JianBin Zhou Thesis

Electrical Characteristics of Aged Composite Insulators

JianBin Zhou

September 2003

Electrical Characteristics of

Aged Composite Insulators

A thesis submitted for the degree of Masters Degree

by

JianBin Zhou, B. Eng

School of Electrical & Electronics Systems Engineering

Queensland University of Technology

September 2003

Declaration of originality The work contained in this thesis has not been previously submitted for a degree or diploma at

any other higher education institution. To the best of my knowledge and belief, the thesis

contains no material previously published or written by another person except where due

reference is made.

Signed:

Date:

Acknowledgements

The author wishes to express sincerely thanks to his principal supervisor Associate Professor

David Birtwhistle of the Electrical & Electronics Systems School of Queensland University of

Technology for his support, suggestions, and encouragement through this 3 years research.

Also the author wishes to thank his associate supervisor Dr. Greg Cash of the School of

Physical Sciences for his guidance, support, and help for this research. The author wishes to

express thanks to Professor R.S. Gorur from Arizona University, who provided valuable help

regarding new composite insulator assessment method described in Chapter 6.

Thanks are due to Mr. Ronald Penfold for his work in setting up lab for research test,

especially for the help on setting up the fog chamber in the lab. The author wishes to thank to

Dr. HePing Liu of School of Physical Sciences for performing part of the infrared emission

spectroscopy and Ms. Wen Hu of Faculty of Science for performing part of the scanning

electron microscopy analysis in the thesis.

The author gratefully acknowledges Powerlink of Queensland in funding the research and

financial support from the Electrical & Electronics School of Queensland University of

Technology for travel assistance.

Keywords:

composite insulator, electrical characteristic, aging, fog chamber, EPDM insulator, leakage

current, waveform, chemical analysis, ester/ketone ratio, oxidation index, scanning of electron

microscopy

Abstract:

Composite insulators are widely being used in power industry to alternate traditional

porcelain-based insulators for their advantages, including better pollution performance, low

maintenance cost, light weight, compact line design. However, due to the short application

history and experience, the degradation of composite insulators in natural environment is a

big concern for the power utilities. The knowledge on the degradation of composite insulators

is being studied world wide. The methods to assess the working conditions of composite

insulators are being studied and created. In Queensland University of Technology (QUT), the

approach based on chemical analysis methods was first developed. The work in this thesis

based on the previous research work is focused on correlating electrical characteristics with

chemical analysis results of the composite insulators and physical observations results. First,

the electrical characteristics of composite insulators were presented and analysed, including

leakage current, cumulative current, peaks of leakage current, the statistic results of the

leakage current. Among them, the characteristics of leakage current were mainly studied. The

shape of waveforms was found to relate to the degree of discharge activities of the composite

insulators. The waveforms analysed by FFT revealed that the odd harmonic components

became obvious during the discharge activities. The correlations between the electrical

characteristics of composite insulators and chemical analysis results showed that the

composition of composite insulators plays significant roles in terms of electrical performance.

The oxidation index (O.I.) and the ester/ketone ratio (E/K) differentiated the different

degradation reasons of the composite insulators in the test conditions. Finally, the thesis

presents one approach, which aims to assess the surface conditions of composite insulators in

an easy manner and in short time.

Publications Arising From This Thesis

J. Zhou and D. Birtwhistle, "Comparison of Electrical Performance of EPDM Composite Insulators with Chemical and Physical Indicators of Shed Material Condition", presented at Electricity Engineers' Association of NZ, Christchurch, NZ, 2002. J. Zhou, D. Birtwhistle, and G. Cash, "Chemical and Electrical Techniques for Condition Assessment of Composite Insulators", presented at The 7th International Conference on Properties and Applications of Dielectric Materials, Nagoya, Japan, 2003.

FIGURES

Figure 2-1 Section View of a Long Rod Composite Insulator 4 Figure 2-2 Section View of a Post-type Composite Insulator 4 Figure 2-3 Formation of Cross-linked Polymer 6 Figure 2-4 Chemical Structure of Polydimethyl Siloxane Polymer 7 Figure 2-5 Cause Failure Distribution 9 Figure 2-6 Degradation Process of EPDM due to Impurities 11 Figure 2-7 Scanning Electron Microscope Images of the Surface of an Aged EPDM Insulator 14 Figure 2-8 Live Line Tool for Sampling Composite Insulators 16 Figure 2-9 Diagram of the Infrared Emission Spectrometer 17 Figure 2-10 Infrared Spectrum of an Aged EPDM 19 Figure 2-11 Oxidation Index of a 275kV EPDM Aged Insulator 20 Figure 2-12 Chalking Index of an Aged EPDM Insulator 21 Figure 2-13 Expanded FTIR Spectra from the Carbonyl Region 22 Figure 2-14 Scatter Plot Relating the Oxidation Index to the Ester/Ketone Ratio of Insulators from Different Locations 25 Figure 3-1 Fog Chamber Test Systems 28 Figure 3-2 Fog Chamber 29 Figure 3-3 Plan View of the Fog Chamber 30 Figure 3-4 Control Panel Systems 31 Figure 3-5 Power Systems of the Fog Chamber Control Panel 32 Figure 3-6 Layout of the Fog Chamber and the Control Panel 32 Figure 3-7 Test System and Measurement & Protection Circuitry 34 Figure 4-1 IEC 1106 Accelerated Weather Aging Cycle under Operating Voltage 38 Figure 4-2 Classification of Leakage Current Measurement 50 Figure 5-1 Hydrophobicity Classification of EPDM Insulator in Fog Condition 56 Figure 5-2 Hydrophobicity Classification on Topside Shed of EPDM Insulator #3 57 Figure 5-3 Water Droplets on Core Surface of #3 Insulator 57 Figure 5-4 Water Droplets on Core Surface of #3 Insulator 58 Figure 5-5 Rectified Mean Values of LC (0-100hours) (#1 -#3) 59 Figure 5-6 Statistics of MVLC of the three Insulators 60 Figure 5-7 MVLC of the Three Insulators in Test 61 Figure 5-8 Waveforms of LC at Specific Time (#1-#3 Insulators) 62 Figure 5-9 SEM Images of Surface of the Insulators (#1-#3) before and after the Test 65

Figure 5-10 Mean Values of LC of Insulators in Test A 71 Figure 5-11 Cumulative Charge of LC of Insulators in Test A 71 Figure 5-12 LC Distribution of Two Composition Insulators in Test A 72 Figure 5-13 MVLC of Insulators #1- #4 in Test B 77 Figure 5-14 MVLC of Insulators #5- #8 in Test B 77 Figure 5-15 LC Distribution of the same material insulators in Test B 78 Figure 5-16 (a) LC Waveforms and FFT of #1 Insulator in Test A at Specific Time 82 Figure 5-16 (b) LC Waveforms and FFT of #3 Insulator in Test A at Specific Time 83 Figure 5-17 LC Waveforms and FFT Results of #1 Insulator in Test B at specific time 88 Figure 5-18 LC Waveforms and FFT Results of #5 Insulator in Test B at specific time 90 Figure 5-19 LC Waveforms and FFT Results of #3 Insulator in Test B at specific time 92 Figure 5-20 LC Waveforms and FFT Results of #7 Insulator in Test B at specific time 94 Figure 5-21 LC Waveforms and FFT Results of Flashovered Insulators before Flashover 99 Figure 5-22 Interval Time between Flashovers 101 Figure 5-23 SEM Images of the eight insulators after test C 103 Figure 5-24 Sequence of Discharges on Hydrophobic Silicone Rubber 109 Figure 5-25 Locations of Sampling for Chemical Analysis 110 Figure 5-26 Oxidation Index of Insulators #1 - #8 before and after the Tests 111 Figure 5-27 Ester/ketone Ratio of Insulators #1 - #8 before and after the Tests 112 Figure 6-1 Arrangement for Water Spray Test 118 Figure 6-2 Surface Conditions of sr1 before and after using Liquid Soup 120 Figure 6-3 LC Waveform of sr1 in Spray Water Test (conductivity=315S/cm with liquid soup) 121 Figure 6-4 Surface Resistance of Insulators in Spray Water with Liquid Soup 121

Figure 6-5 Thermal effect on insulator surface caused by leakage current 123

Table Table 2-1Number of Insulators that have Failed in Service 8

Table 2-2 Chemical Analysis Report of Aged Medium Voltage Insulators in Queensland 23

Table 4-1 Summary Test Methods on Composite Insulators 37

Table 4-2 Parameters of Standard 61109Test Conditions 40

Table 4-3 Overview of Discussible Parameters 40

Table 4-4 Main Characteristics of the Inert Material Used in Clean Fog Tests 41

Table 4-5 Kaolin Composition: Correspondence between the Reference Degrees of Pollution

on the Insulator and Volume Conductivity of the Slurry 42

Table 4-6 Relationship between and b 44 Table 4-7 Correspondence between the Value of Salinity, Volume Conductivity, and Density

of the Solution at a Temperature of 20C 47

Table 5-1 Parameters of Insulators (test voltage = 12kV) 53

Table 5-2 Parameters of Preliminary Test Conditions 54

Table 5-3 Distribution (number of times) of MVLC of the Three Insulators 60

Table 5-4 Chemical Analysis Results of the three Insulators before and after the Test 63

Table 5-5 Electrical Characteristics of the three Insulators 63

Table 5-6 HC and Contact Angle of Insulators before and after the Test 64

Table 5-7 Comparison of SEM Images of the three Insulators 67

Table 5-8 Test Parameters of Tests 69

Table 5-9 Parameters of Insulators of Batch I & II 70

Table 5-10 Insulators List after Test C 70

Table 5-11 LC Distribution of Two Composition Insulators in Test A 73

Table 6-1 Shape of Sample Insulators 119

Table 6-2 Configurations for Water Spray Test 119

Table 6-3 Thermal conductivity of four materials used in insulators 124

Table of Contents

CHAPTER 1 INTRODUCTION...1

CHAPTER 2 COMPOSITE INSULATORS...4

2.1 Construction & Material of Composite Insulators.........4

2.1.1 Construction4

2.1.2 Housing and Weathershed Materials..5

2.1.2.1 Introduction.5

2.1.2.2 Ethylene Propylene Diene Monomer (EPDM)6

2.1.2.3 Silicone Rubber6

2.1.3 Service Report of Composite Insulators.7

2.2 Aging of Field EPDM..10

2.3 New Condition Monitoring Techniques for Composite Insulators.13

2.3.1 Introduction..13

2.3.2 New Method to Diagnose the EPDM Insulators..13

2.3.3 Oxidation Index Analysis Method...15

2.3.3.1 Sampling.......15

2.3.3.2 Oxidation Index17

2.3.4 Chalking Index Analysis Method20

2.3.5 Ester / Ketone Ratio Index..21

2.3.6 Investigation of Aging of Medium Voltage Insulators.......22

2.4 Summary25

CHAPTER 3 DEVELOPMENT OF THE TEST EQUIPMENT..27

3.1 Literature Review..27

3.2 Fog Chamber System28

3.2.1 Fog Chamber28

3.2.2 Fog Chamber Control System..30

3.2.3 High Voltage Supply Equipment.33

3.2.4 Data Acquisition System.34

3.3 Summary.35

CHAPTER 4 REVIEW OF ELECTRICAL TESTS ON COMPOSITE

INSULATORS.36

4.1 Introduction.36

4.2 Electrical Test Standards.36

4.2.1 Introduction..36

4.2.2 IEC Standard........38

4.2.3 IEEE Standard..41

4.2.3.1 The Clean Fog Test41

4.2.3.2 The Salt Fog Test..46

4.3 Test Methodology48

CHAPTER 5 AGING TESTS ON COMPOSITE INSULATORS.52

5.1 Introduction.52

5.2 Preliminary Tests on Composite Insulators53

5.2.1 Test Introduction..........53

5.2.2 Hydrophobicity Loss on Surface of Composite Insulators..54

5.2.3 LC Measurement Results.........59

5.2.4 Comparison between Electrical Characteristics, Chemical Analysis and Physical

Analysis Results63

5.2.5 Summary.67

5.3 Electrical Tests on Composite Insulators..69

5.3.1 Test Conditions and Insulators Parameters69

5.3.2 Results of Test A.70

5.3.3 Results of Test B.74

5.3.4 Summary. .......78

5.3.5 Waveforms of LC.. ....80

5.3.5.1 Introduction ..80

5.3.5.2 Waveforms and Analysis of LC in Test A - Clean Fog Test.......80

5.3.5.3 Waveforms of LC in Test B 2.5 kg/m3 Salt Fog.......86

5.3.5.4 Waveforms of LC in Test C 5 kg/m3 Salinity Fog Test98

5.3.6 Summary.........101

5.4 Relationships between Physical, Chemical Analysis Results of Insulator103

5.4.1 SEM (Scanning Electron Microscopy) Observations of Insulator Surface103

5.4.2 Chemical Analysis Results and Comparison with Physical Observations.110

5.4.3 Discussion of the Relationships between Physical Characteristics and Chemical

Analysis Results of Composite Insulators..115

CHAPTER 6 SURFACE RESISTANCE MEASUREMENT TO ASSESS

SURFACE CONDITIONS OF COMPOSITE INSULATORS11.117

6.1 Introduction117

6.2 Leakage Resistance Assessment Using a Water Spray..117

6.2.1 Test with Water Spray.117

6.2.2 Test with Reduced Surface Tension Water.119

6.2.3 Surface Resistance of Artificially-wet Insulators120

6.3 Discussions.122

6.4 Conclusions.125

CHAPTER 7 SUMMARY...127

7. 1 Electrical Characteristics of Composite Insulators in Fog Tests.127

7. 2 Relationships between Electrical Characteristics and Surface Conditions of

Composite Insulators.129

7. 3 Future Work130

Appendix

Appendix-1 - Control Circuitry of Fog Chamber

Appendix-2 - Equivalent Circuitry of Test Transformer and Variac

Appendix-3 - Power Supply in Fog Chamber Test System

Appendix-4 - Terminal Connection of Control Panel and Fog Box

Appendix-5 - LC Waveforms and FFT Analysis of #2 & #4 Insulators in Test A

Appendix-6 - LC Waveforms and FFT Analysis of #2, #4, #6 & #8 Insulators in Test B Appendix-7 - LC Waveforms and FFT results of the Eight Insulators before Flashover in Test C

1

CHAPTER 1

INTRODUCTION

Insulators are important electrical equipment, which are installed on power transmission

towers or poles to suspend or support transmission power lines. The history of composite

insulators in application can be traced back in the late 1960s and 1970s [1]. In 1980s,

composite insulators were widely accepted as substitutes for traditional ceramic insulators [3]

[4]. The advantages of composite insulators over traditional insulators include lightweight,

better contamination performance, resistance to impact damage, particularly to gun-shot, and

the feasibility of compact line design [3].

Lightweight: This great advantage of composite insulators over porcelain reduces the weight

of insulators dramatically, and this characteristic reduces the cost of design, construction, and

maintenance of power tower and poles. In inaccessible areas, the characteristic of lightweight

of composite insulators makes it possible for helicopters to set up high voltage power towers

[5].

Resistance to damage: It is well known that porcelain insulators can be broken accidentally,

such as transportation, installation, and collision. Also vandalism is an important reason

responsible for the failure of porcelain insulators, especially by gunshots. Composite

insulators are resistant to deliberate damage and this is an important reason for power supply

companies to be fond of them.

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Compact Line Design: The characteristics of light weight of composite insulators, which

means less volume than traditional insulators, simplify and optimise the traditional power

tower design, especially on high or extra-high voltage transmission towers. The compact line

towers have been applied in Queensland on 132 kV and 275 kV power lines. Report on

reasons of selection of composite insulators suggested lighter clarifies 30% [6]. In urban

areas, the compact line design reduces the visual impact and improves the urban landscape.

Pollution Performance: The materials of sheds and sheath of composite insulators are

commonly silicone rubber (SIR), ethylene propylene rubber (EPR), or the combination of

these two materials and other materials, including fillers, anti-oxidants, colorants, UV

stabilisers. One important characteristic of SIR and EPR is hydrophobicity [7]. Compared

with porcelain insulators, which have high surface free energy, composite insulators have

lower surface free energy, which help them not easily form water films on surface. So they

provide good water resistant characteristic for insulators in moist environments. In polluted

environments, this characteristic gives composite insulators good resistance to form atom of

conductive electrolyte along insulator surfaces, which can initiate flashover process [8].

However the polymeric materials of composite insulators deteriorate with time under natural

environment and electric stress. Lifetime of composite insulators is therefore shorter in some

cases [9].

The deterioration of polymer materials of composite insulators over time is a multi-factor

aging process. The process happens in the conditions, which combine natural environmental

and electric stresses. The factors from the natural environment include: fog, ultraviolet (UV),

rain, moisture, temperature, and pollution. These factors combine electric stress in wet and

3

pollution environments resulting in the acceleration of deterioration of polymeric materials.

Studies of the fundamental mechanisms of deterioration of composite insulators in different

environments and to find efficient methods of assessing rates of deterioration of composite

insulators become necessary and urgent with development of polymeric materials. Better

understanding of deterioration of composite insulators helps power supply companies to draw

up optimising policies to manage a large number of composite insulators. Efficient, fast, low

cost, and practical assessment methods on composite insulators help power supply companies

appraise the conditions of composite insulators and avoid insulator failures during service life.

Also the conditions of composite insulators provide useful feedback information to line

designers, which let them select composite insulators with knowledge and service experience.

The objective of this thesis is to investigate how the electrical characteristics of EPDM and

EPDM/silicone rubber insulators change in laboratory test conditions, and to correlate the

electrical characteristics with results of surface analysis of EPDM and EPDM/silicone rubber

insulators. Using procedures developed over the past two years at QUT, the knowledge of

relationships between electrical characteristics and chemical analysis results supplements the

understanding of the aging process and leads to improved aging assessment methods for

composite insulators. The thesis also investigates one new technique for diagnosis of aging

conditions of composite insulator surfaces based on surface resistance measurement. The

method explores a new direction for assessment of aged composite insulators in a fast,

efficient, and economical way.

4

CHAPTER 2

COMPOSITE INSULATORS

2.1 Construction & material of Composite Insulators 2.1.1 Construction

There are two main types of composite insulators commonly used in the power industry. One

type is the suspension insulator. The other one is the post type insulator [10, 11]. A typical

suspension insulator is shown in Figure 2-1. Suspension insulators are mainly used in the

situations where insulators are in tension. Post type insulators (see Figure 2-2) are used in the

situations where there is compressive load and bending force.

Figure 2-1 Section View of a Long Rod Composite Insulator [10]

Figure 2-2 Section View of a Post-type Composite Insulator [10]

hallaThis figure is not available online. Please consult the hardcopy thesis available from the QUT Library


5

Basically, composite insulators have four main components. They are core, protective

housing, weather sheds, and end fittings. The protective housing and weather sheds of

composite insulators are made of polymeric materials. In the centre of composite insulators, a

load-bearing core carries the mechanical load. The core is composed of glass fibre and

bonded with thermosetting resin. The protective housing and weather sheds envelope the

whole core and provide environmental protection and long surface electrical creepage length.

Mental end fittings consist of malleable iron or aluminium alloy, which are compressed

around the core.

The main differences between suspension insulators and post type insulators are the design of

end fittings and the size of the core. The diameter of the core for post insulators is larger than

that of the suspension insulators due to the fact that its load is dominated by bending force.

Some other forms of composite insulators for specific applications in electrical equipment,

e.g. circuit breakers and transformers, have hollow fibreglass-reinforced core [12].

2.1.2 Housing and Weathershed Materials

2.1.2.1 Introduction

A variety of polymeric insulating materials have been used in composite insulators for

overhead lines. They include, PTFE (Teflon), epoxy resins, polyethylene, instant set polymers

based on urethane chemistry, polymer concretes, various copolymers, ethylene-propylene

elastomers [11]. In this section, ethylene propylene diene monomer (EPDM) and silicone

rubber (SIR) while as by for the most common are described in detail.

6

2.1.2.2 Ethylene Propylene Diene Monomer (EPDM)

EPDM is the copolymer of ethylene and propylene with the mixture of nonconjugated diene.

According to [13, 14], the chains of EPDM consist of randomly combined ethylene and

propylene units forming saturated polymer chains without double carbon bonds, which are

susceptible to attack by ozone and UV. A diene provides C=C double bonds capable of

forming cross-linking. The main chains without double carbon bonds possess the

characteristics of high resistance to weathering by UV and ozone [15]. The cross-linking

process of EPDM with the most common diene, ethylidene-norbornene, is shown in Figure 2-

3.

Figure 2-3 Formation of Cross-linked Polymer [13]

2.1.2.3 Silicone Rubber

Silicone rubber is based on polymers having a molecular backbone of alternate atoms of

silicon and oxygen. Some organic groups are attached to the main chains, which include

methyl, phenyl, or vinyl. The structure of silicone rubber provides properties of good

resistance to UV and ozone. One basic polymer used in silicone rubbers is shown in Figure 2-

4, which is predominantly based on linear chains of polydimethyl siloxane polymer [2].


7

There are two basic types of silicone rubbers. One is high temperature vulcanised (HTV) or

room temperature vulcanised (RTV) and the other is liquid silicone rubber (LSR). Recently

the insulator industry has introduced new materials, which are blends of EPDM polymer and

silicone rubber. The purpose is obviously to combine the rigidity characteristic of EPDM with

the hydrophobic properties imparted by silicone rubber. Apart from the base polymers, the

shed materials also include: UV stabilisers, reinforcing filler (e.g. hydrated aluminium

Al2O33H2O), tracking and erosion fillers, processing aids and colorants. The amount of base

polymers range from 10% to 90% of the net weight of the insulator.

2.1.3 Service Report of Composite Insulators

The survey by CIGRE [4] revealed that the benefits of the improved technology and the

increased use of composite insulators have led to decrease in costs of composite insulators,

which has made them competitive with conventional porcelain insulators. According to the

CIGRE survey, the main reason for selecting composite insulators was that they possess good

performance under pollution environment. Silicone occupies over 90% of weathershed

material of insulators and 4.2% composite insulators are made of EPDM.

For power industry and insulator researchers, the life expectancy of composite insulators is

the main concern in terms of application. Table 2-1 abstracted from the report [8] shows the

Figure 2-4 Chemical Structure of Polydimethyl Siloxane Polymer [2]


8

number of insulators, which have failed in service. The total number shows that rod failure is

the biggest failure reason followed by weathershed-related failures. The next reason is rod slip

out. End-fitting is the least reason to be responsible for composite insulator failures.

Table 2-1 Number of Insulators that have Failed in Service [8]

But for composite insulators under 200 kV power systems, the number of weathershed

related failures is nearly three times of the number of rod failures. This reason also came the

first in the previous report [6]. That report combined two surveys carried out by the

Southeastern Electric Exchange (SEE), USA, in 1987 and the Electric Power Research

Institute (EPRI), USA, in 1988. The two surveys covered 45,817 composite suspension

insulators across over 58 utilities and a total of 26,967 composite post type insulators used by

51 utilities. Figure 2-5 shows the reasons for deterioration according to the survey. The entire

failure rate was 0.43%, which is higher than that of traditional ceramic insulators. In the

figure, deterioration of weathershed is the major reason responsible for the failures of

composite insulators (64%). In that case deterioration includes erosion, corona cutting,

chalking, and crazing of the surfaces.

hallaThis table is not available online. Please consult the hardcopy thesis available from the QUT Library

9

It is noted that the surveys [6] included the first generation design of composite insulators, so

the result of statistics may contain the failure modes of the first generation designs and these

modes may not be characteristic of later improved designs.

There were some reports about service failure accidents of composite insulators. In 1991

Christmas period in Florida, U.S.A, the Florida Power & Light Co. suffered record number of

contamination-related outages. According to the outage investigation report [16], FPL

experienced 172 outages on overhead lines in just 9 days that was far more than the normal

level. Bad weather conditions were blamed for the outages. Under serious fog conditions,

composite insulators lost dielectric properties quickly and resulted in a wide range of

flashovers. The investigation of the incident observed that foggy weather conditions and

industry pollution were responsible for flashovers on insulators of transmission lines and

substation power equipment. These cases show the fact that under specific environments

composite insulators could show poor insulation characteristic rather than reliable

performance. Aging of composite insulators was another important factor which was involved

Figure 2-5 Cause Failure Distribution [6]


10

in the process of rapid-loss of insulation property under serious wether conditions. The

following section describes the mechanism of aging of EPDM insulator material.

2.2 Aging of Field EPDM

It is known that composite materials or polymer materials degrade with exposure in the

natural environment [15] and electrical environment [9]. Aging mechanism of composite

materials involves external and internal factors. The deterioration of composite materials

depends on how and to what extent it interacts with its surroundings. In terms of outdoor

environmental factors, the main components of the environment, which accompany

deterioration, are sunlight, temperature change, moisture, wind, dust, and pollutants. These

factors vary widely in duration, intensity and sequence. On the other hand electrical factors,

such as discharges, corona, and leakage current, etc. also play significant roles in the process

of aging [2]. The consequence of aging includes surface cracking or crazing, ablation of

surface material and exposure of insulator inner material. Aging may also cause breaching of

protective housing and even mechanical failure of the structural core. Among the factors, for

EPDM insulators, photo-oxidation is ascribed the main reason for material deterioration [17].

The following sections describe the photo-oxidation aging mechanism.

Theoretically, pure EPDM should not be affected by terrestrial ultraviolet (UV) light of

wavelength >290nm; however, experience showed that EPDM deteriorates under UV. The

research [18] revealed that polyethylene and polypropylene both are susceptible to light with

wavelength of 300nm, and terrestrial UV light with wavelength greater than 290nm was

identified as the main cause of deterioration. And the presence of impurities, such as

11

hydroperoxides and carbonyl groups, which are left from the process of manufacturing, e.g. in

the process of high temperature extrusion and injection moulding processes, initiates the

process of aging. Because catalyst residues are able to absorb sunlight, they ultimately

produce a free radical, which initiates a chain photo-oxidation process. The process is

illustrated in Figure 2-6 [17].

Figure 2-6 Degradation Process of EPDM due to Impurities [17]

(i) The impurities, which are attached to the carbon backbone of the polymer chain, absorb

the sunlight (wavelength 290nm), and produce free radicals, which are the triggers of a

chain reaction.

(ii) The presence of oxygen reacts with radical forming a peroxy radical.

(iii) The peroxy radical reacts with another polymer chain to produce another free radical and

a hydroperoxide (OOH).

(iv) The hydroperoxide absorbs UV and breaks down to produce an alkoxy radical (O) and a

hydroxy radical (OH).


12

(v) Because the hydroxy radical is very active, it reacts with another polymer chain to produce

further free radical and produces water. Electrical-driven aging on composite insulators

depends on several factors, including environment, composition of insulators, electrical field

stress, and surface condition. In terms of aging, corona and leakage current play considerable

roles which are responsible for composite insulator deterioration [18]. There are three aspects

of aging mechanism caused by corona. (1) Electrical particles impact directly on the bonds of

insulator chains. It is estimated that the energy of one electron is about 3.2 eV, while one C-C

bond binding energy is 4 eV and ionisation energy is about 10-11 eV, so there is chance that

one high energy electron could cause scissoring C-C. When this process is repeated, it leads

to the gradual degradation of the polymer. (2) High temperature on composite insulators

caused by short-period discharge activities can reach as high as 1000 C, which would lead to

disintegration of the polymer producing caves, carbon deoxidation, melt, and dissolve the

structure of composite insulators. (3) The dynamic products left by discharge activities such

as O, O2*, and O2+, react with chemical molecular of composite insulators, strengthening the

process of aging. Leakage current brings about the formation of dry band, arcing [2], and this

induces tracking on insulator surface. Tracking is irregular and random between HV and

ground. Similar to the process of discharge activities, the effect of tracking results in the

decrease of hydrophobicity of the surface of insulators, decrease in the volume resistance of

insulators, and acceleration of aging of tracking sites.

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2.3 New Condition Monitoring Techniques for Composite Insulators

2.3.1 Introduction

According to a survey [19] conducted by electricity distribution organisations in Queensland,

Australia, over 7,000 EPDM insulators have been installed in the 66-132 kV range network.

EPDM insulators currently make up 91% of the composite insulator population. The survey

shows 6% of composite insulators are made from silicone rubber, and 3% of composite

insulators are made from the mixture of EDPM and silicone. More than 13,000 medium

voltage (11-33 kV) EPDM insulators are in service across Queensland [20]. The increase in

the use of EPDM insulators in power industry requires efficient, practical, and economical

method to indicate working condition of composite insulators.

2.3.2 New Method to Diagnose the EPDM Insulators

According to Vlastos [21] EPDM composite insulators show good hydrophobicity

characteristic during the first few service years, but deteriorate after they become hydrophilic.

Vlastos and Sherif [22] found that EPDM composite insulators from a +300 kV DC test line

in Sweden flashed over less often than porcelain and glass insulators installed in the same line

during the first three years of service. Unexpectedly, composite insulators flashed over more

often than ceramic insulators during the subsequent 5 years of operation. In 1991, Florida

Power and Light suffered the most serious outages in history [16]. Accident analysis revealed

that flashovers caused by fog environment and degradation of housing of composite

insulators. Two kinds of EPDM composite insulators had worse flashover records than

normal porcelain insulators with same creepage length. From these two cases, the reduced

performance of EPDM insulators was attributed to aging of the surface of the EPDM

insulator.

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Degradation of EPDM typically happens with the process of losing hydrophobicity on

insulator surface. Accompanied by losing hydrophobicity, surface of EPDM insulator would

appear surface cracks and produce surface layer known as chalking or flouring due to natural

and electrical aging factors [21].

(a) Top View (1000) (b) Cleaved Section (1000) Figure 2-7 Scanning Electron Microscope Images of the Surface of an Aged EPDM insulator Left: surface in plan view showing surface cracking and erosion. Right: section through surface indicating a layer of loose surface material (chalking) and bulk polymer

Figure 2-4 shows surface conditions of an aged EPDM insulator using SEM (Scanning

Electron Microscope). It is clear that on surface of the aged EPDM insulator, cracks and

chalking layer formed as the results of degradation. The loose powdery surface accumulated

chalking materials and deposits on insulator surface. The explanation for this is due to

degradation on insulator surface. The oxidation process on composite insulators results in

water repellence of polymer surface decreasing from hydrophobicity to hydrophilicity. The

predominant form of oxygen exists in oxidised hydrocarbon polymers in a single oxygen

atom is bound to a carbon atom in the polymer chain through a double bond, which is known

as carbonyl (C=O). Theoretically, carbonyl is the product of oxidation process, so monitoring

its development and existence provides evidence of the existence of surface oxidation. If

15

using some technology to assess the composition of oxidation products in EPDM material, the

information on deterioration extent of EPDM insulators could be retrieved.

2.3.3 Oxidation Index Analysis Method

At QUT, researchers have developed a new method to quantify oxidation and chalking extent

for aged EPDM insulators [18, 24-27]. This method provides a simple, practical, and cost-

effective condition assessment technique for power companies to operate. The results provide

useful and reliable information related to assessing working condition of composite insulators.

It supplements the existing composite insulator assessment methods, which include visual

inspection (naked eyes and SEM), hydrophobicity classification [27], and on-line leakage

current measurement [29, 30]. The following section is the description of this method.

2.3.3.1 Sampling

The first step of this method is to take a material sample from the surface of composite

insulators. There are three sampling methods available:

Surface swabbing

For EPDM a cotton bud soaked in xylene is used to swab an area of 10 cm2 on the surface of

insulator to get suitable amount material for analysis. In this procedure traces of surface

polymer are dissolved by the xylene solvent. Some non-soluble material such as ATH fillers

and surface impurities are also removed by this method. The cotton bud is subsequently

rinsed in a bottle, which contains 0.5 cm3 of xylene. The solution that contains the dissolved

polymer material and other substance is then allowed to settle and polymer-solvent free of

16

solid material is drawn off for chemical analysis. It is noted that the swabbing process does

not damage insulators.

Surface scraping

This technique is achieved by razor blade. The amount of the shed surface for analyse is about

1 mg. Infrared absorption spectroscopy is employed to analyse the surface and get chalking

degree information.

Surface planing

This sampling method is accomplished by use of a patented hot-stick device to cut thin slivers

of surface material from sheds. The slivers area is ~3 cm2 and they are ~0.25 mm thick. The

samples are analysed by XPS to determine the composition of surface layer of material. Also

scanning electron microscopy (SEM) is used to observe the surface condition of slivers. A

live line tool has been developed to make it possible to take samples without de-energising

lines [26]. Figure 2-8 shows the line tool to get samples from live power line insulators.

Figure 2-8 Live Line Tool for Sampling Composite Insulators

Swabbing tool

Planing tool

Attached live tool

Scraping tool

17

2.3.3.2 Oxidation Index

From the surface swabbing method, the solvent contains minute traces of dissolved polymer,

which can be analysed using Fourier Transform Infrared (FTIR) spectroscopy. The oxidation

of insulator surface is determined by analysis of infrared spectrum. The theory of this method

is described as follows.

The frequency of vibration and the wavelength of absorbed or emitted radiation is

characteristic of the resonant frequency of the chemical bond, that means the vibrations of

carbonyl (C=O) bonds can be clearly different from those of sound polymer (C-H) bonds.

Researchers at QUT developed a method using infrared emission spectroscopy technique to

measure the wavelength of C=O and CH bonds from the samples which can be retrieved

from the sampling method (A). A schematic diagram of the infrared emission spectrometer

[23] is shown in Figure 29.

Figure 29 Diagram of the Infrared Emission Spectrometer [23]

Using this apparatus, polymer solvent is dropped on a 6mm-diameter platinum hotplate by 5-

10 drops. The solvent is heated by an electrically heated platinum hotplate to 120C. This


18

approach is to evaporate the xylene solvent just leaving a thin film of polymer residue on the

hotplate. As showed in the figure, a paraboloidal mirror collects the infrared light emitted by

the hot sample and the infrared light is directed into a Fourier Transform Infrared (FTIR)

spectrometer, which provides an intensity spectrum of the emitted light as a function of

wavenumber. The wavenumber is the reciprocal of wavelength and thus the unit for

wavenumber is cm1. In the spectral diagram, the height of the spectral peaks is proportional

to the concentration of the molecular structure that produces the spectral peaks. Accordingly,

the degree of polymer oxidation can be determined by counting the ratio of the magnitude of

spectral peak heights combined with carbonyl (C=O) and sound polymer (C-H). A new

concept Oxidation Index was introduced.

Oxidation Index = peak height of carbonyl (1735-1745 cm-1) / peak height of sound polymer

(1460 cm-1)

The characteristic wavenumber of carbonyl (C=O) is 1735 1745 cm-1, for sound polymer

(C-H), the characteristic wavenumber is 1460 cm-1. Figure 210 is an infrared spectrum

sample of an aged EPDM material insulator [23] and it shows the spectrum peaks used to

calculate the oxidation index.

19

Figure 210 Infrared Spectrum of an Aged EPDM [23]

The oxidation index was used to diagnose a 275 kV EPDM insulator [25], which had been in

service at a polluted site close to a power station. In Figure 211 [25], the solid diamond

points how the oxidation indices along the length of the insulator. It is clear that the maximum

oxidation index occurred at the high voltage end of the insulator. It is consistent with the fact

that the electrical stress is the highest at the high voltage end of the insulator. It is noted that

an increase trend towards to the grounded end of the insulator. Another 275 kV EPDM

insulator without energised but was installed at the same site with the same environment also

has been investigated using oxidation index. The hollow diamond is the oxidation index along

the insulator. The oxidation indices of this insulator dont change with position, and the value

of oxidation index is generally below the lowest value of oxidation index of energised

insulator. This result indicates that the increased oxidation indices are due to energization and

surface charge. Oxidation index provides a new quantitative analysis method for assessing

EPDM insulators.


20

Figure 211 Oxidation Index of a 275 kV EPDM Aged Insulator [25]

2.3.4 Chalking Index Analysis Method

Another indicator Chalking Index has also been developed for quantitatively evaluating the

amount of surface chalking. The following steps describe the approach of calculating chalking

index [24].

Scrap a small amount of the powdery surface material from degraded EPDM insulators. The

tool is suggested is a razor blade. This method is explained in 2.3.3.1(b).

Mix the sample material with 300 mg of potassium bromide powder, which is transparent to

infrared light.

Press the mixture into a 13mm diameter disk under a pressure of 10 tonnes. The result of this

step is to make a thin transparent disk with finely divided and evenly dispersed sample

material.

Using Fourier Transform Infrared (FTIR) spectrometer to get infrared absorption spectrum of

the sample.


21

Chalking Index = peak height of alumina-tri-hydroxide (1020 cm-1) / peak of height of sound

polymer(2918 cm-1)

The characteristic wavenumber for alumina-tri-hydroxide (ATH) is 1020 cm-1, and the

characteristic wavenumber for sound polymer is 2918 cm-1. Figure 2-9 is a typical FTIR

absorption spectrum from a surface scraping and KBr disc sample [25].

Figure 2-9 Chalking index of an aged EPDM insulator [25]

2.3.5 Ester / Ketone Ratio Index

Ester/Ketone ratio is defined as the ratio of the peak heights associated with the ester carbonyl

(1735 cm-1) and the ketone carbonyl (1718 cm-1) [30].

Ester/Ketone Ratio = peak height of ester carbonyl (1735cm-1) / peak of height of ketone

carbonyl (1718 cm-1)


22

Figure 2-10 [31] shows that an insulator from inland (Roma, 425 km from the sea) has a peak

at 1735 cm-1, which is the characteristic wavelength of ester carbonyl. The spectra for the

insulator from coastal (Beenleigh, 15 km from the sea; Ingham, 5 km from the sea) form a

peak at 1718 cm-1, which is the characteristic wavelength of ketone carbonyl. George [30]

explained the phenomena that for EPDM insulators, UV-induced degradation produces

carbonyl peaks that are centred on the ester group, with characteristic wavelength around

1734-1735 cm-1. While aging is mainly dominated by thermal oxidation, the carbonyl peaks

always focus on the ketone group with characteristic wavelength about 1717-1718 cm-1.The

significance of Ester/Ketone is that it explains the primary cause for EPDM aging. If the

Ester/Ketone is a high value, which indicates degradation of EPDM insulators is mainly

related to UV radiation. Whilst a low value of Ester/Ketone means the aging of EPDM

insulators is principally dominated by thermal degradation, which is strongly related to

discharge [25].

2.3.6 Investigation of Aging of Medium Voltage Insulators

A survey has been carried out using the chemical analysis methods to investigate the

condition of medium voltage insulators in Queensland [25]. Most sample insulators were

Figure 210 Expanded FTIR spectra from the carbonyl region [32]


23

EPDM and a smaller proportion of EPDM/silicone rubber blends. Table 22 lists the analysis

results.

Table 22 Chemical Analysis Report of Aged Medium Voltage insulators in Queensland [25]

(sea means the area close to sea (the Pacific Ocean) no more than 200 meters and exposed to salt spray directly. coastal refers to sites more than 200 meters but less than 100km from sea. The inland locations are 100km from sea. )

It is noted that the oxidation indices for the seaside insulators of manufacturer A are higher

than those of coastal and inland insulators of the same manufacturer. The exception is the

insulator installed at GoodnaCoastal. This insulator was installed near the Brisbane River

where fog occurs frequently. It is supposed that fog weather condition resulted in more moist

environment; therefore, this moist condition brought about more dry band phenomena which

resulted in degradation of surface of EPDM insulators. Similarly, for insulators near seaside,

salt fog spray provided suitable condition for dry band formation. This could explain why the

oxidation indices for seaside insulators are higher than those of the insulators installed at the

other locations.

For insulators from manufacturer B, the oxidation indices are significantly smaller than those

of manufacturer A in spite of the fact that the insulators were installed on the same pole.


24

According to SEM analysis, however, the insulators from manufacturer B showed more

extensive surface damage than those of manufacturer A. The thickness of degradation layer of

manufacturer A is around 10m, whereas for manufacturer B, the thickness of degradation

layer is more than 20m. For insulators from manufacturer C, the performance is the worst,

including the oxidation indices and the thickness of degradation layer. Another point is that

the insulator with blend material showed a higher chalking index than that of pure EPDM

insulators.

Figure 2-11 [31] uses ester/ketone ratios and oxidation indices to classify different insulators

into groups. This two-dimension scatter plot shows the ester/ketone ratio to the oxidation

index for insulators from manufacturer A. Several distinct groups can be identified according

to the indices. The insulators installed in the location of seaside of Miami and the insulators

from Goodna Coastal (G) show high values of oxidation index. At the same time, the

coastal insulators indicate high values of ester/ketone ratio. This can be explained by the fact

that UV at Goodna is stronger than that of Miami. Another location with strong UV radiation

and sunny weather is Roma (R); it is clear that the insulators in this area indicate higher

values of ester/ketone ratio. The insulators from Beenleigh (B) and Ingham (I) show relative

lower values of oxidation index and ester/ketone ratio. Their values overlapped each other;

maybe it is expected that the weather conditions of these two places have some extent

similarity. Summarise the chemical analysis on EPDM insulators, the following lists the

suggested end of life criteria of EPDM insulators [25].

25

Figure 211 Scatter plot relating the oxidation index to the ester/ketone ratio for insulators from manufacturer A, B [31]

The ester / ketone ration determined from the FTIR spectrum is below 0.6.

The Oxidation Index FTIR is above 0.4.

Levels of surface aluminium from XPS are above 7%.

The degradation layer is thicker than 20 m and the width of surface cracks exceeds 7 m.

2.4 Summary

This chapter introduces the innovative chemical methods to assess surface conditions of

EPDM composite insulators developed in QUT. In other literature, electrical characteristics

are widely used to assess conditions of composite insulators [33, 34]. Leakage current and

flashover voltage are two important electrical characteristics. However, the relationships

between chemical surface conditions of composite insulators and electrical characteristics are

still blank at this stage. It requires research in this area. The following chapters in this thesis

aim to do this work. The strategy is that aged EPDM insulators can be acquired by

accelerating aging on composite insulators in the laboratory. The electrical characteristics of


26

insulators can be recorded. Surface conditions of insulators can be acquired. There are

essential elements in my research. First is to design controlled test procedures. Secondly, it is

necessary to find and record proper electrical characteristics of composite insulators. Thirdly,

compare electrical characteristics of composite insulators with surface conditions to find

relationships between them.

27

CHAPTER 3

DEVELOPMENT OF TEST EQUIPMENT

3.1 Literature Review

Papers dealing characteristics of insulators with aging show that universities and research

organisations in insulator area use fog chamber to age composite insulators and characteristics

of fog chambers can be found from the publications.

The fog chamber in Ohio State University, USA, is a 1.72 m (length) by 2.44 m (width) by

1.83 m (height) high chamber with a gable roof [34]. A fog chamber with a cubic size of 2.54

m has been built in University of Windsor, Canada [35]. At Dow Corning Corporation, the

first fog chamber is a cube with 1.52 m sides and a pyramidal roof. The details of the fog

chamber are described in [36]. A fog chamber at Arizona State University is in 3.65 m (l) by

3.65 m (w) by 2.44 m (h) [37]. In Japan, a fog chamber was set up at University of

Tokushima. The size is 2 m (l) by 2 m (w) by 3 m (h) [38].

A comprehensive review on different designs of fog chambers can be found in [39]. In this

paper, the authors classify fog chambers into ranges from large size, with dimension 5 m,

medium size with dimensions between 1 m and 5 m, to small size with dimensions smaller

than 1 m.

28

3.2 Fog Chamber System

The whole fog chamber test system is composed of four parts. I - fog chamber. II fog

chamber control system. III - high voltage supply equipment. IV data acquisition system.

The following sections illustrate these parts individually. Figure 3-1 illustrates the system.

Figure 3-1 Fog Chamber Test Systems

3.2.1 Fog Chamber

Fog Chamber Test System

Fog Chamber

Fog Chamber Control System

High-voltage Test Power Equipment

Data Acquisition System

29

Developing a fog chamber is one part of my research project. After surveying other fog

chambers, a fog chamber was developed in the High-Voltage Laboratory at QUT. Figure 3-2

illustrates the outline of the fog chamber.

Figure 3-2 Fog Chamber

The body of fog chamber is made of acrylic plastic. The outline of the fog chamber is a

square case. Its size is 2000 x 2000 mm at the base and 1500 mm in height. The fog chamber

body sits on a 20-mm thick wooden board, under which there are four universal wheels that

can move the fog chamber in any direction easily. Two doors are mounted on two opposite

sides that allow operator accessing the interior of the fog chamber. Eight brass hooks are

installed on ceiling of the fog chamber allowing eight insulators to be suspended vertically. A

35 kV class bushing is in the centre of the ceiling of the fog chamber. The end-fittings of

insulators are grounded through the measurement system. Two fog boxes are installed in

diagonal position. Two funnels with an area of 78 cm2 each are installed beside the fog boxes

30

measuring precipitation rate of fog. The location of the bushing and the hooks is showed in

Figure 33.

Figure 3-3 Plan View of the Fog Chamber

3.2.2 Fog Chamber Control System

The function of fog chamber control system is to control the production of fog. Four

ultrasonic fog nebulizers are installed in two separate ancillary fog boxes attached to the main

chamber in a diagonal position. Each fog box has two ultrasonic fog nebulizers. Fog

generation speed is divided into three settings. At the maximum output rate, the fog nebulizer

consumes water 80ml per hour. Beside each fog box, there are two fans, which provide the

function of circulating fog in the fog chamber. One is installed beside of the fog box and the

other is on the floor. The locations of the fans enable circulating air avoiding to blow directly

on the insulators. One 60-litre barrel provides water for each fog box powered by a

submergible pump. In each fog box, two float switches control water level. If water level is

lower than the low-position float switch, the pump starts to work automatically,

31

supplementing water until water level reaches the position of the high-position float switch.

The high-position float switch controls pump to stop supplementing water when water reaches

the optimum height. The optimum water height is about 3.4cm above nebulizers. The two

float switches maintain the water level in the optimum range for the ultrasonic fog nebulizers.

Water in the fog chamber is collected by a water tank installed under the base of fog chamber

through a slope drain hole (diameter = 10mm) on the floor of fog chamber. Water is not

recycled. In order to drain away water in the tank, another pump is mounted outside the tank

to pump tank water into sewer. A digital thermometer in the laboratory records the ambient

temperature and humidity. A removable control panel was built outside high-voltage test zone

that isolates the operating zone from the high-voltage zone. Inside the control panel, the

secondary control power source and the control circuit board are installed. Figure 3-4 shows

control panel systems.

Control Panel

Power Supply (Figure 4-5) Control Circuit

Fan Speed Controller and Switch

Pump Speed Controller and Switch

#1 Fan

#2 Fan

#3 Fan

#4 Fan

#1 Barrel Pump

#2 Barrel Pump

Tank Pump

Nebulizer Switch

#1 Nebulizer

#2 Nebulizer

#3 Nebulizer

#4 Nebulizer

Figure 3-4 Control Panel Systems

32

Figure 3-5 Power Systems of the Fog Chamber Control Panel

Figure 3-6 Layout of the Fog Chamber and the Control Panel

Figure 3-5 illustrates power systems of the fog chamber control panel. The front-view of the

control panel is shown in Figure 3-6. The whole control circuitry is available in the Appendix-

1. Appendix-3 illustrates power supply of the fog chamber test system. Appendix-4 is the

terminal connection of the control panel and the fog box.

AC 24V

AC Power (240V)

AC 12V

DC Power

DC 12V

Fog Nebulizers

Fans

Pumps

Indicator Lights

Power Supply

Transformer (240V/24V/12V) Rectifier (240V AC/ DC )

33

3.2.3 High Voltage Supply Equipment

A 250V/19100V, 5 kVA high-voltage test transformer is employed as the power supply. An

independent power transformer, which is separated from the laboratorys lighting power

system, provides power to the high voltage test transformer. The input voltage of the testing

transformer is controlled by an autotransformer. The nameplate of the autotransformer

indicates that input/output voltage range is 240V/0-240V. A section of cable connects the

high-voltage testing transformer and the 35 kV bushing, providing power source for the test

samples in the fog chamber. The equivalent circuit of the testing high-voltage and

autotransformer (variac) is attached in the Appendix-2. Below are terms defined by IEC

60507 regarding the insulators test.

(a). Test voltage

The r.m.s value of the voltage with which the insulator is continuously energised throughout

the test.

(b). Specific creepage distance (ls) of an insulator

The overall creepage distance L of an insulator divided by the product of the test voltage and

3 , which is normally expressed in mm/ kV.

34

3.2.4 Data Acquisition System

Through a literature review, it was found that there are two main methods to monitor leakage

current. One is the direct measurement method. And the other is the indirect measurement

method. The direct measurement method is described in [35], [36]. It uses resistance to

measure voltage caused by leakage current. The indirect measurement method uses

transducers to convert current signals into voltage signals, avoiding direct contact with the

HV source [40]. Comparing these two methods, they both have their own advantages; the

direct measurement is simple, practical, and economical; while the indirect method is safer,

but expensive. They both meet the required measurement accuracy. Considering the ratio of

price / function, in this project, the direct data acquisition system was chosen as the leakage

current monitoring method. Figure 3-7 shows the whole test system and the measurement &

protection board.

Figure 37 Test System and Measurement & Protection Circuit

In the figure, the signal into the LabVIEW board is a voltage signal, and the leakage current

flows a sampling resistor forming a voltage drop, which is proportional to the current. This

35

signal is connected to the input terminals of an A/D card, which is controlled by LabVIEW

program. The input voltage range for the A/D board, 6023E, is 10V to +10V. In order to

avoid damage to the board, a back-to-back zener diode is used to limit the input voltage of the

A/D card in the range of 5V to +5V. The Data Acquisition System is based on a computer

with 233MHz CPU, 32M memory. A National Instrument Data Collection Board (6023E)

carries out the data acquisition task. It consists of a 12 bits, 16 channel Analog-Digital (A/D)

converter, which samples leakage current at the preset frequency. The data-recording program

was based on the LabVIEW program, which was designed to record leakage current of 8

insulators simultaneously. The waveforms of leakage currents can be displayed on screen.

Also waveforms of individual channel are recorded in a data file. The total sampling duration

and the sampling interval can be changed from the LabVIEW panel. The LabVIEW program

for recording the leakage current of one channel is shown in the Appendix-5.

3.3 Summary

This chapter describes the major test equipment, the fog chamber developed in QUT during

this thesis work. It comprises four parts, the body of fog chamber, the control system, the high

voltage supply system, and the data-acquisition system. The appendices include the details of

the fog chamber system.

36

CHAPTER 4

REVIEW OF ELECTRICAL TESTS ON COMPOSITE INSULATORS

4.1 Introduction Chapter-2 describes the chemical analysis methods to assess surface conditions of EPDM and

EPDM/silicone rubber insulators at QUT. Chapter-3 describes the development of the

electrical test equipment, the fog chamber. This chapter reviews the test standards and

methodology, which describe test procedures, sample preparation, test parameters, and test

procedures on composite insulators. The objective of this chapter is to produce a set of

suitable test methods, based on reasonable standards and valuable experience from other

research results, for this research project. Chapter-5 will describe test details and test results

on EPDM composite insulators, using the test methods described in this chapter.

4.2 Electrical Test Standards

4.2.1 Introduction

There are two international standards relating to this research project. IEC standard 60507

[41], Artificial pollution tests on high-voltage insulators to be used on a.c. systems is used

for testing the power frequency withstand characteristics of ceramic and glass insulators for

applications. It is applicable to systems with rated voltages ranging from 1000V to 765 kV.

37

IEC standard 61109 [42], Composite insulators for a.c. overhead lines with a nominal

voltage greater than 1000V Definitions, test methods and acceptance criteria, defines the

terms used, prescribes test methods and prescribes acceptance criteria. These two standards

are fundamental guidelines for tests in my research, especially the definitions and terms

involving the electrical tests.

R. Barsch, H. Jahn, J. Lambrecht summarised electrical test methods for composite insulators

[43]. Namely, they are: inclined plane test, arc test, modified rotating wheel dip test, salt fog

test and hydrophobicity transfer evaluation. Table 4-1 lists the main test parameters of these

tests.

Table 4 - 1 Summary of Test Methods on Composite Insulators [43]

All the test methods, except hydrophobicity classification, involve high voltage electrical

tests. The criteria for assessing working conditions of composite insulators vary with

methods. Only the inclined plane test indicates quantitative criteria for assessing insulator

degradation. It is concluded that the other tests have subjective criteria, which may lead to


38

different results from different assessors. In this thesis, the quantitative assessment method

and the other methods are combined together to assess the conditions of composite insulators.

4.2.2 IEC Standard

IEC 60507 [41] is a standard which describes aging test procedures for ceramic and glass

insulators. IEC 61109 (1992) [42] is a standard which defines aging test procedures for

composite insulators. It defines two aging test procedures, the 1000-hour salt fog test (clause

5.3) and the 5000-hour cyclic test (annex C) [44]. The 5000-hour cycle test is a multi-factor

aging test procedure, which aims to simulate the natural environment of the composite

insulators. Figure 4-1 lists the details of this multi-factor artificial aging test.

Figure 4-1 IEC 61109 Accelerated Weather Aging Cycle under the Operating Voltage [42]

In this IEC guide, insulators are subjected to repeating environment stress factors, which

include rain, fog, UV, and surrounding temperature. The duration of 5000 hours is

recommended by the standard. Perrot [45] carried out tests under this guideline, and found

good correlation between the multifactor accelerated aging test and degradation observed on

composite insulators recovered from the network in coastal areas. In another report related to

accelerating aging test carried out by Riquel [46], accelerating aging test was found effective

in producing similar degradation results to those in the real field application. Riquel induced a


39

concept named as the acceleration ratio, which is defined as the ratio of time under test to

time in the field to produce a similar level of damage. It is clear that the acceleration ratio is

dependent on the environment factor because different environment has a wide range of

effects on insulators. According to Riquel, the ratio calculated by their test is about 15 for a

coastal location in France and about 7.5 for a highly polluted coastal industrial area of France.

No other publications have found using this ratio to conduct accelerated aging tests on

composite insulators. It is concluded that aging in the environment is a very complex multi-

factor process, although some ratios could be found in laboratory, different laboratories have

different test conditions, and that would result in different effects. So it is supposed that

different areas have different so-called acceleration ratios. The application of the ratio to other

areas needs more investigation. Although the 5000-hour multifactor aging test applies more

aging factors than the 1000-hour salt fog test, the 1000-hour salt fog test is still commonly

used and accepted by manufacturers and researchers to study characteristics of composite

insulators. IEC 61109 1000-hour salt fog test involves the following main test parameters,

which is listed in Table 4-2.

40

T

S

Table 4-2 Parameters of Standard 61109 Test Conditions [42]

In this test guide, the evaluation criterion is numbers of flashovers (not more than three

overcurrent trip-outs for each specimen tested) and the visual examination of degradation

(no tracking, erosion does not reach the glass fibre core, sheds are not punctured, core is not

visible). However, according to Gutman, some test parameters in this test and test criteria are

doubtfully specified, questionable, or not specified at all [47] [44]. Table 4-3 lists these

points.

Table 4-3 Overview of Discussible Parameters [47]

4.2.3 IEEE Standard



41

Besides IEC standards, IEEE also provides a relevant test standard, IEEE Standard

Techniques for High-Voltage Testing [48]. It mainly applies to ceramic and glass insulators.

It defines some common parameters as in IEC 60507. In this standard, it also defines two

testing environments, the clean fog test and the salt fog test. The following section introduces

these two tests.

4.2.3.1 The Clean Fog Test

4.2.3.1.1 Preparation

In the clean fog test, a contamination layer is applied to the insulator surface using slurry

consisting of water, an inert material, such as kaolin, and an appropriate amount of sodium

chloride (NaCl). The amount of NaCl is determined by the required salt deposit density (Sdd)

or layer conductivity. The slurry composition consists of:

(i) 40 g kaolin

(ii) 1000 g tap water

(iii) suitable amount of NaCl of commercial purity

Table 4-4 lists main characteristics of the inert materials used for contamination purpose.

W

Table 4-4 Main characteristics of the inert material used in clean fog tests [48]

1 conductance (20 C)


42

Before the insulators are subjected to slurry contamination, they are required to be processed

in the following steps: (a) To be cleaned by scrubbing the insulation surfaces with an inert

material, e.g. kaolin. (b) To be thoroughly rinsed with clean water. After the above process,

the samples are ready for contamination. Before applying high voltage on test samples, two

kinds of surface condition, dry and wet, are applied. In both cases, the standard recommends

that the test starts at the same time as the start of fog generation. The fog around the test

objects in chamber must be uniform and the temperature rise of fog chamber must not exceed

15C by the end of test. The desired volume conductivity of the contamination is reached by

adjusting the amount of salt in the slurry. Also, as a guide, the IEEE standard gives a

correspondence between the reference degree of pollution on the insulator and the volume

conductivity. (It is noted that the temperature of the slurry mentioned in the table is 20 C)

Table 4-5 Kaolin composition: correspondence between the reference degrees of Pollution on the insulator and volume conductivity of the slurry [48]

4.2.3.1.2 Application of the contamination layer

After cleaning the dry insulators following the steps described in the above section, the next

step is to use contamination slurry (described as the Contamination) to contaminate the


43

insulators. Two methods are recommended for applying the contamination layer: using spray

nozzles or commercial-type spray guns. With the latter one, a distance of 20-40cm between

insulators and spray mouth is recommended by the standard. The purpose of this is to obtain a

reasonably uniform pollution layer. After spraying, the layer is left to dry prior to

commencement of the test.

To determine the conductivity of the contamination layer on insulators, this IEEE standard

describes one method, which defines the degree of contamination by salt deposit density or

layer conductivity. The following steps describe how to measure the salt deposit density Sdd.

Remove carefully the deposit on the surface of a separate insulator. This insulator must be

identical to the tested insulator and have been subjected to the same contaminating process.

Dissolve the deposit in a known quantity of water, preferably demineralised water.

Stir the mixture of water and the deposit for at least 2 minutes.

Measure the volume conductivity at the ambient temperature (C).

The value 20(ambient temperature=20C) is calculated using the following formula:

20= * [1 b ( 20)] (1)

where

20 is the layer conductivity at a temperature of 20 C (in S/m)

is the volume conductivity measured at the ambient temperature of C (in

S/m) is the temperature of the insulator surface (in C)

b is a factor depending on temperature, as given in Table 4-6:

44

Table 4-6 Relationship between and b [50]

The salinity, Sa ( in kg/m3 ), of the slurry is determined using the formula:

Sa = (5.7 20) 1.03 (0.004 20 0.4 S/m) (2)

The Salt Deposit Density, Sdd, is then determined using the formula:

Sdd = ASaV (3)

where V is the volume of the slurry (in cm3)

A is the area of the cleaned surface (in cm2)

The layer conductivity is determined by the following formula.

The layer conductivity (K) = the layer conductance measured on the unenergized insulator F

F = L dllp0

)](/1[ (4)

where F is the form factor

p ( l ) is the circumference at partial creepage distance l along the surface

L is the total creepage distance

dl is the increment of integration

4.2.3.1.3 Test procedure


45

In IEEE standard, two alternative test procedures are proposed. Basically the procedures

differ in the conditions of the pollution layer, which is dry or wet when the test voltage is

applied.

(a) Dry before energisation

After preparation described in above section, insulators are put into fog chamber with the

condition of dry contamination layer. The IEEE standard suggests that under the ambient

temperature, the steam input rate shall be within the range of 0.05 0.01 kg/h per cubic meter

of the fog chamber volume. Fog is applied when the test voltage is applied to the insulators.

(b) Wet before and during energisation

This method requires that the prepared insulators are put into fog chamber, which is filled

with fog. The fog generation rate must be sufficient to ensure that the surface conductivity of

insulators reaches the maximum value in 20-40 minutes from the start of fog generation at the

ambient temperature. The maximum value of conductivity is assumed as the reference layer

conductivity. When the maximum conductivity is achieved, the test voltage is applied.

4.2.3.1.4 Test objective

The IEEE standard defines the withstand test and the acceptance criterion as follows [48].

The objective of this test is to confirm the specified withstand degree of contamination at the

specified test voltage. The insulator complies with this specification if no flashover occurs

during three consecutive tests performed in accordance with Procedures.

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4.2.3.2 The Salt Fog Test

4.2.3.2.1 Preparation

In this test, insulators are subjected to salt fog, which is produced by salt water solution. The

contamination degree is defined by specified salinity of the salt water solution. Before the

test, the insulator surface is cleaned by the solution whish is mixed with water and neutral

detergent, such as trisodium phosphate (Na3PO3). And then the insulators are cleaned by tap

water. The last step allows the insulators to dry out in the natural environment. After finishing

these steps, the insulators are ready for the test. The test voltage is supplied when the fog

generation system starts.

4.2.3.2.2 Salt solution

The salt solution consists of sodium chloride (NaCl) of commercial purity and tap water.

IEEE standard lists the following salinity to be used in test: 2.5 kg/m3, 3.5 kg/m3, 5 kg/m3, 7

kg/m3, 10 kg/m3, 14 kg/m3, 20 kg/m3, 28 kg/m3, 40 kg/m3, 56 kg/m3, 80 kg/m3, 160 kg/m3, or

224 kg/m3. The salinity is decided by measuring the conductivity or by measuring the density

with a correction of temperature. The following Table 4-7 lists the correspondence between

the value of salinity, volume conductivity, and density of the solution at a temperature of 20

C.

47

Table 4-7 Correspondence between the Value of Salinity, Volume Conductivity, and Density of the Solution at the Temperature of 20C [48]

If the solution temperature is not 20C, the conductivity and density should be corrected by

the following formula,

20 = [1 + (200 + 1.35 Sa) ( 20) 10 6] (5) where

20 is the density at a temperature of 20 C (in kg/m3)

is the density at a temperature of C (in kg/m3)

Sa is the salinity ( in kg/m3 ) - see formula (2)

is the solution temperature (in C)

4.2.3.2.3 Conditions before starting the test

Before the test, the insulators should be prepared according to 4.2.3.2.1. When the test voltage

is applied, the surface of the insulators should be wet. Additionally, the ambient temperature

should be in the range of 5C to 40C and the difference between the water solution and the

ambient temperature should be no more than 15C.


48

4.2.3.2.4 Test procedure

The IEEE standard states that the objective of the salt fog test is to show whether samples will

withstand the application of test voltage, that is to confirm the specified withstand salinity of

the insulator at the specified test voltage. The acceptance criterion for the withstand test is

described as follows: The insulator complies with this standard if no flashover occurs during

a series of three consecutive tests in accordance to the procedure in withstand test. If only one

flashover occurs, a fourth test shall be performed and the insulator then passes the test it no

flashover occurs.

4.3 Test Methodology

After reviewing test guidelines, this section describes the test methodology for my research

project. The objective of this section is to determine the suitable electrical test parameters and

electrical characteristics based on the previous sections.

The significant factors influencing the electrical performance of composite insulators are the

decrease of hydrophobicity and material aging due to electrical and environmental stresses.

When a number of factors, such as UV, moist, corona, salty fog, etc., affect composite

insulators simultaneously, surface degradation on composite insulators could develop

considerably. From the electrical point of view, the electrical characteristics of composite

insulators may change dramatically during the aging process. In terms of electrical

characteristics, leakage current, partial discharge, corona, dry-band, and flashover, are typical

49

parameters to study the aging process of composite insulators [49] [29]. These electrical

characteristics can be measured or studied in the field [28] [51] or under laboratory test

conditions [51]. Among these electrical characteristics, leakage current is treated as one

typical parameter to represent surface conditions of composite insulators. Fernando and

Gubanski [49] summarised a review of leakage current measurement on composite insulators.

In the conclusion, the authors gave the following directions for future work on composite

insulators:

However, knowledge of the correlation between the parameters of the leakage current

(current level, harmonic content and accumulated charge), and the state of the insulator

surface (contamination level, hydrophobicity and aging) on the other side, is not yet complete.

More work is needed to elucidate the above mentioned relations and, therefore, create a basis

for broader use of LC measurements in practical situations.

Figure 4-2 shows the methods of measuring leakage current on composite insulators. They

contain the site measurement and the laboratory test measurement.

50

Figure 4-2 Classification of Leakage Current Measurement [49]

Gorur, etc. [52] presented leakage current measurements for EPDM and silicone composite

insulators in the clean fog environment and the salt fog environment. The composite

insulators were selected from different ranges: energized at field, field not energized, and kept

indoors with plastic bags. The ones kept indoors are treated as reference for comparing the

results. The leakage current measurement was carried out three times. The first time is

immediately after receiving insulators from the field; the second measurement was done

following the surface wetting of insulators, and the third time is carried out after the DC

flashover tests. For EPDM insulators, the results showed that the EPDM insulators kept

indoors without energized history showed low leakage current, whereas the EPDM insulators

which are

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