.
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[39]
Sediver: “Endurance … the unique ability of toughened glass insulators to indefinitely
withstand the effects of time and the elements”, Sediver publication.
[40]
IEC 1995b. "Insulators for overhead lines with a nominal voltage above 1000 V -,"
International Electrotechnical Commission, IEC 61325 ed1.0, Mar.1995.
[41]
EPRI 2008. Glass Suspension Insulators: Review of Current Technology. EPRI, Palo
Alto, CA: Dec. 2008. 1015923.
[42]
EPRI. 1998. Application Guide for Transmission Line NCI. EPRI, Palo Alto, CA: 1998.
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[43]
Armentrout, D. L., M. Kumosa, and T. S. McQuarrie. 2003. “Boron-free Fibers for
Prevention of Acid Induced Brittle Fracture of Composite Insulator GRP Rods.” IEEE
Transactions on Power Delivery. Volume 18. Issue 3. July. Pp. 684–693.
[44]
Mobasher, B., D. Kingsbury, J. Montesinos, and R. S. Gorur. 2003. “Mechanical Aspects
of Crimped Glass Reinforced Plastic (GRP) Rods.” IEEE Transactions on Power
Delivery. Volume 18. Issue 3. July. Pp. 852–858.
[45]
Meyer, L. H., E. A. Cherney, and S. H. Jayaram. 2004. “The Role of Inorganic Fillers in
Silicone Rubber for Outdoor Insulation—Aluminum Tri-hydrate or Silica.” IEEE Electric
Insulation Magazine. Volume 20. Number 4. July/August.
[46]
Phillips A. J., D. J. Childs, and H. M. Schneider. 1999a. “Ageing of Non-Ceramic
Insulators due to Corona from Water Drops.” IEEE Transactions on Power Delivery.
Vol. 14. Pp. 1081–1086.
[47]
Phillips, A. J., D. J. Childs, and H. M. Schneider. 1999b. “Water-Drop Corona Effects on
Full-Scale 500 kV Non-Ceramic Insulators.” IEEE Transactions on Power Delivery.
Vol. 14. Pp. 258–263.
[48]
EPRI. 2002b. Non-ceramic Insulator End Fitting Analysis. EPRI, Palo Alto, CA:
November. 1001744.
[49]
EPRI. 1999. Electric Field Modeling of NCI and Grading Ring Design and Application.
EPRI, Palo Alto, CA: December. TR 113-977.
[50]
EPRI. 2000a. 500 kV Aging Chamber – Testing and Final Results. EPRI, Palo Alto, CA:
1000719.
[51]
EPRI. 2002a. 230 kV Accelerated Aging Chamber: Description of Test and Condition of
NCI After One Year of Aging. EPRI, Palo Alto, CA: November. 01001745.
[52]
EPRI. 2002a. 230 kV Accelerated Aging Chamber: Description of Test and Condition of
NCI After One Year of Aging. EPRI, Palo Alto, CA: November. 01001745.
[53]
EPRI. 2003a. 230 kV Accelerated Aging Chamber: Condition of NCI After 2 Years of
Aging. EPRI, Palo Alto, CA: 1001746.
[54]
EPRI. 2004a. 230 kV Accelerated Aging Chamber: Condition of NCI After 3 Years of
Aging. EPRI, Palo Alto, CA: 1008737.
11762887
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[55]
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Insulators. EPRI, Palo Alto, CA: 1015917.
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Limits for the Design of Grading Rings for Composite Line Insulators.” IEEE
Transactions on Power Delivery, 2015, Vol. 30, No. 3, pp. 1110–1118.
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3
ELECTRICAL PERFORMANCE OF INSULATORS
Lightning Impulse Flashover Strength of Line Insulation
Defining the Lightning Impulse Strength of Insulation
Transient lightning overvoltages on transmission systems are characterized by very short
durations and fast front times. A typical overvoltage, as shown in Figure 3-1 has a front time (T1)
ranging between 0.1 μs and 20 μs and an overall duration—as defined by the time to half value,
(T2)—of less than 300 μs [1].
Figure 3-1
Definition of a fast-front transient overvoltage
These, so-called fast-front overvoltages [1] are represented, for testing purposes, by the Standard
Lightning Impulse. Ideally, this is an impulse with a double exponential wave shape, which is
defined in terms of its front time (Tf) and time to half value (Th) as shown in Figure 3-2.
Practically, laboratory generated lightning impulses often have significant noise (in the form of
fast oscillations) on the wave front so a virtual front is defined my measuring the time interval
from when the voltage reaches 30% of the peak (t0.3) until it reaches 90% of the peak value (t0.9).
The front time is then calculated as Tf = (t0.9-t0.3)/0.6 [4].
1.1
0.9
0.8
0.8
0.7
0.7
0.6
0.5
0.4
0.6
0.5
0.4
0.3
0.3
0.2
0.2
0.1
0.1
0
-1
0
Th
1
0.9
Voltage [p.u.]
Voltage [p.u.]
1.1
Tf
1
1
2
3
4
5
6
Time [μs]
0
-10
0
10
20
30
40
50
60
Time [μs]
Figure 3-2
Definition of the parameters characterizing the Lightning Impulse as per IEEE Standard 4.
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3-1
The standard Lightning Impulse has a defined front time of 1.2 μs and a time-to-half value of
50 μs. The testing standards further define limits on the overshoot, oscillations and tolerances of
the defining parameters [2] [3].
The dielectric strength of insulation relevant to lightning conditions is determined through
performing disruptive discharge voltage tests. These tests consist of a repetitive application of
voltage impulses to the insulation at different voltage magnitudes so that the probability for
flashover is determined as a function of the applied impulse voltage peak. Generally, it is found
that the probability for flashover increases as the magnitude of the applied impulse voltage is
increased. This statistical relationship is usually described with a cumulative normal (or
Gaussian) distribution, as shown in Figure 3-3, which is described in terms of its 50% flashover
voltage and standard deviation.
1
Standard Deviation = 3% of the CFO
Probability for Flashover [p.u.]
0.9
0.8
0.7
0.6
0.5
0.4
0.3
CFO
0.2
Statistical BIL
0.1
0
90
92
94
96
98
100 102 104 106 108 110
Applied voltage [% of CFO]
Figure 3-3
Probability for flashover in disruptive discharge tests as a function of the applied voltage.
For dimensioning purposes, the lightning impulse strength of a gap, or insulator, may be defined
in terms of [4]:
•
•
Critical flashover voltage (CFO), which is the crest value of an impulse wave that, when
applied under standard conditions, causes flashover on 50% of the total number of impulse
applications.
Basic insulation level (BIL) is the electrical strength of insulation expressed in terms of the
crest value of a standard lightning impulse under standard atmospheric conditions. BIL may
be expressed as either statistical (10% flashover probability) or conventional (withstands a
specified number of impulse applications). The statistical BIL is applied to self-restoring
insulation, and the conventional, to non-self-restoring insulation.
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3-2
The relationship between the CFO and BIL (statistical) is illustrated in Figure 3-3 and can be
calculated as follows:
BIL = (1 − 1.28 ⋅ c)CFO
Eq. 3-1
Where: “c” is the normalized standard deviation, which is given by the standard deviation
divided by CFO.
Some general findings from standard lightning impulse tests are:
•
•
•
•
On non-symmetrical gaps, the positive polarity flashover voltage is lower than that of the
negative polarity.
The standard deviation of the positive polarity lightning impulse strength of air gaps is in the
range 1.5% to 3% of the CFO [5] [6]. For gaps where the flashover path follows the surface
of the insulator the standard deviation may be 5 to 9 % higher.
The effect of the gap configuration on the flashover strength under lightning impulse tests is
much less than for switching impulse tests.
The introduction of insulators into the gap results in a significant change in the flashover
strength.
Critical Flashover Strength of the Line Insulation
The dielectric strength of transmission line insulation under lightning conditions is primarily
determined by the shortest strike distance from the “live metal” (a line conductor, corona ring,
yoke plate, etc.) to “ground metal” (a tower leg, cross arm, insulator hanger, etc.). Typical I- and
Vee-insulator strings are shown in Figure 3-4. The figure shows the principal insulation distances
that require consideration when determining the lightning impulse strength of the entire
structure. They are:
•
•
•
The dry arc distance across the insulator string (DI)
The vertical distance to the cross arm (Da)
The horizontal distance to the tower body (DL)
Figure 3-4
Flashover paths for a I, and V-string configuration.
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3-3
A distinction is made between pure air gaps, which are gaps without insulators (DL, Da-center phase)
and gaps containing insulators (i.e., Di and Da outer phase).
Present guidelines for estimating the lightning impulse strength of transmission lines is
summarized in a Cigré Brochure [7]. Their recommendations assume that the insulator presents
the weakest gap (DI in Figure 3-4) of all the competing gaps in the tower (i.e., DI, Da and DL in
Figure 3-4).
Both Cigré and IEC recognize that there is some influence of the gap configuration on the
flashover stress. A first estimate of the lightning impulse strength of transmission line
configurations may be obtained with the so-called “gap factor” method. With this method the
estimation of the insulation strength is based on a rod-plane gap with the same gap length, but
applying a suitable correction factor, or gap factor, to adjust for the differences in the insulation
configuration. The same defined gap factors are used for switching surges but are adjusted to
account for the fact that the lightning impulse strength is less impacted by insulation
configuration than the switching impulse strength.
The rod-plane air gap is used as reference because it is the weakest of all the pure air gaps and
has been studied extensively. A summary of the flashover gradient of rod plane gaps for a range
of gap lengths is given in Figure 3-5[8]. The graph for positive polarity lightning impulse tests
shows a constant flashover stress for gaps larger than 1 m and up to a gap length up to 20 m. For
negative polarity there is a clear non-linear trend with the flashover stress approaching that of
positive polarity for extremely long gap lengths.
Mean Breakdown Gradient [kV/m]
1600
Negative LI
1400
Positive LI
1200
1000
800
600
400
200
0
0.1
1
10
Gap Length [m]
Figure 3-5
Breakdown strength gradient of Rod-Plane gaps under lightning impulse and standard
atmospheric conditions [8].
There are some differences in the reported flashover stress for rod—plane gaps larger than 1 m
and for positive polarity. Jones and Waters estimates a value of 550 kV/m [8] whereas Cigré [6]
mentions values between 508 and 525 kV/m and the IEC assumes 530 kV/m [9]. These
variations fall within 5% of the mean, which is similar to that reported by Jones and Waters [8].
Based on these published gradients the critical flashover strength of a rod-plane gap (CFOr-p)
with length “d” may be estimated as follows [4]:
CFOr+− p = 525 ⋅ d 1 m ≤ d ≤ 8 m
11762887
Eq. 3-2
3-4
Figure 3-5 shows that the flashover gradient for negative polarity lightning impulse is a function
of the gap length. For short gaps the flashover gradient is about double that of the positive
polarity but approaches the flashover gradient for positive polarity for very long gaps. The best
fit to the data presented in the Cigré report [6] is given by [10]:
CFOr−− p = 950 ⋅ d 0.8
Eq. 3-3
For other gap configurations, the CFO can be calculated from the dielectric strength of rod-plane
gaps by applying a correction based on the gap factor, kg, as defined for switching impulses.
There are several equations proposed, but they are all basically derived from the same data. The
differences between them mainly originate from the differences in the flashover stress assumed
for the rod-plane gap. Continuing therefore with the equations presented in CIGRÉ Technical
brochure (TB) 72 [6] [4], the following generalized expression may be used for estimating the
positive polarity lightning impulse strength of air gaps:
CFO + = CFOr+− p (0.75 + 0.25k g )
For negative polarity the expression valid for air gaps smaller than 7 m is:
CFO − = CFOr−− p (1.51 − 0.51k g ) k g ≤ 1.44
CFO − = CFOr−− p (0.776) k g > 1.44
Eq. 3-4
The introduction of insulators into a gap generally leads to a deterioration of the lightning
impulse strength as the insertion of floating metal objects (as in the case of disc insulators) plays
a major part in the development of the flashover process. It is further reported that the effect of
inserting insulators in the gap is bigger for negative polarity than it is for positive polarity [6].
Based on the collected data, CIGRÉ [6] concluded that it is impossible to derive general
equations based on the gap factor (as has been done in the previous section for pure air gaps),
because the flashover strength is also influenced by the particulars of the insulator design and
construction (that is, disc vs. long-rod) and in the case of disc insulators, by the size of individual
insulator units (that is, standard vs. anti-fog units). They suggest, therefore, testing as the only
way to obtain accurate results. On the other hand, insulator manufacturers do publish the CFO
for their insulators in their insulator catalogs, but it is important to note that these tests are
performed with the insulator installed in an assembly that resemble the conductor upper-rod
configuration—which is not representative of a typical transmission line configuration.
For lighting performance calculations, Cigré [7] recommends a simplified approach where the
positive polarity CFO of the insulation of transmission lines is estimated on a flashover gradient
of 560 kV/m and that for negative polarity CFO on a flashover gradient of 605 kV/m. They
consider these gradients valid for all voltage levels and line configurations that do not utilize
wood as part of the insulation.
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3-5
Testing at EPRI [11] [12] [13] on typical 138 kV and 161 kV line configurations with glass and
porcelain disc insulators as well as polymer long-rod insulators have shown that:
•
•
•
•
The average flashover stress of porcelain or glass disc insulator strings is 536 kV/m of dry
arc distance.
The average flashover stress of polymer long-rod insulator is 569 kV/m of dry arc distance.
On a steel pole line configuration, it was found that the strength of the air gaps (without
insulators) is 544 kV/m of air gap length.
On a grounded wood pole line (with a single conductor ground lead) it was found that the
flashover strength of insulators was about 6 % higher compared the same insulators installed
on a steel pole configuration.
Electrical Performance of Insulators and Air Gaps Under AC Voltage
Introduction
An insulator needs to withstand all the electrical stresses that it is subjected to for the whole of its
expected life. These stresses include transient overvoltages, such as switching and lightning, as
well as more long-term voltage stresses, such as ac temporary overvoltage and the continuous ac
supply voltage.
Dry AC Flashover Strength of Air Gaps and Insulators
Experience shows that the dry ac flashover strength of air gaps and insulators is rarely a limiting
factor for the design of the insulation of overhead lines. It is usually only considered for
determining minimum clearances in the tower under maximum conductor swing conditions.
Dry AC Flashover Strength of Insulation Arrangements
Generally, the ac flashover strength of insulation arrangements found on transmission lines lies
between that of the rod-plane and rod-rod configurations unless special field grading is involved.
Figure 3-6 provides an overview of strength data for several basic insulation configurations [6]
[14]. Data for shorter air gaps is presented in Figure 3-7 [15]. In cases where the gap factor, “K”,
is known, the ac flashover strength may also be estimated with Equation 3-5 [16], which is valid
for gap spacings greater than or equal to 2 m:
𝑽𝑽𝒂𝒂𝒂𝒂_𝑪𝑪𝑪𝑪𝑪𝑪_𝒓𝒓𝒓𝒓𝒓𝒓 = 𝟕𝟕𝟕𝟕𝟕𝟕(𝟏𝟏. 𝟑𝟑𝟑𝟑𝟑𝟑 − 𝟎𝟎. 𝟑𝟑𝟑𝟑𝑲𝑲𝟐𝟐 )𝑳𝑳𝑳𝑳(𝟏𝟏 + 𝟎𝟎. 𝟓𝟓𝟓𝟓𝑳𝑳𝟏𝟏.𝟐𝟐 )
Eq. 3-5
In this equation, Vac_CFO_rms is the rms value of the 50% ac flashover voltage under dry
conditions, and L is the length of the air gap. The withstand voltage may be calculated by
assuming a standard deviation of 2%; therefore, at the 3-σ level, it would be 94% of the 50%
flashover voltage (CFO).
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3-6
Critical Flashover Voltage (Crest) [kV]
2000
1600
1200
Rod - Plane
Rod - Rod
Conductor - Plane
800
Conductor - Lower structure
Conductor - Lateral Structure
Conductor - Rod (vertical)
400
Conductor - Rod (tower leg)
Insulator String (Dry)
0
0
1
2
4
3
5
6
Gap Spacing [m]
Figure 3-6
AC flashover strength of air gaps [6].
50% a.c. flashover gradient (kV/m)
600
500
Rod-rod (dry)
400
Rod-plane (dry)
300
200
100
0
0
0.5
1
1.5
2
2.5
3
3.5
4
4.5
5
Gap spacing (m)
Figure 3-7
AC flashover gradient of rod-rod and rod plane gaps under dry conditions. Note that the rod-plane
data is represented by a band [15].
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3-7
Effect of Fire
Fires under transmission lines have proven to be a major cause of transmission-line outages. For
example, in South Africa, 15.6% of transmission-line faults were classified as due to fires under
the lines [17]. Investigations have shown that fires under lines cause a dramatic reduction in the
withstand strength of the air between phases and between phase and ground [18] [19] [20] [21]
[21].
The heat in the flame associated with a fire reduces the air density according to the well-known
expression (Equations 3-6):
δ=p
293
273 + t
Eq. 3-6
Where:
δ = air density relative to a pressure of 1.0 bar and a temperature of 20°C.
p = pressure in bar.
t = air temperature in °C.
Bearing in mind that temperatures as high as 900°C are found in the flames of a large fire, the
equation shows that the air density can be reduced to 25% of its value at 20°C. Since breakdown
strength is directly proportional to air density [6], the heat of the fire can reduce the strength of
the air to 25% of its value at 20°C. However, elevated temperature is not the only mechanism
present in a fire that causes a reduction in the breakdown strength. Wilderness (bush) and
agricultural-land fires produce conducting particles in the air gap, which increase the
conductance of the gap. The carbonized particles in the gap shorten the electrical length of
the gap, and they are also sources of electrons, contributing in two ways to increasing the
conductivity of the air [21]. Long carbon particles, like those produced by sugarcane fires, lead
to the greatest reduction in breakdown strength [18] [20]. Measurements have shown that the
resistivity of an air gap in a fire ranges between 5 MΩ-m and 25 MΩ-m [23]. Because of the
combined effect of these mechanisms, the withstand gradient in the presence of a fire can be
reduced to as little as 10% of that without the fire. Flashovers are most common at mid-span,
since that is where the clearance to ground is the least [23] [18] [22].
Fires also lead to deposits on the surface of the line insulation. However, it has been found that
the conductivity of the deposits is very small compared with other environmental deposits and
does not make a significant contribution to insulator flashover [18].
When considering the impact of fires on line design, investigations have shown that it is
necessary to achieve an average gradient between conductors and between conductors and
ground of not more than 11 kV/m if fire flashovers are to be eliminated [19]. Table 3-1 gives
representative values for the average field associated with modern transmission lines (taken from
data in [23]).
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3-8
Table 3-1
Average Gradient to Ground, at Mid-span, as a Function of Transmission-Line Voltage
Max System voltage, kV (rms)
145
245
300
420
800
Average gradient, kV (rms)/m
13
20
23
30
31
From the table, it is obvious that the gradients of transmission lines of 200 kV and above are too
high to prevent flashover to ground in the event of a bush fire. The cost of increasing the
clearances to values where the probability of flashover is negligible is so significant that it is not
done. Rather, the strategy is to manage the right-of-way by regular clearing of the vegetation
under the line and controlling the nature of farming activity in the right-of-way.
Bird Streamers
Bird excrement may also lead to flashover directly across the air gap by forming a continuous
streamer of up to 2.5 m (for large birds). These streamers may span enough of the air gap in the
tower window to cause flashover under steady-state ac conditions. This phenomenon proved to
be the explanation of many “unknown” flashovers in the United States [24], Germany [25], and
South Africa [17]. The only solution is to install bird guards to prevent the birds from sitting
above critical gaps in the tower [26] [27].
Wet AC Flashover Strength of Air Gaps and Insulators
Rain may substantially reduce the ac strength of insulator strings, depending on the rate of
rainfall, conductivity of the rainwater, and the insulator configuration considered [28]. Typical
flashover stress levels on glass and porcelain cap-and-pin insulators are between 250 and 300 rms
per meter of section length during standard wet tests, with a low conductivity artificial rain [29].
Figure 3-8 shows the wet rms ac flashover strength of a selection of typical disc insulator strings.
The main insulator parameters that influence the flashover voltage are the spacing of the
individual discs and their diameter. The results in Figure 3-9 show the wet rms ac flashover
voltage of a typical silicone rubber insulator. This curve has been based on catalog data [30].
A comparison of these curves shows that there is not much difference between the wet flashover
strength of ceramic and glass disc and hydrophobic composite insulators. Hydrophilic polymer
insulators may have a wet ac flashover voltage that is 10–20% lower than that of the
hydrophobic ones [31].
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3-9
50% Wet a.c. flashover voltage (kV)
1400
1200
1000
800
600
400
200
0
0
1
2
3
4
5
6
Insulator length (m)
Figure 3-8
Wet rms AC flashover voltage of various shapes of cap-and-pin insulator strings [29].
50% Wet a.c. flashover voltage (kV)
1400
1200
1000
800
600
400
200
0
0
1
2
3
4
5
6
Insulator length (m)
Figure 3-9
Wet rms AC flashover voltage of a silicone rubber insulator [30].
The rainfall rate mainly influences the flashover strength by the amount of water that cascades
down from one unit to the next. The effect is greatest on vertically orientated strings (I-strings).
For testing purposes, ANSI Standard C-29.1-1961 has specified a rain rate of 5 mm/min. This
rate is equivalent to an extremely heavy rain, which rarely occurs in nature, and it causes a
reduction in strength on long insulator strings of about 30% from the clean, dry critical flashover
voltage [28] [32] [33] [34]. While this heavy rain rate was used historically, current wet tests on
power apparatus are performed at a more realistic rain rate of 1.5 mm/min and a resistivity of
100 ohm-meters [28] [2] [35]. Figure 3-10 shows the correction factor curve used at Project
UHV for rain rate. The critical flashover voltage for clean, dry conditions is defined as 1 p.u.
To find the critical flashover voltage at any rain rate, one multiplies the reference value by the
corresponding correction factor.
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3-10
Figure 3-10
Correction factor for rate-of-rain on the AC flashover strength of I-strings [36].
Critical ac flashover voltage also depends on water resistivity. The resistivity of rain is affected
by pollution of the air, salt particles near seacoasts, and different kinds of contaminants near
industrial areas. As rain begins, the rainwater resistivity is lowest, thereafter increasing with
time. Figure 3-11 shows the correction factor curves used at Project UHV for rain resistivity on
glass and ceramic insulators. The curve corrects the per-unit critical flashover voltage versus
water resistivity for the case of a rain rate of 5 mm/min. As a reference value, Figure 3-11 uses a
resistivity of 17.8 kΩ/cm. The slope of this curve is less for a lower rain rate.
Figure 3-11
Correction factor for rainfall resistivity on the ac flashover strength of insulators [36].
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3-11
Increasing levels of rainwater resistivity also adversely affect the ac flashover voltage of polymer
insulators. Hydrophilic insulators are more affected than hydrophobic insulators, as shown in
Figure 3-12 [31]. However, even hydrophobic insulators are strongly affected for rainwater
conductivities above 10 mS/cm.
400
Flashover stress (kV/m)
350
Hydrophobic
300
250
200
150
Hydrophilic
100
50
0
100
1000
10000
100000
Rain conductivity (µS/cm)
Figure 3-12
Relationship between ac wet flashover and rain conductivity for hydrophobic and hydrophilic
polymer insulators [31].
Contamination Flashover Performance of Insulators
Introduction
Contamination-related outages came to the fore soon after the introduction of high-voltage
transmission in the 1930s, which prompted the development of many of the presently used
insulator monitoring-techniques, such as leakage current measurement. (Note: In other parts of
the world, the term insulator “pollution” is also used. The words “pollution” and
“contamination” will be used interchangeably in this text.) Since then, the study of transmissionline performance under contaminated conditions has become increasingly important. Both the
IEEE and CIGRE have active and long-standing working groups dealing with this subject. The
work of these groups culminated in a series of important review publications [37] [38] [39].
Also, during this time, polymer insulators were developed, which proved to be effective in
reducing the number of contamination-related outages, especially if the insulator housing
material was hydrophobic. Polymer insulators are, however, more prone to the effects of aging—
an issue that will be dealt with in section dealing with the long-term performance of insulators.
Power frequency flashovers on transmission systems are often the result of airborne
contamination that is deposited on the insulators. These contaminants may originate from natural
sources such as the sea or desert, or they may be generated by industrial, agricultural, or
construction activities. One of the most common contaminants is sea-salt (sodium chloride),
which may cause severe problems on transmission-line insulators in coastal areas. Other types of
salt, such as magnesium chloride, may cause problems in inland areas, where it is increasingly
used on highways to combat ice during the winter season. In industrial or agricultural areas, a
great variety of substances, such as gypsum, sulfuric acid, fly ash, and cement, may be present as
contamination on the insulators. Generally, these deposits do not decrease the insulation strength
when dry; they only become a threat under wet conditions, when the salts contained in the
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deposit dissolve to form a conductive layer on the insulator. Often, however, the contamination
may already be in the dissolved state when deposited onto the insulator, as may happen when the
insulators are exposed to a saltwater fog. Under certain extreme cases—for example, close to
certain types of mining activity—the deposits themselves could be conductive (e.g., metallic or
carbon deposits); wetting is not required to reduce the strength of the insulator.
The formation of a conductive layer on an energized insulator leads to the flow of leakage
current and the formation of dry bands in the areas with a high current density. When this
happens, the voltage distribution along the insulator becomes highly nonuniform, with most of
the voltage stress concentrated over the dry bands. This concentration of voltage stress may
cause the dry bands to spark over. If this happens, a partial arc is established in series with the
resistance of the conductive layer on the insulator. Depending on the layer conductivity, this
partial arc may grow to span the whole insulator, leading to flashover.
In summary, three aspects play an important part in the contamination flashover process [40]:
1. Buildup of contaminants on the insulator surfaces
2. Wetting of the insulator
3. Discharge activity and its development into flashover
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Table 3-2
Key Processes of the Contamination Flashover Process
Wetting
Contaminant Build-Up
Description and Mechanisms
Influencing Factors
1.Clean Insulation surface
None
2. Contamination Deposited
a. Airborne particles
b. Salt spray
c. Electric field (mainly DC)
d. Under dry conditions surface remains a good insulator
• Aerodynamic properties
• Surface properties
• Contamination type
3. Cleaning (removal of contamination)
a. Rain
b. Wind
• Insulator profile
• String orientation
• Precipitation type and intensity
4. Wetting of Contamination Layer
a. Condensation
b. Fog
c. Rain
d. Absorption
e. Chemical diffusion
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• Contamination type (e.g., salt
solubility)
• Insulator profile
• Surface properties
• Wetting type
3-14
Table 3-2 (continued)
Key Processes of the Contamination Flashover Process
Description and Mechanisms
Influencing Factors
5. Formation of Dry Bands
a. Leakage current flows on surface
b. Increased heating in regions of high current density
c. Dry bands form in regions of increased heating
• Surface resistance
- Humidity of air
- Rate of rainfall
- Level of contamination
Discharge Activity and Flashover
• Distribution of contamination
- Insulator geometry
6. Dry Band Arcing
a. Dry bands interrupt leakage current flow
b. Full voltage across dry bands
c. Air/surface cannot maintain potential difference
d. Arcs form across dry bands
e. Leakage currents surge when arcs form
• Surface properties
7. Growth/Quenching of Dry Band Arcs
a. Dry band arcs sustained if surface resistance of entire string is low
enough
b. Increased heating at arc roots dries out contamination, increasing
dry band size and hence arc length
c. Surface resistance decreases with increasing arc lengths, resulting
in increased leakage current magnitudes
d. Arc grows and may self-extinguish as gap bridged becomes too
large for arc to maintain itself
e. Arcs may be quenched by precipitation
• Surface resistance
- Rate of precipitation
- Humidity
- Amount and type of contamination
- Surface properties
8. Flashover
a. If dry band arcs bridge a critical length of insulator, flashover occurs
b. Multiple arcs may join (coalesce)
c. Single arc may grow entire length
• Surface resistance
- Rate of precipitation
- Humidity
- Amount and type of contamination
- Surface properties
• Degree of wetting
• Level of contamination
• Size of dry band
• Insulator profile
• Insulator profile
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I
V
Each of these aspects may comprise several subprocesses, as highlighted in Table 3-2. Although
these subprocesses are listed as individual items in the table, in reality they combine into one
seamless process. Some of the listed items may occur simultaneously, while others may happen
at different times.
In practical situations, two types of contamination are generally identified: in this chapter, the
terms “solid” and “liquid” contamination will be used. In the revised edition of the IEC 60815
[41], these types are identified as Types A and B, respectively. These two types can be described
as follows [39]:
•
•
Solid contamination, or predeposited contamination. Contaminants are deposited. Flashover
may occur in a separate phase when the insulator is critically wetted by rain, fog, or
condensation.
Liquid contamination, or instantaneous contamination. Contaminants and wetting are
deposited on the insulator surface simultaneously, which may result in flashover.
Of these two types of contamination, solid contamination occurs more frequently, and it may
originate from industry, agriculture, mining, bird feces, road-salt, or the sea. Examples of liquid
contamination are salt fog conditions or liquid salt spray directly from the sea, or mist from
cooling towers.
The deposition and wetting conditions associated with solid and liquid contamination are
distinctly different, as will be highlighted in the sections that follow.
Buildup of Contaminants on Insulator Surfaces
Types of Contaminant
Solid Contaminant
The deposited dry contaminants can be described in terms of two distinct components [39]:
•
•
Soluble contaminant that, when in dissolved in water, will form a conductive solution.
Examples include ionic salt such as sea-salt (NaCl), gypsum, and CaSO4, or other
constituents such as fly ash and cement.
Nonsoluble contaminant, which reduces the insulator’s flashover voltage due to retention of
water and the resulting influence on the formation of the conductive layer. Nonsoluble
pollution may also be hydrophobic, such as oily or greasy substances that may enhance the
insulator flashover characteristics.
Liquid Contaminant
The active component of liquid contamination is already in the dissolved state when it is
deposited on the insulator surface. Typical examples are saltwater spray close to the coast or
gases in solution, such as SO2, H2S, or NH3 close to chemical plants. Liquid contamination
generally contains little to no nonsoluble contaminants.
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Mechanism of Contaminant Deposit
Solid or liquid contaminants can be deposited onto the insulators by several mechanisms.
•
Aerodynamic action. Contamination particles suspended in the air can be carried over great
distances by wind [42]. When this contaminant-laden air encounters an insulator, the air is
deflected around the insulator body. The particles suspended in the air are, however, not
deflected to the same extent and are deposited on the insulator. Denser particles (e.g., sand)
will be deposited on the windward side of the insulator since they are not sufficiently
deflected by the airflow, as illustrated in Figure 3-13. Less dense particles will follow the
airflow more closely and will only be deposited in areas where the airflow becomes turbulent
(i.e., small curvature of the airflow), such as on the leeward side of the insulator or between
the shed under-ribs [43]. Figure 3-14 shows the concentration of the contamination deposit in
areas of turbulence, as indicated by the arrows. Aerodynamic action is, with a few
exceptions, the dominant mechanism of contamination deposit [44].
Air stream
Dense particles
Insulator
Light particles
Path of suspended particles
Figure 3-13
Pollution deposit by aerodynamic action [43].
Figure 3-14
Photographs showing typical particle distribution on aerodynamically contaminated insulators.
Note the concentration of the contaminants in areas of turbulence, as indicated by the arrows.
•
Precipitation by gravity. Under low wind or still conditions, suspended particles in the air
will precipitate and settle on horizontal surfaces under the influence of gravity. Precipitation
by gravity may be the dominant mode of pollution deposition in areas close to a distinct
contamination source, such as an industrial plant.
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•
•
Heating effect of leakage current. During conductive fog conditions, the heating effect of
the current evaporates the water from the wet contaminant, leaving a salt residue behind. This
residue is normally concentrated around the areas of the insulator with the highest current
density. Heating by leakage current occurs on insulators installed close to the coast that are
exposed to salt-fog.
Electric field. Contamination may be deposited on the insulator surfaces due to the force
exerted by the electric field on charged particles. This effect is, however, negligible under
power-frequency energization, because of the alternating polarity of the field. It is more
relevant for direct current energization, which falls outside the scope of this document.
Natural Cleaning of Surface Contaminant
Generally, two agents may remove contaminants from the insulator surface, thereby reducing the
risk of flashover. These agents are:
1. Precipitation. High-intensity rain is very effective in removing contaminants from insulator
surfaces. Exposed (i.e., top) surfaces that come in direct contact with the rain are most
effectively cleaned. The more protected, or bottom, surfaces on the insulator may also
undergo a significant amount of cleaning, but this cleaning is reduced as the amount of
“protected” creepage increases [45].
2. Wind. In desert areas, strong winds may carry large sand particles that have a “sand
blasting” effect, removing pollutants from the windward side of the insulator.
Accumulation of Contaminants on Insulator Surface
Solid Contaminant
Contamination settles on the insulating surfaces in the form of dusty deposits. The contamination
may be naturally removed from the insulators by the mechanisms indicated. The extent of this
removal is related to the intensity and duration of the cleaning event. As a result, the level of
contamination deposit varies over time, with the highest levels occurring at the start of cleaning
events. Over time, equilibrium is reached when the rates of deposition and cleaning are in
balance with random variations. Depending on the environment, it may take from weeks to years
to reach this equilibrium [43]. In cold climates, where icing performance is a concern, the longest
periods without rain tend to occur over the winter season. For example, climate norms for
Minneapolis, Minnesota in the United States suggest that maximum temperature will be below
freezing from December to March, a period of 120 days, well in excess of the days between rain
events during the spring, summer, and fall.
Liquid Contaminant
Wet pollution is characterized by the fast buildup of contaminants during events when the
insulator is exposed to simultaneous pollution and wetting. In this case, the heating effect of the
leakage current plays a major role in the deposition process, with the highest pollution deposit
occurring in the areas with the highest current density on the insulator [38]. The buildup of the
deposit on the insulator may, in fact, be so fast that a clean insulator can accumulate enough
contaminants to flash over during a single event. Thus, natural cleaning has little influence on the
flashover process in the case of liquid pollution.
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Effect of Insulator Properties on Accumulation of Contaminants
From the description above, it should be clear that the level and distribution of contamination are
the result of a complex interaction between the insulator and the environment. This process is
influenced by the profile of the insulator, its surface properties, and the orientation in which the
insulator is installed. All these factors need to be taken account of when selecting insulators for a
particular environment. Some guidelines are provided below:
Profile
•
•
When insulators with convoluted profiles are exposed to wind-borne pollution, vortices are
created by the under-ribs, which are conducive to the deposition of pollution, as illustrated in
Figure 3-15 [43]. These regions are also sheltered, reducing natural cleaning and resulting in
high contamination levels over time.
Insulator shapes having large horizontal surfaces are at a disadvantage when contaminated by
gravitational precipitation, as these surfaces present large areas on which the contaminants
can settle.
Figure 3-15
Airflow around a disc insulator [43]
Based on these principles, it can be concluded that: Open aerodynamic profiles tend to be
beneficial in areas where there is a risk of a long-term buildup of airborne contaminants since
these profiles collect generally less pollution and are accessible for natural or artificial cleaning.
When there is a risk of a rapid buildup of contaminants, such as during storm conditions, profiles
with a more convoluted design can be advantageous since large parts of the surface are
“protected” from fast pollution accumulation. Likewise, profiles with large horizontal surfaces
should be avoided in the presence of a significant gravitational precipitation.
Surface Properties
The insulator surface properties are also important in determining how much pollution attaches
to the surface:
•
•
Smooth surfaces accumulate less pollution than rough ones.
Dry surfaces retain less pollution than damp ones.
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•
Studies have shown that silicone rubber insulators, due to the presence of the silicone oils,
collect more contaminants than glass or ceramic surfaces [46] however, this is offset by the
hydrophobicity encapsulation of the pollution layer [47]. The surface hydrophobicity also
influences the uniformity of the pollution deposit. The surface hydrophobicity causes the
contaminated water drops to bead on the surface, leaving distinct spots of contamination
behind when the water evaporates [48]. On the other hand, solid pollution is not affected in
the same way—due to absence of water—resulting in a more uniform deposit [49] [50].
Insulator String Orientation
Vertically orientated insulator strings (I-strings) collect more contamination than angled
(V-strings) or horizontally (dead ends) installed units since these units have large, sheltered areas
on the underside of the insulator where natural cleaning is less effective.
Horizontally orientated insulator strings pointing to, or from, a well-defined source may collect
more contamination than strings pointing in other directions due to the larger windward and
leeward regions where airborne deposition may occur [51].
Wetting Processes
Wetting Mechanisms
It is commonly recognized that flashovers caused by contamination generally occur during
drizzle, fog, or high humidity conditions due to a reduction in the surface resistance. Four
wetting processes are recognized [52] [53] [54]:
•
•
•
•
Collision of water droplets. The insulator is wetted by the collision of free water droplets in
the air (e.g., during rain, mist, or fog) with the insulator. The distribution of the wetting on
the insulator is dependent on the insulator shape and the droplet size. Small droplets are more
likely to wet the insulator underside since they are more influenced by air movement around
the insulator.
Hygroscopic behavior of surface deposits (absorption). Surface contamination absorbs
water molecules from the air by the process of deliquescence if it is salt, or absorption if it is
a nonsoluble material. For typical contamination layers, this process occurs when the partial
vapor pressure of the ambient is greater than the vapor pressure of the salt; for sodium
chloride, this occurs approximately at a relative humidity of 75%. The type of salt and inert
material present determines the distribution and amount of the wetting.
Condensation. Condensation occurs when the insulator surfaces are colder than the ambient
temperature and are below the dew point temperature. The temperature difference is due to
thermal lag or radiation and is, therefore, influenced by the thermal properties of the
insulator. Polymer insulators, due to their low thermal conductivity and thermal mass, adjust
quickly to the ambient temperature, resulting in small temperature differences, while a larger
temperature difference would occur with glass and porcelain insulators during the same
conditions. Hence polymer insulators have less condensation than glass or porcelain
insulators [50].
Chemical diffusion. The condensation rate is higher for solutions than for pure liquids due
to the phenomenon of chemical diffusion. This is a contributing factor that results in a higher
rate of condensation on moist contaminated surfaces than on clean surfaces.
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These wetting processes combine during different ambient conditions to produce a characteristic
wetting-pattern on the insulator surface. Some examples are:
•
•
•
•
Clear conditions. Under clear air conditions, moisture can only be deposited on the insulator
via condensation or moisture absorption. The whole insulator surface is likely to be wetted
during these conditions. Typically, this wetting occurs during late night or early morning
when the insulator may be cooler than the ambient air due to thermal radiation or thermal lag.
Fog or mist. Fog occurs when the ambient air is cooled down sufficiently that condensation
occurs in the air itself, resulting in suspended water droplets. The wetting of the insulator
surface is mainly through collisions of fog droplets with the insulator surface, but
condensation and absorption also make a significant contribution. The whole insulator
surface is likely to be wetted during these conditions, unless deep shed under-ribs are present,
which prevent effective droplet collision with the protected parts on the insulator.
Salt spray. In areas close to the coast, wind can transport the salt-spray produced by the
breaking waves. Wetting occurs due to the collision of the droplets with the insulator surface.
The distribution of the wetting is mainly determined by the aerodynamic properties of the
insulator and the size of the salt-water droplets. Logically, the exposed upper surfaces are
wetted most effectively, but the insulator underside may also be wetted to some extent due to
the turbulence created by the under-ribs, if present.
Rain. Rain wets the insulator surface by the collision of the raindrops with the insulator
surface. It is mostly the upper surfaces of the insulator that are wetted, while the “protected
creepage” remains relatively dry.
The rate by which the moisture impinges on a contaminated insulator may vary from light,
during mist or fog, to heavy, during rain. It may further impinge on the insulator surface gently,
as during a light drizzle, or violently as during a wind-driven downpour. As the rate of the
wetting increases, so does its natural cleaning effect, as was discussed in the previous section.
These are important factors that need to be considered when identifying when wetting conditions
pose the greatest risk to the insulators.
Critical Wetting on Solid or Predeposited Contamination
In an area characterized by a predeposited contamination layer, the soluble electrolytes within
the contamination coating gradually dissolve. A thin film of conducting liquid then forms on the
insulator surface if it is hydrophilic, or droplets form if the surface is hydrophobic. As the
wetting continues, a redistribution of the contamination may take place, and some of the
contamination may even leach by run-off. Because of these processes taking place, the surface
resistivity initially decreases due the salts that dissolve and increases after a while due to the
leaching effect.
The minimum resistivity of the layer (i.e., highest conductivity) and the time at which it occurs
are very dependent on solution characteristics of the predeposited contamination layer. Both the
solubility and the speed by which it goes into solution play an important role [55] [56].
•
The impact of the wetting rate on the flashover voltage is greater for low-solubility than for
high-solubility salts. This difference was illustrated during laboratory tests that found a
greater reduction in flashover voltage as a function of the steam input rate on insulators
polluted with gypsum, as compared with insulators polluted with sea-salt [57].
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•
•
The amount and type of nonsoluble contamination present also influence the wetting process.
The nonsoluble contamination “binds” water to the insulator surface, which helps the
formation of the low-resistance layer, resulting in a lowering of the flashover voltage.
Different kinds of inert material influence the time it takes to reach the minimum resistivity
and the value of the minimum resistivity depending on its hygroscopic and hydrophobic
properties [58].
Thus, the surface conductivity of the insulator is the result of a complex process that depends not
only on the amount of moisture and the chemical composition of the soluble and nonsoluble
contaminants, but also on the material and shape of the insulator itself. On this basis, the critical
wetting is defined as a wetting rate that is fast enough to wet the pollution sufficiently for the
flashover process to take place and slow enough not to wash the pollutants from the insulator
surface. In general, low wetting rates, such as during fog or mist, are critical for fast dissolving
salts, and a heavy wetting rate is required to produce critical conditions for slow dissolving salts.
For instance, in coastal areas where the main pollutant is sea-salt (NaCl), condensation or fog
conditions generally provide sufficient wetting to dissolve the contamination layer, whereas in
certain industrial areas, where gypsum is prevalent, a more severe wetting condition, such as
rain, is needed to dissolve the contamination layer.
Wetting Aspects When Dealing with Liquid Contamination
Under conductive-fog conditions, the contaminants are deposited in the dissolved state. This is
typical of sea storms when sea spray may be carried inland by wind, or close to industrial plants
where the insulators may be exposed to a conductive rain or fog. The dissolving characteristics
of the salts involved are, in this case, not important; what is important is the conductivity of the
solution itself. A higher conductivity solution results in a greater risk of flashover. Leakage
current flowing in the surface layer will cause a drying out in the areas of the insulator with the
highest current density, and the initiation of dry-band activity [59]. This electrical activity may
also enhance the deposition of salt on the surface due to the heating effect of the current.
Discharge Activity and Development of Flashover
A critical part of the contamination flashover process is the formation of the conductive layer
on the insulator’s surface. The presence of such a layer invariably leads to a very nonuniform
voltage distribution along the insulator and the inception of discharge activity. Depending on the
conductivity of this layer, the wetting conditions, and the surface properties of the insulator, the
discharge activity may develop into a flashover. The discharge development is basically the same
for both solid and liquid pollution types, so no distinction will be made in the text that follows.
However, the discharge development is markedly different on hydrophilic (e.g., ceramic and
glass) and hydrophobic (e.g., silicone rubber) insulators. These two types of insulator will,
therefore, be treated separately.
Hydrophilic Insulators
Contamination Flashover Process on Single-Unit Insulators
Development of electrical discharges on contaminated insulators will be discussed with reference
to the simplified diagram presented in Figure 3-16.
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Figure 3-16
Typical steps and their associated voltage distribution, in the discharge development of
contaminated insulators. (A - Wetting begins, B - Dry bands form, C - Consolidation of dry bands,
D - Scintillation, E - Discharges extend, F - Flashover) [37].
The following description covers the flashover process from the formation of dry bands to the
final arc in terms of the steps identified in Figure 3-16.
•
•
•
Condition A. As wetting increases, the impedance of the insulator lowers and changes from
mainly capacitive, at the start of the wetting, to mainly resistive. This is demonstrated by the
change of surface impedance over time presented in Figure 3-17 [60] [61] [62], as measured
during laboratory tests. The increase of the capacitance shown in the figure is a result of the
increase in the conductive area on the insulator surface.
Condition B. This reduction in impedance leads to an increased level of leakage current
across the insulator, which, in turn, leads to the formation of dry bands in the areas with the
highest current density due to localized heating. On disc insulators, this is around the pinand-cap area. The dry band blocks the flow of leakage current, which results in a
concentration of the applied voltage over the dry bands. Figure 3-18 shows this voltage drop
around the pin area of the disc insulator, as measured during laboratory tests. Corona and
sparking activity ensue, which leads to a further drying out and an increase in the size of the
dry band, until a stable condition is reached where the dry band can withstand the applied
voltage with occasional sparkovers [37].
The degree to which dry bands form initially and the rate at which they reabsorb moisture
depend on the intensity of the wetting process and the drying effect of the leakage current. In
falling rain conditions, the wetting action may be so intense that dry band formation may not
be possible until after the rain ceases.
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Figure 3-17
Example of dynamic surface impedance of standard insulators. (Salt-deposit density =
0.07 mg/cm2; kaolin = 40 g/l.) Applied voltage per 5¾ in. (146 mm) disc = 6.3 kV.
Figure 3-18
Voltage distribution measured from grounded cap before onset of scintillation for different values
of surface impedance magnitude.
•
Condition C. When the dry band is established, the general level of leakage current over the
insulator drops, which allows the wetting process to overcome the drying effect of the
leakage current. On long-rod insulators, this effect may lead to the re-wetting of the smaller
dry bands and the formation of only one dominant dry band, which is maintained by the
heating effect of the discharge and corona activity [63].
11762887
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•
Condition D. During the occasional sparkovers of the dry band, the voltage distribution over
the insulator becomes more linear. This observation is supported by experimental findings,
such as those presented in Figure 3-19, which shows the average measured voltage
distributions along the insulator surface for different levels of leakage current. This
linearization is more pronounced at higher levels of leakage current, and it is caused by the
voltage drop associated with the current flow through the conductive surface layer [37].
Figure 3-19
Typical measurement results of the dynamic voltage distribution on a disc type insulator under
various levels of leakage current.
•
•
Condition E. Exactly how the scintillation activity develops into flashover is not yet fully
understood, as many factors influence this process. Most theoretical studies have been based
on a simplified model that assumes the contaminated insulator surface is already wetted and
highly conductive [64] [65] [66] [67]. However, these models ignore the drying effect of the
leakage current and partial arcs on the wet pollution layer, which in some cases can be so
intense that it extinguishes the partial arc over the insulator, preventing flashover despite a
high level of leakage current.
However, on single-disc insulators, it is known that the arc develops from the high-voltage
electrode, and that the complete flashover is the result of the growth of the partial discharges
to span the whole insulator length.
Condition F. At an advanced stage of discharge development, flashover is determined by the
breakdown strength of the contamination layer, which holds most of the voltage [37].
Flashover Mechanism of Long Insulator Strings under Light Wetting Conditions
During the contamination tests at Project UHV [36], which were performed under a relatively
low degree of wetting, it was found that a nonlinear voltage distribution on the insulator string
might exist. This suggests that the contamination flashover of long insulator strings might be
different from that of single insulator discs. From observations, the following phases in the
flashover process were identified:
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•
Initially, the contaminated insulator surface is completely dry. Consequently, the voltage
distribution on the string may be regarded as the same as that on a dry, clean insulator string
(i.e., mainly capacitive). The equivalent circuit may be represented by a network of
capacitances only, since the leakage resistance of the insulator surface may be ignored (see
Figure 3-20). This distribution is usually nonuniform, with the highest voltage stress on the
insulators closest to the high-voltage end.
Figure 3-20
Equivalent circuit for voltage distribution along contaminated insulator string.
•
As the wetting progresses, the resistance of the insulator becomes more important. The value
of this resistance is influenced by the drying effect created by leakage current and corona
discharges, which are functions of the voltage across individual discs. Since the electric field
distribution along the string is not uniform, the voltage across the units closest to the
conductor is higher, and hence these units dry out first, forming a dry zone.
The surface temperature of the discs in the dry zone is much higher than that of the insulators
on the remaining section of the string. A wet zone is usually formed at the mid-section of the
string, where the voltage drop is the lowest. Thus, the nonuniform voltage distribution can be
held throughout the time of wetting. Surface leakage current in this period is about
100–600 mA (rms).
•
•
As the dry zone dries out further and the wet zone becomes wetter, the voltage across the dry
zones increases. Finally, the units on the bottom section can no longer withstand the voltage
stress, and they flash over. This is observed when an arc bridges several units at the bottom
of the string.
The activity develops upward. The arcs bridging the bottom section result in an overvoltage
across the rest of the string, producing heavier activity along the string. This activity appears
as leakage current surges, usually having peak values ranging from 500 to 700 mA (rms).
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•
•
The leakage currents dry the insulator surfaces in the wet zone, linearizing the voltage
distribution along the entire string and reducing the voltage drop across the initial dry zone,
extinguishing the arc. However, this heavy activity does not make the insulator surfaces in
the wet zone as dry as those of the dry zone of the string.
After the activity has ceased, the insulator surfaces under low-voltage stress begin to absorb
moisture, making the values of surface impedance lower. The units in the high field region
do not absorb as much moisture due to their higher temperature. Therefore, the voltage
distribution along the string again becomes nonuniform enough to produce another surge.
This process is repeated either until a flashover develops or until the surge activity gradually
disappears as the contaminants are leached from the insulator surface.
Because it is a thermal process that causes the nonlinearity of the voltage distribution along the
string [68][69], it does not appear when the rate of surface wetting is fast enough to overwhelm
the drying effect of the leakage current. Since the rate of wetting in natural conditions is often
low, this nonlinear phenomenon has only been found for those tests in which the wetting
condition was arranged to duplicate a natural wetting process. These nonlinear effects are
reduced when the voltage distribution along the insulator string is made more uniform by the
application of a grading/corona ring, an effect that has been illustrated in tests.
Influence of Pollution Level and Degree of Wetting on Flashover Development
Observations of artificially polluted insulators under natural wetting conditions have shown that
the degree of discharge activity is a function of both the contamination severity and the degree of
wetting [70]. These observations were performed during times when condensation and moisture
absorption were the main wetting processes. A schematic diagram, based on the observations, is
presented in, to illustrate this dependency. Images taken with a daylight ultraviolet camera
during the different zones identified in Figure 3-21 are presented in Table 3-3.
Figure 3-21
Schematic diagram of typical discharge activity on artificially polluted insulators, as observed
during natural wetting conditions. Zone I: No activity, Zone II: Corona, Zone III: Scintillation,
Zone IV: Quiet, Zone V: Intermittent sparking, Zone VI: Flashover. The different zones are
described in more detail in the accompanying text.
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Table 3-3
Photos of the Typical Discharge Patterns That May Be Observed During the Zones Defined in
Figure 4.4-9
Zone I: No
Activity
Zone II:
Corona
Zone III:
Scintillation
Zone IV:
Quiet
Zone V:
Intermittent Sparking
Zone VI:
Flashover
The following distinct phases, or zones, were observed:
Zone I
No discharges occur on dry insulators independent of the contamination level. Clean
insulators also showed no discharges independent of the degree of wetting.
Zone II In this zone, the insulator is partly wet, and corona discharges occur at the edges of the
wet areas. These are generally concentrated in the high E-field stress areas of the
insulator string.
Zone III A dry band is established, and sparking activity occurs—Condition B in Figure 3-16.
This level of activity can be maintained for a relatively long time since the heating
effect of leakage current is insufficient to increase the size of the dry band. Therefore,
this type of activity is mostly common on insulators with a critical-to-subcritical level
of pollution.
Zone IV If the degree of wetting is balanced by the drying-out effect of the leakage current, a
stable condition arises that is characterized by a low level of discharge activity—
Condition C in Figure 3-16.
Zone V If the wetting rate is high enough to overcome the drying effect of the leakage current,
occasional sparkovers of the dry band occur. This corresponds to Conditions D and E
in Figure 3-16.
Natural cleaning and a quenching of the discharge activity take place if the degree of wetting is
higher than the critical wetting rate.
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Effect of the Insulator Properties
On convoluted insulator designs, scintillation discharges may take shortcuts between the shed
protrusions, rendering a part of the leakage distance ineffective [67] [71]. This phenomenon is
generally more apparent at lower contamination levels where the capacitive steering of the
voltage across the insulator is still significant. A comparison of different insulator types at low
contamination severities shows that the flashover strength of insulators is not proportional to the
leakage distance. At a higher degree of contamination, the conductivity of the surface layer is
low enough so that the scintillation discharge follows the surface more closely, and the flashover
strength is more proportional to the leakage distance.
On both single insulator discs and long insulator strings, the flashover process is driven by the
nonuniform voltage distribution caused by thermal phenomena related to the leakage current.
Recognizing this, some measures to improve the contamination performance may be proposed.
For instance, employing insulators having high capacitance between cap-and-pin can reduce the
nonuniformity of voltage distribution on long insulator strings, because the voltage distribution
along the string would be greatly linearized. Also, a better contamination performance of single
insulator units can be expected when the voltage concentration around the pin is greatly reduced
[72].
Hydrophobic Polymer Insulators
The flashover process on hydrophobic polymer insulators is markedly different from that of
hydrophilic insulators such as porcelain and glass. Observations of the leakage current behavior
of polymer insulators show a continuous low level of current that is interspersed with single high
current spikes [73]. This finding is in contrast with the gradual buildup of current over ceramic
and glass insulators and the densely spaced high current pulses. The main reason for the
difference in behavior is the hydrophobicity that inhibits the formation of a continuous
conducting layer of the polymeric insulator.
When a hydrophobic insulator is wetted—by condensation, fog, or rain—the water on the
surface forms into droplets due to the hydrophobic properties. Through a process of diffusion,
some of the salt on the insulator dissolves into the water, making the droplets conductive. The
water from the drops also migrates into the dry pollution to form a damp layer with a high
resistance. At this stage, a high resistive layer with conductive water drops scattered over it
covers the insulator. The leakage current across the insulator reaches a stable, but low, value
once equilibrium is reached between the evaporation caused by the heating effect and the
reduction of the surface resistance by wetting [74] [75].
The scattered water drops on the insulator surface react to the presence of the oscillating electric
field in two ways: first, the water drops elongate on the sheath sections and flatten under the
oscillating force that the electric field exerts on the polar water molecules, and second, the
electric field is enhanced at the edges in the wet areas because of the high permittivity of the
water. If neighboring droplets are close enough, these may coalesce to form runnels, leading to
a further strengthening of the electric field at the edges. The electric field may be increased
sufficiently to cause corona discharges [77] [74] [75]. The discharge activity may reduce the
surface hydrophobicity locally, which may help the formation of longer runnels.
11762887
3-29
On short insulators with a relatively uniform E-field distribution, the leakage current across the
insulator may increase sufficiently over time to cause the formation of a dry band on the shank
(or sheath) of the insulator, which is the area of the highest current density [78]. As the
hydrophobicity breaks down further in the high-stress zones, the dry-band activity extends to
the sheds. The discharges extend as the water runnels extend further, resulting in sparking that
bridges the wet areas. Depending on the conductivity of the water, the sparking may eventually
extend to reach a flashover.
On long insulators (transmission voltages), the electric field along the insulator is very nonuniform, and the initial corona and sparking activity occurs in the area of the highest electric
field close to the high voltage end. This activity causes the highly stressed section of the
insulator to dry out more than the rest of the insulator, forming a high resistance area compared
with the rest of the insulator [73]. This effectively blocks the leakage current from flowing. The
highly nonuniform field concentrations at the ends of this high-resistance area may initiate a
streamer breakdown process. If the streamer discharge spans the high resistance section, and the
width of this region is large enough, a condition will arise whereby the wet section of the
insulator is overstressed. The streamer can then quickly develop into a flashover. This flashover
process is characterized by a general absence of leakage current, until the breakdown of the high
resistance section, leading to single high current pulses or flashover.
Contamination Flashover Strength of Insulators
Over the years, many reports have been published on the performance of insulators under
contaminated conditions. It is generally difficult to extrapolate results from one particular
insulator to another, since small changes in the profile may lead to quite big differences in
performance. On the other hand, most transmission lines are installed with very similar, or in
many cases, the same type of insulator. In this section, some general conclusions are presented
regarding transmission line insulators, based on the assumption that most are installed with disc
insulators or polymer longrod insulators. Some information is also provided regarding porcelain
post insulators.
Results are presented for both glass-and-porcelain insulators and polymer insulators separately
since their characteristics differ considerably. It is, however, difficult to draw general
conclusions for polymer insulators since there is still no general agreement on a standardized
method to determine the contamination performance of these insulators [79]. Consequently, the
results from different laboratories cannot be compared directly.
Glass and Porcelain Insulators
Flashover Voltage as a Function of Contamination Severity
Figure 3-22 shows withstand specific creepage distance as a function of contamination severity,
based on a compilation of published results for standard-shape disc insulators [39]. This
relationship can be adequately described by Equation 3-7 and Equation 3-8:
𝑉𝑉
𝐿𝐿
= 𝐴𝐴 ∙ 𝛾𝛾 −𝛼𝛼
Equation 3-7
Flashover Gradient
or
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3-30
𝐶𝐶𝐶𝐶
= 𝐵𝐵 ∙ 𝛾𝛾 𝛼𝛼
𝑉𝑉
Equation 3-8
Unified Specific Creepage Distance
V = flashover voltage.
L = section length of the insulator.
CD = leakage (or creepage) distance of the insulator.
γ = contamination severity level.
A, B, and α are experimentally determined constants.
Figure 3-22
Withstand ac contamination performance of standard types of disc insulator based on the results
from Salt-Fog and the Solid-Layer tests [39].
The value of α, which determines the “slope” of the curve, can be considered as a weighted
average of the value for an electrolyte (α = 0.33) and that of air (α = 0). For line insulators, a
value of α = 0.2 can be considered typical [43].
Table 3-4 presents the constants of the above equations associated with the curves in Figure
3-22. These values assume that the flashover gradient is expressed in kV/m and the Unified
Specific Creepage Distance (USCD) in mm/kV. (Note: the unified creepage distance is the
11762887
3-31
creepage, or leakage, distance of the insulator divided by the maximum operating voltage across
the insulator, not the phase-to-phase system voltage as previously defined for the creepage
distance, as used in the 1984 version of IEC 60815.) The values for A were derived from B by
assuming a creepage distance to section length ratio of 2.21, which is typical for a standardshape disc insulator.
Table 3-4
Experimental Parameters for the Withstand Curves Presented in Figure 3-22
Type of Laboratory Test
(Severity Parameter)
Lower Limit
Average
Upper Limit
A
B
α
A
B
α
A
B
α
Salt – Fog (kg/m )
115.7
19.1
0.22
134.8
16.4
0.22
156.7
14.1
0.22
Clean – Fog (mg/cm2)
38.8
56.9
0.22
45.1
49.0
0.22
52.6
42.0
0.22
Wet contaminant (µS)
126.3
17.5
0.28
148.3
14.9
0.28
175.4
12.6
0.28
3
Insulators with a long leakage distance, the so-called antifog insulators, have generally higher
flashover strengths per unit length, as compared with standard units, as shown in Figure 3-23.
These results have shown:
•
•
•
The performance of antifog insulators is not always proportional to leakage distance. The
flashover values approach that of standard insulators at low contamination severity levels,
while at high contamination levels, the performance becomes more proportional to the
leakage distance.
The spacing of the insulator discs is an important parameter at low pollution levels (i.e.,
SDD < 0.1). A larger spacing results in a higher flashover voltage, even if the leakage
distance is kept the same.
Larger discs, with a diameter greater than 280 mm, have higher flashover strengths than
regular disc insulators with a diameter of 254 mm.
Figure 3-23
Flashover voltage of antifog insulators in relation to that of a standard-shape disc. (Labels on the
graph refer to insulator types listed in Table 3-5) [36]
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Table 3-5
Geometrical and Mechanical Characteristics of the Insulator Units Tested at Project UHV
Type
Image
Spacing (SP)
(mm)
(in.)
Diameter
(mm)
Leakage Distance
(LD)
(in.)
(mm)
Ratio
Mechanical Strength
(in.)
LD/SP
(kg)
(lb)
305
12
2.08
7,500
15,000
Standard-type
A-11
146
5 3/4
254
10
Fog-type
F-2
165
6 1/2
320
12 1/2
510
20
3.08
18,000
40,000
G-2
170
6 3/4
305
12
520
20 1/2
3.04
18,000
40,000
H-1
146
5 3/4
254
10
435
17
2.95
11,500
25,000
H-2
160
6 1/4
290
11 1/2
470
18 1/2
2.94
18,000
40,000
H-3
198
7 3/4
400
15 3/4
690
27
3,5
30,000
66,000
H-4
220
8 11/16
420
16 1/2
740
29
3.34
40,000
90,000
L-2
170
6 3/4
320
12 5/8
545
21 1/2
3.2
23,000
50,000
L-5
250
9 13/16
420
16 1/2
720
28 1/4
2.9
55,000
120,000
M-1
140
5 1/2
280
11
435
17
3.08
11,500
25,000
M-4
200
7 7/8
380
15
540
21 1/4
2.72
38,000
84,000
N-3
184
7 1/4
330
13
572
22 1/2
3.11
30,000
66,000
N-5
230
9 3/16
380
15
730
28 3/16
3.16
55,000
120,000
Longrod and post insulators have approximately the same flashover performance as standardshape insulators, as illustrated in Figure 3-24. The shed profile of these insulators may, however,
significantly influence the ultimate flashover strength. For example, experimental data has
shown insulators with a spiral shed design to perform inferior to a regular shed design [80].
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Figure 3-24
Performance of post insulators. (Standard disc A-11 – see Table 3-5 – is shown as a reference.)
[36]
In previous section, the importance of the nonsoluble components in the contamination layer was
highlighted. Standardized solid layer tests utilize a nonsoluble deposit density (NSDD) of 0.1 mg
per cm2 of surface area of the insulator. In desert areas, the NSDD may be much higher, which
may severely affect the flashover voltage. As Figure 3-25 shows, longrod insulators are more
affected by NSDD than disc insulators, and the reduction in flashover strength can be by as much
as 40% in extreme cases [58]. These results show the importance of taking account of the
nonsoluble deposit density when dimensioning insulators. It may even be prudent to confirm the
insulator performance with testing at appropriate NSDD levels.
The type of soluble contaminants on the insulator may also affect the flashover under fog
conditions [56] [81]. Results from comparative Clean-Fog tests with different kinds of
contamination salts are shown in Figure 3-26. These results show that low-solubility salts have a
higher fog withstand voltage than high-solubility salts such as sodium-chloride.
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Comparitive contamination withstand
voltage (p.u.)
1
0.8
Disc insulators
0.6
Longrod insulators
0.4
0.2
0
0.1
1
10
100
Non-Soluble Deposit Density (mg/cm2)
Figure 3-25
Influence of the amount of non-soluble material on the contamination withstand voltage of disc
and longrod insulators [39].
Clean Fog Withstand Voltage [kV/unit]
20
Test insulators: 254-mm Standard disc type
NSDD: 0.1 mg/cm2 (constant for all tests)
CaSO4 . 2H2O
15
10
CaCl2 [≈MgSO4, MgCl2]
Na2SO4 [≈Mg(NO3)2]
NaCl [≈NaNO3]
5
0
0.01
0.1
1
Equivalent Salt Deposit Density [mg/cm2]
Figure 3-26
Influence of various salts in the contamination layer on the insulator fog withstand voltage [81].
Leakage Path Length
In most international standards the leakage path length is used as the main parameter for the
dimensioning of insulators with respect to contamination. The guidelines commonly used are
presented in Table 3-6. A comparison of this table with Figure 3-22 shows that the creepage
distance guidelines agree well with the performance of standard-shape disc-type insulators. This
agreement is probably because the recommendations were based on the performance of standardshape disc insulators in the first place.
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Table 3-6
Commonly Used Guidelines for the Selection of Creepage Distance Based on ESDD
Measurements
Pollution Class
From IEC ESDD
(mg/cm2)
IEEE ESDD
(mg/cm2)
Unified Specific Creepage Distance
(mm/kVp-g)
< 0.03
21 (IEEE only)
1. Light
0.03–0.06
0.03–0.06
28
2. Medium
0.10–0.20
0.06–0.1
35
3. Heavy
0.30–0.60
>0.1
44
4. Very heavy
> 0.80
55
The reasons for the differences in the classifications of the IEC and IEEE are not clear. It could
be speculated that the differences may be due to differences in the NSDD levels of the typical
environment on which each of these recommendations was based.
However, a growing body of evidence suggests that neither the leakage distance nor the section
length can be used as a sole parameter for dimensioning [82]. This fact is also demonstrated in
Figure 3-23, which shows that:
•
•
At low pollution levels, the antifog and reference insulator have a similar flashover stress,
despite the large differences in the leakage path length.
At high pollution levels, the flashover voltage per unit length of the antifog units is much
higher than that of the reference insulator.
Observations during tests at a low contamination severity have shown that the growth of the dryband arcing takes place through air, whereas at a high contamination severity, the breakdown is
more likely to follow along the surface. The greater amount of inter-skirt breakdown at low
contamination levels, therefore, reduces the leakage distance effectiveness of antifog insulators
[82]. This is illustrated graphically in Figure 3-27.
Figure 3-27
General effect of inter-skirt breakdown on the creepage distance requirement of antifog
insulators.
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3-36
Other conditions may also exist when the leakage path may be rendered less effective. Field
observations of longrod insulators with a close shed spacing have shown that the dry-band arcing
often develops from the shed tips, as can be seen in Figure 3-28. This is in contrast to laboratory
tests, with a higher degree of wetting, where dry-band arcing typically follows the surface much
closer.
Figure 3-28
Discharge development on a porcelain longrod insulator under natural wetting conditions.
In conclusion, the creepage distance concept seems to work well for those cases where the
insulator profile has been selected to suit the environment. The concept breaks down, however,
for inefficient profiles where nonlinear effects, such as inter-shed or inter-skirt breakdown,
become important.
Natural Versus Artificial Contamination Tests
In Figure 3-29, the ac flashover voltage data obtained at three different natural test stations
(situated in coastal areas) is compared to those of artificially polluted insulators under a CleanFog test [83]. It shows that:
•
•
The withstand voltage is about the same for the natural and artificial tests.
The dispersion in the test results of natural tests is greater than that of artificial tests.
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Figure 3-29
Results of ac natural contamination tests compared with clean-fog tests [83].
The larger dispersion of the natural test results is mainly due to variations in the wetting
conditions, as well as the greater nonuniformity of the contamination deposit during the natural
tests.
For inland areas, the agreement between artificial and natural contamination tests is not always
as good. In most cases, this is because of higher levels of nonsoluble contaminants and the
presence of low-solubility salts [84].
Linearity of Flashover Voltage as Function of Insulator Length
In the preceding sections, the results were presented based on the assumption of a linear
relationship between insulator length and flashover voltage. There seems to be general
agreement, based on results from both natural and artificial contamination tests, that this is in
fact, correct [81] [51] [43]. However, some evidence from laboratory tests performed at Project
UHV suggests a nonlinear relationship for insulator strings of over 3 m in length and low
contamination levels (i.e., a Salt Deposit Density of below 0.02 mg/cm2) [36]. The results
suggest further that this non-linearity is accentuated by natural wetting conditions (i.e.,
noncritical wetting). Based on these tests, the concept of the long-string efficiency, λ, has been
defined, which is expressed as Equation 3-9:
𝝀𝝀 =
Where:
𝑳𝑳𝑬𝑬𝑬𝑬𝑬𝑬 ∙𝑽𝑽𝑼𝑼𝑼𝑼𝑼𝑼
Eq. 3-9
𝑳𝑳𝑼𝑼𝑼𝑼𝑼𝑼 ∙𝑽𝑽𝑬𝑬𝑬𝑬𝑬𝑬
λ = long-string efficiency.
LUHV = string length required at UHV voltage level.
LEHV = string length determined at lower voltage level.
VUHV = UHV voltage level.
VEHV = lower voltage level.
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The dependence of long-string efficiency on the line-to-earth voltage is shown in Figure 3-30,
which applies to standard vertical insulator strings up to 11.5 m connection length [39]. The
equivalent salt deposit density (ESDD) is in the range of 0.01-0.04 mg/cm2. For antifog
insulators, the results for long-string efficiency are shown in Figure 3-31 for string connection
lengths up to 8 m. In this case, the range of ESDD is 0.02–0.04 mg/cm2 [39].
No general agreement still exists on how the long-string efficiency should be applied when
dimensioning insulators, since this mainly occurs under light wetting and low contamination
severities. This reduction in strength, which is only on the order of 5–10%, needs to be weighed
against the greater uncertainty with which the site contamination severity is known.
Long String Efficiency, λ [%]
100
95
90
85
80
75
70
65
60
300
400
500
600
700
800
900
Voltage [kV]
Figure 3-30
Long-string efficiency for ac energization as a function of line-to-ground voltage. Range of ESDD
0.01-0.04 mg/cm2 [39]. IEEE insulators (146 mm spacing, 254 mm diameter, and ratio leakage to
spacing 2.1).
Long String Efficiency, λ [%]
100
95
90
85
80
75
70
65
60
300
400
500
600
700
800
900
Voltage [kV]
Figure 3-31
Long-string efficiency for ac energization as a function of line-to-earth voltage. Range of ESDD
0.02-0.04 mg/cm2 [39]. Antifog insulators (220 mm spacing, 420 mm diameter, and ratio leakage to
spacing 3.3).
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Effect of Insulator Orientation on Contamination Flashover Performance
It is generally agreed that inclined and horizontal line insulators have a better contamination
performance than vertical insulators. The most important orientation effect is the accumulation
of pollution, where inclined and horizontally installed insulators are more accessible for natural
cleaning.
Also, during artificial testing, inclined and horizontally installed insulators may have
significantly higher flashover voltages, as illustrated in Table 3-7, which presents the 50%
flashover strength for the horizontal and V-string configurations, as compared to equivalent
flashover strength for I-strings. All tests were conducted on identical-length standard-shape
insulators (Type A-11 – see Table 3-5) at a Salt Deposit Density of 0.02 mg/cm2 (average). Table
3-7 also gives a comparison of long-string efficiency (λ). From these results, it may be seen that
the strength of horizontal configurations falls between the I- and V-configurations, and that they
are somewhat more linear (higher λ). It would appear that these results, together with the
available data on I- and V-strings, provide a sufficient guide for horizontal string usage.
Table 3-7
Comparison of 50% Flashover Strength and Long-String Efficiency for Different String
Configurations (ESDD = 0.02 mg/cm2)
Applied Voltage (kV l-g)
Relative Strength Using I-String as Reference
Horizontal
I-String (Ref)
V-String
370
1.22
1.0
1.60
740
1.29
1.0
1.63
λ = 95%
λ = 90%
λ = 92%
Flashover Performance of Closely Spaced Insulator Strings
Insulator assemblies consist sometimes of multiple insulator strings to fulfill mechanical or
security requirements. Experimental results have shown that a reduction occurs in flashover
strength over and above that expected from statistical considerations. The following trends were
observed [85] [86]:
•
•
•
•
•
The flashover strength of closely spaced strings may be up to 30% lower than that of an
identical single string. From purely statistical considerations, a reduction of only 7% is
expected.
The reduction in strength is caused by partial arcs bridging the gap between the parallel
insulator strings.
The proximity effect was independent of the laboratory test method used.
Proximity effects have been observed on disc, longrod, and post insulator types.
The proximity effect is independent of the orientation (i.e., vertical, inclined, or horizontal)
of the parallel insulator set. Horizontal insulators are subjected to more frequent instances of
natural cleaning, which may counter the proximity effect in practical situations.
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•
•
The reduction of strength increases with a decrease in the spacing between the parallel
insulator sets.
The reduction in strength was higher for longer insulator sets.
Based on the test results, an inter-string spacing of between 400 and 500 mm is recommended.
Tapered insulator installations with a closer string spacing at the live end than at the grounded
end may also offer a significant improvement in the flashover voltage of the double string.
Polymer Insulators
Overview of Contamination Flashover Performance
Hydrophobic polymer insulators generally have a superior contamination flashover performance
when compared to that of glass and porcelain. Tests at Brighton insulator testing station showed
that hydrophobic (i.e., silicone rubber) insulators exhibited a 60% higher flashover voltage than
ceramic or glass insulators of the same axial length, and hydrophilic polymer insulators (i.e.,
EPDM) showed a 20% better flashover performance [87]. Most transmission line owners who
have changed the line insulation from glass or porcelain to polymer insulators have reported a
major improvement in line contamination outage performance [88] [89]. The reasons for this are:
•
•
•
•
Surface hydrophobicity. Good hydrophobicity is very efficient in preventing the formation of
a uniform wet surface that is so fundamentally important to the contamination flashover
process [90]. A part of the contamination deposit may also be “neutralized” by the
hydrophobicity transfer phenomenon [91].
Thermal characteristics. Polymer insulators adjust quickly to the ambient temperature. The
wetting is, therefore, less efficient than on ceramic and glass insulators under critical wetting
conditions [50].
The slender shape of the insulators. For a given surface conductance, insulators with a
slender shape will have a higher overall resistance than insulators with a larger diameter.
Longer leakage distances. Polymer insulators are often installed with a longer leakage
distance than ceramic and glass insulators [92]. This is often done to avoid material
deterioration due to leakage currents.
The above discussion does not account for differences between the contamination collection on
polymer and ceramic or glass insulators (e.g., aerodynamic profile and surface roughness).
Certain exceptions exist where the implementation of polymer insulators was not successful. In
areas prone to bird streamer outages, an increased line outage rate was reported after the
installation of polymer insulators. This increased rate was ascribed to the presence of corona
rings and the resulting shorter strike distance to the tower on replacement units [24]. In extreme
contamination conditions, polymer insulators may suffer from erosion and eventual electrical or
mechanical failures due to the long-term exposure to damaging levels of leakage current [89].
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Effect of Hydrophobic Properties on Insulator Flashover Performance
The level of surface hydrophobicity has a great influence on the surface conductivity of
contaminated insulators during wetting conditions. Surface hydrophobicity measurements have
shown that the surface layer becomes increasingly conductive for a level of hydrophobicity of
above HC 4 (see Figure 2-16) [93]. This level corresponds to the level of hydrophobicity when
water runnels form on the surface. This behavior is reflected in the flashover gradient, as shown
in Figure 3-32 [90]. (A runnel is defined as a narrow channel of water.)
Insulator Flashover Gradient [kV/cm]
1.4
1.2
1
0.8
0.6
SDD [mg/cm2]
0.02
0.08
0.4
0.4
0.2
0
-7
-6
-5
-4
-3
-2
-1
Hydrophobicity Class
Figure 3-32
Flashover voltage over the leakage distance, as a function of the hydrophobicity class, as
determined by modified Clean-Fog tests [90]
Results from field inspections of hydrophobicity concluded that silicone rubber insulators
showed good long-term hydrophobic properties (HC 1–4) in most environments, except close to
the coast where hydrophobicity may regularly be suppressed. It was also noted that the loss of
hydrophobicity is often very localized and concentrated around the end fittings, especially
around the high-voltage end where the electric field is the highest [94] [76] [77]. EPDM
insulators do not have significant long-term hydrophobic properties (i.e., typically in the range of
HC 5–7) [92] [95].
Flashover Voltage as Function of Contamination Severity
Laboratory tests on polymer insulators suggest that the performance of polymer insulators as a
function of contamination severity can be expressed by the same power function as that used for
ceramic and glass insulators. An example of typical results (NGK test method) is presented in
Figure 3-33, which shows that silicone rubber insulators offer a significant improvement in
insulator flashover stress as compared with standard disc insulators [96]. Tests indicated that this
improvement may be between 20 and 70%, depending on the condition of the insulator’s
hydrophobicity when tested [90].
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180
NSDD = 0.1 mg/cm2
50% Flashover Gradient (kV/m)
160
140
Silicone Rubber
120
100
EPDM
80
60
Standard disc
40
20
0
0.01
0.1
1
Salt Deposit Density (mg/cm2)
Figure 3-33
Comparison of the flashover stress of a hydrophobic silicone rubber insulator [96] to that of a
standard-shape disc insulator (derived from Figure 3-22 and based on a standard deviation of 8%).
The level of nonsoluble deposits in the contamination layer, as expressed by the NSDD, affects
the flashover voltage of polymer insulators to the same extent as the ceramic longrod insulators
(see Figure 3-25) [58].
Laboratory test results suggest strongly that the contamination performance of hydrophobic
polymer insulators should be evaluated under heavy wetting conditions [97] [98] [31]. Not only
should the steam fog input rate used in Clean-Fog tests be much higher than specified in the
standards, but also simulated rain tests on contaminated insulators are important to evaluate the
shed profile and spacing in terms of water-cascading effects.
Resistive Glaze Insulators
Insulators with semiconducting glaze have been available for some time. The use of these
resistive coatings has been found effective both in suspension- and post-type insulators for EHV
applications as a solution for insulation design in heavily contaminated areas. The presence of a
resistive coating on the insulator surface results in two phenomena that lead to superior
contamination performance. First, the continuous current flow of approximately 1 mA through
the resistive layer provides enough heat on the surface of the insulators to keep them dry in dew
or fog. Second, the resistive grading results in a significantly more uniform electrical stress along
the insulator length. However, in the past, some difficulties have occurred with the fabrication
and field life of these insulators. Significant technological improvements have since been made,
and substantial service experience exists. Consequently, their use should be considered in the
contamination design of UHV transmission lines.
An important limitation on the use of resistive glaze insulators for EHV applications is the
operating stress of 10–12 kV/unit suggested by several manufacturers. On an 1100-kV system,
for example, 58 units would be required if the nominal rating were 11-kV/unit. The use of such
long insulator strings raises performance- and cost-related questions. First, there is some concern
as to the voltage distribution on these long strings, even if they are semiconducting. Second, the
11762887
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issue of thermal stability, with even a slightly nonuniform voltage distribution, should be
considered. Finally, there is the economic consideration of the acceptability of a constant power
loss due to resistive heating.
The voltage distribution on a long string of semiconducting glaze insulators will be more
uniform than on a conventional string because of the resistance of each unit [99]. The thermal
stability of a long string should also be better than that of a short string because changes in the
impedance of one unit have a small effect on the total string impedance. Consequently, the total
series current does not change very much, and it is, therefore, reasonable to expect that the test
results obtained with short strings in fog tests at constant voltage will also apply to the long
strings required for UHV. This is also because the primary mechanism involves the heating of
the surfaces of each insulator.
To verify that the performance of semiconducting glaze insulators would exceed that of
conventional insulators in the type of artificial contamination tests used at Project UHV, tests
were conducted on suspension units with a predeposited contaminant and a clean fog. The
insulators were the standard shape (146 mm by 254 mm) and were intended for energization at
11 kV per unit and a nominal resistive current of 1 mA. Short strings containing five units of
these insulators were contaminated with a 40/100 mixture of Kaolin and NaCI (g/l)
corresponding to a Salt Deposit Density of about 0.25 mg/cm2, which represents a heavy level of
contamination severity. The insulators were energized at a constant voltage of 11 kV/unit and
exposed to the clean fog. The heat dissipation of 11 W/insulator kept the surfaces dry, and no
flashovers occurred. Thus, it was verified that this type of insulator is effective for heavy
contamination in areas where wetting usually occurs by fog.
The possibility of reducing string lengths with semiconducting glaze insulators was investigated
with units designed for nominal 15-kV, 1-mA operation. Such insulators would be attractive for
UHV line design. For example, on an 1100-kV system, 42 of these insulators would be required.
This would mean a shorter overall string length than that possible with the number of
conventional units [100] necessary for even light contamination. (This calculation assumes the
semiconducting glaze units have the same spacing as the conventional ones.) Although the use of
such semiconducting glaze units will aid in the power-frequency design of UHV lines, the
resulting increased stress per unit in this case requires that attention be focused on the insulation
strength during the energization of strings that are contaminated and wet, a condition known as
cold switch-on. This situation occurs on lines that have been unenergized for a period of time
long enough to render the heating, which results from the semiconducting glaze while the units
are energized, ineffective in preventing the accumulation of moisture on the insulator surface.
Some data on the cold switch-on strength of semiconducting glaze insulators are available [101].
However, these data were obtained with relatively short strings, containing ten units (1.5 m) or
fewer. The purpose of the tests reported here was to extend the data to strings that would be
suitable for UHV transmission systems and to make a direct comparison with the cold switch-on
strength of conventional insulators, which have a similar shape.
The cold switch-on test voltage was not applied to the insulator strings until they were
thoroughly wet from the clean fog. To determine the time at which this condition was achieved,
impedance measurements were made either on the strings to be tested or on an auxiliary monitor
string that was prepared in an identical manner to the test strings. The impedance was found by
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applying a maximum voltage of 1 kV/unit to the insulators every five minutes for a duration that
was only long enough to measure the current, generally 0.5 s or less. When the resistance
reached its minimum value and was stabilized, the test series was begun.
In the test, two I-strings (one conventional and the other semiconducting glaze) were always
tested in parallel by applying the full test voltage alternately to the conventional string for a
maximum duration of 30 s and to the semiconducting glaze units for 5 s, with another application
of voltage on each string every 10 min. The 50% flashover voltage was determined by an upand-down technique, in which the voltage for consecutive shots was raised or lowered by ~10%
depending on whether a withstand, or a flashover, occurred. The total time of the test series was
about 2–3 h. Consequently, the results of 10–15 voltage applications on each string were used to
determine the 50% flashover voltage for a given string length and contaminant.
The preceding test procedure was devised after performing enough tests to verify that the short
time durations, intervals, and total test time did not influence the performance. The data on cold
switch-on strength are presented in Table 3-8 for the two types of insulators and two different
contaminants. The results showing 50% flashover strength as a function of string length are
given in Figure 3-34.
The issue of constant heat-energy dissipation and its economic penalty should be considered in
any widespread application of the semiconducting glaze insulators. As an example, consider the
possible use of these units for 1100-kV transmission. With 1 mA resistive current, each leg of a
semiconducting glaze string would dissipate 581 W. Assuming a double V-string for each phase,
the dissipation per tower would be 7.0 kW. With four towers per mile, the constant loss due to
these insulators would be 28 kW per mile. For a typical 1100-kV design, the expected total
average yearly 12R and corona loss would amount to 110 kW/ mile. This implies that the
insulator losses are 30% of these other losses and are thus a factor that would contribute
significantly to operating costs. These costs, however, must be balanced against the costs of
over-insulation, greasing, or live-line washing, which might be required for conventional
insulators. In cases of heavy contamination, the cost of power lost due to scintillation and dry
band arcing of conventional insulators may also be worth considering.
Table 3-8
50% Cold Switch-on Flashover Voltage of Conventional and Semiconducting Glaze Insulators
Number of Units
Contaminant
50% Flashover Voltage (kV)
kV/unit
15
—
143 Conv.
9.5 Conv.
—
173 S.C.
11.5 S.C.
—
285 Conv.
9.2 Conv.
(40/20)
305 S.C.
9.8 S.C.
—
525 Conv.
9.4 Conv.
—
525 S.C.
9.4 S.C.
—
575 Conv.
9.0 Conv.
—
620 S.C.
9.7 S.C.
31
56
64
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Table 3-8 (continued)
50% Cold Switch-on Flashover Voltage of Conventional and Semiconducting Glaze Insulators
Number of Units
Contaminant
50% Flashover Voltage (kV)
kV/unit
14
—
160 Conv.
11.4 Conv.
—
155 S.C.
11.1 S.C.
—
275 Conv.
11.0 Conv.
(40/40)
286 S.C.
11.4 S.C.
—
595 Conv.
10.6 Conv.
—
615 S.C.
11.0 S.C.
25
56
Figure 3-34
Cold switch-on flashover voltage as a function of string length [36].
Performance of Insulators in Freezing Conditions
Introduction
The accumulation of contamination during or followed by ice or freezing fog accretion has
proved to create particularly severe conditions for insulators in power systems to withstand. In
many areas, improvements in switching surge control led to the adoption of reduced insulation
levels—for example, 1550-kV BIL for 500-kV systems, where many utilities had used 900-kV
BIL for 230-kV systems. This insulation level has proved to be inadequate in cases where
moderate levels of contamination (often caused by road salting in the winter) can be exposed to
freezing conditions that include fog or freezing rain.
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In the years 1993–2001 (excluding 1997), the National Electric Reliability Council
(www.nerc.com) reported 307 severe disturbance events. Of this total, six involved ice storms,
and three of these were mainly mechanical problems, such as the collapse of 1300 hydro towers
on January 4–9, 2003. Notable problems traced to the combined effects of pollution
accumulation and winter precipitation are:
•
•
•
March 10, 1986. Ontario Hydro nearly lost the operational use of its 500-kV network through
a rare combination of contamination buildup (16 days without rain) and relatively mild
winter icing conditions, leading to 57 flashovers on 500-kV lines and stations within a 2-h
period. Nearby 230-kV and 115-kV lines were not affected.
December 14, 1994. NERC Report on Western Systems Coordinating Council (WSCC)
system disturbance affecting 1.7 million customers: “The three-terminal 345 kV (Idaho
Power) Midpoint-Borah-Adelaide No.1 line protection scheme correctly detected a single
line-to-ground fault when a contaminated insulator bell flashed over to ground. These
insulator strings are located in an agricultural area and are prone to collect dust and fertilizer
contamination. The insulators had been washed the previous month.”
December 20, 2000. NERC Report on New Brunswick Power (NBP) Salt Contamination/
Freezing Rain Related Loss of Transmission: NBP experienced a series of transmission
system outages as a result of salt contamination on insulators combined with precipitation in
the form of snow and freezing rain. The insulator contamination monitoring stations in the
Saint John area recorded their highest level ever of contamination the day before the short
circuits occurred. The contamination occurred following two days of strong southwesterly
onshore winds (70 mph) off the Bay of Fundy, which deposited salt spray from high waves
over a wide area in the south of the province. Light snow and freezing rain on the
contaminated insulators caused five 345-kV flashovers and many lower-voltage flashovers in
a 2h period on December 20, 2000. As the precipitation turned to rain, the salt spray
contamination on the insulators began to wash off, and the insulators regained their voltage
withstand capability.
Most troubles have occurred on transmission lines and stations that are located near sources of
salt, such as the ocean or urban expressways. With typical road salting levels of 16 tons per lane
mile in the winter season for most provinces and states that perform winter maintenance, a
location near an expressway is equivalent to a location 1 km from the seacoast.
A “Smart Washing” insulator monitoring and maintenance program using deionized water in
freezing conditions has allowed one utility [102] to maintain adequate 500-kV network reliability
without reinsulating a large number of stations and lines. With the relatively rare problem
occurrence, this choice can be valid in many areas of limited exposure.
Clean- and Cold-Fog Test Results
Cold-Fog tests [103] on a variety of pre-contaminated insulators are summarized in Figure 3-35
Results are all expressed in terms of critical flashover strength (50%) for 30 min of exposure of
line-to-ground voltage under cold fog conditions, including fog of moderate visibility (< 4 km)
and temperatures rising from below to above 0°C. Results from conventional fog tests on strings
of suspension insulators are plotted as circles to compare with the Cold-Fog test data.
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Cold-Fog Line-to-Ground Flashover Voltage divided
by Leakage Distance,
kV/m
80
500-kV post
230-kV 5xPin / 14xDisc
115-kV 3xPin
69-kV post
Theory: 300-mm Dia.
IEC 60815
254 mm Fog type disc
254 mm Normal Disc
y = 174.2x-0.358
70
60
50
40
30
20
10
0
10
100
1000
Pollution, Equivalent Salt Deposit Density, µg/cm 2
Figure 3-35
Cold-Fog and Clean-Fog flashover strength, kV of line-to-ground voltage per meter of leakage
distance, decreases nonlinearly with increasing pollution level [103] [104].
According to the 1986 version of IEC Standard 60815 [105] and multiplying units of ESDD in
mg/cm2 by 1000, the four pollution levels shown in Table 3-9 are suggested for selection of
insulator leakage distance.
Table 3-9
Specific Leakage Distance for Clean-Fog and Cold-Fog Conditions
Pollution Level
Unified Specific Leakage
Distance for 20°C Fog
Unified Specific Leakage
Distance for Cold Fog*
28 mm per kV
19 mm per kV
Level II (Medium) – 30 to 60 mg/cm2
35 mm per kV
24 mm per kV
Level III (Heavy) – 60 to 200 mg/cm
43 mm per kV
38 mm per kV
Level IV (Very Heavy) - > 200 mg/cm2
54 mm per kV
68 mm per kV
Level I (Light) – 2 to 30 mg/cm2
2
* For transmission-line disc insulators.
Generally, the cold-fog requirements for leakage distance on transmission-line insulators are
satisfied by IEC Standard 60815 recommendations, except for very heavy contamination levels
above 300 mg/cm2. The use of extended-leakage (fog-type) disc insulators is often needed to
achieve the required specific leakage distance for EHV transmission lines. For example, with
500-kV system voltage and 25-disc insulators, the Level-III requirement of 11 m gives 440 mm
per disc, while most standard-profile disks offer about 300 mm per disc. This leakage distance
requirement for a single insulator string leaves no margin for system overvoltage or for exposure
of several insulators in parallel.
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Icing Test Results
Under conditions of moderate icing, it is common for icicles to form on insulator strings. These
icicles tend to grow in length, bridging the air gaps between insulator caps or sheds and shorting
out the leakage distance. Figure 3-36 shows typical ice accretion levels on exposed 500-kV
transmission disc insulators and on 230-kV polymer insulators under conditions that led to linevoltage flashovers, at three orientations.
a) Conventional
disc
b) Alternating aerodynamic and
conventional disc
c) Polymer
longrod
d) Angled polymer longrod and line
post
Figure 3-36
Examples of natural ice accretion on various types of transmission line insulator.
The electrical strength of the fully bridged insulator has been studied extensively, notably by
[106] [107] [108] [109] [110]. Detailed modelling of the flashover process can be carried out
using the Obenaus concept [111], as adapted by Rizk [112] for ac flashover. On iced surfaces,
the modelling uses different expressions for the voltage-current relation of the arc and the arc
root voltage, compared to modelling of flashover on polluted surfaces [106] [110]. It is further
complicated by several nonlinear factors, including the sensitivity of ice conductivity to
temperature in the narrow range of –2 to 0°C and the nonlinear voltage distribution for EHV
insulators, compared to HV systems.
One intermediate step in modelling the flashover process for engineering use was suggested in
the CIGRE Task Force paper on Icing Test Methods [113]. An “Icing Stress Product (ISP),”
formed by the product of the ice conductivity and its weight per meter of dry arc distance, is
proposed for evaluating performance (Equation 3-10). This product essentially defines the
resistance of the deposit per unit length used in the Obenaus model.
𝑰𝑰𝑰𝑰𝑰𝑰 = 𝝈𝝈
Where
𝑫𝑫𝑫𝑫𝑫𝑫𝑫𝑫𝑫𝑫𝑫𝑫𝑫𝑫 𝒘𝒘𝒘𝒘𝒘𝒘𝒘𝒘𝒘𝒘𝒘𝒘
Eq. 3-10
𝑫𝑫𝑫𝑫𝑫𝑫 𝒂𝒂𝒂𝒂𝒂𝒂 𝒅𝒅𝒅𝒅𝒅𝒅𝒅𝒅𝒅𝒅𝒅𝒅𝒅𝒅𝒅𝒅
σ = electrical conductivity of ice deposit at 20°C in mS/cm.
Deposit weight = weight of ice deposited on whole insulator string in g.
Dry arc distance = dry arc distance of insulator string in cm.
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The use of melted-water weight in the icing stress product automatically corrects for variations in
ice or snow density. Figure 4.5-3 shows that the relations between electrical strength under
melting conditions and icing stress product is well correlated over a wide range of conditions,
including not just ice but also snow and cold-fog deposits.
Withstand Voltage, kV/m
150
y = 396 x-0.19
100
y = 1303 x-0.26
50
Ice Tests (Farzaneh)
y = 1196x-0.37
Snow Tests (Naito)
Cold Fog (Chisholm)
0
100
1000
10000
100000
1000000
Icing Stress Product: g/cm dry arc times uS/cm
Figure 3-37
Relation between withstand voltage (line to ground) and icing stress product for ice, snow, and
cold fog accretion.
The use of the icing stress product for evaluating dry-arc distance requirements is simple in
experimental tests, using the recommended procedures as described in [109] [110]. This
approach calls for the evaluation of insulator withstand performance using a fixed freezing-rain
water conductivity of 100 mS/cm, corrected to 20°C. Ice accretion is measured, ideally both on
the insulator surface and on a rotating reference cylinder of 25 to 29 mm diameter, similar to
transmission-line conductors. The relationship between ice accretion thickness on the reference
cylinder and ice weight on the insulator is established by the insulator shape and size. Ice tends
to accumulate only on one side of the insulator, and only the top surface of exposed disc
insulators contributes any additional contamination to the native electrical conductivity of
the freezing rainwater. Farzaneh and Kiernicki give the relation between ice accretion on a
25-mm reference cylinder and weight of wet-grown ice on IEEE standard disc insulators [108]
(Equation 3-11):
𝑾𝑾𝑾𝑾𝑾𝑾𝑾𝑾𝑾𝑾𝑾𝑾𝒈𝒈/𝒄𝒄𝒄𝒄 𝒅𝒅𝒅𝒅𝒅𝒅 𝒂𝒂𝒂𝒂𝒂𝒂 = 𝟑𝟑. 𝟐𝟐 ∙ 𝑻𝑻𝑻𝑻𝑻𝑻𝑻𝑻𝑻𝑻𝑻𝑻𝑻𝑻𝑻𝑻𝑻𝑻𝒎𝒎𝒎𝒎
Eq. 3-11
Most tests suggest that the median electrical conductivity of snow, freezing rain, and rain
samples at a particular site are roughly the same. Large day-to-day variations exist in
conductivity, often inversely correlated with daily precipitation amount, because the initial
11762887
3-50
precipitation tends to capture most of the airborne pollution. At critical locations, site selection
should probably rely on multiple measurements of snow conductivity to establish the probable
values of freezing rain, which tends to have fewer opportunities for sampling without melting.
The process of freeze-thaw purification causes important gradients in the electrical conductivity
of the ice deposit. Impurities from the ice itself and from surface pollution tend to migrate away
from the ice caps and into the icicles, and also produce a radial gradient with highly conductive
ice near the insulator surface.
The total icing stress product of an insulator string under natural conditions comprises the sum of
two components:
1. A fixed contribution from the ice-coated area on the pre-contaminated top surface of the
insulator
2. A variable contribution of the precipitation conductivity times the accumulation weight.
For example: The overall icing stress product of a disc insulator string can be evaluated as
follows:
Insulator and ice characteristics:
•
•
•
•
•
•
•
•
Dry arc distance per insulator
Diameter of the insulator disc
Total top surface area
Surface area per insulator in contact with ice
Equivalent Salt Deposit Density
Salt from surface deposit in ice
Ice accumulation thickness on reference cylinder
Median freezing rain conductivity
146 mm
254 mm
647 cm2 per disc
647 cm2/4 = 162 cm2
100 mg/cm2
16,200 mg
20 mm
33 mS/cm
From Equation 3-11 the weight of wet grown ice per unit dry arc distance of the insulator can be
estimated as 64 g/cm.
The contribution of the surface deposit can be calculated by evaluating the electrical conductivity
of the melted ice deposit, corrected to 20°C (Equation 3-12):
𝝈𝝈 = �
Where:
𝑬𝑬𝑬𝑬𝑬𝑬𝑬𝑬∙𝑨𝑨𝑨𝑨𝑨𝑨𝑨𝑨 𝟎𝟎.𝟗𝟗𝟗𝟗𝟗𝟗
𝟎𝟎.𝟒𝟒𝟒𝟒∙𝑽𝑽𝑽𝑽𝑽𝑽𝑽𝑽𝑽𝑽𝑽𝑽
�
Eq. 3-12
ESDD is in mg/cm2.
Area is in cm2.
Volume is in ml.
Conductivity σ is in mS/cm at 20° C.
11762887
3-51
For each insulator, with a deposit weight of 64 g/cm, the ice weight per insulator is 64 g/cm ×
14.6 cm = 934 g, corresponding to a water volume of 934 ml. Using Equaion 3-12 and an ESDD
of 100 μg/cm2, the contribution of ESDD to the conductivity of the ice deposit is calculated as
35.8 μS/cm. The icing stress product of the pre-deposited contamination layer can then be
evaluated from Equation 3-10 and is calculated as 2295 μS/cm x g/cm.
The surface deposit contributes a constant amount to the icing stress product, relatively
independent of the amount of ice. For half the ice thickness, the concentration of the salt is
doubled, giving no significant change in the series resistance of the ice deposit. For an ice
deposit weight of 32 g/cm, the ice weight per insulator is 467 g, corresponding to a volume
467 ml. The electrical conductivity of the ice deposit at 20°C is 70 μS/cm, which translates as an
icing stress product contribution of 2235 μS/cm x g/cm. Likewise, if the ice thickness is tripled
to a deposit weight of 96 g/cm of dry arc distance (for the same insulator cross section), the ice
volume per 146-mm insulator disc is 1402 ml, the conductivity is 24.3 μS/cm, and the icing
stress product is nearly the same at 2329 μS/cm x g/cm.
The contribution from precipitation conductivity to icing stress product is evaluated directly from
Equation 3-10. For an accumulation of 20 mm of ice, with a median freezing rain conductivity
value of 33 mS/cm, the icing stress product on clean insulators would be 64 g/cm x 33 µS/cm, or
2112 μS/cm x g/cm.
The overall icing stress product of the pre-contaminated insulator exposed to the natural
precipitation of 65 g/cm is the sum of the individual contributions, with (2295 + 2112), giving a
total of 4407 μS/cm x g/cm.
Equation 3-13 gives an empirical expression for the electrical strength of the fully bridged iced
insulator, in line-to-ground flashover voltage per meter of dry arc distance, as:
−𝟎𝟎.𝟏𝟏𝟏𝟏
𝑰𝑰𝑰𝑰𝑰𝑰 𝑭𝑭𝑭𝑭𝑭𝑭𝑭𝑭𝑭𝑭𝑭𝑭𝑭𝑭𝑭𝑭𝑭𝑭𝒌𝒌𝒌𝒌𝒍𝒍−𝒈𝒈/𝒎𝒎 𝒅𝒅𝒅𝒅𝒅𝒅 𝒂𝒂𝒂𝒂𝒂𝒂 = 𝟑𝟑𝟑𝟑𝟑𝟑 ∙ 𝑰𝑰𝑰𝑰𝑰𝑰𝒈𝒈/𝒄𝒄𝒄𝒄.𝝁𝝁𝝁𝝁/𝒄𝒄𝒄𝒄
Eq. 3-13
For the moderate accumulation on clean insulators, the ice flashover stress will be 92.5 kV/m,
and a dry arc distance of 3.28 m would be needed to withstand 500 kV ac system voltage using
5% above nominal or 303 kVl-g. For the same accumulation on an insulator with ESDD of
100 μg/cm2, the flashover stress is 80.4 kV/m, and a dry arc distance of 3.77 m (26 standard
units) would be appropriate for a single insulator string.
Snow Test Results
Accumulation of snow on parallel strings of tangent (dead-end) insulator strings is a specific
concern for EHV transmission lines. From Figure 3-37 it can be seen that snow becomes an
electrical concern at an icing stress product of 30,000 g/cm x μS/cm for a typical voltage gradient
of 100 kV/m. This value is valid for a dense snow accumulation (25% water equivalent density)
of more than 50 cm on a pair of horizontal insulator strings spaced at 50 cm, with a typical snow
conductivity of about 30 μS/cm. CIGRE [114] provides a detailed summary of test results for
these special cases.
11762887
3-52
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Maxwell, A. J. and R. Hartings. 2000. “Evaluation of Optimum Composite Insulator
Design using Service Experience and Test Station Data from Various Pollution
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of Aged Nonceramic Insulators in Service.” IEEE Transactions on Power Delivery.
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Insulators in a Wet Atmosphere.” IEEE Transactions on Dielectrics and Electrical
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Massey, J. R. 1972. “Control of Insulator Contamination in Substations.” Journal of the
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4
LONG-TERM PERFORMANCE OF INSULATORS
Introduction
The various components of composite insulators were introduced and explained in Chapter 2 for
each component it covers the constituents, or subcomponents, as well as the manufacturing
processes used. Although the various design concepts available may look the same, there may be
subtle differences which could have a large impact the long-term performance of the insulator.
Important to the long-term performance of insulators is the degradation and failure mechanisms
of insulators. They can be divided into the following categories:
•
•
•
•
•
Manufacturing defects. Manufacturing defects can be any flaw that results from an
improper manufacturing and assembly process, or a lack of quality control [1].
Damage from handling. The insulator may be damaged during installation due to improper
handling, such as improper storage, dropping, or using incorrect hoisting techniques.
Insulators may also be damaged during maintenance due to improper cleaning procedures [2]
[3].
Service-induced damage or deterioration. Service-induced damage may result if the
insulator is not dimensioned correctly for the particular environment in question. This may
result in damaging discharge activity or mechanical overload conditions. Degradation of
correctly dimensioned insulators may also occur due to normal aging as a result of
environmental and electrical stresses [4].
Vandalism. Vandalism is damage inflicted on the insulator by human activity other than that
related to installation or maintenance. Gunshot damage or damage from projectiles are
examples [5] [4]).
Damage caused by animals. Rodents and birds may damage polymer insulator housings
through pecking or gnawing [4].
This section will focus exclusively on service-induced damage and deterioration since this
should be taken account of when dimensioning the insulators.
Ceramic and Glass Suspension Disc Insulators
Overview
Through many years of experience, the behavior of porcelain and toughened glass suspension
insulators under a variety of service conditions is well known and understood. Well-designed
insulators that are manufactured from materials, whose quality has been maintained under strict
control, indeed have performed well, having service lifetimes exceeding 50 years, and often in
extreme conditions requiring little or no maintenance. In some operating environments,
maintenance is required, and the methods are well developed. However, from time-to-time
problems with insulators arise mainly because of changes that have taken place to materials, the
production process, or in quality control, which do not always show up immediately, but are
manifested by failures later in service, that have often been attributed to aging. Understanding of
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the aging mechanisms of the various components as well as maintaining good quality control of
the materials and manufacturing, is of the utmost importance, particularly on the porcelain or
toughened glass dielectric.
Dielectric Shell
Porcelain
The general structure of fired porcelain is quartz or alumina particles embedded in a glassy phase
matrix that forms during firing. As the thermal expansion coefficient between the filler particles
and the glassy phase matrix are very different, microcracks are often seen around the filler
particles (see example in Figure 4-1). Such small cracks and pores within the porcelain body are
considered as flaws, often referred to as Griffith flaws, and the incidence of these flaws is also
dependent on the particle size of the fillers. The concentration of mechanical stress by these
small flaws is a well-recognized mechanism of aging.
Figure 4-1
Scanning Electron Micrograph at 1000X Showing Microcracks Between an Alumina Particle and
the Glassy Phase in a Porcelain Disc Insulator
Microcracks may eventually lead to a fracture of the porcelain. This is a two-stage process:
•
The first stage is the formation of the microcracks, or Griffith flaws. These primarily develop
during manufacturing when the shells are cooled from the firing temperature, due to the
mismatch between thermal expansion coefficients of the filler particles and the glassy phase
matrix. It is thought that these flaws may also form under service conditions because of the
environmental thermal cycles they are exposed to, but then only under extreme temperature
cycles, since porcelain insulators are known to perform well for many years under the normal
temperature range of between -20 to 130°F (-28.9 to 54.4°C). There are, however, no studies
to explicitly show this.
•
The second stage is the propagation of the crack to rupture [6], for which the stress at the tip
of a microcrack must exceed the local ultimate stress for rupture of the porcelain, and when
this occurs, the porcelain body fails.
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The distribution of flaws varies greatly with the distribution of the size of the filler particles. An
important consequence of this is that aging of porcelain is statistical in nature, depending on the
probability that a flaw, capable of initiating fracture at a specific stress, is present. Thus, time and
duration of mechanical load, and temperature, all play a role in the aging of porcelain insulators.
The observed strength of porcelain is also related to the volume of the porcelain under stress,
becoming lower as the volume under stress is increased. The best known theory to explain this
observation was developed by Weibull who assumed that the risk of rupture is proportional to a
function of the stress and the volume of the body under stress [6].
A further observation in the aging of porcelain is that the measured strength depends on the
length of time that a load is applied as well as on the rate at which load is applied. Thus,
porcelain can withstand a given stress for a short period, and lower stresses ultimately lead to
fracture if applied for a sufficiently long period. This phenomenon is referred to as static fatigue.
Toughened Glass
Glass is an amorphous solid of which the molecules are trapped in different levels of disorder
depending on how fast the cooling took place. Good quality glass has therefore a uniform
internal structure with little to no inclusions, which basically eliminate the possibility of Griffith
flaws. Without these internal defects glass do not exhibit a deterioration of the mechanical
strength over time. However, it is not unusual to have a very small number of insulator units
shatter within a short time of installation which is primarily due to the presence of inclusions in
the glass. Such inclusions are more likely due to poor production processes during manufacture
(most common reason) and is also related to the quality of raw materials used and how good the
quality control was during manufacture.
In HVDC applications, the unidirectional field may result in an accumulation of sodium or
potassium ions in the glass increasing the internal mechanical stresses in the insulator [14]. This
can ultimately lead to a failure of the insulator shell. Higher purity raw materials with a lower
level of inclusions and a very high resistivity are used. In addition, should the composition be not
suitable for DC current one runs the risk of rapid dielectric failure by thermal runaway.
Corona Discharge
Corona emanating from the rim of the metal cap, and impinging on the shell, (see example in
Figure 4-2) will after a very long period, give rise to a circumferential crack in the shell of a
porcelain insulator, which eventually results in a full separation of the shell. An example of this
separation failure of the shell is presented in Figure 4-3 and has been referred to as a “donut”
failure because of the resemblance to a donut. This same phenomenon has been observed in glass
insulators but in this case, the glass shell completely disintegrates as the toughened layer is
eroded away.
The problem stems from corona discharge that occurs in the air space between the metal cap and
the shell of the disc and this depends on the voltage on the disc insulator. In addition, the spacing
between the cap and the shell, which is a variable in the assembly of the discs, also plays a role
in the corona onset voltage. The voltage on the disc depends on the voltage of the line, shielding
of the insulator string, configuration of the string and the position of the disc in the string. Most
often, it is the first several units closest to the energized end that are affected. In the glass
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insulator design, this problem has been overcome by gluing graphite fibers or other conductive
material onto the rim of the cap (called flock – see Chapter 2) so that they fill the space between
the shell and the cap thereby electrically shielding the air space to prevent corona discharge from
occurring.
Figure 4-2
Example of corona discharges between the metal cap and the porcelain shell of a disc insulator.
Figure 4-3
Example of a donut failure of a porcelain insulator
To date, this failure mechanism of porcelain insulators has been known to occur in V strings at
735 kV (see example in Figure 4-4) and reported in the literature on 765 kV lines [10], but could
also occur at lower system lines depending on the stress grading of the suspension strings.
Bundled conductors on transmission lines, particularly a four-conductor bundle, offer some
electrostatic shielding of the first two units in a suspension string thereby lowering the electric
stress on these units. However, a higher stress is experienced on the subsequent units,
particularly on the third unit in the string.
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Figure 4-4
On right, an image of corona activity on the first bell of a 765-kV insulator string with no grading
devices installed and on left, corona activity surrounding the pin of a porcelain insulator disc
under dry conditions.
Because of the profile of the insulator and dielectric constant of either porcelain or toughened
glass, this stress is greatest near the pin cement, which may result in corona discharge between
the porcelain and the pin cement (see example in Figure 4-4). Corona discharge, in time, causes
slow but significant erosion of the pin-cavity cement so much so that this erosion can reduce the
pull-out strength of a disc insulator (see Figure 4-5).
Figure 4-5
Example Showing an Extreme Loss of Pin- hole Cement in a Porcelain Suspension Insulator by
Corona Discharge That Was Simulated in the Laboratory to Deter- mine the Loss of Mechanical
and Electrical Strength
Contamination Discharges
In severely contaminated environments surface erosion of the glass may occur when the insulator
is subjected to continual and intense discharge activity. The erosion usually occurs in the high
stress regions around the pin and cap. The high temperatures associated with these types of arcs
etch the glass surface, thereby roughening the surface in the high-stress area. These rough
surface areas collect more contaminants and increase the discharge activity. In severe cases, this
surface erosion may eventually become deep enough to disturb the internal mechanical
toughening stresses to cause the disc to shatter. An example of surface erosion on glass due to
continual dry band arcing is presented in Figure 4-6.
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Figure 4-6
Example of glass disc erosion
In cases where thick contamination layers are present, this may result in the formation of stable
arcs and will accelerate the rate of erosion and in some cases lead to a failure of the glass disk in
a relatively short time. In such cases, the application and design of the insulator will need to be
reviewed.
Dry band arcing may also etch the glaze of porcelain insulators, but to a much lesser extent than
glass insulators so that no long-lasting effects occur.
Steep-Front-Voltage
Lightning surge voltages encountered by insulators on overhead lines vary in rise time from
several hundred to several thousand kilovolts per microsecond. For example, a typical
subsequent stroke current with a rate of rise of 40 kA/µs, discharging into a ground electrode
with a minimum initial transient impedance of 60 Ω will generate a voltage surge with a
steepness of 2400 kV/µs. The situation for shielding failures is even worse as the transient
impedance of the stricken conductor may be between 2 and 4 times larger.
For very steep voltage surges, the formative time for the external flashover of a disc insulator
gives rise to a very high voltage stress across the insulator shell prior to flashing over. This
typically happens at times to flashover below 0.2 µs. In this region the external flashover
develops along the surface of the insulator so that the external flashover voltage becomes more
dependent on leakage distance of the shell, than it is on the dry arc distance of the insulator
(which is the primary factor determining the critical flashover strength, or 50% flashover
voltage, V50, of the insulator) [11]. The external flashover characteristic is shown for a high- and
low-leakage disc insulators in Figure 4-7.
The porcelain itself also has a time dependent puncture characteristic as represented by the
continuous red line in Figure 4-7. For the insulator with the standard leakage distance, the
external flashover strength, for all voltage steepness values, falls well below the puncture
voltage, so a single steep front impulse is unlikely to cause a puncture. For the long leakage
distance unit, however, the two strength curves are much closer together. Thus, puncture is more
likely for voltage steepness values higher than about 4000 kV/µs where the data points of the
two characteristics start overlapping.
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Flashover Voltage [kV]
700
600
Puncture Voltage
500
400
High Leakage
Standard Leakage
300
200
0.05
0.1
0.15
0.2
0.25
Time to Flashover [µs]
Figure 4-7
Steep impulse flashover and puncture characteristic of porcelain disc insulators [11]
Under these conditions a puncture through the head of a porcelain suspension disc can occur,
particularly in the corner of the head in the region where radius of curvature is small, and
therefore subjected to high internal electrical stress. Sometimes puncture will occur in the
sidewall of the porcelain insulator head, which has been attributed to poor application of the sand
band.
Figure 4-8
Examples of an incomplete and completed localized puncture or worm hole
In addition, repeated steep fronted lightning surges can eventually lead to “wear-out” failures.
This is because a steep fronted impulse may result in a partial breakdown of the porcelain. Such
localized punctures of the porcelain resemble electrical trees in solid dielectrics, but they are not
conductive. They are referred to as “worm holes” and example is shown in Figure 4-8.
In general, it is found that first few units of the string are more likely to suffer punctures due to
the non-linear voltage distribution along the string, which results in higher voltages on these
insulators.
The shells of toughened glass insulators will shatter if the design/manufacturing is poor or if
poor quality glass is used.
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Flashover and Power Arc
Porcelain Insulators:
The power arc, following a flashover, may damage insulators. The damage greatly depends on
both the magnitude of the current and the clearing time of the line breakers. Normally, very little
damage occurs when the fault cleared by primary line protection. The extent of the damage may
be as little as some heat ablation of the glaze on a porcelain insulator at the ground end unit of a
string (see Figure 4-9 on left), to breakage of the shell at the line end of the string (see Figure 4-9
on right), corresponding to the location of the arc roots where the greatest heating takes place
Figure 4-9
Example of Glazing Damage Caused by Power Arc
Usually superficial arc damage does not result in a reduction in mechanical strength. However,
the likelihood for more severe damage, such as shed breakage, increases at fault locations close
to a station, where fault current levels are much higher. Considerable damage can be expected if
the primary protection fails, and the fault is cleared by the secondary protection scheme. In this
case, the damage by heating may melt the pin of the line end unit and may cause considerable
damage to the cap of the grounded end unit.
Toughened Glass Insulators:
For glass insulators, the high temperature associated with power arcs when an insulator string
flashes over may damage the surface of the glass shell. During the short duration of the fault (8
power frequency cycles), the topmost surface layer is heated to more than its melting point,
while the bulk of the glass remains at the ambient temperature. After the fault passes, the melted
layer cools, contracts, and it detaches from the glass body because of the contraction when it
cools. An example of this is shown in Figure 4-10.
The duration of the fault current is so short that the toughening of the glass is not significantly
affected, so this condition does not affect the mechanical strength of the insulator unit. However,
it is expected in contaminated conditions that the increased surface roughness will result in an
increase in the contamination accumulation, which will negatively affect the contamination
flashover strength.
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Figure 4-10
Example of the Flaking of the Glass Disk Surface after a Power Arc
Cement
Portland Cement
As Portland cement hydrates, its strength attains 90 % of its ultimate strength in about 30 days
after which it continues to gain strength but only very slowly with time, which may take many
years as hydration only continues when the humidity is above about 90 %. Of the materials used
in insulators, Portland cement probably has the flattest strength characteristic with time.
However, this is not the main concern of aging of Portland cement.
Initially, Portland cement in an insulator shrinks on curing. The shrinkage of neat cement is very
rapid, reaching a maximum within about 100 days, and remains approximately constant
thereafter. This shrinkage manifests itself by drying cracks that are visible in the pin-cavity of
an insulator. However, Portland cements contain several mechanisms that result in a volume
expansion with time. The first of two main expansion mechanisms in Portland cements is the
delayed hydration of periclase (MgO), which is considered to be an impurity in Portland
cements, forming brucite (Mg(OH)2). This hydration proceeds very slowly, and it is often
referred to as a delayed hydration, which may take many years even in optimum moisture
conditions before appreciable expansion occurs.
Figure 4-11
Example of cement cracking as a result of cement expansion caused by the absorption of water
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The second mechanism is the slow reaction of excess gypsum with the tricalcium aluminate
component of Portland cement forming expansive calcium sulph-aluminate phases such as
ettringite [8]. A small percentage of gypsum is ground together with Portland cement clinker to
control the setting properties and optimize the development of strength with cure, but it is the
excess gypsum that causes the expansion.
The cement expansion, or aging, has been problematic in porcelain suspension insulators, as
expansion subjects the porcelain dielectric to a mechanical hoop stress, which ultimately leads to
cracking as shown in Figure 4-11. Mortars, made by adding sand or other filler to Portland
cements, have the effect of reducing both the initial shrinkage and the long-term expansion.
As cement expansion is related to time of wetness, and two observations have been made in the
field [7]:
1. dead-end strings are more likely to experience cement cracking than suspension strings
because the pin-cavity of suspension strings is better protected from rain and hence is wet for
shorter periods of time.
2. an increased incidence of cracked cement is found in more humid regions resulting in longer
times of wetness.
Excessive loss of cement around the pin, Figure 4-12, can lead to a reduction in mechanical
strength over time but such incidences are rare and have not been substantiated in the field.
Figure 4-12
Example showing loss of pin-cavity cement in a porcelain suspension Insulator
Aluminous Cement
This type of cement is an inert material, and it does not react chemically with metals, therefore
corrosive action between the pin and cement cannot occur. In addition, alumina cements are not
known to expand over time so there are no long-term expansion problems.
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Metallic Fittings (Cap and Pin)
Material Aging
Pins are forged from carbon steel, which are heat treated after forging to increase strength and
then galvanized. Aging is not normally considered, as the strength of the forged pins is
considerably greater than the design loads, so fatigue is not an issue.
Caps are cast from malleable iron, trimmed, annealed, and galvanized. Again, the strength of the
caps is considerably greater than the design strength of the insulators. Some types of malleable
compositions are prone to low temperature brittle fracture, so proper specification of the
operating temperature range is necessary for the manufacturer to supply the correct type of
material. There are no problems that are known with the pin at either temperature extremes.
For these reasons, aging of the hardware is generally not a consideration in both porcelain and
toughened glass insulators.
Metallic Fitting Corrosion
In exceptional service environments that are of a chemical or saline nature, and where the
humidity is always very high, for example near to the sea coast in tropical climates, leakage
current develops over strings of discs which is often insufficient to cause flashover but over time,
hardware corrosion by electrolysis occurs. The pin is normally more affected than the insulator
cap because this is where the highest current density and the dry band arcing occurs most
frequently. An example of an extreme case is shown in Figure 4-13. In these service
environments, line drops have occurred due to pin corrosion in both porcelain and toughened
glass suspension insulators. Although possible, no line drops are known to have occurred
because of corrosion of the cap (this is mainly because of the increased mass of the cap as
compared to the pin). This section therefore focuses mostly on pin corrosion.
Figure 4-13
Examples of extreme pin corrosion due to electrolysis
Corrosion by-products surrounding the pin within the cement also increase the hoop stress within
the head of the porcelain shell causing it to crack. Over the years, there have been several
variations in the design of the pin for insulators in these environments. One is a zinc sleeve
attached to the pin, which is a sacrificial part of the pin. Another for porcelain insulators, is a
corrugated metal collar attached to the pin, called a “cookie cutter” shown in Figure 4-14, which
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is designed to crush with increased compression due to the corrosion by-products of a corroding
pin thereby reducing the hoop stress within the head of the disc insulator [9]. Both have aided in
reducing the occurrence of line drops and head cracks.
Figure 4-14
Corrugated Metal Collar around the Pin (Cookie Cutter)
In the same environment, pin corrosion is more severe on the suspension strings than on those
applied in a dead-end configuration. The leakage current activity is normally less frequent on
tension, or dead-end, strings because they are more accessible to natural cleaning.
Aging of the Bituminous Coating
In addition to preventing galvanic action between the galvanized hardware and the alkali in the
Portland cement, the bituminous coating provides lubricity to the surfaces in contact with the
cement thereby distributing the mechanical stresses more uniformly to the porcelain shell.
Without this layer, the tensile strength of both porcelain and toughened glass insulators drops
appreciably, and in some porcelain insulators, reported to be as much as 50 percent [12]. The
loss of lubricity of the coating occurs as the natural petroleum oils are gradually lost and
estimates of the time for this take place vary considerably, from several, to tens of years.
In very hot climates, above 130°F, the hardware coating dries out more rapidly and becomes less
effective as a lubricant, and strength decreases somewhat. Similarly, at low temperatures, below
-20°F (-28.9°C), the hardware coating becomes brittle and is not as effective as a lubricant. A
1963 study showed that porcelain suspension insulators at the low temperature extreme, the
insulator strength has been shown to decrease by about 10 % [12].
Failure Modes of Glass Disc Insulators
Glass insulators may experience infant mortality to some degree—that is, it is not unusual to
have a very small number of insulator units shatter within a short time of installation. Failure
rates of good quality toughened glass insulators is typically in the order of up to 1 to 2 units per
10,000 units per year.
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Electrical Puncture
Glass insulators are highly resistant to electrical puncturing. However, if they do puncture, the
residual tensile stress in the glass, due to the toughening process, will cause the glass shell to
shatter. Therefore, no hidden punctures can exist within a glass insulator [13]. Punctures and
subsequent shattering of the glass shell can be caused by:
•
•
•
Concentrated electrical discharges under thick pollution layers may cause localized heating,
leading to a thermal puncture.
Thermal punctures due to heating caused by dielectric losses in the glass.
Punctures or thermal shock due to lightning or high-energy power frequency power arc
flashover.
Mechanical Failure
Factors other than electrical puncture may also cause the glass shell to break. Internal mechanical
stresses can build up in the glass shell and can lead to its eventual breaking. These stresses
include:
•
•
•
•
•
The presence of inclusions in the glass which becomes more likely due to poor production
process during manufacture (most common reason) related to the raw materials used and
quality control during manufacture.
Lightning or power arcs: sustained periods of high electrical currents flowing across the
surface, caused by back flashovers (lightning) or fault current.
Erosion due to leakage currents (Figure 4-6), or in desert conditions due to “sand blasting,”
may lead to a disturbance of the internal mechanical forces, causing the glass shell to shatter.
Vandalism is also a major contributor to insulator breakages. Gunshot and rocks thrown at
insulator strings are common types of vandalism.
Under dc energization, the migration of ions in sodium-rich glass cause the sodium to
aggregate or deplete under the insulator cap. This may lead to a redistribution of mechanical
forces inside the shell that can eventually shatter it [14].
Hardware corrosion (i.e., corrosion of the metal end fittings) may also lead to deterioration of the
mechanical strength of the insulators (Figure 4-13).
Consequences of Failure
One important feature when a glass disk shatters is that the load-bearing part of the glass disk
between the cap and pin remains intact, resulting, in a loss of less than 35% of its original
minimum failing strength [16]. On high quality insulators the loss of mechanical strength may be
as little as 20%. The string (as a whole) will therefore remain intact and can continue normal
operation [7]. An example of a shattered insulator (called a stub) is shown in Figure 4-15 and as
part of an insulator string in Figure 4-16.
Although the risk of mechanical failure is low, the electrical insulation strength (leakage
distance) will be reduced. The electrical behavior of the stub also remains reliable. Typically, in
the event of extreme electrical stresses, such as flashover, internal arcing is prevented by the
compact trapped particles of glass in the cap (see Figure 4-15 on the right). Instead, the arc
11762887
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occurs externally because of the short distance in air between the lower edge of the metal cap
and nearest point of the metal pin. An example of this is shown in Figure 4-17. Glass insulator
stubs can support about 10 kV.
Depending on the number and locations of the shattered disk or disks, they should be replaced as
soon as is operationally convenient. The influence and number of shattered disks that can be
tolerated is a function of reliable operation and live-line working.
Figure 4-15
Example of Stub Following Shattering of the Glass Shell, and a cut-through view showing the
compact trapped particles of glass in the cap
Figure 4-16
Example of Stub Maintaining Mechanical Load Following Shattering of the Dielectric Shell
11762887
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Figure 4-17
Example of External Arcing of Glass Stub
Failure Modes of Porcelain Disc Insulators
Electrical Puncture
An electrical failure on porcelain disc insulators normally manifests itself as a pinhole through
the porcelain shell between the cap and pin (see Figure 4-18). The causes for puncture are varied,
and may include [13]:
•
•
•
Steep electrical impulse normally caused by lightning.
Thermal runaway because of the heat generated by dielectric losses.
Long-term high electric field stressing.
Figure 4-18
Examples of electrically failed insulator units.
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Mechanical Failure
A porcelain disc may be considered to have mechanically failed when it can no longer hold
mechanical load or when significant damage occurs to the porcelain shell.
Examples of mechanical failures are as follows:
•
•
•
•
•
Radial crack of porcelain shell – Figure 4-19.
Donut crack of porcelain shell – Figure 4-3.
Crack in the porcelain under the metal cap or in the porcelain head.
Mechanical separation of the cap or pin hardware – Figure 4-20.
Mechanical failure of the porcelain shell – Figure 4-21.
These cracks may be formed due to one or a combination of the following:
•
•
•
•
•
•
•
•
Stresses generated by ion movement within the porcelain under dc energization.
Material erosion due to corona activity and/or high E-fields.
Localized stresses induced by corrosion of metallic parts of the insulator.
Mechanical stresses or forces created by the swelling of some of the components in the
cement such as gypsum [13] [15].
Stresses created by unequal thermal expansion and contraction of the various insulator
components (porcelain, metals, glazing, sand band, and bituminous material between the
metal and cement, etc.).
Mechanical overload conditions, such as those occurring during severe conductor icing
conditions.
Cracks and shell breakage caused by an impact and/or vandalism.
Mechanical stresses in the disc that are induced by the electrical puncture of the porcelain.
Figure 4-19
Example of a radial crack.
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Figure 4-20
Example of a mechanical separated pin
Figure 4-21:
Example of a mechanically failed insulator.
Consequences of Failure
Broken or punctured porcelain units do not support their design voltage and are sometimes
referred to as “dead” units. Thus, the electrical strength of the insulator string reduces with an
increase in the number of dead units. Most utilities have therefore general rules-of-thumb for
changing out strings depending on the number of dead units in a string. The change-out rules are
based on the length of the string and whether the number of dead units exceeds the threshold at
which removal of the string using live line work methods is no longer judged safe, or if the tripout rate due to flashover of defective strings exceeds a predetermined level. Mechanically, a
string with dead units usually remain sound for normal day-to-day loads as, by technical
specifications, the residual strength of broken or punctured porcelain insulators is in the range of
75 % of their ultimate strength or higher. This is, however, not always the case. For example, a
bullet from a vandal striking the cap may give rise to a considerably lower mechanical strength,
so much so that there could be a danger of a line drop.
11762887
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Figure 4-22
An example of a burst porcelain disc due to fault current passing through an internal puncture
A more hazardous situation may arise if a fault occurs on a porcelain insulator string containing
dead units. Normally, when there are only a few dead units in the string, the arc is established
outside of the dead units, and the damage is similar to that described above. However, if there are
two or more dead units in series, then the arc may not be established outside the units, but rather
may penetrate the dead unit. In this case, the heat of the arc in the head of a dead unit may cause
porcelain units to burst and cause a line drop. An example of a burst porcelain insulator is
presented in Figure 4-22.
Polymer Insulators
Stresses that result in degradation of polymer insulators may be categorized into the following
broad areas:
•
•
•
Environmental stresses
Mechanical stresses
Electrical stresses
Environmental stresses include temperature cycling, precipitation, solar radiation, and
contamination, while mechanical stresses include static and dynamic loading (e.g., compression
and tension loads, vibration, bending, twisting, and torque loads). If the stresses are applied
within the manufacturer-specified ranges, today’s designs of polymer insulators are designed and
tested to withstand these individual stresses without significant degradation. Hence
environmental and mechanical stresses alone may be considered secondary as regards long-term
degradation. However, some of the above stresses in combination with electrical stresses may
result in significant degradation.
Electrical stresses may result in degradation of polymer insulators either alone or when
combined with environmental stresses, such as precipitation and contamination [17] [18] [19]
[20] [21] [22]. The electrical stresses considered are:
•
•
Electric field distribution along the insulator
Voltage applied across the insulator
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These electrical stresses may result in discharge activity and leakage currents that, in turn, may
degrade the rod, polymer housing material, interfaces, end fittings, and end fitting seals. The
ability of the insulator to withstand these stresses is a function of the insulator design,
manufacturing process, and application. However, polymer insulator designs and manufacturing
processes vary considerably from manufacturer to manufacturer and, hence, so does the ability to
withstand these stresses.
Degrading discharge activity and leakage currents may be classified into distinct categories that
are described in detail in the following sections:
•
•
•
•
•
Discharges internal to the FRP rod and polymer housing material or, at the interface between
the rod and housing
Corona activity from metallic end-fittings or corona rings under dry conditions
Discharges due to nonuniform wetting of the polymer rubber material
Dry band arcing under contaminated conditions
Damage due to external power arcs
Eventually these stresses may precipitate the failure of the insulator, which is when it can no
longer fulfill either of its principal roles:
•
•
Unable to insulate under power frequency conditions.
Unable to hold everyday mechanical load.
The inability of an insulator to withstand transient overvoltages or temporary mechanical
overloads within rating may also be considered a failure. However, in most cases, it is almost
impossible to know the magnitude of these events for in-service units.
Mechanical failure modes include:
•
•
•
Brittle fracture (stress corrosion cracking of fiberglass rod)
Destruction of rod by discharge activity
Mechanical failure due to end fitting pullout or rod fracture due to overload.
Electrical failure modes include:
•
•
Flashunder (tracking along or through the fiberglass rod and the resulting flashover)
Flashover due to contamination
Failure due to the environmental stresses include:
•
•
Corrosion of the end fittings
Hydrolysis of the housing or core materials
These are further discussed for each component of the insulator in the sections that follow.
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The Core
An analysis of the failures captured in the EPRI database has shown that 95% of insulator
failures (see Figure 4-23) can be ascribed to one of four failure modes of the insulator core.
These are:
•
•
•
•
Brittle Fracture
Flashunder
Mechanical Failure, i.e., end fitting pullout or rod breakage, because of a mechanical
overload, such as under torsion, bending or compression forces
Destruction of Rod by Discharge Activity
120
All Others
Lapp
Number of Failures
100
80
51
60
26
40
58
20
29
5
2
18
16
1
4
4
Mechanical
Failure
Rod
Destroyed by
Discharge
Activity
Unknown
Flashover
0
Brittle Fracture
Flashunder
Failure Mode
Figure 4-23
Occurrence of different failure modes on actual in-service composite insulators as captured in the
EPRI failure database. Note Lapp refers to one particular insulator make which is no longer
marketed.
The first two failure modes are a result of a relatively slow degradation process caused by
discharges in or along the core. These discharges could occur when the core is exposed to the
environment because of a functional failure of either the rubber housing or the end fitting seal.
Internal discharges in voids, cracks or inclusions may also arise when a critical E-field
magnitude is exceeded. This may result in discharge activity in and around defects in the core—
such as voids, inclusions, or poor bonding between the rod and rubber sheath [23].
This discharge activity may result tracking along or through the fiberglass rod, or a local
destruction of the core material. Tracking is the formation of conductive (carbon based) paths
due to the breakdown of the core material when exposed to discharge activity. Eventually the
tracking may grow axially along the length of the insulator, resulting in a larger conductive
defect increasing discharge activity. An example tracking along the interface between the
fiberglass rod and rubber sheath is shown in Figure 4-24.
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Figure 4-24
Tracking along the housing—core interface of a composite insulator.
Destruction of Rod by Discharge Activity
Destruction of the rod by discharge activity is a mechanical failure mode. Internal defects or
moisture or contaminant ingress may result in internal discharge activity. If the rod becomes
carbonized, a larger conductive defect is formed. These discharges degrade the rod until the unit
is unable to hold the applied mechanical load and the rod separates. Figure 4-25 shows images of
a rod damaged by discharge activity.
Figure 4-25
Unit that failed due to destruction of the rod by discharge activity.
Flashunder
Flashunder, which is initiated by tracking along or through the core, is an electrical failure mode
that results in flashover. This failure mode occurs when internal discharge activity results in
carbonization within or on the surface of the fiberglass rod. Internal discharge activity may occur
due to moisture ingress or internal defects—e.g., voids, poor bonding, or conductive defects.
Internal tracking grows in or on the rod until a critical distance along the insulator is reached and
the applied voltage can no longer be withstood and a flashunder occurs.
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Features of a flashunder include:
•
•
Tracking through the rod or along the rod/rubber interface.
Puncture holes and splits along the length of insulator due to internal discharge activity and a
power arc during failure.
Figure 4-26 shows images of a flashunder and the associated features.
Tracking through rod or along
rod/rubber interface
Splits and puncture holes
Two halves of a dissected composite insulator that has
failed due to a flashunder.
External photograph of the live end of an insulator that
has failed due to a flashunder.
Figure 4-26
A flashunder and associated features.
In a number of cases, after a flashunder occurred, and the line was re-energized, the insulator has
been able to provide insulation adequate to prevent an immediate outage. This is due to the
resulting power arc drying out the insulator and improving the insulation ability of the unit.
However, with time or renewed wetting, the unit may precipitate further outages, leading to
further damage that eventually results in complete electrical or mechanical failure.
Brittle Fracture
A brittle fracture, also known as a Stress Corrosion Cracking of Fiberglass Rod, is a mechanical
failure of the fiberglass rod—i.e., a complete separation of fiberglass rod, as shown in
Figure 4-27 [24] [25] [26] [27].
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Broomstick
Axial
delamination
Planar Fracture
Planes
Figure 4-27
Brittle fracture. Note the several separate flat transverse fracture planes and the “broomstick.”
Features of a brittle fracture are:
•
•
•
One or more smooth, clean planar surfaces, mainly perpendicular to the axis of the fiberglass
rod giving the appearance of the rod being cut.
Several planar fracture planes separated by axial delaminations.
Residual mechanical fracture surfaces—i.e., broomstick.
Brittle fractures are caused by chemical attack of the RBGF rod when non-siliceous ions are
leached from the fibers, and the surrounding thermoset resin matrix is hydrolyzed. This chemical
attack, together with the mechanical load, results in transverse cracking. The cracking will
progress until the remaining cross section of the rod can no longer support the applied load, and
total separation occurs. Brittle fracture is more accurately defined as stress corrosion cracking.
Research indicates that brittle fracture occurs due to the presence of acids in proximity of the
rod. There are several competing theories on how these acids are formed [28] [29] [30]. The
authors of this document do not have any opinion on which of the models is correct or whether
these models have merit in explaining this phenomenon.
For this document the theories will be divided into two main categories:
1. Acid, which may have been generated somewhere else, comes in contact with the rod. In this
case the acid may have been generated under internal or external discharge activity or may
have come from acid rain or other chemical reactions.
2. The acid forms in inside the insulator when moisture comes into contact with the rod and
reacts with chemical residue in or on the surface of the rod, to form an acid. It is proposed
that the water reacts with remnants of hardener left over from the core manufacturing
processes to form the acid.
In both theories the key ingredient necessary for brittle fracture is the exposure of the rod to acid,
which reduces its mechanical strength. Most researchers agree therefore that the possibility to
reduce or at best, eliminate the possibility for brittle fractures is to prevent the rod from coming
into contact with the environment, or by using cores made from corrosion resistant glass fibers.
11762887
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Based on the second theory, it may be possible to specify a rod composition that will not form
acids when water comes into contact with it. In this regard two different approaches have been
proposed:
1. Design and test the rod to ensure that moisture in contact with the rod does not result in a
significant reduction of pH. Such a test is under discussion in CIGRÉ for inclusion in a
forthcoming document.
2. Another researcher indicates that acid formation by chemical residue can only occur on
epoxy resin rods and hence avoiding these may prevent such failures. This researcher has
also suggested, based on his experience that it is unlikely that this failure mode is the
predominant reason for brittle fracture.
Another way of approaching the problem is to apply mechanically over dimensioned insulators
to reduce the risk for brittle fracture, i.e., with thicker cores. The thinking is that the use of a
thicker core will reduce its mechanical stress to a level below the threshold needed for brittle
fracture. Actually, this criterion is already fulfilled in many practical configurations, such as
suspension and jumper configurations where the insulator subjected to a mechanical loading well
below its capability. The need to specify units with a higher than necessary SML is more
appropriate on dead-end units, which are subjected to much higher mechanical forces than
suspension units.
Mechanical Failure Due to End Fitting Pullout or Mechanical Failure of the Rod
These are mechanical failure modes where either the insulator mechanically fails when the rod
separates from the end fitting or the rod itself mechanically fails. These failures may occur due to
mishandling, errors in the manufacturing process, and/or degradation—e.g., overheating of the
fiberglass rod during manufacturing, or decomposition of the epoxy in an epoxy-cone-type end
fitting, etc. Figure 4-28 shows an example of a fiberglass rod that failed mechanically in-service.
The reason for failure was traced back to a manufacturing defect.
Figure 4-28
Mechanically failed rod due to manufacturing defect.
Figure 4-29 shows an example of a unit that has failed due to the rod pulling out of the end
fitting due to decomposition of the epoxy cone.
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Dissected end fitting of failed unit.
Rod from failed unit.
Figure 4-29
Unit that has failed due to decomposition of the epoxy cone.
The End Fittings
The end fitting itself may degrade or fail because of:
•
•
•
Mechanical overload of the end fitting may result in either end fitting pullout or fracture of
the fitting itself. Mechanical overload is not more of a concern with composite insulator than
for glass or porcelain insulators since the materials involved in its manufacturing are the
same. Mechanical failure only occurs if the mechanical loading of the insulator was
underestimated during design time or if the strength of the fitting was compromised because
of a production error. These production errors are normally identified by the routine
mechanical test.
Corrosion of the end fitting may result when the galvanization is damaged by sustained
corona activity on the end fittings. An example of this type of degradation is shown in Figure
4-30. Damage to the galvanization and its associated corrosion does not directly impact the
mechanical strength of the end fitting, but it may degrade the end fitting seal if the corrosion
occurs at the triple point where metal fitting, housing material and air meet. A degraded end
fitting seal may eventually result in exposure of the core and the risk of damage to the core
itself—as is described in the section dealing with aging of the core.
Power arc damage may result in the end fitting to slip off the core, or it may compromise
the end fitting seal initiating a failure of the rod. Power arc damage may result in a short- and
long-term reduction of mechanical strength. The short-term loss of strength is caused by the
thermal expansion of the end fitting during the power arc, and the long-term loss of strength
is due to the relaxation of the residual crimping pressure in the end fitting. The short-term
loss of mechanical strength due to power arcs may range between 20% and 40% of the
ultimate strength of the insulator and the long-term reduction in strength may range between
10 and 20% of the ultimate strength. Since composite insulators are generally loaded to less
than 50% of their SML, the reduction in mechanical strength is not a major concern. A bigger
concern is, however, the damage to the seal and end fitting caused by a power arc terminating
on the end fitting. In severe cases the core could be exposed resulting in the long run in a
failure of the core as described in the previous section. Figure 4-31 shows examples of units
removed from service with damaged end fittings due to power arcs [4].
IEC 61467 describes standardized tests to determine the ability of complete insulator
assemblies to withstand power arcs. The tests specify how the power arc tests should be
performed, together with visual and mechanical criteria by which the insulators are assessed
after the test. It should, however, be noted that none of the three composite insulator
standards contain tests to verify the power arc performance of the insulator itself.
11762887
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Figure 4-30
An example of moderate end fitting corrosion.
Figure 4-31
Examples of damage to end fittings due to power arcs.
The end fitting design and performance may impact the performance of other components of the
composite insulator. An important aspect is how the shape of the end fitting grades the E-field
in the region of the end fitting seal and the nearby rubber sheath and shed sections which are
often the area with the highest E-field. Some end fitting designs aim to move the point of the
highest electrical field away from the end fitting seal and nearby rubber sheath as is illustrated in
Figure 4-32, Insulator A, C and D. At higher voltage levels the E-field grading of the end fitting
on its own is not enough, which makes the application of additional grading rings necessary.
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Insulator A
Insulator B
Insulator C
Insulator D
Figure 4-32
Examples E-field calculations performed for various end fitting designs (EPRI). Blue corresponds
to the lowest E-field magnitude and Red to the highest. The corona threshold corresponds
approximately to orange.
E-field design of
the end fittinjg
External
Discharges
Degradation
End fitting
Corrosion
End fitting seal
Internal
Discharges
Audible/Radio
Noise
Housing
Destruction of Rod by
Discharges
Flashunder
Customer
Complaints
Rod Exposure
Figure 4-33
A schematic representation of how the E-field design of the end fitting may impact the
performance of other insulator components.
11762887
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Insufficient grading of the E-field around the end fitting may give rise to external or internal
electrical discharges. In Figure 4-33 a schematic representation is shown which illustrates the
consequences of a poor E-field design around the end fitting. As shown in the figure, external
discharges could lead to:
•
•
•
Degradation of the end fitting itself – The discharges may cause damage to the galvanization
leading in the long run to corrosion of the end fitting.
Damage to the end fitting seal – The end fitting seal may puncture if exposed to a high
electric field. This aspect is discussed more in the section dealing with aging of the end
fitting seal.
Damage to the housing – It has been shown that regions of the insulator housing which is
exposed have a high likelihood of losing its hydrophobicity during prolonged wet periods.
This is further discussed in the section dealing with aging of the housing.
Ultimately these damages may grow in severity over time, eventually leading to core exposure.
Continuous external discharges may also be severe enough to give rise to complaints from
people living close to the line because of audible or radio noise.
A poor end fitting design may also cause internal discharges in the housing core interface. The
damage caused by these discharges may grow along the core and ultimately cause either
flashunder or destruction of the rod by discharges. These failure modes are discussed in section
dealing with the core.
In Chapter 2, the importance of the attachment method to the overall mechanical performance of
the whole insulator is described. The attachment method should not lead to a stress concentration
in the core, nor should the crimping pressure be too high or low. If the pressure is too low, the
end fitting will not grip the core properly increasing the risk for end fitting to slip off below the
insulator SML, and a crimping pressure which is too high (i.e., so called over crimping) may
cause axial cracks in the rod, resulting in internal discharges that in the long run may cause the
rod to fail.
The End Fitting Seals
Every manufacturer has its own end fitting seal design. Service experience has shown that each
design has its own vulnerability, so it is difficult to generalize. In general, the end fitting seal
may suffer:
•
•
•
Electrical damage
Mechanical damage
Chemical deterioration, e.g., loss of bonding
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Electrical Damage:
The region around the end fitting has potentially the highest E-field of the insulator. As such is
also the area with potentially the highest level of electrical discharge activity. If this activity is in
direct contact with the end fitting seal it may cause erosion, which may compromise it. An
example of this type of erosion is shown in Figure 4-34 (a). A compromised end fitting seal may
lead to moisture ingress to the core increasing the risk for brittle fracture, destruction of the core
by discharges or flashunder as is described in the section dealing with the core.
During wet conditions, the presence of water on the insulator surface may disturb the E-field
distribution around the end fitting considerably. This leads in many cases, to a high field gradient
at, or across, the end fitting seal—especially if the housing material encapsulates the end fitting.
Under these conditions there is a risk for puncture through the sealant if the material thickness is
not sufficient to withstand this E-field gradient. An example of such a puncture is shown in
Figure 4-34 (b).
The end fitting is, in many cases, the termination point for the power arc if the insulator flashes
over. Damage to the end fitting seal may result if the end fitting is not designed to handle such
power arcs. An example of such damage is shown in Figure 4-31.
Mechanical Damage:
Damage to the end fitting sealing material may also be the result of the mechanical forces that it
may be subjected to. Improper handling practices may place forces on the end fitting seal for
which it was not designed. End fitting seals are especially prone to damage if subjected to
torsional loads during installation. Examples of damage cause by mishandling are presented in
Figure 4-34 (c) and (d).
Internal stresses in the housing material and the different coefficients of expansion of the
different materials in contact with each other in the end fitting seal may also stress the materials
used in the end fitting seal. This may lead to tearing of the end fitting seal material.
Chemical Degradation:
Another possible mode for damage to the end fitting seal is due to de-boning of the sealant to the
end fitting. De-bonding may be the result when the sealing material and insulator housing is
exposed to nitric acid, which is generated when there are corona discharges on a wet insulator
surface.
A compromised seal may allow the seepage of water into the seal that may lead to further
de-bonding. Corrosion of the end fitting may accelerate the process. Figure 4-34 (e), (f) and (g)
shows examples of de-bonding of the end fitting seal.
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a) Electrical erosion
b) Puncture
c) Handling damage
d) Handling damage
e) De-bonding
f) De-bonding and corrosion of the end fitting
g) power arc damage
Figure 4-34
Examples of deterioration and damage to the end fitting seal.
The Housing
Housing materials used in modern transmission line composite insulator generally withstand well
the normal environmental stresses that it is subjected to. There are a host of material tests
available to verify the materials suitability in terms of its environmental, electrical, mechanical
11762887
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and physical properties. However, most of these tests are single stress tests and service
experience has shown that the combination of stresses that the material may be subjected to may
still lead to deterioration or damage. The most important aging agents are:
•
•
•
•
Corona Activity from Metallic End-fittings or Grading rings under Dry Conditions
Discharges due to non-uniform Wetting of the Polymer Rubber Material
Dry Band Arcing under Contaminated Conditions
Damage due to External Power Arcs
Corona Activity from Metallic End-Fittings or Grading Rings Under Dry Conditions
Service experiences has shown that continual discharge activity from the insulator end fittings
under dry conditions may result in insulator failures and severe degradation of the housing
material. This may happen on EHV systems (i.e., 275 kV-800 kV) on units where corona rings
were inadvertently not installed or on HV systems (115 -230 kV) systems where corona rings
were previously not always considered mandatory. Examples of corona from the end fitting on
500 kV and 115 kV insulators without corona rings are shown in Figure 4-35.
Continual corona activity, and its byproducts, may result in the severe degradation (in the form
of cracking or erosion) of the housing material and it compromise the end fitting seal– as is
shown in Figure 4-36. Once the hermetic seal of the core offered by the housing and end fitting
seal is compromised, moisture can come into contact with the fiberglass rod. This may result in
the long run in a brittle fracture. Brittle Fracture is a mechanical failure of the fiberglass rod due
to acid attack where the fracture exhibit one or more smooth, clean planar surfaces, mainly
perpendicular to the axis of the fiberglass rod, giving the appearance of the rod being cut.
Image of corona activity from the metallic end fitting of a
500-kV insulator installed without a grading ring.
A DayCor image of dry corona activity
from an insulator end fitting at 115 kV
Figure 4-35
Corona activity from energized end fittings.
It is possible to prolong the life expectancy of polymer insulators by applying proper E-field
grading (e.g., by the application of corona rings).
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Erosions on the rubber housing material
because of corona activity.
Example of an insulator at 115 kV that suffered severe
material degradation and brittle fracture because of
continual dry corona activity
Figure 4-36
Material degradation caused by continual dry corona activity from energized end fittings.
Discharges due to Non-uniform Wetting of the Polymer Rubber Material
Discharge activity may occur on the surface of composite insulators due to the presence of
moisture. Moisture may be in the form of discrete droplets or water patches, depending on the
surface properties of the rubber and the type of wetting. This type of discharge activity is the
result of the E-field enhancement caused by the water (due to its high dielectric constant) and
hence is not dependent on contamination being present—i.e., it occurs under low contamination,
or even clean, conditions [31] [32] [33] [34]. The discharge activity takes on different forms on
hydrophobic and hydrophilic insulators.
14
Air
εr = 1
10
E-field (kV/mm)
Water
Drop
12
ε r = 80
8
Cylindrical
Insulator Rod
εr = 4
6
4
Sheath
εr = 4
(a) Equipotential lines surrounding a water drop on
the surface of a composite insulator in an E-field.
Water Drop ε r = 80
2
A
0
0
0.5
1
B
1.5
2
2.5
3
3.5
Distance from drop center (mm)
4
4.5
5
(b) Graph showing the increase in the E-field
magnitude surrounding a water drop.
Figure 4-37
Results of finite elements modeling, showing enhancement of the E-field surrounding a water
drop on the surface of a composite insulator [31].
On hydrophobic surfaces, such as silicone rubber, water drops and patches on the rubber surface
enhance the E-field due to the high permittivity of water (εr = 80). If the E-field (E-field) is
enhanced above a critical value, corona activity will result from the edge of the water. Figure
4-37 shows how a water drop enhances an E-field.
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Figure 4-38, shows examples of corona activity induced by the presence of water. Note how the
corona is located at the tip of the drop where the E-field enhancement is the strongest. These
corona discharges and the resulting byproducts may, in turn, degrade the polymer material.
(a). Corona activity from a single water drop.
(b). Wetting corona activity at the live end of a
composite insulator.
Figure 4-38
Image intensifier image showing corona activity wetting activity [31].
The unperturbed E-field magnitude (that is, the E-field under clean and dry conditions) necessary
to initiate corona activity from water drops is primarily a function of drop size and
hydrophobicity. Corona inception occurs at a lower E-field for larger water drops and lower
hydrophobicity levels. Furthermore, the onset of water drop corona on the sheath and shed
occurs at different E-field magnitudes due to the orientation of the E-field. Single drop
experiments have shown that drops on the sheath have an onset field of greater than 4 kV/cm,
depending on the hydrophobicity, while drops on the shed surfaces require an E-field of
8.5 kV/cm.
Aging chamber
Insulator removed from service
Figure 4-39
Photos illustrating localized loss of hydrophobicity in the aging chamber and on an insulator
removed from service.
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EPRI research has verified the occurrence of water drop corona under both artificial testing and
normal service conditions. As shown in Figure 4-39 it is found that this corona activity may
result in a localized loss of hydrophobicity on silicone rubber insulators, especially in the high
field regions [31] [32] [2] [1] [35] [36]. This loss of hydrophobicity can be attributed to either the
chemical by-products formed by combination of corona and moisture [37] or a thermal increase
due to the localized ionization.
Research indicates that it is unlikely that water drop corona alone will result in significant
degradation of the polymer housing, as the temperature increases due to this type of corona is
minimal [38] [39]. There is however significant evidence to suggest that the chemical byproducts of the corona, together with moisture, may result in significant material degradation. In
this respect the formation of Nitric acid is considered important. It was found that the pH on the
surface of the insulator drop from an initial value of about 7 to 3.4 after 15 minutes of corona
activity on a wet insulator surface [37]. Furthermore, it was found that some silicone rubber
formulations may be particularly vulnerable to deterioration when exposed to Nitric Acid [40]
[41].
Recent findings have indicated that water drop corona may just be the initial phase of the
following, more severe, degradation mechanism that affects the long-term performance of the
insulator:
1. Water drop corona in the high E-field regions results in localized loss of hydrophobicity.
Regions affected have E-field magnitudes above the water drop corona onset threshold.
2. Under wetting conditions, patches of water form in the regions of lower hydrophobicity.
These surface water patches are separated from each other by dry regions or bands.
3. Localized arcs form, bridging the gaps between the water patches [35].
4. The energy and temperature of these localized arcs are significantly higher than that of water
drop corona, stressing the rubber housing surface further [42].
5. Over time, as the affected regions lose hydrophobicity, and completely wet out, the E-field in
the adjacent regions is enhanced above the water drop corona onset threshold under wetting
conditions.
6. The aging mechanism is then initiated in the previously unaffected regions. In this manner,
the region affected is increased.
7. The by-products formed by corona in combination with water, notably nitric acid, may by
aggressive to the housing resulting in cracks in the material.
The activity described above is initially localized to the high E-field region of the insulator—i.e.,
the energized or grounded ends. The rest of the insulator remains hydrophobic and in good
condition, hence no significant increase in the leakage currents measured at the grounded end
will be measured. Observations from the EPRI accelerated aging tests have indicated that, after
30 years of simulated aging, the loss of hydrophobicity can encompass as much as one-quarter of
the insulator length [35] [36]. Figure 4-40 shows an example of arcing activity observed in the
high E-field region of a silicone rubber insulator.
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Ultraviolet image
Infrared image
Figure 4-40
Localized arcing activity observed on a 230-kV silicone rubber insulator. The observed activity
was correlated with localized loss of hydrophobicity in the high field region. Apart from the region
showing activity, the rest of the insulator had a high level of hydrophobicity, and no leakage
currents were measured at the grounded end.
During wetting conditions on hydrophilic insulators (such as EPDM), the rubber surface of
hydrophilic composite insulators is covered with distinct droplets and patches of water. Dry
regions separate these patches, and due to E-field enhancement, sparking may occur between
patches. These discharges may degrade the rubber material. Figure 4-41 shows an example of
this arcing activity.
Ultraviolet image
Infrared image
Figure 4-41
Infrared and ultraviolet images of dry-band arcing activity on a composite insulator [35].
Although this activity may also occur away from the high E-field region, casual observation in
aging tests indicates that it is more prevalent in the high E-field regions.
Dry Band Arcing Under Contaminated Conditions
Contaminated insulators may have surface leakage currents and dry band arcing on the polymer
housing surfaces. For most types of contaminants, these phenomena occur only under wetting
conditions due to the increased conductivity of the contamination layer.
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The dry band arcing on long composite insulators is usually concentrated around the end fittings
of the insulator, resulting in increased degradation in these areas. This discharge activity may
result in degradation of the rubber housing as well as the end fitting seal. This degradation may
include erosion, tracking, and localized loss of hydrophobicity. Loss of hydrophobicity is a
concern with silicone rubber insulators only. Severe examples of erosion and tracking are
presented in Figure 4-42.
Severe erosion
Tracking on a composite insulator
(Courtesy of Eskom)
Figure 4-42
Examples of erosion (left) and tracking (right) along mold lines.
Damage due to External Power Arcs
The localized heating generated during power arcs may damage the insulator housing (see
example in Figure 4-43). In most cases, the damage caused to the end fitting and the end fitting
seal is more severe. Thus, the damage to the housing can be regarded as secondary.
Figure 4-43
Example of superficial power arc damage on a polymer insulator
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The Housing – Core Interface
The bonding between the housing and the core may be broken or damaged because of:
•
•
•
Mechanical forces or impacts applied to the insulator housing due to mishandling or
misapplication.
Electrical discharges because of moisture ingress or other internal faults in the insulator.
Chemical deterioration of the bond because of the use of inappropriate materials or poorquality control during manufacturing.
Degradation and failure of the housing core interface may give rise to electrical discharges along
the core, and ultimately may lead to a flashunder. These degradation types are discussed in the
section dealing with aging of the core.
Summary of Failures
Occurrence of Failures
In 1997, EPRI started a database recording failures of transmission polymer insulators in the
field. Information and images, where possible, were obtained on each individual failure and
stored in an electronic database, which may be queried at a later date. Information on failures as
far back at the 1970s was obtained. The database continues to track failures on an ongoing basis,
and the data presented in the following section was current as of December 2017 [44].
Information is obtained from the participant utilities using a questionnaire containing a range of
standard questions. Often the utility is unable to answer all of the questions in the questionnaire.
This is typically the case when utilities provide information on failures that did not occur
recently.
For purposes of the database, a failure is defined as either of two conditions:
•
•
Electrical: The insulator was unable to electrically insulate the energized conductor and
hardware from the grounded structure. This may occur internally or externally along the
surface of the polymer insulator.
Mechanical: The insulator loses its ability to hold its everyday mechanical load and,
consequently, the mechanical load that it is holding is released.
Precluded from this failure database are three types of failures:
•
•
•
Flashover due to external contamination—e.g., due to marine pollution.
Failure due to extreme mishandling—e.g., the unit is broken during installation.
Failure due to extreme mechanical loads—e.g., icing or hurricanes.
Although the database contains a comprehensive number of failures in North America, no
attempt was made to collect information on a significant number of failures internationally due to
the logistics involved. As of December 2021, EPRI has collected 430 failures from 75 different
utilities. Of these, 63 are North American utilities. Of the 430 failures, 385 occurred in North
America. Figure 4-44 shows the distribution of the failures between the different failure modes
[44]. The failures from one overrepresented insulator model, which is no longer manufactured, is
shown separately.
11762887
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An analysis of the data captured in the database has shown that 40% of failures occur within ten
years of installation (see Figure 4-45). This may be attributed to the weeding out of defective
units or minor damage during installation. Although the number of units installed has increased
over the years, the number of failures has not, indicating improved manufacturing techniques and
materials have resolved early issues.
Figure 4-44
Failure mode distribution from EPRI failure database [44].
11762887
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Figure 4-45
Age of failures (the age of failure for 97 failures could not be determined). Note: Installation year is
used rather than year of manufacture, as that data is more readily available [44].
A review of the IEEE Task Force Report: Brittle Fracture in Nonceramic Insulators [24],
indicates that an additional 46 international brittle fracture failures are not included in the EPRI
failure database. The Task Force report only reported brittle fracture failures, and hence the total
number of failures worldwide may be larger. The total number of recorded failures worldwide,
therefore, exceeds 460.
Further, the failure database has by no means captured all failures that have occurred. In reality,
it is the authors’ opinion that a large percentage have not been captured in the EPRI failure
database. EPRI is continuing to obtain failure information to increase the accuracy of the
database and results.
Failure Rates
Of the 188 failures reported in North America up to 2003, 89 related to the manufacturers that
provided information to EPRI on the number of units sold. Based on this information, the
average failure rate for all the manufacturers that provided sales information was 1 in every
45,000 units sold. Apart from one manufacturer for which there are no recorded failures, the
individual manufacturer failure rates varied from 1 in every 65,000 to 1 in every 31,000 units
sold (EPRI 2003b).
Utilizing the average failure rate data indicated above may be misleading, as 100 of the failures
recorded in the database were from manufacturers that did not provide data or are no longer
selling product and hence did not provide sales information.
11762887
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Phillips, A. J., A. J. Maxwell, C. S. Engelbrecht, and I. Gutman. 2015. “Electric-Field
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Insulators for Transmission Lines: A Review of Standards and the Latest Research
Results and Service Experience. EPRI, Palo Alto, CA: 1015920.
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EPRI 2008b. Application of Corona Rings on 115/138 kV Polymer Transmission Line
Insulators. EPRI, Palo Alto, CA: 1015917.
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Maxwell, A. J. and R. Hartings. 2000. “Evaluation of Optimum Composite Insulator
Design using Service Experience and Test Station Data from Various Pollution
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Cherney, E. A. 1991. “Partial Discharge, Part V: PD in Polymer Type Line Insulators.”
IEEE Electrical Insulation Magazine. March/April. Vol. 7. No. 2.
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Shaffner, J. Yu, and J. Varner. 2002. “IEEE Task Force Report: Brittle Fracture in
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Chandler, H., R. Jones, and J. Reynders. 1983. “Stress Corrosion Failure of Composite
Long Rod Insulators.” Paper No. 23.09. Presented at the Fourth International Symposium
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Voltage Electric Systems (CIGRÉ). August.
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Montesinos, J., R. S. Gorur, B. Mobasher, and D. Kingsbury. 2003. “Mechanism of
Brittle Fracture in Nonceramic Insulators.” IEEE Transactions on Dielectrics and
Electrical Insulation. Volume 9. Issue 2. April. Pp. 236–243.
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Kumosa, M., L. Kumosa, and D. Armentrout. 2004. “Can Water Cause Brittle Fracture
Failures of Composite Non-ceramic Insulators in the Absence of Electric Fields?” IEEE
Transactions on Dielectrics and Electrical Insulation. Volume 11. Issue 3. June.
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de Tourreil, C., L. Pargamin, G. Thevenet, and S. Prat. 2000. “Brittle Fracture of
Composite Insulators: Why and How They Occur.” Power Engineering Society Summer
Meeting. IEEE. Volume 4. 16-20 July. Pp. 2569–2574.
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Phillips A. J., D. J. Childs, and H. M. Schneider. 1999a. “Ageing of Non-Ceramic
Insulators due to Corona from Water Drops.” IEEE Transactions on Power Delivery.
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[32]
Phillips, A. J., D. J. Childs, and H. M. Schneider. 1999b. “Water-Drop Corona Effects on
Full-Scale 500 kV Non-Ceramic Insulators.” IEEE Transactions on Power Delivery.
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[33]
Lopez, I., S. H. Jayaram, and E. A. Cherney. 2001. “A Study of Partial Discharges from
Water Droplets on a Silicone Rubber Insulating Surface.” IEEE Transactions on
Dielectrics and Electrical Insulation. Vol. 8. No. 2. April. p. 262.
[34]
Lopez, I., S. H. Jayaram, and E. A. Cherney. 2001. “A Study of Partial Discharges from
Water Droplets on a Silicone Rubber Insulating Surface.” IEEE Transactions on
Dielectrics and Electrical Insulation. Vol. 8. No. 2. April. p. 262.
[35]
EPRI. 2003a. 230 kV Accelerated Aging Chamber: Condition of NCI After 2 Years of
Aging. EPRI, Palo Alto, CA: 1001746.
[36]
EPRI. 2004a. 230 kV Accelerated Aging Chamber: Condition of NCI After 3 Years of
Aging. EPRI, Palo Alto, CA: 1008737.
[37]
Goldman A., M. Goldman, R. Sigmond, and T. Sigmond. 1989. “Analysis of Air Corona
Products by Means of Their Reactions in Water.” Proceedings of 9th International
Symposium on Plasma Chemistry. Pugnochiuso, Italy. Pp. 1654–1658.
[38]
Moreno, V. M. and R. S. Gorur. 2001. “Effect of Long-term Corona on Non-ceramic
Outdoor Insulator Housing Materials.” IEEE Transactions on Dielectrics and Electrical
Insulation. Volume 8. Issue 1. February. Pp. 117–128.
[39]
Moreno, V. M. and R. S. Gorur. 2003. Impact of Corona on the Long-term Performance
of Nonceramic Insulators.” IEEE Transactions on Dielectrics and Electrical Insulation.
Volume 10. Issue 1. February.
[40]
Tanaka, K, “Acid Immersion Test on Silicone Rubber for Polymer Insulators” Discussion
Cigre Study committee D1 question 2.15, Paris session 2008.
[41]
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Aging of Silicone Rubber Housing for Polymer Insulators”, 2008 International
Symposium on Electrical Insulating Materials (ISEIM) on 7th-11th Sept., 2008.
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Rubber.” Proceedings: World Conference & Exhibition on Insulators, Arresters &
Bushings. Pp. 285–296. Marbella, Spain.
[43]
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[44]
EPRI. 2017a. Overhead Transmission Line Component Failure and Performance
Summary Report. EPRI, Palo Alto, CA: 2017. 3002010095.
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11762887
5
ELECTRICAL DESIGN AND SELECTION OF
INSULATORS
Design Methodology
Insulation coordination is the methodology that is used to design the transmission line insulation
and select insulators to achieve an acceptable outage performance. An overview of the insulation
coordination process is given in Figure 5-1. The individual tasks shown in the figure are
described in the following subsections.
Figure 5-1
Overview of the steps making up the insulation coordination methodology.
Define Acceptable Performance
The starting point of the insulation coordination process is to define an acceptable performance.
This step should be taken with due consideration of the cost involved in achieving the required
performance, and of other constraints that may be imposed on the insulation design such as
regulatory requirements from OSHA (Occupational Safety and Health Administration) and
NESC (The National Electrical Safety Code) [1] [2]. Usually, the limitation in improving the line
performance is cost rather than the technical feasibility. For example, the cost of increasing the
line insulation length is not only the extra costs for the longer insulators, but also the
consequential costs associated with the taller support structures and larger foundations that will
be needed to accommodate the extra mechanical loading resulting from these longer insulators.
These latter costs may overshadow the additional cost of the longer insulators. Thus, a proper
balance must be struck between the required performance and the costs associated with
achieving it.
When considering the performance of a line, a distinction should be made between factors
that could cause outages, and aspects that could affect the rate of success for re-energizing the
line (via auto-reclose, or ARC) after a fault has been cleared. This is shown schematically in
Figure 5-2.
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Figure 5-2
Overview of the aspects that need to be considered when defining the required line performance.
Line outages are usually expressed in faults per 100 miles (or kilometer) per year. They are
commonly caused by environmental stresses such as: lightning, contamination, ice, snow, and
rain. Other causes of faults include bird interaction, vegetation, or fires. The total required outage
rate should, therefore, be divided between these causes of faults. The required line performance
(in terms of the outage rate) is defined by considering the impact of a fault on the surrounding
system. The severity of an outage is related to:
•
•
•
•
•
Voltage dips due to the fault (that is, the number and importance of the customers affected).
Interruptions and possible system instability due to loss of the line.
Reduction in the operational security due to loss of the line.
Time required to bring the line back into service.
Direct consequences of a line outage (e.g., faults close to important [nuclear] power stations
that could result in loss of offsite power (LOOP) to power safety systems, which are to be
avoided).
The outage rate of the line will vary from year to year because of variations in the environmental
stresses. It is, therefore, also important to consider whether the line insulation design is based on
a maximum allowable outage rate, or on an average failure rate. This decision is made based on
the consequences of an outage. In the case of overhead lines, the insulation is self-restoring,
therefore the outages are generally of transient nature, which means that the line can in most
cases be auto reclosed. Thus, it is sufficient to consider the average outage rate as the basis for
the line insulation design. In the case of non-self-restoring insulation (such as cable insulation),
the dimensioning of the insulation is done based on a maximum allowable outage rate, because
the consequences of a fault are more severe—i.e., the circuit cannot be re-energized before the
fault is fixed.
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The success rate of line re-energization is calculated by considering the switching overvoltages
during fast auto-reclosing (ARC). This condition usually results in the highest switching
transient overvoltages on overhead lines. The performance of the line in terms of switching is
normally expressed as the number of outages (i.e., unsuccessful ARCs) per 100 switching
operations, or a switching surge flashover rate (SSFOR) of 0.01.
In North America and many parts of the world, lightning remains the primary cause of outages
on overhead lines. Although approaches to specify the required lightning outage rate vary, a
typical target is about 1 flashover per 100 miles of line length per year (or 0.6 flashovers/
100 km/year). In some cases, the lightning outage rate is combined with the switching
performance of the line to express the storm outage rate (SOR). This rate is calculated by
multiplying the lightning outage rate by the rate of switching surge flashovers per reclose.
Hileman [3] extends the “logic” of using the SOR to practical terms in determining performance
criteria for the line insulation. In areas with low-lightning activity, the switching surge flashover
rate (SSFOR) may be selected as high as 0.1, since the probabilities of lightning flashovers are
low. Similarly, in the areas of high lightning activity, the SSFOR may need to be selected very
low (i.e., 0.001) for reliable line operation. (The lightning flashover rate [LFOR] is essentially
the backflashover rate [BFR] for effectively shielded lines.)
The insulation distances required for lightning and switching overvoltages are usually also
adequate to cover the power frequency outages of the line. It is, therefore, quite common, on
modern line designs, not to specify a specific performance requirement for power frequency
voltages—that is, unless the line crosses an area with significant levels of insulator
contamination. Other causes of power frequency outages, such as those listed in Figure 5-2 are
difficult to assess, and it is, therefore, not possible to derive a performance indicator. In the case
of contamination, a design methodology is now available, as described in later in this chapter,
which makes it possible to design the insulators to a specific outage rate. It remains, however,
difficult to obtain sufficient details on the site severity to enable such detailed methods. A further
complication is that it is often difficult to reclose lines during a contamination event, due to the
cold switch-on phenomenon (see Chapter 3) resulting in a sustained outage. This may be
compensated for in the design process by incorporating conservative assumptions or safety
factors in the design.
Power frequency overvoltages, or temporary overvoltages, are generally not considered when
designing the line insulation, because the required insulation is generally less than that required
for an acceptable lightning or switching performance. However, it is still important that they be
assessed because they are important to consider in terms of the equipment installed at the line
terminals in the substations. This equipment may include surge arresters, line shunt reactors, etc.
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Characterization of Stresses
The performance of the electrical insulation is related to both the magnitude and duration of the
stress to which it is exposed. Since the breakdown, or flashover, process is different for different
types of stress, it is customary to classify and consider each stress separately when doing the
insulation design. For transmission lines, both environmental and electrical stresses are considered.
The electrical stresses that are considered are:
•
•
•
Lightning
System transients due to switching
Temporary power frequency overvoltages
Environmental stresses that need to be considered are:
•
•
•
•
•
•
•
Altitude of the area where the line is located
Rain
Contamination of the line insulator surfaces
Ice or snow accretion on the insulators
Birds, or other animal, interactions with the line
Vegetation under or close to the line that may result in under clearance or contact.
Fires close to or under the line
Recently, an emphasis has been placed on the response of the power system to a potential highaltitude electromagnetic pulse (HEMP) resulting from a nuclear explosion. It is generally
considered that transmission line insulation (i.e., with system voltages of 100 kV and above) will
not flash over because of transients coupled on to the transmission line from the resulting
transient electric fields.
For transmission lines, the primary insulation is made up of air gaps and insulators. For this
relatively simple insulation system, it is sufficient to quantify the electrical stress in terms of the
total voltage applied across the insulation for each type of stress. This is in contrast to more
complex insulation systems, such as are found inside power transformers, where other factors,
such as the steepness of the applied overvoltage, temperature, and mechanical forces, may also
influence the performance of the insulation system. With these more complex insulation systems,
a simple relationship may not exist between the voltage applied to the terminals and the voltage
stress in the insulation. For example, the voltage appearing across individual turns inside a
transformer may not be of the same shape or polarity as the surge voltage applied to its terminals.
The standards [4] [5] formalize an approach for categorizing overvoltages. Table 5-1 presents an
overview of these categories and associated stresses on transmission lines. With these categories,
voltage stresses in the network are classified according to the duration of low-frequency
voltages, or the shape of transient overvoltages. For each category, a representative test is
defined. These tests are used to determine, or to verify, the insulation strength.
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Table 5-1
Overview of the Standardized Approach of Classifying Voltage stresses on Transmission Lines
(after IEC 60071 1, [4])
Class
Low Frequency
Continuous
Transient
Temporary
Slow-Front
Fast-Front
Voltage Shape
Very-Fast
Front
Not
applicable to
transmission
lines
Time Domain
f = 50 Hz or
60 Hz
10 Hz < f <
500 Hz
20 µs ≤ TP ≤
5000 µs
0.1 µs ≤ TP ≤
20 µs
Condition
Normal System
Operations
Abnormal
System
Conditions
System
Operation
Lightning
Origin of
Stresses
Environmental
Contamination:
Ice and Snow
System Faults
Reactive Power
Balance
Resonances
Line
Energization
Reactor
Switching
Fault Initiation
and Clearing
Shielding
Failure
Backflashover
Induced
Lightning
Overvoltages
Standard Test
-Voltage
Shape
TP ≤ 0.1 µs
Not present
on -overhead
lines
No standard
test method
defined
Test
parameters
f = 50 Hz or
60 Hz
48 Hz < f <
62 Hz
Duration 60 s
TP = 250 μs
T2 = 2500 μs
T1 = 1.2 μs
T2 = 50 μs
Standard test
Contamination
Test, Long
Duration Power
Frequency Test
Short Duration
Power
Frequency Test
Switching
Impulse Test
Lightning
Impulse Test
Environmental
-Condition
Dry and Wet
(-Contamination)
Dry and Wet
Air Gap (Dry) Insulators (Wet)
Dry
Note: Wet tests are performed under simulated rain conditions.
An integral part of the line insulation design is to gather information on the environmental and
voltage stresses to which the insulation will be subjected. The environmental stresses are usually
determined through severity assessments, which, for example, in the case of lightning, may be
determined by consulting maps of lightning ground flash density, or for contamination, it may be
to measure the amount of contamination accumulated on the insulators. The information about
the voltage stresses in the network may be obtained either by measuring the overvoltages
associated with real network events or by simulating power system events on network models.
With the widespread availability of electromagnetic transient simulation programs and other
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simulation software, most utilities now rely mostly on digital simulation of network events to
quantify the stresses in the network. The expected magnitude of temporary overvoltages may
also be determined by analytical means, as described in many engineering texts.
The variation of the occurring stresses on the line insulation over time can adequately be
described by statistical distribution functions. For environmental stresses and switching
overvoltages, the variation of the stresses on the insulation is described in terms of a probability
density function, which is characterized in terms of the “statistical stress severity” (which is the
stress level that has a 2% probability of being exceeded) and a standard deviation. For lightning,
a slightly different approach is followed. The probability that the minimum stress necessary for
flashover is exceeded is calculated from lightning current statistics and the lightning ground flash
density.
Select Insulation Strength
The insulation strength is expressed in terms of a withstand voltage, which is the highest voltage
that the insulation can withstand with an acceptably low probability for flashover. For selfrestoring insulation, as is the case for transmission lines, the withstand voltage is defined in
terms of the voltage stress that has a 10% probability for flashover.
The flashover strength of the line insulation depends strongly on the wave shape of the applied
voltage, and it is also influenced by the overall insulation configuration and the closeness of
grounded objects. Therefore, the quantification of insulation strength is preferably done through
dielectric testing. Such testing should be done:
•
•
With applied voltage wave shapes that are representative of service conditions. Due to the
wide range of wave shapes that may occur on transmission lines, it is considered impractical
to test insulation for all naturally occurring stresses. Rather, a standardized approach is
followed, whereby the strength of the insulation is determined for a limited number of
standard wave shapes that are representative of each of the voltage categories defined in
Table 5-1, which lists both the representative wave shapes and the standardized tests.
On representative insulation configurations, because the insulation configuration and
surrounding grounded structures also have an impact on the withstand voltage. In practice,
this means that standardized withstand tests performed on insulators only (that are often
provided in product catalogues) cannot be directly used without adjustment to estimate the
insulation withstand strength of the line insulation.
Alternatively, the line insulation withstand strength may be estimated through calculation. Such
calculations are usually based on empirical equations such as those presented by CIGRE [6].
The insulation design for the transmission line is based on the flashover strength of the line
insulation under rain conditions. Tests on transmission line insulation configurations are,
however, often done, for practical reasons, under dry conditions. Suitable correction factors
should, therefore, be applied to obtain the flashover strength under wet conditions. Correction
factors used for adjusting the switching impulse strength of the line insulators vary for different
insulation configurations, but values between 0.95 and 0.96 are typically used [7]. It is assumed
that the lightning impulse flashover strength of the line insulation is not affected by rain [8].
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The insulation withstand voltages obtained through testing and calculation usually refer to
standard atmospheric conditions (i.e., standard temperature, air pressure, and humidity), which
relate to the insulation strength at sea level. For lines at altitude, suitable adjustments must be
made to take into account that the insulation will have a lower strength because of the reduced
air density (at altitude).
In the above text, the insulation strength is characterized simply by the withstand voltage. A
more complete description would be to describe the probability of flashover as a function of the
applied stress. This description is made with a cumulative distribution function, which is
characterized by two parameters, usually the critical flashover voltage (or V50, which is the
voltage at which the insulation has a 50% flashover probability) and the standard deviation. For
dimensioning purposes, the withstand voltage and standard deviation may also be used.
Evaluate Line Performance
In this step of the insulation coordination process, the expected line outage rate is calculated by
determining how often the environmental and voltage stresses will exceed the withstand strength
of the insulation. As can be expected, also here the calculations are done separately for each of
the voltage stress categories defined in Table 5-1, and by considering all relevant origins of the
insulation stresses, as listed in the table. Briefly the items listed can be described as follows:
•
•
Lightning: The overall lightning line outage rate comprises three components:
- Shielding failures, which are lightning strikes that bypass the shielding system,
terminating directly onto the phase conductors.
- Backflashovers, which are caused by lightning strikes to the shielding system of the
transmission line, but which cause such a high-voltage build-up on the transmission line
grounding system that a flashover occurs from the grounded metal parts to the phase
conductors.
- Induced lightning outages are caused by nearby lightning strikes (i.e., not hitting the line
directly) but which are close enough to induce large enough voltages on the phase
conductors to cause a flashover. Induced lightning outages usually do not occur on
transmission lines, because the typical basic line insulation levels on these lines of 350 kV
and above exceed the maximum induced overvoltages, which rarely exceed 250 to 300 kV.
Continuous low frequency voltage: As explained later in this chapter, the performance of
the line under the continuously applied power frequency voltage is governed by the response
of the insulation to the environmental stresses. The primary stresses in this regard are:
- Contamination flashovers: Over time, the insulator surface may become contaminated
with salt deposits originating from the sea, road de-icing or industry. Under wet
conditions, this contamination may form a conducting layer on the insulator surface,
resulting in dry band arcing and, possibly, flashover.
- Ice and snow: Under thaw conditions, insulators may be subject to ice or snow covering,
with high conductivity water runoff. Also, this could result in partial discharges, which
further melts the ice covering and could eventually result in flashover.
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5-7
-
•
•
•
Rain: Under heavy rain conditions, the streaming of water from insulator sheds may
bridge the gaps between shed tips, resulting in a lower flashover strength. However, in
practice, outages due to heavy rain occur mainly on substation insulation with larger
diameters and rarely on line insulation [9].
Power frequency outages may result from several other causes, which are traditionally not
taken into account in the design of the insulation. However, these causes may be considered
when selecting overall line configurations, minimum clearance distances, or line routing.
- Bird-related outages: These outages are caused by bird interactions with lines, which can
include “bird streamers,” which are bird feces that may bridge air gaps or contaminate
line insulators, bird electrocutions, or nesting material encroaching on air gaps. Utilities
have approached this problem by incorporating features in the line design to discourage
birds from perching in the high-risk regions of the structure. For some new designs, this
is in the form of steel bird diverters, which are incorporated as part of the initial tower
design. On existing lines with bird-related outages, the bird diverters are typically made
of plastic.
- Vegetation: Vegetation growth or fall-ins of vegetation, branches, or trees may cause
under-clearance conditions and possibly flashovers. Remedial measures may include
increasing the height of the conductor or adopting vegetation species management on the
right-of-way.
- Fires: The ionized cases and smoke contamination may significantly reduce the dielectric
strength of the air insulation of the line. On new lines that are known to be in high fire
risk zones, utilities have adopted higher conductor heights to get the insulation out of the
ionization and debris zones.
Switching: Switching transients are considered to ensure that the line can successfully be
energized, or re-energized, after a fault. The following conditions are generally considered:
- Energization: The line is energized with no voltage on the phase conductors prior to the
breakers closing.
- Three-phase reclosing (if applicable): The line is energized with at least two of the three
phases charged to the maximum line voltage prior to the circuit breaker closing. The
highest overvoltages occur if the voltage on the source side of the breaker has the
opposite polarity from the voltage to which the line is charged.
- Single-phase reclosing (if applicable): In this case, only one of the phases is energized,
while the other two phases are already energized. This condition is relevant to systems
with single-phase reclosing.
Other switching events that may be considered include:
- Induced switching transients. Switching transients on a higher voltage circuit of a multicircuit line could induce overvoltages on lower voltage circuit(s) installed on the same
structure.
- Switching of reactive circuits such as capacitor banks or inductive reactors
- Fault initiation and fault clearing
- Circuit breaker restrike
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The fundamental dimensioning method is illustrated in Figure 5-3, showing how the strength of
the insulation is selected with respect to the stress to achieve a required risk for failure. For this
purpose, a coordination factor is applied. The coordination factor is essentially the ratio of the
strength to the stress (i.e., the withstand voltage divided by the statistical stress severity). In
simple terms, the required minimum withstand strength of the insulation is obtained by
multiplying the stress parameter (i.e., the statistical stress severity) by the coordination factor.
Two basic types of methods can be used for determining a suitable coordination factor: statistical
and deterministic methods.
Statistical method:
1. Studies or measurements are done to determine the probability density function describing
the expected stresses to which the insulation will be subjected.
2. Tests results or historical data are used to establish the insulation flashover probability curve.
3. Risk of flashover calculations are made for different insulation strengths until one is found
that corresponds to the desired performance. During this process overvoltage control
measures to lower the stress level may also be considered.
With the deterministic method, the determined statistical stress severity is multiplied by a
predetermined coordination factor to obtain the minimum required withstand voltage. The
coordination factor typically varies between 1 and 1.1, to cover for uncertainties in the
determination of the stress and strength parameters.
1
0.9
0.9
0.8
0.8
0.7
0.7
0.6
0.6
0.5
Stress F(S)
0.5
Strength P(S)
0.4
0.4
Risk of flashover
0.3
0.3
0.2
0.2
0.1
0
0.1
F(S)*P(S)
1
1.5
2
2.5
Strength: Probability for flashover
Stress: Density of occurence
1
3
3.5
4
0
Switching Overvoltage Level [p.u.]
Figure 5-3
Evaluation of risk for flashover using a statistical design process.
Apply Stress Mitigation or Strength Enhancement
To reach the set performance criterion, one or more of the following measures may be applied to
limit or control the overvoltage stresses over the insulation or to enhance the insulation strength
under critical conditions.
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Measures to control or limit lightning overvoltages include:
•
•
•
Installation and placement of ground wires
Ground electrodes of appropriate resistance/-impedance at each transmission line structure
Installation of transmission line surge arresters
Measures to control or limit switching overvoltages include:
•
•
•
•
Application of surge arresters at line ends or along the line
Utilizing circuit breakers with closing resistors
Controlled switching
Application of shunt reactors on the line or other devices to drain trapped charge
Alternatively, the insulation performance can also be improved to cope with the envisaged
stresses. In most cases, this improvement is the selection of higher insulation levels, meaning
longer insulator strings and larger clearances. To deal with contamination stresses, the flashover
performance of the line can also be improved by selecting insulators with a suitable shed profile
or surface properties. In addition, the performance of existing insulators can be enhanced with
the application of hydrophobic or anti-fouling coatings.
In certain cases, specific insulator configurations may have to be chosen to limit conductor
movement in order to realize a compact design.
Finalization of Design
In Figure 5-1, the feedback loop indicates that the design process may comprise a number of
iterations until a satisfactory solution is found. During this process, the expected performance of
the line may need to be optimized against the cost of various options, while taking account of
any constraints that may affect the choices made.
A part of this step is also to evaluate the insulation design in terms of any national standards or
regulations that may be applicable. For example, in the United States, the National Electric
Safety Code prescribes minimum clearances for transmission lines to ensure the safety of
employees and the public. In addition, certain requirements may be specified by independent
system operators and national regulators (e.g., NERC which specifies minimum vegetation
clearance distances [10]). When applicable, insulation clearances need to also account for live
work to ensure that minimum approach distances (MAD), which are specified by OSHA, are not
compromised during maintenance activities, energized or un-energized.
Verification of Characteristics
The last step in the insulation coordination process is the verification of the characteristics of the
chosen insulation solution. This is achieved by the specifying dielectric design tests (i.e., type
test in IEC terminology) for the line insulation. On newly designed structures, full-scale
dielectric tests on the structure itself, or a mockup thereof, may need to be conducted.
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Selection and Dimensioning Insulators
The following characteristics need to be considered when selecting and dimensioning insulators
for overhead lines:
•
•
•
•
Dry power frequency flashover voltage
Lightning impulse flashover strength (or BIL)
Switching impulse flashover strength
Contamination withstand severity
In terms of insulator dimensioning, the first three aspects are usually of secondary importance
and will therefore only be discussed briefly. The last aspect, contamination, is the most important
and be discussed in greater detail.
Dry Power Frequency Flashover Voltage
The first step in the selection of the electrical characteristics is determine the minimum required
insulator length to fulfill the required dry flashover voltage for the system voltage as per rule 273
of NESC C2 [1]. As an example, for a nominal system voltage of 161 kV, the dry flashover of
the string is specified as 445 kV. This represents the minimum insulation level as required by the
NESC, which may be higher depending on the required string length for acceptable lightning
performance and for contamination performance of the string. However, the effect of altitude
must be considered.
Basic Impulse Insulation Level
Lightning flashover of line insulation is the first consideration after the dry flashover and
normally this pertains to systems that are below 345 kV as switching surges are the prominent
factor above 345 kV. The lightning impulse strength (or the basic insulation level, BIL), which
represents the 1.2 x 50 μS full impulse flashover voltage of the line insulation, is selected to
achieve the required lightning performance. Over the years, these levels have been standardized
for the standard system voltages, but these standardized values do not always guarantee
acceptable lightning performance.
The lightning impulse strength of the line insulation is generally determined by the shortest strike
distance (or internal clearance) of the line insulation, and in many cases, this corresponds to the
insulator dry arc distance. So, the specified BIL often determines the insulator dry arc distance.
As an example, for a nominal system voltage of 230 kV, the standard string length of standard
suspension insulators is the equivalent of 14 discs, giving a BIL of 1275 kV positive and 1265
negative. It is however important to note that for the same axial length, polymer insulators will
have a shorter dry arc distance, and therefore a lower BIL than a suspension disc insulator string.
Thus, a direct replacement of a suspension disc insulators with polymer may result in a
deterioration of the lightning outage performance.
On wood structures insulator length can be reduced to take advantage of the additional insulation
of the wood. On the other hand, in regions of high keraunic level or high grounding resistance
the insulator length needs to be increased. Contamination and wet conditions do not influence the
BIL of a string.
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Switching Surge
On lines with nominal voltage of 345 kV and higher, the line insulation level is selected to
withstand switching surges. Switching surge levels are computed based on line length,
transformers, capacitor banks, and breaker operation, with or without resistor pre-insertion, and
the point of breaker opening on the wave, so the system needs to be evaluated by performing a
transient network analysis of the line. As an example, a 2.0 per unit design of a nominal 500 kV
line produces switching surges of 820 kV, so this switching surge level must be used to evaluate
the line flashover performance with string length.
The switching impulse strength of the line insulation is determined by the overall insulation and
tower head configuration, and not necessarily by the shortest strike distance. Laboratory tests
show that flashover often occurs across one of the air gaps even if it is longer than the insulator
dry arc distance. Thus, the strength of the line insulation often not determined by the insulator
characteristics.
One factor that must be considered though, is that the switching impulse flashover of an insulator
assembly is reduced under wet conditions by between 4% and 5% [7]. The reduced level must be
used in the strength evaluation and for selecting the required insulator length.
Contamination
In some situations where the contamination is severe, the leakage distance requirement becomes
the dominant design factor of an insulator string. As for switching and lightning, the selection
and dimensioning of insulators with respect to contamination and ice conditions involve the
selection of the insulation strength relative to the stresses that it will be subjected to during its
service life to obtain an acceptable performance. For both contamination and ice conditions, it is
sufficient to assume that the insulator will be stressed by a constant voltage. In this case, it is the
environment that presents itself as a statistical variable(s).
Simplifying Multi-Stress Problems
In many cases, the environmental stresses can be sufficiently characterized with a single stress
parameter. The installation is then designed to withstand a single contingency—adverse weather
stresses. Examples of this design philosophy for overhead lines include:
•
•
•
Use of towers with adequate strength to withstand the static weight of accumulated ice.
Use of overhead groundwires and grounding electrodes to protect against 95-99% of
overvoltages resulting from direct lightning flashes.
Use of insulators with adequate wet flashover performance under normal ac operating
voltage for rain rates of 1–2 mm per min (both horizontal and vertical) with a rain resistivity
of 100 Ω-m.
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In other cases, a single-contingency approach is not sufficient since some composite adverse
weather stresses are common enough that they should be included in transmission-line design
analysis. Examples of two-contingency stresses include:
•
•
•
•
Use of adequate parallel capacity (limited-time thermal rating) to carry summer peak load
after loss of a double-circuit line from a severe lightning flash.
Use of towers with adequate strength to withstand the static force of wind pressure on
accumulated ice on conductors and overhead groundwires.
Use of adequate clearance or galloping control devices (torsional dampers or inter-phase
spacers) to limit the coupling of high-speed steady wind energy into lightly iced conductors.
Use of adequate insulator dimensions to withstand the line voltage stress when insulator
surfaces are coated (over a long time of exposure) with electrically conductive pollution, then
wetted by fog.
Industry experience has shown that combinations of two or three moderate contingencies at the
same time can be more damaging than single, extreme events. A good example is the series of
three sequential ice storms that occurred in North America from January 4 to 9, 1998, leading to
1300 toppled towers in Quebec, Ontario and the northeast United States, and more than two
million customers without power. No single storm was extreme, but the combined accumulation
of ice onto previously iced conductors added more than 80 mm of radial ice and 1000 kg to each
transmission span in some locations.
As a two-contingency design is significantly more complex to perform, assumptions are often
made to simplify the problem to allow a single-contingency analysis. This approach will be
explained by considering the design of insulation with respect to contamination.
When considering contamination on insulators, three statistical variables need to be considered:
1. Applied voltage
2. Level of contaminants and their distribution on the insulator surface
3. Degree of wetting
A worst-case design would dictate that insulation needs to be designed to withstand the:
1. Highest temporary overvoltage that may occur in the network
2. Highest level of contaminants that are distributed evenly over the insulator surface
3. Critical (or worst) wetting conditions that occur
By doing this, it is implicitly assumed that all three variables reach their maximum level at the
same time. While often overly pessimistic, this assumption makes it very simple to specify a
design requirement for the insulators.
A fully statistical design will consider the density functions of the applied voltage, the pollution
level and its distribution, and the intensity of the wetting to obtain a distribution of the total stress
on the insulator. This approach demands a lot of input information, since enough data should be
available to characterize the probability density function of each stress parameter.
11762887
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A middle-of-the-road approach would be to simplify to a single-contingency stress by identifying
which variables are correlated. One simplification is to assume that critical wetting occurs at the
peak level of the pollution deposit. In many cases, this is a reasonable assumption, since after a
critical wetting event, the contamination level is less due to the leaching of contaminants from
the insulator surface. Another assumption that could be made is to say that no correlation exists
between the level of temporary overvoltage (TOV) in the network and the occurrence of a
critical wetting event when the insulator has its highest probability for flashover, which means
that the design can be based on the maximum continuous operating voltage. By making these
assumptions, the multiple contingencies are reduced to a single-contingency problem that can be
solved relatively easily.
Approach
Another aspect that should be considered when designing insulators is whether to design for an
average or maximum failure rate. This is decided by the consequences of a failure. If the
consequences of a failure are severe—for example, in the case of non-self-restoring insulation—
then the statistical variables are quantified so that the maximum possible failure rate is evaluated.
For self-restoring insulation, it is generally sufficient to consider average failure rates, since
these types of faults are of transient nature, and a line can be auto-reclosed.
Contamination flashovers lie somewhere between the self-restoring and non-self-restoring cases,
since restoring the line in service is often difficult after this type of outage. This difficulty
manifests either as unsuccessful reclose operations or as subsequent flashovers shortly after a
successful re-closing. However, after a relatively short period of time, the line can be
successfully energized due to drying out of the contamination layer. To account for this when
designing for contamination, conservative assumptions are made while evaluating average
outage rates.
The basic steps necessary to select and dimension insulators are:
1. Characterize the environment in terms of both the type of contamination and its severity.
2. Select the insulator characteristics that would be best suited to this environment—that is, the
type of insulating material and the insulator profile.
3. Determine the required insulator length or leakage.
These steps will each be explained in the sections as indicated above.
Characterizing the Environment and its Severity
Introduction
In designing transmission system insulation for contamination, it is essential to know the degree
of contamination over the area where the power transmission system is to be constructed. Several
methods to assess the site severity have been described in the literature [11] [12]. These methods
range from very simple, such as directional dust deposit gauges, to complex, such as automated
surface conductivity measurements [13]. Also, not all methods are equally suited to assess the
severity of a site, depending on the type of pollution present. Whereas the measurement of the
Equivalent Salt Deposit Density is preferred at sites with solid, or pre-deposited, contamination,
11762887
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it may underestimate pollution levels at sites with liquid (or instantaneous) contamination. A first
step in a site assessment should, therefore, be to determine the predominant type of
contamination. Thereafter, the site assessment technique best suited to the circumstances can be
selected.
Initial Informal Assessment
It is usually easy to identify parts of the overhead network that may be subject to contamination
flashovers. Usually there may be enough circumstantial evidence available that indicate
sufficiently high contamination levels to cause flashovers. Examples of such information include
(see also Figure 5-4):
•
•
•
•
•
In most cases there is a clearly identifiable source of contamination close to the substation or
line. Substations, or lines, at risk are usually located within 15 miles from the coast, or within
2 miles from industrial plants or mining activity, or adjacent to roads that are salted during
winter. Table 5-2 provides some example descriptions of typical environments and their
associated contamination severities that can be used in this regard.
Premature aging of insulators due to leakage current activity can be used as an indicator of
elevated contamination severity levels. On disc insulators this is normally evident from
corrosion of the pin or cap of these insulators. Glass insulators may also lose its shine and
become dull because dry-band arcing may etch the glass surface. Polymer insulators may
show erosion and even tracking of the housing material.
High audible noise levels during wet periods and if it is dark, clear scintillation activity can
be seen on insulators. These (partial) discharges might not necessarily lead to a flashover in
the short term, but it does give an indication of the presence of contamination, which could
eventually lead to a flashover under more unfavorable conditions.
The insulators look dirty, although this is not always a reliable indication of a problem. For
example, a visually dirty insulator may be contaminated mainly by inert contamination may
not present a real threat in terms of flashover while, on the other hand, insulators
contaminated with highly conductive contaminants like marine salt may not look dirty at all.
There is evidence that the insulators have been maintained before. For example, the
insulators are covered with old, whitened layers of grease.
A study of past outage events may also provide useful information that could be used to identify
contamination as the probable cause. The following indicators may signal contamination
flashovers:
•
•
•
•
The flashovers occurred during wet conditions such as fog, mist or rain.
Insulation flashovers occurred during the early morning hours when condensation is most
likely. One should however be aware that bird streamer flashovers are also concentrated in
the early morning hours when birds relieve themselves before taking off.
The time when the flashovers occurred were preceded by an extended dry period where no
significant precipitation has occurred to naturally wash the insulators
The flashovers cannot be attributed to other causes such as lightning, fires etc.
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Close to source
Corrosion
Discharges
“Dirty” insulators
Old silicone grease
Figure 5-4
Typical evidence of contamination related problems
Formal Assessment
If insulator contamination is identified as a necessary consideration for dimensioning, the next
step would be to initiate a program to perform a more detailed assessment of the site
contamination severity. In general, three reasons for such a detailed assessment can be identified:
1. Contamination site severity measurement: The results from the site severity measurements
can used to classify the site according to a set of predetermined severity levels. Table 5-2
lists the five site severity categories defined by the IEC [14].
Site severity measurements quantifies the environmental stress for dimensioning the
insulators. It can also be used as a measure that can be used in laboratory tests to determine
the flashover strength of insulators.
Site severity measurements provide information that can be used to better understand the
environment and the conditions which would result in the highest risk for flashover of the
insulators. This information is useful when selecting the insulator material and profile.
The dimensions of the presently installed insulators can be compared against the dimensions
recommended for that environment to determine whether the installed insulators present an
increased risk. If so, they may need to be replaced, or a mitigation technology implemented,
or a regular maintenance program initiated.
2. Characterization of the insulator flashover performance: To establish a comparative
study of the flashover performance of various types of insulator installed at the same testing
site. Through such a study, the most appropriate insulator design and dimensions—for the
given conditions—can be selected.
3. Initiator for insulator maintenance: Results from regular, or continuous, site assessments
can also be used as trigger for insulator maintenance before critical conditions arise.
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Table 5-2
Contamination Site severity classification and sample descriptions of typical environments [14]
Severity class
Very Light [VL]
Light [L]
Medium [M]
Heavy [H]
Very heavy [VH]
Example Description of Typical Environment
> 50 km from any sea, desert, or open dry land
> 10 km from man-made contamination sources or within a shorter distance, but:
the prevailing wind is not directly from these contamination sources
and/or subjected to regular monthly rain washing
10-50 km from the sea, a desert, or open dry land
5-10 km from man-made contamination sources
or within a shorter distance, but:
the prevailing wind is not directly from these contamination sources
and/or subjected to regular monthly rain washing
3-10 km from the sea, a desert, or open dry land
1-5 km from man-made contamination sources
or within a shorter distance, but:
the prevailing wind is not directly from these contamination sources
and/or subjected to regular monthly rain washing
or further away, but:
a dense fog (or drizzle) often occurs after a long dry contamination accumulation
season (several weeks or months)
and/or heavy rains with a high conductivity occurs
and/or there is a high NSDD level, typically between 5 and 10 times the ESDD level
Within 3 km of the sea, a desert, or open dry land
Within 1 km of man-made contamination sources
Or with a greater distance, but:
a dense fog (or drizzle) often occurs after a long dry contamination accumulation
season (several weeks or months)
and/or there is a high NSDD level, typically between 5 and 10 times the ESDD
Within the same distance of contamination sources as specified for “Heavy” areas
and:
directly subjected to sea-spray or dense saline fog
or directly subjected to contaminants with high conductivity, or cement type dust with
high density, and with frequent wetting by fog or drizzle
Desert areas with fast accumulation of sand and salt, and regular condensation
Areas with extreme levels of NSDD, more than 10 times the level of ESDD
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Methods for Determining Contamination Severity
Several methods to assess the site severity have been described in the literature [11] [12]. The
most widely used ones are:
•
•
•
•
•
•
•
Environmental monitoring (Air sampling, Climate measurements)
Directional dust deposit gauge
Equivalent Salt (NaCl) Deposit Density (ESDD) and Non-Soluble Deposit Density (NSDD)
Surface Conductance
Insulator Flashover stress
Surge counting
Leakage current measurement
Detailed descriptions of these methods may be found in Annex A, they range from very simple,
such as directional dust deposit gauges, to complex, such as the automated surface conductivity
measurements [13]. Also, not all methods are equally suited to assess the severity of a site,
depending on the type of contamination present. For example, although the measurement of the
Equivalent Salt Deposit Density (ESDD) is preferred at sites with pre-deposited contamination, it
may underestimate site severity at sites with instantaneous contamination. A first step in a site
assessment should, therefore, be to determine what predominant type of contamination is
present. Thereafter, the site assessment technique best suited to those circumstances can be
selected.
Figure 5-5 [15] shows the relationships between the different site severity techniques. In the
figure, those methods shown beneath another one indicates increasing levels of refinement; e.g.,
Surge Counting is a refinement of the method of Insulator Flashover Stress.
Figure 5-5
An overview of some site assessment techniques [15]
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With reference to Figure 5-5, the site assessment techniques are classified into two groups:
•
•
Contamination performance measurements which assess the insulator on the basis that the
leakage current across the insulator under operating conditions. It assesses all aspects of the
insulator flashover process, which includes the effects of both the contamination deposit and
natural wetting.
Environmental severity measurement assesses only the accumulation of contamination on the
insulator, which in the best case ESDD/NSDD, includes the effect of natural washing. From
this measurement, the flashover performance of insulators is derived from either artificial or
natural contamination test results. There are also purely environmental measurements, such
as directional dust deposit gauges (DDDG) and air pollution sampling, which do not take
account of the contamination accumulation and natural washing characteristics of insulators,
but rather, measure in a standardized way the amount of contamination present in the air.
Usually, it is also advisable to complement the site assessment measurements with
meteorological data for the site. In many countries this type of information was available from
the local weather office that often have publications that summarizes the climatological
information as collected over many years. More recently the Internet has also become a valuable
source of detailed information. It is recommended that the following meteorological parameters
be collected:
•
•
•
•
Temperature (maximum, minimum and daily and yearly variation)
Relative humidity (maximum, minimum and daily and yearly variation)
Atmospheric precipitation (maximum, minimum and daily and yearly variation)
Direction and speed of wind
Another source of valuable information is to investigate previous insulator flashovers in terms of
time of day and seasonable variations. In some cases, it is possible to correlate times when
flashovers occur frequently with specific causes, such as bird activity, lightning or
contamination. The aim should be to try and collect as much information as possible of each
fault, and specifically for contamination related flashovers, include the following items:
•
•
•
•
•
•
•
Time of the flashover
Insulator type
Insulator position (horizontal, vertical)
Unified Specific Creepage distance of the insulator (defined below)
Meteorological data, previous to and at time of flashover (as listed above)
Duration of the insulator exposure on site (without cleaning)
Additionally, if available the following data may also be collected:
- Surface conductivity (measured by IEC probe) of the insulator that flashed over
- Instantaneous data from all contamination monitors present
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Contamination Maps
It would be desirable to arrive at a contamination map in which the degree of contamination
condition is shown in the same manner as the isokeraunic levels for lightning [16] [17].
Achieving this goal requires an intensive investigation over large areas for several years, because
the deposition of contaminants varies with weather conditions, such as wind and precipitation,
and with specific locations. There is, of course, still much uncertainty surrounding the
knowledge of weather conditions. In particular, many past contamination flashovers were caused
by unusual weather conditions, such as an exceptional salt storm or a long dry period that
allowed a heavy accumulation of pollutants [18] [19] [20]. Also, industrial pollution levels
change with the activity of industry in the vicinity of power systems. Application of air pollution
controls should reduce artificial pollution in general.
The prediction of contamination conditions is an arduous and continuing task. In one country, the
contamination map has been revised three times in 10 years [18]. It is, therefore, advisable to use
as far as possible automated, very simple site-assessment techniques, such as air pollution
sampling. Figure 5-6 shows a typical example of how dustfall measurements have been used to
obtain a pollution map of an area of heavy industry on the east shore of Lake Ontario. The HV
transmission lines adjacent to this heavy industry will be exposed to relatively severe ESDD
levels of up to 0.6 mg/cm2.
Figure 5-6
Typical variation in dustfall near urban industrial area of Hamilton, Ontario.
Choice of Material
In the past, the choice of insulator material has often been based on historical experience and the
confidence that has been gained in a specific product. As was highlighted in previous chapters,
all insulator technologies have their strengths and weaknesses. The choice of material is,
therefore, a balancing act, where the advantages and disadvantages need to be weighed against
each other in order to find the optimal solution. A broad overview of some of the advantages and
disadvantages of using a particular insulator technology are listed in Table 5-3.
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Table 5-3
Advantages and Disadvantages Associated with Different Insulator Technologies
Prime targets for vandals because of shattering.
Surface may be etched by long-term dry-band
arcing resulting in shattering.
May require long insulator strings in polluted
conditions.
Heavy.
Lack of availability in certain regions.
Surface glazing resistant to etching from dry
band activity.
Do not shatter when shot by vandals.
Proven long-term reliability.
Insulators from different manufacturers are
interchangeable and generally have similar
performance.
May contain hidden internal defects.
May require long insulator strings in polluted
conditions.
Heavy.
Lack of availability and time to delivery in certain
regions.
Lighter weight (easier to handle and ship).
Lower cost.
Better availability and shorter lead times.
Enables single-pole structures (i.e., post
application).
Better shock loading characteristics (post
only).
Less susceptible to vandalism.
Better contamination performance.
Unknown life expectancy.
Limited service experience.
Different designs, materials, and manufacturing
processes between suppliers.
More susceptible to damage during handling.
May contain hidden defects.
Concerns regarding live working.
Difficult to identify high risk units prior to failure.
Glass
Give visual indication of internal defects.
Good puncture resistance.
Proven long-term reliability.
Insulators from different manufacturers are
interchangeable and generally have similar
performance.
Porcelain
Disadvantage
Polymer
Advantage
In many companies, the decision to utilize glass or porcelain has been taken long ago and is
generally based on many years of service experience. The electrical performance of these two
materials is, for all practical purposes, the same, and the choice of material rests on previous
good or bad experience. In comparison, polymer insulators have been introduced relatively
recently, and the designs of most manufacturers have evolved over time. Results from service
inspections are also not always relevant due to the many revisions and refinements to the
designs, and to the materials and manufacturing processes that have been made to improve the
product and address degradation and failure modes. This situation is compounded by the facts
that: (a) each manufacturer employs different materials, construction details, and manufacturing
processes; and (b) many utilities are not certain of what vintage units they have in-service on a
specific structure.
The aim of this section is, therefore, to focus more on the selection of polymer insulator
materials than on glass or porcelain.
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Insulator Selection Considerations
The following factors need to be considered when selecting the type of insulator to be utilized.
Cost and Availability
As manufacturing techniques improve, polymer insulators are becoming more cost competitive,
and their inherently shorter lead times often make polymer insulators more attractive. Their light
weight may also reduce shipping, handling, and most significantly, installation costs [21] [22].
Standardization
Unlike porcelain and glass insulators, the basic dimensions and designs of polymer insulators are
not well defined. Differences in materials and manufacturing techniques are significant, making
the choice between different manufacturers’ designs difficult. Utilities must survey
manufacturing techniques, materials, and designs to determine which is best for their
environment and application. Often trade-offs must be made.
No standard connection lengths are defined for polymer insulators. Concerns have arisen when
replacing in-service units since connection length changes can influence conductor tension and
sag. Certain manufacturing processes allow the manufacture to almost any predefined length,
while other processes are less flexible. Due to industry pressures, most manufacturers have
addressed this issue by providing a comprehensive range of lengths.
No standardization exists for corona ring designs, attachment mechanisms, or effective
performance criteria. The only performance criteria that has been put forward has been by EPRI
and STRI, where the E-field is recommended to be below specific levels on the rubber housing
and the end fitting seal [23] [24] [25] [26].
Not only is it difficult for the utility engineer to evaluate differences in corona ring designs,
but it may also result in confusion in the field. It is not uncommon to find corona rings from one
manufacturer installed on another manufacturer’s units. Since each manufacturer utilizes a
unique attachment method specific to their end fitting design, a corona ring from another
manufacturer may be installed in an incorrect location or backwards.
Power Arc Performance
The ability of polymer insulators to withstand power arcs terminating directly on the end fittings
may be divided into three categories:
1. Short-term mechanical performance
2. Long-term mechanical performance
3. End fitting seal performance
Testing has indicated that a short-term loss in mechanical strength may arise during the power
arc to approximately 60% of the ultimate strength of the insulator. For the design tested, this
reduction corresponded to 80% of the specific mechanical load (SML) [27]. Long-term
reductions of 10 to 20% in ultimate mechanical strength have also been observed in testing. For
the design tested, the long-term strength of units was above the SML. Since polymer insulators
are applied at less than 50% of SML for extreme loading conditions, concerns are reduced [27].
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Damage to the end fitting seal resulting in exposure of the fiberglass rod is a concern. Certain
designs appear to be inherently more susceptible than others. The removal of galvanization and
the resulting localized corrosion is of lesser concern. Figure 4-31 shows examples of units
removed from service with damaged end fittings due to power arcs [28]. Standard tests exist to
determine the ability of insulator strings to withstand power arcs. The tests specify how the
power arc tests should be performed, together with visual and mechanical criteria by which the
insulators are assessed after the test [24].
The use of corona rings or arcing horns will reduce the effect of power arcs. Both the energized
and grounded end fittings need to be addressed. Manufacturers should be consulted as to whether
units that have experienced flashover should be removed from service.
Live Working
Concerns have been raised over working with polymer insulators under energized conditions.
These concerns arise in two circumstances:
•
•
Installing new units. Unlike manufacturers of porcelain/glass insulators, manufacturers of
polymer insulators do not perform electrical routine tests on individual polymer insulators,
due to the high voltages required for such testing. To address this concern, some utilities test,
tag, and package all new polymer insulators intended to be installed under energized
conditions. Another approach is to utilize a high-voltage test set in the field to test the units.
Utilizing the transmission line being worked on as a test source is another, although
somewhat controversial, approach proposed [29].
Working with or around in-service units. Defects should be identified and their impact on
the withstand characteristics of the worksite assessed before work commences to ensure a
safe worksite for utility personnel performing live work in proximity to a composite
insulator. EPRI has developed polymer insulator testers (Live Working NCI Tool, LWNCI
Tool) capable of detecting internal or external conductive defects, which has subsequently
been commercialized [30] [31][32].
Audible Noise, EMI, and RIV
Polymer insulators have been applied in some situations to address audible noise, EMI, and RIV
complaints due to discharge activity [15]. The unwanted discharge activity may have occurred
due to contamination or poor connection between individual porcelain/glass bells on lightly
loaded strings.
High-Temperature Conductors
The maximum permissible conductor temperature has been generally limited by the maximum
allowable conductor sag, which, in turn, is determined by conductor clearance regulations.
Conductor sag is a function of the properties of the conductor, the current flowing through the
conductor, mechanical load, ambient temperature, prevailing wind, and environmental
conditions. To increase the power throughput, new conductors have been designed that have
reduced sag at elevated temperatures. Some of these new conductors can operate at temperatures
exceeding 200°C (392°F) without compromising clearance regulations.
With the advent of these new conductors, the factor limiting the temperature at which conductors
may operate may shift from conductor sag to the maximum operating temperature of the attached
line hardware and associated components. One of the components considered to be vulnerable to
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elevated temperatures is the polymer insulator due to the material used in its construction.
Manufacturers of polymeric insulators generally specify a maximum ambient operating
temperature of 50°C (122°F). Elevated conductor temperatures may lead to this value being
exceeded, which is a concern.
A number of tests have been performed on polymer insulators connected to high-temperature
conductors to determine the temperatures that the insulator end fittings will be subjected to.
Figure 5-7 shows the results of some of these tests.
Figure 5-7
Summary of results obtained by different organizations with respect to the end fitting temperature
of an insulator for different conductor temperatures. Ambient temperature in all cases was
between 20 and 25°C [33] [34].
Polymer insulator end fitting temperature was found to be a function of [33]:
•
•
•
•
Conductor temperature.
Applied mechanical load. (Tests performed with no load provide lower end fitting
temperatures due to the poor contact between the hardware. A relatively modest load of
235 kg (520 lb) ensures effective contact.)
End fitting design of the polymer insulator.
Type and length of hardware connecting the conductor and the polymer insulator.
It can be seen from Figure 5-7 that, in some cases, end fitting temperatures of almost 70°C were
reached for conductor temperatures of 250°C when the ambient temperature was 25°C.
A number of insulator manufacturers have indicated that these levels of end fitting temperature
can be withstood. In a survey of manufacturers, the maximum recommended end fitting
temperatures varied between 70°C and 90°C, depending on manufacturer [34].
Not evaluated or investigated in the testing was the impact of ambient conditions or solar
radiation. The effect of these high temperatures on the long-term performance remains under
investigation.
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Ease of Inspection
Identifying high-risk polymer insulators prior to failure remains an issue. Conditions indicating
an increased risk are relatively small, and inspection distances are large [35] [36] [37]. As the
population of installed polymer insulators ages, utilities will be faced with an increased
challenge. Detailed close-up visual inspection, at distances less than 0.5 to 1 m, remains the most
effective method of inspection, but is impractical and not cost effective. It also requires
considerable inspector expertise [28].
Development of the EPRI daytime corona camera was intended to assist in this regard, but it has
limited application since it does not address the main failure mode, brittle fracture [38].
Developments currently under way to improve inspection methods, include:
•
•
•
Inspection technique to evaluate the resonant characteristics of insulators [39].
“Self-diagnosing” polymer insulator [40].
Design and vintage identification guides to assist in the identification of high-risk designs
[42] [41].
These developments are currently under way, and it is uncertain whether they will fully resolve
the issue.
Wood Pole Fires
The use of polymer insulators has been effectively applied to reduce the occurrence of wood pole
fires by reducing the leakage current. Silicone rubber units have been applied in most cases due
to their hydrophobic properties and hence lower leakage currents.
Storing, Transporting, and Installing
The root cause of numerous failures has been handling damage. The light weight, apparent
“toughness” of polymer insulators, and the small size of the critical damage that they can incur
appear to make polymer insulators more susceptible to handling damage. Education of
warehouse and field personnel is essential to reduce the number of handling-related failures.
Both utility and contractor personnel need to be addressed. Several guides and an educational
video are available to assist in this regard [43] [44] [45].
Animal Damage
Polymer insulators at several utilities have experienced damage from rodents and birds, as shown
in Figure 5-8.
Rodent damage has occurred to units while stored in warehouses or shipping yards. Effective
packaging and storage procedures can be put in place to reduce concerns.
Utilities in Australia and the United States have experienced bird damage on installed units.
Damage is more prevalent prior to energization; however, damage to energized units has also
been reported. The coverup of installed units prior to energization has been implemented to
reduce damage.
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Rodent Damage
Bird Damage
Figure 5-8
Examples of rodent and bird damage to polymer insulators.
Vandalism
Polymer insulators have been effectively applied in situations where vandalism is high. Unlike
porcelain or glass units, polymer insulators provide little gratification when struck by a bullet
and present a smaller profile to aim at [46].
On the other hand, gunshot damage is difficult to identify on polymer insulators and can have a
catastrophic result if the rod is exposed.
Resources
When determining which type of insulator, or what design of insulator to utilize, engineers can
draw on a number of resources, including:
•
•
•
•
•
•
Compliance with national and international standards
Field experience
Accelerated aging tests
Stress testing
Published application guides
Reference books
International and National Standards
A wide range of international and national standards exists. In this document, reference will be
made to both IEC and ANSI standards. The relevant IEC and ANSI/IEEE standards are
discussed in Chapter 7.
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Manufacturers’ products are expected to comply with all requirements outlined in the applicable
standards. It is often useful for decision makers to determine whether the product design
complies with standards that may not be mandatory in their region.
Some of the “tracking and erosion tests” described in the standards are often called “aging tests”
in the literature. These tests are not “accelerated aging tests” in the sense that these tests do not
simulate exactly the real-life degradation conditions, nor do they accelerate them to give a lifeequivalent test in a short time. Rather these tests use continuous, cyclic, or combined stresses to
try to detect potential weaknesses that could compromise the insulators’ performance in-service.
These tests can best be described as “screening tests” [47] [48] [49].
Field Experience
Even though an insulator may have passed all of the tests identified in the relevant international
and national standards, further information is often required to obtain an indication of the life
expectancy for the environment and application in which the unit will be applied.
Field experience is one of the best methods to obtain life expectancy and performance
information since the artificial stresses in aging/flashover tests are negated. This information is
often not available since decades worth of experience is ideally necessary, and the designs of
units manufactured today are different from those manufactured 20 years ago.
When determining whether field experience information is relevant to a new installation, one
must determine whether aging and flashover mechanisms are similar. Considerations include:
•
•
•
•
•
•
Difference in environment between the field units being reviewed and the region in which the
new units are to be applied. Care should be taken when basing the decision for units to be
applied in a highly contaminated environment, on field units installed in a low contamination
region and vice-versa.
Differences in designs, manufacturing methods, and materials between the field units and the
new units.
Changes in the design of units presently manufactured and the field units.
Differences in voltage level—to ensure that similar aging mechanisms occur (e.g., wet
corona activity).
Configuration and corona ring application since the E-field distribution has a significant
effect on the aging characteristics.
Differences in mechanical loads—both every day and under extreme loading conditions.
Notwithstanding the above considerations, field experience remains the best resource on which
to base a decision. Three areas from which this experience may be obtained include:
•
•
•
Utility experience
Test lines and structures
Test stations
Utility experience on similar units installed in a similar environment for prolonged durations is
required. Since modern-day polymer insulators only became available in the late 1970s, and
since some of the designs changed significantly until the 1990s, this data is often not available.
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Approaches to reviewing field data should involve removal of units and include detailed visual
inspection and dissection, and mechanical and electrical tests [50]. Leakage current
measurement, discharge observations, weather data, and material analysis may also be
performed.
Care should be taken to ensure that field units reviewed are representative of the units being
considered for application in terms of design, manufacturing, voltage level, and application. With
a thorough understanding of the differences, these factors can often be accounted for in the
decision-making process.
During the advent of polymer insulators, several utilities applied small numbers on test structures
or installed test lines. The information from these installations has provided important guidance
and verification. Since many of these test installations were initiated prior to mass production,
units may have been hand-crafted or not representative of the designs available today.
Differences in environment, insulator design, voltage, and application should be noted when
utilizing this information.
A number of outdoor test stations exist where large numbers of test units have been installed and
monitored on a regular basis. In some cases, these test stations were also instrumented for
leakage current measurement and weather parameters. Observations and analyses were
performed using a range of techniques.
Test stations have been constructed in both high- and low-contamination locations [51] [52] [53]
[54] [55], which have provided valuable information. In some cases, the test sites were located in
very highly contaminated environments to accelerate degradation. Care needs to be taken when
interpreting results to ensure that the aging and flashover mechanisms in these harsh
environments are representative of the application in which new units will be installed.
Configurations in test stations should also be applied in a manner that the E-field distribution is
similar to that in service. The voltage levels should also be representative. Test stations that
provide an acceleration aging environment, due to exceptionally harsh environmental conditions
not experienced on normal transmission lines, should be considered as an accelerated aging test
rather than a field test when considering experience.
Multi-Stress Accelerated Aging Tests
Since the required life expectancy for polymer insulators is often 30 years or more, a number of
accelerated aging tests have been used worldwide to evaluate the long-term performance of
polymer insulators. The accelerated aging tests are intended to simulate specific environments,
around which an aging cycle is developed. The design of the cycle to accelerate aging is
dependent on the primary aging mechanism under consideration. For example, if a highly
contaminated environment is being considered, the number of pollution events in a year may be
increased. In the case of an aging test simulating a low-contamination environment, the number,
or duration, of wetting events may be increased
When considering the results of an existing test, or implementing a new aging test, care should
be taken to consider the environment in which units will be installed, and to evaluate the primary
and secondary degradation modes. The aging cycle should be designed to simulate the
degradation phenomena that will occur in the field as accurately as possible. If a degradation
mode is introduced that does not occur in the field, the results may not be relevant.
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Acceleration rates quoted for the individual tests are only approximate and are specific to the
environment being simulated. Determining the acceleration rate requires a thorough
understanding of the aging mechanisms, and in some cases, research performed later may require
initial acceleration rates be adjusted. For example, at the time of development of the EPRI
“Deserts with a Distinctly Cold Season” aging test, the assumption was made that elevated
temperature was the primary aging process. Future research indicated that time of wetness was
the primary aging factor; hence the initially calculated acceleration factor of between 12 and 20
was revised at the end of the test to between 7 and 14 [56].
In designing an aging cycle, care must be taken to allow rest periods where silicone rubber-based
insulators are able to recover their hydrophobicity. The inclusion of these rest periods was not
always accounted for in early accelerated aging tests. The required conditions and duration of
rest periods remain undefined and an area of ongoing research.
Comparison of accelerated aging test results against field-aged units, to confirm that the aging
mechanisms are relevant, is essential. In several cases, the accelerated aging results have
compared favorably with field-aged and outdoor test station units [55] [56] [57].
Several tests, to determine the long-term performance, have also been developed to assess the
performance of one, or possibly two, components of an insulator, but not the entire insulator
(e.g., end fitting seal or rubber). Examples include the incline plane test, EPRI’s end fitting seal
tests, and EPRI’s long-term dynamic and mechanical loading tests. These tests do not provide an
indication of life expectancy; rather they provide a performance comparison between different
designs or highlight design weaknesses in the component being evaluated. [58] [49] [48].
Choice of Profile
Insulator profile is an important factor that influences the interaction between the insulator and
the environment. The following general profile types are identified:
•
•
•
Aerodynamic Profile is designed to minimize the contamination accumulation of the
insulator.
Fog (or anti-fog) profiles is designed to maximize the amount of leakage distance per unit
length.
Standard profiles aim to find a balance between contamination accumulation characteristics
and leakage distance.
It affects the contamination catch on the insulator as well as the effectiveness of natural cleaning.
It also influences the amount of leakage distance that can be fitted per unit of insulator length.
The leakage distance per unit connecting length of the four profiles is compared in Figure 5-9.
This shows that the fog profile followed by the aerodynamic profile have the highest leakage
distance per unit of connecting length [59].
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Leakage distance per unit axial length
4
3
2
1
Aerodynamic
0
Fog Bowl
Standard
Fog Profile
Profile Compexity
Figure 5-9
A Comparison of the Leakage Distance per Unit Length for four Toughened Glass Suspension
Insulator Profiles [59]
The choice of profile will be discussed separately for porcelain and glass insulators and polymer
insulators. The main reason is that there is a wider range of profiles available for porcelain and
glass than for polymer insulators.
Porcelain and Glass Insulators
Over the years, and largely gained from field experience, insulators having various profiles have
been developed for application in specific regions. Of the designs, four are prevalent; namely,
•
•
•
•
The standard
Fog
Aerodynamic
And fog-bowl designs
However, only the standard suspension unit has been standardized. More information on how
insulator designs perform in various environments are provided in Chapter 3.
Standard Profile
An example of a standard profile is shown in Figure 5-10. Twelve suspension insulator designs
have been standardized which are shown in ANSI C29.2, however only four are designs for
transmission. These are 52-3, 52-5, 52-8 and 52-11, corresponding to 15, 25 36 and 50 kip (66.7,
111, 160, and 222 kN) M&E rated insulators. IEC has many more standardized designs with
strength ratings up to 120 kip (533.8 kN). This design is effective for use in “light” or “medium”
contaminated areas where a long creepage distance or aerodynamically efficient profile is not
required.
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Figure 5-10
Photograph and drawing of a Standard Profile Insulator
Fog Profile
The fog profile insulator usually has a larger diameter and longer under-ribs than the standard
profile (Figure 5-11).
The larger diameter and deeper ribs increase the leakage path, and the larger ribs act as a barrier
against wind-driven contaminants from accumulating at the pin area. However, the vortices
created by the under-ribs lead to an accumulation of contaminants. This cavity area is also
protected from natural cleaning and may lead to a long-term accumulation of contaminants in
some environments. Experience in such environments is initially good but deteriorates as the
contaminants accumulate on the underside. The widely spaced ribs also reduce the possibility of
arcs bridging the air gap between two ribs and water bridging during heavy rainfall.
Figure 5-11
Photograph and drawing of a Fog Profile Insulator
These insulators are designed to provide a long creepage length per unit string length; therefore,
this type of insulator is usually applied in coastal areas where fog from the ocean is a common
occurrence. Inland, where warm fog is more common, this type of insulator is not used. In
addition, fog-type insulators have not been standardized.
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Aerodynamic Profile
Analogous to fog profile, aerodynamic-type suspension insulators are not standardized. The
industry has developed designs of various diameters (leakage distance), and strengths. The
design is characterized by a smooth profile, without ribs on the lower surface, and therefore more
aerodynamic in their shape than the standard profile insulators. These insulators work well in
dessert areas where wind is constant, which tends to prevent the deposition of contaminant.
Figure 5-12
Photograph and drawing of an Aerodynamic Profile Insulator
The insulator disk of an open profile is generally flat and without any under-ribs, and the goal is
to establish a smooth airflow without many vortices around the insulator. The open profile does
not accumulate large amounts of contamination and is accessible to natural cleaning (Figure
5-12). This profile also offers a relatively long creepage distance per string length because of the
relatively large diameter of the dielectric shells. This design is typically applied in desert areas
where rainfall is low and washing or cleaning of insulators is infrequent.
Fog-Bowl Profile
The fog-bowl profile resembles an inverted bowl with no under-ribs but with a large protected
creepage distance. The objective with this profile is to reduce wetting by wind driven cold fog
and therefore it is primarily used in coastal regions. Like the aerodynamic profile, the fog-bowl
reduces the collection of contaminants and due to the open shape and is much easier to wash.
The leakage distance on these insulators is similar to that of a standard profile (Figure 5-13).
Note that this profile is not frequently used and therefore not available for all mechanical
strength classifications.
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Figure 5-13
Photograph and drawing of a Fog-bowl Profile insulator
Polymer Insulators
Shed profiles of polymer insulators tend to be of the aerodynamic type to facilitate the molding
process. Some examples are given in Figure 5-14 [59].
Figure 5-14
Typical examples of polymeric insulator profiles [59]
(Notes: a: Flat sheds have an underside inclined between 7o below and 3o above the horizontal,
i.e., angle β b: Inclined sheds have an underside inclined more than 10o below the horizontal,
i.e., angle β.)
When considering profile parameters for composite insulators the following considerations
should be taken:
•
Laboratory results suggest that profile parameters should be evaluated for good performance
under a combination of contamination and rain conditions. Heavy rain wetting in
combination with pre-deposited pollution should be considered when considering profile
shape. Factors that impact the performance of an insulator under these conditions are; shed
projection, shed angle, shed spacing and the diameter of the insulator. Under these
conditions, large sheds with a shallow shed angle (i.e., large and flat) will not perform as well
as short sheds with a steep inclination, because of its poor drainage characteristics.
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•
•
•
•
In contaminated conditions the pollution catch of the insulator is determined to a large extent
by the shed aerodynamic properties. Flat aerodynamic sheds will collect less contamination
than steep sheds with protected creepage. The pollution accumulation on the protected part of
steep shed designs (i.e., under the shed) may produce a high E-field concentration across the
shed material during humid conditions, increasing the possibility for shed puncture.
In contamination conditions it is generally found that alternating long and short shed profiles
perform better than regular shed profiles.
Closely spaced shed designs should be avoided due to the increased risk of inter-shed
breakdown. Test results indicate that the efficacy of the creepage distance decreases rapidly
for a shed spacing of 30 mm or less.
There seems to be general consensus that the shed parameters included in the IEC 60815 are
conservative when applied to composite insulators. These parameters are presently under
review by the relevant IEC working group. Many users still use these parameters since
because of the lack of recommendations for composite insulators. The only risk is that a
limited number of insulator types are excluded, which probably would have performed quite
well.
The Insulator Dimensioning Process
Introduction
The aim of any dimensioning method is to select the properties of the insulator so that it has an
acceptable flashover performance for its whole service life. This means that an insulator must be
selected so that it can withstand the stresses placed on it without failing. Generally, the following
methods are used, listed from simple to complex:
•
•
•
Service experience
Selection of creepage distance
Methods based on statistical principles which includes:
- A deterministic method using laboratory tests
- A statistical method utilizing flashover performance data
Service Experience
In a great majority of cases, operating lines or substations are in the area for which the insulation
needs to be designed. If these installations have had an acceptable performance, the same
insulation configuration can be used. Results from different voltage levels may even be
extrapolated, based on the linearity principle discussed in Chapter 3. When introducing a new
type of insulator, some network owners have opted for establishing test stations where the
performance of insulators can be evaluated under natural conditions without risking system
security. This approach provides a secure way to dimension insulators, but unless special testing
is performed (e.g., using explosive fuses to determine the insulator flashover stress), this method
does not offer much to optimize the insulation length. The IEC recommends that typically a
period of 5–10 years of service, and 2 to 5 years in testing stations, may be needed to be able to
adequately select insulators based on service experience [14]. These values are naturally
dependent on the characteristics of the environment and the testing philosophy used.
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Selection of Leakage Distance
Most national and international standards provide a simple table with four or five site severity
categories and corresponding levels of minimum leakage distance. The site severity is
determined through one of the methods described in Annex A or by using a set of descriptions of
typical environments provided in the standard. The recommended leakage distance levels listed
in the IEC and ANSI guidelines are provided in Table 5-4.
Table 5-4
IEC and ANSI Guidelines for the Selection of Leakage Distance for Different Site Severity Classes
Pollution Class
Unified Specific Creepage Distance (mm/kVp-g)
1. Very light
22
1. Light
27.8
2. Medium
34.7
3. Heavy
43.3
4. Very heavy
53.7
When using this method there many factors, other than leakage distance, that affect the insulator
flashover strength which need to be factored in. Documents providing leakage distance
recommendations, therefore, contain a set of limits within which the creepage distance
recommendations are valid. In some cases, correction factors are provided to adjust the
recommended values for insulators outside these limits [66]. In other documents, such as the IEC
60815, factors are only provided to compensate for the effect of diameter, whereas profiles that
fall outside the limits are disqualified [14].
This method makes it possible to specify insulators, within a limited profile range, based on the
collected long-term service and test experience of many countries without the need to perform
additional laboratory or field-testing. All insulators within the profile limitations and with the
minimum required creepage distance are approved for service.
Methods Based on Statistical Principles
Introduction
Insulator dimensioning would be very easy if the insulator had a well-defined strength above
which it will fail and below which it will withstand, and if the stresses to which it is subjected
had a definitive maximum value that would never be exceeded. In reality, both the stress and the
strength are probabilistic variables. That is, the stress placed on the insulator varies randomly
over time, and for any particular level of stress, a probability exists that the insulation will flash
over. As a result, there is always a chance that the stress may exceed the strength, leading to a
flashover.
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In the case of insulators, the stress is the combination of the a.c. voltage across the insulator and
the salt contamination that may lead to a conductive surface layer. If the resistance of this
pollution layer becomes low enough the electrical strength of the insulator will be sufficiently
reduced to lead to a failure, which precipitates as a flashover across the insulator. The risk of
such a flashover can be determined with reference to Figure 5-15, as follows [7] [60] [15]:
•
•
•
The insulators are energized with an ac voltage with constant amplitude, corresponding to the
maximum continuous operating voltage. In special cases, where the insulators are exposed to
extended periods of temporary overvoltages, it could be necessary to base the design on a
higher voltage level.
The variation of the pollution stress to which the insulator is exposed is represented by the
probability density function “f(γ)”, which is expressed in terms of the site severity “γ”.
A cumulative distribution function “P(γ)” describes the strength of the insulation—that is, the
probability of flashover as a function of the same measure of site severity “γ” as was used to
describe the pollution stress.
The multiplication of the f and P functions gives the probability density of flashover of the
insulator at the given site, and the area under this curve expresses the risk of flashover.
25
1
Risk for flashover
Probability Density
20
0.9
Strength P(γ)
Density of Site severity
Probability for flashover
0.8
0.7
Stress f(γ)
15
0.6
0.5
10
0.4
0.3
f(γ) ∗ P(γ)
5
0.2
Probability for flashover
•
0.1
0
0.001
0.01
0.1
1
0
Contamination severity (γ: ESDD: mg/cm2)
Figure 5-15
Stress-strength concept for the calculation of the risk of flashover with respect to polluted
conditions [15] [7].
The risk of flashover can be minimized by “moving” the P curve to the right relative to the f
curve—i.e., by selecting an insulator with a higher flashover strength, taking into account
reasonable economics. In practice, it is not always possible to evaluate the risk of flashover in
this way since these probabilistic functions are often time consuming or difficult to obtain.
A probabilistic approach is followed when the user wants to specify the design and dimensions
of the insulator. In this approach it is necessary to know the density function describing the
pollution severity at the site (f curve in Figure 5-15) as well as the flashover characteristics of the
candidate insulator as a function of the pollution severity (P curve in Figure 5-15). The latter can
11762887
5-36
be determined by performing a series of flashover laboratory tests at different pollution
severities. This information can then be used to evaluate the risk for flashover at different
insulator lengths in order to select the length that will have an adequate performance.
Uncertain
stress
Safety factor
Uncertain
strength
Strength:Probability for flashover
Minimum insulator withstand severity
maximum site severity
Stress: Density of occurence
The deterministic approach on the other hand, is built on the idea that the user wants to specify
the withstand strength of the insulator. With this approach the demands on the quality of the
input data are much less than those of the probabilistic approach. This approach is illustrated
graphically in Figure 5-16 [61] and it is based on the definition of a worst-case pollution severity
that may stress the insulation, while the insulator strength is described in terms of a minimum
withstand severity below which flashover is not possible. The minimum insulation withstand
severity is then selected so that it exceeds the maximum pollution stress with a safety margin
which is, in turn, chosen to cover only the uncertainties in the designer's evaluation of the
strength and stress parameters. Candidate insulators are then subjected to a withstand test to
verify that their characteristics do not fall below that which is needed to obtain an adequate
performance.
Pollution Severity( γ)
Figure 5-16
Graphical illustration of the deterministic approach [61].
It is clear that the probabilistic method offers the greatest possibility to obtain a compact
insulation design, but it places the highest demands on the input data, which can be expensive to
obtain. The deterministic method, on the other hand, may be based on a worst-case condition,
which could be a very rare occurrence as it could be the simultaneous occurrence of several
unlikely events; the insulation could therefore be considerably longer - and more expensive than would be the case with a probabilistic design. It should also be realized that even for a
deterministic design there is a finite risk for failure although it is not evaluated.
The choice between the deterministic and probabilistic method is generally based on a
comparison of the costs involved in obtaining sufficient information about the various
distribution functions versus the capital costs of installing more expensive insulation. In some
cases, it may be company policy that dictates the use of one or the other. A summary of the two
methods is given in Table 5-5.
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Table 5-5
A comparison of the deterministic and statistical approaches to dimensioning [62].
Step
Probabilistic Method
Deterministic Method
1
Determination of site severity: Quantify the stress the insulator is subjected to. This is both the
pollution site severity and the applied voltage across the insulator
2
The flashover characteristics of the candidate
insulator(s) are determined through laboratory
pollution flashover tests
The required insulator withstand strength
that will fulfil the performance requirement
is determined.
3
The length of the insulator is selected so that the
system will have an acceptably low risk for
flashover
The flashover strength of candidate
insulators is verified with laboratory
pollution withstand-tests
Probability Density of the Site Severity
An overview of the processes governing the accumulation of contamination on insulators is
given in Chapter 3. Briefly it can be stated that the pollution deposit on the insulators builds up
during dry periods. It may be washed or leached from the insulator under wetting events. The
extent of this removal is related to the intensity and duration of the wetting [63]. As a result, the
pollution deposit on the insulators varies over time with maxima occurring usually at the start of
wetting events. Since periods wetting is also when discharge activity and flashover is likely to
occur these “events” poses the highest risk for flashover and it is only natural that these events as
used as a basis for the dimensioning process [64]. The severity of the events should therefore be
quantified in terms of [63]:
•
•
Distribution of the amount of contamination at the start of the wetting event.
Frequency and intensity of the wetting events.
For the dimensioning process it is necessary to establish a probability density function that
describes the variation of the contamination severity at the time of wetting events (i.e., the f(γ)
curve in Figure 5-15). Wetting events also correspond to the times of maximum contamination
severity (due to the washing effect), which means that the density function describing the
contamination severity of the site is a distribution of maximum values for which an extreme
value probability density function must be used. Furthermore, since the maximum values of the
contamination severity is of interest, it is preferred to describe this severity density function in
terms of “statistical severity”, γs2, which is the pollution severity having a 2% probability of
being exceeded [60], and the standard deviation.
Ideally site severity measurements should be performed just prior to -or during- the wetting
events to capture the levels during wetting events. Since this is not practical, most users follow a
pragmatic approach and perform site severity measurements at a fixed time interval [14]. This
means that peak contamination levels are not necessarily captured as it is unlikely that the time
of measurement exactly corresponds to the time when the contamination levels on the insulator is
at its highest. It should therefore be borne in mind that contamination measurements provide an
estimate of the expected values (i.e., the mode of the probability density function) rather than the
peak values.
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Another aspect of the contamination deposit that should be considered is the non-uniformity of
the pollution layer on the insulator under natural conditions. This differs from artificial
laboratory testing, where the aim is to produce an as uniform deposit as possible. The greater
non-uniformity of the pollution under natural conditions leads, generally, to higher flashover
values and also to a greater spread in the flashover values than those obtained during laboratory
tests [65]. As will be explained in the section dealing with the insulation strength, this aspect is
taken account of in the dimensioning process by making a suitable adjustment to the flashover
characteristics obtained from artificial tests.
With sufficient pollution severity measurements available, a suitable distribution function can be
fitted to obtain a statistical description of the pollution stress at the site. Most appropriately this
is described by an extreme value distribution, as it is a distribution of maximum values, but the
log-normal distribution is often used [64] [67]. This fit is illustrated in Figure 5-17 that shows the
distribution of measured ESDD from 6 different sites plotted on Log-Normal probability paper
together with the best fit straight lines which represent a true Log-Normal distribution. Note that
the slopes of the fitted straight lines is very similar which indicates that standard deviation of the
Log of the ESDD values is approximately the same for sites with a wide range of contamination
severity. For reference a horizontal line at 2% is included to show the “statistical severity”, γs2,
for each site.
Probability of exceding absyssa [%]
99.9
99
98
95
90
80
70
50
30
20
10
5
2
1
0.1
0.0001
0.001
0.01
Equivalent Salt Deposit Density
0.1
[mg/cm2]
1
Figure 5-17
Example of the distribution of Site severity Data (ESDD) data from six sites, plotted on Log-Normal
probability paper [61]
Flashover Probability of Contaminated Insulators
The flashover probability of a contaminated insulator string during critical wetting conditions is
a function of both the contamination severity and the applied voltage. An increase in either of
these variables leads to a higher flashover probability, as illustrated in Figure 5-18.
11762887
5-39
0.6
0.4
Po
llu
tio
nL
ev
el
(E
SD
D:
mg
/cm 2
)
0.0
0.2
0.4
0.6
0.8
1.0
0.8
ov
y for flash
Probabilit
er (p.u.)
1.0
1
0.2
0.1
0.0
140
120
100
Volt
age
0.01
80
Stre
ss
(kV/
60
m)
40
0.001
Figure 5-18
Three-dimensional representation of the probability for flashover during critical wetting as a
function of the voltage stress across the insulator and the pollution severity level.
Since variable voltage tests are easier to perform, it is usual to express the probability for
flashover in terms of voltage at a constant pollution severity. In most cases, flashover probability
as a function of applied voltage is approximated by a normal distribution function [68].
However, a Weibull distribution function has also been used to take account of the truncation of
the distribution function. That is, at a specific contamination severity, there is a voltage below
which flashover is not possible [69].
This distribution function is usually characterized by the critical or 50% flashover voltage (V50)
and the standard deviation (σ). Laboratory tests have been shown to have a normalized standard
deviation (i.e., σ /V50) of between 6 and 10%. For field tests, it is approximately 20%. This
difference between laboratory and natural testing can be ascribed to the larger variation in
wetting and contamination distribution on the insulator surface under service conditions.
When considering the flashover probability of a transmission line, or station, it is also necessary
to take account of the number of insulator strings that are exposed to the same environment. The
risk of flashover increases with more insulator strings exposed to the environment. The flashover
probability of “n” insulator strings, “Pn”, can be calculated from the flashover probability of one
insulator string, “P1” as follows (Equation 5-1):
𝑷𝑷𝒏𝒏 = 𝟏𝟏 − (𝟏𝟏 − 𝑷𝑷𝟏𝟏 )𝒏𝒏
Eq. 5-1
This relationship assumes that all the strings have the same single-string flashover probability
and that they are statistically independent. It is, therefore, only possible to apply this relationship
to a group of strings if they all are exposed to the same contamination severity, and all subjected
to the same wetting conditions. The assumption of statistical independence implies that the
flashover mechanism on one string does not affect the mechanism of others. Consequently, this
relationship cannot be applied to closely spaced strings where the sub-strings are close enough to
interact.
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An experimental study was conducted for a setup of 14 parallel strings of eight-unit, Type A-11
insulators to prove the validity of this relationship. The results of these tests and two computed
curves are plotted on normal distribution paper in Figure 5-19. Curves are shown for an assumed
standard deviation, 10% and 8%, respectively of the V50.
Figure 5-19
Test results of flashover probability of 14 I-strings.
The relationship between flashover voltage and the number of strings in parallel is shown in
Figure 5-20. In this figure the flashover voltage of all the strings in parallel is expressed in
percentage of the V50 of a single string, while assuming a normal or Gaussian distribution
function, with a normalized standard deviation of 10%.
Normalized flashover voltage (U/U 50: %)
100
95
90
85
U50
80
U10
75
U5
70
65
60
1
10
100
1000
Number of Strings
Figure 5-20
Relationship between flashover voltage of a single string and multiple strings, for 10% standard
deviation.
11762887
5-41
For a single string, the withstand voltage (i.e., 10% flashover voltage, V10) is 84% of V50, but
this percentage deteriorates as the number of parallel strings increases. For example, a section of
single-circuit, 10-mile-long, transmission line with four suspension towers per mile would
contain 120 vertical strings. Under contaminated conditions, the withstand voltage of these 120
strings together would only be about 69% of the V50 of a single string.
The decrease of flashover voltage with the number of strings shows a trend of saturation for the
case of more than 100 strings. For instance, the difference in withstand voltage between 100 and
500 strings is about 6.5%.
It is also necessary to take account of the effect of the parallel strings when performing
laboratory tests on naturally contaminated insulators removed from a line that has experienced
flashover. The naturally contaminated single string that has a V50 of 135% of the nominal line-toground voltage may be indication enough to verify that a contamination flashover has indeed
taken place. This is because the V50 of 120 strings is 75% that of a single string, as shown in
Figure 5-20. Laboratory testing often found that units that experienced flashover have higher
flashover voltages, from 110 to 150% of the nominal line-to-ground voltage.
These points emphasize that contamination flashovers on transmission lines, in areas of
widespread contamination, occur at much lower voltages than the test voltages used in the
laboratory (where the number of parallel strings is limited). This should be carefully reviewed
during line design.
Deterministic Method
The deterministic approach is used when insufficient statistical information is available to
warrant a full risk analysis. A minimum performance criterion is specified based on a worst-case
analysis. Laboratory testing may be used to verify that a candidate insulator fulfills this criterion.
With reference to Figure 5-16, this approach can be described as follows:
1. The maximum site contamination severity that the insulation will be exposed to is
determined through site severity measurements or a subjective judgment based on the
available site severity information.
2. The minimum contamination severity that the insulator must withstand is selected so that it
exceeds the maximum site severity with a safety factor, which is chosen to cover the
uncertainties in the designer’s evaluation of the strength and stress parameters.
3. Candidate insulators may then be subjected to a withstand or flashover test to verify that their
characteristics are above the minimum level determined in the previous step. The test method
used is selected to be representative of the service environment.
Step 1: Determine Maximum Site Severity
More often than not, an insufficient number of site severity measurements will be available.
Depending on the number of measurements available, the user may choose one of several
strategies to estimate the maximum contamination severity:
•
The user has many (i.e., more than 30) measurements available: The maximum site severity
is then simply taken as the maximum value of the values available.
11762887
5-42
•
The user has several measurement values available but not sufficient to feel confident that the
maximum value can be taken as representative. This would be the case where the user has
between 10 and 30 points available. In this case, the measurements can be assumed to
provide a good estimate of the average contamination severity of the site. The average value
of the measurements, (γ average), is then calculated, and the maximum site severity, (γmax), can
be estimated with (Equation 5-2):
𝜸𝜸𝒎𝒎𝒎𝒎𝒎𝒎 = 𝜸𝜸𝒂𝒂𝒂𝒂𝒂𝒂𝒂𝒂𝒂𝒂𝒂𝒂𝒂𝒂 ∙ 𝒆𝒆
•
�𝟐𝟐.𝟎𝟎𝟎𝟎∙𝝈𝝈 −
𝝈𝝈𝟐𝟐
�
𝟐𝟐
Eq. 5-2
Where σ is the standard deviation of natural logarithm of the site severity measurements.
Typical values of σ for ESDD measurements range between 0.4 and 0.9.
The user has only single measurement values available. In this case, it would be best to
assume that measured values correspond to the mode—i.e., the most likely level of pollution
severity. In this case, the maximum site severity can be calculated from the most likely level
of pollution severity, (γ mode) (Equation 5-3):
𝟐𝟐
𝜸𝜸𝒎𝒎𝒎𝒎𝒎𝒎 = 𝜸𝜸𝒎𝒎𝒎𝒎𝒎𝒎𝒎𝒎 ∙ 𝒆𝒆�𝟐𝟐.𝟎𝟎𝟎𝟎∙𝝈𝝈 + 𝝈𝝈 � 4.8-5
Eq. 5-3
Where the other parameters are as above.
Step 2: Determine Minimum Contamination Withstand Severity
The minimum withstand is determined by multiplying the maximum site severity by a safety
factor, which should be determined by taking the following factors into account:
•
•
•
•
Number of insulators exposed to the same environment (i.e., parallel insulators).
Differences in pollution accumulation characteristics of the insulator used for the site
pollution severity measurement and the candidate insulator.
If contamination measurements were performed on unenergized units, it could be necessary
to adjust the measured values if heating by leakage current contributes significantly to the
contamination deposit.
Difference in pollution type of the pollution deposit at site and in the test. It was shown in
Figure 3-26 that low-solubility salts have a higher flashover value than marine salt
contamination under Clean-Fog tests. In some cases, it may be warranted to test at a lower
severity level with the standard test to adjust for this.
Differences in the uniformity of the pollution deposit at site and in the test, and the wetting
conditions in service and those during the test; the effects of these two factors have been shown
in Figure 3-29.
•
•
•
Differences in the equipment assembly.
Effect of aging on the pollution catch and wettability of the insulation during the expected
lifetime.
Number of critical wetting events per year.
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Statistical flashover risk calculations have been performed to obtain a guideline for suitable
safety factors that can be used in a deterministic design [61]. The results are presented in Figure
5-21, which shows the safety factor as a function of the number of insulators exposed to the same
environment (i.e., parallel insulators). These calculations were based on the following
assumptions:
•
•
•
•
•
The risk for flashover is once in 50 critical wetting events—i.e., 0.02.
The contamination comprises mostly marine salt.
The insulator flashover voltage determined during testing has a normalized standard
deviation, Cins, of between 6 and 10%.
The statistical distribution of site severity can be described as lognormal, with a standard
deviation of the logarithm of the severity between 0.4 and 0.9.
The withstand characteristic of the insulator is described by the voltage or contamination
severity, where the insulator has a 10% flashover probability.
For typical lines, as indicated by the shaded area in Figure 5-21, the safety factor lies between
1.3 and 1.8.
Figure 5-21
Typical range of a safety factor for transmission-line insulators [61].
Step 3: Verify Insulator Withstand Characteristic with Laboratory Tests
The performance of the insulator can be verified by laboratory tests. In the standards, withstand
tests are described that consist of a maximum of four tests during which only one flashover is
allowed. These tests aim to show that the insulator does not have a flashover probability of
below 10% for the voltage and contamination severity at which the test was performed. There is
an uncertainty in the test outcome, however—i.e., an insulator with a lower than 10% flashover
probability may pass the test, because only a limited number of tests are performed.
11762887
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It is possible to overcome this lack of discrimination by performing more than the prescribed
four laboratory tests, but these additional tests can be costly. Another method is to perform the
withstand test at a higher voltage or contamination severity to compensate for the limited number
of tests performed.
For line insulators, it is more feasible, however, to base the verification tests on determining the
50% flashover voltage, V50. This determination can be made by a relatively small number of
tests if variable voltage application techniques are used [70]. These tests are performed at the
minimum withstand severity, as determined by the deterministic method. The withstand voltage,
V10, for the tested can then be calculated by (Equation 5-4):
Eq. 5-4
𝑽𝑽𝟏𝟏𝟏𝟏 = (𝟏𝟏 − 𝟏𝟏. 𝟐𝟐𝟐𝟐 ∙ 𝒄𝒄𝒊𝒊𝒊𝒊𝒊𝒊 )𝑽𝑽𝟓𝟓𝟓𝟓
where Cins is the normalized standard deviation of the flashover voltage, which is typically on the
order of 0.06 to 0.1 for laboratory tests.
The insulator is approved for service if the calculated withstand voltage level is above the
maximum continuous operating voltage.
Statistical Method
A statistical method can be used to calculate the required insulator dimensions for a specific site
based on a full risk of flashover assessment. When performing the statistical method, the
following aspects should be considered:
•
•
•
•
•
•
•
•
Number of insulators that will be exposed to the same environment (i.e., parallel insulators).
Differences in pollution accumulation characteristics of the insulator used for the site
pollution severity measurement and the candidate insulator.
If contamination measurements were performed on unenergized units, it could be necessary
to adjust the measured values if heating by leakage current contributes significantly to the
contamination deposit.
Difference in pollution type of the pollution deposit at the site and in the test. It was shown in
Figure 3-26 that low-solubility salts have a higher flashover value than marine salt
contamination under Clean-Fog tests. In some cases, it may be warranted to test at a lower
severity level with the standard test to adjust for this.
Differences in the uniformity of the pollution deposit at the site and in the test, and the
wetting conditions in service and those during the test; the effects of these two factors have
been shown in Figure 3-29.
Differences in the equipment assembly.
Effect of aging on the pollution catch and wettability of the insulation during the expected
lifetime.
Number of critical wetting events per year.
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The statistical method methodology has the following steps:
1. Site contamination severity and wetting intensity
Input:
A sufficient number of site severity measurements.
Output: A probability density function describing the site severity.
2. Insulator flashover characteristic
Input:
Laboratory flashover test results at a range of contamination severity.
Output: A curve describing the flashover voltage as a function of the contamination
severity.
3. Insulator flashover probability as a function of the pollution severity
Input:
A curve describing the flashover voltage as a function of the contamination
severity.
Output: The flashover probability as a function of the contamination severity for a specific
insulator length.
4. The effect of parallel insulators
5. The probability function obtained in step 3 is adjusted for the number of parallel insulators.
6. Risk of flashover evaluation
Input:
A probability density function describing the site severity.
7. The flashover probability as a function of the contamination severity for a specific insulator
length and number of parallel insulators.
Output: The risk of flashover.
Each step will be discussed in some detail below with the help of a practical example. In this
example, ESDD measurements are used, since it is the most representative of the American
environment. It should be noted that this method is essentially the same for other site severity
and laboratory testing techniques, such as the Site Equivalent Salinity and the Salt-Fog test.
Step 1: Site Contamination Severity and Wetting Intensity
With sufficient pollution-severity measurements available, a suitable distribution function can be
fitted to obtain a statistical description of the pollution stress at the site. An example of ESDD
measurements on a standard-shape glass disc insulator string over a period of 55 months is
shown in Figure 5-22.
These values are sorted from low to high, and the cumulative probability of each data point, fi(i),
is calculated as (Equation 5-5):
𝒇𝒇𝒊𝒊 (𝒊𝒊) = 𝟏𝟏 −
(𝒊𝒊−𝟎𝟎.𝟑𝟑𝟑𝟑𝟑𝟑)
(𝑵𝑵+𝟎𝟎.𝟐𝟐𝟐𝟐)
4.8-7
Eq. 5-5
Where “i” is the index of the datapoint and “N” is the total number of datapoints in the set.
A suitable cumulative distribution function, such as the lognormal distribution function, can be
fitted through these points by utilizing statistical techniques (e.g., the method of maximum
likelihood) or by graphical means (i.e., a straight line fit on lognormal graph paper) [68]. The
sorted site severity measurements and the fitted distribution function are shown in Figure 5-23.
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Measured ESDD value [mg/cm 2]
0.07
0.06
0.05
0.04
0.03
0.02
0.01
0
0
10
20
30
Month
40
50
60
Figure 5-22
Time variation of ESDD measurements at a coastal site.
Figure 5-23
Typical results from pollution site severity measurements and the fitted lognormal distribution.
The pollution severity of a site is usually characterized by the 2% severity, which is the severity
having a 2% probability of being exceeded, and the standard deviation of the logarithm of the
site severity measurements. In the example presented here, the 2% severity level is an ESDD
level of 0.06 mg/cm2 and the standard deviation of ln (ESDD) of 0.55.
It has been suggested that double-contingency analysis be performed to take account of the
independent variation of the contamination severity and the degree of wetting [70]. This analysis
would require a two-dimensional risk-of-flashover assessment. However, this approach is rarely
feasible, as the insulator strength is not evaluated under different wetting conditions (i.e., the
standard laboratory tests only test insulators under critical wetting conditions). To enable a
single-contingency analysis, it is conservatively assumed that all wetting events are critical.
11762887
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Step 2: Insulator Flashover Characteristic
The insulator flashover probability needs to be described in terms of the contamination severity.
To do this in a cost-effective way, laboratory tests (e.g., Clean-Fog or Salt-Fog) are performed to
determine the 50% flashover voltage, (V50), and standard deviation, (σ), at two or, preferably,
more test severities. A power law function can then be fitted through the data points to obtain a
mathematical description of the V50 as a function of the contamination severity, as discussed
above. An example of such a relationship is shown in Figure 5-24. This example uses the
average relationship for standard-shape insulators listed in Table 3-4 for the Clean-Fog test.
Unified Specific Creepage distance
(mm/kV)
50
0.0
45
0.1
40
0.5
35
0.9
30
0.999
25
20
Probability for flashover
0.0
0.1
0.5
0.9
0.999
15
10
5
0
0.001
0.01
0.1
1
2
Contamination severity (ESDD; mg/cm )
Figure 5-24
Insulator flashover characteristic as derived through laboratory tests. The standard deviation is
assumed to be 8%. (The solid curve is the withstand characteristic (V10) of the standard shape
insulator.)
This V50 curve can then be used to calculate a family of curves, each describing a different
probability of flashover, as shown in Figure 5-24. This is relatively easily done by using the
inverse probability function characteristics found in standard tables. For example, at a specific
contamination severity and assuming a normal distribution function, the 10% flashover value,
V10, can be calculated from the 50% flashover voltage, V50, and the normalized standard
deviation, cins = σins/V50, from Equation 5-4.
Similar relations exist for the other flashover probabilities.
Step 3: Insulator Flashover Probability as Function of Pollution Severity
The curves in Figure 5-24 can then be used to derive a function describing the probability of
flashover in terms of the contamination severity of a specific insulator. This process is illustrated
in Figure 5-25 for an insulator with a unified specific creepage distance of 28 mm/kV. As
illustrated in the figure, the probability of flashover for each contamination level is where the
service stress line intersects with the probability curves. It can also be derived analytically if the
insulator flashover voltage is described by a Weibull distribution function [62].
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Unified Specific Creepage
distance (mm/kV)
45
0.0
0.1
0.5
0.9
0.999
40
35
30
25
1
0.0
Probability for flashover
0.1
0.9
0.5
0.8
0.9
0.7
0.999
0.6
Service stress = 28 mm/kV
0.5
20
0.4
15
0.3
10
0.2
Insulator flashover
characteristic
5
0
0.001
0.1
Probability for flashover
0.01
0.1
Probability for flashover
50
0
1
2
2
Contamination severity (ESDD; mg/cm )
Figure 5-25
Derivation of the insulator flashover probability as a function of contamination severity.
Step 4: Effect of Parallel Insulators
The next step is to take account of the number of insulators exposed to the same conditions. As
mentioned previously, this can be done with Equation 5-1. Figure 5-26 shows the flashover
characteristic of one insulator, from Figure 5-25, and that derived for 120 parallel insulators.
1
Probability for flashover
0.9
0.8
120 insulators
0.7
0.6
0.5
One insulator
0.4
0.3
0.2
0.1
0
0.001
0.01
0.1
Contamination Severity (ESDD: mg/cm2)
Figure 5-26
Derived probability for flashover characteristic for one and 120 insulators.
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1
Step 5: Evaluation of Risk of Flashover
50
1
45
0.9
40
0.8
35
0.7
30
0.6
25
0.5
20
0.4
15
0.3
Risk for flashover
10
0.2
Strength: Probability for
flashover
Severity: Density of occurance
Enough information is now available to evaluate the risk of flashover for 120 insulators installed
in the environment with a severity characteristic as derived in the first step. This is shown in
Figure 5-27, where the contamination severity density function (from Figure 5-23) is multiplied
with the insulator flashover probability curve (from Figure 5-26), and the area beneath this
derived curve is the risk of flashover. This has numerically been calculated to be 0.028, or
approximately one flashover in 36 critical wetting events.
0.1
5
0
0.001
0
0.01
0.1
Contamination Severity (ESDD: mg/cm2)
1
Figure 5-27
Calculating the risk of flashover from the site severity and the insulator flashover characteristic.
With this calculation, the fraction of critical events that will lead to flashover has been
determined. This value can be expressed as the contamination flashover rate (CFOR) per year by
taking account of the average number of wetting events (Nevents) that take place each year
(Equation 5-6):
𝑪𝑪𝑪𝑪𝑪𝑪𝑪𝑪 = 𝑵𝑵𝒆𝒆𝒆𝒆𝒆𝒆𝒆𝒆𝒆𝒆𝒆𝒆 ∙ 𝑹𝑹𝑹𝑹𝑹𝑹𝑹𝑹 𝒑𝒑𝒑𝒑𝒑𝒑 𝒆𝒆𝒆𝒆𝒆𝒆𝒆𝒆𝒆𝒆 4.8-8
Eq. 5-6
For a site where 10 critical wetting events occur per year, the CFOR can be calculated as 0.28
flashovers per year, or on average one flashover each 3.6 years.
If this flashover rate is unacceptably high, an insulator with a higher unified specific creepage
distance is selected and the risk of flashover is re-evaluated. This process is repeated until an
insulator with an acceptable risk of flashover is found.
This calculation can then be repeated at different contamination severities to obtain a “design
curve” for that particular insulator type. An example of such a curve is shown in Figure 5-28 in
comparison with a typically used creepage distance requirement. The performance is expressed
in risk of flashover per critical wetting event.
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70
Std Deviation of Ln(ESDD) = 0.777
No of parallel insulators 60
Std Deviation insulator 8%
Required USCD [mm/kV]
60
50
40
30
Risk = 0.2/per event
20
Risk = 0.02/per event
Risk = 0.002/per event
10
IEC Requirement
0
0.01
0.1
1
10
2% Contamination Deverity [ESDD: mg/cm2]
Figure 5-28
Design curve for a typical standard-shape disc insulator for three different levels of the risk of
flashover.
A software implementation of the statistical method has become available, and its results show
good agreement with Russian dimensioning criteria [72].
Guidelines for Limiting the Effect of E-Fields on Insulators
E-Field Distribution on Polymer Insulators
The E-field distribution on the surface of and within polymer insulators is a function of
numerous parameters including voltage class, insulator design, tower configuration, phase
spacing, etc. The following discussion will provide generalized information that relates to the Efield distribution of most transmission-line applications. Applications may arise, both on
transmission lines and in substations, where the E-field distributions will differ from those
presented in the following section.
In general, the E-field magnitudes are larger close to the energized and grounded ends of a
polymer insulator. In some cases, the position of highest E-field occurs adjacent to the end
fitting, while in other cases, it may occur a short distance away from the end fitting. The case
where the position of highest E-field magnitude occurs adjacent to the end fitting is illustrated in
Figure 5-29, which shows a shaded plot of the E-field magnitude distribution on the polymer
housing surface of a 230-kV suspension polymer insulator as well as lines of equal potential.
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Figure 5-29
Shaded plot of the E-field distribution on the surface of a polymer insulator and the equipotential
lines in the air surrounding the unit. The E-field magnitude is indicated in grayscale, with white
being the highest and black the lowest.
As can be seen from Figure 5-29, the magnitude of the E-field close to the energized end is
higher than that at the grounded end. It can also be seen from the equipotential lines surrounding
the polymer insulator in Figure 5-29 that the direction of the E-field is mainly axial—i.e., in the
same direction as the fiberglass rod [75] [76] [77].
Figure 5-30 is a plot of the normalized E-field magnitude within the fiberglass rod of a 115-kV
I-string measured along an axial line. As can be seen from Figure 5-30, the E-field magnitude is
high at the energized end and decreases exponentially. The field magnitude increases again at the
grounded end, but the maximum value reached is lower than that at the energized end.
Although the distribution indicated in Figure 5-30 is common for many situations, applications
arise where this may not be the case. Most significantly, for certain designs of overhead
transmission-line polymer insulators, the corona ring results in the highest E-field magnitude
occurring a short distance away from the end fitting rather than adjacent to the end fitting. An
example of this is illustrated in Figure 5-31.
It can be seen in Figure 5-31 that the presence of the corona ring has shifted the position of
highest E-field three sheds away from the energized end fitting. The application of a corona ring
does not always result in the point of maximum E-field being shifted away from the area
adjacent to the end fitting. Whether this shifting will occur depends on the dimensions of the
corona ring, its location, and the configuration geometry [75] [78].
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Normalized E-field Magtnitude
1
0.8
0.6
0.4
0.2
0
0
0.4
0.2
0.6
0.8
1
Normalized Distance measured from Energized End Fitting
Figure 5-30
Example of the normalized E-field magnitude within the fiberglass rod of a suspension I-string
115-kV polymer insulator determined using three-dimensional finite elements modeling. The axial
measurement line starts at the energized end fitting and ends at the grounded end fitting.
Normalized E-field
250
1.1
200
0.9
150
0.7
100
0.5
50
0.3
00
0
5
5
10
10
15
15
20
20
25
25
Shed Position from Live End
30
30
35
35
40
40
Shed Number (counted from energized end)
Figure 5-31
E-field profile measured along a suspension 500-kV V-sting polymer insulator using a field probe.
The unit has a corona ring in place on both the live and grounded ends.
Factors that Influence the E-Field Distribution
Numerous factors influence the E-field distribution of polymer insulators. The most important
factors include [25] [79]:
1. Insulator geometry including housing with sheds, fiberglass rod, and end fittings.
2. Electrical properties of housing polymer, fiberglass rod material, and any semi-conductive
grading that may be included.
3. The dimensions and position of the corona rings, as well as the attachment hardware.
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4. The geometry of the attachment hardware, conductor bundles, grounded hardware, and line
structure.
5. The orientation of the polymer insulator and its physical relationship to the attachment
hardware, corona rings, conductor bundles, grounded hardware, and line structure.
6. Energized line voltage.
7. Presence of nearby phases.
Each of these parameters needs to be taken into account when determining the E-field
distribution of a polymer insulator utilizing either modeling or measurement techniques.
Depending on the case, these parameters may have a larger or reduced effect on the E-field
distribution.
Due to the dependence of the E-field distribution on this range of parameters, identical polymer
insulators applied in different situations may have different E-field distributions, and similarly,
different polymer insulator designs applied in the same situation may have different E-field
distributions.
Regions of Interest
The distribution of the E-field distribution magnitude is of interest in three main regions of the
polymer insulators:
1. Within the fiberglass rod and polymer housing material.
2. On the surface, and in the air surrounding, the polymer housing surface and surrounding the
end-fitting seal.
3. On and in the air surrounding the metallic end fittings and attached corona rings.
If the E-field magnitude in any of these three regions exceeds critical values, unwanted or
excessively large magnitudes of discharge activity may occur, affecting either the long- or shortterm performance.
Discharge Activity
The presence, location, and magnitude of discharges are a function of both the E-field magnitude
and direction. Four categories of discharges are of concern:
•
•
Discharges internal to the fiberglass rod and polymer housing material or at the interface
between the rod and housing system. If a critical E-field magnitude is exceeded, defects
(such as voids or inclusions) may result in internal discharge activity. This internal discharge
activity may result in destruction of the rod or housing material [80].
Corona discharges on the surface of, or in contact with, the polymer housing material and/or
end-fitting seals. Corona activity, either under dry or wetting conditions, has been shown to
result in degradation or changes in the surface properties of the polymer housing material.
[81] [82] [83] [84].
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Arcing activity that may occur in the high E-field region under wetting conditions will also result
in degradation of the rubber material and/or end fitting seal. Arcing activity is generally more
damaging than corona activity due to its high-energy nature. Arcing may occur between patches
of water on the surface of the polymer insulator. This activity is more likely on surfaces that have
lower values of hydrophobicity [85].
Research has shown that corona activity, due to water drops or poorly graded metallic end
fittings, may result in a hydrophobic surface losing some of its hydrophobicity. This loss of
hydrophobicity allows patches of water to form that, in turn, result in arcing activity. The high
energy of the arcing activity may result in more severe degradation of the rubber material.
Dry band arcing under contaminated conditions. Under critical wetting conditions,
contaminated insulators may have leakage currents and dry band arcing on the polymer
housing surfaces. The occurrence and magnitude, and hence the destructive nature of the
arcs, are influenced by the E-field magnitude.
Electrostatic forces result in contamination and moisture being drawn in the direction of the
high electric field, resulting in increased accumulation in the high E-field magnitude regions.
This effect is considered secondary for polymer insulators applied on ac transmission lines.
Corona activity from metallic end fittings or corona rings. High E-field magnitudes on
the surface of the metallic end fittings and corona rings can result in corona activity under
dry conditions. These discharges result in electromagnetic interference and/or audible noise
that, in turn, may result in customer complaints. If this discharge activity is in contact with
the rubber housing system or end fitting seal, degradation may occur. Figure 4.6-7 shows
such activity [86] [38].
•
•
Recommended E-Field Limits for Polymer Insulators
Based on the present understanding of the ageing mechanisms EPRI has determined a set of
threshold levels for the E-field distribution on polymer insulators. These are presented in Table
5-6 for insulators of all voltage levels installed at or close to sea level. Adjustments to these
limits are needed for installations at altitudes of higher than 3,300 feet (1,000 m). It should be
noted however that these limits are still provisional which may be adjusted as more experience is
gained.
Table 5-6
In summary the EPRI recommendations on Electric field limits for Polymer Insulators.
Type
Insulator Component
A
Dry corona
End fittings
Corona Rings
B
Wet corona
Sheath
E-Field Limit [kV/mm]
Testing
Calculation
1.7 - 2.1*
Yes
Yes
0.42 for more than 10 mm
No
Yes
0.35*
No
Yes
End fitting seal
Note: * At present there are not yet consensus on an appropriate value and they are therefore still under review.
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With reference to Table 5-6, the EPRI criteria can be described as follows:
Requirement A: Dry Discharges from Metal End Fitting:
There should be no discharge activity on the metal end fitting under dry conditions when the
units are applied in-service. It is critical that the end fitting be designed such that discharges, if
they do occur are not in contact with the housing or the end fitting seal. There are two methods
of verifying that the metal end fittings will be corona free under dry conditions:
1. This can be verified in mockup testing as described in the IEC Standard 61284 [73] using
optical (or UV) observations to determine whether discharge activity is occurring from the
metal end fitting under dry conditions.
2. It can also be verified by E-field modeling to show that the E-field on the end fitting within
100 mm of the rubber weather shed material or the end fitting seal is below a threshold of
1.7-2.1 kV/mm. Work is presently underway to refine this limit.
Requirement B: Non-Uniform Wetting Discharge Activity:
Excessive discharge activity under wetting conditions that is contact with either the rubber
housing material or the end-fitting seal should be avoided. This can be achieved by limiting the
E-field magnitude so that it does not exceed 0.42 kV/mm over a distance of more than 10 mm on
the sheath of the housing and 0.35 kV/mm at the critical end fitting seal.
Adjustment for High Altitudes:
The adjusted E-field limit can be by following the procedure given in IEEE Std. 4-1995, IEEE
Standard Techniques for High-Voltage Testing. The adjustment for is a ratio of the relative air
density. Simplified, the adjustment for the E-field thresholds becomes:
Ealtityude = δ ⋅ ESeaLevel
Eq. 5-7
• Where δ is the relative air density and E is the E-field.
The mean air density as a function of height above sea level is given by [60]:
δ = ⋅e
•
 −A 


 8600 
Eq. 5-8
Where δ is the relative air density and A is the height above sea level in meter.
General Comments:
Experience with applying these recommendations have shown that:
•
•
•
If an insulator fails to meet Requirement A it will in most cases fail to meet Requirement B
In most cases failure to meet Requirement A would result in a failure in a much shorter time
span than an insulator that fails only Requirement B
Experimental results[74] indicates that Requirement A is more important than previously
believed. Contrary to some insulator catalogue recommendations it is found that corona rings
are in some cases necessary to prevent dry corona from insulator end fittings on 115 and
138 kV systems.
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Selecting Corona Rings for Polymer Insulators
To grade the E-field to below the recommended limits, corona rings are applied in many
configurations. Although generic recommendations may be made, they often result in
misapplication due to the variety of applications and the lack of definition of key parameters,
such as ring size and location. It is preferable that the rings be selected based on E-field
modeling, together with testing in accordance with electric field-based methods [87] [92].
Recommendations in Table 5-7 are generic and do not account for corona ring size or differences
in configurations. The authors caution the reader in using the table for nonstandard applications.
Table 5-7
Generic Recommendations for Corona Rings. (Note that ring dimensions and locations are not
defined. Note that this table is under continual development as the industry’s understanding of
the issue increases.) [90] [91] [88]
Insulator Type
System Voltage (kV)
V < 100 kV
100 kV < V < 161
161<= V < 230
230 <= V <= 345
345 < V
Suspension Units
-
Line-end
Line-end
Line-end
Line-end
Ground-end
Dead-End Units
-
Line-end
Line-end
Line-end
Line-end
Ground-end
Phase-to-Phase
Spacers
-
Both ends
Both ends
Both ends
Both ends
Braced Post
-
Live end of
suspension unit
Live end of
suspension unit
Live end of
suspension unit
Line-Posts
-
-
Line-end maybe
Line-end
The recommendations in Table 5-7 are stricter than present industry practice, as corona rings are
also required on insulators at 115 and 138 kV insulators. This revision was deemed necessary
after an EPRI investigation found that several insulator failures at 115 kV and 138 kV could be
attributed to high electric fields (E-fields) occurring close to, or on, the high-voltage end fittings
of these insulators [88] [89].
At voltages greater than 345 kV, separate E-field grading devices attached to the energized
hardware may be used, together with the corona rings attached to the polymer insulator. The
combination of the corona rings and grading devices controls the distribution of the E-field.
Due to the differences in geometry, different corona ring designs may be selected for suspension
and dead-end applications on the same line. However, most utilities select only one size to
reduce confusion both during construction and maintenance.
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The dimensions and locations of corona rings from various manufacturers vary considerably, as
do the E-field distributions, as shown in Table 5-8 and Figure 5-32. It is, therefore, not sufficient
to just specify the need for rings, as is done Table 5-7, because this will not necessarily ensure
that the E-field limits are met. Often additional measures, such as E-field modeling, are
performed with the unit installed in the configuration of interest to confirm that the E-field
magnitudes are kept below the limits specified in the sections above. Details on the correct
E-field modeling methods to utilize are provided in the sections that follow and elsewhere [90]
[91] and EPRI has also developed software to aid in this task [92].
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Table 5-8
Comparison of Generic Recommendations Obtained for Four Different Insulator Designs (It should be noted that these are generic
recommendations; manufacturers may adjust recommendations for different configurations or situations.)
Manufacturer W
Manufacturer X
Manufacturer Y
Manufacturer Z
Energized
End (in.)
Grounded
End (in.)
Energized
End (in.)
Grounded
End (in.)
Energized
End (in.)
Grounded
End (in.)
Energized
End (in.)
Grounded
End (in.)
None
None
6.4 or 7.8
None
None
None
None
None
200-230 kV
8
None
6.4 or 7.8
None
8
None
11
None
300-345 kV
12
None
7.8
None
12
None
11
None
400 kV
12
8
13.8
None
12
None (1)
15
None (1)
500 kV
15
12
17.7
7.8
17
8
15
11
756 kV
15
12
(2)
(2)
17
12
16
16
161 kV
Notes:
1. May be required in certain applications.
2. Special design required.
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1.6
Standard Practice
1.4
Same insulator design
different configs:
W & W/O rings
Maximum E-field [kV/mm]
1.2
1
Non-Standard Practice
Special configurations
Recommended Threshold
Same insulator design different
configs: W & W/O rings
0.8
0.6
0.4
0.2
0
Comparison of different
designs in same config
0
100
200
300
400
500
Nominal System Voltage [kV]
600
700
800
Figure 5-32
Maximum E-field magnitudes (rms) on the sheath sections of polymer insulators modeled as a
function of system voltage. (All models account only for the presence of a single phase [93]
Several practical considerations need to be accounted for when designing/selecting a corona ring:
•
•
•
•
•
•
•
A reasonable clearance is necessary between the corona ring and the housing of the insulator
being graded and nearby insulators.
- Concerns have been raised in braced post configurations, where the suspension unit
corona ring touches the sheds of the post unit.
- Small gaps between the corona ring and the first shed have been shown to result in high
levels of discharge activity.
Interference between the corona ring and other hardware should be avoided.
Corona ring should be easily installed and removed when insulator is installed.
- Note: This maybe accomplished using a design with a gap in the ring. When using
multiple insulators in the connection, the facing the gaps towards each other can optimize
the effectiveness of the corona rings.
Corona ring should not prevent access to end hardware for live line work (e.g., access to
cotter key).
Ring should have a simple locking/keying mechanism to ensure that it is installed in the
correct location/position.
The ring should be able to withstand the required level of vibration.
Power arc termination on the ring should not expose the end fitting seal or housing system to
undue stresses.
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•
•
•
The corona ring should be able to withstand specific levels of power arc current without
sustaining considerable damage.
The resulting reduction in the dry arc distance needs to be considered.
Inclusion of corona rings in certain V-string (and possibly I-string) applications has increased
the risk of bird streamer outages.
The selection or corona rings is often complicated when units from a range of manufacturers are
installed on the same system. Since corona rings are manufacturer-specific, different corona ring
designs need to be stocked for maintenance purposes, and maintenance staff need to be trained to
select the correct ring for the insulator selected.
Verification of Corona Rings for Polymer Insulators
Introduction
When buying new insulators, utilities must ensure that the insulator designs contain features that
limit the E-field gradients on the polymer insulators to below the levels that would result in
premature aging. This is not a trivial task as there is not yet international consensus on the
methods and tests applicable to verify that new designs fulfill this criterion. A further
complication is the fact that the E-field on the insulator is determined to a large extent by its
application, something that does not fall in the control of the manufacturer. Traditionally for
glass and porcelain insulators the design of corona rings and grading devices fell outside the
responsibilities of the insulator manufacturer since the insulators was not affected significantly
by high electric fields. On polymer insulators this is different, and a more integrated approach
needs to be followed. Such an approach may contain the following aspects:
•
•
•
E-field calculations to verify that the limits for water induced corona and continuous dry
corona is not exceeded.
High Voltage Testing to confirm that the end fitting, seal and/or corona ring design and
materials used is free from continuous corona.
Experience and Industry Information are used to evaluate designs and identify possible
weaknesses.
A brief description of these approaches is provided below.
E-Field Calculations
E-field calculation is presently the only way to guarantee that E-field on the insulator will not
exceed dry and wet corona limits given at the start of this chapter. The experiences with 115 and
138 kV insulators certainly underline the necessity for such calculations to determine the need
for corona rings before insulators are installed. On higher voltages E-field calculations are even
more crucial not only to determine the need for corona rings, but also to determine its position
and size.
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Previously such wide implementation of E-field calculations was not practical due to the
computational and specialized manpower resources required, but this has changed with the
release of EPIC software which is specifically designed to calculate the E-field on polymer
insulators in typical transmission configurations in 3-D. Users should still be careful to include
the necessary details in the E-field models. Requirements for E-field calculations are provided in
Annex B.
High Voltage Testing
High voltage testing can be performed on polymer insulators and their grading rings, if present,
to ensure that the metallic components is free of visible corona. In this section general
considerations are given regarding test arrangements and procedures to determine the corona
onset or extinction voltage of the test object. For such testing it is necessary to select the test
setup and the test voltage so that the same surface E-field is obtained on the insulator hardware
during the test as what it will be subjected to under service conditions.
High voltage testing is generally limited to verify that the assembly being tested is free from
visible corona under dry conditions. As such it verifies the correctness of the chosen grading
devices and also that the finish of the hardware components is free perturbations that could give
rise to corona. Corona testing under wet conditions is at present not considered practical the
conditions for such a test cannot defined sufficiently to obtain repeatable results.
In view of the limited scope achievable with high voltages testing, it is recommended that tests
are only performed on the insulator assembly with the highest E-field, normally a single insulator
dead-end structures. This test is then regarded as sufficient for all other structures with the same
insulator-ring combination.
For lines, the only way to evaluate the corona performance correctly will be to perform the test
on a three-phase, full-scale mockup of the tower in an open-field setup. The electric fields
around such a test set-up would exactly match those on the actual line. However, this type of
testing is prohibitively expensive and only a very few laboratories have facilities to allow such
testing. A less than perfect alternative is to perform the test on a single-phase set-up and to adjust
the test voltage so that the E-field on the hardware approximate that of the service condition as
closely as possible. The phase to ground test voltage is therefore often different from the actual
phase to ground voltage of the system to compensate for:
1. The absence of the other two phases.
2. The absence of other circuits on the same structure.
3. The proximity of “unnatural” ground planes such as walls and a test setup which is closer to
ground than on the actual structure.
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Such a test method is described in the IEC Standard 61284 [73], which describes two options for
corona testing.
1. Voltage method: whereby a test setup is exactly defined together with a corresponding test
voltage at which the test shall be performed. These test setups include the use of large ground
planes to simulate the presence of the other energized phases.
2. Voltage gradient method: An intentional perturbation on the test setup conductor is used to
obtain the relationship between the test voltage and the surface E-field on the conductor. This
is possible as this perturbation, usually in the form of a small ball bearing, presents an easy
identifiable corona source that goes into corona in a predictable manner.
Both methods are based on designing an equivalent single-phase test setup that replicates the
E-service E-field gradient on the conductor (or conductor bundle) when installed on an actual
transmission line. These test methods and their limitations are explored by way of an example.
Consider the single circuit 3-phase 138 kV line shown in Figure 5-33. This line has a 3.13 m
vertical phase spacing and the suspension insulator assemblies have a total connection length of
about 1.7 m. The aim is to devise a single-phase test setup and test voltage that would result on
the same E-field on the insulator and its hardware.
For this example, four single phase test setups are considered, of which two are shown in Figure
5-33. It comprises a mockup of the tower, cross-arm and insulator assembly that is identical to
the three-phase line but with different heights (i.e., 22.9 m, 7.4 m, 5.4 m and 3.4 m) of the
energized conductor. The highest single-phase conductor placement, i.e., 22.9 m, which
corresponds approximately to that of the middle phase on the 3-phase line. This is because the
insulator on the middle phase of this particular line configuration is subjected to the highest Efields. The other conductor heights (i.e., 3.4 m to 7.4 m) are considered typical of indoor testing.
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3- Phase line
1 phase at 22.9 m
1 phase at 5.4 m
Figure 5-33
A 138 kV single circuit 3-phase transmission line (left) and two single phase test setups.
EPRI’s Insulator Calculation Engine (ICE) E-field modeling software package was used to
calculate the E-fields on middle phase polymer insulator of the 3-phase line and on the singlephase test setups. The maximum E-fields are listed in Table 5-9 and the E-field profiles are
shown in Figure 5-34 for the end fittings and in Figure 5-35 for the E-fields on the sheath of the
insulators.
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3
3
2.5
2.5
2
2
Actual 3-phase Line
Single Phase: H = 22.86 m
Single Phase: H = 7.39 m
E-field [kV/mm]
E-field [kV/mm]
Single Phase: H = 3.39 m
1.5
1
Actual 3-phase Line
Single Phase: H = 22.86 m
0.5
1.5
1
0.5
Single Phase: H = 7.39 m
Single Phase: H = 3.39 m
0
-21
-18
-15
-9
-12
-3
-6
0
0
0
Distance along End Fitting [mm]
3
6
9
12
15
18
21
Distance along End Fitting [mm]
Figure 5-34
The E-field on a suspension insulator end fitting on a 3-phase line compared with two single
phase setups. (Energized end on left and grounded end on right)
1.6
1.4
Single Phase: H = 22.86 m
Actual 3-phase Line
1.4
Single Phase: H = 22.86 m
Single Phase: H = 7.39 m
1.2
1
0.8
0.6
0.8
0.6
0.4
0.2
0.2
0
20
40
60
80
100
120
Distance along Sheath [mm]
Single Phase: H = 3.39 m
1
0.4
0
Single Phase: H = 7.39 m
1.2
Single Phase: H = 3.39 m
E-field [kV/mm]
E-field [kV/mm]
1.6
Actual 3-phase Line
0
-120
-100
-80
-60
-40
-20
0
Distance along Sheath [mm]
Figure 5-35
The E-field on a suspension insulator sheath on a 3-phase line compared with two single phase
setups. (Energized end on left and grounded end on right)
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Table 5-9
Calculated maximum E-field on the polymer insulators in the configurations shown in Figure 5-33.
Three Phase
Single Phase
Top
Middle
Bottom
Test 1
Test 2
Test 3
Test 4
[m]
25.87
22.74
19.61
22.86
7.39
5.39
3.39
[kV/mm]
9.919
10.62
9.901
8.341
9.017
9.264
9.73
--
2.71
2.59
2.08
2.23
2.28
2.38
Energized end - Sheath
1.36
1.48
1.42
1.15
1.23
1.25
1.30
Grounded end - Sheath
--
0.39
0.29
0.57
0.48
0.45
0.40
Grounded - End fitting
--
0.72
0.52
1.03
0.86
0.81
0.71
Height of conductor
Phase Conductor
Energized - End fitting
The results show that the E-field on the energized end fitting of the insulator for the single-phase
setup with a conductor height of 23 m is 23% lower than that on the 3-phase setup. This means
that the test voltage applied to the single-phase setup should be 30.2% higher (i.e., 100/77%)
than the phase to ground voltage of the 3-phase line to reproduce the same E-field on the end
fitting. This process can be repeated for the other insulator components (i.e., the sheath and other
end fitting of the insulator) and the phase conductor. The results are presented in Table 5-10.
Table 5-10
Required test voltages for the configurations considered.
Test Voltage in Percent of the Phase to Ground System Voltage
Three-Phase
Single Phase
Height of conductor
m
22.74
22.86
7.39
5.39
3.39
Phase Conductor
%
100
127.3
117.7
114.6
109.1
Energized - End fitting
%
100
130.2
121.4
118.7
114
Energized end - Sheath
%
100
129.3
120.8
118.1
113.6
Grounded end - Sheath
%
100
68.49
81.72
87.02
98.23
Grounded - End fitting
%
100
69.46
83.08
88.72
100.4
The table shows that test voltage for a single-phase setup needs to be adjusted according to
where on the insulator the electric field need to be replicated. For example, the E-field on the
phase conductor of the 5.4 m single phase setup is the same as that in the 3-phase setup if the test
voltage is equal to 115% of the phase to ground voltage. To get the correct E-field on the end
fitting in the same setup would require a test voltage of only 119%. In other words, a test with
the correct E-field on the conductor would result in an E-field on the end fitting which is lower
than that in service.
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The table further shows that the single-phase test is much worse at replicating the E-field at the
grounded end of the insulator. It so happens that these E-fields can be much higher in the singlephase setup than on the actual transmission line. Although this is not a great concern at 115 and
138 kV tests, as the E-field is much lower than the dry corona inception field, it should be
considered for test at higher transmission voltages such as 400 kV and higher where corona rings
are considered on the grounded side of the insulator.
It is important to note that the values above serve to illustrate the problem of single-phase
testing, and they are therefore only valid for the example considered. Other configurations and
insulators will result in a different distribution of E-field and accordingly different test voltages,
but the overall trends should be the same.
From the above results it becomes clear that the only “correct” way to design a single-phase test
setup is to perform 3-D E-field calculations much in the same way as is illustrated above. If this
is not possible or practical it is recommended to follow the procedure as described in Annex C.
Experience and Industry Information
Testing may be unnecessary if enough field experience is available for a particular design, but
the following aspects should be taken into account:
•
•
•
•
•
•
•
The design of insulator is similar.
The design and dimensions of corona rings is similar.
That the insulator dimensions are similar, e.g., end fitting, connection length shed profile, etc.
The phase spacing is similar or greater.
That the number of circuits on the structure are the same or less.
That the altitude at which the installation to be installed in is similar.
That the contamination level (and type) is similar or lower.
E-Field Distribution on Glass and Porcelain Insulators
The E-field distribution on disc-type insulator stings is considerably different from polymer
insulators due to the presence of the metallic cap and pins along the entire length of the unit. The
self and mutual capacitance between the cap and pins have the effect of grading the field along
the string length, resulting in maximum E-field magnitudes at the sting ends that are generally
lower than that of a polymer insulator installed without a corona ring in the same application.
The E-field distribution on disc-type insulators may need to be considered for the following
reasons:
•
•
•
•
Corona activity under dry conditions may result in customer complaints due to audible noise
or electromagnetic interference.
Corona activity under dry conditions in the pin region may damage the grout, reducing the
life expectancy. See Figure 5-36.
Corona activity under dry conditions may result in damage to the glaze on porcelain units
after extended exposure.
Corona activity on the metallic surfaces under dry conditions may result in loss of
galvanization, which, in turn, may result in localized corrosion after extended exposure.
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•
•
•
Corona activity and/or high E-fields may damage the porcelain bulk material, resulting in
donut-type failures, as previously discussed. See Figure 4-3 [94].
Puncture due to steep front lightning impulses. See Chapter 4 (Steep Front Voltage).
Corona-induced flashovers in clean environments [95].
Figure 5-36
Top: Images of corona activity on the first bell of a 765-kV insulator string with no grading devices
installed. Bottom: Corona activity surrounding the pin of a porcelain insulator disc under dry
conditions.
Unlike polymer insulators, wet corona activity on porcelain and glass insulator stings is generally
not a consideration due to the durability and aging characteristics of porcelain and glass.
To address the above issues, corona rings and arcing horns may be applied. Another benefit of
applying rings and horns is that they are often the preferential termination point for power arcs
reducing the probability of damage to the insulator. Corona rings and arcing horns are usually
applied to the line end hardware, not to the insulators themselves. The rings are designed to
prevent corona from the hardware, as well as grade the E-field in, on, and around the insulators
themselves.
Corona rings and E-field grading hardware are generally not utilized directly on insulator strings
for applications at voltages lower than 345 kV. Field grading of 765-kV insulator strings has
been shown to be important to prevent customer complaints and avoid reduction in life
expectancy (see Chapter 4). Arcing horns have been applied at all voltage levels.
Other Considerations
Corrosive Environments
Corrosive environments include hot and humid environments, near the coast where salt in the air
is prevalent, and in the near vicinity of certain industrial plants, particularly of an acid
environment. In these regions, insulators are likely to suffer pin or cap corrosion. Insulators fitted
with a zinc collar or sleeve on the pin are particularly effective in extending the life of insulators.
In addition, some manufacturers will offer a stainless steel pin.
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High Temperature Conductor Applications
On a continuous basis, ACSR usually can be operated at temperatures up to 100°C (212°F) and
for limited time emergencies, at temperatures as high as 125°C (257°F). At these temperatures,
there are no long-term effects on the line end insulator, that may reach a temperature of 75°C
(167°F) in an ambient temperature of 55°C (131°F). However, today’s high-temperature low-sag
(HTLS) conductors have an operating range of 150 to 200°C (302 to 392°F), and in an ambient
of 55°C (131°F), the temperature of the line end unit may be well over 100°C (212°F).
At this time there are no studies that examine the long-term effects of high temperature on
standard porcelain or glass suspension insulators [96], although it is not expected that these types
of insulator will be affected at all.
Polymer insulators may be vulnerable to elevated temperatures due to the material used in its
construction, and tests at EPRI have showed that a conductor temperature of 250°C may elevate
the end fitting temperature to just below 70°C. In a survey of manufacturers, the maximum
recommended end fitting temperatures varied between 70°C and 90°C, depending on
manufacturer [34].
Protection Against Power Arc Damage
Arcing horns are sometimes uses on insulator strings for insulation coordination and as a means
of diverting an arc away from the string, thereby preventing possible damage to the insulators.
The horns, or conductors shaped in the form of a ring, are attached to both ends of strings so
flashovers are encouraged across the horns as opposed to the string itself. They are commonly
used in Europe and in North America they can be found on older systems that have slower fault
detection and clearing times. An assessment of the fault levels and clearing times is required to
determine whether arcing horns may be required.
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Suzuki, Y., T. Fukuta, Y. Mizuno, and K. Naito. 1999. “Probabilistic Assessment of
Flashover Performance of Transmission Lines in Contaminated Areas.” IEEE
Transactions on Dielectrics and Electrical Insulation. Volume 6. Issue 3. June.
Pp. 337–341.
[72]
Gutman, I., K. Halsan, D. Hübinette, E. Solomonik, and L. Vladimirsky. 2004. “New
Developed Insulator Selection Tool (IST) Software: Results of Application Using
Known Russian Service Experience.” 12th Asian Conference on Electrical Discharge.
19–22 November. Shenzhen, China.
[73]
IEC Standard 61284 – 1997. “Overhead Lines – Requirements and Tests for Fittings.”
[74]
EPRI. 2008. Application of Corona Rings on 115/138 kV Polymer Transmission Line
Insulators. EPRI, Palo Alto, CA: October. 1015917.
[75]
EPRI. 1999. Electric Field Modeling of NCI and Grading Ring Design and Application.
EPRI, Palo Alto, CA: December. TR 113-977.
[76]
Zhao, T. and M. G. Comber. 2000. “Calculation of Electric Field and Potential
Distribution along Nonceramic Insulators Considering the Effects of Conductors and
Transmission Towers.” IEEE Transactions on Power Delivery. Volume 15. Issue 1.
January. Pp. 313–318.
[77]
CIGRE. 1992c. “Use of Stress Control Rings on Composite Insulators.” CIGRE Working
Group 03 of SC 22. Electra. No. 143. August. Pp. 69–71.
[78]
Kondo, K. 2002. “Corona Ring Position of Polymer Insulators and Electric Field Stress,”
CIGRE session 2002. Paris. Group 33. Answer to Questions 4.1.5 and 4.2.4.
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[79]
IEEE. 2008. Electric Fields on AC Composite Transmission Line Insulators, IEEE Task
Force Paper, IEEE Transactions on Power Delivery, 2008, Vol. 23, No. 2, pp. 823–830.
[80]
Cherney, E. A. 1991. “Partial Discharge, Part V: PD in Polymer Type Line Insulators.”
IEEE Electrical Insulation Magazine. March/April. Vol. 7. No. 2.
[81]
Phillips A. J., D. J. Childs, and H. M. Schneider. 1999a. “Ageing of Non-Ceramic
Insulators due to Corona from Water Drops.” IEEE Transactions on Power Delivery.
Vol. 14. Pp. 1081–1086.
[82]
Phillips, A. J., D. J. Childs, and H. M. Schneider. 1999b. “Water-Drop Corona Effects on
Full-Scale 500 kV Non-Ceramic Insulators.” IEEE Transactions on Power Delivery.
Vol. 14. Pp. 258–263.
[83]
Moreno, V. M. and R. S. Gorur. 2003. Impact of Corona on the Long-term Performance
of Nonceramic Insulators.” IEEE Transactions on Dielectrics and Electrical Insulation.
Volume 10. Issue 1. February.
[84]
Lopez, I., S. H. Jayaram, and E. A. Cherney. 2001. “A Study of Partial Discharges from
Water Droplets on a Silicone Rubber Insulating Surface.” IEEE Transactions on
Dielectrics and Electrical Insulation. Vol. 8. No. 2. April. p. 262.
[85]
EPRI. 2003a. 230 kV Accelerated Aging Chamber: Condition of NCI After 2 Years of
Aging. EPRI, Palo Alto, CA: 1001746.
[86]
ANSI. 2013b. American National Standard for Composite Insulators—Transmission
Suspension Type: ANSI C29.12-2013. ANSI. New York, N.Y.
[87]
IEEE. 2017. IEEE Guide for Conducting Corona Tests on Hardware for Overhead
Transmission Lines and Substations. IEEE Guide 1829-2017, IEEE Power Engineering
Society, March 17, 2017.
[88]
EPRI 2008b. Application of Corona Rings on 115/138 kV Polymer Transmission Line
Insulators. EPRI, Palo Alto, CA: 1015917.
[89]
Phillips, A. J., A. J. Maxwell, C. S. Engelbrecht, and I. Gutman. 2015. “Electric-Field
Limits for the Design of Grading Rings for Composite Line Insulators.” IEEE
Transactions on Power Delivery, 2015, Vol. 30, No. 3, pp. 1110–1118.
[90]
EPRI. 1999. Electric Field Modeling of NCI and Grading Ring Design and Application.
EPRI, Palo Alto, CA: December TR 113-977.
[91]
EPRI. 1998. Application Guide for Transmission Line NCI. EPRI, Palo Alto, CA: 1998.
TR-111566.
[92]
EPRI. 2016a. Insulator Calculation Engine (ICE) v4.0 (for Polymer Insulators). EPRI,
Palo Alto, CA: 3002007723.
[93]
EPRI. 2002c. Results of Electrostatic Modelling of the Electric Field Magnitude on the
Surface of Polymer Insulator Sheaths. TC Funder report. EPRI, Palo Alto, CA:
September.
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[94]
Jagtiani, A. S. and J. R. Booker. 1995. “Aging of Porcelain Suspension Insulators under
Mechanical and Electrical Stress on EHV AC Lines.” ESMO-95 Proceedings. Seventh
International Conference on Transmission and Distribution Construction and Live Line
Maintenance. 29 October–3 November. Pp. 80–86.
[95]
Landy, R. C. and J. P. Reynders. 2003. “Corona Inception on Cap-and-pin Insulators in
Clean Environments.” 13th International Symposium on High Voltage Engineering
(ISH). Delft, the Netherlands.
[96] [37] "Considerations relating to the use of high temperature conductors," CIGRE,331,
2007.
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6
MECHANICAL DESIGN AND SELECTION OF
INSULATORS
Introduction
Rule 250 of the National Electric Safety Code (NESC) provides the anticipated wind and ice
loadings for various zones of the USA, which must be followed, and the proof test load of the
insulator selected for an application, must be higher than the anticipated load in the operating
region of the line as per NESC rule 277 [1]. Conductor galloping is an unusual condition that
may need to be considered in the selection of the mechanical strength of insulators. Dead end
strings are normally higher in rating than tangent strings, due to the higher loads that they must
be capable of supporting and are often paralleled for safety reasons.
Note: This chapter is being introduced here with the following opening discussions. As EPRI
continues to compile data on this topic, this chapter will be expanded in future releases.
Minimum Mechanical Failing Load Rating
Following the discussion above, the M&E or Minimum Mechanical Failing Load rating of an
insulator can be specified. Users will take one of two approaches in the specification of the
mechanical rating of an insulator. In the first, and often referred to as the deterministic approach,
the rating is based on the maximum anticipated line load not to exceed the proof test or one-half
the mechanical rating of an insulator selected for the application. Therefore, the mechanical
rating specified is twice this maximum load and normally rounded up the nearest standard rating.
For example, if the maximum line load is estimated as 9,000 lbs (40 kN) under specified
conditions, this is doubled giving 18,000 pounds (80 kN) as the required insulator mechanical
rating. The insulator selected should be the rated at or above the requirement and will be
dependent on ratings offered by the supplier. The second approach, and one that is often applied
by users that experience extreme ice and wind loadings, is a statistical one in which the line loads
will exceed the proof test but will occur infrequently and for relatively short periods. This
approach better utilizes an insulator’s strength rating. For example, if the combined ice and wind
loading is 9,000 lbs (40 kN) as in the above example, with a return period of 10 years, and
lasting just a few hours, some users may allow this to exceed the proof test to possibly 60 % of
the rated strength. With this approach, a 15 kip (15,000 lb or 66.7 kN) insulator would be
specified for the application at a lower cost. Although this approach is used, there is no common
methodology, and each user will have selection rules that are based on many years of experience.
Porcelain and glass insulators, as introduced in chapter 2, are made for use in suspension strings,
called disks, or, commonly for porcelain only, as posts. Suspension disks are designed to be used
under tension and post insulators are designed for cantilever loads. The following discussion
describes various tests performed on both designs. Future revisions intend to include how to
consider the design loads in the insulator selection process.
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Several national and international standards can be applied to verify insulators meet certain
design and quality metrics, during both the development and the production phase of insulators.
Two tests are most used when assessing the mechanical performance of porcelain suspension
insulators: the Thermal-Mechanical (TM) cycling test and the combined Mechanical and
Electrical (M&E) strength test. For porcelain post insulators, the most used test is the cantilever
test.
Description of Testing
In 2018, EPRI devised a test plan as shown in Figure 6-1 for testing porcelain and glass
insulators. After receiving samples from member utilities, a count of the manufacturers and
M&E ratings was made along with several other non-destructive measurements. If more than
twenty samples of a manufacturer and rating are available, they are split into groups and tested
per the scheme presented in Figure 6-1. A description of how each stress is applied and test is
performed is presented in the following sections. Some insulators would be subjected to the
combined mechanical and electrical strength test without any pre-stress.
Figure 6-1
Test plan for porcelain and glass insulators
Thermal-Mechanical Cycling
The thermal-mechanical cycling tests follow ANSI C29.2-2012 Section 8.2.5 [3] Thermalmechanical load cycle test as a reference. The cycle profile involves both mechanical tension and
temperature changes as shown in Figure 6-2. A mechanical tensile load equal to 60% of the rated
M&E strength is applied on the insulator and held constant during each 24-hour cycle for a total
of 96 hours. At the end of each 24-hour cycle, the mechanical load is released and re-applied.
The standard does not specify how quickly the load is released and re-applied. The temperature
cycle begins by decreasing to -22°F (-30°C), maintain this temperature for at least four hours,
then increasing to 104°F (40°C) and maintain this temperature for at least four hours to complete
a 24-hour cycle.
After the thermal-mechanical cycling test is completed, the surviving insulators are then
submitted to M&E testing.
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Figure 6-2
Example test load for thermal-mechanical cycling
Combined Mechanical and Electrical (M&E) Tests
The tests follow ANSI C29.2 Section 8.3.4—“Combined mechanical and electrical strength test”
[3]. As per the standard, each insulator (porcelain and glass) is tested mechanically while under
electrical load. The applied voltage was set to 75% of the dry flashover voltage determined
through testing.
EPRI also tested stub insulators while under electrical load to learn how the damaged dielectric
performs. EPRI determined the average flashover strength of each stub based on three low
frequency flashovers (approximately 12kV for most stubs) and applied 75% of the average
flashover during the test.
The mechanical load is applied as shown in Figure 6-3 and as defined in the standard. The load is
brought up quickly to 75% of the rating M&E strength of the bell. Then the mechanical load
increases at a rate between 15% and 30% of the rated M&E strength per minute. Figure 6-3
shows the maximum rate, minimum rate, and the average rate of applying the mechanical load.
EPRI uses the average rate.
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Minimum
Load (% of rating)
250%
Maximum
Average
200%
150%
100%
50%
0%
0
0.5
1
1.5
2 2.5 3 3.5
Time (minutes)
4
4.5
5
Figure 6-3
Mechanical load rate of increase for M&E testing
The M&E test ends when:
•
•
•
•
Electrical Puncture: The test is stopped immediately upon electrical puncture; the
maximum applied mechanical load is recorded. The insulator may still be mechanically
intact.
Predetermined Load: The test is stopped when the insulator reached 100% of rating or
higher predetermined limit but before mechanical failure. This is done either to save the
insulator for additional analysis or prevent test equipment damage.
Mechanical failure: The test is stopped when the insulator fails mechanically. The
maximum mechanical failure load is recorded.
The types of mechanical failures are:
Figure 6-4
Bell Breaks
Figure 6-6
Pin Breaks or Pin Breaks followed by Bell
Breaks
Figure 6-5
Cap Breaks or Cap Breaks followed by Bell
Breaks
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Figure 6-7
Pin Pullout
Figure 6-8
Cap from Bell Separation
EPRI records two test values from the M&E test:
•
•
Electrical strength: the tensile load when the insulator fails to hold the applied voltage
(detected by a power supply trip); it is always lower than the mechanical strength
Mechanical strength: the tension load when the insulator fails to hold the applied tension
A third value, named M&E strength, is calculated as the lower of the Electrical and Mechanical
strength. This report presents the M&E strength and the Mechanical strength. In the cases that
the insulator held the applied voltage until tension failure, the M&E strength equals the
Mechanical strength.
Figure 6-9 shows the combined M&E strength test results of 9810 insulators collected by EPRI.
These results cover a variety of ages from new for 60 years old, various service environments,
and various makes and models. Test results of aged insulators are used by utilities to make
decisions about population replacement. EPRI’s database of test results also helps with
comparing performance across the industry so utilities can benchmark their population’s
performance against other regions.
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Figure 6-9
Mechanical strength of insulators tested by EPRI
Mechanical Failing Tensile Load Assessment
To help a utility determine if a population is at risk of incurring string failures, a statistical
approach in used. The following describes an approach to a population assessment on an
example dataset.
An insulator string is only as strong as its weakest insulator; the following determines the
minimum failing tensions of strings in the population. The analysis is applied with the following
results: [2]
•
•
•
•
•
•
The minimum mechanical failing tension of the n=9 strings is used.
The mean mechanical failing tension of the strings (μ) is 52 165 lbf.
The standard deviation (σ) of the failing tension is 10 064 lbf.
The lower 95 % confidence bound of the failing tension is 44 590 lbf as calculated using
Equation 6-1.
The standard deviation of the population is σ∙√n = 30 193 lbf.
The withstand tension (three standard deviations of the population below the mean tension or
99.985% probability) is below 0 indicating there is a probability that there are insulators in
the population at risk of being weaker than the design limits.
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•
The probability of strings failing below 50% of the insulator rating (25 000 lbf.) is 26%. In
other words, 26 of every 100 strings may have a mechanical failing tension below 25 000 lbf
(111 kN).
- This is calculated using Equation 6-2 and using the lower 95% confidence bound as the
population mean failing tension, using the population standard deviation, and 50% of the
rated insulator strength as the x reference.
𝑳𝑳𝑳𝑳𝑳𝑳𝑳𝑳𝑳𝑳 𝟗𝟗𝟗𝟗% 𝑪𝑪𝑪𝑪𝑪𝑪𝑪𝑪𝑪𝑪𝑪𝑪𝑪𝑪𝑪𝑪𝑪𝑪𝑪𝑪 = 𝝁𝝁 − 𝟏𝟏. 𝟗𝟗𝟗𝟗
𝑷𝑷(𝒙𝒙) =
𝟏𝟏
𝝈𝝈√𝟐𝟐𝟐𝟐
𝒆𝒆
−�
(𝒙𝒙−𝝁𝝁)𝟐𝟐
�
𝟐𝟐𝝈𝝈𝟐𝟐
𝝈𝝈
√𝒏𝒏
Eq. 6-1
Eq. 6-2
Based on the above calculated parameters, the chart in Figure 6-10 can be created to show the
estimated distribution of the failing strength of insulator strings in the population.
This information is used in conjunction with the NESC guidance introduced at the start of this
chapter to let a utility assess the overall risk of mechanical failure in the represented population.
Figure 6-10
The normal probability curve of example test results
References
[1]
"National Electrical Safety Code," Institute of Electrical and Electronics Engineers, Inc.,
3 Park Avenue, New York, NY 10016-5997, USA, C2-2007, Apr. 2006.
[2]
ANSI. 2018. American National Standard for Electrical Power Insulators—Test
Methods: ANSI C29.1-2018. ANSI. New York, N.Y.
[3]
ANSI. 2013 American National Standard for Insulators Wet Process Porcelain and
Toughened Glass—Transmission Suspension Type: ANSI C29.2B-2013. ANSI. New
York, N.Y.
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7
SPECIFICATION OF INSULATORS
Introduction
In broad terms, there are two philosophies that can be followed when writing specifications:
1. Design Specification: In this type of specification the design, dimensions, materials and
processes followed for the construction of the equipment are specified in detail.
2. Functional Specification: The required operational capability of the equipment is described
in terms of a set of functions—or the minimum operational and environmental requirements
that it must meet.
The big difference between these two philosophies is how the responsibility is divided between
supplier and buyer. With a design specification, the buyer takes the full responsibility of the
design of the object and the supplier’s responsibility is limited to the proper execution of the
manufacturing process. With a functional specification, more responsibility is placed on the
supplier since he is not only responsible for the manufacturing, but also for the design of the
object.
A design specification has the advantage that the buyer can utilize his available service
experience to exclude specific designs or concepts that have a known history of failure or poor
performance. However, to implement a design specification, the buyer needs to have full insight
into the design, components, materials, and interfaces that make up the product, whereas
manufacturers prefer to keep this propriety information secret.
A functional specification may result in more expensive equipment, since the supplier carries a
greater responsibility, but this is not always the case. A functional specification also offers the
supplier/manufacturer a greater degree of freedom than under a design specification, as it allows
the supplier to be competitive by the innovative use of materials and processes to offer a costefficient and fit for purpose product.
Presently utilities favour a functional approach since they do not have the intension, manpower
or in-house technical expertise necessary for preparing design specifications. There are however
two major obstacles that prevent the use of fully functional specifications:
1. Not all the functions required from the insulator can be verified through standards testing,
because laboratory test methods may lag developments in insulator technology, or it may be
difficult or impractical to devise appropriate test methods for some required functions. Users
must rely therefore on additional design requirements to avoid known service problems.
2. It is generally not possible for the buyer to hold the manufacturer liable for all consequential
damages related to an insulator failure: Insulators are a relatively inexpensive component in
terms of the total cost of a transmission line, but its failure may have severe cost implications
in terms of outage and the manpower for its replacement. Normal practice, however, relates
the damages that the supplier can be held responsible for, to the cost of the component. Thus
there may be a need to implement measures to minimize risk in terms of insulator failure.
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Based on these considerations, most technical demand specifications for insulators follow a
hybrid approach. That is, essentially the specification follows the functional approach of the
standards, with the addition of a number of design requirements, based on experience, to avoid
known design deficiencies.
Role of Specification and Standards
Early in the development of suspension insulators in the USA, it was recognized, that two types
of tests were needed in the manufacture of insulators; one done on each and every unit produced,
as a proof test, and another done on manufactured lots, as a conformance test of the design [1].
Although through the course of insulator manufacture, the manufacturers’ had developed their
own specifications, but it took 40 years for the first USA standard to be developed and another 9
years for standard test methods to be published; in total, almost 50 years were needed to
standardize the suspension insulator [2].
Since then, standards have become important to users and suppliers alike as they provide a
common basis—in terms of definitions, terminology and test methods—that can be used when
specifying insulators. As service experience and knowledge about the technology increased,
standards are updated, often to redress specific problems experienced with insulators in service.
Another important function of standards is the definition of coupling designs and dimensions to
ensure compatibility with connection hardware and to ensure interchangeability with other
insulator types and makes.
In most cases, the standards are used as the point of departure from which a specification is
developed. It is, therefore, necessary to indicate in the specification which of the national or
international standards is used as basis. The products offered are expected to comply with all of
provisions of the referenced standard(s). As explained earlier, the user may also stipulate
additional requirements, not covered by the referenced standard(s) to ensure the quality or
suitability of a product.
For this part of this reference book, the standards covering insulators from the following three
standardization bodies are used as basis:
•
•
•
ANSI (American National Standards Institute)
IEC (International Electrotechnical Commission)
CSA (Canadian Standards Association)
The standards rely on a set of tests to verify the physical, electrical, and mechanical
characteristics of the insulator. These tests are divided into various categories depending on the
aim with the test and at what stage of insulator production it is performed. In Table 7-1
descriptions are presented of the various types of testing defined in the standards. It will be noted
that the terminology used by ANSI, on the one side, and the IEC and CSA on the other, differ
with respect to the naming of the first two test categories. Users should be aware of this
difference as it may lead to some confusion over the type of testing performed.
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Table 7-1
Comparison of the Terminology used in ANSI, IEC and CSA to describe the various types of test.
ANSI/IEEE
IEC/CSA
Definition
Prototype
tests
Design
tests
The purpose of these tests is to verify the suitability of the design, materials
and method of manufacture. Results are valid for the whole class of
insulator. These tests do not provide an indication of life expectancy.
Design
tests
Type
tests
Sample
tests
Sampling
tests
These tests are for the purpose of verifying other characteristics, including
those depending on the quality of manufacture and on materials used. They
are made on insulator samples taken at random from production lots.
Routine
tests
Routine
tests
The aim of these tests is to eliminate insulators with manufacturing defects.
They are made on every insulator of the production lot.
The purpose of these tests is to verify the main characteristics, which
depend mainly on size and shape.
Problem Statement
International and national standards have undoubtedly played a major part in improving the
quality of the insulators on offer by eliminating weak designs, but there is still room for
improvement as they do not always differentiate between good- and poor-quality insulators. This
perceived weakness and the big differences in the performance of different insulator designs
have left many potential users with a feeling that more research and development is needed,
especially in terms of the long-term performance of insulators.
In addition, not all information needed for evaluating the suitability of offered insulators may be
available. This may include information on:
•
•
•
Manufacturing/assembly methods
Quality assurance procedures
Previous experience, especially for imported insulators
There may also be concerns about using insulators from distant factories where it is difficult to
verify that the required quality control procedures are in place and executed. Moreover, such
insulators may be manufacturers according to local standards which may not fully comply to the
requirements of ANSI or IEC.
Finally, company policy and procurement procedures may not fully allow for the particular
issues regarding insulators by overly relying on compliancy with the standards. This is often due
to an underappreciation of the complexity of the technology, and an unawareness of the critical
factors underpinning its manufacturing, application, and maintenance. This may result in
acquiring the cheapest insulators that comply to the standards, but which may not have an
acceptable performance.
Industry as a whole and EPRI more specifically, have reacted to these stimuli by performing a
considerable amount of research as is testified by the many publications and research reports
available. Based on this world-class expertise is utilized to develop a set of principles that can be
used to specify and procure insulators for transmission lines.
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Industry Concerns
The electric power industry has experienced great changes in the last couple of decades. Capital
investment in the transmission network declined as the UHV transmission network matured. This
has resulted in a dramatic reduction in the demand for insulators and precipitated in a large-scale
re-organization and consolidation of the insulator industry. As a result, all the porcelain
transmission line insulator-manufacturing plants in the U.S. have been closed down as
production has been moved to developing countries.
In recent years there has been a significant increase in the demand for insulators in the U.S., as
the network has to grow to cater for the continuous growth in the electric power demand. This
increase in capital spending is expected to continue for the foreseeable future. In addition to new
lines there is also an increase in the number of insulator replacements where vintage insulators,
which are nearing their end of life, are being replaced by new ones.
Utilities have relied in the past on locally made porcelain or glass insulators, since these
technologies have a proven track record. However, in recent times, composite insulators have
gained market share, not only because of their technical advantages, but also based on price and
availability. Nowadays the choice to go with composite or glass or porcelain is no longer clear
cut and there are many factors that need to be considered as discussed in Chapter 5. Table 5-3
lists some of the advantages and disadvantages of each technology.
Industry issues, such as interchangeability, availability, and cost play an important part in the
decision and in certain cases may dictate the choice being made. These considerations are
especially acute when considering the implementation of composite insulators, which requires a
different approach to that of conventional glass and porcelain types. Each manufacturer has a
unique design and manufacturing process, which has its own strong and weak points. It is
therefore generally not possible to utilize the service experience on one type of insulator to make
decisions on another type. Differences in dimensions may also limit the extent to which different
types of composite insulators are interchangeable. These differences necessitate a greater
reliance on quality control procedures that has been the case in the past to ensure consistency in
the insulators purchased.
Specification of Ceramic and Glass Insulators
Introduction
Ceramic (or porcelain) and toughened glass insulators have been used since the earliest days of
power transmission and are nowadays applied worldwide at all voltage levels up to 1,000 kV.
Their development has reached a mature stage with stable designs and a well proven track
record. Consequently, the standards for these insulators are also well developed and subject to
only minor revisions from time to time. This is underscored by service experience, which shows
these insulators to be reliable and long lasting when manufactured properly. Since the
development of porcelain and glass insulators ran more-or-less parallel, they have similar shapes
and are designed to be interchangeable.
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Applicable Standards
Although numerous standards have been developed for porcelain and toughened glass
suspension insulators for high voltage AC lines, this guide will highlight three; namely, those
published by the American National Standards Institute (ANSI), the International
Electrotechnical Commission (IEC) and the Canadian Standards Association (CSA).
ANSI has one directly applicable standard for porcelain and toughened glass insulators. It refers
other supporting standards for detailed descriptions of test methods, and they are also listed in
Table 7-2. Standard C29.1 outlines the applicable test methods while C29.2 outlines the
requirements for each of the standard designs of suspension insulators. Normally these standards
are reviewed every five years and either updated or renewed. These standards may also be listed
with NEMA (National Electrical Manufacturers Association).
Table 7-2
List of ANSI Standards Applicable to Porcelain and Toughened Glass Insulators
Main Standard
Supporting Standard(s)
Number
Title
Number
C29.2
Wet-process porcelain and
toughened glass - suspension type
C29.1
ASTM
C151-84
Title
Electrical power insulators - test methods
Standard Test Method for Autoclave
Expansion of Portland Cement
IEC has developed many more standards than ANSI, with each standard addressing a very
specific aspect of, or test methods for suspension insulators. The standards directly applicable to
porcelain and toughened glass insulators are shown in Table 7-3.
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Table 7-3
List of IEC Standards Applicable to Porcelain and Toughened Glass Insulators
Main Standard
Number
Supporting Standard(s)
Title
Number
Title
60060-2
High Voltage Test Techniques –
Part 2: Measuring Systems
N/A
60383-1
Insulator units - Definitions, test
methods and acceptance criteria
60060-1
High-voltage test techniques, Part 1:
General definitions and test requirements
60120
Dimensions of ball and socket coupling of
string insulator units
60305
Characteristics of insulator units of the cap
and pin type
60471
Dimensions of clevis and tongue coupling of
string insulator units
60437
Radio interference test on highvoltage insulators
N/A
60060-1
High-voltage test techniques, Part 1:
General definitions and test requirements
60383-2
Insulator strings - Definitions, test methods
and acceptance criteria
60383-1
Insulator units - Definitions, test methods
and acceptance criteria
60383-1
Insulator units - Definitions, test methods
and acceptance criteria
60797
Residual strength of string
insulator units
60815
Guide for the selection of
insulators in respect of polluted
conditions
N/A
N/A
61211
Insulators of ceramic material
or glass for overhead lines with a
nominal voltage greater than
1 000 V—Impulse puncture
testing in air
N/A
N/A
Table 7-4 lists the only standard issued by the CSA that is applicable to porcelain and toughened
glass suspension insulators.
Table 7-4
List of CSA Standards Applicable to Porcelain and Toughened Glass Insulators
Main Standard
Supporting Standard(s)
Number
Title
Number
CSA
411.1-10
AC
suspension
Insulators
IEC 60383-1
Insulator units - Definitions, test methods and acceptance
criteria
IEC 60060-2
High Voltage Test Techniques – Part 2: Measuring Systems
ANSI C29.1
Electrical power insulators - test methods
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Title
7-6
Cross Reference of Definitions in ANSI, IEC, and CSA Standards
There are some differences in insulator terminology used in the three reference standards, these
are cross-referenced in Table 7-5.
Table 7-5
Cross Reference of Terms used in the Various Standards
ANSI/IEEE
IEC
CSA
Leakage distance
Creepage distance
Creepage distance
Combined Mechanical and
Electrical Strength
Electro-mechanical Failing
Load
Electro-mechanical Failing
Load
Unit
String Insulator Unit
Unit
String
Insulator String
String
Critical impulse flashover
50 % lightning impulse
flashover
Critical (50%) lightning impulse
flashover
Ultimate mechanical strength
Mechanical failing load
Design tests
Type tests
Type tests
Quality Conformance tests
Sample tests
Sample tests
Routine tests
Routine tests
Routine tests
Functional Characteristics of Ceramic and Glass Insulators
The various insulator terms, characteristics and parameters that are used to define insulators in
specifications and standards are listed and defined in Chapter 2: “General Insulator Terms and
Classification”.
Design/Type Tests in the Standards
Background
Design/Type tests are intended to verify the main physical, electrical, and mechanical
characteristics of an insulator. The tests are generally required to be done only once to qualify
the design/Type. These tests must, however, be repeated if the dimensions or materials described
on the manufacturers’ drawings are modified or if the manufacturing processes have changed.
When the change affects only certain characteristics, only the tests relevant to those
characteristics need to be repeated.
Many of the design tests for porcelain insulators were developed more than 100 years ago and
over this period, some tests have undergone several iterations, sometime with little
documentation. Where this information has been found, the origin and reason for the various
tests are included in this section. Most often, the development of design tests was in response to
specific problems with insulators in service; for example, the autoclave expansion test for
cement, was introduced into standards once the mechanism was demonstrated to be the cause of
cracks in the shells of insulators, even though this mechanism was perceived to be problem at a
very early stage.
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The first design tests for suspension insulators were developed by the Ontario Power Company
for a 110 kV line. The requirement was based on a safety factor of three for the dry flashover of
a string, i.e., 330 kV, and a safety factor of two for the wet flashover of a string, i.e., 220 kV, and
based on phase-to-phase voltage [3]. The original string length was eight units, and no record
could be found as to how these safety factors were determined. Mechanically, the transmission
line specifies a design strength of 8,000 lb (35.6 kN) for tangent strings and 10,000 lb (44.5 kN)
on dead ends which required two parallel strings as the individual units exhibited a pull-out
strength just meeting the 8,000 lb (35.6 kN) requirement [3]. These and other design tests
eventually found their way into ANSI standards.
As noted by Austin in 1916 [4], puncture under oil tests of suspension insulators came about
during the very early days of insulator development as a means of demonstrating the quality of
the fired porcelain shell. However, initially the test was discarded in favor of a routine high
frequency flashover test on the fired shells, thereby rejecting defective shells prior to cementing.
In fact, firing of shells was often so bad that a high percentage of shells punctured during the test.
It was a few years later when the firing process was better controlled resulting in fewer shells
that punctured under the high frequency routine test, and at that time, several manufacturers
began to test insulators under oil to demonstrate the puncture strength. It is unknown as to when
puncture under oil became a conformance test.
For toughened glass insulators, many of the design tests came much later and were developed
following their introduction to the market in 1955 [6].
Except for the more recent tests, such as the thermal-mechanical test, the origins of the design
tests in the IEC are much more difficult to source. The design tests in CSA standards follow from
a combination of ANSI, IEC and a few from specifications from major Canadian utilities [5].
Overview of Tests
The Design tests in ANSI C29.2 are called Type tests in IEC 60383-1 and in CSA 411.1-10 and a
cross reference of these tests is shown in Table 7-6. A common test name was created for
comparison. Note that in the cross reference many tests are not completely equivalent as their
procedures and requirements differ. In addition, some tests not listed in IEC 60383-1 can be
found in separate IEC standards (see Table 7-6).
Table 7-6
Cross Reference of Design Tests in various Standards
Common Test Name
Low Frequency Dry
Flashover
Low Frequency Wet
Flashover
Impulse Flashover
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Standard
Standard Test Name
ANSI C29.2
Low-frequency dry flashover test
CSA C411.1-10
Dry power frequency flashover voltage test
ANSI C29.2
Low-frequency wet flashover test
IEC 60383-1
Wet power-frequency voltage tests
CSA C411.1-10
Wet power frequency flashover voltage test
ANSI C29.2
Critical impulse flashover tests-positive and negative
IEC 60383-1
Lightning impulse voltage tests
CSA C411.1-10
Critical lightning impulse flashover voltage test
7-8
Table 7-6 (continued)
Cross Reference of Design Tests in various Standards
Common Test Name
RIV
Standard
Standard Test Name
ANSI C29.2
Radio-influence voltage test
IEC 60437
Radio interference test on high-voltage insulators
CSA C411.1-10
Radio-influence voltage test
CSA C411.1-10
Steep-front impulse voltage test
IEC 61211
Impulse voltage puncture test on insulators in air
IEC 60383-1
Electromechanical failing load test
CSA C411.1-10
Electromechanical failing load test
ANSI C29.2
Impact test
CSA C411.1-10
Impact test
Mechanical Strength
IEC 60383-1
Mechanical failing load test
Residual Strength Test
ANSI C29.2
Residual-strength test
IEC 60797
Residual strength test
CSA C411.1-10
Residual strength test
ANSI C29.2
Thermal-mechanical load cycle test
IEC 60383-1
Thermal-mechanical performance test
CSA C411.1-10
Thermal-mechanical performance test
Thermal Shock Test
ANSI C29.2
Thermal shock test
Cement Expansion
ANSI C29.2
Cement expansion
Cotter Key
ANSI C29.2
Cotter key test
CSA C411.1-10
Position of locking device
Verification of coupling locking system
IEC 60383-1
Verification of the dimensions
Steep-Front
M&E Test
Mechanical Impact Strength
Thermal Mechanical load
cycling
Dimensions
Electrical Tests
Electrical design/type tests verify the electrical functions of the insulator. The required electrical
values all refer to the insulator performance at standard atmospheric conditions. The standards
also provide a procedure to correct the raw test results for the prevailing ambient conditions
during which the test was performed. In this regard CSA C411.1-10 uses the same standard
atmospheric conditions and similar corrections for air density and humidity as IEC 60383. ANSI
C29.1 uses different standard conditions and corrections. The requirements for artificial rain also
differ between ANSI and CSA/IEC. The standard conditions and artificial rain are summarized
in Table 7-7.
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Table 7-7
Comparison of Standard atmospheric conditions and artificial rain
Conditions
IEC
CSA C411.1-10
ANSI C29.1
20
20
25
1013
1013
1008.6
Absolute Humidity (g/m³)
11
11
15
Equivalent Relative Humidity (%)
64
64
64
Resistivity (Ωm)
100 +/- 15
100 +/- 15
178 +/-27
Rate (mm/min)
1-2 H and V
1-1.5 H and V
5V
Temp (°C)
Pressure (hPa)
Artificial Rain:
Wet and dry flashover requirements were originally derived from tests done during the design of
early high voltage transmission lines. The impulse flashover values for the individual units were
derived from the flashover values obtained from the strings. As the dry and wet power frequency
flashover voltages, and the positive and negative impulse flashover voltages, of a single unit is
governed by the dry arcing distance, these values became standardized as the dimensions of the
suspension insulator were optimized and insulation coordination was standardized. The IEC
electrical tests are carried out on a short string (at least five units and up to 1.5m length); this
method is intended to give a better idea of the voltage per unit when cap and pin insulators are
assembled into a string.
Dry Low Frequency Flashover
The low-frequency dry flashover values, for the standard porcelain and toughened glass
insulators in ANSI, classes 52-1 through 52-12, are given in the applicable figures in ANSI
C29.2. There are several non-standard designs of suspension insulators, for example, fog and
aerodynamic types, but the test method in C29.1 is still used to determine the dry flashover
voltages. As the dry flashover value is directly related to the dry arcing distance, design tests
must be done in accordance with the test arrangement outlined in ANSI C29.1, which also
outlines the test methodology. The required test values are corrected for air density, from the
values provided in the standard which is specified at the standard atmospheric conditions.
IEC 60305 gives the characteristics of suspension insulators concerning electromechanical
failing load, and physical dimensions of the units, but unlike ANSI, no electrical flashover values
are given. The design tests, called type tests in IEC, are outlined in IEC 60383. No lowfrequency dry flashover tests are required by the standard.
The CSA 411.1-10 standard outlines the standard suspension units CS-1 through CS-15 and the
designs CS-1 through CS-12 are identical to ANSI 52-1 through 52-12. However, the test set-up,
methods of test, and correction factors, are per IEC 60060-1 and 60060-2. The difference in the
dry flashover strengths range generally from 1.5 to 3.5 % due to the differences in procedures,
the values are considered irrelevant, so the same dry flashover values as ANSI are given.
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Wet Low Frequency Flashover
The low-frequency wet flashover values, for the standard insulators in ANSI, classes 52-1
through 52-12, are given in the applicable figures in ANSI C29.2. As the wet flashover value is
directly related to insulator orientation, direction of rain, conductivity of rainwater, and the
precipitation rate, and the angle of the precipitation, the design tests must be done in strict
accordance as outlined in ANSI C29.1, which also outlines the test methodology. The values are
corrected to the standard conditions of temperature and barometric pressure, without humidity,
which comply with those in the applicable figures, demonstrate compliance to the standard.
For the non-standardized designs of fog and aerodynamic types, the test method in C29.1 is still
used to determine the wet flashover voltages.
The type tests in IEC 60383 stipulate a low-frequency wet test that is done in accordance with
the test set-up and procedure outlined in IEC 60060-1 and 600060-2, respectively.
The type tests in CSA 411.1-10 also call for a low-frequency wet test. However, the test set-up,
methods of test, and correction factors, are per IEC 60060-1 and 60060-2. The suspension units
CS-1 through CS-12 in CSA are identical to ANSI 52-1 through 52-12, have similar but not
identical wet flashover values. However, as passing of test requires the flashover value to be
within 90 % of the rated value, the values in both standards can be considered equivalent.
Impulse Flashover
The critical impulse flashover, positive and negative voltage, for the standard insulators in ANSI,
classes 52-1 through 52-12, is given in the applicable figures in ANSI C29.2. The values are
corrected to the standard conditions of air density and humidity, comply with those in the
applicable figures, and demonstrate compliance to the standard. For the non-standardized designs
of fog and aerodynamic types, the test method in C29.1 is still used to determine the critical
impulse flashover voltages.
The type tests in IEC 60383 stipulate critical impulse flashover tests that are done in accordance
with the test set-up and procedure outlined in IEC 60060-1 and 600060-2, respectively.
The type tests in CSA 411.1-10 also call for critical impulse flashover tests. However, the test
set-up, methods of test, and correction factors, are per IEC 60060-1 and 60060-2. The standard
suspension units CS-1 through CS-12 which are identical to ANSI 52-1 through 52-12, have
similar impulse flashover values but due to the variation in the values from laboratory to
laboratory, the difference in the values can be different by up to 8 %, so the test values in the two
standards are considered equivalent.
Radio-Influence Voltage Test
The origin of the radio-influence voltage (RIV) test and specified test values are not known.
Neither Sothman in 1912 [1] nor Austin in 1925 [4] indicated a specification for RIV. It is
therefore likely that the RIV testing requirement was written to reduce radio interference during
the time when commercial AM radio licenses were issued in North America in the 1920’s and
FM licenses in 1933.
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American National Standards (ANSI) was formed in 1919 and the first standard covering the test
requirements for RIV for standard suspension insulators appeared in 1961. The circuit that is
specified for the test was first outlined in the National Electric Manufacturers Association
standard 107 (NEMA), which was first published in 1940. It is to be noted that this NEMA
standard has been withdrawn and the test description is now to be found in Annex A of
ANSI/NEMA CC1-2009 “Electric Power Connection for Substations”. The test voltage of either
7.5 or 10 kV for standard suspension insulators, depending on the ANSI insulator class, likely
came about because this is the nominal voltage of a suspension insulator when used in a string
i.e., 7 units at 115 kV nominal phase-to-phase or approximately 70 kV line-to-ground.
The RIV test requirement for the standard insulators in ANSI, classes 52-1 through 52-12, is
given in the applicable figures in ANSI C29.2. For the non-standardized designs of fog and
aerodynamic types, the test method in C29.1 is still used to determine the critical impulse
flashover voltages.
The type tests in IEC 60383 do not stipulate RIV tests. These tests are carried out by agreement,
usually on a complete insulator set, according to IEC 60437.
The type tests in CSA 411.1-10 also call for RIV tests. However, the test set-up, methods of test,
and correction factors, are per IEC 60060-1 and 60060-2. The standard suspension units CS-1
through CS-12, which are identical to ANSI 52-1 through 52-12, have similar RIV test voltages
and values.
Steep Front Impulse Test
In the beginning, annealed glass and porcelain puncturing was identified as a problem in the
performance of suspension insulators. Punctures were common and it soon was recognized that a
routine voltage test (Megger testing) was necessary to cull out unacceptable shells before
assembly. This practice was common up to the 1950s after which became more infrequent,
presumably because the quality of the insulators had significantly improved [7]. Impulse testing
was also found to be good way of culling out unacceptable shells and was introduced very early
in the manufacture of insulators [4]. Another effective test to find poor quality shells was to
demonstrate the puncture strength of an insulator under oil which soon became an important
design test [4].
During the 1970s, it was noticed that the lightning performance of lines had significantly
deteriorated, so much so that some utilities began to remove insulators to examine them to
determine the possible reason for failure [8]. Many porcelain insulators showed evidence of
cracking, from what was thought to be cement expansion, but many insulators were punctured
electrically. This finding caused considerable concern about the quality of the porcelain and
many laboratories began to examine the puncture strength under steep rising waves [9].
Ontario Hydro initiated a study in 1980 to examine the effectiveness of a steep-front-of-wave
test, as a possible design test. This test takes advantage of the formative time lag for flashover to
develop externally to the insulator, to stress the internal dielectric with a voltage exceeding
500 kV, depending on the steepness of the wave. Given a sufficient steepness, it was possible to
cause a puncture in the head of a porcelain insulator or shatter glass containing inclusions. Thus
it became possible, by varying the steepness and the number of impulse applications, to
differentiate between good and poor-quality dielectrics. A rise time of higher than 1000 kV/μS
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was required for puncture to occur within the head; otherwise, puncture took place outside of the
head. Most designs of insulators failed with one or two applications of a wave having a steepness
of 5,000 kV/μS. Extensive tests were done to establish a test consisting of five successive
positive impulse waves followed by five successive negative waves having a minimum rate of
rise of each wave being 2,500 kV/μS, which was followed by low-frequency dry flashover tests
to confirm the integrity of the insulators. This test was specified as a design test on 12 units,
which first appeared in the Ontario Hydro standard specification for porcelain and toughened
glass suspension insulators, dated 1984.
The steep-front-of-wave test was included in CSA 411.1 in 1989. In the present standard, the
mounting arrangement, test method and instrumentation is in accordance with IEC 61211 [25],
and 60060-2, respectively. The number of applications of the wave follows the sequence of five
positive, five negative, five positive and five negative impulses, with several reduced impulses
between the positive and negative sequence to redistribute the charge in the insulators, which is
then followed by three low frequency dry flashovers to confirm the integrity of the insulators.
This test is not specified in ANSI; there is an IEC standard (61211) which requires a test voltage
based on a per unit multiplier of the critical impulse flashover voltage. This requirement is
proposed instead of steepness as studies have shown that there is less error in measuring the peak
voltage of fast impulses compared to measuring the steepness. With correct measuring
equipment, the CSA and IEC criteria are equivalent in severity.
Mechanical Tests
The mechanical strength of modern suspension insulators is the result of a series of continuous,
small improvements, interspersed with a few major changes. It took nearly 60 years since the
first suspension insulator was produced to achieve the strengths that are available today. Along
with these developments, came various design tests to confirm the mechanical strengths and
many of these tests are still specified today, although some of them may no longer be relevant.
Electromechanical Failing Load
This type test in IEC and CSA is equivalent to the combined mechanical and electrical test listed
as a sample test in ANSI.
Note that IEC only requires electromechanical testing for porcelain units, toughened glass
insulators are submitted to a mechanical test without applied voltage. This is because a porcelain
unit can crack internally and lose electrical soundness without any external indications, while
toughened glass insulator shells will always fail by visibly shattering,—hence no applied voltage
is needed to detect internal cracks or puncture.
Impact
During the 1930s there was increased attention paid to the mechanical ruggedness of suspension
insulators as during construction, there was considerable breakage of insulators.
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An impact testing machine was designed and the test was eventually included in the NEMA
standard for suspension insulators in 1940 [4]. The test characteristics were established at 55, 60
and 90 inch-pounds for standard suspension units. Gradually, as compression glazes grew more
effective and sophisticated, impact strengths increased and virtually all insulators today meet the
characteristics established for suspension insulators; but the test is still part of the ANSI standard
test procedure.
The impact test requirement for the standard insulators in ANSI, classes 52-1 through 52-12, is
given in the applicable figures in ANSI C29.2. For the non-standardized designs of fog and
aerodynamic types, the test method in C29.1 is still used to test for the impact strength.
The type tests in CSA 411.1-10 also call for an impact test. However, the test set-up, methods of
test, are identical to ANSI C29.1 and the test requirements are as shown in ANSI C29.2.
The type tests in IEC 60383 do include an impact test.
Residual Strength
The shells of early suspension insulators easily broke particularly under the conditions of power
arc flashover and because of vandalism. To ensure that insulators with broken shells could
maintain mechanical load, without dropping the line, a residual strength test was introduced in
the 1940 NEMA insulator standard, which still is specified today in ANSI C29.2. Modern
insulators still face breakage of the shell, but they easily meet this requirement.
In the ANSI test, the shells of 25 units are completely broken off so that no part of the shell
projects beyond the edge of the cap and the units are then subjected to mechanical tests in
tension. Both the average failing load and the standard deviation of the 25 units tested are used to
determine whether the units meet the requirement for residual strength. To pass the test, the
average strength of the 25 units, less a factor that depends on the standard deviation, must be
above or equal to 60 % of the rated strength. Therefore, as a minimum requirement, the average
failing load of the sample must be at least equal to 60 % of the rated strength. However, most
commonly, this strength is found to be closer to 85 % of the rated strength.
The CSA standard also specifies a residual strength test that is based on ANSI C29.2 and IEC
60797 but has a slightly different approach. First, the test is done after the 25 units have been
subjected to the thermal shock test. In determining the average and standard deviation of the
samples tested, insulators that separate by pin pull-out are used in the calculation. Insulators that
fail due to hardware breakage are not included in the calculation; however, the failing load of
these insulators must be above the rated strength of the insulators. The acceptance criterion is
somewhat different as well, requiring the average strength of all units that separate by pin pullout to be a minimum of 65 % of the rated strength. In other words, insulators that fail due to
hardware breakage are not included in the determination of residual strength.
Time-Loading
Shortly after the first suspension insulators were produced, it was discovered with dismay that
the strength, after a short period of service, had decreased, in some cases, alarmingly. Various
reasons for this decrease in strength were advanced. Prominently mentioned was a change in the
character and nature of the bituminous layer used to provide necessary lubrication between the
cement and the metal hardware. Cement expansion giving rise to a hoop stress in the porcelain
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was another common reason. In addition, there was also the possibility that under maximum
loading the cement would crush and thus present a new load distribution situation. However, the
most challenging argument of all, was that under long-term loads, the cap slipped upward with
respect to the porcelain head and cement, and the pins had moved downward, which changed the
original load distribution. It was this latter argument that led to the time-loading test.
In ANSI C29.1, a load of 60 to 67 percent of the rated strength, depending on the ANSI class of
insulator, is applied for 24 hours and mechanical failure constitutes failure of meeting the test
requirement. However, since no electrical test is done to confirm the integrity of the porcelain
dielectric, it is possible that insulators with internal cracking of the porcelain may pass the test.
This test is considered not particularly useful today.
The time-load test is not specified as a type test in either the IEC or CSA.
Thermal Shock
As it was noted by Austin [21], insulators that were heated to 66°C (150°F) would crack when
subjected to rain. A thermal shock test was therefore introduced as test on the strength of the
porcelain. However, the advent of the compression glaze virtually eliminated this problem. This
test is specified in ANSI and routinely done by glass insulator manufacturers (on the glass shell)
to check the quality of toughening and cement as described in Chapter 2. In the test, complete
insulators are completely submerged in hot water at approximately 96°C (205°F), for 10 minutes,
and then submerged in cold water at approximately 4°C (39°F) for 10 minutes, for a total of 10
cycles. After the test, the insulators are tested for dielectric integrity.
The thermal shock test is not a type test in either IEC or CSA.
Thermal-Mechanical
In 1967, the IEC set up a working group to examine and review the tests of long-term electrical
and mechanical tests done on suspension insulators at many utilities. A draft report was produced
in 1973 and the first edition of the thermal mechanical test, IEC 60575, was issued in 1977 [10].
The basis for a thermal mechanical test on porcelain suspension insulators stems from the
observations that some porcelain insulators when subjected to high mechanical loads at low
temperature will develop internal cracks. The results of tests by many utilities, and in particular
of Hydro Quebec during the early 1970s, showed a significant decrease in combined M&E
strength after thermal cycling from + 50°C (122°F) to – 50°C (-58°F) with a load applied at 60 %
of the M&E rating.
In its simplest form, porcelain can be viewed as consisting of two distinct phases, a phase
consisting of quartz or alumina particles of filler that is embedded in a glassy phase. If the
thermal expansion coefficient between the filler and the matrix are very different, microcracks
will develop between the two phases and the incidence of these flaws is dependent on the particle
size of the filler. The development of microcracks between the two phases is the first stage of
failure by brittle fracture. Crack propagation to failure is dependent on the stress, temperature
and time that the stress is applied. Thus, time and duration of mechanical load and temperature
all play a role in the brittle fracture failure of porcelain insulators.
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The thermal-mechanical test in IEC 60575 and ANSI C29.2 (as a sample test) consists of
•
•
•
•
Loading a string of insulators at room temperature to between 60 and 65 % of the M&E
rating (ANSI specifies just to 60%).
Then lowering the temperature to -30°C (-22°F) which is held for a minimum of 4 hours.
After which the temperature is raised to +40°C (104°F) and also held for a minimum of
4 hours.
Then the load is reduced to zero while the temperature is lowered to room temperature
(ANSI maintains the temperature).
Twenty-four hours constitutes one complete cycle. Four complete cycles are performed which is
followed with a combined M& E test. Failure to pass the M&E test constitutes failure of meeting
the requirements of the thermal-mechanical test.
CSA has a modified version of this test in which the loading is 70 % of the M&E rating and the
temperature extremes are + 50°C (122°F) to – 50°C (-58°F) for a minimum of 8 hours at each
extreme. In addition, the M&E test requirements are somewhat stiffer to meet.
Dimensional Tests
Verification of Dimensions
As a design test, ANSI and CSA do not provide for checking of the dimensions as this is done as
a routine test in ANSI and CSA. However, IEC stipulates gauging of the ball and socket as well
as a check of the creepage, dry arcing and connection dimensions as a type test.
Cotter Key
The cotter key test in ANSI first appeared in the 1977 edition of the standard. The test specifies a
range of the force for disengagement with a minimum of 25 lbs (111 N) for extraction. A similar
test exists in CSA, but without specifying a numerical value for extraction, and therefore, it is
rather vague in its requirement. However, the CSA standard has a requirement on the position of
the locking key, which stipulates that the eye of the key must protrude from the hole in the cap
by a distance equal to one-half of its diameter, and this is to ensure that a tool can be inserted to
extract the key. The CSA standard also has a requirement on the length of the legs of the key to
ensure that they do not extend beyond the opening of the socket, to prevent corona discharge
from the ends of the key legs. The IEC requires equivalent operation and position tests as sample
tests.
Material Tests
The test in this section have been introduced into the standards because of specific problems that
have been encountered in service, either due to service conditions, or in operation, and compared
to the above tests, are more recent, and the tests are intended to confirm their use under the
various service conditions.
Cement Expansion
ANSI C29.2 has as a design test on Portland cement, if used, stipulating an expansion of less
than 0.12 %, when tested in accordance with ASTM C151. This test is not a type test in either
IEC or CSA.
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Quality Conformance/Sample Tests in Standards
Overview and Sampling
Quality conformance tests in ANSI, IEC and CSA are tests that are performed on randomly
selected insulators form each manufactured batch. The purpose is to verify insulator
characteristics and the quality of the materials used. During sample tests insulators may be tested
to destruction, dissected, analyses etc. so these tests are only performed on a few samples from
each batch.
ANSI gives the number of insulators for the quality conformance tests, which varies with the test
to be performed but does not depend on the size of the lot that is offered for inspection.
However, the number of samples in IEC varies as the size of the lot, increasing from 4 to
12 units. CSA provides a formula to determine the sample size based on the size of the lot.
Overview of Tests
The conformance tests in ANSI C29.2 are referred to as quality conformance tests whereas in
IEC 60383-1 and in CSA 411.1-10, these tests are referred to as sample tests. The quality
conformance test values for the standard insulators in ANSI, classes 52-1 through 52-12, are
given in the applicable figures in ANSI C29.2.
Table 7-8 in this section provides a cross references of these tests. However, caution must be
observed in the cross references as many tests are not equivalent as often their procedures and
requirements differ significantly. To help with the cross reference, a common test name was
developed. The standard test name is listed for clarification.
Table 7-8
Cross Reference of Conformance Tests
Common Test Name
Standard Number
Standard Test Name
Cement Expansion
CSA C411.1-10
Cement
Cotter Key
IEC 60383-1
Verification of the locking system
CSA C411.1-10
Operation test on cotter key
ANSI C29.2
Visual and dimensional tests
IEC 60383-1
Verification of the dimensions
Verification of the axial, radial, and
angular displacements
CSA C411.1-10
Visual inspection and verification of
dimensions
ANSI C29.2
Galvanizing test
IEC 60383-1
Galvanizing test
CSA C411.1-10
Galvanizing test
Dimensions
Galvanizing Test
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Table 7-8 (continued)
Cross Reference of Conformance Tests
Common Test Name
M&E Test
Standard Number
Standard Test Name
ANSI C29.2
Combined mechanical and electricalstrength tests
IEC 60383-1
Electromechanical failing load test
CSA C411.1-10
Electromechanical failing load test
Mechanical Strength
IEC 60383-1
Mechanical failing load test
Porosity Test
ANSI C29.2
Porosity Test
IEC 60383-1
Porosity Test
CSA C411.1-10
Porosity Test
ANSI C29.2
Puncture Tests
IEC 60383-1
Impulse overvoltage puncture
withstand test
Power-frequency puncture withstand
test
CSA C411.1-10
Puncture Test
RIV
IEC 60437
Radio interference test on highvoltage insulators
Thermal Cycle
IEC 60383-1
Temperature cycle test
CSA C411.1-10
Temperature cycle test
IEC 60383-1
Thermal Shock Test
Puncture
Thermal Shock Test
Visual and Dimensional Tests
In ANSI, three insulators are taken at random from the lot for inspection and checked for glaze
uniformity, smoothness, imperfections, and color. The dimensions are checked for conformity
with the dimensions shown in the manufacturer’s drawings.
In IEC, the dimensions are checked against the relevant drawings and the ball and socket are
gauged with the appropriate gauges. In CSA, the dimensions are checked with the drawings
supplied by the manufacturer and for compliance, the dimensions must be within the tolerances
stated.
In all three standards, failure to comply constitutes cause for rejection of the lot.
Verification of the Axial, Radial, and Angular Displacements
This test is only specified in IEC and checks sample insulators for cap and pin centering by
measuring the shell for out-of-roundness and variation from the horizontal plane. In the
procedure, sample insulators are held in an apparatus under light tension and rotated manually
with gauges set to the outer diameter of the shell and in the horizontal plane to determine the
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degree of off-centering of the hardware during cementing. The sample size is based on the size
of the lot and the degree of out-of-roundness and deviation from the horizontal plane are
specified. A re-test procedure is specified in the event of failure to comply.
Verification of the Locking System
ANSI does not specify a verification test of the locking system as a conformance test. Both IEC
and CSA have this requirement as a sample test. In IEC, there are four aspects to this
requirement. First, to indicate conformance of the design, the manufacturer must supply a
certificate. Second, samples are pinned together and checked to verify that no uncoupling occurs
during normal operation. Third, the key is checked to ensure that it can be removed by a tool
from the eye end, in other words, the eye does not enter into the hole of the cap to the extent that
removal with the usual tool is difficult. Finally, a test is performed on samples to check for the
load required to cause movement of the key from the locked to unlocked position. This operation
test is carried out three times after the final movement a specified load (Fmax) is applied to
check that it does not cause complete removal of the key.
In CSA, the test requirement is somewhat similar to IEC requiring verification that uncoupling
cannot occur during normal operation and that key can be easily removed from the eye end with
the usual tool.
Material tests
Porosity (Porcelain Only)
In ANSI, pieces taken from insulators that have been destroyed in other conformance tests, and
representative of the lot, are used to determine the porosity in accordance with the procedure
outlined in ANSI C29.1. The test in IEC and CSA are very similar to ANSI.
Cement Expansion (Porcelain Insulators Only)
CSA is the only standard that specifies a cement expansion test as a conformance test, but only
for porcelain insulators. In the specification, 6 samples of Portland cement are to be taken from
the batch used in the assembly of insulators in the lot. When tested in accordance with ASTM
C151, the cement expansion must be less than 0.12 % for acceptance of the lot.
Galvanizing
The requirements in ANSI, IEC and CSA on the thickness of the zinc layer are all different and
each specification refers to individual standards. ANSI states the required thickness and refers to
the measurement method in ASTM B499. IEC refers to the thickness and method of
measurement in ISO. CSA gives as a minimum, the mass for the layer, and refers to the method
in CSA C164 for the method of measurement.
The measurement methods of the three standards are compatible. The required thickness/mass of
the three standards is equivalent, though not equal. ANSI requires a 3.4 mil (86.36 μm) average
thickness over the entire sample of insulators with a minimum average per single insulator of
3.1 mil (78.74 μm). IEC requires 600 g/m² total average and 500 g/m² individual average
(3.35 mil/27.5 mil)) and CSA requires 550 g/m² (3.0 mil).
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Performance Tests
Combined Mechanical and Electrical Strength
The requirements for the combined M&E test in ANSI, IEC and CSA are all different, with
ANSI being the least stringent and CSA being the most stringent. Each standard refers to their
own method of loading and failing/criteria. However, all three recognize the load at which
electrical failure occurs to be taken as the failing load of the insulator under test.
In ANSI, 10 units are tested, regardless of the size of the lot. Acceptance is dependent not only
on the results of the tested sample but also depends on the historical standard deviation in
manufacturing.
IEC outlines the sample size that is dependent on the lot size. The acceptance criterion depends
on the standard deviation of the sample tested, which is dependent on the sample size. A retest is
permitted with a stiffer requirement should the initial sample fail to meet the specification.
In CSA, the sample size increases with the lot size, with 15 units being the minimum.
Acceptance requires that the mean strength must be three standard deviations above the rated
strength and each sample must be above the rated strength. This requirement is the most stringent
in the industry.
Puncture
Puncture under oil tests were introduced very early in the development of cap-and-pin porcelain
insulators as a means of testing the quality of the fired porcelain. At the time, the controls on the
firing were not as developed as they are today, and there were many problems with underfired
porcelain [4]. However, with improvements to kilns for better control of temperature, and
uniformity of temperature, the need for this test gradually disappeared. Today, this test is
redundant in lieu of the steep-front-of-wave test that can be used to identify underfired porcelains
and poor-quality glass. However, all three standards still specify puncture under oil test.
In ANSI, five insulators are tested in the manner described in ANSI C29.1. The criteria for
determining conformance depends on the puncture value given for each insulator type an also is
dependent on the historical average for puncture. In IEC, the test can be done either with power
frequency voltage or with impulse, as agreed upon between the purchaser and the manufacturer.
The sample size is determined by the size of the lots and a re-test is possible should one or two
units fail to meet the puncture value stated for the insulator type. The CSA requirement is
somewhat more demanding requiring all tested units have a puncture strength that exceeds the
value given for the applicable insulator type. In addition, the sample size is dependent on the size
of the lot, with five units as the minimum sample.
Temperature Cycle
ANSI does not specify a temperature cycle test as a conformance test. IEC and CSA are
essentially the same. In both, the number of samples is dependent on the size of the lot. The
insulators are cycled from hot to cold water, according to methodology specified, and on the
third cycle, the shells are examined for cracks/shattering, which constitutes failure to meet the
requirement. After thermal cycling and inspection, the units are tested for power frequency dry
withstand for 1 minute at 75 % of the dry flashover test. This is just to confirm that no internal
cracks developed.
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Routine Tests in Standards
Overview of Tests
Sample tests are performed as part of the quality control process to check the consistency of the
manufacturing process of each batch of insulators. During sample tests insulators may be tested
to destruction, dissected, analyses etc. so these tests are only performed on a few samples from
each batch.
The routine tests in ANSI C29.2 are also referred to as routine tests in both IEC 60383-1 and in
CSA 411.1-10. The routine test values and inspection criteria for the standard insulators in
ANSI, classes 52-1 through 52-12, are given in the applicable figures in ANSI C29.2. Table 7-9
provides a cross references of these tests.
Table 7-9
Cross Reference of Routine Tests
Common Test Name
Dimensions
Low Frequency Dry Flashover
Tension Proof
Thermal Shock Test
Standard Number
Standard Test Name
IEC 60383-1
Routine visual inspection
CSA C411.1-10
Visual Inspection
ANSI C29.2
Flashover test
IEC 60383-1
Routine electrical test
CSA C411.1-10
Electrical tests
ANSI C29.2
Tension proof test
IEC 60383-1
Routine mechanical test
CSA C411.1-10
Mechanical tension proof load test
ANSI C29.2
Cold-to-hot thermal shock test
Hot-to-cold thermal shock test
CSA C411.1-10
Thermal shock test
Visual Inspection
There is no requirement for a routine visual inspection in ANSI whereas a detailed visual
inspection is a requirement in both IEC and CSA. In both, the shell is inspected for uniformity
and for defects, with guidelines allowing flaws of a certain size. Defects include bubbles, in
complete shell molding etc. The metal hardware is also examined for uniformity of the
galvanizing layer.
Performance Tests
Tension Proof
The tension proof test is the same in all three standards. Each insulator is tensioned to 50 % of its
rated combined M&E strength and then stamped “Test” or “Proof Tested” to indicate that it has
been proof tested.
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Electrical Flashover
IEC allows for flashover of shells prior to assembly. ANSI and CSA specify the electrical
flashover test to be performed after the mechanical proof test.
Material tests
Cold-to-Hot Thermal Shock Test (Toughened Glass Only)
ANSI and CSA specify that each glass insulator produced be raised to a temperature 540°F
(300°C) above ambient temperature and maintained for at least 1 minute. Any glass shells that
break fail the requirement.
Hot-to-Cold Thermal Shock Test (Toughened Glass Only)
ANSI and CSA specify that each glass insulator produced submerged in water no hotter than
122°F (50°C) after the insulators had been heated to a temperature 212°F (100°C) above the
water. Any glass shells that break fail the requirement.
Example Specification
In this chapter, an example is provided for a technical specification for the procurement of
porcelain or toughened glass suspension insulators by the “Company”. Users will often
supplement IEC, CSA or ANSI tests from other specifications, and possibly tests of their own.
Normally, the technical specification is numbered, dated as to when it was issued, and if it
supersedes an existing standard, indicating that it is new. In addition, some users will combine
the technical requirements with the procurement requirements into one specification.
Note that in this example, the technical specification provided does not constitute the complete
specification as both technical and procurement specifications are necessary for the purchase of
insulators.
Note that throughout this chapter, italicized notes are used to provide instruction.
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Example specification
1. Scope
1.1 This specification covers the technical requirements for suspension type insulators, made of
porcelain or of toughened glass.
1.2 This specification supplements ANSI C29.2.
Note that in this example, insulators meeting ANSI standards are specified and this specification
supplements the standard.
2. References
Reference is made in this specification to the following standards, their latest issues,
amendments and supplements shall form part of this specification to the extent specified herein.
2.1 Standards of the Company
In this section, technical standards of the Company are referenced. These standards supplement
referenced National or International standards.
Note that in this example, there are no technical standards of the Company, but, for example,
this could be a withstand test to power arc, as in the Appendix of this guide.
2.2 Standards of the American National Standards Institute (ANSI)
As ANSI standard insulators are specified in this example, the applicable ANSI standards are
referenced and they are as follows:
2.2.1 C29.1 Test Method for Electrical Power Insulators
2.2.2 C29.2 Wet-Process Porcelain and Toughened Glass Insulators (Suspension Type)
2.2.3 Z55.1 Gray Finishes for Industrial Apparatus and Equipment
Note that Z55.1 is referenced if gray is the color specified for the porcelain insulators. Some
users will specify other colors to identify a strength rating, for ease of identification in the field.
2.4 Standards of the Canadian Standards Association (CSA)
As above, as ANSI insulators are specified in this example specification, only the applicable test
standards are referenced to supplement those of ANSI. In this example, the following is
referenced.
2.4.1 C411.1-10, AC Suspension Insulators
3. General
3.1 Insulators shall comply with all requirements of ANSI C29.2, except as modified herein.
3.2 Porcelain insulators shall be colored light gray, No 70, in accordance with ANSI Z55.1.
3.3 Ball-socket gauging shall be done on assembled insulators.
3.4 Sample sizes for acceptance tests shall be as specified in CSA 411.1-10.
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Note that as standard ANSI insulators are specified, only exceptions to the standard are
indicated. This example includes color, gauging of hardware on assembled insulators as
opposed to gauging of hardware as received from suppliers, and sample size for conformance
tests that are different from ANSI. Other requirements may be on the specification of cotter pins
for clevis-type insulators and on the force necessary for withdrawal of the cotter pin.
4. Design Tests
Except as otherwise indicated, the design tests outlined in Clause 8.2 of ANSI C29.2 is a part of
this specification. The number of samples for each of the design tests shall be as indicated in
Table 10 of CSA 411.1-10.
4.1 Thermal-mechanical load cycle test
This test shall be performed in accordance with clause 5.10 of CSA C411.1-10.
4.2 Steep front-of-wave flashover test
This test shall be performed in accordance with clause 5.6 of CSA C411.1-10.
4.3 Verification of coupling locking system
This test for ball-socket insulators shall be performed in accordance with clause 5.11 of CSA
C411.1-10.
4.4 Position of locking device
This test for ball-socket insulators shall be performed in accordance with clause 5.12 of CSA
C411.1-10.
5. Acceptance Tests
Except as otherwise indicated, the acceptance (conformance) tests as outlined in Clause 8.3 of
ANSI C29.2 is a part of this specification. The sample size is dependent on the size of the lot and
the number of units required for each conformance test is specified in CSA C411.1-10. A copy of
the test results in the form of report shall be supplied with each shipment.
5.1 Electromechanical failing load (porcelain)
This test shall be performed in accordance with clause 6.6.1 of CSA C411.1-10
5.2 Mechanical failing load (toughened glass)
This test shall be performed in accordance with clause 6.6.2 of CSA C411.1-10.
5.3 Visual inspection and verification of dimensions
This test shall be performed in accordance with clause 6.4 of CSA C411.1-10
5.4 Operation test on cotter key (ball-socket insulators)
This test shall be performed in accordance with clause 6.3 of CSA C411.1-10
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6. Routine Tests
Except as otherwise indicated, the routine tests as outlined in Clause 8.4 of ANSI C29.2 is a part
of this specification. A written statement (warrant) shall be supplied with each shipment
indicating that the routine tests have been performed.
6.1 Visual
This test shall be performed in accordance with clause 7.6 of CSA C411.1-10.
7. Insulator Identification
Each insulator must be permanently marked clearly showing the following:
7.1 Rated Strength in pounds
7.2 Proof test strength in pounds
7.3 Date stamp or date code of manufacture
7.4 Mark of the manufacturer
7.5 Country of manufacture
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Specification of Polymer Insulators
Introduction
The first polymer insulator designs were developed during the 1960’s, with the first test
installations following during the 1970’s. Users generally followed a conservative approach and
were slow to accept composite insulators as a good alternative to glass and porcelain insulators.
From its development until the 1980’s the application of composite insulators was limited to
either test installations or locations with a severe level of contamination where a quick return on
investment could be realized. Since the 90’s, however, the installed numbers have grown steadily
at a rapid pace indicating the general acceptance it has gained. Today, most of the manufacturers
have stable designs on offer and many utilities consider them as a mature alternative for use on
transmission overhead lines and substations. That being said, it is also true that there are still
many users that remain uncertain or skeptical about implementing composite insulators in their
networks. For these users the risks and associated costs outweigh the potential benefit that these
insulators may offer.
From the very beginning of its development, users have been confronted with the problem of
specifying the technical requirements for composite insulators. Although the basic functionality
of composite insulators is the same as for glass or porcelain insulators, its aging behavior and
construction were so different that a new approach had to be taken to verify the suitability of the
insulator’s design and performance. Initially users had to come up with their own requirements
and tests that need to be performed to verify the performance of the insulators, since there were
no standards available. This changed in 1989 when the American National Standards Institute
published the first standard for composite insulators (ANSI C29.11-1989). This was followed in
1992 by a standard from the International Electrotechnical Commission (IEC 61109), and one
from the Canadian Standards Association (CAN/CSA-C411.4-98) in 1998. These early standards
formed the basis for subsequent standards dealing with line post insulators (ANSI 29.17 and IEC
61952 both issued in 2002) and hollow insulators (IEC 61462 issued in 1998).
These standards are important to users and suppliers alike as they provide a common basis—in
terms of definitions, terminology and test methods—that can be used when specifying composite
insulators. As service experience and knowledge about the technology increased, the standards
became dated and a need for a substantial revision arose. Some years ago, the IEC started with
its revision with the development of a common clause standard (IEC 62217) that contains a
description of the definitions and test methods common to all composite insulator standards. This
standard has been completed in 2005. IEC continues this process with a revision of all standards
covering composite insulators (i.e., suspension, line post and hollow insulators) to bring them in
line with the latest knowledge and to establish a link to the common clause standard. It is
expected that these updates will become available during 2006-2007.
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Technology Issues
Several unresolved technology issues are still under discussion in the standards committees.
Some of the more important ones are:
•
•
•
•
2
The definition of the physical properties and minimum requirements for each type of outdoor
polymeric insulator material. It is common to refer to polymer materials by generic names,
such as “Silicone rubber”, EPDM, EPR etc., and to treat all materials of that class as having
identical characteristics. Field experience and laboratory results show however, that the
variation in performance of materials in each class can be large. This concerns both the longterm and flashover performance of the insulators. Also, without proper material definitions it
is not possible to objectively verify that a housing material is of a specific type.
The present insulator standards do not prescribe any artificial contamination tests for
composite insulators because there are no generally agreed upon methods that could be used.
The standardized methods available, that is, the Salt-Fog and Clean-Fog methods, are not
valid for use on composite insulators as they produce unacceptably large variations in the test
results. The major difficulty being the temporary loss and recovery of the water-repellent
properties of the polluted surface of especially silicone rubber insulators.
Historically insulator manufacturers produced short ceramic insulator units that can be
connected together to form into long assemblies. The individual insulator units can relatively
easily be subjected to both electrical and mechanical routine tests (i.e., every unit
manufactured can be tested). Composite insulator assemblies, on the other hand, are normally
made up of a single insulator unit. The long length of these insulators makes factory
electrical routine testing impractical, especially in the case of transmission class insulators.
Consequently, the routine tests in the relevant standards cover only a visual inspection and a
routine mechanical test. Aspects such as the electrical withstand, hydrophobicity, quality of
the end fitting seals, and end-fitting alignment are not assessed. The lack of electrical routine
tests is especially a concern when installing insulators live-line. There is thus a need to
consider other possibilities to verify and ensure production quality. In this regard the IEC is
considering an alternative where an ISO 9000 quality system may be implemented to
guarantee production quality to compliment the routine tests.
Traditionally standards distinguished between the insulator and the insulator assembly 2. The
design of the insulator assembly was considered as part of the tower configuration and due to
the nature of the materials used (i.e., glass and porcelain) it was assumed that the design of
the insulator assembly did not influence the performance of the insulator. For composite
insulators, however, this assumption is not true as it has been shown that the long-term
performance of this type of insulator is strongly influenced by the E-field distribution along
its surface and the possible damages caused by a power arc in case of flashover. Both these
issues may be resolved by a proper design of the insulator assembly and it’s positioning in
the tower. As a result, the clear line of responsibility that existed for glass and porcelain
insulator no longer exit for composites, and this may lead to the “double” application of
grading devices such as shown in Figure 7-1. An appropriate resolution to this problem still
needs to be found.
The assembly includes—conductor, tower, fittings, grading rings and their assembled geometry.
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Figure 7-1
Example of double grading ring application illustrating the problem of not properly resolving the
line of responsibility for assembly and insulator design.
From the user’s point of view there are other technology issues that should be resolved. These
are:
•
The life expectancy of composite insulators. From the beginnings of composite insulator
development, a concern of potential users has been that its life expectancy may be shorter
than that of the traditional insulator types. Reasons for this concern are:
- The bulk of composite insulators designs have been installed quite recently, and there is
not enough service experience available to enable a good estimation of the expected life.
- There have been a significant number of well-publicized brittle fractures that resulted in a
line drop and severe consequential damage.
- A large number of failures occurred within the first three years of installation due to
production problems or mishandling during transport, storage and installation.
There are indications that these concerns are being resolved at present. Information captured
in the EPRI failures database indicates that the design concepts of composite insulators have
improved since the failure rate per installed number of units shows a steady decrease. Also, a
lot of work has been done to educate users on good handling practices and, finally, there has
been significant research effort to better understand brittle fracture and methods to prevent it.
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•
•
•
The standards for composite insulators require the manufacturer redo prototype tests (i.e.,
Design tests in IEC and CSA) when there is a “change” in the materials used. What
constitutes a “change” however is not further defined and users have presently no method of
keeping track or enforcing this requirement. Work is underway to develop fingerprint
techniques to better identify changes in material composition.
There are several application related issues that may impact the performance of composite
insulators. These are issues such as:
- The use of high temperature conductors.
- The presence of fires under the overhead lines.
- The ability of the insulator to sustain a flashover without permanent damage.
- Risk for damage inflicted by animals during storage and on new installations before it is
energized.
- The risk that biological growth, such as mold, bacteria or lichen, may affect the flashover
performance of the insulators.
- The correct selection and installation of grading rings.
- The impact of the utility specified grading rings (for the insulator hardware) on material
aging.
- The proper specification of packaging requirements to prevent damage during shipping.
- Provision of instructions and training to contractors and utility staff on insulator handling,
storage, transporting and installation.
Presently none of these aspects are treated in the available standards and there is a need to
formalize an approach to address them in the specifications.
Inspection and assessment of in-service composite insulators: Although not directly
applicable to the specification of composite insulators, it is still a concern of insulator users.
High-risk composite insulators need to be identified before they fail to avoid involuntary
outages. Determining the end of life of an entire population is a concern. Also, from a live
line working perspective it is necessary to evaluate the flashover strength of the insulators
before work commences to ensure the safety of live line workers.
Applicable Standards
In most cases, the standards are used as the point of departure from which a specification is
developed. It is, therefore, necessary to indicate in the specification which of the national or
international standards is used as basis. The products offered are expected to comply with all of
provisions of the referenced standard(s). As explained in the previous chapter, the user may also
stipulate additional requirements, not covered by the referenced standard(s) to ensure a product’s
quality or suitability.
This chapter provides a review of the standards covering composite insulators from three
standardization bodies. These are:
•
•
•
ANSI (American National Standards Institute)
IEC (International Electrotechnical Commission)
CSA (Canadian Standards Association)
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A complete list of reference documents relevant to composite insulators is presented in Tables
4.1 and 4.2 for the ANSI and IEC standards respectively.
Table 7-10
ANSI standards and IEEE Guides Covering AC Transmission Line Composite Insulators.
Code
Year
Title
Remarks
ANSI C29.1
1988
Test methods for electrical power insulators
Revised 2002
ANSI C29.11
1989
Tests to composite suspension insulation for overhead
transmission lines
Revised 1996
ANSI C29.12
1997
For Insulators composite – suspension type
Revised 2002
ANSI C29.17
2002
For Insulators – Composite line post type
IEEE Std 987
2001
IEEE Guide for Application of Composite Insulators
IEEE Std 4
1995
IEEE Standard Techniques for High-Voltage Testing:
Amended 2001
The standards themselves also utilize a system of reference documents with the aim to reduce the
amount of duplication. In this way a hierarchy of documents is established where the higherlevel documents refer to lower-level documents, which provides definitions or describe standard
test methods. In theory this system of reference documents should work well, but in practice it
has become quite cumbersome. An example of this is illustrated in Figure 7-2 where the
hierarchy of the documents referred to by the IEC 61109 is presented. Note the two instances of
circular references present in this diagram. In these cases, it may not be clear which document
takes precedence in the case of conflicting requirements.
Table 7-11
IEC Standards and Reports related to Composite Insulators
Code
Year
Title
Remarks
IEC 60383-1
1993
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
Being
Updated
IEC 60383-2
1993
Insulators for overhead lines with a nominal voltage above
1000 V - Part 2: Insulator strings and insulator sets for a.c.
systems - Definitions, test methods and acceptance criteria
Being
Updated
IEC 62217
2012
Polymeric insulators for indoor and outdoor use with a nominal
voltage greater than 1 000 V - General definitions, test
methods and acceptance criteria
IEC 61109
2008
Composite insulators for a.c. overhead lines with a nominal
voltage greater than 1000 V - Definitions, test methods and
acceptance criteria
IEC 61466-1
2016
Composite string insulator units for overhead lines with a
nominal voltage greater than 1000 V - Part 1: Standard
strength classes and end fittings
IEC 61466-2
2002
Composite string insulator units for overhead lines with a
nominal voltage greater than 1 000 V - Part 2: Dimensional
and electrical characteristics
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Amended
2018
Table 7-1 (continued)
IEC Standards and Reports related to Composite Insulators
Code
Year
Title
IEC 61952
2008
Insulators for overhead lines – Composite line post insulators
for alternative current with a nominal voltage > 1000 V
IEC 60120
2020
Dimensions of ball and socket couplings of string insulator
units
IEC 60372
2020
Locking devices for ball and socket couplings of string
insulator units - Dimensions and tests
IEC 60471
2020
Dimensions of clevis and tongue couplings of string insulator
units
IEC/TS 61467
2008
Insulators for overhead lines with a nominal voltage above
1000 V - a.c. power arc tests on insulator sets
IEC 60437
1997
Radio interference test on high-voltage insulators
IEC 60507
2013
Artificial pollution tests on high-voltage insulators to be used
on a.c. systems
IEC TR 62662
2010
Guidance for production, testing and diagnostics of polymer
insulators with respect to brittle fracture of core materials
IEC/TS 62073
2016
Guidance on the measurement of wettability of insulator
surfaces
IEC 60815-1
2008
Selection and dimensioning of high-voltage insulators
intended for use in polluted conditions - Part 1: Definitions,
information and general principles
Being
updated
IEC 60815-3
2008
Selection and dimensioning of high-voltage insulators
intended for use in polluted conditions - Part 3: Polymer
insulators for a.c. systems
Being
updated
IEC 60050-471
2007
International Electrotechnical Vocabulary. Chapter 471:
Insulators
IEC 60060-1
2010
High-voltage test techniques. Part 1: General definitions and
test requirements
IEC 60071-1
2019
Insulation co-ordination - Part 1: Definitions, principles and
rules
IEC 60071-2
2018
Insulation co-ordination - Part 2: Application guide
IEC 60038
2009
IEC Standard voltages
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Remarks
IEC 61109
IEC 60507
IEC 60815
IEC 60305
IEC 60120
IEC 60383-1
IEC 60471
IEC 60347
IEC 60137
IEC 60168
CISPR 16-1
CISPR 18-2
IEC 60433
IEC 60372
IEC 60720
IEC 60672-1
Etc.
IEC 60672-3
IEC 60071-1
Etc.
IEC 60071-2
Etc.
IEC 60071-3
IEC 60050-471
IEC 60060-1
IEC 60383-2
Figure 7-2
The reference document hierarchy for the IEC 61109, showing the complexity that may arise. (Standards indicated by thick borders do
not contain reference documents.)
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At present the IEC is in a process of rationalizing the standards covering all types of composite
insulator. The first step has been completed with the publishing of a common clause document,
the IEC 62217, which contains all the tests common to all types of composite insulator. At
present the IEC 61109, which deals with composite insulators for lines, is being revised to refer
to the common clause document aims where applicable and to contain only those clauses specific
to line type insulators. The other standards dealing with composite insulators, e.g., line post
insulators (IEC 61952), will be revised in a similar manner. Working documents show that this
revision is substantial. It introduces, for example, the damage limit concept for defining the longterm mechanical characteristic of the composite insulator. The work on this revision is ongoing
and it is expected that the insulator specific standards will be ready for publication during
2006/9.
In addition to these standards there are a number of tests methods described by the American
Society for Testing and Materials (ASTM) to verify the electrical, mechanical, physical and
chemical properties of the materials used in composite insulators. The available ASTM test
methods are listed below. However, it should be noted that the composite insulator standards do
not refer to these tests in a uniform way. The standards dealing with suspension insulators only
refer to one, (i.e., the galvanizing test, ASTM A153-82) whereas the line post standard refers to
five (i.e., ASTM A153-95, D2240-95, G26-95, D2565-92a, and G53-95). It is therefore mostly
up to manufacturers to use these tests during insulator development and for quality control
during production.
A list of the available ASTM test methods is listed below, grouped together by the type of
properties that are tested.
Electrical Properties
•
•
•
•
Standard Test Method for Dielectric Breakdown Voltage and Dielectric Strength of Solid
Electrical Insulating Materials at Commercial Power Frequencies
(ASTM D 149)
Standard Test Methods for AC Loss Characteristics and Permittivity (Dielectric Constant) of
Solid Electrical Insulation
(ASTM D 150)
Standard Test Method for High-Voltage, Low-Current, Dry Arc Resistance of Solid
Electrical Insulation
(ASTM D 495)
Liquid-Contaminant, Inclined-Plane Tracking and Erosion of Insulating Materials
(ASTM D 2303)
Mechanical Properties
•
•
•
Standard Test Methods for Determining the Izod Pendulum Impact Resistance of Plastics
(ASTM D 256)
Standard Test Methods for Vulcanized Rubber and Thermoplastic Elastomers—Tension
(ASTM D 412)
Standard Test Methods for Rubber Properties in Compression
(ASTM D 575)
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•
•
•
•
•
•
Standard Test Methods for Rubber Property-Heat Generation and Flexing Fatigue In
Compression
(ASTM D 623)
Standard Test Method for Tear Strength of Conventional Vulcanized Rubber and
Thermoplastic Elastomers
(ASTM D 624)
Standard Test Method for Shear Strength of Plastics by Punch Tool
(ASTM D 732)
Standard Test Methods for Flexural Properties of Unreinforced and Reinforced Plastics and
Electrical Insulating Materials
(ASTM D 790)
Standard Test Method for Rubber Property—Durometer Hardness
(ASTM D 2240)
Standard Test Method for Apparent Hoop Tensile Strength of Plastic or Reinforced Plastic
Pipe by Split Disk Method
(ASTM D 2290)
Physical Properties
•
Standard Test Method for Coefficient of Linear Thermal Expansion of Plastics Between 30°C and 30°C With a Vitreous Silica Dilatometer
(ASTM D 696)
Chemical and Environmental Properties
•
•
•
•
•
•
Standard Practice for Determining Resistance of Synthetic Polymeric Materials to Fungi
(ASTM G 21)
Standard Test Method for Rubber Property-Effect of Liquids
(ASTM D 471)
Standard Test Method for Rubber Deterioration-Surface Ozone Cracking in a Chamber
(ASTM D 1149)
Standard Test Method for Voltage Endurance of Solid Electrical Insulating Materials
Subjected to Partial Discharges (Corona) on the Surface
(ASTM D 2275)
Standard Specification for Zinc Coating (Hot-Dip) on Iron and Steel Hardware
(ASTM A153)
Xenon-Arc Exposure of Plastics Intended for Outdoor Applications
(ASTM D 2565)
Functional Characteristics of Polymer Insulators
The various insulator terms, characteristics and parameters that are used to define insulators in
specifications and standards are listed and defined in Chapter 2: “General Insulator Terms and
Classification”.
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Design/Prototype Tests in the Standards
Background
The design, or prototype tests are performed on a specific design of composite insulator to ensure
that the materials and technology used to produce the insulators will be able to withstand the
stresses that it will be subjected to during its service life. Each standard defines a composite
insulator design or class according to a list of properties that should be the same. These
properties are listed in Table 7-12 as defined by ANSI, IEC and CSA. All three standards agree
to a large extent on how an insulator design or class is defined, but there are some significant
differences as can be seen in the table.
In the present ANSI and IEC standards requirement is that the manufacturer redo all the design
(or prototype) tests if one of the parameters is changed. The Canadian standard has a schedule
for retesting based on which design parameters have been changed. (Future IEC standards will
also follow the CSA lead.) A problem with deciding when retesting ins necessary is that some of
the items listed in Table 7-12 are not, or cannot be, defined in a precise way. For example, it is
not defined what constitutes a type of weathershed material or how it can be verified that the
insulator offered has the same weathershed material than the one tested. Other problematic
definitions are the concepts “end fitting design” and “method of manufacture”. With these
imprecise definitions it is not always clear when retesting should be done. This may lead to
differences in opinion between buyer and manufacturer about what constitutes a change. Also,
the insulator user may not be aware of any changes of the insulator design that has taken place
since the manufacturer did not regard them as significant. With this in mind, some utilities keep
spare reference units, or are considering some form of chemical fingerprinting, that could help
keeping track of changes.
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Table 7-12
Comparison of the properties used by ANSI, IEC and CSA to define an insulator design concept.
Insulator Design Concept Definition
ANSI
IEC
CSA
Weathershed material
Shed material
Shed material
—
—
Housing material
—
—
Shed design
(diameter thickness and
shape)
Housing thickness
Layer thickness of shed or
sheath material over the core
Housing design (thickness and
covering of metal fittings)
Core material
Same core material
Core material
Core diameter
Same core diameter
Core diameter
Ratio of S.M.L to the smallest
core radial cross-sectional
area
Ratio of all mechanical loads
to the smallest core diameter
—
Method of manufacture
—
Manufacturing process
End fitting material
End fitting material
Metal fitting material
—
—
Metal fitting connection zone
design
End fitting design
End fitting design
Metal fitting coupling design
—
—
Core-housing-metal fitting
interface design
End fitting method of
attachment to core
End fitting method of
attachment
Metal fitting method of
attachment to core
—
Ratio of highest system
voltage to insulation length
—
Overview of Tests
In the ANSI and IEC standards the design or prototype tests are named after the component of
the composite insulator that it tests. These are:
•
•
•
•
Tests on interfaces and the connection of the end fittings
Assembled core load-time test
Test of housing (tracking and erosion)
Tests on the core material
The CSA Standard contains essentially the same tests, but they are not identified in the same
way.
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It should be noted that the design or prototype tests are not performed on full-scale insulators
since the required minimum length of the tested sample is 800 mm. This means that the tested
sample may not have all the design features that are present full-scale insulators. Examples
include:
•
•
•
Housing to housing interfaces resulting from a double shot molding process or the need for
multiple shed sections that slips onto the rod to make up the full insulator length.
The housing may not be machined in the same way on non-standard insulator lengths as is
done on full-scale units.
Inclusion of spacers to fix the core in position during the molding process.
Since the above listed features may present weak points in the design, it is important to ensure
that the insulators subjected to the design tests include these if present on full-length insulators.
Tests on Interfaces and Connection of Metal Fittings
Interfaces are those points on an insulator where different kinds of material come into contact
with each other. An overview of the types of interface that may occur in composite insulators is
presented in Figure 7-3. These interfaces present possible weak points in the insulator design, as
they may be points of mechanical or electrical stress concentration. Mechanical stresses may
arise because of differences in the expansion coefficient or flexibility of the materials in contact,
and an E-field concentration may result from differences in the electrical characteristics, e.g.,
conductivity and permittivity, of the materials in contact. The tests on interfaces and the
connection of the metal fittings aim to verify that these interfaces can withstand the operating
mechanical and thermal loading for its expected lifetime without any degradation.
Core – end fitting
interface
End fitting seal
-Rod
- Housing
- Metal end fitting
Housing – housing
interface
Core – housing
interface
Figure 7-3
A cut-away drawing of a composite insulator showing its different interfaces.
In both the ANSI and IEC standards the test on the interfaces and connection of metal fittings
constitutes a series of tests that are performed on the same specimen, as is shown in Figure 7-4.
The CSA standard follows a different strategy where the where the tests are performed
independently from each other.
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A schematic representation of the ANSI and IEC test series is presented in Figure 7-4. It starts
with determining the dry power frequency flashover voltage of the test specimen. This value will
be used at the end of the test as benchmark to track any change in performance that may be
induced by the stressing tests. The initial benchmarking is followed by three so-called pre-stress
tests that are performed on the same unit:
•
•
•
Sudden load release test – This simulates the service condition were an overhead line
conductor sheds an ice load.
Thermal mechanical test – On suspension insulators, the insulator is under a constant tensile
load while being subjected to four 24-hour temperature cycles. Both ANSI and IEC specify
the temperature levels as –35°C and +50°C. The tensile load applied to the suspension
insulator corresponds to the routine test load—i.e., 50% of the Specified Mechanical Load.
Line post insulators are subjected to the same temperature cycles, but the maximum design
cantilever load, which is in the order of 50% of the Specified Cantilever Load, is applied.
The direction of the cantilever force is reversed halfway through the thermal-mechanical test.
This test is derived from the thermal-mechanical test is performed on glass and porcelain
insulators.
Water immersion (penetration) test – This test is designed to verify the integrity of the end
fitting seal after the mechanical and thermal stresses has been applied. The insulator is
immersed in boiling water for 42 hours. For this test ANSI prescribes tap water while the
IEC requires that a 0,1% Saline solution is used.
Benchmark tests
Single sample
Dry P.F.
Flashover test
Prestressing tests
Sudden Load
Release test
Thermalmechanical test
Water
immersion test
Verification tests
Visual
inspection
Steep front
test
Dry P.F.
Flashover test
Figure 7-4
A schematic representation of the tests on interfaces and connection of metal fittings (ANSI and
IEC only).
It is assumed that any water that penetrates into the insulator during the water immersion test will
negatively affect the electrical performance of the insulator. This is utilized in the verification
tests that follow directly after the pre-stress tests. Three verification tests are performed:
•
•
Visual inspection to check for any visible damage, such as cracks, to the insulator.
Steep front impulse test to verify that the insulator housing will not puncture (and that no
water has penetrated to the core during the water immersion test).
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•
A dry power frequency test is performed at the end of the test series to verify that the
flashover performance of the insulator has not deteriorated by more than 20%. The insulator
is also continuously energized for a period of 30 minutes to detect any temperature rise
caused by water that penetrated the insulator housing. The standards do not specify how the
temperature rise shall be measured.
The CSA standard does not require the test series as a whole to be performed on one particular
test sample as ANSI and the IEC does. However, it prescribes both the thermal-mechanical and
the water penetration tests as stand-alone tests. For comparison both the water penetration and
thermal mechanical tests as described by the CSA are shown in Figure 7-5.
Benchmark tests
Three samples
Hardness of
the sheds
Thermalmechanical test
Water
immersion test
Verification tests
Hardness of
the sheds
Visual
inspection
Dry P.F.
Flashover test
One sample
Prestressing tests
Three samples
Steep front impulse
voltage test
Thermal
mechanical
Verification tests
Moisture (Dye)
penetration
Evaluation
Figure 7-5
A schematic representation of the tests on interfaces and connection of metal fittings (CSA).
The water penetration test of the CSA resembles the test on the interfaces and connection of the
ANSI/IEC with the exception that no mechanical tests are performed. The water penetration test
itself also differs significantly from that of ANSI and the IEC. In the Canadian standard the time
that the insulator is submerged in boiling water is 100 h instead of the 42 h specified in ANSI
and IEC. The CSA standard also contains an additional requirement that the shed material be
subjected to a hardness test to verify that this has not deteriorated during the test.
The Canadian standard does not prescribe any equivalent to the sudden load release test.
The thermal mechanical test prescribed by the CSA differs in some respects to that of ANSI/IEC.
In the CSA test, the temperature levels are specified as –50°C and +50°C as opposed to the
–35°C and +50°C specified by ANSI/IEC. In addition, the damage to the end seal and housing is
assessed through a dye penetration test and a limit is placed on the length increase of the
insulator, both these aspects are not required by ANSI/IEC.
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Tests for the Core Material
The core is subjected to both the mechanical forces and voltage applied to the insulator. It is
however protected from the environment by the housing. The core of the insulator is indicated in
Figure 7-6.
Core
Figure 7-6
A cut-away drawing of a composite insulator showing its core.
Two tests are specified in all of the standards to verify the electrical performance and quality of
the core material:
1. Dye penetration test
2. Water diffusion test
There are only minor differences between the three standards in description of these tests. These
differences are highlighted in the following.
For the dye penetration test, short sections (i.e., 10 mm) of core are placed in a shallow dye
solution and the time is measured that it takes for the dye to rise through the core. The IEC
standard specifies that the 1% ethanol solution of fuschin dye be used, whereas for the ANSI and
CSA dye penetration test a 1% methanol solution is specified. All standards use the same
minimum 15-minute time criterion. In the newly published IEC 62217, two important changes
have been introduced:
1. A different type of dye is specified, i.e., methin instead of the fuschin used previously.
2. The choice of using a methyl or ethyl alcohol solution is left up to the testing facility.
Initial experimentation has shown that the choice of dye and solvent may influence the outcome
of the test. ANSI working group C.29 is in a process of investigating this matter further with a
view to finalize their choice of dye.
The water diffusion test is a multi-step test that comprises three steps:
1. Preparation of the sample. Six samples, each with a length of 30 mm, are cut from the
insulator core and prepared for testing.
2. The pre-stressing test consists of boiling the samples for 100 hours in a 0,1% by weight
saline solution.
3. The samples are electrically verification test by checking that the samples can withstand an
a.c. voltage of 12 kV for one minute during which the leakage current may not exceed 1 mA.
The description of the water diffusion test is identical in the three standards.
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Assembled Core Load - Time Test
The core forms, with the end fittings, the main mechanical load-bearing component of the
composite insulator as is shown in Figure 7-7. The tensile strength of the insulator is determined
by the combined strength of the:
•
•
•
Metal end fitting
End fitting rod interface
Rod
In the standards the test on the assembled core (i.e., core with end fittings attached – is therefore
used to characterize the mechanical characteristics of the insulator.)
End fitting
Core
End fitting
Figure 7-7
A cut-away drawing of a composite insulator showing its core and end fittings.
An important factor that determines the long-term mechanical performance of the composite
insulator is the strength of the core. It is assumed that the mechanical strength of a Resin Bonded
Glass-Fiber rod is time dependent. This means that the strength of the rod at any time is
dependent on the history of mechanical loading and previous exposure to high temperatures. In
general, it can be stated that the time to failure becomes shorter for increasing mechanical
loadings, because of the assumed progressive failure of the glass fibers in the rod under loading.
The weakest fibers break first and their mechanical load is then transferred via the resin matrix to
the remaining fibers, which are then subjected to a higher loading. This, in turn may lead to more
fibers breaking and through this process the core is progressively weakened until it cannot
withstand the loading any longer and breaks. The rate at which the fibers break is dependent on
the level of the mechanical load, and it is described by the so-called “load-time” characteristic of
the core.
A number of characteristics are used to define the mechanical strength of a composite insulator.
The terms used in the following sections are summarized in Table 7-13.
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Table 7-13
The definition of important mechanical characteristics as used in the standards.
Suspension
Line Post
Definition
Mav
—
The Mav is the average tensile mechanical failing load of the composite
line post insulator under short time testing.
SML
STL
The Specified Mechanical Load (SML) or the Specified Tensile Load
(STL) is the minimum tensile mechanical failing load of the composite line
post insulator under short time testing. It is up to manufacturers to
determine the SML of an insulator.
Not
applicable
SCL
The SCL is the cantilever mechanical load which the insulator is able to
withstand under specified conditions. It is up to manufacturers to
determine the SCL of an insulator.
Not
applicable
MDCL
IEC defines the MDCL as the load level above which damage to the core
begins. It is therefore the ultimate level for service loads. The
manufacturer specifies the MDCL and its direction.
Not
applicable
RCL
ANSI defines the RCL as the load level above which damage to the core
begins. It is therefore the ultimate level for service loads. The
manufacturer specifies the RCL and its direction.
RTL
—
This is the level of mechanical tensile load which all assembled insulators
are subjected to during the routine mechanical test. The RTL is defined
as 50% of the SML/STL.
Longrod or suspension insulators:
In the standards dealing with suspension insulators reference is made to three different time-load
characteristics. These are:
1. The average failing strength load-time curve of the insulator.
2. The withstand strength load-time curve of the insulator corresponding to a 10% probability
for failure.
3. The specified strength load-time curve of the insulator is the guaranteed withstand
characteristic. This is determined by the manufacturer from the withstand curve with the
incorporation of a safety factor based on own experience.
The first two curves mentioned above, (i.e., average and withstand strength), describes the actual
strength characteristic of the core while the third, (i.e., specified strength), is the characteristic on
which the user will base his selection of the mechanical strength of the insulator. At the time
when the present standards were written, experimental evidence indicated that these load-time
characteristics should be described by a logarithmic function as is illustrated in Figure 7-8.
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Mechanical Strength (% of SML)
140
Manufacturer's
safety factor
120
Average Failing Strength
Withstand Strength
Specified Strength
100
80
60
40
20
0
100
101
102
104
103
105
106
107
108
Time (minutes)
Figure 7-8
An Illustration of the three types of load-time strength mentioned in the present ANSI, IEC and
CSA standards for composite suspension insulators.
The assembled core test prescribed in the standards for composite longrod insulators is intended
to verify the time-load characteristic of the core. It focuses therefore on verifying the average and
withstand strengths, i.e., characteristic (1) and (2) listed above. The specified strength, or
characteristic (3), is used by the IEC as part of the type definition and it is therefore verified by a
type test—see section on Design/Type tests.
The test itself is devised to verify that the slope of the average load-time failing characteristic of
the core does not exceed 8% per decade of time 3. The standards have opted for the following
testing sequence:
1. Determine the short time average failing load (Mav) of the core of three assembled insulator
units (i.e., Point 1 in Figure 7-9.)
2. Perform a 96 hour withstand test on three insulator units at a mechanical loading which is
60% of average failing load (Mav) determined in step one (i.e., Point 2 in Figure 7-9).
This approach is in line with the normal approach in the standards to prescribe a withstand test
that results a clear “pass”/“fail” verdict. Since the 96 h test is a withstand test, it needs to be
performed at a mechanical loading which is below the expected failing load—which is minimal
70% of the average one minute failing load (Mav).
In Annex A of IEC 61109 it is explained how the withstand strength characteristic is derived
from the average failing strength. Based on three test samples and a standard deviation of 8% it
is shown that the applied test load should be 60% of Mav.
3
In this case a decade of time does not represent 10 years but an increase of one power of ten in time.
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Mav
1
Average Failing Strength
Withstand Strength
120
Specified Strength
100
0.7 x Mav
2
80
0.6 x Mav
60
40
96 hours
Mechanical Strength (% of SML)
140
20
0
100
101
102
103
104
105
106
107
108
Time (minutes)
Figure 7-9
The load time strength relationship that forms the basis of the present IEC61109 standard.
Since the standards were issued, a substantial body of evidence has been collected which
indicates that the assumed logarithmic strength time relationship as shown in Figure 7-8 is a
pessimistic view of the deterioration of strength over time. Evidence from long-term testing has
shown that there exists a loading, called the damage limit, below which the strength of the core
does not deteriorate with time. The core thus exhibits two distinct phases of behavior under load.
Below the damage limit the core behaves “elastic” and above the damage limit its behavior
becomes “plastic” when damage is inflicted to the rod. It was found experimentally that the
damage limit is about 60% to 70% of the ultimate tensile strength (UTS = Mav) of the rod. As a
result the average failing load curve as a function of Log-time is not a straight descending line as
shown in Figure 7-9 but it flattens out at 60-70% of average short time failing load as is
illustrated in Figure 7-10 (i.e., equal to 78% of the SML for the example shown in the figure).
As shown in Figure 7-10 the withstand curve approaches the failing load curve for long time
exposures. This is a result of the damage limit. The specified strength curve, which is based on
the SML, is conservatively still assumed to have the same slope as the average failing load curve
as is illustrated in Figure 7-10.
This new information has a great impact on the selection of the mechanical characteristics.
During its working life the insulator will only be loaded within the elastic phase. It is therefore
not necessary to take the load-time characteristics into account to the same extent as previously.
The damage concept will be introduced into the upcoming revision of IEC 61109.
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140
Mav
100
80
Damage limit = 0.6 x 130 = 78
Elastic phase
60
40
96 hours
Strength (% of SML)
120
Plastic phase
Average failing load curve
Withstand load curve
Specified strength curve
20
0
0
1
10
10
2
10
3
10
4
10
5
10
10
6
10
7
10
8
Time (minutes)
Figure 7-10
A schematic representation of the load time strength relationship as is indicated by experimental
evidence.
Line Post Insulators:
Line post insulators differ greatly from longrod insulators with respect to their mechanical design
and loading. Whereas longrod insulators are only subjected to axial tensile loads, line post
insulators may be subjected to a complex load pattern comprising a summation of compression,
tension, cantilever and longitudinal conductor forces. These forces, which are illustrated in
Figure 7-11, result in an equivalent bending moment around the point where the core is fixed
into the end fitting. The line post insulator must be selected so that this bending moment do not
result in a compressive stress in the core which is greater than that defined by the maximum
usable bending stress of the insulator. This requirement assumes that the maximum usable
bending stress does not lead to any permanent damage to the core, which is in turn based on the
concept of a damage limit, as explained for longrod insulators. In many cases manufacturers
provide the insulator user with a set of curves to help users to select the correct insulator in cases
with a complex loading pattern.
In the IEC standard (IEC 61952) the maximum bending stress of a line post insulator is verified
by the test for the verification of the Maximum Design Cantilever Load (MDCL). After this test
a dye penetration test is performed to verify that the core is free from cracks or delaminations.
The IEC leaves it up to the manufacturer to define the MDCL in terms of the Specified
Cantilever Load (SCL), which is the guaranteed short-term cantilever withstand load of the
insulator. The underlying assumption here is that the MDCL represents the damage limit for post
insulators. By making sure the service loading is below the damage limit, the insulator operates
in the elastic phase without permanent damage to the core.
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ANSI on the other hand, defines in ANSI C29.17 the load to be applied during the 96-hour core
time load test as 40% of the Specified Cantilever Load (SCL). Alternatively, the manufacturer
may define a Reference Cantilever Load (RCL), which is equivalent to the MDCL defined in
IEC. In such a case the time load test is performed at the RCL or MDCL only if it exceeds 40%
of the SCL. As with the IEC, ANSI also subjects the insulator core to a dye penetration test after
the 96 hours test is completed to detect any cracks or delaminations in the core.
Equivalent
Bending moment
Longitudinal
Tension
Compression
Vertical
d
Figure 7-11
A schematic representation of the load time strength relationship as is indicated by experimental
evidence.
In both IEC and ANSI standards, the end fittings and method of attachment is checked by the
tensile load test during which the loading of the insulator is increased to its Specified Tensile
Load (STL) within 90 seconds. The insulator must withstand this load without any damage to
core or pull-off of the end fittings.
Test of the Housing, the Tracking and Erosion Test
The housing of a composite insulator, see Figure 7-12, is intended to provide the necessary
creepage distance and to protect the core from the environment. In the standards, the tests are
aimed verifying the durability of the housing to withstand the environmental and subsequent
electrical discharges that may occur.
Housing
Figure 7-12
A cut-away drawing of a composite insulator showing its housing.
All three standards specify a tracking and erosion test. ANSI and IEC specify a 1000-hour salt
fog test while the CSA requires that one of two so-called “tracking wheel” tests be performed. In
addition, the IEC also describes a 5000-hour multi-stress test that may be performed in lieu of
the 1000-hour test. These tests are often called “ageing tests” in the literature. This is however
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not correct as these tests do not simulate the real-life degradation conditions, nor do they
accelerate service stresses to give an equivalent life test in a relatively short time. All these
standardized tests use continuous, cyclic or combined stresses to try and detect potential
weaknesses that could compromise the insulators performance in service. These tests are
therefore best described as “screening tests”.
The 1000-hour salt fog test specified by ANSI and IEC is a continuous stress test. Two
composite insulators—one installed vertically and the other horizontally—are constantly
energized to a USCD of 34.6 mm/kV and subjected to a standard salt fog of 10 kg/m3 for
1000 hours. During this time no more than three over-current (i.e., 1 Amp) trip outs are allowed
and the test specimens may not exhibit tracking or punctures of the weathersheds. Erosion may
not have reached the core.
Subsequent research has shown that the salinity of 10 kg/m3 defined in the ANSI and IEC
standards are too high. This level of salinity leads to a high level of leakage current and a high
mobility of the dry-band arcing on the insulator surface. The high arc mobility leads to a lesser
degree of tracking and erosion than during tests performed at a salinity in the order of 1-5 kg/m3.
In the new general definitions document, IEC 62217, the 1000-h salt fog test is substantially
revised and updated. One of the major points is the reduction of the salinity of the salt water in
order to avoid flashovers and to increase the potential for erosion. This test, even in the updated
version, should be classified as a pure tracking and erosion test and not an aging test since there
is no attempt to subject the insulator to typical service stresses such as Ultra-violet light,
temperature cycles or periods of “recovery”.
The CSA standard describes two versions of the tracking wheel test. During this test the insulator
is subjected to alternate wet and dry periods that gives rise to surface arcing on the insulator. The
two alternatives are:
•
•
Constant energization and alternate periods of exposure to a salt spray and drying for a
duration of 1000 hours.
Four stationary test points i.e., (1) Dipping in salt water, (2) Drip off period, (3) energized
period with surface arcing, and (4) cooling period. The duration of this tests is 30 000 cycles
that each lasts about 192 s, or a total of 1600 h.
In IEC 62217, the new common clause document, also describes a version of the tracking wheel
test very similar to the latter one described above.
As with the 1000-h test, tracking wheel tests are classified as pure tracking and erosion tests that
can be used for the screening of materials and designs.
The IEC standard also describes an alternative tracking and erosion test that can be performed in
lieu of the 1000-h salt fog test. This is the 5000-h multi-stress test originally developed by
Electricité de France (EdF) and subsequently adopted by Cigré and the IEC. The 5000-h multistress test subjects the insulator under test to multiple stresses in 24-hour cycles while the
insulator is energized to its maximum operating voltage, i.e., Vm/√3.
One cycle consists of different periods during which the insulator is exposed to demineralized
rain, heating, humidification, fog generated from saltwater, and simulated solar radiation. The
representativity of the test was confirmed by comparing the damage sustained during the test
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with that occurring at an outdoor test station. Based on this comparison, an acceleration factor of
10 was determined for this test. Due to practical and cost limitations, the 5000-h test is normally
performed in a small test chamber with a test voltage of between 14 and 20 kV. However, an
aging chamber with a test voltage of 245/√3 kV has been installed in France for full-scale testing
at higher voltage levels.
The present version of IEC 61109 provides a general description of the 5000-h test but not much
detail has been given about the exact conditions of the test and the test apparatus that should be
used. This has contributed to a questionable reproducibility of the test. In the presently ongoing
revision of the test methods within the IEC (i.e., IEC 62217) the test procedure is firmed up with
respect to its reproducibility.
Daily cycle
Test Voltage: 14-20 kV (rms)
Fog generated from a salinity
of 7 kg/m³
Demineralized rain
1,5 mm/min
Humidification 98 % r.h.
Heating 50 °C
Solar radiation simulation
≈ 0,9 kW/m²
0
2
4
6
8
10 12 14 16 18 20 22 24
Time Hours
Figure 7-13
The aging cycle for the CIGRÉ 5000-hour test.
Housing Material Tests
In the IEC 61109, IEC 61952 and ANSI C29.17 standards, a flammability test is required to
check that the housing material does not ignite easily and that it self-extinguishes when the flame
is removed from the sample. This test is important to verify that the insulators will not be
jeopardized when exposed to fires (e.g., sugar cane burning) under the overhead lines. There is,
however, some debate over the necessity of such a test as the tracking and erosion test will also
fail materials that do ignite easily or do not self-extinguish.
Another test of the housing materials required by some standards is a check of its UV stability:
•
•
CSA-C411 and ANSI C29.17 requires a 1000 h UV testing according to ASTM.
IEC 61952 and the new common clause document, IEC 62217 are based on a 1000 h solar
irradiation or UV test according to the ISO 4892 documents.
The test is passed if the housing material does not exhibit surface degradations such as cracks or
blisters.
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Design/Type Tests in the Standards
Background
The Type or Design of an insulator is defined in terms of the dimensions listed in Table 7-14.
The ANSI, IEC and CSA all use the same parameters to do this. From a system application point
of view the required characteristics of the insulator is described in terms of its electrical and
mechanical strength. Type, or in ANSI terminology Design, tests aim to verify that the insulator
on offer comply with the required electrical and mechanical strength values.
There is a difference the way the IEC on the one hand, and ANSI and CSA on the other, define
the insulator’s electrical characteristics. In the IEC standard it is defined in terms of withstand
values, whereas in the ANSI and CSA standard it is done in terms of critical flashover
characteristics. This means that electrical characteristics quoted in IEC cannot be compared
directly to those of the ANSI and CSA standards.
Electrical
Mechanical
Insulator Type Definition
Table 7-14
Comparison of the definition of an insulator type according to ANSI, IEC and CSA.
ANSI
IEC
CSA
Dry arcing distance
Arcing distance
Arcing distance
Leakage distance
Creepage distance
Leakage distance
Weathershed inclination
Shed inclination
Shed inclination
Weathershed diameter
Shed diameter
Shed diameter
Weathershed spacing
Shed spacing
Shed spacing
Core diameter
Core diameter
Core diameter
Method of attachment of the
end fittings
Method of attachment of
the end fittings
Method of attachment of
the end fittings
—
Specified cantilever load
(for line posts)
—
Type tests are only repeated if any of the parameters that define the insulator type, i.e., those
listed in Table 7-14, has been changed. Logically the electrical tests need to be redone if an
electrical parameter is changed and the mechanical tests for a change in any mechanical
parameter. In this regard all standards follow the same approach.
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It is not customary for users to specify values for the parameters in Table 7-14, rather the
required electrical and mechanical strength characteristics of the composite insulator are
specified. It is then up to the manufacturer to determine the required dimensions to fulfill the
electrical and mechanical performance criteria. There are however two exceptions to this general
rule:
1. Creepage distance: The creepage distance needs to be specified by the insulator user
because a general agreement has not yet been reached on a suitable contamination test
method, or methodology, that could be used reliably to verify the adequacy of the provided
creepage distance of the insulator. General practice is to specify the same creepage distance
as for glass or porcelain under the same conditions.
2. Section length: In the case of re-insulation projects, it may be necessary to specify the
section length of the insulators to facilitate direct replacement. In such cases the user should
be aware that there is a risk for conflicting demands if the user specifies both the section
length and the electrical insulation level, i.e., (i.e., the lightning or switching impulse
strength). It should be noted that normally the manufacturer is free to determine the section
length of the insulator based on the insulation level specified by the user.
Overview of Tests
A set of electrical and mechanical type tests is performed to confirm that the required values are
met. A list of the type tests listed in the standards reviewed is presented in Table 7-15. Of the
tests mentioned, only the mechanical load-time test specified in the IEC and CSA is specific to
composite insulators. The ANSI standard requires no mechanical type test.
The mechanical type test for longrod insulators verifies the correctness of the Specified
Mechanical Load (SML) and the load-time characteristic of the insulator. Both IEC and CSA
describe the same test, but in the evaluation of the results, the IEC holds to stricter acceptance
criteria. CSA only requires the insulator to remain intact to pass the test while the IEC also
requires that no cracks have formed in the core, but no method to check for cracks is described.
For line post insulators IEC specifies that a cantilever failing load test be performed to verify that
the failing load values are higher than the SCL. No mechanical design tests are prescribed for
line post insulators in ANSI C29.17.
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Table 7-15
Comparison of the type tests according to ANSI, IEC and CSA.
Electrical
Mechanical
Insulator type definition
ANSI
IEC
CSA
Lightning Critical Impulse
Flashover
Dry Lightning impulse
withstand voltage test
Critical Impulse Flashover
Low frequency Dry flashover
—
—
Low frequency wet flashover
Wet P.F. test
60 Hz wet flashover
Switching Critical –impulse
flashover test
Wet switching impulse
withstand test
—
Corona test
Radio Interference test
(Radio-influence voltage and
visible corona test on line post
insulators)
Radio Interference test
—
None
Verification of the SML – for
longrod insulators
(Mechanical load-time test)
Verification of the SML
(Mechanical load-time test)
Cantilever failing load test –
for line post insulators
In the CSA standard an extensive corona test is described. The aim is to check that the corona
extinction gradient is higher than that occurring under nominal service conditions. For this
purpose, a gradient calibration device is used to ensure that the test voltage produces an E-field
gradient representative of nominal service conditions. The insulator buyer needs to provide
information about the conductor bundle that should be used and the surface E-field gradient at
which it is operated.
A corona test is not required by the IEC and ANSI standards. However, the IEC and ANSI
standards do include a Radio Interference test, but the acceptable levels are left for agreement
between purchaser and manufacturer.
The mechanical type tests prescribed by the IEC and the CSA serve as a verification of the
Specified Strength Characteristic, which is the guaranteed withstand load-time characteristic of
the insulator that forms the basis for the mechanical selection of the insulator.
The specified strength load-time strength curve, as is described in the present IEC 61109, is
shown in Figure 7-8. It has the following properties:
•
•
At one minute the Specified Strength is equal to the Specified Mechanical Load (SML) of the
insulator. It is up to the manufacturer to choose the SML of the insulator.
The slope of the logarithmic curve is 8% per decade of time (in minutes).
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Mechanical Strength (% of SML)
120
Specified Strength
100
80
60
40
20
0
100
101
102
103
104
105
106
107
108
Time (minutes)
Figure 7-14
The assumed load time strength used by the IEC for composite insulators.
The verification testing prescribed by the IEC checks by sequential testing two points on the
Specified strength characteristic.
1. A tensile test is performed on four samples to verify that the insulator can withstand 70% of
the SML for 96-hours. One of these samples is then subjected to a dye penetration test to
check that no cracks formed in the housing, end fitting seal or core during the test.
2. Verify that the same insulator as is tested in step (1) can subsequently withstand the
Specified Mechanical Load (SML) for a maximum of 60 seconds.
The insulator passes the test if the insulator withstood the prescribed mechanical loadings
without any damage. The standards indicate that the mechanical load may be increased directly
after the withstand test (i.e., step 2 above) to determine the breaking load to obtain more
information.
Quality Conformance/Sample Tests in Standards
Overview and Sampling
Sample tests are performed as part of the quality control process to check the consistency of the
manufacturing process of each batch of insulators. During sample tests insulators may be tested
to destruction, dissected, analyses etc. so these tests are only performed on a few samples from
each batch.
The IEC provides a table for selecting the sampling size as a function of the lot size. ANSI
provides a sample size, independent of the lot size and CSA leave the selection of the sample
size over to agreement between purchaser and manufacturer.
Overview of Tests
The sampling tests specified in ANSI, IEC and CSA are presented in Table 7-16. There is
general agreement between the standards in terms of the sample tests required.
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Table 7-16
Comparison of the sample tests according to ANSI, IEC and CSA.
ANSI
IEC
CSA
Verification of Dimensions
Verification of dimensions
Visual inspection and
verification of dimensions
Verification of the locking system
Verification of the locking system
Cotter Key Operation
Mechanical load test
Verification of the interface between endfitting and housing and the SML/SCL
SML verification
Galvanizing test
Galvanizing test
Galvanizing test
—
—
Dye penetration
Verification of dimensions: In this test the dimensions of the insulators from the production line
are verified for conformance to the drawing supplied by the manufacturer. The standards are not
specific in which information should be included in the drawing and as a result also not specific
in which dimensions are checked in this test. It is therefore up to the purchaser to specify which
dimensions must be included in the verification process by placing minimum requirements on
the drawing. For example, the thickness of the housing over the insulator core is generally not
indicated on the drawing, hence this important dimension will not be verified during the
sampling tests.
Verification of the locking system: This test verifies that the locking system used on ball and
socket couplings prevent the insulator from disengaging when in the locked position.
Verification of the tightness of the interface between the end fittings and the insulator
housing and the SML: A dye penetration test is performed on one insulator while it is subjected
to a load of 70% of the SML. This test is the check that any movement between the core, housing
and end fitting, which may occur under mechanical loading, does not compromise the end fitting
seal or housing.
The other samples are subjected to a SML withstand test which verifies that the insulators can
withstand the SML for at least 60 seconds. The test is passed if the insulator withstands the load
without damage. Additional information may be obtained by increasing the mechanical load
directly after the test is completed to determine the ultimate failing strength.
Galvanizing test: This test checks that the quality of the galvanizing on the metal parts.
The Canadian standard (CSA) also includes a dye penetration test of the core material to check
its quality.
None of the standards specify any dielectric sample tests.
Routine Tests in Standards
Routine tests are performed on each insulator that leaves the production line. The aim of
routine testing is to monitor the quality of the production process. These tests should be nondestructive and economical to be performed. The routine tests specified by the standards are
listed in Table 7-17.
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Table 7-17
Comparison of the routine tests according to ANSI, IEC and CSA.
ANSI
IEC
CSA
—
Identification of the composite insulators
—
Visual examination
Visual examination
Visual examination
Mechanical routine test
Mechanical routine test
Mechanical routine test
The routine tests include:
•
•
•
The identification (IEC only) comprises the marking of the insulator with its trade name and
its SML.
A visual inspection of the composite insulator to check that the insulator is labeled correctly
and that there are no obvious manufacturing defects.
The mechanical routine test verifies that the insulator can withstand at least 50% of its SML
or Specified Tensile Load (STL) in the case of line post insulators.
As can be seen from the table, the routine tests required by the standards are very basic and,
importantly, no dielectric tests are prescribed. This means that, in most cases, the insulator will
be energized for the first time when installed for service. This is especially a concern when live
line replacement of insulators is considered. At present there is no practical way around this
problem since dielectric testing needs to be performed full-scale and such large-scale test
facilities—in the case of transmission voltages –are normally not available at insulator
manufacturing plants.
Non-Standard Tests
Introduction
In developing standards, the focus is to define, as far as possible, objective measurements, or
tests, that can be used to quantify the characteristics of the product. However, there are not yet
standard tests available for all aspects related to polymer insulators. There is thus a need to
identify, or develop, appropriate test methods for evaluating specific aspects of the insulator
performance. In this regard tests can be used to either verify that the insulator will meet the
required functional characteristics or determine its durability in withstanding the anticipated
service stresses. Both these aspects are to a certain extent covered in the existing standards but
there is still scope for improvement.
In this regard is advantageous to follow a tiered approach to minimize risk and cost. This
approach is illustrated in Figure 7-15 and can be described as follows:
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Figure 7-15
Three-tier testing approach
•
•
•
Tier 1: Small scale testing: These tests normally apply a single stress to small, standardized
material samples.
Tier 2: Laboratory Testing on Components: During these tests, a limited number of stresses
are applied to insulator samples in a controlled environment.
Tier 3: Field Demonstrations at Utility Sites: A limited number of insulators, are exposed to
a typical service environment. Usually, the service stresses are also monitored and recorded
during trials. In some cases, it may also be necessary to implement special precautions to
ensure that the power system is not adversely affected should a trial sample fails.
Tier 1 Tests
Inclined Plane Test
Flat rubber samples are placed at a predefined angle with two electrodes touching the surface at a
predefined distance. A saline solution is then dripped onto the rubber surface between the
electrodes, which results in leakage currents and arcing activity. The test is intended to evaluate
the ability of the rubber formulation to withstand tracking and erosion (ASTM D2303).
EPRI Small-Scale Aging Tests
Recognizing the high cost and time-consuming nature of full-scale testing, EPRI is now
developing small-scale tests to verify the ability of insulator designs to withstand primary and
secondary aging mechanisms in a cost-effective manner [11] [12]. These methods are also
developed with the aim that they can be included in insulator specifications to test the
vulnerability of insulators to aging due to water-induced corona—which has been identified as
an important aging mechanism of polymer insulators.
These small-scale tests are performed on sections of completely manufactured insulators so that
all design features and manufacture-induced stresses are included in the test samples. This
approach was found necessary as specially made rubber samples are not always representative of
the housing material, because it was not processed in the same way and, therefore, may not
include essential features such as internal molding stresses.
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EPRI’s approach in developing these test methods is to first identify and understand the primary
and secondary aging mechanisms active on the insulator throughout its life. These aging
mechanisms include storing, transporting, installing, and in-service stresses. Information about
these stresses is then used to develop a set of test methods each targeting a specific aging
mechanism, rather than combining all mechanisms in an expensive multi-stress test.
One small-scale test [11] focuses on corona aging of the housing material. Insulator samples
are subjected during this test to continuous corona in a dry or wet atmosphere. As shown in
Figure 7-16, the corona source is placed directly above the insulator sheath section. This test has
successfully been used to vet insulator housing materials.
Figure 7-16
Test setup for the sheath corona exposure test.
A second small-scale test [12] focuses on the ability of the insulator to withstand corona from the
insulator end fitting. In this test, short sections of insulator, which includes the end fitting and
seal, are energized in a controlled high E-field environment. The insulator samples are adjusted
so that corona inception on the end fitting occurs at the same test voltage (see Figure 7-17). For
the duration of the test, the housing and end fitting seal are continually exposed to the corona
discharges from the end fitting. The test chamber environment can be dry or humid.
Figure 7-17
Test setup for the corona from end fitting exposure test.
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Future small-scale test methods will focus on handling damage during installation to ensure that
insulator designs are rugged enough.
Tier 2 Tests
CEA Tracking Wheel Tests
Two tracking wheel test methods are commonly utilized as tests for polymer insulators. The tests
are not accelerated aging tests with a fixed acceleration factor. The intent of the tests is more as a
material and design screening test. During the tests, the insulators are subjected to surface arcing
generated through wetting with a saline solution and applied voltage. The properties of the
insulator examined are material suitability, design (shed spacing and thickness, housing
thickness), and the sealing system.
IEC 601109 5000-h Test (CIGRE, Electricité de France Specification)
This 5000-h test, which was developed by Electricité de France (EDF) and subsequently
formalized by the IEC, introduces multiple stresses in 24-h cycles while energized to the highest
system voltage Vm/√3 kV [13] [14] [15]. One cycle consists of different periods during which the
insulator is exposed to demineralized rain, heating, humidification, fog generated from saltwater,
and ultraviolet (UV) radiation, as shown in Figure 7-18. The representativity of the test was
confirmed by comparing the damage sustained during the test with that occurring at an outdoor
test station. Based on this comparison, an acceleration factor of 10 was determined for this test.
Due to practical and cost limitations, the 5000-h test is normally performed in a small test
chamber with a test voltage of between 14 and 20 kV. However, an aging chamber with a test
voltage of 245/√3 kV has been installed in France for full-scale testing at higher voltage levels.
Daily cycle
Test Voltage: 14-20 kV (rms)
Fog generated from a salinity
of 7 kg/m³
Demineralized rain
1,5 mm/min
Humidification 98 % r.h.
Heating 50 °C
Solar radiation simulation
≈ 0,9 kW/m²
0
2
4
6
8
10 12 14 16 18 20 22 24
Time Hours
Figure 7-18
Aging cycle for the IEC/CIGRE 5000-h test.
ENEL 5000-h Test
This test is based on the same types of stresses as the IEC/CIGRE test, but it comprises a sevenday cycle [16], of which details are presented in Figure 7-19. Other differences between the
ENEL and IEC/CIGRE tests concern the salinity of the saltwater used for the pollution period
(i.e., ENEL uses 80 g/m3 instead of 7 g/m3) and the intensity of the solar radiation (i.e., ENEL
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uses 1.5 kW/m2 instead of 0.9 kW/m2). The test was devised for the selection of polymer
insulators based on Italian conditions. It can be performed on full-scale insulators for system
voltages of up to 540 kV.
Weekly cycle
Test Voltage: Um/√3
Fog generated from a salinity
of 80 kg/m³
Demineralized rain
15 mm/min
Humidification
steam rate 0,033 kg/(m³ h)
Drying period
Solar radiation simulation
1,5 kW/m²
Stress free period
1
2
3
4
5
6
7
0
24
24
24
24
24
24
24
|_____________|_____________|_____________|_____________|______________|_____________|_____________|
Days
Hours
Figure 7-19
Aging cycle of the ENEL 5000-h test.
EPRI Summer/Winter Cycle Test
This test was devised to simulate the weather conditions of the Florida seacoast area. It includes
two different 24-hour cycles, one for the summer and one for the winter. One year of service is
represented by 10 summer cycles, which is followed by 11 winter cycles. The schematic of the
cycles is shown in Figure 7-20. By this definition of the test cycles, the acceleration factor is
about 17. The test has been performed on full-scale insulators at 138 and 15 kV [17] [18].
Figure 7-20
Aging cycle for the EPRI summer/winter cycle test.
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EPRI Test to Simulate “Deserts with a Distinctly Cold Season”
This test has been devised to simulate the weather conditions of the western part of the United
States, where there is light rainfall, extensive UV duration, and elevated temperatures with
relatively little contamination, which can be described as “deserts with a distinctly cold season.”
The aging cycle of this test is shown in Figure 7-21. One year of service is represented by 30
daily cycles. By this definition, the acceleration factor lies between 7 and 14. The test duration
depends on the number of years that have to be simulated.
This test was performed on full-scale 500-kV insulators in both a horizontal and V-string setup.
The V-suspension insulators were placed under a static mechanical load of 27 kN each. The
horizontal insulators were not mechanically loaded. Figure 7-22 shows a general view of the
500-kV test set-up. The test was completed after six years on 22 insulators from five different
manufacturers. The results of the test and comparison between the performance of different
designs may be reviewed in the appropriate EPRI reports [19] [20].
Daily special desert-climate cycle
Test Voltage: 288 kV (rms)
Fog generated from salt water
Clean rain
(applied only every 3. cycle)
Clean mist
UV radiation simulation
0
4
8
12
16
20
Time Hours
24
Figure 7-21
Aging cycle for EPRI test to simulate “Deserts with a Distinctly Cold Season.”
Figure 7-22
EPRI 500-kV accelerated aging test.
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EPRI Test to Simulate a “Warm Temperate” Climate
This full-scale multi-stress test was designed to simulate the climate of the southeastern United
States, although the results may be translated to regions with similar climates. The aging cycle is
presented in Figure 7-23, and the stresses applied to the insulator include voltage, UV, light fog,
rainstorms, salt fog, mechanical loading, and temperature cycling. The level of contamination
applied in this test is relatively low. One year of experience is simulated by 36 days of aging.
Units are assessed biannually using a detailed visual inspection, as well as infrared and discharge
inspection tools under energized conditions. A system voltage of 230 kV is simulated and 43
I-string, V-String, dead-end, post, and braced post units were tested. This test also included
transmission-line surge arresters, fiberglass cross-arms, and fiber optic polymer insulators.
Suspension units were mechanically loaded to their routine test load (RTL) and post units to their
maximum design cantilever loads. Figure 7-24 is an image of the 230-kV aging test chamber
[21] [22] [23].
Figure 7-23
Aging cycle for EPRI test to simulate a warm temperate climate.
Figure 7-24
Some of the insulators installed in 230-kV accelerated aging chamber.
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FGH 5000-h Test
This test produces accelerated aging on polymer insulators under 100-kV dc test voltage at a
specific leakage distance of 20 mm/kVDC. A simple 14-day cycle is used, including a stress-free
period of five days. The test duration is 5000 h (see Figure 7-25).
14 days cycle
Test Voltage: - 100 kV d.c.
Fog generated from a salinity of
7-10 kg/m³
Rain
10 µS/cm
UV radiation simulation
≈ 1,5 kW/m²
Stress free period for regeneration of hydrophobicity
1
2
3
4
5
6
7
8
9 10 11 12 13 14
Days
Figure 7-25
Aging cycle for FGH 500-h test.
EPRI End Fitting Evaluation Tests
The end fitting regions of suspension polymer insulators are subjected to electrical and
environmental stresses, while the entire insulator is subjected to both a static and vibration
mechanical load. The test apparatus used to apply these stresses to the insulators is shown in
Figure 7-26.
An electrical stress is applied to insulator end fitting regions using a remote electrode. The
electrode geometry is designed to ensure that the peak magnitude of the E-field surrounding the
end fitting is 0.7 kV/mm. Wetting is applied at regular intervals, together with temperature
cycling.
A static tension load is applied to each insulator with two leaf springs. Each insulator is loaded to
10,000 lb (4,535 Kg). In addition, large pulleys apply a 4.2-Hz dynamic tension load (an
oscillating load of +/- 20 lb [9 Kg]).
After 365 days of testing, the failure load of the insulators is obtained and compared against
reference units. Dye penetration, together with dissection, is used to evaluate the effectiveness of
the end fitting seals [24].
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Mechanical Test Fixture
Tension Loads
Static = 10000 lbs
Dynamic = +/- 20 lbs @
4.2 Hz
Test
Insulator
Electrical and
Environmental Stress
Applied at End Fitting
Figure 7-26
Overall view of test rig used for evaluating the end fitting seal and the mechanical performance of
the insulator.
EPRI Mechanical Loading Tests
Suspension polymer insulators are subjected to the following simultaneous mechanical stresses
using the apparatus shown in Figure 7-27:
•
•
•
50% of SML (specific mechanical load)
4.2-Hz dynamic tension load (an oscillating load of +/20 lb [9Kg]).
Twisting of +25° is applied at 0.1 Hz
After 365 days of testing the units, the failure load of the insulators is obtained and compared
against reference units [24].
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Figure 7-27
Test to evaluate mechanical performance (arrows indicate the static and dynamic loading
applied).
Considerations for Specification
In the previous sections the focus was on the available test methods, both standard and nonstandard. These tests may verify one or more functions or properties of the insulators or its
components. But these tests may not cover all aspects important to obtain a good performing
insulator with a long service life. In this section the perspective is changed to focus on the
insulator components, and the things to consider when evaluating submitted insulator designs.
The components and its constituents are discussed in Chapter 2, and the long-term performance,
in terms of degradation and failure is discussed in Chapter 4. In this section the component
constituents and known problems are cross referenced to available tests methods to identify the
need for additional tests or further research.
The Core
In Table 7-18 a summary is given of the constituents of the core, the properties expected of it, the
failure modes as well as the standard and non-standard tests available. This table can be used as a
cross reference when selecting insulators.
In the first column of the table the constituents of the core is listed together with some of the
most common choice options that are presently available on the market. In the second column
the most common failure modes, as discussed Chapter 4, is listed. Form the failure mode a list of
properties was devised that would be beneficial in preventing that failure mode form occurring.
In the next two columns Standard and non-standard tests are listed which could be used to verify
that the rod has the required property.
The table shows that the only failure mode that is not at all addressed in the present standards is
brittle fracture. Often the question is of how to prevent brittle fractures are simplified to a
question of acid resistant glass fibers or not. In reality, however, the optimal solution to the
brittle fracture problem is far from clear, and at this stage no simple answer is apparent. There
are a number of aspects that needs to be considered when dealing with brittle fracture. The most
important facts to consider is as follows:
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Table 7-18
A summary of the information that can be helpful when considering requirements for the insulator core.
Constituent
Glass fibers
E-type
ECR-type
Acid resistant
Component
Failure Mode
Brittle fracture
Bonding between
Resin and rod
Complete core with
end fittings
• Lack of acid forming
chemicals
Standards
Testing
Hollow Fibers
Non-Standard Testing or Previous Tests
None
1. Acid test with mechanical load to see if the
rod fractures
2. Test where moisture is put in contact with
the rod and the change in pH is measured
to see if acids form – CIGRE.
3. EPRI accelerated aging tests – 230kV
1. Dye
Penetration
1. Using special Dye Penetrants – EPRI
trying Zyglo
2. Use SEM to see if there are hollow fibers
3. EPRI is trying partial discharge testing.
• Low boron content
(corrosion resistant)
Flash under
Destruction by
discharge activity
Resin
Epoxy type
Vinyl ester
Modified vinyl ester
Polyester
Properties that Influence
Performance
Conductive inclusions
Internal voids and cavities
1. Using special Dye Penetrants – EPRI
trying Zyglo
2. Use SEM to see if there are gaps between
fibers
3. EPRI is trying partial discharge testing
Hydrolysis
Chemical stability
Water diffusion
test
Brittle Fracture
Susceptibility of matrix to
brittle fracture
None
1. Tests have been done at University of
Denver to compare different resins
Presence of chemicals that
form an acid when in contact
with water
None
2. CIGRÉ acid formation test
Short- and long-term
mechanical strength
Ultimate tensile
strength/Loadtime
Mechanical stability under
thermal stress
Sudden load
release/Thermal
mechanical
1. EPRI 230kV aging test with sustained
loading
2. EPRI 500kV Aging test with sustained
loading
3. EPRI vibration and torque testing of units
for prolonged periods of time.
Mechanical
Fracture
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•
•
•
•
•
•
•
•
•
•
•
Acid resistant rods have low probability for brittle fracture to occur.
Although acid resistant rods do reduce the possibility of failure by brittle fracture, they are
still susceptible to the other failure modes, such as flashunder and destruction of rod by
discharge activity.
If moisture comes into contact with acid resistant core it will have a high probability to fail
due to:
(a) Tracking along the core or
(b) Destruction by discharges independent of which type of core is used.
If moisture comes into contact with e-glass core it will have a high probability to fail due to:
(a) Brittle fracture
(b) Tracking along the core or
(c) Destruction by discharges independent of which type of core is used.
Destruction by discharges and flashunder is a slower process than failure by brittle fracture.
Acid resistant rods therefore extend the time to failure (in case of a compromised end seal).
This gives the user more time for diagnostic inspections.
Some BF resistant rods are prone to internal tubes in the fibers and gaps in the resin matrix,
which may make it more susceptible to tracking in the core in the case of housing or sealing
end failure. It is thought that these voids may result in internal discharges (partial discharge)
but initial research indicates that this is unlikely as they are too small to generate partial
discharges in the applied field magnitudes.
Not all manufacturers produce acid resistant rods. May result in less competitive market or
exclusion of some manufacturers that have good performing units.
If manufacturers are forced to use a technology that they are not familiar with, it may
introduce other design problems (such as weak housing—core interface).
Small voids, i.e., in the µm range, in the rod matrix are considered to be very unlikely to
result in internal discharge activity due to their small dimensions.
Poor bonding between the housing and the rod has been shown to result in discharge activity
which in-turn has resulted in failures.
Overheating of the rod during the housing molding process has been shown to result in
failures in the past. This may have resulted in:
- Poor bonding between or poor bonding between the outer layers of the fibers of the core
has been shown to result in discharge activity which in-turn has resulted in failures,
usually flashunder. This poor bonding in the outer layers of the rod has been attributed to
gases being formed in outer rod the rod during a high temperature housing molding
process. Current thinking is that the high temperature of the molding process re-initiates
the curing process of the rod resin. Correct formulation of the rod will prevent this.
- If the rod is significantly heated during the molding process and then it is bent while still
hot as permanent deflection in the fibers may exist. The result is fibers that are not
perfectly aligned with the applied load result in high mechanical stress regions and
consequential mechanical failure.
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The End Fitting
Table 7-19 presents a summary of the constituents of the end fitting, failure modes, properties
expected of it, as well as the standard and non-standard tests available. This table can be used as
a cross reference when selecting insulator properties.
The first column of the table names the constituents of the end fitting. In the second column the
most common failure modes, as discussed Chapter 4, is listed. A list of properties was devised
that would be beneficial in preventing that failure mode from occurring. In the next two columns
Standard and non-standard tests are listed which could be used to verify that the end fitting has
the required property.
The table shows that the mechanical strength and corrosion resistance of the end fitting are more
or less addressed by the tests in the standards. It should however be noted that the power arc
testing is not covered by the composite insulator specification, but by a separate standard for the
testing of insulator sets, i.e., IEC 61467. Another aspect that is not fully covered by standard
testing the E-field grading offered by the shape and size of the end fitting.
Nearly every manufacturer has its own design for the end fitting shape. The shape is determined
to a large extent by the type of end fitting seal and how the manufacturer wants to protect the
seal from excessively high E-field gradients. A bad end fitting design will lead to premature
aging of the end fitting seal and housing material. The following aspects needs to be considered
when considering the shape and general design of the end fitting:
•
•
•
The shape and size have an effect of the E-field distribution on both the housing and end
fitting seal as well as internal to the insulator. A high E-field magnitude on the insulator
surface may result in dry corona activity or high levels of corona activity during wetting.
This may degrade the end fitting, the end fitting seal and/or housing.
- End fittings with a larger diameter tend to perform better than small and slender ones.
- The shape of the end fitting should be such that the location of the highest E-field on the
end fitting is so that corona, when present, will not be in contact with the housing
material.
- The presence of correctly dimensioned grading rings improves the end fitting
performance, but end fitting seal may still be vulnerable to a bad end fitting design even
with grading rings installed.
When a grading ring is fitted to the insulator, the end fitting shape and grading ring work
together to determine the E-field levels. The influence of the end fitting is still considerable
and the extent to which the end fitting influences the E-field is dependant on the grading ring
design and attachment mechanism.
The end fitting may be the first point of contact for a power arc—it needs to withstand this
condition. The use of grading rings or arcing horns will reduce the effect of power arcs. Both
the energized and grounded end fittings need to be considered if power arc withstand is a
concern. The arcing devices should be designed to shunt the fault current away from the end
fitting, and more specifically the end fitting seal region. Manufacturers should be consulted
whenever units have experienced flashover to make recommendations regarding its removal
from service.
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Table 7-19
A summary of the information that can be helpful when considering requirements for the end fittings.
Constituent
End Fitting
Component Failure
Mode
Fracture of metal end
fitting
Properties
Mechanical
strength
Standards Testing
Ultimate tensile strength
Non-Standard Testing
• EPRI 230kV aging test with sustained loading
• EPRI 500kV Aging test with sustained loading
• EPRI vibration and torque testing of units for
prolonged periods of time.
Thermal
mechanical
stability
Sudden load release/
Thermal - mechanical
Corrosion
Corrosion
resistance
Galvanizing test
Compromised housing
or end fitting seal
E-field grading
Corona/RIV test
(e-field modeling)
• E-field modeling
• EPRI Wet tests as defined in application guide
• EPRI Aging Tests
Melting of fitting
Core-metal fitting
interface
Mechanical strength
Power arc
withstand
None (only tested as
part of an insulator set,
IEC 61467)
Slip off
Rod failure
Ultimate tensile strength
Load-time
• EPRI 230kV aging test with sustained loading
• EPRI 500kV Aging test with sustained loading
• EPRI vibration and torque testing of units for
prolonged periods of time.
End fitting housing
interface
Thermal mechanical
stability
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Sudden load release
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7-67
The mechanical design of the end fitting should be such that the crimping process does not result
in a high stress concentration in the insulator core. Some manufacturers use a graded crimping
process to ensure an even stress distribution in the core, while others do not. The collected field
experience have shown some cases where a stress concentration has caused radial cracks in the
insulator core, but there are also many insulators with a non-graded designs that have a
successful operation history. Since the mechanical testing of composite insulators are quite
rigorous it can be assumed that most bad designs will be filtered out by the standard. However, it
is still advisable to evaluate the service history of the insulator makes considered and to discuss
the end fitting design of the manufacturer to gain confidence in the designs that will eventually
be selected.
A final concern with end fittings is related to the ability of the manufacturer to consistently crimp
the end fittings to the right pressure. As stated earlier, over crimping may lead to axial cracks in
the rod, which, in turn, may lead to internal discharges resulting in either destruction of the rod
by internal discharges or flashunder. Routine tests will identify under crimping, but it will not
always identify units that were over crimped. To ensure a good manufacturing process, the
purchaser need to convince himself that the manufacturer has a good quality control system in
place that will deliver repeatable and reliable results. Some manufacturers use diagnostic
techniques to monitor crimping pressure. Examples include ultra-sonic listening devices and the
use of calibration test units.
The end fitting seal
Table 7-20 presents a summary of the constituents of the end fitting seal, failure modes,
properties expected of it, as well as the standard and non-standard tests available. This table can
be used as a cross reference when selecting insulator properties.
Table 7-20
A summary of the information that can be helpful when considering requirements for the end
fitting seal.
Constituent
Housing
Core
Metal fitting
Sealing mechanism
Component
Failure Mode
Properties
Standards
Testing
Puncture
Dielectric strength
None
Erosion of seal
Ability to withstand
discharge activity
UV resistance
Chemical stability
(Tracking and
erosion1)
• Sealant
• Gel
Thermalmechanical stability
• Compression
seal/O-ring
Handling
Power Arc
resistance
Sudden load
release/Thermalmechanical/water
immersion/Steep
front/Dry ac
Non-Standard
Testing
EPRI End fitting
test
EPRI 230 kV and
500 kV aging tests
None
Note: 1: The tracking and erosion test does not specifically evaluate the seal. It is possible that a unit may pass the test with a
compromised seal.
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The first column of the table names the constituents of the end fitting seal. In the second column
the most common failure modes, as discussed Chapter 4, is listed. From the failure mode a list of
properties was devised that would be beneficial in preventing that failure mode from occurring.
In the next two columns Standard and non-standard tests are listed which could be used to verify
that the end fitting seal has the required property.
About 70% of all composite insulator failures are related to the failure of the end fitting seal. The
different designs offered by manufacturers have a wide range of performance. An indication of a
successful end fitting design is how long the design has remained unchanged. Manufacturers that
do experience problems with their seal designs need to make frequent adjustments to their
design.
Features of a good end fitting seal are:
•
•
•
•
•
The seal should be protected from high electrical field gradients under both dry and wet
conditions.
Seal should be protected from mechanical damage.
Seal should be protected from the environment. Service experience has showed that the
external sealant exposed to the environment is prone to erode under the combined
environmental stresses and a high electrical field.
Non-galvanized regions of the end fitting should not be exposed to the environment—even if
it is underneath the sealant since the seal may de-bond and allow rust to penetrate to the core.
The choice of materials in and around the seal should take account of power arc conditions
(where the arc will terminate).
The extent to which end fitting seal problems occur in service indicates that the standards testing
does not fully test the functionality of the end fitting seal. For example, none of the design tests
specifically stresses the end fitting seal with an E-field gradient representative of service
conditions. Also, none of the mechanical tests subjects the seal to the typical torsion forces that
an insulator may experience due to twisting of multi-conductor bundles.
EPRI has been pursuing the development of suitable test regimes for end fitting seals. Two test
methodologies have proven successful:
1. EPRI end fitting test
2. EPRI’s full-scale aging tests (both 230 kV and 500 kV)
In addition to test methods, ongoing EPRI research projects investigate more effective methods
to evaluate the condition of end fitting seals has been pursuing the development of suitable test
regimes for end fitting seals. Two test methods that are investigated are:
1. Dye penetration with alternative high penetration dyes such as Zyglo, since the presently
used fuchin dye proved not to be effective.
2. Performing tightness tests by pressurizing the end fitting cavity at the top of the rod with
helium to a pressure of 4-bar and using a helium sniffer, or a water bath to show bubbles, to
detect leaks.
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The Housing
Table 7-21 presents a summary of the constituents of the insulator housing, its failure modes, the
properties expected of it, as well as the standard and non-standard tests available. This table can
be used as a cross reference when selecting insulator properties.
The first column of the table names the constituents of the housing. In the second column the
most common failure modes, as discussed Chapter 4, is listed. Form the failure mode a list of
properties was devised that would be beneficial in preventing that failure mode from occurring.
In the next two columns Standard and non-standard tests are listed which could be used to verify
that the insulator housing has the required property.
Table 7-21
A summary of the information that can be helpful when considering requirements for the housing.
Constituent
Rubber
Sheds
Sheath
Component
Failure Mode
Properties
Flashover
Electrical strength
Splits in the
material due to its
brittleness
UV stability
Tracking and
erosion
Hydrolysis
Tracking and erosion
resistance
Chemical stability
Tearing of the
material
Thermal mechanical
strength
Standards Testing
Non-Standard
Testing
Contamination
testing
Tracking and erosion
Flammability
Accelerated
aging tests (e.g.,
EPRI) or field
testing
Water immersion/
Steep front/dry A.C.
test
None of the standards evaluate the flashover performance of composite insulators. It is generally
accepted that composite insulators in a good condition offer higher flashover values than
conventional insulators. The reasons for this are:
•
•
•
•
Surface hydrophobicity. Good hydrophobicity is very efficient in preventing the formation
of a uniform wet surface that is so fundamentally important to the contamination flashover
process. On silicone rubber insulators, a portion of the contamination deposit may also be
“neutralized” because of the transfer of hydrophobicity caused by the natural migration of
low molecular weight silicone from the housing to the contamination layer.
Thermal characteristics. Composite insulators adjust quickly to the ambient temperature.
The wetting is, therefore, less efficient than on ceramic and glass insulators under critical
wetting conditions.
The slender shape of the insulators. For a given surface conductance, insulators with a
slender shape will have a higher overall resistance than insulators with a larger diameter.
Longer creepage distances. Composite insulators are often installed with a longer creepage
distance than ceramic and glass insulators. This is often done to avoid material deterioration
due to leakage currents.
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In summary, the flashover performance of the insulator is a function of the housing material,
shed profile and creepage distance. It should however be noted that the flashover performance of
composite insulators may deteriorate when aged. Especially a rough surface collects more
contaminants, and the flashover voltage will be negatively affected if the insulator is in a
hydrophilic state.
There are also a number of manufacturing related issues that are not adequately recognized in the
standards. This relates to the centering of the core in the housing, which is not verified by any
test, and the inclusion of additional interfaces (e.g., when performing multi-step molding) that
were not tested with any of the design tests.
The first issue relates to longer insulators (i.e., for transmission voltages) with a molded housing
where steps have to be taken to keep the core centered in the mold during the molding process.
As the example show in Figure 7-28 the measures taken by manufacturers are not always
successful, which indicates the importance of including some form quality testing.
Utilities often specify a minimum housing thickness, e.g., 3 mm, but include no test to verify this
under production. One solution is to include a sample test, which is destructive, to check that the
thickness criterion is met by cutting the insulator in sections for a visual inspection and housing
thickness measurement. An example of such a requirement is included in Clause 6.4.3 of the
Example specification below.
Figure 7-28
An example of an insulator where the core is not centered in the housing.
The second also relates to molded insulator units were, because of a limited mold length, a
multistep molding process may be introduced for the manufacturing of long insulator units.
Some manufacturers also include spacers on longer insulator units to centering of the core in the
housing. These design features are however not necessarily tested during the design tests as they
are not present on the short insulator lengths which are used for the design tests. Again, this
aspect is not covered by the present standards, and it should therefore be addressed in the utility
specification. An example of such a requirement is included in Clause 6.2.1 of the Example
specification below.
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Considerations when selecting the housing material
A major issue that the purchaser needs to consider when specifying composite insulators is the
choice of the housing material. In this regard there are a number of issues that need to be
considered.
In areas with a high level of contamination:
•
•
The hydrophobic properties of silicone rubber insulators will provide an excellent flashover
performance, provided it is dimensioned correctly. The hydrophobicity of under dimensioned
insulators may be suppressed leading to premature ageing or flashover.
In areas exceptionally high levels of contamination, silicone rubber may become
overwhelmed and loose its hydrophobicity during extended periods—this may lead to
material erosion. These are conditions where either the SIR is more or less continuously
wetted, or where the insulators are stressed close to its point of flashover. The discharge
activity associated with the flashover process may suppress the hydrophobic properties to
such an extent that may lead to material erosion.
For areas with a low contamination level there are two lines of thought:
1. The hydrophobic properties of silicone rubber insulators suppress discharge activity, and
thereby leakage current, which leads to low level of aging. In this case it is also important to
have a correct design and application of grading rings to ensure that the surface E-field
magnitudes are below the threshold values to avoid discharges due to a Non-uniform wetting
of the housing.
2. An insulator housing made of EP rubber may have a low level of hydrophobicity, and
therefore a higher level of discharge activity, but it is generally tough and more resistant to
erosion damage due to discharge activity than silicone rubber.
Both types of material could suffer from premature aging that may reduce its life expectancy if
applied incorrectly. Important parameters that affect life expectancy is:
•
•
•
•
•
The type of rubber used and its composition (e.g., amount and type of filler used)
The thickness of the housing. A thicker housing offers a more robust protection of the core
and will be less prone to electrical puncture or mechanically induced damage. Utility
specifications often require a minimum housing thickness. The required minimum values
range from 3-5 mm.
The molding process used to form the rubber into the housing. Important here is how much
internal stress remains in the material after manufacturing and how the chosen molding
parameters, e.g., temperature, may affect the long term performance of the rod.
The presence of axial mold lines. Electrical activity tends to concentrate on the mold lines.
This aspect is tested sufficiently by the 1000 h tracking and erosion test. Also mechanically
the mold lines presents a weak point that could tear easily, especially after a long period of
aging.
The level of environmental stresses, such as temperature variations, intensity of the sunlight,
contamination level etc.
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•
•
The level of the E-field. A too high level of E-field may give rise to discharges due to a nonuniform wetting of the housing. Field and laboratory observations have shown that there is a
correlation between damages observed and the E-field level on the insulator.
Treatment and handling of the insulator during its whole life, including manufacturing,
storage, transport and installation. Imperfections resulting from flash-removal or damage
sustained during transport, storage and installation may negatively impact the insulator
service life.
The life expectancy is also a function of how well the various components of the insulator
functions together. Standards testing do not fully evaluate this aspect, since testing is normally
done on component level and often not performed on full scale units. So the user needs to rely on
natural and non-standard artificial testing results to select an appropriate insulator/manufacturer.
The user should however be aware that service experience for a particular manufacturer might
not always be relevant due to recent design changes. Also, results from accelerated aging tests
needs to be analyzed with caution. Accelerated ageing should be representative of the
environment, for example for clean environments the accelerated ageing test should be run at a
low contamination level. This is important since the aging phenomena are different for areas
with a low and high contamination levels.
Accelerated aging tests with a lack recovery periods may overstress the material leading to nonrepresentative results. However, such tests may still provide information to compare the
performance of different insulator designs.
It should be clear from this discussion that the choice of materials, especially for contaminated
conditions, is not simple and may involve a certain degree of compromise. It is recommended,
therefore, that data on previous experience with specific formulations in similar environments be
obtained where possible (i.e., relevant service or natural test experience).
Considerations when selecting the profile parameters
When considering profile parameters for composite insulators the following considerations
should be taken:
•
•
•
Laboratory results suggest that profile parameters should be evaluated for good performance
under a combination of contamination and rain conditions. Heavy rain wetting in
combination with pre-deposited pollution should be considered when considering profile
shape. Factors that impact the performance of an insulator under these conditions are; shed
projection, shed angle, shed spacing and the diameter of the insulator. Under these
conditions, large sheds with a shallow shed angle (i.e., large and flat) will not perform as well
as short sheds with a steep inclination, because of its poor drainage characteristics.
In contaminated conditions the pollution catch of the insulator is determined to a large extent
by the shed aerodynamic properties. Flat aerodynamic sheds will collect less contamination
than steep sheds with protected creepage. The pollution accumulation on the protected part of
steep shed designs (i.e., under the shed) may produce a high E-field concentration across the
shed material during humid conditions, increasing the possibility for shed puncture.
In contamination conditions it is generally found that alternating long and short shed profiles
perform better than regular shed profiles.
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•
•
Closely spaced shed designs should be avoided due to the increased risk of inter-shed
breakdown. Test results indicate that the efficacy of the creepage distance decreases rapidly
for a shed spacing of 30 mm or less.
There seems to be general consensus that the shed parameters included in the IEC 60815 are
conservative when applied to composite insulators. These parameters are presently under
review by the relevant IEC working group. Many users still use these parameters since
because of the lack of recommendations for composite insulators. The only risk is that a
limited number of insulator types are excluded, which probably would have performed quite
well.
Considerations when selecting the creepage distance
The contamination flashover performance of composite insulators is determined by a complex
interaction of the material hydrophobicity, shed profile, axial length and creepage distance. The
relative importance of the creepage distance on the flashover performance of an insulator is
determined by the extent to which inter-shed breakdown occurs. This, in turn, is largely
dependent on the level of hydrophobicity and, of course, the shed parameters. On fully
hydrophobic insulators, the probability for inter-shed breakdown is large because of the lack of a
continuous surface-wetting layer. As a result, creepage distance will not play a minor role in the
insulator’s flashover performance. On the other hand, if the insulator is fully hydrophilic, the risk
for inter-shed breakdown is smaller and the length of creepage distance will have a bigger impact
on the insulator’s flashover performance. Based on these arguments the following
recommendations can be made:
•
•
For hydrophobic insulators (e.g., silicone rubber) the selection of creepage distance is less
important because the hydrophobicity prevents formation of a conductive layer. Results from
field and laboratory shows that it should be possible to reduce the required creepage distance
by 25% from that needed for ceramic and glass insulator. Users should realize however, that
such a reduction in creepage distance could result in a shorter insulator life due to a higher
rate of ageing.
For hydrophobic insulators it is very important to consider the use of correctly dimensioned
grading rings to grade the E-field to prevent discharges due to a non-uniform wetting and
subsequent loss in hydrophobicity.
For hydrophilic insulators (e.g., EP rubber) the selection of creepage distance is very
important, since the material will not maintain its initial hydrophobicity. The selection of the
grading ring is less important since the continuous wet surface layer grades the E-field during
wet contaminated conditions. In this case it is prudent to follow the recommendations
presently used for ceramic and glass insulators given in Table 7-22 with example
descriptions of typical environments.
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Table 7-22
The site severity classification and sample descriptions of typical environments
Classification
Very Light
Example Description of Typical Environment
> 50 km from any sea, desert, or open dry land
> 10 km from man-made pollution sources
or within a shorter distance, but:
Unified Specific
Creepage Distance
(USCD: mm/kV)*
22
• the prevailing wind is not directly from these pollution
sources
• and/or subjected to regular monthly rain washing
Light
10-50 km from the sea, a desert, or open dry land
5-10 km from man-made pollution sources
or within a shorter distance, but:
28
• the prevailing wind is not directly from these pollution
sources
• and/or subjected to regular monthly rain washing
Medium
3-10 km from the sea, a desert, or open dry land
1-5 km from man-made pollution sources
or within a shorter distance, but:
35
• the prevailing wind is not directly from these pollution
sources
• and/or subjected to regular monthly rain washing
or further away, but:
• a dense fog (or drizzle) often occurs after a long dry
pollution accumulation season (several weeks or
months)
• and/or heavy rains with a high conductivity occurs
• and/or there is a high NSDD level, typically between 5
and 10 times the ESDD level
Heavy
Within 3 km of the sea, a desert, or open dry land
Within 1 km of man-made pollution sources
Or with a greater distance, but:
• a dense fog (or drizzle) often occurs after a long dry
pollution accumulation season (several weeks or
months)
• and/or there is a high NSDD level, typically between 5
and 10 times the ESDD
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44
Table 7-22 (continued)
The site severity classification and sample descriptions of typical environments
Classification
Very heavy
Example Description of Typical Environment
Unified Specific
Creepage Distance
(USCD: mm/kV)*
55
• Within the same distance of pollution sources as
specified for “Heavy” areas and:
• directly subjected to sea-spray or dense saline fog
• or directly subjected to contaminants with high
conductivity, or cement type dust with high density, and
with frequent wetting by fog or drizzle
• Desert areas with fast accumulation of sand and salt,
and regular condensation
• Areas with extreme levels of NSDD, more than 10 times
the level of ESDD
Note: (*) The “unified specific creepage distance” is the creepage distance divided by the maximum operating voltage across the
insulator.
The Housing Core Interface
Table 7-23 presents a summary of the constituents of the housing—core interface, its failure
modes, the properties expected of it, as well as the standard and non-standard tests available.
This table can be used as a cross reference when selecting insulator properties.
The first column of the table names the constituents of the housing—core interface. In the second
column the most common failure modes, as discussed Chapter 4, is listed. Form the failure mode
a list of properties was devised that would be beneficial in preventing that failure mode from
occurring. In the next two columns Standard and non-standard tests are listed which could be
used to verify that the rod has the required property.
Table 7-23
A summary of the information that can be helpful when considering requirements for the housing.
Constituent
Core
Bonding/gel
Housing
Component Failure
Mode
Properties
Standards
Testing
Loss of bonding
Thermalmechanical stability
Steep-front
Dry AC
Internal discharge activity
Good bonding
None
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Non-Standard
Testing
230 kV aging test
The main concern regarding the housing—core interface is that the bonding intended by the
manufacturer remains intact for the service life of the insulator. Loss of bonding or voids
between the housing and core will give rise to discharges on the rod surface, and ultimately may
result in a flashunder. Presently there are no tests included in the standards that specifically test
the housing core interface. Therefore, the user of composite insulators must rely on field and
non-standard accelerated aging tests for information about bad performing designs. Additionally,
it is necessary to ensure that:
•
•
The insulator manufacturer has a good quality control system in place to insure a consistent
manufacturing process.
Good handling practices are used from manufacturing to installation to ensure that the
housing core interface is not damaged because of mistreatment.
In terms of the method used to attach the housing to the core, there is no clear advantage of one
method above another. Table 7-24 gives a summary of pros and cons for each type.
Table 7-24
A comparison of different methods of attaching the housing to the core.
Method
Pros
Cons
Single shed
units slipped
onto the core
Provides flexibility in terms of obtaining
required insulator section lengths at a low
cost.
Silicone gel used in the shed-shed and shed
core interface allows shed movement without
damage that may impact service life.
Gel fills splits and cracks thus forming a
dynamic seal which could extend life.
The housing contains many interfaces
The insulators may be more sensitive
to handling damage.
The shed-shed and shed-end fitting
interfaces rely on mechanical pressure
that may lead to radial splitting of the
sheds subjected to a high E-field.
Multiple shed
units slipped
onto the core
Shed sections comprise typically 4 to 6 sheds
that still give a relatively good flexibility in
obtaining required insulator section lengths.
Silicone gel used in the shed-shed and shed
core interface allows shed movement without
damage that may impact service life.
Lower mechanical stress in material that
single shed stacked design results in a lower
risk for radial splitting
Gel fills splits and cracks thus forming a
dynamic seal which could extend life.
May be more sensitive to handling
damage especially at the shed section
and end fitting interfaces.
Insulator contains many interfaces
which increases the risk for a failure of
any particular one
Tubular
sheath of
rubber
vulcanized to
rod with
individual
sheds
vulcanized to
outside of
rubber
sheath
Provides flexibility in terms of obtaining
required insulator section lengths at a low
cost.
Low residual mechanical stresses in sheath
and sheds
Flexible shed spacing gives freedom in
satisfying both axial length and creepage
distance requirements
No axial mold lines
Bond between sheds and the sheath
may be sensitive to puncture (not many
cases observed)
Potentially more difficult to obtain a
good end fitting seal and to check its
quality
Flexible shed spacing may lead to
inferior performing designs if shed
spacing is too small.
Difficult to have pre-qualified shed
designs.
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Table 7-24 (continued)
A comparison of different methods of attaching the housing to the core.
Method
Pros
Cons
One or multishot molding
Manufacturing process can be automated to a
large extent
Direct bonding between housing and end
fitting is possible—leading to good end fitting
seals.
O-ring molding is possible
Less interfaces
Expensive to change lengths
Long length may require multi-shot
molding—leading to extra housing to
housing interfaces.
Axial Mold lines potential weak point in
the design
High temperature injection molding
may affect the long term performance
of the rod
Residual mechanical stresses in the
material may lead to splits in the
housing material when the insulator
ages.
Expensive to change shed profiles
Grading Rings
Depending on the system voltage level, grading (or corona) rings may be necessary at the live
end or/and at the grounded end of the insulator. Grading rings are sometimes also called corona
rings. A grading ring is defined by outer diameter, inner diameter and height above end fitting.
Grading rings function both to grade the E-field along the insulator and act as arcing horns to
protect the polymer insulator from arc damage in case of a flashover. When buying new
insulators, utilities must ensure therefore that the insulator designs contain features to fulfill these
functions well.
The first function of grading rings is to limit the E-field gradients on the polymer insulators to
below the levels that would result in premature aging. Based on the present understanding of the
ageing mechanisms EPRI has determined a set of threshold levels for the E-field distribution on
polymer insulators. These are presented in Table 7-25 for insulators of all voltage levels installed
at or close to sea level. Adjustments to these limits are needed for installations at altitudes of
higher than 3,300 feet (1,000 m). It should be noted however that these limits are still provisional
which may be adjusted as more experience is gained.
Table 7-25
In summary the EPRI recommendations on Electric field limits for Polymer Insulators.
Type
Insulator Component
E-Field Limit [kV/mm]
Testing
Calculation
A
Dry corona
End fittings
Corona Rings
1.7 - 2.1*
Yes
Yes
B
Wet corona
Sheath
0.42 for more than 10 mm
No
Yes
End fitting seal
0.35*
No
Yes
Note: * At present there are not yet consensus on an appropriate value and they are therefore still under review.
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With reference to Table 7-25, the EPRI criteria can be described as follows:
Requirement A: Dry Discharges from Metal End Fitting:
There should be no discharge activity on the metal end fitting under dry conditions when the
units are applied in-service. It is critical that the end fitting be designed such that discharges, if
they do occur are not in contact with the weathershed system or the end fitting seal. There are
two methods of verifying that the metal end fittings will be corona free under dry conditions:
1. This can be verified in mockup testing as described in the IEC Standard 61284 using optical
(or UV) observations to determine whether discharge activity is occurring from the metal end
fitting under dry conditions.
2. It can also be verified by E-field modeling to show that the E-field on the end fitting within
100 mm of the rubber weather shed material or the end fitting seal is below a threshold of
1.7-2.1 kV/mm. Work is presently underway to refine this limit.
Requirement B: Non-Uniform Wetting Discharge Activity:
Excessive discharge activity under wetting conditions that is contact with either the rubber
weathershed material or the end-fitting seal should be avoided. This can be achieved by limiting
the E-field magnitude so that it does not exceed 0.42 kV/mm over a distance of more than
10 mm on the sheath of the weathershed system and 0.35 kV/mm at the critical end fitting seal.
Although the 0.42kV/mm is well defined. The 0.35kV/mm level for the seal region remains
under research.
Adjustment for High Altitudes:
The adjusted E-field limit can be by following the procedure given in IEEE Std. 4-1995, IEEE
Standard Techniques for High-Voltage Testing. The adjustment for is a ratio of the relative air
density. Simplified, the adjustment for the E-field thresholds becomes:
Ealtityude = δ ⋅ ESeaLevel
Where:
δ is the relative air density
E is the E-field
The mean air density as a function of height above sea level is given by:
 −A 


δ = ⋅e  8600 
Where:
δ is the relative air density
A is the height above sea level in meter
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General comments:
Experience with applying these recommendations have shown that:
•
•
•
If an insulator fails to meet Requirement A it will in most cases fail to meet Requirement B.
In most cases failure to meet Requirement A would result in a failure in a much shorter time
span than an insulator that fails only Requirement B.
Recent field experience indicates that Requirement A is more important than previously
believed. Contrary to some insulator catalogue recommendations it is found that corona rings
are in some cases necessary to prevent dry corona from insulator end fittings on 115 and
138 kV systems [25].
Verification of E-Field Limits:
It is not a trivial task to implement the above limits and to ensure that the insulator designs
actually conform to the requested E-field limits. This is because there is, as yet no consensus
internationally on the applicable test and calculation methods to verify the E-field design of
insulators. A further complication is the fact that the E-field on the insulator is determined to a
large extent by its application, something that does not fall in the control of the manufacturer.
Traditionally for glass and porcelain insulators the design of corona rings and grading devices
fell outside the responsibilities of the insulator manufacturer since the insulators was not affected
significantly by high electric fields. On polymer insulators this is different, and a more integrated
approach needs to be followed. Such an approach may contain the following aspects:
•
•
•
E-field calculations to verify that the limits for water induced corona and continuous dry
corona is not exceeded.
High Voltage Testing to confirm that the end fitting, seal and/or corona ring design and
materials used is free from continuous corona.
Experience and Industry Information is used to evaluate designs and identify possible
weaknesses.
E-Field Modeling:
E-field calculation is presently the only way to guarantee that E-field on the insulator will not
exceed both the dry and wet corona limits given above. These calculations should be performed
before insulators are installed determine the need for corona rings. The configurations should be
modeled in three dimensions (3D) to calculate the E-field, and should take the following
components into account with an appropriate level of detail:
1. Insulator, including precise representation of the end fitting as well as dielectric components
such as rod and rubber.
2. Corona rings, if present, should be included with correct dimensions and shape including any
openings in the ring if present. It is also necessary to include the corona ring attachment
hardware especially if it is close to the weathershed material.
3. Hardware, ground and energized end, especially if there are additional hardware present.
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4. An appropriate length of the phase conductors on each side of the tower. This length should
be in the order of about 5 to 10 insulator lengths on each side of the tower of interest.
5. The supporting structure which can be simplified to a series of ground planes forming the
outline of the tower.
6. All three phases should be included in the model with the correct phase spacing.
7. On a double circuit structures, both circuits should be included in the model.
8. Voltages applied to each phase should be equal to Umax (that is the maximum system
voltage).
It is found that simplified models based on rotational symmetry do not offer accurate enough
results to evaluate E-fields on polymer insulators.
It is important to consider all the insulator assembly types utilized on the line. If identical
insulators, with identical corona ring, are being considered for suspension and dead-end
applications, testing of the dead-end maybe sufficient providing the phase spacing does not
decrease sufficiently in the suspension configuration.
Previously wide implementation of E-field calculations was not practical due to the
computational and specialized manpower resources required, but this has changed with the
release of EPIC software which is specifically designed to calculate the E-field on polymer
insulators in typical transmission configurations in 3-D [26].
High Voltage Corona Testing:
High voltage testing is generally limited to verify that the assembly being tested is free from
visible corona under dry conditions. As such it verifies the correctness of the chosen grading
devices and also that the finish of the hardware components is free perturbations that could give
rise to corona. Corona testing under wet conditions is at present not considered practical the
conditions for such a test cannot defined sufficiently to obtain repeatable results.
In this section general considerations are given regarding test arrangements and procedures to
determine the corona onset or extinction voltage of the test object. For testing it is necessary to
select the test setup and the test voltage so that the same surface E-field is obtained on the
insulator hardware during the test as it will be subjected to under service conditions. In view of
the limited scope achievable with high voltages testing, it is recommended that tests are only
performed on the insulator assembly with the highest E-field, normally a single insulator deadend structures. This test is then regarded as sufficient for all other structures with the same
insulator-corona ring combination.
For lines, the only way to evaluate the corona performance correctly will be to perform the test
on a three-phase, full-scale mockup of the tower in an open-field setup. The electric fields
around such a test set-up would exactly match those on the actual line. However, this type of
testing is prohibitively expensive and only a very few laboratories have facilities to allow such
testing. A less than perfect alternative is to perform the test on a single-phase set-up and to adjust
the test voltage so that the E-field on the hardware approximate that of the service condition as
closely as possible. The phase to ground test voltage is therefore often different from the actual
phase to ground voltage of the system to compensate for:
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1. The absence of the other two phases.
2. The absence of other circuits on the same structure.
3. The proximity of “unnatural” ground planes such as walls and a test setup which is closer to
ground than on the actual structure.
Such a test method is described in the IEC Standard 61284, which describes two options for
corona testing:
1. Voltage method: whereby a test setup is exactly defined together with a corresponding test
voltage at which the test shall be performed. These test setups include the use of large ground
planes to simulate the presence of the other energized phases.
2. Voltage gradient method: An intentional perturbation on the test setup conductor is used to
obtain the relationship between the test voltage and the surface E-field on the conductor. This
is possible as this perturbation, usually in the form of a small ball bearing, presents an easy
identifiable corona source that goes into corona in a predictable manner.
Both methods are based on designing an equivalent single phase test setup that replicates the
service E-field gradient on the conductor (or conductor bundle) when installed on an actual
transmission line. These test methods and their limitations are explored by way of an example.
During the test optical (or UV) observations are used to determine whether or not discharge
activity is occurring from the metal end fitting under dry conditions. Special issues to
concentrate on when performing tests are:
•
•
The corona ring and end fitting should be corona free under dry conditions.
No sparking should be allowed between ring and insulator under wet conditions, nor shall the
ring touch the housing material.
Considerations on the Corona Ring Design:
When evaluating submitted designs attention should be given to the following design features.
•
•
The attachment of the ring to the end fitting should be designed so that it can only be fitted in
the correct position.
The design of the grading ring and its attachment should also take account of the effects of
power arcs in the event of a flashover across the insulator. The attachment design shall take
account of the flow of fault current and the possible negative effect it may have on the
mechanical and ageing performance of the insulator.
Table 7-26 presents general guidelines for the application of grading rings on composite
insulators. These guidelines are based on the results from experimental work performed by
EPRI.
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Table 7-26
A summary of the information that can be helpful when considering requirements for the housing.
System Voltage
Live End
Ground End
115 kV
Manufacturer dependent
(Insulators with small and slender end fittings
do requires rings, others not)
Configuration dependent
(Extra hardware may force the use of rings)
No
138 kV
Yes
No
161 kV
Yes
No
345 kV
Yes
Horizontal dead end insulators: yes
Suspension insulators: Dependent
on the design and configuration
400 kV and
above
Yes
Yes on all configurations
In Chapter 2 it was mentioned that corona rings also serve as arcing horns to shield the insulator
from arc damage should a flashover occur. In fulfilling this function, the corona ring should:
•
•
•
Shunt the arc away from the insulator housing material and end fitting seal.
Prevent the end fitting from heating up to the extent that it relaxes its crimping pressure on
the core.
Be able to withstand the temperatures and forces exerted during a short circuit.
The only way to sufficiently evaluate the ability of a corona ring (or arcing horn) is to subject it
to short circuit testing. For this type of testing, it is important that the insulator be installed in a
mock-up of the actual situation in which it will operate as this plays a large part in determining
the dynamic behavior of the power arc. A power arc test is described in IEC 61467. This test
should be followed by a detailed evaluation of the polymer insulator that should include the
diagnostic tests:
•
•
•
•
Dye penetration test
Residual mechanical strength determination by a tensile strength test.
Adhesion test to determine the condition of the core-housing interface if it is of the bonded
type.
Dissection of the insulator to determine the extent of dye penetration.
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Handling, Transport, and Packaging
Originally when composite insulators were first introduced, they were hailed as robust against
handling damage. Through the years evidence has accumulated to prove the opposite. It is now
generally accepted that composite insulators are relatively easy to damage from handling or
misapplication. The root cause of many insulator failures could be traced back to handling
damage or incorrect installation techniques. Factors that play a role are:
•
•
•
The low weight of the insulator and its apparent “toughness”.
Damage with a relatively small size could be critical and lead to a premature failure.
The damage incurred during handling or installation might be hidden so personnel are not
always aware that their actions have damaged the composite insulator.
Experience has shown that the education of warehouse and field personnel is essential to reduce
the number of handling-related failures. Both utility and contractor personnel need to be
addressed. Several guides and an educational video are available to assist in this regard (See
detailed discussion in Chapter 8), most manufacturers also provide handling and corona ring
installation instructions with each shipment. It is also a good idea to state minimum packing
requirements upfront to ensure its adequacy, even for long-term storage. The following essential
characteristics are:
•
•
•
•
•
•
Insulators should be packed in sturdy crates to provide protection from external mechanical
loads for the units during transport and storage. The crates should also provide a sufficient
barrier against the entry of rodents.
The packaging should be designed so that the insulators are adequately supported to prevent
them from moving around in the crate and to prevent excessive bend through. The internal
supports should not chafe or cause damage to the insulator.
Additional protection against the environment is provided if the insulators are packed in
individual plastic sheaths.
Accessories, e.g., grading rings, should be secured in the crate so that they do not come into
contact with insulators.
A list detailing the contents of the crate should be fixed on the outside.
Each crate should contain a copy of the manufacturer’s handling and grading ring installation
instructions.
When handling composite insulators there are a few simple rules that should be followed:
•
•
The housing should not come into contact with other objects that could cause abrasion.
Insulators should not be dragged along the ground or come into contact with conductors,
ropes, tools and other gear. When hoisted, lifting ropes should be attached to the end fittings
and not come into contact with the insulator housing.
The housing should not come into contact with sharp objects. When unpacking insulators
sharp nails may be exposed that could nick the housing. Damage may also be inflicted on the
insulators if knives are used to remove packing materials, such as plastic sheaths.
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•
•
•
•
•
The housing should not be subjected to mechanical forces for which it is not designed. The
housing may be damaged, or sheds may be torn if insulators are stepped on or climbed upon.
Also, the sheds should not be used as “handles” to lift insulators.
Composite insulators may be damaged if impacted by other objects. An impact to the sheath
may cause damage to the bond between the housing and the core. This damage may not
easily detectable. Also, an impact to the shed may lead to a tear in the shed material.
The insulators should not be subjected to excessive bend through. This may happen if only
one person carries long insulators, or if the core is not adequately supported during
transportation.
When installing insulators care should be taken not to subject especially longrod insulators to
bending (cantilever) or twisting loads. These may weaken the insulator core or cause damage
to the end fitting seal that could result in premature failures.
The manufacturer’s instructions should be precisely followed when installing corona or
grading rings onto the insulator. Care should be taken that the ring is positioned correctly and
that all bolts are tightened firmly.
Insulators that have been mistreated should be marked and set aside for a thorough inspection to
determine whether, or not, they can be installed or taken into service. During this inspection
special attention should be given to detect damage to the end fitting seal, cuts, or abrasions in the
housing, and de-bonding of the housing to the core.
Quality Assurance and Documentation
In the past consumers have relied on watertight specification and standards to ensure that
products of a good quality and consistency are installed on the system. In the preceding chapters
it is shown that this approach is not feasible or practical to be applied to composite insulators.
The reasons for this are many, but the difficulty and cost of extensive routine testing on full-scale
insulator units must count as one of the more important reasons. Consumers need therefore rely
more on a good quality assurance program to ensure the quality of the delivered product. In fact,
the IEC is considering the incorporation of quality assurance principles in the standards dealing
with composite insulators.
Quality assurance is in essence a process whereby all relevant information to the manufacturing
process, its key variables and its calibration, components and handling practices are documented
and audited in a well-structured way. It can go as far as identifying individuals and their
qualifications necessary for key processes. There are several clear advantages for both
manufacturer and user to document and monitor the manufacturing process through a quality
assurance program:
•
Consistency of product quality: Proper quality assurance requires that all processes and input
used in the manufacturing process be documented properly. This is true for the:
- Manufacturing process. A good quality assurance system requires a full documentation
of the manufacturing process where each step of the process is described in detail. This is
then used to ensure consistency of manufacturing with the aim to remove the human
factor as far as possible.
- Ground materials. Full documentation and traceability can be used to ensure
consistency of the ground materials used in the manufacturing.
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•
•
•
Traceability: A good quality assurance system ensures that all manufacturing data is
available for inspection. This improves the possibility to trace and identify other insulators of
the same batch in case of a manufacturing error.
- Documentation of the manufacturing process may be useful when performing a failure
analysis to help with pinpointing the root cause for the failure.
- The fact that the manufacturing process is well documented also makes it more difficult
to implement design or material changes without knowledge of the buyer.
Accountability: A good quality assurance system also ensures that all people working in the
manufacturing process is accountable for the part of the process that they are responsible for.
However, it is necessary to verify that there are no conflicts of interest with regards to
checking the quality of the manufactured product and set production performance targets that
the same person may have.
Customer confidence: The system of quality assurance provides the information necessary
for the customer to gain confidence in the processes and systems used by the manufacturer to
obtain a consistent product.
The buyers of composite insulators also need their own quality assurance system to govern the
application and use of composite insulators in their network. An important part of this process is
to evaluate the quality assurance process at the manufacturer. Quality Assurance (QA) is quite a
specialized field of expertise, and it is advisable to involve specialists in the area when preparing
or evaluating such processes. In the following bullet list some aspects are highlighted which
should be looked at:
•
•
Evaluation of the quality assurance program at a manufacturer:
- Certification of the QA process according to ISO 9000.
- Existence and completeness of a quality manual.
- Procedures for management of technical information, such as drawings.
- Review of the quality management system. These are in essence the feedback procedures
to ensure that lessons learned on the factory floor are captured and utilized to improve the
product.
- Existence and completeness of a change management procedure. This includes an
evaluation of the manufacturer’s criteria for retesting of the insulators when changes have
been implemented.
- Existence of internal control reviews at the manufacturer to ensure that the QA
procedures are followed.
Evaluation of the process management procedures in place:
- The existence of documents that describe the manufacturing process in detail. This also
includes a process flow diagram to illustrate the sequence of production, QA,
transportation and storage.
- Evaluate the manufacturer’s contingency plans for alternate suppliers, distribution, and
storage locations.
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-
Check that the manufacturer has proper procedures in place to handle non-conforming
materials and insulators. These include procedures for sample testing and acceptance or
rejection criteria.
Calibration of the equipment that measure the critical parameters during the
manufacturing process.
In addition, paying attention to the following aspects could be used to monitor manufacturers for
compliance:
•
•
•
•
•
•
Factory visits to confirm that the manufacturer has a good quality control processes in place
and that they adhere to their own procedures. Also, a general impression of the factory, e.g.,
neatness and cleanliness in critical areas, can be valuable to assess to which extent
production quality will be maintained.
On large orders it may be worthwhile to have a representative at the manufacturing plant to
show commitment to obtain the best quality products.
Check that critical information is safeguarded against loss by fire or otherwise.
Check that important process measurements are regularly calibrated, e.g., crimping pressure
for metal fitting attachment.
Level of training and experience of staff, which is also indicated by the level of employee
turnaround at the facility.
Witnessing of type and sample tests.
In this regard it is useful to build a good relationship with the supplier to foster a spirit of
teamwork with the aim to give the manufacturer a good understanding of the needs, requirements
and expectations of the buyer. It also enables a discussion of alternatives such as design changes,
packing and practical organization issues, which could lead to a cost reduction.
In addition, the users of composite insulators should also maintain their own quality assurance
through:
•
•
•
•
•
Development of instructions for transport, handling, storage and installation
Training of persons
Tagging of units to uniquely identify insulator units.
Documentation handling system and database of installation information
System of inspections and quarantine of damaged units
Example Specification
A specification is written to describe:
1. The required characteristics of the object: These are a list of characteristics that are
associated with each of the functions that the item must perform to fulfill the desired
operational capability.
2. The physical environment in which the object is going to operate in. Normally these are the
worst-case conditions that the item may be subjected to during its service life.
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3. The external interfaces to other co-functioning objects. For example; type of connection
fitting and the requirements for connection between the insulator and its grading ring.
4. It may be necessary to define a life profile, which is a set of instructions that covers the
whole lifetime of the object, from factory acceptance to final disposal. These instructions
include packaging, storage, handling, and disposal.
5. Define organizational procedures for delivery, submission of information, quality assurance
and project organization.
When writing a specification there are a number of basic principles that should be followed:
•
•
•
•
•
The desired technical capability of the equipment is described in terms of functions. Each
function may comprise one or more performance requirements, parameters and design
constraints. Design requirements are only included when a functional approach is not
possible.
Every property or function that is specified should be accompanied by a description of how it
will be verified by measurement or testing.
The section headings of the specification should follow that of the principle referenced
standard to allow for easy cross-referencing.
The values of the parameters that the supplier needs for the testing should be summarized in
easily accessible tables or schedules.
Where applicable, allowable tolerances should be specified for the required dimensional
parameters.
A typical composite insulator specification will comprise the following sections:
•
•
•
•
•
•
•
Scope; A short statement that defines the extent and applicability of the specification.
Normative references; this is a list of applicable standards and publications .
Definitions; Definitions are included of terms used in the specification that is not defined in
the normative references.
Inspection: A short descriptive text addressing the purchaser’s rights to inspect insulators
during the manufacturing process.
General requirements: Buyer specific requirements, which are not listed in the standards, are
grouped together under this point. This may include statements that define the responsibility
of the manufacturer.
Design requirements: These include specific features that the buyer wants incorporated for
the insulators offered. These can include items such as the required housing material,
thickness and end fitting type.
Performance and dimensional requirements: Electrical, mechanical and dimensional
parameters that define the insulator are specified in this section. These are parameters such as
the Specified Mechanical Strength (SML), Electrical withstand or critical flashover values
and the section length.
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•
•
Tests: Any special tests the buyer requires or modifications to the standards testing are listed
in this section.
Packing and handling: Specific requirements regarding packaging and handling are defined
in this section.
These principles were used to draft an example specification presented below. It serves to
illustrate certain aspects of specification writing and it is very important to note that it not
intended as a complete ready-to-use specification. The requirements included are illustrative only
and users should come up with their own criteria based on their evaluation of the considerations
listed in the report.
In this example, the fictitious AJP & E electric power company presents their specification for
composite suspension insulators on their 400 kV network.
•
•
On the left-hand pages information is given about the clauses and where to find information
in the report on this topic.
On the right-hand pages the specification itself is presented. The values and criteria shown is
valid for AJP & E but not necessarily for other utilities.
It is important to note that this specification is based on the IEC standards so there are significant
differences between the type definition presented here compared to that used by the ANSI
standards. See the introduction to this chapter for more details.
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EXPLANATORY TEXT AND REFERENCES
(NOT PART OF SPECIFICATION)
1. Scope
The scope is a short statement that defines the extent and applicability of the specification.
2. Normative references
A list of applicable standards is presented in this section. The user should be aware that there might be
crucial differences between international and national standards. This example is based on the standards
from IEC.
3. Definitions
Terms used in the specification which are not defined in the referred to standards are defined here. In this
section the user should also clarify which definition is binding if there are conflicts in the definitions listed
in the referred to standards. For example, if the user refers to both the IEC and ANSI standards, the term
“Design tests” should be defined for the purpose of the specification.
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TECHNICAL SPECIFICATION FOR COMPOSITE INSULATORS FOR USE ON
A.C. TRANSMISSION LINES.
1.
Scope
This specification covers the design, manufacture, testing and supply of composite line insulators for use
on AJP & E Electric power’s overhead power transmission system.
2.
Normative references
The insulators shall be designed, manufactured and tested in accordance with the latest versions and
amendments of the following standards:
IEC 61466-1
Composite string insulator units for overhead lines with a nominal voltage greater than
1 000 V – Part 1: Standard strength classes and end fittings.
IEC 61466-2
Composite string insulator units for overhead lines with a nominal voltage greater than
1 000 V – Part 2: Dimensional and electrical characteristics.
IEC 61109
Composite insulators for a.c. overhead lines with a nominal voltage greater than 1 000 V
- Definitions, test methods and acceptance criteria.
IEC 62217
Polymeric insulators for indoor and outdoor use with a nominal voltage greater than
1 000 V - General definitions, test methods and acceptance criteria
IEC 60071-1
Insulation co-ordination - Part 1: Definitions, principles and rules.
IEC 60815
Guide for the Selection of Insulators in Respect of Polluted Conditions.
IEC 60120
Dimensions of ball and socket couplings of string insulator units.
IEC 60471
Dimensions of clevis and tongue couplings of string insulator units.
3.
Definitions
The meaning of terms used in this technical specification concerning composite insulators is defined in
the normative references. Additional definitions are:
3.1 Section length. The section length (also known as connecting length) refers to the shortest
distance between fixing points of the live and earthed metalware, ignoring the presence of any stress
control rings, but including intermediate metal parts along the length of the insulator (see Figure 1).
Figure 1: The definition of section length.
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EXPLANATORY TEXT AND REFERENCES
(NOT PART OF SPECIFICATION)
4.
General requirements
Buyer specific requirements, which are not part of the referenced standards, should be included in the
general requirements section.
Clause 4.1:
A statement that defines the responsibility of the manufacturer is usually included.
Clauses 4.2 and 4.2.1: It is important to list here what information the supplier should provide with the
insulators.
Clause 4.2:
One of the sample tests defined in the standards is to verify the dimensions of the insulator
given in the drawings. The user indicates, therefore, which dimensions should be checked
in the sampling test by including them in the list of dimensions that should be included in
the drawing.
Clause 4.2.1: It is important to highlight the correct handling of the insulator. To align company practices
with that of the manufacturer it is suggested that the user require handling instructions to
be supplied with the insulators.
Some utilities require that the recommendations be included with the delivery crates.
Another option, especially for first time users of composite insulators are to require the
manufacturer to provide training on the handling of composite insulators to utility staff.
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4.
EXAMPLE SPECIFICATION
General requirements
4.1 The supplier shall be fully responsible for his designs and their satisfactory performance in service.
Approval by AJP & E Electric power does not relieve the supplier of responsibility for the adequacy of his
design, dimensions and details.
4.2 Each tender shall include one copy of all the detail and assembly drawings of the composite
insulator offered. The drawings shall contain the following information and dimensions in metric units:
a) Minimum arcing distance
b) Minimum creepage distance
c) Maximum diameter over insulating part
d) Minimum diameter over sheath
e) Shed inclination
f) Shed diameter
g) Shed spacing
h) Core diameter
i) Section length and tolerance
j) Coupling method, dimensions and IEC designation
k) Method of attachment of the metal fittings
l) Position and dimensions of the grading ring(s) if present.
m) Housing material description
n) Core material description
o) Insulator mass
p) Specified mechanical load (SML)
q) Routine test load (RTL)
r) Maximum system voltage
s) Dry lightning impulse withstand voltage
t) Wet power frequency withstand voltage
u) Wet switching impulse withstand voltage
4.2.1 manufacturer’s recommendations for the handling of the composite insulators shall be included
with the offer and in each delivery box. It shall at least cover the following aspects:
a) Instructions for unpacking.
b) Recommendations for storage.
c) Recommendations for transportation.
d) Recommendations for field handling.
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EXPLANATORY TEXT AND REFERENCES
(NOT PART OF SPECIFICATION)
5.
Design requirements
Specific features that must be incorporated into the insulator design must be included in this section.
Clause 5.1:
Specific requirements that the user may have regarding the end fittings are provided in this
clause.
Clause 5.2:
Specific requirements for the end fitting seal are provided in this clause.
Some utilities require that the end fitting seal comprise a direct bonding between the end
fitting and the insulator housing or that the seal design should incorporate an o-ring sealing
arrangement. Since the end fitting seal is highly manufacturer dependent, the risk exists
that the user may exclude most insulator designs.
Clause 5.3:
Specific requirements that the user may have regarding the insulator housing are provided
in this clause.
Clause 5.4:
Requirements for the shed design are listed in this clause. It should be noted that, in
general, shed profile characteristics are not critical to the flashover performance of the
insulator so the specification does not need to be overly strict on this point. In this example
a preference is expressed for an alternating design, although plain shed designs will also
be accepted if the manufacturer provides supporting evidence as justification.
Clause 5.5:
An important requirement to include is that for the design of grading rings. In this example
the user opted to include a table to indicate on which voltage levels the use of a grading
ring is mandatory. The user also needs to specify the line configuration on which the E-field
calculations be based. In order to reduce the number of different type of corona rings
available it is recommended that the structure specified that presents the worst case for
that voltage class. Generally speaking, the following features results in the highest electric
field gradient:
• Dead-end structures
• Vertical double circuit configuration
• Closest phase spacing
• Lowest tower height
• Smallest diameter conductor (single conductor)
• Longest hardware inserts such as extension straps between
(1) Insulator and structure
(2) Insulator and conductors
• Steel lattice structures or Steel pole
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5
Design requirements
5.1
End fittings
EXAMPLE SPECIFICATION
5.1.1 The end fitting connection type and dimensions shall be as specified in schedule A.
5.1.2 The end fittings of the insulators shall be connected to the core by means of a compression method
of attachment.
5.2
End fitting seal
5.2.1 The manufacturer shall submit information to prove that the end fitting seal shall maintain a water
tight seal for the useful life of the insulator.
5.3
Housing of the composite insulator
5.3.1 To prevent moisture ingress from the environment, the core shall be totally encapsulated and fully
sealed, from live to earth ends, by the insulator housing.
5.3.2 The housing shall have a minimum thickness of 3 mm over the core at any point along or around
the insulator.
5.3.3 Housing material shall be as is specified in schedule A.
5.4
Shed design
5.4.1 The shed design shall be of an alternating shed design. Plain shed design shall be acceptable if
the manufacturer supplies good technical justification for his choice.
5.4.2 The shed spacing shall be more than 40 mm.
5.5
Grading ring requirements
5.5.1 Grading rings shall be supplied with the composite insulator for the following voltage levels:
System voltage
Live end
Ground end
115 kV
By manufacturer recommendation
No
138 kV and 161 kV
Yes
No
345 kV
Yes
Horizontal dead end insulators: yes
Suspension insulators: By manufacturer
recommendation
400 kV and above
Yes
Yes on all configurations
5.5.2 Grading rings shall be designed to control the field along the insulator to below 4,3 kV/cm for any
length more than 10 mm under dry and clean conditions. The design of the grading ring shall be based on
the maximum system voltage and structure and insulator assembly as is illustrated in Schedule B.
5.5.3 Grading dings shall be designed in so that there will not be partial discharges from the ring to the
insulating material even in the case of severe pollution.
5.5.4 The grading ring shall be able to withstand the power arc current and duration specified in 8.1.4 (b).
5.5.5 The grading ring shall be designed in such a way that its correct installation is guaranteed.
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EXPLANATORY TEXT AND REFERENCES
(NOT PART OF SPECIFICATION)
In the following sections, i.e., 5.6, 5.7 and 5.8 the parameters are specified which define the insulator
type. As far as possible the type characteristics should be limited to electrical and mechanical
performance criteria as tested during the type tests.
For convenience the parameters that define the insulator are grouped together in Schedule A, so the
clauses in this part are limited to text that refers to the schedule.
Clause 5.6:
The mechanical characteristics of the insulator are specified in this clause.
Clause 5.7:
The electrical characteristics of the insulator are specified in this clause.
Clause 5.7:
The dimensional characteristics of the insulator are specified in this clause. In the normal
case the dimensions of the insulator is determined by the manufacturer to fulfill the
performance criteria as specified in 5.6 and 5.7.
For re-insulation projects it could be necessary to specify the section length of the insulator.
In this case the user should be aware that a conflict could arise if the user also specified
the Lightning Impulse Withstand level, which is normally the parameter, which is used by
the manufacturers to determine the insulator section length.
6.
Tests
This chapter lists amendments to the standards testing, or additional tests that should be performed to
verify the characteristics of the insulator. The user should be aware that additional testing may impact the
price of the insulators; this is especially so in the case of long-term testing.
Clause 6.1:
The general requirements for the testing of the insulator are listed here. It normally
specified on which standard the testing should be based. It is recommended that the
structure of this section follows that of the referred to standard for easy reference and
clarity.
Clause 6.2:
Amendments to the design test of the standard are listed in this section. A number of
typical examples are listed in this section.
Clause 6.2.1: The referred to standard does not specify that all design features of the insulator should be
present in the insulator subjected to the test. These additions, especially to long insulators,
often present weak points where accelerated aging may take place.
Clause 6.2.2: In cold or hot climates it may be necessary to adjust the temperatures at which the tests
are performed.
Clause 6.2.3: In cold or hot climates it may be necessary to adjust the temperatures at which the tests
are performed.
Clause 6.2.4: An updated version of the tracking and erosion test is described in IEC 62217.
Clause 6.2.5: An updated version of the simulated weather test is described in IEC 62217.
Clause 6.3:
Amendments to the type tests of the standard are listed in this section. A number of typical
examples are listed in this section.
Clause 6.3.1: Parameters to define a Radio Interference Test is defined. This test is not required by the
present IEC 61109 standard.
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5.6
EXAMPLE SPECIFICATION
Mechanical requirements
5.6.1 The mechanical requirements for the insulator are specified in Schedule A.
5.6.2 Withstand time-load cure for the insulators offered shall be submitted with the offer.
5.7
Electrical requirements
5.7.1 The electrical requirements for the insulator are specified in Schedule A.
5.8
Dimensional requirements
5.8.1 The insulator shall be dimensioned as is specified in Schedule A.
6
Tests
6.1
General
6.1.1 The composite insulators shall be tested in accordance with IEC 61109 and the provisions of this
specification.
6.1.2 The supplier shall supply test certificates that verify that the insulator meets all required
characteristics.
6.2
Design tests
6.2.1 Test specimens and preliminary tests: The test specimens for all the design tests shall be as
described in the IEC 61109 with the following amendment:
The tested samples shall also include all the design features—that may not be present on the shorter
insulator—present on the insulator being offered. These are items such as spacers to fix the core rod in a
concentric position in the housing and joint sealant rings or other housing joints perpendicular to the core.
6.2.2 Sudden load release test: The sudden load release test is performed as is described in the IEC
61109 with the following amendment:
The temperature at which the test is performed shall be -40°C to -45°C.
6.2.3 Thermal-mechanical test: The thermal mechanical test are performed as is described in the IEC
601109 with the thermal cycle amended as follows:
Each 24 h thermal cycle has two temperature levels with a duration of at least 8 h, one at +50°C ± 5 K,
the other at -50°C ± 5 K.
6.2.4 Test of housing: tracking and erosion test: The tracking and erosion test is performed as is
described in the IEC 62217.
6.2.5 Ageing test under operating voltage simulating weather conditions: The insulator shall be
tested with the accelerated ageing test as is described in Annex B of the IEC 62217.
6.3
Type tests
6.3.1 Radio interference test: At a voltage stress of the maximum operating voltage shall the noise limit
be 60 dB (1 µV/300Ω) at a 500 kHz measurement frequency and reference atmospheric conditions.
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EXPLANATORY TEXT AND REFERENCES
(NOT PART OF SPECIFICATION)
Clause 6.4:
Amendments to the sample tests of the referred to standard is specified in this section.
Clause 6.4.2: In the present standard there are no sample or routine dielectric tests performed on the
composite insulator. Electrical routine testing is not practical on transmission class
insulators. This deficiency is addressed by including a simple dielectric test on a limited
number of the sampled insulators.
Clause 6.4.3: An additional requirement is included to verify that the housing thickness conforms to the
design requirement in clause 5.3.2.
Clause 6.5:
The requirements for routine testing are specified in this section.
Clause 6.5.1: The markings on the insulator to identify it are specified in this section.
Clause 6.5.2: The criteria for rejection of blemished insulators are redefined with specific point based on
the utility’s past experience.
7.
Packing requirements
The buyer should specify their requirements for the packaging of the insulators.
Clause 7.1:
The quality of the packing is important that the insulators will reach the installation site
undamaged. Special requirements may apply if the insulators will be subjected to long-term
storage. In the latter case the crates should be strong enough to be stacked.
Clause 7.2:
Each crate should include a set of instructions that service personnel can follow to handle
and install the insulator. It is especially important to have clear installation instructions for
grading rings which are normally fitted at site prior to installation.
Clause 7.3:
The labeling of the crates is important so that warehouse staff is in a position to easily
verify the delivery.
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6.4
Sampling tests
EXAMPLE SPECIFICATION
6.4.1 General rules: For the sampling tests the general rules of the IEC 61109 shall be followed.
6.4.2 Dry power frequency withstand test (E1): A dry power frequency test shall be performed on
sample E1 before the verification of the specified mechanical load, according to clause 5.1.4.3. of IEC
1109: 1992.
6.4.3 Verification of minimum housing thickness (E1): The minimum thickness (clause 5.3.2) of the
housing shall be verified on sample E1 after the verification of the SML. Conformance shall be verified by
cutting the insulator in sections at a maximum interval of 400 mm. The cuts shall be performed
perpendicular to the core rod, midway between two sheds. A cut shall also be made on the two sheath
portions closest to the end fittings. The housing thickness is then measured at the thinnest point for each
cut.
6.5
Routine tests
6.5.1 Identification: Each insulator shall be marked with the (1) name or trademark of the manufacturer
(2) Catalog number (3) the year and month of manufacture. In addition, each insulator shall be marked
with the SML and a unique serial number or batch identification. These markings shall be legible and
indelible.
6.5.2 Visual inspection: A visual inspection shall be made on each insulator with the following
additional rejection criteria: An insulator is rejected when:
a) The mould line or flashing is higher than 1 mm above the shed surface.
b) The depth of cavities is over 1 mm.
c) There are cracks at the root of the sheds next to the fittings
d) There are cracks in the metal fitting
e) There is a separation or lack of sealant at the shed/metal-fitting interface
7.
Packing requirements
7.1 The packing of the composite insulator shall be adequate for the handling and transport to the
delivery destination as is specified in the Schedule A. Details of the packaging shall be supplied with the
tender and is subject to agreement between supplier and buyer.
7.2
Each crate shall contain:
a) Instructions for unpacking.
b) Instructions for affixing the corona ring.
b) Recommendations for handling.
7.3
The packaging of the insulators shall be clearly marked with at least the following information:
a) Purchase order number.
b) Insulator brand and catalog number.
c) Quantity of insulators included in the crate
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EXPLANATORY TEXT AND REFERENCES
(NOT PART OF SPECIFICATION)
Schedule A: All environmental and insulator parameters are grouped together for easy reference during
the tender evaluation.
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8.
EXAMPLE SPECIFICATION
SCHEDULE A: TECHNICAL DETAILS
Insulators for the 145 kV Paradise – Tribulation Overhead line
Technical
Requirements
8.1 Manufacturer
8.2 Manufacturer's type reference
8.3 Classification
(a) Application
(b) Housing material
8.4 Operating conditions
(a) System Maximum Voltage Um
(b) Power Arc Rating
(c) IEC Pollution Classification
(d) Type of environment
(e) Operating Temperature
Minimum Temperature
Maximum Temperature
Maximum Diurnal Variation
8.5 Mechanical Strength Requirements
(a) Ordinary Mechanical Load
OML
(b) Extraordinary Mechanical Load
EML
(c) Maximum Mechanical Load
MML
(d) Specified Mechanical Load
SML
8.6 Electrical Strength Requirements
(a) Dry Lightning Impulse Withstand (at Sea Level)
(b) Wet Switching Impulse Withstand (at Sea Level)
(c) Wet Power Frequency Withstand(at Sea Level)
8.7 Dimensions and Clearances
(a) Connecting Length and tolerance
(b) Minimum Creepage Length
(c) Minimum Ratio of Shed Spacing to Shed Projection
(d) End Fittings
IEC 120 Designation 16 mm Ball and Socket
8.8 Quantity
8.9 Delivery Date
8.10 Delivery Destination
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Please specify
Suspension
Silicone Based
145 kV
10 kA; 500 ms
Medium
Marine
-50 °C
40 °C
20 °C
30 kN
58 kN
96 kN
Please specify
550 kV
N/A
230 kV
Please specify
3625 mm
0.8
Ball(Live)-Socket
1200 Units
Oct 2006
Paradise
Substation
Guaranteed
Technical Values
EXPLANATORY TEXT AND REFERENCES
(NOT PART OF SPECIFICATION)
Schedule B: A drawing of the tower configuration and insulator assembly is supplied to the insulator
manufacturer in order to perform the electric field calculations.
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EXAMPLE SPECIFICATION
SCHEDULE B: CONFIGURATION DETAILS
9
Requirements for E-field modelling
9.1
Model Parameters:
Provide the following Modeling Parameters for each of the configurations considered:
1. Modeling Package Used
a. Name
b. BEM or FEM or other
c. 3D or 2D
2. Modeling parameters
a. Energy Error (or other)
b. Number of Passes (or other)
c. Number of Tetrahedra (or other)
3. Definition of Boundary
Conditions
Note a precise definition of these
is provided in a later section—
this is intended to confirm the
voltages used.
Top Phase Voltage
Middle Phase Voltage
Bottom Phase Voltage
Earth
Structure
4. Use of Symmetry
Yes or No—please provide detail separate from table
5. Images of Model showing how
geometry was represented
a. Structure and conductors (Fig. #s)
b. Hardware (Fig. #s)
c. Insulators -. End fitting detail (Fig. #s)
c. Insulators—Core and Weathershed system detail (Fig. #s)
9.2
Results:
The E-field shall be calculated at the:
•
•
•
•
Energized end fitting
Grounded end fitting.
Along the sheath of the insulator close to the energized end fitting
Along the sheath of the insulator close to the grounded end fitting
The tables below define the E-field magnitude plots and images needed for each of the sheets.
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Measurement
1. E-field magnitude
along the surface of
metallic energized end
fitting of the Middle
Phase Composite
Insulator
2. E-field magnitude
along the surface of
metallic grounded end
fitting of the Middle
Phase Composite
Insulator
3. E-field magnitude
along the surface of
rubber sheath of the
Middle Phase
Composite Insulator.
(for a distance of
300mm starting 1 mm
from the energized
end fitting,
measurement line
should be straight and
parallel to the axis of
the insulator)
Definition of measurement line
Number of points on measurement
line: 100
Side View
Number of points on measurement
line: 100
Side View
Number of points on measurement
line: 1000
Overview of results to be provided
1) Location of maximum E-field
2) Maximum Value (rms kV/mm)
Plan View
1) Location of maximum E-field
2) Maximum Value (rms kV/mm)
Plan View
1) Location of maximum E-field
2) Maximum Value (rms kV/mm)
Plan View
Side View
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Measurement
4. E-field magnitude
along the surface of
rubber sheath of the
Middle Phase
Composite Insulator.
(for a distance of
300mm starting 1 mm
from the grounded
end fitting,
measurement line
should be straight and
parallel to the axis of
the insulator)
5. E-field magnitude
inside the rod of the
Middle Phase
Composite Insulator.
(for a distance of
300mm starting 1 mm
from the energized
end fitting,
measurement line
should be straight and
parallel to the axis of
the insulator)
Definition of measurement line
Number of points on measurement
line: 1000
Overview of results to be provided
1) Location of maximum E-field
2) Maximum Value (rms kV/mm)
Plan View
Side View
Number of points on measurement
line: 1000
1) Location of maximum E-field
2) Maximum Value (rms kV/mm)
Plan View
Side View
Additional Calculations
6. Equipotential Plots – Middle
Phase composite insulator (as
modeler sees fit)
7. E-field Magnitude Shaded Plots
– Middle Phase composite
insulator (as modeler sees fit)
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a. Energized End (Fig. #s):
b. Grounded End (Fig. #s):
c. Other (Fig. #s):
a. Energized End (Fig. #s):
b. Grounded End (Fig. #s):
c. Other (Fig. #s):
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9.3
Pole Geometry and Boundary Condition Definition (An Example)
Calculations shall be made at the maximum system voltage,
which is a phase-to-ground voltage of 83.7 kV rms (phase-tophase voltage = 145 kVrms). The voltage on the insulator
being considered shall be at the peak of the AC cycle. This is
accomplished by assigning to each phase the voltage
indicated in the table and treating the problem as if all the
voltages where in phase.
Top Phase
Top Phase Voltage: - 41.85 kV
Middle Phase Voltage: 83.7 kV
Bottom Phase Voltage: -41.85 kV
Earth: 0 kV
Structure: 0 kV
83.7*√2
Middle Phase
Bottom Phase
41.85*√2
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Figure 7-29
Pole Assembly. (Pole has circular cross section).
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Figure 7-30
Phase Wire Davit Arm Detail
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Figure 7-31
Ground Wire Davit Arm Detail
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Insulator: Energized end detail
Hubbell Part Number:
HAS-139-S
* This part includes the
Aluminum Clamp and
Socket-Eye Connection
Drawings are Not To Scale
Figure 7-32
Insulator – Energized End Detail
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References
[1]
P. W. Sothman, "Comparative Tests on High-Tension Suspension Insulators," American
Institute of Electrical engineers, Dec. 1912.
[2]
"American National Standard for Electrical Power Insulators - Test Methods," American
National Standards Institute, 1430 Broadway, New York, NY 10018,C29.1-1988, Aug.
1988.
[3]
"Hydro-Electric Commission, Test on Insulators,", 19 ed 1910, pp. 623–624.
[4]
A. O. Austin, "Present Practice in the Design and Manufacture of High-Tension
Insulators," American Institute of Electrical Engineers, June1917.
[5]
F. Bologna and C. Engelbrecht, Glass Suspension Insulators: Review of Current
Technology. EPRI, Palo Alto, CA: Dec. 2008. 1015923.
[6]
P. W. Sothman, "Comparative Tests on High-Tension Suspension Insulators," American
Institute of Electrical engineers, Dec. 1912.
[7]
E. A. Cherney, "Cement Growth Failure of Porcelain Suspension Insulators," PAS-102
ed 1983, pp. 2765–2774.
[8]
D. Lecomte and P. Meyere, "Evolution of the design for the 735 kV transmission lines of
Hydro-Québec," CIGRE, 21 rue d'Artois 75008 PARIS/FRANCE, 22-08, 2010.
[9]
K. Morita, T. Imakoma, M. Nishikawa, and H. Nozaki, "Steep Impulse Voltage
Characteristics of Suspension Insulators," Electrical Engineering in Japan, vol. 115, No.
2, pp. 21–31, 1995.
[10]
"Thermal-mechanical performance test and mechanical performance test on string
insulator units," International Electrotechnical Commission, 3, rue de Varembé, PO
Box 131, CH-1211 Geneva 20, Switzerland, IEC 60575: 1977, 1977.
[11]
EPRI. Small Scale Aging of Polymer Insulators: Development of Small-Scale Test
Chamber and Insulator Evaluation Criteria. EPRI, Palo Alto, CA: 2015. 3002005690.
[12]
EPRI. Effect of End Fitting Design on Controlling Corona Research Results After 17,000
Hours of Aging. EPRI, Palo Alto, CA: 2018. 3002012659.
[13]
IEC. “Polymeric insulators for indoor and outdoor use with a nominal voltage > 1 000 V
– General definitions, test methods and acceptance criteria”. IEC International Standard
62217. Geneva, Switzerland, 2012.
[14]
Riquel, G. “Accelerated Ageing Test for Nonceramic Insulators: EdF’s Experience.”
Workshop paper, presented at the Nonceramic Outdoor Insulation Workshop. Paris.
April 1993.
[15]
CIGRE. Field Experience and Laboratory Research on Composite Insulators for
Overhead Lines. Paris. Report 15-12, 1986.
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[16]
Fini, G., G. Marrone, L. Sartore, and E. Sena, “Qualification Tests Performed on
Composite Insulators for 132-150 kV Overhead Lines.” Paper presented at the 12th
International Conference on Electricity Distribution. Birmingham, England. May 1993.
[17]
EPRI. Clean Fog Flashover Tests on 138-kV Nonceramic Line Post Insulators Before
and After Artificial Aging. EPRI, Palo Alto, CA: 1992. 100886.
[18]
Schneider, H., W. Guidi, J. Burnham, R. Gorur, and J. Hall. “Accelerated Aging and
Flashover Tests on 138 kV Nonceramic Line Post Insulators.” IEEE Transactions on
Power Delivery. Vol. 8, No. 1, pp. 325–336, 1993.
[19]
EPRI. 500 kV Aging Chamber – Testing and Final Results. EPRI, Palo Alto, CA: 2000.
1000719.
[20]
Schneider, H., W. Guidi, J. Slocik, J. Burnham, J. Hall, R. Brown, D. Chaply, J.
Ellsworth, R. Robarge, and L. Wakefield. “Accelerated Aging Facility for Full Scale
500 kV Nonceramic Insulators.” Paper No. 47.07. Presented to the 8th International
Symposium on High Voltage Engineering. Yokohama, Japan. August 1993.
[21]
EPRI. 230 kV Accelerated Aging Chamber: Description of Test and Condition of NCI
After One Year of Aging. EPRI, Palo Alto, CA: November 2002. 01001745.
[22]
EPRI. 230 kV Accelerated Aging Chamber: Condition of NCI After 2 Years of Aging.
EPRI, Palo Alto, CA: 2003. 1001746.
[23]
EPRI. 230 kV Accelerated Aging Chamber: Condition of NCI After 3 Years of Aging.
EPRI, Palo Alto, CA: 2004. 1008737.
[24]
EPRI. Non-ceramic Insulator End Fitting Analysis. EPRI, Palo Alto, CA: November
2002. 1001744.
[25]
EPRI. Application of Corona Rings on 115/138 kV Polymer Transmission Line
Insulators: Existing Populations and New Applications. EPRI, Palo Alto, CA: 2008.
1015917.
[26]
EPRI. Software for Polymer Insulators Electric Field Calculations – EPIC. EPRI, Palo
Alto, CA: 2008. Software Product ID #1018048.
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8
APPLICATION
Introduction
This chapter draws on EPRI’s extensive research on application of polymer, porcelain and glass
insulators. The chapter addresses the following major topic areas:
1. Handling and Storage
2. Live Working
Handling and Storage
Great strides have been made in understanding polymer insulator design and application.
Although polymer insulators offer advantages compared to porcelain and glass insulators,
including light weight and good contamination performance, the greatest concern remains the
question of life expectancy. During service life, polymer insulators have to insulate the line
conductor from the structure under severe static and dynamic loads and environmental
conditions. Initially, the aging of the polymer material was considered the main factor in
reducing the life expectancy of polymer insulators. Recent experience has shown that life
expectancy is also related to handling prior to and during installation.
At their introduction in the early 1970s, polymer insulators were promoted and marketed as
being “unbreakable” and therefore it is not surprising that they are treated roughly. Unlike
conventional porcelain and glass insulators, polymer insulators do not shatter or chip, therefore,
if polymer insulators are mishandled, telltale signs are not always immediately evident. This
could eventually lead to insulator failures or line droppings resulting in power outages 20 years
later.
As a means of preventing failures resulting from mishandling, this section provides background
information on how to handle polymer insulators to prevent damage during shipping, storing,
and installation [4] [5] [6]. This information can aid utility engineers and managers in developing
practices and procedures for their specific utility to cover the following specific situations:
•
•
•
While being handled and stored in a warehouse
During transportation to the work site, by either utility line crews or contractors
During installation by either utility line crews or contractors
It is also important to fully implement the developed practices and procedures and an important
tool in this regard is educational tools such as the training videos developed by EPRI
(https://media.epri.com/ secure/024056/20140303/S_2.mp4).
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Handling and Storage
Receiving
When shipments of polymer insulators arrive, the stores manager needs to check the paperwork
for compliance. The crate housing the insulators must be examined for signs of damage. If
damaged, the supplier must be notified immediately and each insulator within the crate must be
visually inspected for any signs of damage.
Storage in Crates or Boxes
It is recommended that the insulators be stored in their original crates for as long as possible. The
crates should be stored indoors away from exposure to the elements and hazardous chemical
substances such as petroleum products. If the insulators are stored outside, ensure that they are
stored in pressure treated lumber rather than cardboard boxes or regular lumber. An example of
damage to regular lumber stored outdoors is shown in Figure 8-1.
Care should be taken when stacking cardboard boxes. Too many cardboard boxes stacked on one
another may result in the boxes at the bottom becoming squashed. Care should also be taken not
to stack heavy material onto cardboard boxes. Figure 8-2 shows an example of this.
Storage Out of Crates or Boxes
If insulators have to be removed from their original crates, care must be taken to protect the
insulators from damage (see Removing Polymers from Shipping Crates). This can be done by
ensuring that they are not stacked on top of each other; also ensure that no other material is
stacked or placed on top of them. This will prevent the sheds from deforming, cracking or
splitting. Figure 8-3 gives an example of incorrect stacking.
There are several effective options for storing polymers out of their crates. Some utilities use
designated bins designed for different insulators while others hang insulators using hooks. If
storing on the ground, PVC pipes and builder’s tubes are also very versatile. These come in
different sizes and can also be used to transport insulators. Examples of storage by using PVC
pipes and hanging are shown in Figure 8-4 and Figure 8-5.
Care should also be taken in the selection of the storage location. Any contact with
petrochemical products must be avoided as these may react with the rubber material. Care should
also be taken to avoid rodents as these have been known to eat the rubber material as shown in
Figure 8-6.
Loading and Off-Loading Crates
If crates need to be loaded and off-loaded using a forklift, care must be taken to avoid damage to
the crate by punching the forks into the crates, thereby damaging the insulators. Also, as already
mentioned, if cardboard boxes are used, they should not be stacked too high and heavy objects
should not be stacked on top of them. An example of forklift damage is shown in Figure 8-7.
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Figure 8-1
Weathered regular lumber placed outdoors.
Figure 8-2
An example of over stacking.
Figure 8-3
Example of incorrect stacking.
Figure 8-4
Insulators stored in PVC pipes.
Figure 8-5
Insulators stored using hooks.
Figure 8-6
Rubber material eaten by rodents.
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Practices for Transporting to Site
Wherever possible, polymers should be transported to site in their original, closed shipping
crates. If only part of the consignment needs to shipped, then insulators removed from the
manufacturer’s packaging must not be transported loosely or without protection. The following
recommendations can be made:
•
•
•
Protection using PVC pipes and builders’ tubes as shown in Figure 8-8 (described in the
previous section) can be used.
Avoid placing objects on unprotected insulators.
Insulators should not be tied down or tied together by ropes, chains, etc. when transported.
On-Site Storage Practices
On-Site Storage
Insulators are a lot more vulnerable to damage on site than at the warehouse. On arrival at site,
the packaging should again be carefully checked for damage or maltreatment. If a crate is found
damaged, then each insulator in the crate needs to be examined for signs of damage. Any units
found damaged should be immediately rejected.
Insulators should be kept in their original packaging for as long as possible; when this is not
possible then PVC pipes or builder’s tubes are recommended. They will protect the insulators
from damage at site and also from each other. If protective coverings cannot be used then the
insulators should be stacked, side-by-side, elevated from the ground surface using pallets
(improper stacking will again make the insulators prone to damage). Packing the polymers on
pallets will ensure the insulators are kept out of dirt, dust, mud etc. and away from site traffic
where they can be struck by equipment, driven over or stood upon. Figure 8-9 shows what could
happen if insulators are not stored correctly.
Removing Polymers from Shipping Crates
Any nails or screws left exposed on removal of the crate lid, or internal batons, must be removed
prior to removing insulators from the crate to prevent damage. Exposed nails and screws may
significantly damage the polymer rubber surfaces when units are removed from the crate. An
example of damage due to an exposed nail is shown in Figure 8-10.
Removing Polymers from Plastic Sheaths
Some insulator manufacturers package insulators in plastic bags (alternatively called plastic
sheaths). If the plastic bag is cut along the length of the insulator there is a risk that the rubber
weathershed material may also be cut. The bag should rather be cut carefully across the top of
the bag away from the insulator. Figure 8-11 and Figure 8-12 show the incorrect and correct
method of cutting the plastic bag.
In view of the significant probability of insulator damage when insulators are transported to the
structure, it is strongly recommended that a temporary, reusable packing system (PVC pipes or
builder’s tubing) be introduced to provide protection during transport and short-term storage.
They should be left in place until stringing and installation of the conductor accessories is
complete.
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Figure 8-7
Damage to insulators due to puncturing of a
crate by forklift blades.
Figure 8-8
Use of PVC tubes in a truck.
Figure 8-9
Insulators left in the dirt and driven over.
Figure 8-10
Damage caused by nails.
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Figure 8-11
Incorrect method for removing polymers from
plastic sheaths.
Figure 8-12
Correct method for removing polymers from
plastic sheaths.
On-Site Handling Practices
Another situation where damage can occur is when polymers are carried. Damage in this case
can vary depending on the type of insulator, i.e., suspension or line post polymer.
All Polymer Insulators
Polymer insulators are especially vulnerable if bent and/or dragged. In cases like these, the rod
can crack or the weathershed system can be damaged. Remember, even a small crack can cause a
failure after exposure to the elements. Typical incorrect scenarios are illustrated in Figure 8-13
and Figure 8-14.
Suspension and Dead-End Polymers
If the fiberglass rod is allowed to flex excessively at any time, the fibers may get damaged.
When this occurs, detection is difficult because the polymer housing covers the rod. To avoid
such damage, polymers should be carried in the following way:
If an insulator has a connecting length of less than 100 inches (2.5 meters) it can be safely lifted
by one person holding the core at a central point. If the unit is longer, then it should be lifted and
carried by two persons, each person holding the insulator about 20 inches (0.5 meters) from the
end. The incorrect and correct methods of carrying insulators having a length greater than
100 inches (2.5 meters) are illustrated by Figure 8-15 and Figure 8-16.
Post Polymers
Post polymers are usually heavy and awkward to move. Hence, they may require a number of
personnel to move or transport. In such cases, slings should be placed around the end fittings,
lifted and then moved. Slings should not be placed around the polymer material as this may
damage the polymer housing. Figure 8-17 and Figure 8-18 show the correct and incorrect
method.
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8-6
Figure 8-13
Insulator dragged on ground: incorrect
handling.
Figure 8-14
Insulator used as a support: incorrect
handling.
Figure 8-15
Incorrect carrying procedure.
Figure 8-16
Correct carrying procedure.
Figure 8-17
Correct attachment point: attached to end
fitting.
Figure 8-18
Incorrect attachment point: attached to
polymer housing.
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Installation Practices
Pre-Installation Inspection
Prior to the polymers being raised up the structure they should be thoroughly inspected for any
damage. Insulators showing signs of damage must be tagged and set aside. This ensures that
these units are not applied in the future unless deemed fit by the appropriate procedure.
Assembly of Polymers and Associated Hardware
During the assembly of the insulator and associated hardware it is recommended that a ground
sheet is used as this provides a clean surface to work from and will also reduce the risk of rocks,
stones and other objects from damaging the insulator (see Figure 8-19).
It is preferable that the insulator and all the string hardware be assembled while on the ground.
This practice will ensure that all the components are compatible and that no force is required to
carry out the assembly.
Like the hardware, if corona rings need to be fitted then it must be ensured that these are fitted
correctly, i.e., in the correct position and the right way round—rounded end away from the
fitting. A loose ring in contact with the rubber weathershed system can wear through exposing
the fiberglass rod resulting in failure. Corona rings should be preferably installed on the ground
where there is more control.
Use of Protective Sleeves
Specially designed protective sleeves can be used to prevent damage during installation and from
most other hazards. Such sleeves are designed using Velcro straps that can be easily removed
once installation has been completed. Ideally, they should be left in place until stringing and
installation of the conductor accessories is complete. An example of such sleeves is shown in
Figure 8-20.
Attachment of Lines and Ropes
Lifting lines or ropes must be attached to the metal caps of the insulators and not the sheds or
rods (see Figure 8-21).
Large line post insulators should be carefully lifted in a horizontal position using slings. The
slings must be attached to the end fittings and not to the polymer housing. Figure 8-22 shows the
correct procedure.
Hoisting Up the Structure
If you are going to use a rope to hoist the insulator up the structure, ensure that a ground line is
attached to the lower end fitting and is handled by a ground-based lineman. The ground-based
lineman must ensure that the polymer is under control during hoisting to prevent the insulator
from banging into or getting hooked onto the structure. He must also ensure that the lifting and
ground lines do not rub against any other polymers. Figure 8-23 and Figure 8-24 give examples
of both the correct and incorrect methods.
Care must also be taken that no bending loads are applied to the insulators when lifting the
assemblies to the top of the structure.
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8-8
Figure 8-19
Corona rings assembled on a ground sheet.
Figure 8-20
An example of a plastic protective sleeve fitted with velcro straps.
Figure 8-21
Incorrect rope attachment point.
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Figure 8-22
Correct method for lifting line post insulators.
8-9
Damage to Polymers by Bucket Trucks
It should be ensured that the working platform, bucket truck, tools, etc. do not come into contact
with the insulator as this may result in damage or the insulator being subjected to unacceptable
mechanical loads. Figure 8-25 is an example of unacceptable mechanical load being applied by
a bucket resting on a post polymer.
Damage to Polymers by Tools
Ladders, tools, blocks, ropes and other equipment must be prevented from coming into contact
with the polymer weathershed system. 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.
Damage to Polymers by Ropes
The practice of throwing a line or rope over the post or dead-end insulator to pull other
components to the pole top is not permitted. This action can totally abrade and remove the
sheath exposing the core and precipitating future failure. An example of such damage is given
in Figure 8-26.
Climbing or Walking on Polymers
Post Insulators
Neither post insulators nor the corona rings should be stepped or climbed on. Owing to the
nature and geometry of the structure, horizontal line posts mounted on single poles are often
stood on and/or used for crawling out to the conductor attachment point. Sheath and shed
damage can occurs from boots, safety belt buckles, tools, crampons etc. To prevent this, suitable
working platforms should be considered either on the structure or bucket trucks.
Figure 8-27 shows some examples of how post insulators may become damaged during
installation.
Suspension Insulators
In the case of suspension insulators, hanging ladders attached to the cross arm could be used to
gain access to the energized end side of the insulator. Dead-end insulators should not be walked
or crawled on to reach the energized end as they are vulnerable to sheath and shed damage
from boots, safety belt buckles, etc. For dead-end insulators, the use of a working platform
is suggested. Stepping or climbing on the insulator or grading ring is not permitted (see
Figure 8-28).
Use of Polymers as Anchoring Points
Insulators may not be used as anchoring points for pulleys, tools, safety belts and/or any other
equipment. The insulator may become overloaded resulting in a fracture of the fiberglass core.
An example of an insulator used as an anchoring point is shown in Figure 8-29.
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Figure 8-23
Correct method: rope tied on top and bottom.
Figure 8-24
Incorrect method: rope tied on to rubber
insulator, collision into structure.
Figure 8-25
Bucket striking and placing a load on the
insulator.
Figure 8-26
Damage to insulator by rope.
Figure 8-27
Damage to the insulator by the safety belt and boots should be avoided.
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Attachment of Hardware and Stringing
Care must be taken that no bending loads are applied to the insulators during attachment of the
hardware. The grounded end hardware should allow the insulator to swing freely in all
directions. Figure 8-30 shows an example where the grounded end fitting cannot move freely
resulting in the insulator being bent.
Torquing Polymer Insulators
During stringing it is also important that the long rod insulators are not subjected to torsional
loads. If the insulator needs to be twisted ensure that this is done when no mechanical load is
applied (i.e., the tension must be taken up by the block and tackle). This will ensure that no
torsional forces are applied to the end fitting. Figure 8-31 shows an insulator (under load) being
twisted.
Final Visual Inspection
Once installed, the polymer including the hardware should be given one final visual inspection.
The installation should be inspected for the following:
•
•
•
Signs of damage to the polymer i.e., sheath, sheds etc. This includes signs of torsional
loading.
Signs of deflection or bending of the insulator.
Incorrectly applied insulators or hardware i.e., corona rings.
Procedures
The previous sections dealt with criteria and actions to avoid damage to polymer insulators. The
aim of this section is to provide the user with a short list of procedures (without definitions) that
can be implemented at a utility. Depending on the nature of the utility and the situation some or
all of the procedures may be applicable.
It is recognized that a number of possible procedures and practices mentioned may already be in
place, either formally or informally.
Warehouse Procedures
Procedures may be put in place to:
1. Ensure that the polymers delivered are of the correct specification and all the appropriate
hardware is included.
2. The contents of any crates received that are severely damaged should be inspected in detail.
Any damaged polymers should be tagged, set aside and quarantined.
3. That the crates or cardboard boxes are stored in the appropriate environment and in the
correct manner, e.g., cardboard boxes are not stacked upon one another or stored outdoors.
4. Polymers removed from the crates should be stored in an appropriate manner.
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Figure 8-28
Climbing on the end fitting or grading ring.
Figure 8-29
Insulator used for an anchor point.
Figure 8-30
Ground end fitting has locked causing the
insulator to bend.
Figure 8-31
Dead end insulator being twisted to fit jumper
(incorrect method).
Tagging and Quarantine Procedure
Procedures may be put in place to deal with damaged or defective polymers. These include:
1. Methods of tagging damaged or suspect polymers should be put in place and a location to
store tagged units should be identified. The tagging and storage location should be such to
ensure that the unit is not inadvertently used.
2. Qualified personnel need to be identified to inspect tagged units. These inspectors will
identify units that should be disposed of and units that may be returned for use.
3. A disposal procedure that ensures that identified units are not inadvertently used.
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Shipping and Transportation Procedures
Provision needs to be made to ensure that the units are shipped to site without damage. Although
it is preferable to ship units in original packaging, when this is not possible it needs to be ensured
that hardware, tools and other insulators do not damage the units. One method is to use PVC or
builder’s tubes.
On-Site Storage Procedures
Units need to be stored in a correct manner to prevent inadvertent damage and significant
contamination, e.g., lying in mud and dirt.
On-Site Handling Procedures
Units need to be handled correctly to prevent damage in particular when carrying, dragging or
leaning on long units.
Installation Procedures
The following procedures may be put in place:
1. Use of a ground blanket to prevent damage.
2. The installation of hardware such as grading rings prior to the unit being hoisted up the
structure.
3. The inspections of units prior to being hoisted up the structure.
4. The use of a ground line to control the polymer while it is hoisted up the structure.
5. A final inspection once the unit has been installed to check for damage and ensure that it has
been installed correctly. Also, that the polymer is installed in the correct orientation and with
the correct grading ring attached securely.
Training Procedures
It is important that appropriate staff and contractors are trained in the correct shipping, storing
and handling procedures as well as the dos and don’ts of handling polymers [6] [1].
One method of training staff would be to show the EPRI video entitled Storing, Transporting and
Installing Polymer Insulators [5] available at
https://media.epri.com/secure/024056/20140303/S_2.mp4 to the appropriate personnel on a
regular basis. A short presentation and discussion on the issue could also follow.
Personnel that should be trained include:
•
•
•
•
•
Line crews and foremen
Warehouse staff
Operations and design engineers
Contractors that are being used for construction or maintenance
Any personnel that are handling polymer insulators or setting procedures or practices for
their use.
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Other useful sources of information that maybe used to train staff include:
•
•
Guidelines and recommendations provided by manufacturers [2]
CIGRE guide
Live Working
Introduction
In simple terms, live work is any activity that is performed on parts that are energized or can be
energized during work. Both national and international experts are making an effort at this time
to derive a proper definition for this term. The following definitions are most commonly used:
Source: IEEE Std 516-1995, definition 3.43 [8]:
“Live work: Work on or near (e.g., part of tools being used or worker’s body less
than minimum approach distance) energized or potentially energized lines (i.e.,
grounding, live tool work, hot stick work, gloving and barehanding work).”
Source: IEC document 1/1737/FDIS, [9]:
“Live working, live work: activity in which a worker makes contact with energized
live parts or penetrates inside the live working zone with either parts of his or her
body or with tools, equipment or devices being handled (604-04-25 MOD).
Notes:
1. Examples of live working include maintenance, connection and disconnection operations.
2. The live working is performed using specific methods:
- Hot stick working
- Insulating glove working
- Bare hand working”
Live working is a work method that has been used safely and satisfactorily by many EPRImember utilities. Working on live (energized) lines avoids costly outages and the associated
revenue loss and results in improved system availability and stability.
Successful live working procedures and tools have been developed and proven over the years for
safe use on lines with porcelain and glass (ceramic, in general) insulators. The introduction of
non-ceramic insulators (polymer insulators) in the last few decades, and the concurrent decline in
the supply of ceramic insulators, has opened many new questions with regard to safety during
live work in the presence of polymer insulators, the proper live working procedures, and the use
of traditional tools originally developed for ceramic units. Preliminary test results obtained at the
EPRI High Voltage Laboratory and at other centers worldwide indicate [10] [11] [12] [13] that
short-term electrical performance (i.e., for purposes of live working) of polymer insulators is
significantly different from that of traditional ceramic units. For example, the voltage distribution
along a polymer insulator is not the same as that along a string of cap-and-pin ceramic units
because in the latter the voltage distribution is controlled by the intermediate electrically floating
electrodes (the cap/pin combinations). The voltage distribution in the presence of tools and other
electrically floating objects is also different for the two types of insulators for the same reason.
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Predicting and estimating the condition of polymer insulator units have proven to be much more
difficult than for the ceramic units. While ceramic units may degrade slowly over time,
eventually losing their insulating capabilities, this is not necessarily a major concern with regard
to live working. However, to ensure safety when performing live work near polymer insulators,
it is necessary to confirm that the polymer insulators maintain functionality during the relatively
short time span of live work. This begins at the moment work is initiated and ends at the moment
the workers depart upon completion of their task. The typical time span under consideration for
live working purposes is about 4 hours (1/2 of a typical work shift). This concern drove EPRI to
develop an instrument for testing both the external and internal integrity of polymer insulators
[33] [34]. This device was subsequently licensed to Hubbell who have been producing and
selling commercial versions of the device named the Hubbell Polymer Insulator Tester (HPIT).
While the HPIT has been shown to be effective in the identification of both internal and external
defects, there was no mechanism available for identifying the degree of damage necessary to
cause insulator failure. To address this, EPRI performed testing to provide a technical basis for
an application guide [35] [36], which specifies the minimum length of undamaged (or healthy)
polymer insulator required to ensure that the worksite withstand voltage (Vws) remains above the
maximum anticipated worksite overvoltage (Vstress) during the performance of live work.
Tools originally designed for cap-and-pin type units are often not directly suitable for use on
polymer insulator units. Significant adaptation and re-design of tools as well as re-training of
crews may be needed to facilitate line work and to improve work efficiency on polymer
insulators. For example, the traditional cradles used to support strings of ceramic units are too
wide for suspension polymer insulator units. Due to the lower weight of polymer insulators, the
elaborate rigs and similar elevating and support arrangements used with ceramic units may be
modified and trimmed down. This can result in shorter setup times and may reduce the number
of tools and materials workers must handle. On the other hand, storage, support, handling and
installation procedures for polymer insulators may need to be modified to account for the more
fragile nature of the long, flexible polymer insulator units.
Minimum Approach Distance Concept
The Minimum Approach Distance (MAD) is, in simple terms, the minimum distance that a
qualified worker must maintain from parts at different potential to ensure that the risk of
electrical flashover is within acceptable limits. Violating this distance, i.e., approaching parts
closer than the MAD value, increases the risk of flashover and endangers the worker beyond a
reasonable level. The following definitions of MAD are in greatest use:
•
Source: IEEE Std 516-1995, definitions 3.46 and 3.47 [8]
“3.46 minimum air insulation distance (MAID): The shortest distance in air between
electrical apparatus and/ or a line worker’s body at different potential. This minimum air
insulation distance, with a floating electrode in the gap, is equal to or greater than the sum of
the individual minimum approach distances. This is the electrical component and does not
include any factor for inadvertent movement.”
“3.47 minimum approach distance (MAD): The minimum air insulation distance plus a
modifier for inadvertent movement.”
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•
•
Source: NESC [10]
“minimum approach distance. The closest distance a qualified employee is permitted to
approach either an energized or a grounded object, as applicable for the work method being
used.”
Source: IEC document 1/1737/FDIS, [9]
“minimum approach distance (DA): the minimum distance in air maintained between any
part of the body or a worker, or any conductive tool being directly handled, and any part at
different potentials. This minimum working distance will vary depending upon the chosen
electrical and ergonomic components.”
Although the details and depth of the above definitions vary, the fundamental concept of MAD is
quite simple: One must maintain sufficient distance around one’s body and tools to avoid
flashover. The actual value of MAD includes the so-called “electrical distance,” DU, which
determines the flashover risk, and the ergonomic (or inadvertent movement) distance, DE, which
accounts for body movements, errors in judging distance and other intangible factors.
In usual situations, the risk of flashover is greatest not during normal operation of the power
system but during abnormal conditions such as switching and lightning. Since live work is
normally not performed under inclement weather conditions, lightning is usually not the
determining factor for workers. However, it may be the most important factor as far as tools are
concerned if tools are left at the worksite during inclement weather. For the same reason,
lightning may be an important factor in live work on polymer insulators. This area requires
further detailed study.
The remainder of this section assumes that switching overvoltages are the determining factor for
live work with polymer insulators.
The determination of the required MAD values is performed according to the following general
procedure:
•
•
•
•
•
•
Determine the maximum nominal system voltage (normally 5% to 10% above the rated
value)
Determine the peak phase-to-ground maximum nominal voltage
Determine the switching impulse overvoltage factor likely to occur at the worksite (this value
is based on experience, results of transient studies using the TNA or EMTP, or utility
practices)
Determine the required “electrical distance,” DU, based on the sparkover characteristics of
the worksite (this is typically done by comparing the worksite with setups for which the
sparkover characteristics are known)
Determine the required “ergonomic distance,” DE, based on accepted criteria (the value of
1 ft. is recommended in North America for system voltages above 72.5 kV)
Compute the MAD value, DA, as DA = DU + DE
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Details of this procedure, computational examples, and comparisons of the various methods to
determine DA are contained in references [8] [9] [10] [15] [16] [17] [18] [19] [20].
It should also be noted that individual utilities may have their own procedures for calculating
DA.
Of course, the value of DA determined according to the above procedure needs to account also
for additional worksite- and tool-related factors, including:
•
•
•
•
•
Altitude
Effects of tools
Effects of electrically floating metallic objects and tool end-fittings
Defective insulators
Geometrical details of the electrodes involved (for example, sharp tools), etc.
Some of the computational procedures include these effects explicitly, others use appropriate
adjustment factors after the “basic” value of DA has been determined.
Protective Gaps for Overvoltage Limitation
Often, the physical dimensions or details of a particular structure are such that the required DA
value, based on the normally expected switching overvoltages, is not available. This condition is
particularly acute in the case of compact lines. It should be recalled that one of the purported
advantages of polymer insulators is their promised ability to facilitate line compaction.
In cases where the required DA values are not available, three fundamental options exist:
•
•
•
Perform the required work, such as replacement of the polymer insulators, with the line
de-energized
Use alternate live working methods (i.e., hotsticking instead of barehanding) that may be less
efficient (hotsticking is often slower and more cumbersome than barehanding)
Provide means for control and reduction of the overvoltages expected at the worksite
The last option is feasible when one recognizes that the value of DA (actually, of DU) is strongly
determined by the expected switching overvoltage factor. In other words, if the overvoltage per
unit (pu) factor can be reduced from, say, 3 pu to 2.4 pu for a 345 kV line, the value of DU is
reduced from 2.38 m (7.48 ft.) to 1.53 m (5.34 ft.) [8]. This reduction in the pu factor is
achievable by “blocking reclosure,” i.e., preventing the breaker from re-closing in the event of a
breaker-open signal during live work.
Further reduction of the pu factor can be achieved with the use of portable protective air gaps
(PPAG). Such devices have been in use since the 1970’s on 500 kV systems in some parts of the
country. The 550 kV PPAG essentially consists of a fiberglass stick with two 6-ft. metal rods
mounted on it. One metal rod serves as the high voltage electrode, the other as the ground
electrode, i.e., the PPAG is connected phase-to-ground, see Figure 8-32. The air distance
between the tips of the rods is 41 inches for the 500 kV gap. Although this device is not listed in
all manufacturers’ catalogues, it can be ordered from at least one manufacturer [21].
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Figure 8-32
Workers installing a PPAG on a 500 kV structure.
The PPAG functions as a spark gap. It sparks over when the phase-to-ground voltage across it
reaches a pre-determined value that is related to the air gap between the rods. The device is
usually connected on the phase on which work is performed and is located on the structure
adjacent to the worksite. Experience and tests show that the sparkover performance of the PPAG
can be influenced significantly by the structure itself and other details of the location at which it
is connected [22] [23]. The simplest PPAG does not include provisions for limiting the powerfrequency follow-on current that results in case of PPAG operation, but recent work [24] [25] has
led to further development to remedy this disadvantage.
The 500 kV PPAG has been used by several utilities on the East Coast of the USA for more than
30 years. More recently, interest in the use of 500 kV PPAGs has increased in other areas of the
USA.
Gaps for other system voltage levels, and gaps with other electrode designs have also been tested
in the past, but these have not gained wide-spread use for a variety of reasons [16] [26] [27] [28]
[29].
The advantages of the PPAG have been demonstrated recently in several specific situations
involving compact lines [13] [22] [23] [31]. A detailed study of this device in relation to polymer
insulators is needed in order to develop general guidelines for the use and specification of the
suitable PPAG.
Changeout of Porcelain or Glass to Polymer Insulators
A major use of polymer insulators is for the replacement of ceramic insulators. Several issues
need to be considered when replacing an existing ceramic string with new polymer insulators
using live working procedures [32]:
•
•
•
•
Electrical and mechanical integrity of the installed ceramic string
Electrical and mechanical integrity of the replacement polymer insulators
Appropriate live working procedures for work with polymer insulators
Use of live working tools
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•
•
•
Connection lengths of replacement polymer insulators versus the replaced ceramic string
Handling of polymer insulators by work crews prior to installation
Care of polymer insulators during installation
These issues are explored in detail in [32]. The highlights and conclusions of this research are
summarized below.
Electrical and Mechanical Integrity of the Installed Ceramic String
The electrical and mechanical integrity of the installed ceramic string is not a new issue, and it
has invariably been addressed and resolved by utilities that have live working experience.
However, it is recommended that the procedures established both for assessing the integrity of
the ceramic string and for its removal be reviewed and followed to the fullest extent. That is, the
fact that the goal of the work is to install new polymer insulator units should not overshadow the
equally important fact that the first step involves the more traditional task of removing the
existing ceramic string.
Electrical and Mechanical Integrity of the Replacement Polymer Insulators
At this time, there are no generally established procedures for confirming the electrical and
mechanical integrity of the replacement polymer insulators at the worksite just prior installation.
In addition, laboratory tests can be performed on polymer insulators that are targeted for
installation before they are delivered to the worksite. However, this in itself does not assure the
worker that the validity of such laboratory tests extends outside the laboratory confines and still
holds during live work that may be performed many days after laboratory tests. While the
engineering community may feel that this apparent “lack of trust” is unwarranted, one only needs
to remember that it is the worker—not the engineer—who is exposed to the risks associated with
live work. Hence, the proper approach would be to approach the issues of electrical and
mechanical integrity of new polymer insulators from the worker’s viewpoint and to address these
concerns directly the best way possible, instead of relying on tests that have not been witnessed
by the work crews.
With the above objective in mind, several utilities have developed distinct procedures that
attempt to confirm the electrical and mechanical integrity of polymer insulators at the worksite:
•
•
To achieve a degree of confirmation of electrical integrity, the normally grounded end of the
polymer insulator may be attached to the structure while the normally energized end is placed
on the energized conductor, using hotsticks rated for full system voltage. The polymer
insulator is left energized in this manner for several minutes (typically between 3 and
10 min.). Work continues if the polymer insulator does not flash over.
To achieve a degree of confirmation of mechanical integrity, the polymer insulator is
installed as prescribed, and the strain sticks are loosened to allow the polymer insulator to
support mechanical load, but the sticks are not removed. The polymer insulator is left under
mechanical load for several minutes (typically between 3 and 10 min.) with the sticks still in
place. The sticks are removed if no mechanical damage to the polymer insulator is observed.
While these extra steps take time to conduct and are not fully equivalent to rigorous tests, they
are about the only tests that can be suggested at this time, and they usually serve to alleviate
concerns of the work crews.
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As mentioned earlier, no general practices or standardized methods have been developed by
utilities or standardization bodies (IEEE, NESC, OSHA, IEC, etc.). This is an area that requires
further activity.
Appropriate Live Working Procedures for Work with Polymer Insulators
Topics of concern in this area include:
•
•
•
•
•
Minimum approach distance appropriate for live work with polymer insulators
Effects of defective polymer insulators on live working
Effects of electrically floating objects on flashover performance of polymer insulators during
live working
Effects of tools on flashover performance of polymer insulators during live working
Effects of polymer insulator contamination on live working
Although available standards and guidelines do not cover live work with polymer insulators, it
appears at the present time that experience with and procedures developed for live work with
ceramic insulators are fully applicable to polymer insulators. Some further work may be needed
to codify this position in regulations and standards.
Use of Live Working Tools
The obvious question of whether traditional tools used with ceramic units are fully applicable for
use with polymer insulators, i.e., whether a crew would need to carry two sets of tools, one for
ceramic units and the other for polymer insulators, is explored in detail in [32].
Based on research reported in [32], the following general conclusions are derived:
•
•
•
•
Since polymer insulators are lighter than ceramic strings, some tools (such as cradles) may
not be needed. Also, lifting arrangements that are essential for ceramic strings are often not
needed for polymer insulators. Figure 8-33 shows a polymer insulator being lifted without a
cradle.
Special precautions may be needed for working with polymer insulators that are equipped
with large grading rings. Typically, the rings are too large to fit comfortably in a cradle. If
forced, the entire polymer insulator may be bend (see Figure 8-34), and the metal rings may
score the cradle sticks. Hence, use of cradles should be reconsidered or eliminated altogether
when working with polymer insulators.
Some other tools that are traditionally used with porcelain strings, such as insulator forks, are
not needed for polymer insulators.
Care must be taken when selecting strain sticks and some other tools. Often the connection
length of the replacement polymer insulator is significantly different from that of the ceramic
string it replaces (see Figure 8-35). Consequently, the strain sticks must be of appropriate
length and adjustment capability to handle both the ceramic string and the replacement
polymer insulator. If not, a very difficult situation may arise wherein the strain sticks may be
too short or too long for installation of the replacement polymer insulator. This difficulty can
often be remedied by installing links of appropriate lengths to compensate for dissimilar
connection lengths. However, this must be recognized before work begins, and proper
detailed instructions must be provided to work crews.
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•
•
Care must be taken when working with sharp tools such as cotter key pullers and pliers to
avoid mechanical damage to the polymer insulator (see Figure 8-36). This is normally not
a concern for ceramic units. Hence, proper training of crews is required.
The use of grading rings on polymer insulator units may cause mechanical interference
with other hardware and make access to end hardware such as cotter keys difficult (see
Figure 8-37). Tools and ring attachment hardware must be designed to allow access to all
essential areas.
Figure 8-33
Lifting a polymer insulator without a cradle.
Figure 8-34
Because the grading ring does not fit in the cradle, the polymer insulator is flexed.
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Figure 8-35
Problems of dissimilar connection lengths: The polymer insulator is longer than the strain sticks
used for the ceramic string.
Figure 8-36
Danger of damage to polymer insulator by sharp tools.
Figure 8-37
Possible mechanical interference caused by the grading ring and difficulty of access with tools.
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Connection Lengths of Replacement Polymer Insulator Versus the Replaced Ceramic
String
This issue is closely linked to the selection and use of tools such as strain sticks and has been
discussed in the previous paragraphs. It is mentioned here again as a separate item due to its
great importance. The issue becomes even more important for compact lines and is discussed in
more detail under that topic.
Handling of Polymer Insulator by Work Crews Prior to Installation
The polymer insulator should not be bent or flexed. Normally, manufacturers recommend that
long polymer insulator units should not be lifted from a horizontal position by one end. These
precautions need to be recognized when removing polymer insulators from the delivery truck
and the shipping container and when lifting polymer insulators to the crossarm, especially when
not using a cradle.
Care of Polymer Insulator During Installation
The polymer insulator should not be bent or flexed and should not be allowed to come into hard
contact with or bang against structure members.
Care should be taken when using sharp tools to avoid damage, see Figure 8-36.
As shown in Figure 8-37, two approaches may be taken when there is a possibility that the
grading ring may interfere with the proper use of tools (mechanical interference).
•
•
The polymer insulator may be installed with the ring in place if appropriate tools are used to
overcome the possibility of mechanical interference.
The polymer insulator may be installed first without the grading ring. The ring would then be
mounted on the installed polymer insulator in a separate operation.
The first option is, obviously, easier and faster, provided appropriate tools are used. The second
option is more time-consuming since it involves two separate steps, and it is more difficult
because installation of the ring and bolts must be accomplished with a hotstick, or by hand if
barehanding, and the bolts need to be tightened. Normally, installation of the polymer insulator
with the ring pre-mounted is preferred and usually possible, but it is worthwhile to review this
step prior to commencement of work.
Whether the ring is installed with the polymer insulator or separately, the ring is an electrically
floating electrode before the polymer insulator is pinned into the yoke plate or the conductor
shoe. The presence of electrically floating electrodes can decrease the dielectric strength of the
worksite significantly (by 10% or more, depending on worksite details). Switching impulse tests
have shown [32] that while this decrease is observable, it usually is not of great significance
during live work since invariably breaker reclosure blocking is enforced for the duration of live
work. However, it is advisable to review this detail prior to commencement of work, especially
for work on compact lines.
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Changeout of Polymer Insulator and Replacement with Polymer Insulator
This process consists of two distinct parts:
•
•
Removal of the existing polymer insulator that has a certain service history
Installation of a new polymer insulator
The second part is normally not different from procedure discussed in the previous subsection. It
should be noted, however, that connection length problems might occur if the replacement
polymer insulator is not identical to the original unit.
The first part introduces the issue of confirmation of the electrical and mechanical integrity of
the existing polymer insulator. EPRI has developed a tool that can detect conductive defects that
would compromise electrical integrity. See introduction to this section. However, the combined
probability is very low that a flashover would occur at the exact time a worker would be in a
position to be affected by it unless the polymer insulator is latently defective. Similarly, the
combined probability is very low that a mechanical failure (such as catastrophic brittle fracture)
would occur at the exact time a worker would be in a position to be affected by the failure. At the
same time, although these considerations are technically convincing, they do not provide the
assurance needed to convince work crews, whose very well-being is at stake, that all steps have
been taken to provide a safe working environment. In other words, nothing short of a valid test
will suffice to assure safety during live work with polymer insulators.
No further quantitative information is available on this issue. It might be prudent to conduct
some selected tests and research to assess quantitatively what kind of damage could be inflicted
should one or the other type of failure take place with workers at the worksite.
Considerations for Compact Configurations
One of the purported advantages of using polymer insulators is the possibility of achieving a
degree of compaction of the line. Research [32] has pointed out several new issues that are
specifically related to the use of polymer insulators on compact lines. These issues include:
•
•
•
•
•
•
•
Length of strain sticks versus “rating”
Length of cradle sticks versus “rating” (if used)
Mechanical interference, access, tools
Switching overvoltage factors
Approach distances
Worksite access
Ergonomics
Length of Tools
This issue was discussed in conjunction with the connection length issue of ceramic strings
versus polymer insulators [32] and is explored here in greater detail.
Table 8-1 summarizes the required [8] [10] [15] [21] Minimum Approach Distance (MAD)
values (based on a 3 p.u. transient overvoltage factor) and the lengths of recommended tools [21]
for three systems voltage levels (115/138 kV, 230 kV and 345 kV) as examples. The typical
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connection lengths of ceramic strings and polymer insulators are also included. The MAD values
and the tools lengths are taken from [21], which is the common reference available to work
crews. Although deviations from these recommendations are possible if they are properly
justified in engineering terms, it must be recognized that the work crews need to be fully aware
of the changes, must understand them, must “buy into them,” and must be convinced that tools
other than those recommended in [21], or an equivalent source available to them, are in fact
appropriate and safe.
Table 8-1
MAD values, recommended tools and connection lengths.
System Voltage
(kVph-ph)
MAD
(ft/m)
Strain
Stick
Length
(ft/m)
Cradle
Stick
Length
(ft/m)
Connection
Length Ceramic
String (ft/m)
Connection
Length Polymer
Insulator (ft/m)
345 (V, 16 units)
8.5/2.59
13.2/4.02
9/2.74
7.98/2.43
8.04/2.45
230 (I, 13 units)
5.25/1.59
9.9/3.02
–
6.23/1.9
6.48/1.97
115/138 (I, 9 units)
3.6/1.09
8.7/2.64
–
4.31/1.31
4.58/1.4
Analysis of Table 8-1 clearly leads to the following observations:
•
•
•
•
The required MAD values are smaller than the ceramic string connection lengths, except for
the case of 16 units on the 345 kV system. This is due to line compaction (no links). Hence,
transient overvoltage control needs to be employed when working on 16-unit ceramic strings.
The required MAD values are smaller than the polymer insulator connection lengths for the
230 and 115/138 kV cases, but they are not smaller than the polymer insulator connection
lengths for the 345 kV cases. This is due to line compaction (no links). Hence, transient
overvoltage control needs to be employed when installing polymer insulators on the 345 kV
system.
The lengths of the recommended adjustable strain stick are greater in all cases than the
insulator connection lengths. This has been found to be a problem in the case of the 345 kV
V-string and sticks that are shorter than recommended have to be used. This is due to line
compaction (no links). For the I-string, no problems were found since the yoke plate was
placed on top of the crossarm. However, there may be situations where sticks shorter than
recommended may need to be used. If shorter sticks must be used, transient overvoltage
control needs to be employed.
The lengths of the recommended cradle sticks are greater than the insulator connection
lengths for the 345 kV system. This is due to line compaction (no links). Figure 8-38 shows
the problem. Cradles are not needed for I-strings. If shorter cradle sticks must be used,
transient overvoltage control needs to be employed.
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Figure 8-38
Close-up photograph showing that the recommended 11-ft. 4-in. cradle sticks are too long.
Mechanical Interference
An example of mechanical interference between sticks and structure components was given
above, see Figure 8-37. These problems arise due to the compact nature of the structure and the
lack of extension links. Shorter tools need to be used, and this may require the use of transient
overvoltage control.
References
[1]
Handling of Composite Insulators in Distribution Projects, Eskom Guide, Draft 1,
August 2000.
[2]
Handling guides from manufacturers, NGK, Ohio Brass, Reliable & Sediver.
[3]
EPRI Guide to Visual Inspection of NCI. EPRI, Palo Alto, CA: 2008. 1000098.
[4]
EPRI Application Guide for NCI. EPRI, Palo Alto, CA: 2008. TR-111566.
[5]
EPRI Storing Transporting and Installing Polymer Insulators Educational Video. EPRI,
Palo Alto, CA: 2008. 1006353.
[6]
EPRI Storing Transporting and Installing Polymer Insulators Viewing Guide for
Educational Video. EPRI, Palo Alto, CA: 6467.
[7]
EPRI Electric Field modeling of NCI and Grading Ring Design and Application. EPRI,
Palo Alto, CA: 2008. TR-113977.
[8]
IEEE Std 516-1995, “IEEE Guide for Maintenance Methods on Energized Power Lines.”
[9]
IEC document 1/1737/FCDIS, 1998-08-07, under circulation for vote.
[10]
IEEE Standard C2-1997, National Electrical Safety Code (NESC).
[11]
Live Working on PSE&G 138 kV Double-Circuit Steel Lattice Tower. EPRI, Palo Alto,
CA: May 1997. TR-108329.
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[12]
G. Gela, H. Kientz, H. M. Fox, J. D. Mitchell, P. F. Lyons, “Live Working with NonCeramic Insulators,” CIGRÉ SC33 International Colloquium, paper 33-1B.2, Toronto,
Canada, September 2–3, 1997.
[13]
Energized Work on Idaho Power Company’s Existing 345 kV Structures, EPRI Final
Report TR-108968, November 1997.
[14]
EPRI Non-Ceramic Insulator Workshop, Lenox, MA, October 28–29, 1996.
[15]
OSHA 29 CFR Part 1990, “Electric Power Generation, Transmission, and Distribution;
Electrical Protective Equipment; Final Rule,” Federal Register, Part II, Monday,
January 31, 1994.
[16]
Esmeralod, Dias, Fonseca, “Calculation of Minimum Safety Distances for Live Line
maintenance, A Statistical Method Applied to 765 kV AC Itaipu Lines (Brazil),” IEEE
Transactions on Power Delivery, Vol. PWRD-1, No. 2, April 1986, pp. 264–271.
[17]
H. J. Kientz, “Tutorial for the Derivation of Live-Line Minimum Approach Distances for
the 1993 Edition of the National Electrical Safety Code,” Proceedings from ESMO-93,
Las Vegas, Nevada, September 12–17, 1993, pp. 5–35.
[18]
G. Gela, P. W. Hotte, M. Charest, “IEC Method of Calculation of Minimum Approach
Distances for Live Working,” IEEE paper 9844 T ESMO-17, awaiting printing in IEEE
Transactions on Power Delivery.
[19]
G. Gela, P. W. Hotte, M. Charest, “Analysis of the IEC Method of Calculation of
Minimum Approach Distances for Live Working,” Presented at the ICoLIM98
Conference, Lisbon, 16–18 September 1998.
[20]
CIGRÉ SC33.07 guide, “Guidelines for Insulation Coordination in Live Working,” under
development. “Electrical Performance of Portable Protective Gap (PPG) in a Compact
550 kV Tower,” EPRI Final Report TR-103860, November 1994.
[21]
Hubble Chance Company, Tool Catalog, T95.
[22]
Electrical Performance of Portable Protective Gap (PPG) in a Compact 550 kV Tower,
EPRI Final Report TR-103860, November 1994.
[23]
G. Gela, A. Lux, H. Kientz, D. A. Gillies, J. D. Mitchell, P. F. Lyons, “Application of
Portable Protective Gaps for Live Work on Compact 550 kV Transmission Lines,” IEEE
Transactions on Power Delivery, Vol. 11, No. 3, July 1996, pp. 1419–1429.
[24]
E.I. Udod, V. N. Moltchanov, V. L. Taloverya, B. A. Brjesitsky, G. Gela, “Device for
Overvoltage Control in Live Line Working,” paper IEEE 9845 C ESMO-19, Proceedings
from the ESMO98 Conference, pp. 246–252.
[25]
V.N. Moltchanov, V.L. Taloverya, B. A. Brzezickiy, G. Gela, “Live-Line Device
Enhances Worker Safety,” Transmission & Distribution World magazine, August 1998,
pp. 61–62.
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[26]
Ohio Brass and Keystone Electrical Advisory Task Force, “Electrical Tests Relative to
the Live Line Maintenance of Keystone 500 kV Transmission Lines,” internal report,
January 1971.
[27]
J. Reichmann, “Safety Aspects of Live Line Work Methods,” IEEE Transactions on
Power Apparatus and Systems, Vol PAS-100, No. 7, July 1981, pp. 48–49.
[28]
I. Barg, O. Pisarenko, S. Polevoy, “Studies of Safety Gaps for 220-1150 kV Live Line
Work,” Proceedings from the ESMO90 Conference, Toronto, Canada, June 19–21, 1990,
pp. 25–26.
[29]
Hu Dingchao, “A Method of Replacing 220 kV Low- Ohmage Insulator String in Live
Line,” Proceedings from the ESMO90 Conference, Toronto, Canada, June 19–21, 1990,
pp. 114–116.
[30]
K.J. Sadurski, “Safety Aspects and Insulation Co-ordination During Live-Line
Maintenance,” Proceedings from the ESMO90 Conference, Toronto, Canada, June 9–21,
1990, pp. 127–130.
[31]
G. Gela, H. Kientz, H.J. Fox, J.D. Mitchell, P.F. Lyons, “Defective Insulators in Live
Working on a 550 kV Compact Steel Lattice Tower,” IEEE Transactions on Power
Delivery, Vol. 12, No. 2, April 1997, pp. 783–790.
[32]
Evaluation of the Performance on Non-Ceramic Insulators for Live Working
Applications: Replacing Ceramic Insulators with NCI, EPRI Interim Report. EPRI, Palo
Alto, CA: April 1998.
[33]
EPRI. 2003. Development of Field Test Equipment for Live Working with Polymer (NCI)
Insulators: Preliminary Study. EPRI, Palo Alto, CA: 2003. 1002029.
[34]
EPRI. 2004. Electrical Condition Assessment of Polymer Insulators for Live Working:
Development of a Simple Portable Tester. EPRI, Palo Alto, CA: 2004. 1002030.
[35]
EPRI. 2019. Critical Defects in Composite Insulators, Testing of Overhead Transmission
Line Structures – Final Report. EPRI, Palo Alto, CA: Dec. 2019. 3002015620.
[36]
EPRI. 2020. Non-Ceramic Insulator (NCI) Live Working Application Guide. EPRI, Palo
Alto, CA: November of 2020. 3002019069.
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9
IMPACT OF BIRDS ON INSULATOR PERFORMANCE
Introduction
Birds may affect the performance of overhead lines to a much greater extent than previously
thought. In the USA it is estimated that 25% of all outages on distribution lines can be ascribed
to bird activity. In other countries such as South Africa, Germany and Portugal as much as 35%
of line outages have been ascribed to birds [1] [10] [11]. These detrimentally affect power
system reliability with associated costs running in millions of dollars every year.
Birds often utilize transmission line and substation structures, Because of their height, for
hunting, nesting and roosting. Their presence and activity around transmission structures may
cause flashovers, resulting in power outages, in several different ways [1] [2] [3] [4] [6]:
•
•
•
•
A bird may bridge the insulation gap resulting in a flashover and the electrocution of the bird
(Figure 9-1 left).
The insulation gap may be bridged by conducting nesting material (Figure 9-1 center).
Bird excrement, which may contain high levels of salt, may contaminate the insulator
surfaces leading to classical contamination flashovers during wet conditions (Figure 9-1
right).
The air gap in the tower may be bridged by excrement (i.e., so-called bird streamer
flashover).
A bird bridging the gap,
courtesy of Eskom
Nest material bridging the gap
Figure 9-1
Bird related flashovers on transmission lines.
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Contamination on the insulators
The impact of birds is not only limited to flashovers. Other bird related problems are:
•
•
•
Damage to composite insulators (Figure 9-2 – left)
Damage to wood poles (Figure 9-2 – right)
Corrosion of supporting structures due to the presence of digestive acids in the excrement of
some bird species.
Damage to polymer insulators
Woodpecker damage in a
wood pole
Figure 9-2
Bird related damages on transmission insulators and structures.
In literature there is very little consolidated information published on bird related outages,
mitigation techniques and their effectiveness. The basic objectives of this chapter are therefore
to:
•
•
Discuss general issues of bird related contamination outages in order to create awareness of
this problem.
Recommend methods and procedures that have proven successful in mitigating bird related
contamination outages.
Bird Contacts
On distribution lines, or compact transmission lines, birds may bridge the any of the clearances
around the phase conductors leading to flashover and, in most cases, the electrocution of the bird.
Bird contacts are avoided by designing bird friendly structures with sufficient clearance around
energized objects and with a configuration that discourages the birds from perching in critical
areas.
In substations, bird contacts are possible in tight places where the energized equipment is close
to grounded surfaces. Especially small birds like starlings and sparrows, are at risk since they
build their nests in any small openings that are available. Their presence may attract larger
predators, typically raccoons, cats or snakes, which may be large enough to bridge insulation
distances when climbing through the station equipment looking for eggs or young in nests.
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Animal caused outages is the third leading cause of all power outages in the U.S. [1] [2] [3]. A
1990 IEEE survey reported that 86% of the responding utilities have indicated that birds caused
major problems in substations, second only to squirrels (90%) [7].
Figure 9-3
Example of a snake causing an outage. The snake was probably out to catch a bird.
Nesting Material Contact
Nests or nest building activities do not necessarily cause outages, as is evident from the many
nests on transmission lines without resulting in many outages. However, the nesting material of
certain bird species, such as ravens and golden eagles, may include conducting material that
could cause an outage when bridging the insulation gap.
Wet nesting material may also result in flashovers if deteriorated nests collapse and bridge the
gap during heavy rainstorms.
Figure 9-4
Examples of stork nests on overhead lines in Portugal.
Soiling of Insulators
The accumulation of excrement on insulator surfaces may result contamination outages in
substations and on transmission and distribution lines. The resulting surface contamination layer
is highly conductive and is not easy to clean by ordinary washing, especially after it becomes dry
and baked onto the insulation surfaces. The highly conductive and sticky (wetness) nature of bird
excrement on insulators reduces the surface resistance to such an extent that the nominal line
voltage easily establishes an arc across the insulators. Both large and small birds can cause such
outages. Figure 9-5 show two examples of insulators covered in bird excrement.
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Insulator contamination may pose a threat to the reliability of the system since a contamination
flashover is frequently followed by additional flashovers of the same insulator within a short
time. This may make it necessary to de-energize the line until the insulator surfaces dry out, and
their insulator strength is restored. It should however be noted that the possibility of flashover
remains, unless the surface is cleaned by either natural or artificial means. Consequently, power
systems experiencing bird related contamination flashovers are likely to have repeated outages.
Figure 9-5
Bird excrement on a post (left) and disc (right) insulator.
Roosts can include several thousands of birds. Starlings and blackbirds, for example roost in very
large numbers. Fecal material from roosts has been linked with contamination caused outages.
For example:
•
•
The post insulator shown in the left-hand photograph in Figure 9-5 was taken from a 69 kV
line, which were contaminated by thousands of small birds (see Figure 9-6). An ornithologist
identified the birds as mostly starlings and some pigeons and doves. It was established that
these birds were attracted by good source of food located close to the line [8]. The
contamination on the insulators accumulated over a period of several months, eventually
leading to a series of flashovers on an early January morning when there was unusually
heavy fog at the line location. ESDD/NSDD measurements performed after the outage
revealed a contamination level on the insulators that corresponded to a “heavy” classification
(ESDD = 0.4 mg/cm2, and NSDD = 0.002 mg/cm2).
Brunswick substation that feeds Carson City, the State Capitol of Nevada, experienced
outages after a large flock (thousands in number) of blackbirds or starlings came to roost
overnight in the substation. The overnight accumulation of bird excrement on insulators was
sufficient to cause an outage.
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Figure 9-6
A large roost of starlings on an overhead line.
Individual birds can also create serious problems in substations if they use structures for nesting.
The accumulation of fecal material on and around the nests may create a conductive path from
the energized conductors to ground when there is a rainstorm after a lengthy dry period. Not only
is the risk for an outage quite high, but also the heat generated by leakage current and discharges
may alight nest material. The resulting fire may spread to the supporting poles or connected
equipment. Examples are shown in Figure 9-7.
Charred wood structure associated with a red-tailed
hawk nest.
Pole Fire due to Contamination Caused
by Raven Nest During Light Rain
Figure 9-7
Examples of pole top fires associated with bird nesting activity.
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Bird Streamers
Probably the largest cause of bird related outages are related to the so-called bird steamer
phenomenon. When large birds such as raptors, vultures, herons and cranes, use transmission
line structures as a perch or hunting platform (as shown in Figure 9-8) they may release a long
continuous stream of excrement into the insulation gap of the tower. The “streamer” may bridge
enough of the gap to cause flashover under steady-state ac conditions. Bird streamer problems
have been known for a long time and have been identified as a major cause of line outages in the
U.S. [8], Europe [12], [11], [10] and Africa [9].
Figure 9-8
Vultures on a 275 kV line. Note the bird diverter that prevents the birds from perching in critical
area directly above the center phase.
Bird streamer flashovers have been reported on nearly all voltage levels. The length of the
streamers is typically the order of 1–2.5 m, which is sufficiently long to completely bridge the
insulation clearances on 145 kV systems. Complete bridging of the gap is however not a
prerequisite for flashover. It has been argued that streamers as short as 1 m could result in
flashover on 420 kV insulators [11].
The frequency of bird streamer outages is related to the size of the air clearances (between phase
and ground) in the tower. It is therefore possible that an increased line outage rate is experienced
after a line is reinsulated with composite insulators, which generally have a shorter arcing
distance for the same section length. The presence of larger corona rings on the composite units
may also result in a shorter strike distance to the tower on replacement units [8].
Damages Caused by Birds
Utilities in Australia, United States, Germany and South Africa have found that birds like to peck
at the weathershed material of composite insulators, in some cases inflicting severe damage as
shown in Figure 9-9. Although damage is more prevalent prior to energization, damage to
energized units has also been reported. Damage to the insulator units does not lead directly to
outages but it may impact the long term and ageing performance of the insulators.
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Figure 9-9
Damage inflicted on composite insulators by birds.
Birds may also cause damage to the supporting structures as stated in the introduction but its
discussion falls outside the scope of this chapter.
Characteristics of Bird Related Outages
The presence of birds and the accumulation of their droppings on insulators depend on the
terrain, availability of food, water, wetlands, and farmlands. In treeless areas, such as the desert
southwest, overhead lines are their only choice of perching, nesting and roosting sites. There are
a wide variety of birds that cause nesting, perching, and staging contamination outages. The
more common birds associated with these outages are ravens, buzzards, hawks, owls, ospreys,
eagles, herons, vultures, ibises, cranes, starlings, doves, blackbirds and pigeons.
Both small and large birds can cause outages. Small birds, such as starlings, blackbirds, and
doves have caused major insulator contamination outages in the Western states (Arizona,
California, and Nevada). The characteristics of these small birds are as follows [1]:
•
•
•
Starlings are clever, successful, abundant, and are found throughout the country. Their
success, like rats and mice, is due to their ability to adapt to a variety of climates and make
use of a variety of food sources. Feeding in flocks during the day, starlings will assemble in
huge roosts at night. During late afternoon, small groups of starlings will assemble and start
calling. Each group will join a nearby group, until a flock of thousands has formed. Starlings,
like pigeons, can be a major nuisance in urban environments.
Doves use substations as roosting sites. Additionally, they will perch by the hundreds on
distribution overhead lines and cause contamination outages.
Blackbirds flock and roost in large numbers. They often join starlings.
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Large birds, such as eagles, hawks, herons, vultures and ospreys cause streamer outages as well
as nesting outages. Vultures, unlike most raptors, will form large roosts [1] [2] [3]. In some
areas, vultures will frequently take advantage of the numerous perching sites on transmission
structures. Although the energized conductors are far enough apart to prevent wingtip contacts,
the roosting vultures cause extensive contamination of the insulators with their droppings,
causing eventual flashovers. Ospreys and blue herons, and to a lesser extent, eagles and hawks,
build very large platform nests on transmission poles and structures.
Bird related outages show distinctive seasonal and diurnal patterns. There is a strong correlation
between bird activity and the rate of outages. More outages occur during evening and early
morning of day when birds arrive or leave their resting places for the night. Seasonal variation
are linked to the nesting/breeding behavior of birds. Different bird species may have different
breeding seasons:
•
•
•
•
Ravens
May–August
Vultures May-August
Ibises, cranes
September-April
Wild buzzards
April-September
Mitigation Techniques-Description, Pros, Cons, and Issues
There are various devices commercially available to reduce the impact of birds on transmission
lines. However, experience has shown that the success of such devices to significantly reduce
bird related outages are not always guaranteed. The main reason for this is that birds easily adapt
to the new circumstances potentially rendering the applied devices useless. Success have
however been booked in situations where the devices have been applied by taking account of
bird behavior and how it can be changed. For this reason, it is advisable to devise mitigation
measures in conjunction with bird behavioral experts.
Another important issue to consider when planning and implementing mitigation measures, is
that there are many bird species that are protected by federal law. Some of these laws not only
protect the birds but also the nests so it is important to take these laws into account when
planning bird control measures.
Preventing Bird Contact Outages
First and foremost, bird contact outages can be prevented by designing pole tops with sufficient
clearance for the birds and other animals that may utilize these structures.
On existing structures, bird guards are used to protect birds from electrocution by preventing
birds from perching in specific hazardous zones on the crossarm. An example of a triangular bird
guard is shown in Figure 9-10. These devices are only effective if other parts of the structure are
still available for perching. An added benefit is that these devices may also alleviate bird
contamination problems to some extent.
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Figure 9-10
A triangular bird guard.
Kaddas insulator/conductor covers are currently being tested for their effectiveness in reducing
electrocution problems. Photographs of a test installation are shown in Figure 9-11. This device
could also be used as an insulator cover to protect the insulators from bird contaminations.
General view of structure
Close-up view
Figure 9-11
Kaddas Insulator/Cover Cover in Trial on 50 Structures in Nevada.
Preventing Bird Streamer Flashovers
The installation of perch preventers to prevent birds from perching on certain critical locations is
an effective means to reduce the number of bird streamer flashovers [4]. Perch preventers
manufactured from either plastic or metallic materials of various designs are available in the
market [1]. One particularly successful homemade design is shown in Figure 9-12 [7]. It consists
of a 2-foot piece of guy wire clamped at one end and unwound at the other end. When installed
on the cross arms, it prevents birds from perching or roosting above the insulators.
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Figure 9-12
Wire type perch preventer.
As with bird guards, perch preventers are only effective if other parts of the structure are still
available to the birds for perching. Perch preventers should therefore only be used to discourage
birds to perch in critical areas on the tower as is illustrated in Figure 9-13.
Figure 9-13
The use of perch preventers to discourage birds to sit in critical areas of the tower.
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Perch preventers can be made of metal or plastic materials. In such a case users must ensure that
the materials used can withstand the environment to which it will be exposed. For example,
plastic perch preventers or spikes should contain UV stabilizers to withstand the sun’s UV rays.
Perch preventers should also be inspected regularly to replace any damaged or deteriorated
devices. Preventers made of plastic materials could become charred and conductive after
flashover or discharge activity, presenting a future flashover potential [5].
Preventing Bird Contamination Flashovers
Bird contamination flashovers are the result of an accumulation of bird excrement on the
insulators over short or long periods. The use of regular insulator cleaning has been found to be
an effective counter measure. However, because these insulators are often hard to clean, this
counter measure can be costly in both time and money. The use of dry cleaning methods utilizing
corncobs, walnut shells and high-pressure washing are proposed for cleaning bird droppings. In
certain situations, however, the accumulation on the insulators may be too fast for regular
insulator cleaning to be effective. In such cases other bird discouragers such as perch preventers
or insulator shields, could be considered.
Installation of insulator shields to protect the insulators and installation of platforms to collect the
bird droppings is another technique effectively used by several utilities [5]. Some shielding
solutions are shown in Figure 9-14.
Polymer insulator shield
Aerodynamic disc
Shielding platform on crossarm
Figure 9-14:
Different kinds of insulator shield that can be used to limit the buildup of bird excrement on
insulators.
A commercially available insulator shield (Figure 9-14 - left) covers the insulators completely
and was found to be effective in protecting the insulators from bird contamination. The same
effect can be obtained by introducing an aerodynamic, or desert profile, disc in the top of the
string (Figure 9-14 - center).
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Fiberglass platforms, plywood platforms, and wooden platforms (Figure 9-14 - right) have also
been used by various utilities to collect the accumulation of the bird excrement. Fiberglass
arms/platforms/dishes were found to be effective protection by more than one utility, but they are
also found to be costly.
Shed extenders are another method to extend the leakage distance of the insulators to reduce
heavy contamination outages caused by birds.
Perch preventers have also been used to discourage birds to sit above insulator strings, thereby
reducing the amount of excrement that lands on the insulators. It was however found that the
perch preventers are not so effective for small birds as against large birds. On their own they
therefore do not offer a complete solution against the soiling of the insulators.
The same solution may not work in all situations, as different bird species and circumstance may
require different approaches to achieve the same end. If the structure has numerous places to
perch, insulator shields may be more effective [5], and in other cases the use both perch
preventers and insulator shields may be required.
Discouraging Nesting In and On Transmission Structures
Regular inspection of substations and prompt removal of bird nests is generally not an efficient
way to solve the nesting problems in substation [1]. Once most birds select a nesting site, they
will attempt to re-build their nests as often as the nests are removed. Some utilities do not
remove nests, but they keep the area cleared of nesting material dropped by the birds and
carefully trim loose material from the outside of the nests. If the birds have successfully built a
nest without causing an outage and the utility chooses not to disturb it, they should install
climbing guards and "snake fences" to keep out raccoons, cats, opossums, and snakes [1]. When
the birds have raised their young and left the substation, the nests can be removed, and the area
screened to prevent nest re-building the next year. It should be noted that the Migratory Bird
Treaty Act protects most birds and their nests, and as such, a permit may be required to remove
their nests. Those permits may be obtained from the U.S. Fish and Wildlife Service [1] [4].
Removing roosting birds in substations is a tedious, time-consuming, and labor-intensive
process. Also the cost of cleaning insulators contaminated with bird droppings is high. It is
therefore attractive to take preventive measures. Since the birds select the substation as a
roosting site due to various reasons, such as safety and comfort, the utility must convince them
otherwise [1]. Regardless of the method, (bird discouragers, perch preventers, pyrotechnics,
noisemakers, lights, or falconry), it may require the presence of a crew daily for a period of
weeks. In addition, it will require frequent follow-up inspections to make sure the birds do not
return. Some measures are:
•
•
In substations, ultrasonic sirens, gel repellents and visual scare devices, such as plastic
hawks, owls, propane guns, bird bombs, flashing lights, rotating disks and cones and rotating
tubes have been shown to be temporarily effective to ineffective as the birds become
accustomed to the devices. The 1990 IEEE Survey reported that out of 56% utilities who
used these only 2% found it to be effective [6].
One Northern Californian utility found that floodlights could be used effectively to prevent
thousands of starlings from roosting in substations. Birds do not like bright light so keeping
the lights on served as an effective deterrent. Based on experience it is suggested that
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•
•
•
high-pressure sodium vapor lamps should be used, and not mercury vapor lamps [1]. It was
found that the bluish light of the mercury vapor lights attract insects, which in turn attract
birds and bats.
Pyrotechnics is another counter measure that could be effective in reducing the roosting of
birds on their transmission structures [1] [5]. This requires the use of a special kind of
firecracker as a way to scare the staging birds. To be effective, this must be done every
evening at least for a week. Further details about this technique can be obtained from the
Animal, Plant Health Inspection Service (APHIS), U.S. Department of Agriculture Animal
Damage Control Unit. Employees need special training in the use of pyrotechnics.
The fine washer gravel used in some substations as ground cover may attract birds. Not
having teeth, birds will swallow fine rocks to help breakdown the tough fibers and grain they
eat. Since birds cause the largest percentage of substation outages, replacing fine washerrefined gravel with large-size gravel could be beneficial.
Weatherproof screening, similar to hardware cloth is an effective barrier when used to cover
openings or cavities in substation structures and equipment where small birds could nest. Use
of flexible weatherproof metal screening, made of copper, is effective in blocking small
insects [1]. This is very effective in substations to cover openings or cavities on structures
and equipment where small birds or insects can nest. It prevents birds and insects from
making a permanent nest. It is easy to install and does not demand extensive maintenance.
Good quality screening compacts tightly and resists being pulled apart by small birds.
Choosing Appropriate Counter Measures
Birds are smart and remarkably successful animals. Virtually no habitat is inaccessible for them.
They are also observant living beings, capable of adapting to the environment. Thus, there is a
major difference in dealing with outages caused by birds compared to outages caused by
lightning, switching surges and air-borne contamination. This aspect has to be kept in mind when
working towards reducing bird related outages. Realistically, there is no practical way to
permanently keep birds out of substations or off transmission structures. Thus, knowledge of bird
behavior and their interactions is essential in understanding the effectiveness of the deterrents. If
a utility is having a chronic problem with birds and the above suggestions do not completely
solve the problem, then the focus should be on protecting the equipment. The following steps can
be used as a guideline to find an appropriate solution to minimize outages due to birds.
1. Knowing the cause is the first step in solving the problem. Find the reason or cause as why
the birds are present and try to eliminate the attraction.
2. Have good outage monitoring and reporting systems and forms that include bird related
outages.
3. Become familiar with the birds in the affected area.
4. Use perch preventers.
5. Provide alternate perch sites.
6. Use insulator shields.
7. Periodically wash and/or clean the insulators in problem areas.
8. Use creepage extenders.
9. Implement an aggressive right-of-way cleaning and a tree-trimming program.
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10. Maintain a regularly scheduled inspection program.
11. For new and modified lines and substations, utilize designs that do not encourage bird use.
Landscaping around substations and other electrical facilities need to be planned carefully.
If there are ornamental fruit and nut bearing trees, flower beds, and shrubs that are providing
food or cover for birds, they need to be replaced with landscaping that will not attract birds
[1]. The substation has to be kept neat and clean, so it will not encourage or attract birds.
References
[1]
[2]
[3]
[4]
[5]
[6]
[7]
[8]
[9]
[10]
[11]
[12]
Animal Caused Outages, Rural Electric Research Project 94-4, 1996, National Rural
Electric Cooperative Association.
S.D. Frazier, “Animals, Power Systems, and Reliability in a Deregulated Environment”,
IEEE T&D Conference, Orlando, FL, Apr 1999.
S.D. Frazier, “Birds, Substations and Transmission”, Panel Session, IEEE Winter Power
Meeting, Columbus, OH, 2001.
R. Sundararajan et. al. (Task Force Paper), “Preventive Measures to Reduce Bird Related
Power Outages, Part I – Electrocution and Collision”, IEEE Trans. On Power Delivery,
Vol. 19, No. 4, October 2004.
R. Sundararajan et. al. (Task Force Paper), “Preventive Measures to Reduce Bird Related
Power Outages, Part II – Steamers and Contamination”, IEEE Trans. On Power Delivery,
Vol. 19, No. 4, October 2004.
Electric Power Research Institute (EPRI), A Joint Utility Investigation of Unexplained
Transmission Line Outages, Report EL-5735, Final Report, May 1988.
IEEE Guide for Animal Deterrents for Electric Power Supply Substations, IEEE
Std 1264-1993.
J. T. Burnham, “Bird Streamer Flashovers on FPL Transmission Lines”, IEEE Trans.
PWRD, Vol. 10, No. 2, Apr 1995.
Vosloo, H., C. van Rooyen, “Guarding against bird outages”, Transmission & Distribution
World/ www.tdworld.com/ April 2001, pp. 70–80.
Dos Santos, J. A., “Storks and transmission finding a middle ground”, Transmission &
Distribution World/ www.tdworld.com/ June 2004.
Seifert, J. M., “Investigations of bird streamer flashovers at 400 kV overhead transmission
line composite insulator sets”, Thirteenth International Symposium on High Voltage
Engineering, Delft, the Netherlands, 2003.
Kaiser, G. 1970 “The Mouse Buzzard as a Cause of Breakdown on 110 kV Single Pole
High Tension Lines.” ETZ-A. June.
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10
INSPECTION AND ASSESSMENT
Introduction
This chapter draws on EPRI’s extensive research on inspection and assessment of polymer and
porcelain and glass insulators. The chapter addresses the following major topic areas:
Polymer (Nonceramic) Insulators:
•
•
•
•
•
Inspection Methods for Polymer (nonceramic) insulators
Assessment of Condition and Decision-making Processes for Component Replacement and
Refurbishment
Lab Testing and Analysis of Results
Information on Unit Being Tested and Analyzed
Forensic Analysis
Porcelain and Glass Insulators:
•
•
Inspection Methods
Approach to Assessing a Population of Porcelain Suspension Insulators
Insulator inspections focuses on detecting one or more of the following symptoms associated
with defects:
1. Visual signs of the defect.
2. Significant discharge activity from the defect. This may be observed in the form of emitted
light, radio interference, audible noise or localized heating.
3. Perturbations in the E-field distribution surrounding the insulator.
From an inspection perspective, the most critical regions of an insulator are close to the
energized and grounded ends. Of the two, the energized end is considered more critical because
most failures occur close to the energized end. This is attributed to the high E-fields in this
region.
Inspection and Assessment of Polymer Insulators
Polymer insulators, also called nonceramic insulators (NCI) that have been in service may need
to be assessed to determine whether they are in good mechanical and electrical working order. If
a given polymer insulator is a risk to the reliability of a transmission line, the unit may need to be
removed from service. This section discusses issues relating to the in-service inspection of
polymer insulators.
Degradation of a polymer insulator due to unacceptable aging, mishandling during installation or
manufacturing defects may eventually result in an unacceptable loss of electrical or mechanical
integrity of the unit. For example, tracking and erosion of the weather-shed/FRP rod interface
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may lead to flashover if the tracked distance extends over a sufficiently long section of the
insulator, or a mechanical failure may occur if the cross-sectional area of the FRP rod is
significantly reduced by electrical erosion. To reduce the likelihood of an outage due to insulator
failure, high risk units need to be identified while in-service. However, there are several
difficulties facing utilities when doing so:
•
•
•
•
•
•
•
There are numerous types of polymer insulator failure modes.
The degradation activity that may be observed on a polymer insulator prior to failure may
take many forms.
Defects are often internal and therefore difficult to detect visually.
Defects that appear small on the surface of polymer insulator can be large internally.
If an internal defect results in discharge activity, the associated symptoms, e.g., heating,
audible noise, radio interference and radiation of light, may be difficult to observe.
A number of polymer insulator defects appear to result in significant discharge activity only
under critical wetting conditions. This makes observing the defect by inspecting for the
symptoms of discharge activity impossible under dry conditions.
Practical and environmental factors such as distance from insulators, background sunlight,
angle of viewing, etc., may make it difficult to detect defects.
Refer to Chapter 4 for more details on degradation and failures on polymer insulators.
EPRI and other research organizations have investigated a wide range of inspection tools. The
results of these investigations are published in a number of reports and papers [1] [2] [3] [4] [5].
Commonly used methods and tools for inspecting polymer insulators, are discussed in the
following sections.
Visual Inspection
Overview
Visual inspection of polymer insulators for external defects may provide valuable information
about its condition. However, when inspecting an insulator visually, it may be difficult to
determine whether an observed external defect or signs of degradation are a risk to the
insulator’s integrity.
In general, any visual degradation, or any defect, that indicates moisture may have penetrated to
the core rod should be considered a high risk. For a reference about types of degradation refer to
Chapter 4.
Visual inspection may be performed either from the ground, a bucket truck, the tower, a
helicopter, or UAV. Each of these methods has drawbacks, which include cost, angle of viewing,
distance to insulator, etc.
When observing an insulator visually, it is a good idea to store both an image and remarks about
the observed degradation or the general condition of the insulator. This requires both an image
capture system, either digital or analog (e.g., photograph), and a database in which to store the
images, e.g., the EPRI TIMS system [6]. Storing the information in a database allows a utility to
track the condition of an insulator with time and compare it with defective and good insulators.
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Practical Considerations
Up to now the EPRI base-funded polymer insulator research program has investigated only
ground-based inspection techniques. Practical issues relating to the position of equipment and
environmental concerns were noted during the program and are listed below.
One obvious statement can be made about the location of inspection equipment: Generally, the
closer one can get to the insulators, the better the inspection tools will perform. However, other
criteria may also apply. For instance, when inspecting I-string configurations, a viewing angle of
approximately 60o from the line of the conductor was found to produce the best results. This is
because the angle both minimizes viewing obstructions and interference from adjacent phases.
Getting close to insulators and viewing them from directly underneath is not recommended.
This location not only offers a poor view of sheath sections, but it also makes aiming the
equipment very difficult. It is far better to set up the viewing equipment farther back, roughly
50 feet, and use a bucket truck to gain elevation as needed.
It is often impossible to view all parts of the insulator from a single position. One position may
be useful for observing the energized end region, but the corona ring may hide another portion of
the insulator. Usually two observation positions will allow most of the insulator assembly to be
observed. In some cases, however, more observation positions may be necessary.
Finally regarding location, the best practice is to take a cursory look from as many viewing
angles as possible before setting up all equipment.
The following difficulties are encountered when doing visual inspections from a remote position:
•
•
•
•
•
•
Defects are relatively small and are difficult to identify and quantify, especially from a large
distance. Visual inspection requires therefore a high level of expertise.
The end fitting seal and live end region of the polymer material are critical regions of the
insulator where most degradation occurs. Unfortunately, these areas are often hidden from
view due to the viewing angle or because corona (grading) rings obstruct the view.
Due to large viewing distances, high-powered optics are generally required. This makes the
use of either a solid platform or gyro-stabilization necessary. This increases the cost and
decreases the speed of the inspection.
Poor lighting often prevents effective long-distance visual inspections in the areas of
concern, that is, close to the end fitting and on the sheath.
Results are often difficult to quantify and record.
Level of confidence in visual inspections performed from long distances is low.
Environmental Considerations
In general, when performing visual inspections, the brighter the ambient light level the better the
ability of the inspection tools to observe defects or aging. However, the position of the sun may
make certain observation positions difficult, as both shadows and looking directly into the sun
may obscure defects. Gray skies may also result in difficult viewing conditions as the insulator
will appear dark against the diffuse and bright background light.
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Visual Inspection Tools
The following sections discuss different visual inspection tools for use from the ground level.
Some of the tools may also be applied when performing aerial inspections.
Binoculars
Visual inspection is the most frequent form of inspection for overhead transmission line
insulators. Critical locations on the insulator requiring further inspection may be identified with
binoculars.
Figure 10-1
Binoculars used for inspection.
Figure 10-1 shows a set of low-power (8 x 42) binoculars that can be used to detect obvious
defects in polymer insulators during daytime inspections from ground level. Binoculars should
have high-quality optics, and should, preferably be image stabilized—especially when high
powered. Binoculars can also be useful at night when discharge activity is more visible.
The binoculars work well in tandem with a spotting scope. First, the binoculars can be used to
find areas of interest, and then the spotting scope, which has a far greater level of magnification,
can be used to observe defects in more detail. The binoculars also can be used effectively to
determine the optimum viewing position for the spotting scope.
Because the binoculars are more mobile than the spotting scope, they can be used from difficult
observation positions, such as on or directly below the tower, on uneven terrain, or even from a
bucket truck.
Spotting Scope
A spotting scope, see Figure 10-2, is best used in conjunction with other methods of inspection,
including binoculars that may identify specific abnormalities that require closer observation.
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Figure 10-2
Spotting scope used for inspections.
The spotting scope offers various levels of magnification from 20X to 60X and allows operators
to view smaller, less obvious polymer insulator defects than cannot be observed with binoculars.
However, because the spotting scope needs to be set up on a firm base, its use is limited to
ground-based observations. Using it on a bucket truck is not advisable as there is far too much
movement for a steady image.
An attachment for the spotting scope that allows the user to capture an image on some form of
media for future reference can be very useful. One such adapter, which allows the spotting scope
to be connected to a SLR camera, has been used successfully at EPRI.
Digital SLR Camera
Figure 10-3 shows a digital SLR camera fitted with a zoom lens that can be used for taking
general photographs of insulators and structures from the ground. The photographs can then be
used to document the position and application of insulators and the related hardware. If the
distance from the camera to the insulator is not too great, the camera can also be useful for
photographing defects. Such photographs are useful when relating observed discharge activity to
defect locations.
Cameras may also be used to capture images of discharges at night by using long exposure times,
a wide aperture, and high ISO settings. To be successful, however, it is important to keep the
camera still while taking the photographs. A firm tripod and remote shutter release for the
camera becomes valuable accessories.
Figure 10-3
The digital SLR camera used for inspections.
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Interpretation
Visual inspection is considered one of the most effective methods of inspecting polymer
insulators. Conditions can be identified and compared against those identified in the EPRI Field
Reference entitled, Field Guide: Visual Inspection of Polymer Insulators, 3002005627.
Recommendations are provided in the Field Reference concerning actions to take based on
observed conditions. (The visual guide is continually updated, and it is also available as a
software application for handheld devices). Figure 10-4 shows an example page of the visual
guide to show the visuals of the insulator condition plus the severity assessment and proposed
remedial action.
Figure 10-4
Example page from the EPRI visual inspection guide.
Discharge Observations
Defects often result in discharge activity, especially when the defect is conductive or is filled
with moisture. Internal tracking, flashed end fittings, or an exposed rod may result in discharge
activity. In the case of an exposed rod, discharge activity is prevalent only if moisture is present.
The discharge activity will most often occur close to the energized or grounded ends of the
insulator due to the high E-field.
Excessive discharge activity in contact with a weathershed system or end fitting seal that is in
good condition is also a concern. With time, discharge activity will age the rubber material and
seal, resulting in damage that in turn will expose the rod. If considerable discharge activity is in
contact with the rubber material and there is no associated defect, an expert in E-field grading
should be consulted.
Discharge activity can be identified by noting light or audible noise emitted by the discharge or
radio interference or localized heating caused by the discharge.
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Although observing discharge activity on an insulator is one of the most promising methods of
identifying a defective insulator, there are several drawbacks:
1.
2.
3.
4.
5.
Not all defects result in discharge activity.
Some defects only result in discharge activity under wetting conditions.
It is difficult for the inspector to know whether the unit is moist and to what degree.
Moisture by itself may result in discharge activity without the presence of a defect.
There are other sources of discharge activity, e.g., discharges resulting from wetting or a
broken strand, from hardware, etc. Therefore, one needs to know the position, magnitude and
type of discharge activity to determine whether it is the result of a defect.
6. Observations of discharge activity are sensitive to environmental conditions.
These may be overcome by using a number of techniques:
•
•
•
Inspecting units under dry conditions. This will remove the concern of false alarms due to
wetting discharge activity but will not allow the identification of moisture sensitive defects.
Inspecting in the early morning after condensation has deposited on the units. The inspector
will be confident that there is moisture present.
Comparing discharge activity on identical units. For example, if a line is inspected and
every unit has discharge activity present, this is most likely a design issue that needs to be
addressed; however, if only a small number of units have discharge activity present, they are
most probably defective units.
Under dry conditions correctly applied polymer insulators should exhibit no discharge activity;
however, under wetting conditions some discharge activity may be expected. In general,
discharge activity from a defect is far stronger than that from wetting activity, making the
differentiation of a defect from “normal” wetting corona activity possible [1].
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Damaged Corona Rings
Incorrectly Applied or No Corona Rings
Damaged End Fittings
Carbonized Rod
Exposed Rod
Split Sheath
Surface Tracking
Undermining
Figure 10-5
Conditions That May Cause Discharge Activity
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Examples of defects or conditions on polymer insulators that can result in visible corona activity
are shown in Figure 10-5 and may include:
1. A conductive defect that has formed either on the surface of the sheath or at the interface
between the rubber sheath and core rod, e.g., tracking or conductive treeing.
2. Dry cracks and splits in the rubber material. Depending on their dimensions, such defects
may not result in corona activity under dry conditions.
3. Cracking or splitting of the core rod. Depending on their dimensions, such defects may not
result in corona activity under dry conditions. Even if cracks or splits do result in corona
activity, the activity may be internal to the weather-shed system and, hence, not visible
externally.
4. Moisture present in cracks or splits in the rubber sheath and sheds.
5. Moisture present on the surface of the core rod or within the rod itself.
Observations of corona activity on polymer insulators without defects also provides useful
information.
1. Significant corona activity observed under dry conditions on a good insulator may indicate
either radio interference, audible noise, or future material degradation problems. Degradation
will be more prevalent if the corona activity is in direct contact with the polymeric rubber
material or end fitting seal. This may result from the incorrect application of grading rings.
2. Significant corona activity under wetting conditions may indicate that considerable
degradation of the material may occur over time.
Although contaminated insulators may show significant discharge activity under wetting
conditions, it is difficult to determine from observations alone whether the conditions are
approaching the critical point necessary for flashover.
Inspection of Light Emitted by Corona Activity
Observation of the light emitted by corona activity appears to be one of the most promising
methods of determining whether a polymer insulator has a serious defect.
Corona activity radiates energy mainly in the form of ultraviolet light, which is mostly invisible
to the human eye (see Figure 10-6). However, a small portion of the energy is visible at night and
appears as “bluish” flames [7]. During the day, the energy radiated by the sun in the UV
spectrum is several orders of magnitude greater that that released by corona discharges over most
of the corona spectrum, making it difficult to view corona activity under daytime or high
background light conditions.
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Figure 10-6
Spectral irradiance of corona and solar energy [8].
Practical Considerations
Practical issues relating to the position of equipment and environmental concerns for groundbased inspections are listed below. The considerations mentioned previously for visual
inspection tools also apply to visual corona inspection devices.
For nighttime corona inspections, the image may be improved by positioning the inspection tool
between any light sources in the vicinity, e.g., street or house lighting, moon, sun, etc., and the
polymer insulator. This is especially true when using either a standard image intensifier or a
corona optimized device at dusk.
The limitations of using UV inspection to identify defective polymer insulators are:
•
•
•
•
•
Not all defects, especially the prevalent ones such as brittle fracture, result in discharge
activity.
Discharges need to be external to the insulator.
Requires skilled operator.
Images are difficult to store.
Images are difficult to interpret.
Refer to the associated Field Reference on Corona and Arcing Inspection of Overhead
Transmission Lines and the section on Inspection Equipment for more information. The EPRI
Application Guide to Transmission Line NCI ( TR-111566), also contains relevant information.
Environmental Conditions
For nighttime inspections using image intensifiers, the corona detection capability improves as
the environment becomes darker. However, in very dark environments e.g., no stars or moon
light, it may become difficult to identify the exact location the corona on the insulator. This,
obviously, complicates the analysis of the discharge activity, and may be overcome by using a
powerful spotlight and switching it on and off to locate the activity.
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None of these concerns are applicable to daytime inspections using daytime corona inspection
technologies, as these devices artificially makes visible the UV light emitted by electrical
discharges.
It has been shown that heavy mists, fog and light rain enhance the chances of locating defective
or contaminated insulators. At the same time, however, these conditions often reduce the quality
of the image produced by the viewing device, and some equipment may be sensitive to moisture.
In addition, one also must be careful to distinguish between discharges due to defects and those
due to wetting of the insulator or associated hardware.
Inspection Tools
An overview of different inspection tools that can be used for ground-based UV inspections is
given in Figure 10-7. Only the Daylight corona camera are also suitable for aerial inspections.
(a) Daytime Corona Camera
(b) Standard Image Intensifier (nighttime only)
(c) Optimize image intensifier (nighttime and indoor low light conditions only)
Figure 10-7
Examples of UV Viewing Devices
Daylight Corona Detection
EPRI developed a daytime discharge camera allowing utilities allows users to observe corona
activity in full sunlight, i.e., the images are totally unaffected by solar radiation. It combines a
visible spectrum camera with a UV detector, to superimpose a digital rendering of the corona
discharges onto a visible image. These video images allow users to exactly pinpoint the
discharge location and help identify the type and magnitude of the activity, thus enabling the
identification defect components. These devices made it possible for utilities to include corona
observations as part of their everyday inspection programs.
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Image Intensifiers
Various types of image intensifiers, some of which evolved from military night vision
equipment, are commercially available. Although standard image intensifiers that operate across
a broad spectral range may be used to observe corona activity, a number of devices that use both
filters and gating circuits to observe corona activity are available. These optimized devices not
only allow one to observe corona activity indoors with either incandescent or florescent lighting
but also under more marginal conditions, e.g., at dusk. Standard image intensifiers only work
well under complete darkness. Any form of background lighting, e.g., street lighting, stars and
moon, reduces their detection capability considerably.
Standard image intensifiers intensify images over a frequency range that includes both the visible
and UV spectra. Since corona activity emits both visible and UV parts of the spectrum, the units
may be very sensitive to electrical discharges. This allows image intensifiers to reveal discharges
that are not detectable by the naked eye, binoculars or a spotting scope. If such devices are to be
used, care must be taken when obtaining such a device to ensure that both the optics and
intensifier are sensitive to the UV spectrum as defined in Figure 10-6. The main drawback of
night vision equipment is that it only works effectively at night under very low light conditions.
Daytime or dusk use is impossible, and background sources, such as city lighting, the stars and
moon, degrade the detection capability significantly. Therefore, these devices are not generally
practical for inspecting polymer insulators.
There are image intensifiers available specifically for corona detection [7]. The main advantage
of these devices is that they can view corona activity with a relatively high level of background
light, the acceptable level of which depends on the design of the device. Although more suitable
to a laboratory environment, these devices may also be used for nighttime inspections, but are
not suitable for use during daytime, dawn, or dusk.
Interpretation
Daylight corona detection inspection is considered one of the most effective methods of
inspecting electric components for electrical discharge activity. Conditions can be identified and
compared against those identified in the EPRI Field Reference entitled, Field Guide: Daytime
Discharge Inspection of Transmission and Distribution Overhead Lines and Substations: Guide
with Video (3002007493). Figure 10-8 shows an example page of the UV inspection guide to
show the visuals of the insulator condition plus the severity assessment and proposed remedial
action.
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Figure 10-8
Example page from the EPRI Daytime Discharge Inspection guide
Inspection of Surface Heating Due to Discharge Activity
Surface heating on polymer insulator may be observed under various conditions:
•
•
•
•
Leakage current and associated discharge activity
Water drop corona
Non-uniform wetting discharges
Discharges from different types of defects.
Large increases in temperature that result from leakage current activity can be mistaken for
defects. However, heating due to leakage currents generally occurs along most of the insulator,
while heating due to defects is localized. Distinguishing between the two is only difficult in
regions of high contamination.
A small increase in the surface temperature of polymer insulator may result from discharge
activity due to non-uniform wetting. Temperature increases associated with this activity are
small and generally distinguishable from heating due to defects or contamination. This activity is
generally not a cause for concern.
Localized heating may result from internal and external defects. It is often possible to distinguish
internal defects from external defects. For instance, if heating is observed but there is no external
discharge activity, the defect very likely is external. However, if both heating and discharge
activity are observed, it is not possible to determine whether the discharge is only external.
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Experience gained from the base-funded in-service inspection program has shown that defects
are more readily identified under wetting conditions [1]. However, it may be difficult to
distinguish between heating due to defects and heating due to normal wetting discharge activity.
Environmental Conditions
Reflections from solar radiation make the observation of heating activity difficult during daytime
hours. Under full sunlight, the levels of heating from solar reflections on “good” insulators are
often equivalent to those observed on defective ones. Although low cloud cover and dusk
conditions are preferable, it is still possible to observe significant defects under full daytime
conditions.
Heavy mists, fog and light rain will enhance the chances of locating defective or contaminated
insulators. However, these conditions often reduce the quality of the image produced by the
viewing device, and the equipment is usually sensitive to moisture. In addition, one also has to
be careful to distinguish between a defect and discharges due to wetting of the polymer insulator
and associated hardware.
Practical Considerations
EPRI has investigated the use of thermal imaging inspection techniques. Practical issues relating
to the position of equipment and environmental concerns were noted during the program and are
listed below. Similar considerations mentioned above for visual inspection tools above apply to
infrared inspection devices.
Better images are obtained if there is nothing behind the insulators being inspected, i.e.,
preferably an open sky. If either a hill or trees provide a backdrop, and they are at the same
temperature as the insulators, possible defects in the insulators may be difficult to distinguish
from the background. Images from the infrared camera provide less information as the distance
from the object increases. In addition, image quality decreases if observations are made when
there is mist or rain between the camera and the object viewed.
Inspection Tools
Presently there is a wide range of infra-red cameras available on the marked from compact, easyto-use and low-cost cameras to more expensive full function ones. Not all cameras are equally
applicable to all inspections as the manufacturers make and market these cameras with a feature
set optimized for a specific intended application. It is therefore crucial to purchase a camera
system that will meet all requirements and expectations for all critical targets and conditions that
will be encountered. Factors that should be considered include:
•
Minimum safe working distance to the insulator and the size of the defects that need to be
observed. The safe or available minimum working distance to each target will determine the
type of lens needed. For distances of 20 ft (6 m) or less from the target, most standard lenses
are all that is needed to perform inspections. This applies to most substation environments.
However, for overhead line inspections greater distances may be expected and a telephoto
lens might be needed to capture details.
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•
•
Environmental considerations: The ambient temperatures during which inspections will be
performed should fall within the operating temperature range specified for the IR camera.
Also make sure that the images displayed by the camera is visible in bright sunlight.
Thermal contrast of all targets and their surroundings: Ensure that the IR camera is sensitive
enough to distinguish the target from its surroundings.
Features typically considered are:
•
•
•
•
•
•
Spectral response: The range of wavelengths that the camera photographs; typically,
problems found on transmission lines and substations components radiate mainly in the long
wavelength band. The use of long-wave IR cameras is recommended for field work because
of the susceptibility of short-wave cameras to solar glare and other reflections.
Thermal resolution: The difference in temperature that the camera can detect; for example,
a thermal resolution of 0.1°C at 30°C means that the camera may be able to detect 0.1°C
difference between two different points when the camera’s temperature is 30°C. Conductive
internal defects will only give rise to a small increase in temperature in the order of single
degrees Celsius.
Temperature resolution: The accuracy of the temperature measurements being recorded by
the camera; for example, the temperature resolution of ±2°C means that temperature readings
will be accurate within 2°C. For insulator inspections this feature is less important since
defects are identified by a relative temperature increase above the surroundings.
Spatial resolution: The number of highly heat-sensitive detectors inside the camera typically
referred to as pixels. A detector array of 160 x 120 is acceptable for substation applications
where only hot spot detection is desired. Detector arrays of 320 x 240 or greater are better
suited for application where analysis is required, especially if readings are to be archived and
used to trend temperature variations.
Emissivity adjustment: The capability to adjust the cameras readings based on the surface
of the material being measured. This feature is convenient for achieving accurate temperature
readings, but not essential for insulator inspections that rely on a relative temperature
measurement.
Minimum and maximum measurement distance: The range of distances from the
measured surface that produce accurate temperature measurements. Make sure that the
camera can measure temperatures at the distances typically encountered during inspections.
For field inspections also consider the ease of use and ruggedness of the camera to ensure its
ability to survive handling and transport over rough terrain.
(Inspection of Compression Connectors: Radiography and Low Cost Infrared (IR) Imaging.
EPRI, Palo Alto, CA: 2017. 3002010120.)
The following sections discuss an infrared imaging system investigated as part of the EPRI basefunded program [1]. The tool discussed was only evaluated for use on the ground.
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Figure 10-9
Infrared imaging system used for inspection.
Interpretation
Infrared cameras can provide valuable information if used under low sunlight conditions, either
to assess the condition of specific insulators or to gain an indication of the general condition of
insulators on a line. Conditions can be identified and compared against those identified in the
EPRI Field Reference entitled, Field Guide: Infrared Thermography for Overhead Transmission
Lines Insulators, Compression Connectors, Overhead Ground Wire, Surge Arresters
(3002007667). Figure 10-10 shows an example page of the visual guide to show the visuals of
the insulator condition plus the severity assessment and proposed remedial action.
Figure 10-10
Example page from the EPRI Infra-Red Inspection guide.
Detection of Corona Activity by Measuring Acoustic Emissions
Directional detectors for acoustic noise are commercially available and have been used
successfully in high voltage laboratories to identify the presence of discharge activity.
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These devices generally consist of a parabolic dish and a microphone that together form a
directional listening device. The device is capable of listening to acoustic activity over a wide
bandwidth. An example is shown in Figure 10-11.
Figure 10-11
A parabolic microphone that can be used to pinpoint sources of acoustic emissions.
It has been shown that a large magnitude of emissions from polymer insulator defects occurs
between 10 and 160 kHz with most emission occurring between 30 and 50 kHz [17]. It is
therefore important that the device used to inspect for this activity is sensitive in this range and
that the proper sensitivity settings are used.
Practical Considerations
One of the limitations of ultrasonic inspection is the inability to pinpoint the exact location of
discharge activity. This limitation can lead to confusing results, for example, an inspector may
not be able to distinguish sources of discharge activity such as a situation in which a large
amount of discharge activity is occurring on hardware (which is not a concern) near where a
small amount of discharge activity is occurring on the sheath of an insulator (which is a
concern). The relatively large distances that are often between the inspector and the components
being inspected exacerbate this limitation.
For example, whether the discharge activity is from the insulator itself, the associated grading
ring, or nearby hardware cannot be easily determined. It is also very difficult to differentiate
between wetting discharge activity on a good insulator and a defect on a faulty unit. Once again,
a possible use for such devices would be to identify the presence of corona and define its general
location on a tower. Inspectors then would have to revisit the tower at a later date and use
different inspection techniques to determine the exact location and cause of the discharge
activity.
For more information, refer to the Inspection Equipment Section of the EPRI Application Guide
to Transmission Line NCI (TR-111566).
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Environmental Considerations
The level of background noise can make such devices difficult to use. In some cases, good
results have been obtained in an indoor laboratory, but outdoors background noise rendered the
same defect undetectable [3].
Detection of Corona Activity by Measuring Radio Interference
Corona activity produces high frequency electromagnetic waves that may interfere with radio
communications, hence the term radio interference (RI) [10] [11] [12] [13] [14] [15]. Therefore,
one method of inspecting for discharge activity is to monitor the RI. Because discharge activity
produces electromagnetic waves over a broad spectrum of frequencies, a directional antenna can
be used together with a receiver to detect the magnitude and approximate location of the
discharge. The magnitude of discharge detectable and the accuracy with which the position is
determined depend on the directionality of the antenna as well as the frequency range monitored.
The EPRI base-funded project has only performed a limited investigation into this technology. A
more in-depth investigation may be warranted.
Practical Considerations
Generally, RI detection devices can only limit the source of discharge activity to a specific pole
or cluster of insulators. Hence, such devices are unable to determine whether discharges are
emanating from an insulator or from a section of hardware or conductor. It is also very difficult
to differentiate between wetting discharge activity on a good insulator and a defect on a faulty
unit. This limitation can lead to confusing results, for example, an inspector may not be able to
distinguish sources of discharge activity such as a situation in which a large amount of discharge
activity is occurring on hardware (which is not a concern) near where a small amount of
discharge activity is occurring on the sheath of an insulator (which is a concern). Therefore, it is
very difficult to identify faulty insulators using available RI detection technology. The relatively
large distances that are often between the inspector and the components being inspected
exacerbate this limitation.
For more information, refer to the Inspection Equipment Section of the EPRI Application Guide
to Transmission Line NCI (TR-111566).
Environmental Considerations
One of the advantages of RI detection equipment is that its performance is not affected by the
level of sunlight. While the equipment can be used effectively during the day, nearby noise
sources such as arc welders, corona sources on the conductor and general radio transmissions can
reduce the instrument’s sensitivity.
Observations under wetting conditions using available technology are almost impossible, since
RI emissions from defects cannot be distinguished from water drop corona sources on the
conductor and end fittings.
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A possible use for such devices would be to identify the presence of corona and identify its
general location on a tower. Inspectors would then have to revisit the tower at a later date and
use different inspection techniques to determine the exact location and cause of the discharge
activity, e.g., whether the discharge was due to a defective polymer insulator or from metal
hardware.
Leakage Current Monitoring
If a conductive defect occurs along a significant portion of the insulator or is coupled to the
grounded end, increases in leakage current activity may be measured at the grounded end of the
insulator. Research has shown that this technique has very limited application due to sensitivity
to the location and size of defects. Increases in the sensitivity of leakage current measurement
equipment may warrant further investigation.
On-line leakage current monitoring has been used to determine the level of contamination of
glass and ceramic insulators in-service with limited success.
Electric Field Measurement
Power Frequency Electric Field Measurement
The presence of a conductive defect may be detected by measuring the E-field distribution along
the length of a polymer insulator. This can be accomplished by using a hot stick to move a sledmounted E-field sensor up and down an energized in-service insulator, as shown in Figure 10-12.
The E-field distribution is recorded in a data logger that is integral to the sled-mounted sensor.
When the test is complete, the data is downloaded from the sensor to a personal computer (PC).
Such devices have been evaluated by the EPRI as well by other research organizations [3] [4] [5]
[16].
Figure 10-12
Inspecting an NCI for defects by measuring the E-field.
The unit works on the principle that any conductive defect will result in a perturbation in the
E-field. By comparing the E-field distribution of an in-service insulator against that of a known
good insulator, it may be possible to identify a conductive defect, which would show up as a
deviation in the E-field. Examples of E-field distributions measured along a good polymer
insulator and one with a conductive defect are shown in Figure 10-13.
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250000
200000
Good Insulator
Defective Insulator
150000
100000
50000
0
0
20
40
60
80
100
120
Shed Number
Figure 10-13
E-field profiles measured along one good and one defective NCI. The defect can be seen in the
distortion in the E-field between 80 and 100 sheds.
Evaluation of the unit has shown that the length of the defect has to exceed some critical value
for effective detection and that conductive defects that are electrically connected to the live end
far more readily identifiable than floating defects. Non-conductive defects cannot be detected.
Practical Considerations
1. The major drawback of this inspection technique is that utilizing live working for general
inspections is cumbersome and slow. Therefore, this method may not be a useful for the
wholesale inspection of polymer insulators on a system. However, it may have its uses for
inspecting small numbers of high-risk insulators or for evaluating insulators during a live
working procedure.
2. Inspections have to be performed under dry conditions because wetting, especially of
polluted insulators, distorts the E-field.
3. The sled has to be kept in contact with the insulator at all times, otherwise false distortions in
the E-field curve may be observed.
4. The unit is unable to detect non-conductive defects. Insulators that have experienced brittle
fracture failures generally do not have conductive defects.
5. The defect needs to be large enough to result in a sufficient distortion of the E-field. For
example, a defect of at least a 20 cm was needed for detection along a total insulated length
of 220 cm [3]. This defect, however, is larger than most one would expect to find in a
polymer insulator.
High Frequency Electric Field Measurement
EPRI has developed a field tool that will allow linemen to test a polymer insulator for electrical
defects prior to performing energized work to ensure the working environment is safe. The tool
is designed for high durability, low weight, and low cost. The device, shown in Figure 10-14 and
Figure 10-15, is attached to the end of an insulating tool (hotstick) and moved along the length of
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the polymer insulator. Alarms are activated when a damaged area (for example, carbonization or
tracking of the fiberglass rod under the sheds) is detected. The device’s sensitivity is pre-set to
respond to damage of sufficient size that it could degrade the integrity of the worksite beyond
acceptable levels.
Figure 10-14
The new insulator tester being used to test a polymer suspension insulator on the line.
Figure 10-15
Close-up view of the insulator tester showing tester status and condition indicator lights.
After ten years of development, the tool has been commercialized by Hubbell Power Systems
and is now available to the industry as the Polymer Insulator Tester for transmission suspension
insulators. As part of the research project, EPRI has also built a polymer post insulator test unit
that will be sent to project funders for field testing and evaluation. (See Figure 10-16.)
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In a closely related project, EPRI is developing an automated robotic delivery system for the
polymer insulator tester as well as other sensor payloads. A prototype is shown in Figure 10-17.
The device is designed to crawl or climb along the insulator and assess its condition. This
continuing development effort is showing the potential advantages of robotic systems in
transmission applications.
Figure 10-16
EPRI polymer post insulator test units.
Figure 10-17
Prototype of the EPRI crawling insulator robot.
Inspection Techniques
In-service insulators may be inspected either from the ground or from and aircraft.
Ground Inspection
Ground inspections can be performed using any of the inspection technologies and tools
described above, keeping in mind the practical and environmental considerations.
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Inspecting insulators from the ground has the following advantages:
1. A stable base or viewing position that allows a good view of the insulator is generally
available.
2. Inspections may be performed at night, allowing effective use of available UV and IR
technology.
3. Inspections may be performed either during or directly after wetting activity, which has been
shown to enhance the possibility of observing discharge or heating activity from defects.
4. Numerous tools may be used, and the results are easily stored and recorded.
However, ground inspections have the following disadvantages:
1.
2.
3.
4.
Structures are not always easily accessible.
Effective viewing positions may be difficult to reach due to terrain or vegetation.
Instruments are bulky.
Tall structures may require the use of a bucket truck for effective viewing. The structure may
also be climbed, but correct procedures need to be followed by qualified personnel.
5. Visual observations have to be performed during the day, while IR and UV inspections are
more effective under at night. This slows the inspection process considerably.
6. Ground inspections are slow, tedious and labor intensive.
Ground inspections utilizing both visual and discharge inspection tools do not appear to be viable
for the wholesale inspection of transmission lines. However, the inspection of isolated structures
can be very useful, either because concern has been raised over a particular insulator or to obtain
an indication of the general performance of the insulators installed on a line from a small sample.
Visual techniques may be utilized on numerous structures during the day to determine if any
units are of concern. These structures may be revisited at night with discharge observation tools
to obtain further information about the condition of the units.
Aerial Inspection
Aerial inspections have the advantage that it allows the observation of a relatively large number
of structures in a short amount of time, but adjustments to equipment and methods may be
needed to effectively inspect polymer insulators.
Aerial inspections are exclusively performed during the day, which means a reliance on visual
inspections complimented with daylight corona detection and IR equipment.
If the inspection is to be performed from a helicopter, it is advisable to mount the inspection
tools on a stabilized platform. In addition, the images and data captured from the inspection need
to be correlated against the tower being viewed by geotagging the images. Systems and software
have been developed to address these issues.
Condition Assessment
Based on the seriousness of the condition observed, different actions need to be taken.
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High Risk of Failure
There is a high risk of failure if the answers to any of the following questions are positive:
•
•
•
Is the fiberglass rod exposed to the environment due to either a compromised end fitting seal
or degraded/dam-aged weathershed system?
Is the level and type of contamination on the surface of the insulator high enough to result in
a high probability of flashover?
Is there any internal damage to the fiberglass rod?
If any of the above conditions are determined to exist or there is a high probability that any of
these conditions exist, the unit being evaluated should be removed from service as soon as
possible as the unit has a high risk of failure.
Conditions that in the Future May Result in a High Risk of Failure
If the answers to any of the following questions are positive, then conditions are present that may
lead to a high risk of failure in the future:
•
•
•
Is there any degradation of the rubber material that in the near future may result in the rod
being exposed to the environment?
Is there any degradation to the end fitting seal that in the near future may result in the rod
being exposed to the environment?
Do the units have any inherent design defects that may result in failure?
If any of the above conditions are determined to exist, the unit should be removed from service at
the next opportunity and inspected for damage by an expert in order to determine the cause and
whether the entire population is at risk.
Conditions that May Result in Premature Aging
If the answers to any of the following questions are positive, then conditions are present that may
result in premature aging:
•
•
•
•
•
•
•
•
Is there any degradation to the metal end fitting or the corona ring that may result in
degradation of the rubber weathershed system or end fitting seal?
Has the unit been incorrectly applied so as to promote degradation/damage to the fiberglass
rod, rubber weathershed system, or end fitting seal?
Are there any external factors that are aging the unit?
Is the design susceptible to premature aging?
Depending on the condition observed, the following decisions may be made:
Continue to monitor the condition until degradation is observed.
Resolve application, corona ring, or end fitting degradation issues by replacement.
Contact an expert to determine the effect of the condition on the rate of aging and probability
of failure. Based on the input obtained, a decision can be made.
The philosophy outlined above is embodied in the Field Reference entitled Guide to Visual
Inspection of Polymer Insulators.
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Information Gained from and Decisions Based on Inspection Results
In-service inspections may be used to identify insulators that should be removed from service,
obtain an indication of the conditions of insulators in-service and highlight insulators that may
need to be monitored more closely in the future.
Removal from Service
Once an insulator has been inspected with any of the tools discussed above, a course of action
must be determined. The following may be listed as reasons for removal of a polymer insulator,
depending on the inspection tool utilized:
1. The sheath is compromised, and the core rod is exposed to the environment. Although one
may not be able to observe the rod remotely, significant cracking, erosion, etc. may indicate
that the rod is either exposed or may be soon.
2. Significant visible discharge activity that is not related to either hardware or wetting corona
activity is observed. This discharge activity may indicate a defect.
3. Significant heating of the rubber sheath that is not related to either hardware or wetting
corona activity is observed. This may indicate either an internal or external defect.
4. The measured E-field is significantly distorted, indicating the presence of a conductive
defect.
5. Degradation or discharge activity that may result in a failure can be observed.
Insulators having each of the above symptoms have been known to remain in-service for a
prolonged period of time after the symptoms have been observed. However, other units have
been known to fail shortly after the symptoms have been observed. It is, therefore, extremely
difficult to determine the life of an insulator with a defect based on an inspection. The inspection
merely gives an indication of the risk of failure.
When an insulator is removed from service, it should be investigated to determine the nature of
the defect. This will help to determine whether other insulators on the system are likely to have
similar problems. As much information as possible about the insulator should be gathered, and
pictures should be taken both prior to and after removal. EPRI may be contacted and consulted
on the nature of the defect and whether further investigation is warranted.
Obtaining an Indication of Condition
An indication of the condition of polymer insulators may be obtained by inspection. This may
provide information about future problems and life expectancy. Units exhibiting degradation that
is not significant enough for removal should be noted and monitored more closely in the future,
as the degradation may become worse with time.
During an inspection, all images and data should be recorded, regardless of whether an insulator
is earmarked for removal from service. This will provide a valuable reference for any future
inspections and will allow a determination of the rate of aging of the insulator.
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Approach to Evaluating Existing Populations of Polymer Insulators
It is a challenge to assess and evaluate an existing population of polymer insulators to determine
whether action, and importantly, which action, should be undertaken to ensure the reliability of
the transmission line.
When assessing an existing insulator population, it is important to follow a well-structured
approach. A typical process should contain the following steps but depending on the situation all,
or only some, of these steps may be necessary:
1. Evaluating Industry Experience
a. Analyzing past service experience and age
b. Evaluating the configuration, environment
c. Evaluating the insulator design
2. Discharge Inspection, usually with a daytime discharge camera, DayCor or Corocam.
3. E-field calculation and evaluation
4. Evaluation of a sample of insulators from service and/or field inspections
5. Analysis of the results and identification of the actions necessary.
6. Determination of replacement criteria
7. Determination of a regime for future inspections
More detail on each of these steps can be found in the sections that follow.
Evaluating Industry Experience
As a first step a paper exercise can be done to form an initial risk assessment of the specific
insulator type involved. Such an assessment is based on past experience in combination with an
evaluation of the insulator design and its installation environment to determine it susceptibility to
ageing as a result of high E-fields.
Using past experience
It is relatively easy to identify high risk insulator designs from historical performance data if it is
available. Such information is useful to:
•
•
Identify particular insulator designs, or vintages, that suffered premature ageing due to high
E-fields in the past. The installation of such units should be investigated further as they are
likely to suffer the same fate unless changes are made to either the design and materials used
in the insulator, or its operating environment (e.g., reduction of the E-field levels).
Determine the expected lifetime of the insulators, to expedite a timely removal from service.
It is therefore good practice to maintain a failure database, or to keep track of insulator
replacements and reasons for such replacements. The usefulness of such a database is extended
if polymer insulator exchange information with others as is done via the EPRI failure database
[20].
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Vintage
Insulator manufacturers have changed their design from time to time to implement new
materials, streamlining processes or in response to negative user experiences. Not all these
designs perform equally well (as is shown in the next Section), and it is therefore necessary to
interpret past performance data in terms of the insulator vintages involved. EPRI helps this
process by keeping track of insulator design changes for their members with the Polymer
Insulator Vintage Guide [21].
An example that illustrates the advantage of having a vintage guide available is that of a
particular insulator manufacturer that changed their rubber formulation in 1998 to make it more
resistant to corona activity. Units manufactured before this date will therefore have a shorter life
expectancy than units manufactured after this change.
Expected lifetime
Deterioration due to corona discharge activity takes time to develop. It is therefore logical that
units which have been exposed to unacceptable levels of discharge activity for a long time will
exhibit more deterioration than fairy new units. How long it takes to deteriorate depends on the
factors mentioned in the later sections of this chapter, but such information can be gained from
past experience as is captured in a failure database and/or industry experience.
Evaluation of the Configuration and Service Environment
Another source of information that can be used to identify high-risk units is to identify
configurations and environments that are more likely to expose insulators frequently to corona
activity.
Configuration
The E-field on the insulator is dependent on the insulator assembly configuration The power line
configuration is an important factor that influence the E-field magnitudes on the end fitting, end
fitting seal and polymer weathershed material. Important parameters are:
•
•
•
Insulator Assembly Type and Orientation
Phase Spacing
Number of Circuits
The insulator assembly and its orientation determine to a large extent the magnitude of the
highest E-field on the insulators. The types of insulator assembly in order of E-field severity are:
•
•
•
Single dead-end insulator assemblies have generally the highest E-field magnitudes on the
insulator surfaces and hence are more likely to have unacceptable discharge activity.
Double dead-end insulator assemblies have lower E-field magnitudes but not low enough in
many cases to negate the use of corona rings.
Suspension, I-sting and Vee-string assemblies have lower E-field magnitudes but once
again in most cases the E-fields may not be low enough to negate the use of corona rings.
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•
•
Braced Post Assemblies: The post units, in all cases investigated to date, have not had
unacceptable E-field magnitudes. The suspension (brace) units, however, may still have high
E-field magnitudes and be subjected to an unacceptable level of discharge activity.
Post Insulators have lower E-field magnitudes. In all cases investigated to date, the post
units have not had unacceptable E-field magnitudes.
The presence of other phases on the same tower can contribute significantly to the E-field levels
on the insulator. Figure 10-18, which is calculated for a 138 kV vertical suspension structure,
demonstrates that a compact line with a close phase spacing will have a significantly higher Efield than a line with a wider phase spacing. Experience shows that this effect is even greater for
dead-end configurations.
Figure 10-18
Example of increase in E-field magnitude on the sheath surfaces as a function of phase spacing
for a vertical suspension configuration.
Multiple circuits on the same structure may also result in higher E-field levels than on a single
circuit configuration with the same phase spacing. This is dependent on the relative positions of
the phases with respect to each other and, of course, the phase spacing. This effect becomes
however less important on double circuit lines with large separation between the circuits.
Environmental Conditions
In terms of corona discharge activity two main environmental parameters that have an influence
are altitude as well as the frequency and duration of wetting events.
The reduced air density at high altitudes results in a lower inception E-field level for corona
discharges. E-field threshold levels should therefore be adjusted accordingly as dealt with in the
section on recommended E-field limits.
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Insulators installed in regions where duration of insulator wetting is longer will be also exposed
to longer periods of non-uniform wetting discharge activity. Figure 10-19 shows a map of the
USA, developed by EPRI, that shows an estimate of the annual number of wetting hours for
polymer insulators [18].
Figure 10-19
Predicted annual wetting hours for polymer insulators in the United States (in hours per year)
(averaged for EP and SIR polymer insulators).
Evaluation of Insulator Design
Service experience has shown that certain insulator designs are more susceptible to premature
ageing due to high E-fields than others. The factors that determine whether an insulator design
unit will be subject to high levels of corona activity. Certain insulator designs, or vintages, may
be more likely to exhibit premature ageing because they:
1. Have higher levels of discharge activity, due to inadequate voltage grading, or,
2. Be more susceptible to degradation, due to weathershed materials that are susceptible to
degradation due to corona discharges or its byproducts.
E-Field Grading
The electrical field on a composite insulator is normally the highest close to or at the energized
end fitting. The magnitude and shape of the E-field profile in this critical area is determined (1)
by the size and shape of the insulator end fitting and (2) the presence, location and size of corona
rings.
On 115/138 kV systems insulators are generally installed without corona rings. In these cases,
the shape and size of the end fitting design is very important in whether or not the design is
susceptible to corona discharges.
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It can be shown that end fittings with a large diameter grade the E-field better than those with a
smaller diameter. This is because:
•
•
The E-field level on a slender end-fitting is more likely to exceed the dry corona inception
thereby potentially exposing the insulator weathershed system to more or less continual
corona discharges.
A slender end fitting provides less E-field grading on the insulator sheath close to it. This
leads to a higher risk for corona on the sheath during wet conditions.
The end fitting shape is also important as it determine where the maximum E-field will occur. It
is beneficial if the end fitting is shaped so that the highest E-field occurs away from the insulator
housing and the end fitting seal is not exposed to high E-fields.
The likelihood for dry corona on 115 and 138kV insulators can be lowered with the application
of a corona ring at the live end. However, not all corona rings are able to reduce the E-field
magnitude along the insulator to below the required thresholds as defined at the beginning of this
chapter. Whether or not a corona ring design is sufficient depends on:
•
•
•
Corona ring dimensions, e.g., inner and outer dimensions
Location of corona ring with respect to end fitting
Attachment hardware (some hardware may influence the E-field distribution).
The only way to verify corona ring designs are through detailed 3-Dimensional E-field
calculations as implemented in the EPRI EPIC or other commercially available software.
Composition of the Rubber Used for the Weathershed System
Certain materials, due to their composition, and molding processes used, are more susceptible to
degradation from corona discharges than others. It is difficult of identify weak materials
beforehand, so it is necessary to resort to either testing or past experience. EPRI has over the
years collected a substantial body of knowledge in this respect. Reports are available that detail
results from:
•
•
•
EPRI aging chamber
Field inspections and Failure Database
Material Corona Test Results
Presently, EPRI is also in a process of developing tests to evaluate the resistance of materials to
discharge activity, both dry and wet. These tests are designed to be relatively easy to use so that
evaluating existing populations can be evaluates as well as be simple enough to be included as a
requirement in utility specifications.
Summary
A summary of the aspects mentioned in this section can be found in Table 10-1.
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Table 10-1
Risk of unit being degraded by an unacceptable level of discharge activity.
Influencing Factors
Primary
Past experience
Secondary
Risk Assessment
Low
Vintage
Medium
High
Insulator Design Dependant
Age
Configuration
Environmental
Conditions
Insulator design
Phase Spacing
Spacing
> 12 feet (4m)
Spacing
< 9 feet (3m)
Number of Circuits
1
2
N/A
Insulator assembly
N/A
I-sting
Brace post
Dead-end/Tangent
Altitude
N/A
Sea Level
> 3300 feet
Frequency of wetting*
Dry Desert
0-400 h
Temperate
400-600 h
Very wet
>600 h
Diameter of end fitting
Large
Medium
Small
Position of highest
E-field on end fitting
N/A
Away from
rubber
Close to rubber
Exposure of seal to
E-field
Shielded from
E-field
End fitting
grades
Exposed to E-field
Design of corona ring
Effective
Marginal
No ring
Weathershed rubber
N/A
Tough material
Weak material
Note * See Figure 10-19
Discharge Inspections
Discharge inspections with a suitable camera to visualize the discharges during daylight (e.g.,
DayCor) can be effective to identify insulators with continual dry corona activity or where the
deterioration of the internal components has reached an advanced stage. It should however be
noted that Daytime Discharge Inspections under dry conditions will not identify whether there
are unacceptable levels of discharge activity under wetting conditions. The best method of
determining whether this issue exists is E-field modeling which is discussed in the next section
of this report.
It is suggested that utilities perform at least a cursory inspection on 115 and 138kV lines fitted
with polymer insulators with no corona rings installed to determine whether they are
experiencing and dry corona activity. Priority should be given to insulator units identified as
high-risk based on the evaluation of past experiences, as explained in the previous section. This
generally includes:
•
•
•
Insulator designs with known a known failure history are in-service
Lines with a tight phase spacing
Line sections that are located at higher altitudes
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Daytime discharge inspections can be made during aerial or ground based line inspections.
Details of the technology available, inspection methods and guidelines on the interpretation of
the results are available in a number of EPRI Reports [24][25]. While doing the inspection it is
also recommended to perform a visual inspection, in as far as it is possible to record any visible
deterioration or damages (See Visual inspection Guide[27]) and to identify installations where
the corona rings are damaged, dislodged or incorrectly installed (Corona Ring guide[26]).
When doing inspections, it is important to capture the following information:
•
•
•
•
•
•
•
•
•
Date
Line Name
Structure Number
Phase Location and electrical circuit
Weather Conditions
Inspector Name
A short description of the observation made
Photo identification if photos have been made
A first rating of the severity of the activity observed and an indication of the need for further
action
It is customary to maintain a simple three tier rating as one of three levels:
•
•
Low
Medium
•
High
Monitor at next scheduled inspection, discharge activity very low or not present.
Discharge activity present and is resulting in component degradation. Close-up
visual inspection of suspect area at next opportunity or component removal for
evaluation.
Immediate remedial action recommended to determine cause of discharge
activity, discharge activity present at a high amount.
Details and an explanation of the priority settings utilized by EPRI on inspections are given in
Table 10-2.
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Table 10-2
Setting and understaning severity ratings for corona inspections.
Condition
Image
Rating
A. Possible
Internal Defect
High
Comments
• Possible internal condition that is
resulting in discharge activity.
• Significant risk to mechanical and
electrical reliability
• Consider replacement at next
opportunity
B. End Fitting
Discharge
Activity
Medium
• Continual discharge activity from
metal end fitting in contact with
rubber material.
• Discharge activity will age rubber
material resulting in exposure of
the rod (there is a probability that
the rod maybe exposed already)
• Perform detailed evaluation to
determine condition of rubber
material and end-fitting seal to
determine whether unit can be left
in-service.
• Install appropriate grading device
(corona ring) to prevent activity.
C. Possible
Degradation of
Rubber
Weathershed
System
Medium
• Visual identification of possibly
damaged rubber material
indicating rubber deterioration.
• Rod may or may not be exposed.
• Notes:
− It often not possible to get a
good line of sight on insulator
units during inspections.
− It may be difficult to visually
identify deteriorations as these
are relatively small compared to
the inspection distance.
D No Activity
Low
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• Insulator may show discoloration
indicating that corona may be
present during different weather
conditions
E-Field Modeling
By far the best way to determine whether or not insulators will be subjected to dry or wet corona
activity is to perform E-field calculations. This is however a complicated and time-consuming
task as the E-fields needs to be calculated with detailed 3-dimensional models of the insulator as
it is installed in the tower configuration. Setting up models for E-field calculations also requires
special skills and experience as the amount of detail in the model and its extent needs to be
balanced against the computational demands of the model to obtain accurate results in a
reasonable time. General guidelines and requirements for E-field modeling are provided in
Appendix B.
Due to the complexity and effort required, E-field calculations are presently only performed on
those structures identified as high risk, based on previous experience or corona inspections.
These are typically single insulator dead-end structures, which often has the highest electric
fields. This is however about to change with the release of the EPRI Software for Polymer
Insulators Electric Field Calculations (EPIC) [23]which is specifically designed to calculate the
E-field on polymer insulators in typical transmission configurations in 3-D. A key feature of
EPIC is the ease with which complex transmission line situations can be set up for calculation,
thereby allowing non-experts to perform E-field calculations in a fraction of the time that it takes
using traditional packages.
With EPIC available it is now possible to perform E-field calculations on a much wider scale
than previously and work towards a situation where all the types of structure where polymer
insulators are installed are evaluated.
Evaluation of a Sample of Insulators and/or Field Inspections
Based on the discharge inspections, insulators are identified for removal from service. These
units are examined for signs of degradation and an assessment of the risk of failure is made. In
service visual inspections may also be used to identify insulators for removal, but this is only
effective if performed at close quarters, i.e., less than 12 inches (30 cm) viewing distance, and by
a well trained and experienced inspector.
The number of samples removed from service can be determined statistically but in reality, it is
found that - due to cost and time constraints - only a small sample of between 6 and 30 units are
usually available for removal.
The following priority list should be used to identify insulators which are taken down for
inspections:
•
•
•
•
Units previously identified (e.g., by visual inspection) as having some form of degradation
Units known to have an unacceptable level of discharge activity
- Dry – any discharge in contact with rubber material or seal
- Wet – a high level of discharges
Units with a high risk design
Units of high risk vintage
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•
•
•
Units in the dead-end position, preferably single dead-end
Units in high altitude or high wetting regions
The sample should preferably include units that were inspected during the Daytime
Discharge Inspection
The detailed evaluation should be performed by personnel that are familiar with evaluating a
population of polymer insulators. The following evaluation techniques are suggested:
•
•
•
•
•
Detailed visual inspection (as per EPRI Visual Guide [27]), with close-up photographs
documenting the findings
Hydrophobicity Measurement and Mapping as per IEC 62073[22]
Dye penetration tests on end fitting
Dissection – on a selection from the taken down units
Mechanical Tests – on a selection from the taken down units, i.e., those not dissected
Replacement/Retrofit Corona Ring Criteria for the Field
Based on the results of the evaluation process described in steps 1-4 above, it should be possible
to determine which course of action is necessary.
•
•
•
•
Severe degradation in the high E-field area of the insulator could serve as a prompt to replace
all units in-service with units with an acceptable E-field distribution.
Insulators with continuous corona present, but with slight signs of deterioration would
warrant a retrofitting of all in-service units with corona rings and removal of any units that
exhibit high risk conditions. It is also prudent to increase the inspection frequency of the line
after the retrofit.
Insulators with continuous corona present, which is not obviously in contact with the material
and with no signs of premature damage may be left in service but may be inspected more
frequently.
Insulators with no dry corona activity observed, but with E-field magnitudes greater than the
recommended threshold levels confirmed by higher levels of degradation in the high E-field
regions may warrant the addition of a corona ring.
When retrofitting corona rings it is possible to further eliminate high-risk units by performing a
visual inspection process. Units should be replaced if severe degradation is identified according
to the following set of criteria. Please note these replacement criteria were developed for one
particular insulator design, other designs may require additional or different criteria:
1. Any cracking in the sheath is observed
2. Any rust
3. If, when bending the first and second shed from the energized end, any cracking is observed
in the shed or sheath
4. Any other damage, e.g., handling damage is observed, (utilize EPRI inspection guide)
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A corona rings maybe retrofitted if slight or normal degradation is observed. Slight or normal
degradation includes but is not limited to:
1. Loss of hydrophobicity in the high E-field region.
2. Surface roughening and discoloration in the high field region.
3. Initial signs of de-bonding of the end fitting sealant to the metal end fitting or housing
material.
EPRI has developed a short educational video to help with the training of field crews during this
process [19].
Future Inspection Approaches
The need for future inspections is determined from the results of activities 1-5 as discussed
above. These follow up inspections are performed to (1) verify that the measures taken are
effective and (2) monitor the insulators for any progression of already observed deterioration.
On high-risk units it may be prudent to increase the inspection frequency to timely identify units
that should be removed from service. This may even be necessary on units that have corona rings
retrofitted.
It is also good practice to evaluate the effectiveness of the measures taken by performing
additional detail inspections on insulator units after about five years after implementation of
remedial measures. This will allow the inspectors to determine whether any acceleration in the
degradation has occurred due to the initial exposure unacceptable levels of discharge activity.
Inspection and Assessment of Porcelain and Glass Insulators
Introduction
This section will discuss porcelain suspension insulators from an inspection and assessment
perspective. Other commonly used names for suspension-type porcelain insulators are disc, bell,
or cap-and-pin type. The focus of inspections on porcelain and glass insulators is to find
damaged or deteriorated insulators that is in need for replacement. This includes insulators with
broken or cracked shells, punctured units, units with severe pin or cap corrosion and so on.
Visual Inspection
Visual inspection is considered one of the most effective methods of inspecting porcelain
suspension insulators. Conditions can be identified and compared against those identified in the
EPRI field guide report Guide to Visual Inspection of Porcelain Suspension Insulators
(1015530). In addition, recommendations are provided in the field guide concerning action to
take based on the observed conditions. Table 10-3 summarizes conditions that can be identified
using visual inspection.
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Table 10-3
Summary of Visual Inspection
Condition
Example Image
Possible Cause and Suggested
Action
Possible Cause:
Cracking of the
shell
• Cement expansion.
Suggested Action:
• Replace insulator.
Possible Cause:
Microcracking
of the shell
• Poor firing of ceramic shell during
manufacture.
Suggested Action:
• Replace insulator.
Possible Cause:
Pin corrosion
• Excessive leakage current
activity in the pin area.
Suggested Action:
• Increase leakage distance or
apply insulator with a zinc collar;
replace insulator.
Possible Cause:
Loss of pinhole
cement
• Excessive corona discharge
activity.
Suggested Action:
• Replace insulator and apply
corona rings.
Possible Cause:
Puncture
through the
shell
• Steep impulse caused by
lightning surges.
Suggested Action:
• Replace insulator.
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Table 10-3 (continued)
Summary of Visual Inspection
Example Image
Condition
Shell failure
due to corona
discharge
Possible Cause and Suggested
Action
Possible Cause:
• Excessive corona activity in the
cap area.
Suggested Action:
• Replace insulator; apply corona
ring.
Removal of
galvanizing on
the cap due to
discharge
activity
Possible Cause:
• Corona activity in the cap area;
usually occurs on discs closest to
the energized end on strings
345 kV and greater.
Suggested Action:
• If severe, replace insulator.
Visual inspections are most effective when inspectors can perform a close-up inspection with the
naked eye. This is often not possible, however, and a telescope or spotting scope with a high
level of magnification may be used (see Figure 10-20).
Figure 10-20
Example of Spotting Scope with High Magnification
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The following difficulties are encountered when performing visual inspections from a remote
position:
•
•
•
•
•
Puncture marks are not always visible.
Small microcracks are not always visible.
Poor lighting makes certain defects difficult to see.
Hardware may obstruct the view.
The level of confidence in visual inspections performed from long distances is low.
Due to large viewing distances, the use of high-powered optics is often required. This makes the
use of stable or gyro-stabilized platforms necessary, increasing the cost and decreasing the speed
of the inspection.
Corrosion of the cap-and-pin and cracks or chips in the shells of disc insulators are easily seen
by close-up inspection, but other defects such as punctures and small microcracks are sometimes
difficult to detect. Corona erosion of the cement and cracks in the shells of the discs are also
sometimes difficult to detect from a distance.
Discharge Observations
Discharge activity from a dry porcelain insulator is often indicative of a defective unit. A
cracked or punctured porcelain shell may result in discharge activity. In the case of
microcracking, discharge activity is prevalent only if moisture is present. Excessive discharge
activity in contact with the insulator’s cap and/or pin is also a concern. With time, discharge
activity will corrode or erode the metal end fitting, resulting in an electrical or mechanical
failure. Carrying out an inspection under wet or humid conditions may in some cases be
misleading, particularly in contaminated areas, for the following reasons:
•
•
It is difficult for the inspector to know whether the unit is moist and to what degree.
Moisture by itself may result in discharge activity without the presence of a defect.
These problems may be overcome by using either of the following techniques:
•
•
Inspect units under dry conditions. This will remove the concern of false alarms due to
wetting discharge activity but will not allow the identification of moisture- sensitive defects.
Inspect in the early morning after condensation has deposited on the units. The inspector will
be confident that there is moisture present.
Ultraviolet Optical Inspection
A number of technologies may be employed to perform ultraviolet (UV) inspections. Some of
these techniques are limited to use during nighttime hours; others may be used during daytime
hours. The devices are:
•
•
•
Daytime corona camera
Standard image intensifier (night goggles): nighttime only
Optimized image intensifier: dusk and nighttime only
Figure 10-21 shows examples of the three technologies.
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The EPRI report Corona and Arcing Inspection of Transmission Lines (1001910), details all
conditions that can be identified using corona inspection technology. The following are the
limitations of using UV inspection to identify defective porcelain insulator discs:
Not all defects—especially prevalent ones such as cap-and-pin corrosion—result in discharge
activity.
Dry band arcing may not be present at the time of inspection.
The technique requires a skilled operator.
•
•
•
a.
b.
c.
Figure 10-21
Examples of UV Viewing Technologies (a: Daytime Corona Camera; b: Standard Image Intensifier;
c: Optimized Image Intensifier)
Refer to Field Guide Daytime Discharge Inspection of Transmission Distribution Lines and
Overhead Substations (1013895), specifically, the section on Inspection Equipment for more
information.
In the case of monitoring for contamination issues, the use of this technology is limited—see the
report, The Feasibility of Using Daytime Corona Inspection to Identify Contaminated Insulators
That Need to Be Washed (1013675). EPRI work shows that visual discharge detection cannot be
used as an unambiguous technique for the identification of critically contaminated insulator
units unless cameras are permanently installed and monitored. However, scintillation activity or
dry band arcing observed on insulator units is a positive indication that the insulators are
contaminated enough to pose a real risk for flashovers [30]. Figure 10-22 provides a summary of
the conditions that can be identified with daytime UV technology.
Some conditions cannot be identified with UV inspection, ranging from rusted caps to chipped
discs. Figure 10-23 summarizes these.
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Figure 10-22
Summary of Conditions That Can Be Detected with Daytime UV Imaging (a, b: Damage to Cap
Due to Discharge Activity; c, d: Permanent Electrical Short Exists Between Cap and Pin;
e, f: Discharge Activity Caused by Microcrack, Noticeable During or After Wetting; g, h: Erosion
of Cement due to High Electric Fields at the Pin/ Cement Interface; i: Variation of UV Image due to
the Amount of Wetting on a Highly Contaminated Insulator Surface)
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a.
b.
Figure 10-23
Summary of Conditions that Cannot Be Detected Using Daylight UV Imaging (a: Chipped;
b: Rusted Caps)
Infrared Inspection
Infrared (IR) thermography may be used to inspect disc insulators for increases in temperature.
Because the increases in temperature are due to discharge activity, the same limitations
discussed in the previous section on UV inspection apply.
One of the limitations of IR inspection is that the temperature increases associated with most
defects have been shown to be relatively low (between 1 and 3°C). The identification of such
small temperature increases is difficult due to solar radiation and to natural heating and cooling
of the insulator; inspections performed at night to avoid solar radiation issues have yielded mixed
results. An example of a punctured disc is shown in Figure 10-24. The camcorder-size infrared
camera with a 4° telephoto lens, shown in Figure 10-25, was used to observe porcelain disc
insulators at sunset. Use of the telephoto lens was imperative during the in-service inspections.
Figure 10-24
Moderate Heating on a Shorted Disc at the Live End
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Figure 10-25
Example of an Infrared Camera Used for Inspection
The infrared camera indicates the surface temperature of an object. It is limited to comparing
relative temperatures if material emissivities are not known but can give absolute temperature
values if the emissivities of the materials inspected are known. Spot temperatures may be read
directly from the image using cursor keys on the camera. The camera also has video output
that allows images to be recorded and processed later, as well as a built-in PC memory card for
storing images. Images from the infrared camera provide less information as the distance from
the object increases. In addition, image quality decreases if observations are made when mist or
rain is present between the camera and the object viewed. For more information on infrared
inspection technologies and related issues, refer to the EPRI report Infrared Inspection
Application Guide: Overhead Transmission and Substation Components (1001915).
Remote Ultrasonic Inspection
Directional detectors for acoustic noise are commercially available and have been used
successfully in high-voltage laboratories to identify the presence of discharge activity. These
devices generally consist of a parabolic dish and a microphone that together form a directional
listening device. The device, see Figure 10-26, can detect acoustic activity over a wide
bandwidth.
Figure 10-26
A Parabolic Microphone That Can Be Used to Pinpoint Sources of Acoustic Emissions
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Practical Considerations
One of the limitations of ultrasonic inspection techniques is their inability to pinpoint the exact
location of discharge activity. This limitation can lead to confusing results; for example, an
inspector may not be able to distinguish sources of discharge activity such as a situation in
which a large amount of discharge activity is occurring on hardware (which is not a concern) or
on the insulator itself (which may be a concern). The relatively large distances that often exist
between the inspector and the components being inspected exacerbate this limitation.
Whether discharge activity comes from the insulator itself or from nearby hardware cannot be
easily determined. It is also difficult to differentiate between wetting discharge activity and a
defect on a faulty unit. Again, a possible use for such devices would be to identify the presence of
corona and define its general location on a tower. Inspectors then would have to later revisit the
tower and use different inspection techniques to determine the exact location and cause of the
discharge activity.
Environmental Considerations
The level of background noise can make these devices difficult to use. In some cases, good
results have been obtained in an indoor laboratory, but outdoor background noise rendered the
same defect undetectable.
Radio Noise Measurement
Radio noise inspection devices may be used to identify discharge activity. Because radio noise
activity is due to discharge activity, the same limitations discussed in the section on UV
inspection apply. Corona and arcing activity produce high-frequency electromagnetic waves that
may interfere with radio communications, hence the term radio interference (RI). Because
discharge activity produces electromagnetic waves over a broad spectrum of frequencies, a
directional antenna can be used with a receiver to detect the magnitude and the approximate
location of the disc