polluted conditions

158 POLLUTED INSULATORS : A REVIEW OF CURRENT KNOWLEDGE

Task Force 33.04.01

June 2000

POLLUTED INSULATORS : A REVIEW OF CURRENT KNOWLEDGE

PREPARED BY Task Force 33.13.01 (formerly 33.04.01) of Working Group 33.13 (DIELECTRIC STRENGHT OF INTERNAL AND EXTERNAL INSULATION)

MEMBERS OF TASK FORCE 01 OF WORKING GROUP 33.04 : D.A. SWIFT (Convenor, United Kingdom), J.P. REYNDERS (Secretary, South Africa), C.S. ENGELBRECHT (Compiler of documents, South Africa), J.L. FIERRO-CHAVEZ (Mexico), R. HOULGATE (United Kingdom), C. LUMB (France), R. MATSUOKA (Japan), G. MELIK (Australia), M. MORENO (Mexico), K. NAITO (Japan), W. PETRUSCH (Germany), A. PIGINI (Italy), G. RIQUEL (France), F.A.M. RIZK (Canada)

TABLE OF CONTENTS 1.

INTRODUCTION.............................................................................................................................................................. 1 1.1 1.2 1.3 1.4 1.5

2.

THE POLLUTION PROBLEM ............................................................................................................................................ 1 PREVIOUS REVIEW DOCUMENTS .................................................................................................................................... 1 RELEVANCE OF IEC 815 (1986) ................................................................................................................................... 2 INSULATOR TYPES AND DEFINITIONS OF SPECIFIC CREEPAGE LENGTH & SPECIFIC AXIAL LENGTH............................... 2 APPROACH FOR INSULATOR SELECTION AND DIMENSIONING ......................................................................................... 3

POLLUTION FLASHOVER PROCESS......................................................................................................................... 5 2.1 INTRODUCTION ............................................................................................................................................................. 5 2.2 MODELLING .................................................................................................................................................................. 6 2.2.1 Hydrophilic surface ............................................................................................................................................. 6 2.2.2 Hydrophobic surface.......................................................................................................................................... 10 2.3 ENVIRONMENTAL ASPECTS......................................................................................................................................... 10 2.3.1 Climates or atmospheric variables and typical environments ........................................................................... 10 2.3.2 Type of pollution ................................................................................................................................................ 13 2.3.3 Mechanisms of contamination accumulation on insulators............................................................................... 21 2.3.4 Mechanisms of wetting....................................................................................................................................... 24 2.3.5 The natural cleaning processes.......................................................................................................................... 29 2.3.6 Critical wetting conditions................................................................................................................................. 29 2.3.7 Effect of various aspects of the insulator on its pollution accumulation ........................................................... 29 2.3.8 Physical and mathematical models of pollution deposit.................................................................................... 33 2.4 ICE AND SNOW ............................................................................................................................................................ 33 2.4.1 Flashover on insulators covered with ice. ......................................................................................................... 34 2.4.2 Flashover on insulators covered with snow....................................................................................................... 35

3.

INSULATOR CHARACTERISTICS ............................................................................................................................ 37 3.1 INTRODUCTION ........................................................................................................................................................... 37 3.2 MATERIALS USED FOR OUTDOOR INSULATORS ............................................................................................................ 38 3.2.1 Porcelain and glass............................................................................................................................................ 38 3.2.2 Polymers ............................................................................................................................................................ 38 3.3 INSULATOR PERFORMANCE ......................................................................................................................................... 39 3.3.1 Ceramic insulators............................................................................................................................................. 40 3.3.2 Polymeric Insulators .......................................................................................................................................... 50 3.3.3 Effect of insulator orientation. ........................................................................................................................... 52 3.3.4 Influence of a non-uniform pollution deposit..................................................................................................... 56 3.3.5 Electric field at the surface of insulators ........................................................................................................... 57 3.3.6 Cold switch-on and thermal lag......................................................................................................................... 59 3.3.7 Contaminated insulators under transient overvoltages ..................................................................................... 59 3.3.8 Air density correction factors for polluted insulators ........................................................................................ 68 3.3.9 General trends for ice covered insulators.......................................................................................................... 69 3.3.10 General trends for snow covered insulators ...................................................................................................... 71 3.4 SPECIAL INSULATORS .................................................................................................................................................. 73 3.4.1 Hollow insulators............................................................................................................................................... 73 3.4.2 HVDC wall bushings.......................................................................................................................................... 75 3.4.3 Circuit breaker and isolator insulation.............................................................................................................. 75 3.4.4 Insulators in desert conditions........................................................................................................................... 76 3.4.5 Semiconducting Glaze insulators....................................................................................................................... 76 3.5 CONCLUSIONS ............................................................................................................................................................. 77

4.

ENVIRONMENTAL IMPACT ...................................................................................................................................... 80 4.1 4.2 4.3 4.4

VISIBLE DISCHARGES .................................................................................................................................................. 80 AUDIBLE NOISE ........................................................................................................................................................... 80 RADIO INTERFERENCE ................................................................................................................................................. 81 TELEVISION INTERFERENCE ........................................................................................................................................ 82

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4.5 4.6 4.7 4.8 5.

CORROSION OF METAL HARDWARE - TELEVISION INTERFERENCE................................................................................ 82 CRITERIA FOR RADIO NOISE LIMITS OF INSULATORS..................................................................................................... 83 CORROSION OF METAL HARDWARE - MECHANICAL STRENGTH REDUCTION ................................................................. 84 FIRES .......................................................................................................................................................................... 85

POLLUTION MONITORING ....................................................................................................................................... 87 5.1 INTRODUCTION ........................................................................................................................................................... 87 5.2 AIR POLLUTION MEASUREMENT .................................................................................................................................. 88 5.2.1 Directional dust deposit gauge .......................................................................................................................... 88 5.3 EQUIVALENT SALT DEPOSIT DENSITY (ESDD)............................................................................................................. 89 5.3.1 Advantages......................................................................................................................................................... 89 5.3.2 Disadvantages.................................................................................................................................................... 89 5.3.3 Further developments ........................................................................................................................................ 89 5.4 NON-SOLUBLE DEPOSIT DENSITY (NSDD) .................................................................................................................. 90 5.4.1 Optical measurement ......................................................................................................................................... 90 5.5 SURFACE CONDUCTANCE ............................................................................................................................................ 90 5.5.1 Advantages......................................................................................................................................................... 90 5.5.2 Disadvantages.................................................................................................................................................... 90 5.5.3 Further developments ........................................................................................................................................ 90 5.6 INSULATOR FLASHOVER STRESS .................................................................................................................................. 91 5.6.1 Advantages......................................................................................................................................................... 91 5.6.2 Disadvantages.................................................................................................................................................... 91 5.7 LEAKAGE CURRENT .................................................................................................................................................... 91 5.7.1 Surge counting ................................................................................................................................................... 92 5.7.2 I highest.................................................................................................................................................................. 92 5.8 CONCLUSIONS ............................................................................................................................................................. 92

6.

TESTING PROCEDURES FOR INSULATORS ......................................................................................................... 93 6.1 INTRODUCTION ........................................................................................................................................................... 93 6.2 CATEGORIES OF TEST METHODS .................................................................................................................................. 93 6.2.1 Testing under natural pollution conditions........................................................................................................ 93 6.2.2 Artificial pollution laboratory tests.................................................................................................................... 95 6.3 TEST PROCEDURES FOR PORCELAIN AND GLASS INSULATORS TO BE USED IN HIGH-VOLTAGE A.C. OR D.C. SYSTEMS ... 95 6.3.1 Standardised test procedures ............................................................................................................................. 95 6.3.2 Non-standardised test procedures...................................................................................................................... 96 6.3.3 Non-standardised test procedures for laboratory tests on naturally polluted insulators .................................. 98 6.4 TEST PROCEDURES FOR POLYMERIC INSULATORS TO BE USED IN HIGH-VOLTAGE A.C. OR D.C. SYSTEMS..................... 98 6.5 TEST PROCEDURES FOR INSULATORS COVERED WITH ICE OR SNOW............................................................................. 98 6.5.1 Laboratory test methods with ice ....................................................................................................................... 98 6.5.2 Laboratory test methods with snow.................................................................................................................. 100 6.6 ADDITIONAL INFORMATION ON PARTICULAR POINTS OF POLLUTION TESTING ............................................................ 100 6.6.1 Ambient conditions during testing ................................................................................................................... 100 6.6.2 Leakage current measurement ......................................................................................................................... 103 6.6.3 Testing of insulators for the UHV range up to 1100 kV................................................................................... 104 6.6.4 Comparison of test results obtained with different pollution test methods ...................................................... 104 6.6.5 Comparison of test results obtained from test stations .................................................................................... 104

7.

INSULATOR SELECTION AND DIMENSIONING ................................................................................................ 106 7.1 INTRODUCTION ......................................................................................................................................................... 106 7.2 SELECTION OF INSULATOR CHARACTERISTICS .......................................................................................................... 106 7.2.1 Selection of profile ........................................................................................................................................... 107 7.2.2 Selection of insulator dimensions..................................................................................................................... 107 7.2.3 Deterministic method ....................................................................................................................................... 108 7.2.4 Probabilistic method. ....................................................................................................................................... 108 7.2.5 Static and dynamic methods in the probabilistic approach. ............................................................................ 109 7.2.6 Present status of the probabilistic approach.................................................................................................... 110 7.2.7 Dynamic method .............................................................................................................................................. 113 7.2.8 Truncation of the distribution .......................................................................................................................... 114 7.2.9 Conclusions...................................................................................................................................................... 115

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7.3 SELECTION OF INSULATORS FOR APPLICATION UNDER ICE AND SNOW ....................................................................... 115 7.4 SELECTION OF INSULATORS FOR D.C. ENERGISATION................................................................................................. 116 7.4.1 Introduction ..................................................................................................................................................... 116 7.4.2 Selection of a site severity correction factor.................................................................................................... 116 7.5 INSULATOR POLLUTION DESIGN OF PHASE-TO-PHASE SPACERS ................................................................................ 117 7.5.1 Introduction ..................................................................................................................................................... 117 7.5.2 Design Practice................................................................................................................................................ 117 8.

PALLIATIVES AND OTHER MITIGATION MEASURES .................................................................................... 118 8.1 INTRODUCTION ......................................................................................................................................................... 118 8.2 MAINTENANCE PROCEDURES .................................................................................................................................... 118 8.2.1 Live-insulator washing of ceramic insulators.................................................................................................. 118 8.2.2 Live-insulator washing of polymeric insulators............................................................................................... 128 8.3 USE OF GREASES AND RTV COATINGS ...................................................................................................................... 129 8.3.1 Introduction ..................................................................................................................................................... 129 8.3.2 Hydrocarbon and silicone greases .................................................................................................................. 129 8.3.3 RTV rubber coatings ........................................................................................................................................ 130 8.3.4 Summary .......................................................................................................................................................... 130 8.4 BOOSTER SHEDS ....................................................................................................................................................... 131 8.5 METHODS FOR INCREASING INSULATOR RELIABILITY UNDER ICE AND SNOW CONDITIONS ......................................... 132 8.5.1 Some measures to prevent flashovers during ice conditions............................................................................ 132 8.5.2 Some measures to prevent flashovers during snow conditions ........................................................................ 133

9.

THERMAL EFFECTS OF CONTAMINATION ON METAL OXIDE ARRESTERS (MOA) ............................ 134 9.1 INTRODUCTION ......................................................................................................................................................... 134 9.2 OPERATIONAL EXPERIENCE AND FIELD TESTS .......................................................................................................... 134 9.3 ARTIFICIAL POLLUTION TESTS OF LIGHTNING ARRESTERS ........................................................................................ 135 9.3.1 Test Techniques................................................................................................................................................ 135 9.3.2 Laboratory Test Results ................................................................................................................................... 135 9.4 STANDARDISATION OF A LABORATORY TEST ............................................................................................................ 139

10.

ADITIONAL INFORMATION AND RESULTS ................................................................................................... 142

10.1 INSULATOR PROFILES AND DIMENSIONS .................................................................................................................... 142 10.2 RANKING OF INSULATORS ......................................................................................................................................... 158 10.2.1 Ceramic Insulators........................................................................................................................................... 158 10.2.2 Polymeric insulators ........................................................................................................................................ 162 10.3 INSULATOR PERFORMANCE AS A FUNCTION OF POLLUTION SEVERITY ....................................................................... 164 10.4 AGEING OF INSULATORS ........................................................................................................................................... 165 11.

REFERENCES........................................................................................................................................................... 1 67

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1. INTRODUCTION 1.1 The Pollution problem The performance of insulators used on overhead transmission lines and overhead distribution lines, and in outdoor substations is a key factor in determining the reliability of power delivery systems. The insulators not only must withstand normal operating voltage, but also must withstand overvoltages that may cause disturbances, flashovers and line outages. The reduction in the performance of outdoor insulators occurs mainly by the pollution of the insulating surfaces from air-borne deposits that may form a conducting or partially conducting surface layer when wet. The presence of a conducting or partially conducting layer of pollution on the insulator surface will dictate flashover performance. It is impractical in many situations to prevent the formation of such a layer and consequently insulators must be designed so that the flashover performance remains high enough to withstand all types of anticipated voltage stresses despite the presence of the pollution layer. In certain situations where pollution is extremely severe, further preventative or curative measures - such as periodic washing or greasing - may be necessary. It is clear that the environment, in which the insulator must operate, together with the insulator itself, will determine the severity of the pollution layer on the insulator. Translating the environment into parameters that can be used to design the insulation, therefore, presents one of the fundamental problems in designing external insulation with respect to polluted conditions. This is due to the vast range of possible conditions such as those found in coastal, industrial, agricultural and desert areas; also in areas with ice and snow or at high altitude. Combinations of these conditions may also occur. A further complicating factor is that environments have an inherent statistical behaviour that is to a large extent unpredictable. Furthermore, the increase of available electrical energy in an area, through the construction of a new substation, may trigger industrial growth that can contribute to the pollution and affect thus the behaviour of the insulation. It is, therefore, difficult to quantify the effect of the environment on insulator performance. This document attempts to address these problems by serving as a review of current knowledge on insulator pollution with the intention of providing information for the selection and maintenance of insulators in polluted environments. A very extensive list of references is provided. It is recognised that ageing may influence the performance of insulators, particularly in the case of polymer insulators. However, this report is restricted to discussing the pollution performance of insulators, since Cigré Study Committees 15 and 22 are mandated to deal with material and insulator ageing.

1.2 Previous review documents The first large-scale review of pollution effects on insulators was published in 19711. That document describes theories of the flashover process as well as artificial and natural test methods for assessing insulator performance in pollution conditions. Various parameters that influence insulator performance, such as surface conductance and insulator dimensions, are also discussed. Furthermore, several methods for measuring pollution severity are described and preventative procedures such as greasing are reviewed. In 1979, a major review on insulator pollution was published as two separate reports: one on the measurement of pollution severity2 and the other as a critical comparison of artificial pollution test methods3. The report on pollution severity measurement analysed the main methods in use in terms of the pollution flashover process. The conclusion was that there is no single best method but rather that the best results are obtained when several methods are used in parallel. Factors pertaining to the equipment - i.e. cost, availability, etc. - and the power delivery system - i.e. extent, voltage level and type, etc. - were identified as being important for selecting a pollution site severity measurement method. It was noted that the cost of optimisation also should be weighed against the cost of a detailed site severity assessment before such measurements are undertaken. The report on artificial pollution test methods gave an analysis of available test methods with the intent of indicating which methods are best suited for international standardisation. This report also recommended the natural conditions best represented by each test method. Another report4 combined the experience of electric utilities, manufacturers, and research laboratories in a comprehensive summary on the design and maintenance of outdoor insulators in polluted environments. In addition to providing a description of the flashover process, this report also contains discussions on pollution severity measurement, test procedures, design practice, and maintenance procedures.

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1.3 Relevance of IEC 815 (1986) The present edition of IEC Publication 815 (1986)5 is based on knowledge obtained mainly from experience with conventional porcelain and glass insulators on a.c. systems. It applies only to these insulators, and only when they are used in a.c. applications. Minimum specific creepage distances are specified in this document for different pollution severity levels. These pollution severity levels do not consider all aspects of the environment that can affect the performance of various insulator profiles. Apart from some restrictions on insulator profile and corrections for diameter, IEC 815 thereby implies that no other factors need to be considered when designing insulators for use in polluted conditions. It is now recognised that a broader approach for insulator design and selection is required to address the optimised design of porcelain and glass insulators as well as polymeric insulators for a.c. and d.c. systems world-wide. Other areas where IEC 815 lacks information have been identified. This review document is based on the following list of areas where IEC 815 is perceived to be weak, and where input is needed for its revision: • Performance of polymeric insulators • Insulator orientation • Extension of applicability to voltages above 525 kV a.c. • Design for d.c. application • Insulators with semiconducting glaze • Surge arrester housing performance, particularly with reference to polymeric materials • Longitudinal breaks in interrupter equipment • Radio interference, television interference, and audible noise of polluted insulators • Effect of altitude • Effect of heavy wetting The revision of IEC 815 was started in 1998 and it is expected that the work will be completed by the end of the year 2005. The revision will appear as five parts under the number ‘IEC 60815’.

1.4 Insulator types and definitions of Specific Creepage Length & Specific Axial Length For the purpose of this document, insulators are divided into the following four broad categories: 1. Ceramic insulators for a.c. systems 2. Polymeric insulators for a.c. systems 3. Ceramic insulators for d.c. systems 4. Polymeric insulators for d.c. systems. Ceramic insulators have an insulating part manufactured either of glass or porcelain, whereas polymeric insulators have a composite insulating part consisting of a polymer housing such as Silicone Rubber (SR), Ethylene Propylene Diene Monomer (EPDM) and others, fitted onto a glass fibre core. In Section 10, details are given of some of the available types of insulators. The tables presented therein are used throughout this document to identify insulators and provide data for analysis. For the purpose of this review, the electrical stress over an insulator is considered in two ways; one is related to the leakage path length and the other to the axial length of the insulator. In IEC 815, the leakage path of an insulator is specified by the ‘Specific Creepage Distance’ defined as the leakage distance of the insulator in mm divided by the maximum system phase-to-phase voltage in kV. The Leakage Distance is defined as the shortest distance, from on end of the insulator to the other, along the surface of the insulating parts. In this document, the Specific Creepage Length (SCL) defined as the Leakage Distance of the insulator divided by the actual voltage across the insulator - i.e. the phase-to-ground voltage in most instances. The corresponding Specific Axial Length (SAL) of an insulator is defined as the axial length of the insulator divided by the actual voltage across the insulator. The axial length refers to the shortest distance between fixing points of the live and

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earthed metalware, ignoring the presence of any stress control rings, but including intermediate metal parts along the length of the insulator - as is shown in Figure 1-1.

Axial Length

Figure 1-1: Definition of axial length of an insulator as is used in this review.

1.5 Approach for insulator selection and dimensioning The process of insulator selection and axial dimensioning together with its influencing parameters is shown in Figure 1-2. The flow chart in this figure forms the basis of this review document for which an overview is given below. The process of insulator selection starts with the collection of the basic data consisting of information on: 1. 2. 3. 4. 5. 6.

Insulator application Insulator characteristics Power system parameters The environment Constraints. Field performance

1. The application of the insulator is an important aspect from the pollution performance viewpoint as it determines both the radial dimension and the orientation of the insulator. Section 3 addresses the application of insulators under a variety of headings. 2. An integral part of the basic data is the characteristics of the available insulators. These are discussed throughout this report, but especially in Section 3. Information may also be obtained from manufacturers. 3. Power system parameters that form part of the basic data consist of: • The electrical environment in which the insulator is applied, i.e. a.c. or d.c. voltage; maximum system voltage; and lightning, switching and temporary overvoltages and their effects on insulator performance. These aspects are comprehensively addressed in Section 2.2 and Section 3. • The performance required from the insulator. This is determined mainly by power quality criteria such as the power system’s sensitivity to outages. 4. Each environment where the insulators are to be installed has a different set of conditions under which the insulator must operate reliably. An insulator that has a good performance under one set of conditions might have a bad performance in a different set of conditions. It is therefore necessary to characterise the environment in terms specific to insulator performance. In Section 2.3, the environmental aspects and how they affect the pollution flashover process are discussed. Methods to monitor the environment are described in Section 5. 5. Constraints may also influence the selection of insulators. For example, limitations on the width of the right of way may dictate the use of structures for which special insulator designs are required. In such cases, the range of available insulators may be restricted. Cost and the need to minimise the visual impact may also be important factors that have to be built into the selection process. 6. Field performance of insulators in service is an invaluable source of data for future applications. Unfortunately, these data are not always available, and, as noted earlier, their applicability to different environments must always be questioned. Nevertheless, service experience is usually a very important component of the basic data since it forms the basis for determining whether the selection of a particular insulator leads to acceptable performance. Service experience also may indicate whether certain artificial pollution tests are appropriate for a specific environment, and it may also contribute information on insulator characteristics.

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Methods to assess insulator field performance are given in Section 5. References to service experience are given throughout the document, but especially in Sections 2 and 3. 2) Insulator Characteristics

3) Power System parameters

4) Environment

5) Constraints

6) Insulator field performance

Basic data

Alternative solutions

1) Insulator application

Field tests necessary?

No

Yes

Field test station Test program Lab tests necessary ?

Yes

Representative Test technique

No

Test results

Lab testing

Test results Insulator monitoring

Design Procedure

Yes

Deterministic ?

No

Preliminary Design

Preliminary Solution Yes

Cost optimisation

Yes

Identify measures

Preventative Measures ?

Acceptable Failure rate ?

No

No

Insulator selection

Figure 1-2: An overview of the process of insulator selection, as based on a published 6 diagram. Once these basic data are collected, the various options for insulator selection can be identified for further study. Depending on whether or not information is available on service experience, insulator characteristics and the environment, the need for further field tests should be determined. However, it should be noted that these tests normally take 2-4 years. An overview of the available methods for site severity measurement and field tests is given in Section 5. Since the time required for field tests is very long, such tests are usually augmented with laboratory tests. A brief overview of laboratory test methods and some examples of field test stations are given in Section 6. When the basic data and field and laboratory test results have been compiled, the actual design procedure - as described in Section 7 - can begin. The choice between a deterministic or statistical approach will depend on the criticality of the design. Economic and time constraints may dictate a shortened selection procedure with the possible concomitant reduction in confidence in the design. In the event that a reliable insulator design is not achieved, mitigation methods may be necessary. Examples of such methods are given in Section 8. Improvement in the design procedure requires verification of performance that also will provide further service experience for future designs.

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2. POLLUTION FLASHOVER PROCESS 2.1 Introduction The pollution flashover process of insulators is greatly affected by the insulator’s surface properties. Two surface conditions are recognised: either hydrophilic or hydrophobic. A hydrophilic surface is generally associated with ceramic insulators whereas a hydrophobic surface is generally associated with polymeric insulators, especially silicone rubber. Under wetting conditions - such as rain, mist etc. - hydrophilic surfaces will wet out completely so that an electrolyte film covers the insulator. In contrast, water beads into distinct droplets on a hydrophobic surface under such wetting conditions. In the Electra No. 64 publication2, the pollution flashover process for ceramic insulators - that is, insulators with a hydrophilic surface - is described essentially as follows: a)

The insulator becomes coated with a layer of pollution containing soluble salts or dilute acids or alkalis. If the pollution is deposited as a layer of liquid electrolyte - e.g. salt spray, stages (c) to (f) may proceed immediately. If the pollution is non-conducting when dry, some wetting process (stage (b)) is necessary.

b) The surface of the polluted insulator is wetted either completely or partially by fog, mist, light rain, sleet or melting snow or ice and the pollution layer becomes conductive. Heavy rain is a complicating factor: it may wash away the electrolytic components off part or all of the pollution layer without initiating the other stages in the breakdown process, or it may by bridging the gaps between sheds - promote flashover. c)

Once an energised insulator is covered with a conducting pollution layer, a surface leakage current flows and its heating effect starts to dry out parts of the pollution layer.

d) The drying of the pollution layer is always non-uniform and, in places, the conducting pollution layer becomes broken by dry bands that interrupt the flow of leakage current. e)

The line-to-earth voltage is then applied across these dry bands, which may only be a few centimetres wide. It causes air breakdown to occur and the dry bands are bridged by arcs, which are electrically in series with the resistance of the undried portion of the pollution layer. A surge of leakage current occurs each time the dry bands on an insulator sparkover.

f)

If the resistance of the undried part of the pollution layer is low enough, the arcs bridging the dry bands are able to burn continuously and so may extend along the insulator; thereby spanning more and more of its surface. This in turn decreases the resistance in series with the arcs, increases the current and permits the arcs to bridge even more of the insulator surface. Ultimately the insulator is completely spanned and a line-to-earth fault is established.

Figure 2-1: Schematic representation of the pollution flashover process across a hydrophilic surface. The key processes involved in the flashover process are shown in Figure 2-1. The environment, in which the insulator must operate in, influences the first two processes - pollution deposit and wetting - whereas electrical aspects govern the last two processes. This Section, therefore, discusses the flashover process from these two viewpoints.

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To date, no clear description exists of the complete insulator flashover process for insulators with a hydrophobic surface - but the key aspects, as defined, will still be present to a greater or lesser extent. The aforementioned points do not include the effects of ice and snow on the electrical strength of insulators. Such additional points are discussed in provided in Section 2.4.

2.2 Modelling 2.2.1 Hydrophilic surface It is assumed that, in general, the flashover process across ceramic insulators applies to hydrophilic surfaces - i.e. where this surface is covered with a film of electrolyte. The models are, therefore, based on the study of an arc in series with a resistance - representing a dry band arc and a wet polluted surface respectively.

2.2.1.1 d.c. Model Mathematical modelling of the pollution flashover of ceramic insulators has already been the subject of an extensive review published in Electra 7. Therefore, only a brief summary of the results will be given here. For modelling of pollution flashover under d.c. energisation, the basic approach8 involves the determination of the minimum voltage needed to sustain a dry band arc of a given length in series with the corresponding pollution surface resistance. The arc length is then varied in order to obtain the critical position that corresponds to the highest value of the supply voltage. The latter is taken as the insulator withstand voltage for the pollution severity concerned9. An alternative approach10, still for the d.c. case, is to consider that the dry band arc will continue to elongate as long as:

Ea < E p where

(2-1)

E a is the arc voltage gradient and E p is the mean voltage gradient of the pollution layer.

The static arc characteristic for a current ‘i’ is of the form:

Eai n = N 0 where

(2-2)

N o and ‘n’ are constants.

Assuming a constant surface resistance

xc =

rp per unit leakage path, the critical arcing distance x c was found to be:

L n +1

(2-3)

were L is the leakage path length. The corresponding critical voltage ‘Uc’ was determined as:

Uc = N0 The critical d.c. current

1

n +1

• rp

n

n +1

•L

(2-4)

ic - i.e. the maximum leakage current not leading to flashover - can be obtained from :

N  ic =  o   rp 

1

n +1

(2-5)

Several refinements have been introduced to the d.c. model. In another paper11, an insulator model was introduced with two different surface resistances per unit length rp1 and rp2 - corresponding to the stem and the shed of a longrod insulator. A circular insulator disc model was also investigated 12. The contribution of arc current concentration at the roots to the pollution layer surface resistance was included 13 14. Other refinements include the consideration of the arc electrode voltage drops 13, effect of temperature on the pollution layer resistance14 and the influence of multiple parallel arcing that takes place on many insulators - especially on those of large diameter15. The d.c. model has been used to study the polluted insulator : test source interaction 16. This contributed to the interpretation of the experimental results and to the determination of the minimum requirements for d.c. sources in polluted insulator tests17.

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Unfortunately, the d.c. model has been frequently used to account for polluted insulator performance under a.c. energisation11 , despite there being important basic differences - as is shown below.

13 14

2.2.1.2 a.c. Model At the instant of voltage and current peak, the circuit equation of an a.c. arc burning in series with the insulator pollution surface resistance is identical to that of the d.c. circuit equation. However, it has been amply demonstrated experimentally that, for the same pollution severity, the peak a.c. withstand voltage far exceeds the corresponding value under d.c. conditions. It has also been observed experimentally that arc-propagation across the insulator surface can take several cycles and, therefore, the arc is subject to an extinction and re-ignition process at around current zero 18 19. This means that the d.c. criterion for arc propagation, i.e. E a < E p , referred to previously will not be sufficient to predict insulator flashover under a.c. energisation. An arc can start propagation when this criterion becomes fulfilled, but if the voltage is not sufficient to cause re-ignition after current zero, the arc will extinguish without leading to flashover. It has been demonstrated, both theoretically18 and experimentally20, that for the current ‘i’ in a resistive circuit the re-ignition voltage ‘U’ can be expressed as:

U=

A• x im

(2-6)

where ‘x’ is the residual arc length and ‘A’ and ‘m’ are constants Inserting this relationship in the circuit equation results in:

A • x No • x = + Rpx i im in

(2-7)

Where R px is the pollution surface resistance corresponding to an arc length ‘x’. Since the voltage drop of a burning arc is much smaller than the re-ignition voltage, an acceptable - although not accurate approximation would be to put n ≅ m. This simplifies the analysis and yields a critical arc length x c :

xc =

L m+1

(2-8)

For constant r p , the corresponding critical voltage ‘Uc’ is: m

U c = B • rpm+1 • L

(2-9)

where ‘B’ is a constant. Expression 2-9 is similar to that of equation 2-4 for the d.c. case, although instead of n ≅ 0.8 - valid for the d.c. static characteristic of a free-burning arc - m ≅ 0.5 in the a.c. arc re-ignition expression 2-6. Also, the constants in equations 2-9 and 2-4 are quite different. In fact, numerical evaluation of these expressions shows that for a high pollution severity - i.e. relatively low values of rp - the critical a.c. voltage (rms) is much higher than the critical d.c. voltage. This difference diminishes, however, at lower pollution severity and ultimately - with no pollution at all - the a.c. sparkover voltage peak value is nearly equal to the corresponding d.c. voltage. The a.c. model 21 has been used to investigate the source: polluted insulator interaction and has revealed the effect of the parallel capacitance on insulator performance. It proved, therefore, to be quite useful in determining the minimum source requirement 22. Recently, the model has been further used to investigate the effect of altitude on the performance of a.c. insulators under pollution conditions23; see also the discussion in Section 3.3.8.

2.2.1.3 Evaluation of the pollution flashover mechanism under transient overvoltages Consider an impulse voltage with a time to crest (tcr ) much smaller than the time to half value (th ). The main influence on the leakage current flashover stress is given by th 24 25 (see Figure 2-2). At very short times to half value (th less than 200 µs), no pre-arc will occur and mainly streamer discharges develop. Then the flashover voltage is determined by the requirement for a streamer discharge to occur and may attain a value close to that for dry conditions.

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For very long times to the half value - i.e. longer than 3000 µs, a long pre-arc could be formed. In this case, the leakage current flashover stress will be determined by the pre-arc only and reaches a value of approximately 0.7 kV/cm. With a virtual impulse duration longer than 100 ms, a further decrease of the flashover voltage will be observed. This is not caused by a new flashover mechanism. It is due to the fact that the pollution layer will be heated for a longer time duration by the current flowing and so the surface conductivity will be increased. In the range between 200 and 3000 µs of th - i.e. SI range, the performance is more complicated; as is analysed below.

Figure 2-2: Flashover strength vs. the voltage-time duration for a cylindrical model insulator under pollution conditions 25.

2.2.1.4 Evaluation of the discharge process under switching overvoltages Discharge without dry bands (application of SI only). Based on the analysis of experimental data as well as on simplifying assumptions for the very complex flashover mechanism for a leader discharge 26 27, a flashover model has been developed 28. Whereas the a.c./d.c. flashover is governed by the prearc 29 10 7, this is not the case with the SI stress - now the leader discharge becomes more important. Because of its comparatively short lifetime and low energy dissipation, the leader can not produce any dry bands - which is contrary to the case of an existing pre-arc. Furthermore, the leader gradient is much higher than the gradient in the pre-arc; i.e. the current flowing in the bridged layer can not be neglected, as in the case of a.c./d.c. stresses. From this consideration it follows that, instead of the usual voltage (U) - current (I) characteristic for a.c. and d.c. cases, only the strength (E) - current (I) characteristic is applicable for SI28, for the instantaneous discharge parameters (Figure 2-3). Analogous to the a.c./d.c. flashover criterion, a critical condition for the SI flashover arises. For this condition, the dotted straight line in Figure 2-3b - which represents the negative slope of the layer resistivity per unit length - becomes a tangent of the E-I leader characteristic - as given by the full curve in Figure 2-3b.

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Figure 2-3: Flashover models for a.c./d.c. (a) and SI (b) 28. Discharge with dry bands (application of SI with pre-stress). As reported by Garbagnati et al 152, the SI strength can be reduced due to the presence of dry bands. If the flashover strength is drawn versus the dry band length, typical U-curves are obtained.

Figure 2-4: Approach for the evaluation of the minimum flashover strength in the presence of dry bands 28. In the presence of a short dry band, having a length ‘ar’ (Figure 2-4), the flashover under positive SI first occurs from this dry band in a very short time (air breakdown in the µs range). This is followed by the flashover along the contaminated layer of the length ‘ag’ during a much longer time period (leakage - current flashover in the ms range).

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For dry band lengths smaller than 1 m, the strength of the air gap corresponds to the positive steamer gradient, i.e. 450 kV/m. For longer dry band lengths, the mean breakdown strength corresponds to the minimum possible breakdown voltage per unit length of a long air gap under positive SI. To check if the proposed approach works, even for insulators of practical interest, the results of calculation are compared with available experimental data. Because non-uniform contamination is to be regarded as the worst case, only the presence of dry bands of critical lengths shall be considered in the following case. As an example, Figure 3-28 shows the results obtained for a post insulator, where the experimental data of Garbagnati et al 152 are used. As is evident from the broken-line curve, the calculated values meet the measured ones quite well up to the longest investigated insulator length of 12 m. Another example is reported in Figure 3-33. Here, the calculated minimum curve agrees satisfactorily with the experimental one presented by Garbagnati et al 152 for practical insulators up to 12 m length.

2.2.2 Hydrophobic surface The superior performance of new polymeric insulators under pollution conditions is generally attributed to its water repellent i.e. hydrophobic - properties. Because the surface does not wet, water forms as isolated drops rather than as a continuous surface film. Hydrophobicity can be lost due to different ageing mechanisms - heavy wetting, blown sand, corona and spark discharges and possibly solar radiation. For the same pollution surface density, the surface resistance of a polymeric insulator is generally some orders of a magnitude higher than that of a similar porcelain or glass insulator. It also follows that the leakage currents associated with polymeric insulator discharges are generally some orders of magnitude lower than the corresponding levels for ceramic insulators. Due to the dynamic nature of a polymeric surface and the resulting complex interaction with pollutants and wetting agents, there exists today no quantitative model of pollution flashover for polymeric insulators that is similar to the one expounded in Section 2.2.1. for ceramic insulators. However, a qualitative picture for the pollution flashover mechanism is emerging 30. It involves such elements as the migration of salt into water drops, water drop instability, formation of surface liquid filaments and discharge development between filaments or drops when the electric field is sufficiently high.

2.3 Environmental Aspects From the discussion of the previous sections, it is clear that there exists a direct relationship between the likelihood of flashover and the conductivity of the polluted surface layer. In this section, attention will now turn to the formation of this conducting layer on the insulator surface and the important aspects that determine its conductivity. These aspects are: • The quantity of pollutants on the insulator surface; this is determined by the contamination deposit-process. • The types of pollutants present, plus the wetting conditions. • The natural cleaning properties of insulators. • Whether the polluted surface layer is in the form of distinct droplets or as a continuous film. An influence common to all of the above is the climate in which the insulator is installed.

2.3.1 Climates or atmospheric variables and typical environments The conditions surrounding a H.V. insulator leading to the pollution deposit, and the wetting or cleaning of the insulator, are caused by a set of atmospheric variables which interact among themselves and with the insulator surface. The most important atmospheric variables are: wind, rain, humidity, temperature and pressure. Atmospheric conditions can vary in both time and space. Similar identifiable patterns of occurring atmospheric conditions may be grouped into climates. Climate is, therefore, the result of the interaction of atmospheric conditions with the surface of the earth and may be classified as local, regional or global. A pertinent feature of meteorological information is that it is expressed in average values, obtained from statistics taken over a long period of time (e.g. 30 years). A general classification of climates is given in Table 2-1.

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Table 2-1 A general classification of climates 31. TYPE OF CLIMATE

DESCRIPTION 1

DESCRIPTION 2

Tropical

Often called Equatorial climates. Here the weather is hot and wet around the year. These climates are found within about 5° of latitude North and South of the Equator

Hot tropical climates with a distinct wet and dry season. They occur roughly between 5° and 15° North and South of the Equator. In parts of South and South-East Asia the division between the wet and dry seasons is so clear that they are called Tropical Monsoon Climates

Dry

Hot deserts with little rain at any season and no real cold weather although temperature drops sharply at night. The Sahara desert and much of the Arabian peninsula are the best examples of this type.

Tropical steppe or semi-desert with a short rainy season during which the rains are unreliable and vary much from place to place. Good examples are found in parts of India and the Sahel region of Africa.

Warm Temperate

Rain occurs at all seasons but summer is the warmest time of the year and temperatures range then from warm to hot. Winters are mild with occasional cold spells. Much of Eastern China and the South Eastern States of the USA fall in this category.

Winters are generally mild and wet, summers are warm or hot with little or no rain. This type of climate is often called “Mediterranean” because of its wide extent around that sea. It occurs in smaller areas elsewhere, for example central Chile, California and Western Australia.

Cold

The cool temperate oceanic types of climate: Rain occurs in all months and there are rarely great extremes of heat or cold. This climate is found in much of Northwest Europe, New Zealand and coastal British Columbia.

Cold continental climates with a warm summer and cold winter. Much of Eastern and Central Europe and Central and Eastern Canada and the USA have this type of Climate

Sub-Arctic or Tundra

The winters are long and very cold. Summers are short but during the long days temperatures sometimes rise surprisingly high. This type of climate occurs in Central and Northern Canada and much of the Northern and Central Siberia.

Arctic or Ice cap

In all months temperatures are near or below freezing point. Greenland and the Arctic continent are the best examples of this type but it also occurs on some islands within the Arctic and Antarctic circles.

High mountain and Plateau

Where land rises above or near the permanent snow line in any latitude the climate resembles that of the Sub-Arctic or Arctic. The largest extent of such climate is found in Tibet and the great mountain ranges of the Himalayas

DESCRIPTION 3

Deserts with a distinctly cold season. These occur in Higher Latitudes in the interior of large continents. The best examples are parts of central Asia and Western China.

2.3.1.1 Local climate For its general characteristics, the local climate depends on the regional climate and - ultimately - upon the global climatesystem. It is, therefore, useful to remember that the local climate of a particular place is a variation on the regional climate. Indeed, the mechanisms acting to create a local climate are essentially the same as those creating the global climate32. This means, that it is possible to apply this knowledge to create models to: a)

Understand the physical process of the interaction between climate and insulator.

b) Predict the pollution phenomena. Work has been done to correlate the general climatic specification and meteorological data with the pollution flashover performance of insulators, as is reported in Section 7, where the impact of climate on selection and dimensioning is discussed.

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The aim of such a study is to find the basic relationship between the atmospheric variables and the pollution phenomena. Information on the time-variation of atmospheric variables is necessary. The information sources will, of course, vary as needs differ. The Meteorological Service usually only provides general information, i.e. average values; However, when an application is submitted to its research department, specific information can be obtained. Depending on the study being made, either regional or local climate data will be used. For example, to study the insulation design or maintenance of a transmission line 100 km long (place) and for an expected life of 50 years (time), regional climate information will be used.

2.3.1.2 Typical environments To assist in the selection and design of external insulation, typical environments have been defined. Some examples are: • Marine: Areas where the insulator pollution is dominated by the presence of the sea. The pollutants present on the insulators are, therefore, mostly NaCl and other marine salts that are easily soluble. On insulators close to the coast it is generally found that the inert component of the pollution is low. • Industrial: Areas in close proximity of polluting industries - such as steel mills, coke plants, cement factories, chemical plants, generating stations or quarries - are classified as industrially polluted. In these areas, the pollution types can be very diverse. The pollutants present may vary from dissolved acids - such as found close to power stations or chemical plants - to slow dissolving salts - such as gypsum or cement - found close to quarries or cement factories. Generally, the pollution has a high inert component in areas close to industries. • Desert: In desert environments, the pollution tends to be sand based. The desert sands may contain high amounts of salt, e.g. 18 % in Tunisia 62, resulting in a very conductive layer when wetted. The pollution on the insulator tends to be hygroscopic with a very high inert component. Inland desert areas are typically very dry, dusty, windy and hot. The large fluctuations between day and night raises the relative humidity to levels as high as 93% during early morning up to sunrise thereby leading to very heavy dew that causes frequent flashovers in some cases. If desert areas are close to the coast, the pollution problems are compounded61. • Mixed: If industrial areas are situated close to the coast or desert, then the pollution can be described as mixed. • Agricultural: Localised insulator pollution may also be caused by agricultural activities such as crop spraying, ploughing etc. When lines cross land ready for harvesting the structures may serve as perches for large birds - thereby leading to flashovers due to bird streamers. The environment may also be classified according to the nature of the contamination-source, as was done in a survey33 on insulator in-service performance. The classification was as follows: • Areas with no signs of pollution-related problems. These areas are defined as ‘clean’ areas. • Areas with isolated pollution problems of limited extent that can usually be traced to a particular pollution-source. These areas are defined as experiencing ‘local’ pollution. Local pollution is often found in areas where the general atmospheric condition is pollution free but local industrial or agricultural activities cause the problem. • Areas with widespread pollution problems that can not usually be traced to a localised pollution-source. These areas are defined as experiencing ‘regional’ pollution. Regional pollution can often be found in extended industrially developed areas - typically with numerous chemical plants, steel mills, and cement or fertiliser factories. Regional pollution may also be found along coastal areas, especially if the weather pattern includes a dry season that allows the accumulation of pollution on the insulators. These types of classification can only be used to describe the environment in general terms. Therefore, a detailed study of the actual pollutants present is required to achieve an optimal insulator selection. Service experience has demonstrated that the performance of ceramic insulators - in all but the severest environments - is adequate if the insulators have been properly dimensioned. However, several factors may adversely influence performance even though insulator selection was appropriate at the time of design. Firstly, the environment may change during the lifetime of the insulators. This can be particularly troublesome in industrialising areas, where the region may have been classified originally as ‘clean’ and then - at some point - additional sources of pollution become located near an installation. This could be the case if new factories are constructed, or if an area becomes developed for agriculture after the insulators have been selected. Secondly, it has been observed that - in some areas thought to be clean - pollution effects become apparent several years after the insulators have been installed, even if no new industrial or agricultural activity takes place. This is simply a matter of the insulators gradually accumulating pollution with time, often on a time-scale of several years. Other changes in the environment could be related to changes in the nesting habits of birds, which have been known to cause pollution flashovers.

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Third, extreme changes in weather have been known to cause major outages because of unusual meteorological patterns. Major storms that may occur with relatively low probability can suddenly cause severe coastal pollution. In inland areas, long dry periods with little rain may also cause an unusual build-up of pollution.

2.3.2 Type of pollution To degrade the service strength of an insulator, the pollution must either form or adversely influence a conductive layer on its surface. Pollution can, therefore, be classified either as being an active type - i.e. pollution that forms a conductive layer - or as being an inert type - i.e. pollution that adversely influences the conductive layer4. The amount, or severity, of the pollution layer on an insulator is normally expressed in terms of the Equivalent Salt Deposit Density (ESDD). This quantity is obtained by measuring the conductivity of the solution containing pollutants removed from the insulator surface and then calculating the equivalent amount of NaCl having the same conductivity 322. ESDD is expressed in mg salt per cm2 of the insulator’s surface area.

2.3.2.1 Active type of pollution Active pollutants are classified according to the ease by which the conductive layer is formed. Two types are apparent: 1. Conductive pollution 2. Pollution that must dissolve in water to become conductive Typical examples of each of these pollutant types are given in Table 2-2. Table 2-2: Examples of the different active pollution types 4 36 37 39 69. CONDUCTIVE POLLUTION Metallic deposits such as Magnitite, Pyrite Gasses in solution: SO2, H2S, NH3 Salt Spray Bird Streamer

DISSOLVING Ionic Salts: NaCl, Na2CO3, MgCl2, gypsum CaSO4 Others, Fly ash, cement

2.3.2.1.1 Conductive pollution Metallic deposits Metallic deposits are normally found close to mining activity and related industries. The electrical strength of the insulator is severely affected if the density of the pollutants on the insulator surface is such that the individual particles are in contact or if the gaps between the particles are bridged by an electrolyte. Bird Droppings It has been reasoned that bird droppings can explain a large number of unidentified outages of transmission lines with system voltages up to 500 kV 34 35 36. When large birds release their excrement, a long continuous length of highly conductive fluid droppings (volume conductivity 10 - 30 mS/cm) can shorten the air gap between the tower structure and the conductor. Then the remaining air gap is too small to withstand the phase-to-earth voltage. Most of these flashovers occur during the time period prior to birds’ commencement of daily activity. A secondary effect is that the insulators are covered with the bird excrement, which is a pollution layer with a very high salt content. If the birds utilise the tower frequently, this may become a very thick layer. Pollutants in dissolved state A more common conductive pollution type is where the pollutants are already dissolved in the wetting agent, as in acid rain and salt-fog conditions. Some of these pollutants - such as gasses dissolved in water, e.g. SO2 - are difficult to detect by taking measurements from the surface of the insulators, because this contaminant returns to the gaseous state as soon as the insulator surface dries4.

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2.3.2.1.2 Pollution that needs to dissolve Various studies have been made to find a relationship between the dissolving characteristics of salt contaminants and the insulator flashover voltage 52 39 37 69. From these studies, the following parameters have been identified as being important: • The solubility of the salt. • The rate at which the salt goes into solution. Figure 2-5 39 shows the effect of salt-solubility on the limiting flashover voltage of an insulator for three different equivalent salt deposit densities (0.01 mg/cm2, 0.03 and 0.10 mg/cm2). The limiting flashover voltage is the minimum value achieved under a cold fog test for a polluted insulator. Eight salts were investigated. From this figure, it is clear that there is very little dependence of pollution flashover voltage on the solubility of the contaminating salt. 14

Limiting Flashover Value (kV, rms)

12

ESDD= 0.01 mg/cm

2

10 0.03 mg/cm

2

8 0.10 mg/cm

2

6 Ca(NO3)2 4

MgCl2 Mg(NO3)2

2

Na2SO4

CaCl2

NaCl MgSO4

NaNO3

0 0

20

40 60 Solubility (g/100 g H2O)

80

100

Figure 2-5: Relationship between Salt solubility and limiting flashover values (LFOV) 39. Different salts also have different rates at which they go into solution; generally the higher the solubility of the salt the quicker it will go into solution - but this is not always the case. This is shown in Table 2-3 where the salt is classified according to its solubility and speed by which it goes into solution. Table 2-3: General classification of salts according to their solution properties. LOW SOLUBILITY SALTS

MgCl2 , NaCl

FAST DISSOLVING SALTS SLOW DISSOLVING SALTS

HIGH SOLUBILITY SALTS

MgSO4, Na2SO4, CaSO4

NaNO3, Ca(NO3)2, ZnCl2

Highly soluble salts that dissolve quickly need a short time in contact with water to go into solution. Therefore, a highly conductive layer can form quickly on the insulator during all wetting processes. However, with higher wetting rates - e.g. rain etc. - the pollution will also be purged more easily from the insulator due to its high solubility. Low solubility salts that also dissolve slowly need a large quantity of water to speed up the solution process. This is illustrated in Figure 2-638. The relationship between ESDD and the quantity of distilled water used to make the measurement is shown for insulators that came from two environments; one in an agricultural area, Huang Du, and another is from an environment close to a steel plant. In both of these areas, the main pollutant is gypsum.

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Figure 2-6: Relation between ESDD and Quantity of distilled water 38. This figure shows that for the naturally polluted insulators, an increase in ESDD occurs for an increase in the quantity of distilled water used for making the measurement. This is in contrast to an insulator polluted artificially with NaCl - i.e. a fast and highly soluble salt - that does not show the same tendency. Various studies have shown that insulators contaminated with highly soluble and fast dissolving salts - such as NaCl - have lower clean-fog withstand voltages than insulators contaminated with low solubility salts which are slow dissolving39 40 41 such as gypsum (CaSO4.2H2O) - in spite of them having the same contamination severity (see Figure 2-7).

Figure 2-7: Influence of various salts in the contamination layer on the insulator fog withstand voltage41. It was also shown that the relationship between the flashover voltage in a steam fog test and the steam input-rate was dependent on the type of salt on the insulator. A comparison was made between insulators naturally polluted - mainly gypsum - and insulators artificially polluted with NaCl and kaolin 42. The results are presented in Figure 2-8, which show that the flashover strength of insulators polluted with mainly gypsum have a greater dependency on steam input-rate than do insulators polluted with NaCl. The decrease in flashover voltage with increasing steam input-rate is ascribed to the greater amount of pollution that is dissolved at the higher wetting-rate. To achieve the same flashover voltage during the test as that applied in-service conditions when flashovers occurred, the steam input-rate had to be an order of magnitude higher than that recommended by IEC 507 22.

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Figure 2-8: Flashover voltage of naturally and artificially polluted insulators as a function of steam input rate42. Flashovers have been reported on insulators polluted by slow dissolving salts - such as gypsum (CaSO4) - but they generally occurred during extended periods of wetting; i.e. dense fog, heavy rain storms lasting longer than three hours or live spray washing 42 43. Other factors that complicate the relationship between the type(s) of salt and the flashover voltage are when: • The solubility of a salt is affected by the existence of other salts; e.g. the solubility of CaSO4 is inhibited by the presence of NaCl 37. • The process by which a salt goes into solution can be either exothermic (temperature rises) or endothermic (temperature lowers). Any temperature change will greatly influence the conductivity of the solution that forms 69. • The wetting process of the insulator is influenced by the hygroscopic properties of the salt. Therefore, different wettingrates will occur for different salts - even though the ESDD values may be the same 69.

2.3.2.2 Inert pollution Inert material deposited on an insulator surface has, until now, been considered to give an indirect and relatively small influence on the withstand voltage. The greater the inert material deposit, the thicker will be the water film retained on the insulator surface - and so the amount of soluble material dissolved in the water film will be higher. Recently, significant differences have been found in the d.c. withstand voltage between insulators contaminated artificially with Tonoko and kaolin under the same ESDD conditions 44 45. In addition, it has also been reported that there is an influence of the amount of the inert material on the hydrophobicity and the withstand voltage of polymeric insulators 46 47. The amount of inert material found in the pollution deposit on an insulator is expressed as the Non-Soluble Deposit Density (NSDD) given in weight of the non-soluble deposit per unit surface area of the insulator 322. NSDD is expressed in mg/cm2. In this section, the influence of both the type and the amount of inert material on the contamination performance of insulators will be discussed.

2.3.2.2.1 The influence of inert material type In the conventional clean-fog procedure for insulator artificial contamination tests, a constant amount of inert material and a variable amount of salt are included in the solution for contaminating a specimen insulator. Kaolin and Tonoko are typical inert materials for artificial contamination tests and so they will form the basis of this discussion. Although the shape of a specimen insulator and the contamination method may influence NSDD, 40 g of inert material per 1 litre of water has been specified in IEC 507. This amount is regarded as giving approximately 0.1 mg/cm2 of NSDD on the insulator surface 22.

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However, the experimental results given in Figure 2-9 show that the deposit density on a specimen disc varies with the type of inert material - in this case, Tonoko and Roger’s kaolin - when the specimen is contaminated with a solution having the same ‘concentration’ of inert material. The results presented in Table 2-4 are, therefore, given for the same inert material deposit density.

Figure 2-9: Relationship between NSDD and the quantity of inert materials in the contamination suspension 45. Comparative test results of d.c. and a.c. contamination withstand voltage with Tonoko and Roger’s kaolin are also shown in Table 2-4 45. Significant differences - 20 to 25% - can be seen in the d.c. withstand voltage between Tonoko and Roger’s kaolin although the salt deposit density (SDD) is the same. Table 2-4: Results form flashover voltage tests45. Test Voltage

Quantity of Salt / NonSDD NSDD 50% FOV Corrected Max. Leakage soluble Contaminant mg/cm2 mg/cm2 kV/unit 50% FOV current g/l kV/unit mA 13/40 0.068 16.7 15.8 250 Tonoko [100] [100] 13/60 0.03 0.079 14.8 14.4 430 kaolin [89] [92] 250S 133/40 0.079 11.0 10.6 850 Tonoko [100] [100] a.c. 96/60 0.025 0.135 10.0 10.5 1200 kaolin [91] [99] 15/40 0.076 26.6 25.5 200 Tonoko [100] [100] 320DC 16/60 0.03 0.113 22.2 22.6 550 kaolin [83] [89] 13/40 0.068 16.3 15.4 230 Tonoko [100] [100] 250S 13/60 0.03 0.085 12.8 12.5 350 kaolin [79] [81] d.c. 13/40 0.16 25.0 26.8 80 Tonoko [100] [100] 320DC 13/40 0.03 0.082 20.9 20.3 160 kaolin [84] [76] Note 1: SDD and NSDD values show average values measured on more than 10 insulator units for individual cases. Note 2: Maximum leakage current shows the average maximum value for individual cases. Note 3: Corrected 50% FOV value was the one corrected to NSDD = 0.1 mg/cm2. Note 4: [ ] shows the percentage ratio of 50% FOV for the case of kaolin relative to that of Tonoko. 45 Note 5: Insulator types are specified in the paper .

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17

Table 2-4 shows that a 5-10% difference in the a.c.-contamination withstand voltages was found between Tonoko and Roger’s kaolin when the NSDD was adjusted to the same level. The variation of the surface resistance of the contaminated insulator during the tests is shown in Figure 2-10, which illustrates that the surface resistance of an insulator contaminated with Roger’s kaolin reduces faster and is much lower than that of an insulator contaminated with Tonoko.

Surface Resistance, Mohm/unit

10

Tonoko Brazilian kaolin Mexican kaolin Georgia kaolin

1.0

Italian kaolin

Roger’s kaolin

0.1 0

10

20

30

40

50

60

Time lapse, min

Figure 2-10: Time variation of surface resistance during the course of clean fog tests of contaminated insulator units polluted with a combination of salt and various types of kaolin and Tonoko 48 . The very wide variations in the physical and chemical properties of the various kinds of kaolin used internationally in insulator contamination tests are shown in Table 2-548. Table 2-5 : Physical and chemical properties of common inert materials used in insulator contamination tests 48.

Item Particle Size, µm (50% value) Main Constituents of material

Measuring method Laser Light Scattering

Tonoko 6.2

Roger’s 5.8

Georgia 6.3

kaolin Italy 4.5

X-ray Diffraction

Quartz Muscovite

Quartz Kaolinite

Quartz Kaolinite

Quartz Kaolinite

Chemical Composition, Percentage by Mass

Loss on Ignition X-ray SiO2 Fluorescence Al2O3 Fe2O3

4.8 67 16 5.8

14 46 37 0.9

14 46 38 0.7

12 48 37 0.7

Mexico 13.5

Brazil 25.9

Quartz Kaolinite Cristobalite 6 77 16 0.2

Quartz Kaolinite 13 48 36 1.0

The surface resistance and the withstand voltage characteristics of an insulator artificially contaminated with these types of kaolin, together with the Tonoko, are shown in Figure 2-10 and Figure 2-11 respectively 48. A large variation is apparent, even among the various types of kaolin 10 49. The main minerals of Tonoko and kaolin - as determined by the X-ray diffraction method - are Muscovite (Al2Si2O5(OH)4) and Kaolinite (KAl2Si3Al10(OH)2) respectively, together with Quartz (SiO2) that is common to both. The different surface resistivities of Tonoko and the various types of kaolin that apply under artificial fog conditions can be explained by the different crystal structures of these materials. Hydroxyl groups [OH]- are located inside the crystal structure in the case of Muscovite, whereas they are located outside the crystal structure in the case of Kaolinite. Kaolin consisting of Kaolinite is, therefore, much more hydrophilic than Tonoko consisting of Muscovite. Recently it was confirmed that the type of inert material had a similar influence on the contamination withstand voltage of silicone rubber polymeric insulators 50.

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100 Comparitive Flashover voltage, % (Tonoko=100%)

Specimen Insulator: 320 DC

SDD

2

: 0.03 mg/cm

2

NSDD : 0.10 mg/cm

80

60

40

20

0 Tonoko

Brazilian kaolin

Roger's kaolin Mexican kaolin Type of inert material

Georgia kaolin

Italian kaolin

Figure 2-11: d.c. Withstand voltage test results of artificially contaminated insulators with various kinds of inert material 48. The type of inert pollution, therefore, influences the formation of a conductive layer. It can be classified as being either: hydrophilic or hydrophobic. A hydrophilic substance will aid the formation of a conductive film on the insulator surface 51 whereas a hydrophobic material will inhibit the formation of such a film. It has been shown that a truly inert material is neither hydrophobic nor hydrophilic - such as is quartz - and so does not significantly influence the flashover voltage of an insulator52.

2.3.2.2.2 The influence of the amount of inert material present a) Ceramic Insulators The influence of the amount of inert material on the contamination withstand voltage of the longrod type and the disc type insulator is shown in Figure 2-12.

Figure 2-12: The influence of the amount of inert material on the contamination withstand voltage of porcelain longrod and disc type insulators (Tests performed at NGK). A substantial reduction is apparent in the withstand voltage with an increase in the amount of Tonoko present, expressed in NSDD. This reduction is in spite of the smaller influence of NSDD compared with that of ESDD. This is due to the thicker layer of inert material because it retains more water - thereby increasing the amount of soluble contaminant that is dissolved. The result is a lower surface resistance and, therefore, a lower withstand voltage.

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b) Polymeric Insulators A similar tendency in the relationship between the NSDD and the contamination withstand voltage exists for polymeric insulators, as shown in Figure 2-1350. A delayed recovery of hydrophobicity with the increase in NSDD on the insulator surface was also reported, as is illustrated in Figure 2-14.

Figure 2-13: The relationship between NSDD and contamination withstand voltage for polymeric insulators 50. The withstand voltage of hydrophobic polymeric insulators that are contaminated heavily with inert materials may be reduced by the thicker water film and the delayed recovery of hydrophobicity. The latter is due to the inhibited migration of low molecular weight silicone from the bulk to the surface of the contaminant layer.

Figure 2-14: The effect of NSDD on hydrophobicity recovery time 53. (Artificial pollution consisted of kaolin and salt; flashover voltage was determined by the Clean-Fog test).

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2.3.3 Mechanisms of contamination accumulation on insulators The accumulation of contaminants on an insulator’s surface is the net effect of the processes which bring them to that surface and those which lead to its self-cleaning54.

2.3.3.1 Contaminating process The contaminating process is decided by the force that brings the contaminant particles towards the insulator surface and by the condition of that surface. The force ‘Fp’ which determines the movement of a contaminant particle close to the insulator is the combination of three forces: wind (Fw), gravitational force (Fg) and the electric field (FE) 54 55 56 57:

v v v v Fp = Fw + Fg + FE

(2-10)

The force of the electric field, E, on a neutral particle is the dielectrophoretic force - sometimes called the ‘grad E’ force - and that on a charged particle is the electrostatic force. The latter can only have an effect under d.c. voltage. The results of calculations by Annestrand and Shei55 indicate that wind is the dominant force governing the movement of contaminant particles for wind speeds of about two to three metres per second and above. When the wind speed is low, the electrostatic force (in case of d.c. voltage) and the gravitational force will dominate. The effect of the dielectrophoretic force is weaker than that of the other forces. Therefore, for a.c. voltages, wind is the dominant factor. In contrast, under d.c. conditions, the electrostatic force also plays an appreciable part. The heating effect of leakage current is another mechanism that may contribute to the accumulation of pollution on the insulator. That is, when salt is deposited on the insulator in the dissolved state - see Section 2.3.2.1.1 - it can be left behind when the water evaporates due to the Joule heating of the leakage current. As a consequence: • In high stress parts of the insulator, the heating effect will hinder its natural cleaning 4. • Under salt-fog conditions, the repeated drying out of the deposited wet contaminant layer leaves a residue of salt that accumulates. It has been shown that under a.c. voltage, the heating effect of leakage current has a larger influence than the dielectrophoretic force on the pollution accumulation on the insulator surface 4.

2.3.3.2 Pollution deposition by Wind Wind is due to changes in atmospheric pressure or by differences of temperature between two sites. Speed and direction are the main characteristics of wind.58 There is a good correlation between the amount of contamination (soluble and insoluble materials) on the insulator surface and the prevailing wind speed, if the wind does not contain large particles. Figure 2-1559 shows an example of the relationship between the Salt Deposit Density (SDD) and the speed of the sea wind for an insulator installed close to the coast and for which the contaminants on its surface are not removed due to wind. The empirical relationship is:

[

S = C∑i Vi 3 • t i where:

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= = = =

]

(2-11) 59

Salt deposit density on the insulator surface average wind speed, for each time interval i length of time interval i a constant that depends on the location of the testing station and type of insulators; typical values are between 5.2 x 10-6 and 8.0 x 10-6

21

(mg/cm2) (m/s) (hour)

Figure 2-15: Accumulation of contaminants by a strong sea-wind on the under surface of a typical insulator59. Wind can transport pollutants over long distances 60. These pollutants can be solids or gasses. Figure 2-16 shows that although the effect of the sea reduces rapidly with distance from the coastline, wind may carry pollutants inland so that the effect of the coast can still be significant at some distance depending on the topography. A higher than normal pollution-layer can result from the use of fertilisers by spraying or the burning of crop residues, due to the transport of the pollutants by the wind.

Figure 2-16: The relationship between the distance from the coast and measured ESDD on a standard disc insulator under ordinary salt-pollution conditions 76. In contrast, the action of wind may mitigate against the pollution flashover process because it could 74 93: • Remove non-attaching particles. • Extinguish the arc on a polluted surface. The processes under which wind brings the contaminants onto the insulator surface is called the “aerodynamic catch”52. Although this process is very complex and can not be fully described, the discussion of this section will highlight the important parameters and mechanisms. When the airflow approaches an insulator, it divides; thereby leaving a stagnation point where the air is at rest. The suspended particles, having a density greater than that of air, are unable to follow the airflow and so may be deposited on the insulator surface. Similarly, when the airflow passes the under-rib on an insulator, it generates vortices inside the ribs. As a consequence, some quite small and low-density particles will be deposited there. Therefore, vertically mounted insulators

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with a simple shape - the so called “aerodynamic profile” - will collect less contaminants in wind than do the insulators with an under-rib profile for the same location. A laboratory measurement in a wind tunnel shows the effect of different shed profiles for vertically mounted insulators 54. The insulators of aerodynamic shed profile are less contaminated when the wind is the only dominant force, as indicated in Figure 2-17.

Figure 2-17: Variation of pollution catch with shape 54 H: Heavy; M: Medium; L: Light; Z: Zero deposit 54. For horizontally mounted insulators, the area presented to the wind by the insulator is important. In cases where the pollution source has a well-defined direction, horizontal insulators pointing to the source, or away from it, will collect more pollution than do corresponding insulators pointing 90o from it125. A rougher surface and the presence of moisture can also contribute to a higher accumulation of contamination 55. 3

10 ESDD (Lee side)

N

ESDD (Wind side)

9

NSDD (Lee side) 2,5

NSDD (Wind side)

F

J

M

L K

I

G H

B A C

E

8

D 7

Lee Side

5

1,5

4

2

6

NSDD (mg/cm )

2

ESDD (mg NaCl/cm )

2

Wind Side

1

3

2 0,5 1

0

0 A

B

C

D

E

F

G

H

I

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K

L

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Position on Insulator

Figure 2-18: Pollution distribution on an insulator in a desert area62. Investigations conducted in desert areas have shown77 61 that the greatest amount of dust on an insulator surface is collected on its lee side, i.e. opposite to the prevailing wind direction, due to the cleaning effect of the wind. This is contrary to the general case, as stated above. Consequently, this produces a non-uniform pollution distribution - as is shown in Figure 2-18.

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The pollution deposit on an insulator is also influenced by the cleaning action of wind. This is especially true in desert areas where the wind may carry quite large sand particles (>200 µm). These particles ‘sand blast’ the insulator surface, thereby enhancing the natural cleaning of insulators. Also, they erode the metallic parts of the insulator. It is the smaller particles carried by wind, 1 indicates a better flashover performance than that of the reference insulator. The Dungeness Insulator Testing Station, opened in the early nineties, is also situated on the south coast of England close to a nuclear power plant. Based on the older results, tests are performed in a way similar to those conducted at Brighton. Koeberg and Sasolburg Insulator test stations, South Africa In 1993, two complementary test stations were set up in South Africa. Koeberg is situated in a coastal environment and Sasolburg in an industrial one. At Koeberg255, it was found that design weaknesses in polymeric insulators showed up within a year. In Sasolburg, the ageing processes are slower. The test voltages at Koeberg are 66/√3 kV and 22/√3 kV whereas Sasolburg tests are at 88/√3 kV and 22/√3 kV. Various parameters of the leakage current flowing across the insulator are monitored. They are: • Maximum positive and negative peak values per time interval. • Sum of the charge flowing across insulator per time interval.

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• Sum of the square of the leakage current per time interval. • Statistical spread of peak values. • Time to flashover. Tests at these stations are continuing.

6.2.2 Artificial pollution laboratory tests A pollution flashover requires the presence of some kind of salt and water on the insulator surface. The test procedures mainly used in laboratories can be classified into two groups, which differ in the insulator-surface conditions before the test. • The clean insulator, energised at constant test voltage, is subjected to a defined ambient condition (e.g. Salt-Fog method). • The insulator with its surface uniformly coated with a layer of inert material and salt is subjected to a constant test voltage and specified wetting conditions (e.g. Solid-Layer method). These two groups cover most situations for pollution flashovers and were taken as the basis for standardising different test procedures. The choice of one of these test methods should be based on the particular natural conditions found in service to reach relevant results for the insulator-design under test.

6.3 Test procedures for porcelain and glass insulators to be used in high-voltage a.c. or d.c. systems The procedures described in the following subsections have been established for ceramic insulators and are not directly applicable to polymeric insulators, to greased insulators or to special types of insulator (i.e. insulators with conductive glaze or covered with a polymeric insulating material). For bushings or other apparatus incorporating hollow insulators with internal equipment, special precautions may be necessary to avoid over-stressing of the internal insulation since the test voltage may be greater than the nominal design one.

6.3.1 Standardised test procedures 6.3.1.1 Salt-Fog test This procedure simulates coastal pollution where a thin conductive layer formed by the salt covers the insulator surface. In practise, this layer contains little - if any- insoluble material. The degree of pollution in a test is defined by the salinity of the salt-fog, expressed in kg of salt (NaCl) per m³ of water. The test conditions (salinity, salt-water flow-rate, and pressure of compressed air) can be controlled easily. Salt-Fog tests are less expensive and less time consuming than Solid-Layer tests. Detailed descriptions of the Salt-Fog procedure can be found in IEC 507, 1991 22 (for a.c. systems) and in IEC 1245, 1993 256 (for d.c. systems).

6.3.1.2 Solid-Layer test 6.3.1.2.1 Procedure A - Wetting before and after energisation This procedure is standardised for a.c. application only. It simulates pollution conditions with thicker layers of deposits containing binding materials and some kind of salt. Also, the situation of ‘cold switch-on’ (energising of a line or a station with contaminated insulators that have their surfaces completely wetted) is covered. The degree of pollution is usually expressed as layer conductivity in µS. The control of the test conditions (surface cleanness before application of the artificial layer, uniformity of the layer, wetting conditions) is difficult and may require additional testing work. To determine the required layer conductivity is time consuming, leading to a higher cost for testing.

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The wetting process in this test procedure runs under two different conditions: wetting of the dry layer up to the maximum layer conductivity (severity value for the individual test) in 20 to 40 minutes without applying the test voltage, and continuing the wetting after immediate application of the constant test voltage for 15 minutes at maximum. A detailed description of the Solid-Layer test ‘Procedure A’ is given in IEC 507,1991 22. Note: This procedure is only rarely used today and is not considered to be optimal. For most of the cases, Procedure B "Wetting after energisation" (see clause 6.3.1.2.2) is to be preferred.

6.3.1.2.2 Procedure B - Wetting after energisation This procedure simulates pollution conditions at service voltage where a layer of binding material and some kind of salt is wetted by condensation. This seems to be the most frequent situation for sites with solid-layer contamination as may occur in rural, industrial and desert regions. The degree of pollution is usually measured in Salt Deposit Density (SDD), which is expressed in mg salt (NaCl) per cm² of a specified surface of the test specimen. The control of the test conditions (surface cleanness before application of the artificial layer, uniformity of the layer, wetting conditions) is difficult and may require additional testing work. To reach the required Salt Deposit Density is time consuming, leading to a higher cost for testing. For this procedure, the wetting process is started after the application of the constant test voltage to the insulator with the layer dry and it lasts with a constant steam input-rate until the end of an individual test. A detailed description of the Solid-Layer test ‘Procedure B’ is given in IEC 507,1991 22(for a.c. systems) and in IEC 1245, 1993 256 (for d.c. systems). As described in IEC 507, the steam input-rate shall be within the range 0.05 kg/h ± 0.01 kg/h per m3 of the test-chamber volume. This steam input-rate is adequate when the pollution layer is formed only with salt (NaCl) and an amount of kaolin, Tonoko or Kieselguhr as the inert material. However, when laboratory tests are performed on naturally polluted insulators, in which a considerable amount of non-soluble material (kaolin or gypsum for example) is deposited on the insulator surface, the steam input-rate shall be increased to wet adequately the pollution layer and to reproduce field conditions. Unfortunately, as the steam input-rate increases, the temperature inside the test chamber also increases - thereby reducing the fog density. For this reason, other sources of fog generation shall be considered (cold or ultrasonic fog) to avoid this rise in temperature. Although various papers dealing with this problem have been published 42 257, more research is still necessary.

6.3.2 Non-standardised test procedures 6.3.2.1 Quick flashover method The quick flashover method is based on the Salt-Fog test and uses a variable-voltage application are lower than those for the standard test procedure.

258

. The cost and test-time

Starting with a stabilisation period of 20 minutes at about 90 % of the estimated flashover voltage at the specified salinity, the test voltage is then raised in 5 % steps, 1 minute at each level, until flashover. The insulator is immediately re-energised at its initial voltage and the process repeated until 5 flashovers are obtained. This part of the procedure is a kind of conditioning of the insulator. For the second part, 90 % of the average of the 5 FOV values is applied to the insulator as a reference voltage. The test voltage is then raised in steps of 2,5 % - 3,5 % every 5 minutes until flashover. The test is continued with 90 % of the previous value of the flashover voltage until the required number of flashovers has been obtained. The performance criterion for the insulator is the mean FOV after the stability of the FOV values has been reached. Lambeth258 has suggested that, for porcelain insulators, there is an acceptable relation between the withstand salinity determined according to IEC 507 and the mean FOV obtained from the quick flashover method.

6.3.2.2 Dust chamber method This method is intended to simulate solid-layer contamination deposition on the insulator surface by wind 259 260. It can be used without any pre-treatment of the insulator’s surface. The amount of pollution accumulated on the insulator will be determined by its surface properties, the shed shape, the applied voltage and the number of test cycles. The wetting is achieved by fog and/or rain. Figure 6-1 shows an example of the cycle 260.

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Voltage Dust Fog Rain Wet Drying Time Figure 6-1: Schematic view of one cycle of the Dust chamber method260. The performance criterion of the insulator is the SDD-value of the artificial pollution layer, the test voltage and the number of cycles required to achieve flashover. To avoid too many cycles, a fixed number can be run to simulate a specific environment. The duration of pollution application and the amount of wetting have been calibrated using a standard type of insulator so that the pollution level after the fixed number of cycles corresponds to the specified degree of pollution. If no flashover occurs during these cycles, the test object is deemed to have withstood the specified degree of pollution for which it has been tested. A more detailed ranking using the leakage current and the SDD and NSDD-values is possible. Additional research is needed to establish the relation between these results and those determined from tests made according to IEC 507.

6.3.2.3 Dry Salt Layer Method (DSL) The DSL is intended to simulate dry salt accumulation close to the coast followed by wetting, ‘rain after the storm’, to achieve critical flashover conditions. No special pre-treatment of the insulator surface is required. The profile and adhesion properties of the insulator surface are allowed to influence the amount of pollution collected. The test is designed to represent the essential features of the pollution accumulation process away from immediate salt spray. Fine humid salt particles from a salt-injection system are blown towards the energised test object by high-speed fans for a predetermined time to give the required pollution level. Subsequently, it is exposed to a cold fog for wetting and to determine the flashover/withstand voltage. The equipment needed to apply the salt to the test object are standard Salt-Fog nozzles, as is described in the IEC 507, and large high-speed fans. A good control over the relative humidity in the test chamber is necessary. Further tests are needed to establish the correlation with results of tests conducted according to IEC 507.

6.3.2.4 Heavy wetting conditions Heavy wetting conditions may occur in service during severe weather situations - like heavy rain, typhoons and strong seastorms; it can also happen during live-line washing. Large amounts of water descend onto the polluted surface, which may lead to high conductivity values and possibly to an over bridging between the sheds, thereby initiating the final pollution flashover at phase-to-earth voltage. To check the ability of a polluted insulator to withstand heavy rain or washing without flashover at service voltage, the following test procedure was developed in the UK with respect to recorded rainfall data for England and Wales 261 262 and the CEGB practise for live washing. This test was an adaptation of a procedure developed to determine the performance of polymeric sheds fitted as supplements to porcelain barrel insulators. The test investigates whether inter-shed breakdown due to pollution and heavy rain bridging the sheds is responsible for reducing the flashover strength of insulators. A good correlation was found between types of insulators experiencing failures during this test and those that have a poor service history during heavy rain or live-line washing (e.g. tapered CTs, inclined transformer bushings, inverted-V substation insulators). The insulator, prepared and preconditioned as for the usual Salt-Fog test 22, is energised at the specified test voltage and subjected to the specified salinity for 15 minutes. After this pre-pollution phase, the fog is switched off and the insulator is left to drain for a further 15 minutes. After that time, the heavy wetting is applied at an angle of approximately 45o to the insulator. The wetting is in the form of an artificial rain of 2 mm/min with a water conductivity of 100 µS/cm. The test is considered a withstand if no flashover occurs during washing off the deposits or if the leakage current activity decreases. The heavy wetting test is deemed to have been passed if three withstand tests out of four applications could be obtained.

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The withstand salinities obtained from the heavy wetting tests are not equivalent to the withstand values from tests made according to IEC 507. This is due to the decrease of salt-fog deposits during both the drain period and the test period and the large difference in the quantity of water impinging on the insulator.

6.3.3 Non-standardised test procedures for laboratory tests on naturally polluted insulators To determine the actual strength of insulators from a specific site, laboratory tests on naturally polluted insulators could be performed. Examples for some of the procedures used are given in various publications 263 264 265 266. The "Hybrid Test" (artificial wetting of the naturally polluted insulator) basically contains the following parts: • Wetting of the pollution layer by steam fog or cold fog. • Application of the constant test voltage before or after the wetting process. • Increase of the test voltage in steps, or continuously, until flashover occurs. The test results, in terms of withstand voltage or flashover voltage, can be compared with the phase-to-earth voltage to determine the safety margin of the insulation to pollution flashover at service voltage. Also, the leakage current measurement during the test is a helpful indicator for the judgement on the insulation strength 267. This check of the actual insulation strength can also be used for implementation of remedial measures on line- and stationinsulators. It is also possible to check the pollution performance of an artificially polluted insulator at a specific site 113. In that case (natural wetting of an artificially polluted insulator), the result shows whether or not an insulator could withstand - at the phase-to-earth voltage - a specified degree of pollution under the wetting conditions at that site.

6.4 Test procedures for polymeric insulators to be used in high-voltage a.c. or d.c. systems Operational and laboratory experiences show that the pollution performance of new polymeric insulators is superior to that of glass or porcelain insulators. This excellent pollution performance may deteriorate during service time due to the influence of UV radiation, temperature, humidity and leakage current discharges. Different accelerated ageing test procedures have been developed 268, but as yet no agreed method is available for predicting the pollution performance of a polymeric insulator under given site conditions with time in service. The Cigré Task Force 33.04.07, ‘Testing of polymeric insulators’, is dealing with this problem. IEC TC 36 also deals with this in its work-programme.

6.5 Test procedures for insulators covered with ice or snow It is very difficult to do flashover tests on insulator assemblies covered naturally with ice or snow. Such tests would only be possible in field test stations located in areas with regular natural ice accretion or with heavy snowfalls. To make a statistical evaluation of the test results, it is necessary to perform multiple tests and, so, the use of laboratory test methods with artificial ice accretion or snow accumulation become necessary. Separate laboratory test methods have been developed for simulating ice and snow conditions. These tests have been made applicable to ceramic, polymeric, line-post and station-post insulators. The aim of the laboratory tests is to simulate, as close as possible, the service conditions the insulators experience under ice or snow.

6.5.1 Laboratory test methods with ice The development of testing methods for evaluating the flashover voltage of HV insulators under icing conditions is still at an early stage 94 359 356 357 269. The number of tests carried out in the past 30 years is rather limited when compared to other types of testing (e.g. Salt-Fog or Clean-Fog tests) and, above all, these tests have only been carried out in a few places. A very limited amount of information about the different icing-test techniques are currently available, as most researchers have developed test methods of their own - according to their extent of knowledge and to the financial means available. Some of the techniques could be considered closer to an art rather than a science, especially the very first techniques employed. Nonetheless, some interesting results have been produced. However, due to the differences in testing methodology, it is often difficult to compare the results of the reported tests. Test methods to determine the flashover voltage of iced insulators involves the following aspects:

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• Mounting arrangement • Ice accretion • Voltage application • Withstand voltage evaluation

6.5.1.1 Mounting arrangement It is recommended that the test object be mounted in a position similar to that of its service conditions. This is necessary because the distribution of ice on the insulator is influenced by the electrical field distribution around the insulator, as have been observed both in service and during laboratory tests 359 357.

6.5.1.2 Ice accretion methods Most of the techniques that have been reported use some kind of nozzle for ice accretion on energised or non-energised insulators 356 269 270 187 271 177 272. Some of the more sophisticated ice-coating methods also make use of wind generation systems in combination with the nozzles 94 269 270 271. The voltage (e.g. maximum operating value) should already be applied during the ice accretion phase by whatever method. The reference parameters used up to now, for describing the severity of the icing condition, are: • The time duration of the icing period 269 271. • The length of the icicles formed 191 194 184 313 273. • The weight of the ice deposit on the insulator 272. • The thickness of the accumulated ice on a monitoring pipe or conductor exposed to the same icing conditions as those of the test object 94 187 357.

6.5.1.3 Voltage application methods In the case of an ice-covered insulator, the surface condition on the test object is particularly sensitive to the presence of voltage. Leakage currents that flow across the insulator surface causes a significant heating effect leading to the melting of some of the accreted ice. This affects the ice deposit characteristics and can even ‘destroy’ the initial ice deposit. In the case where the flashover testing is related to a specific determined icing severity, it becomes obvious that only a single flashover test can be realised for each instance of ice accretion. This is the reason that, in most cases, a constant-voltage method is used in icing tests.

6.5.1.4 Withstand voltage evaluation The evaluation of the withstand voltage of the insulator under test usually varies according to the aim of the test and the chosen method of defining the electrical performance of the insulator under icing conditions. If the purpose of the test is to evaluate and compare the performance of the different types of insulator under a specific voltage level, it is suggested that the applied voltage is kept constant and that the time of ice accretion is varied. The test ends if a flashover occurs or if the probability of a flashover is judged to be low. In the latter case, the test-outcome is considered to be a withstand 359 187 357 182 274. However, in most cases, the aim is to determine the withstand voltage of the insulator under certain icing conditions. In this case, the ice accretion is stopped after reaching the specified value and the test voltage is applied in accordance with the procedures described in the chosen standard (e.g. IEC 60-1, IEC 507) for tests under constant voltage 94 183 194 358 313 271 272 275.

6.5.1.5 Cold fog method The cold fog test 180, reproduces natural conditions in which there is repeated re-icing of the insulator with a thin ice layer as the ambient temperature rises from -2oC to +1oC. For the cold fog test, the flashover strength of the insulator is determined repeatedly while the ambient temperature is raised slowly. During each cycle, the applied voltage is raised in increments of 35% - starting from the service-voltage value - until flashover occurs. At each step, the voltage is held constant for 60 seconds. It is found that roughly half of the flashovers are observed on the voltage-rise and the other half within the 60-second hold period. The flashover strength of the insulator reduces as the dew-point temperature increases to 0oC. This relation can be found through statistical analysis, to obtain the withstand levels for the insulator at 0oC.

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The cold fog test without icicles does not determine the minimum flashover level of an insulator. However, it does reproduce field conditions that are observed frequently and the test is severe enough to give realistic performance rankings.

6.5.1.6 Outdoor tests Outdoor tests of ice-covered insulators are mainly performed at test stations located in areas with suitable meteorological conditions 181. Also, some laboratory tests on ice-covered insulators have been performed in an outdoor/indoor testing station combination 183 358 , where the ice was formed under natural frost conditions by spraying water onto the de-energised insulator by means of a hand-held nozzle. The voltage test was then performed after the insulator had been moved inside. It is also possible to allow the insulator to collect ice during the night in an outdoor test facility and then to determine the flashover voltage during ice melting conditions - due to sunshine - in the morning 111.

6.5.2 Laboratory test methods with snow Various researchers have reported on tests methods with snow covered insulators 189 193 194 190.

6.5.2.1 Snow covering methods It is necessary to cover the test insulator assembly with snow in a short time to avoid a change in the properties of the snow. Some methods are as follows: 1.

2.

A snow-pile “jig” may be used to cover the test-insulator assembly with snow 190. If the test is conducted inside a laboratory, the jig and insulator assembly should first be cooled sufficiently by dry ice. The snow can then be piled into the jig and so onto the insulator. After the whole insulator assembly is covered with snow, the snow-pile jig is removed. Blocks are cut from naturally accumulated snow on the ground. These blocks are then arranged on top of the insulator assembly under test. The conductivity of the snow may be adjusted by uniformly spraying a salt solution over the snow. Just before the test the volume density, liquid water content, conductivity, and volume resistivity of the snow on the insulator are measured 189.

6.5.2.2 Voltage application method and test result evaluation A constant-voltage application method is utilised to determine the a.c. or d.c. withstand voltage during testing. This means that a constant voltage is applied to the insulator assembly covered with snow to check the withstand voltage until the snow falls off the assembly. After each test, the snow covering is renewed. If flashover occurs, the applied voltage is decreased by 5 to 10% and - correspondingly if withstand occurs - the voltage is increased by the same extent. This procedure is repeated about ten times to obtain the minimum flashover voltage and the maximum withstand voltage. The maximum voltage which gives 4 withstands and no flashover may be defined as the withstand voltage. For tests under temporary overvoltages, a continuous a.c. voltage is applied to the insulator assembly for 5 to 20 minutes. Then the voltage is raised steadily for 2 seconds to obtain the temporary a.c. overvoltage characteristics by measuring the time to flashover. This procedure is repeated every 5 minutes until the snow falls off the insulator assembly. For switching and lightning flashover tests, the up-and-down method is used to determine the 50% flashover voltage.

6.6 Additional information on particular points of pollution testing 6.6.1 Ambient conditions during testing 6.6.1.1 Introduction The ambient conditions during testing in a pollution chamber are defined as temperature, pressure and fog. These parameters are influenced by atmospheric conditions around the test chamber, which change during the day and throughout the year. This is especially so at pollution laboratories located at high altitude or in a warm climate - or in the situation where the fog chamber is not well insulated. Differences in ambient conditions during testing contribute to the variation in the results obtained at the various laboratories around the world. It is, therefore, necessary either to control the test conditions or to apply correction factors to the test results.

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From a standardisation point of view, the testing methods must meet the requirement of reproducibility 3. Therefore, it has been necessary to investigate the effect of the ambient conditions during testing on the flashover/withstand voltage of contaminated insulators subjected to a.c. and d.c. voltages. Taskforce 07 of Cigré Working Group 33-04 is dealing with the aspects of testing polymeric insulators. The findings of that taskforce will soon be published. The aim of this section is to review the current knowledge published in the technical literature on the effect of ambient conditions during testing and reproducibility in artificial tests.

6.6.1.2 Effect of Temperature a) Atmospheric temperature Arai 276 has shown that the temperature-rise in the chamber is greatly affected by the atmospheric temperature. This effect should be taken into account during testing, especially if the chamber is poorly insulated and/or tests are conducted in very warm climates - otherwise, the test results will be different from those obtained at other laboratories. Lambeth et al 277 have suggested recommendations to overcome this situation. b) Ambient temperature-difference Several researchers have investigated the effect of the ambient temperature on the wetting process. For example, Rizk 67, Kawai 112 and Naito 278 have observed that the temperature difference between the insulator’s surface and the ambient is approximately 2°C in artificial tests, which are similar to that which may occur naturally. Karady 68 has shown that the fogtemperature is not constant but increases with a definite time constant. The influence of the temperature on fog generation is discussed in a little more detail in the section dealing with fog. c) Effect of the temperature on the flashover/withstand voltage A significant influence of temperature on the contamination flashover voltage has been reported for both the Equivalent-Fog and the Salt-Fog methods under d.c. voltages.

Figure 6-2: Influence of room temperature on 50% FOV 281. Ishii et al 279 have observed - when using the Equivalent-Fog method - that the d.c. flashover voltage of contaminated insulators reduces by about 0.7 - 1.0% /°C rise in temperature and that the d.c. arc-characteristics are temperature independent. This effect is attributed exclusively to the change of the resistance of the pollution layer. Naito 280, using a Salt-Fog procedure for d.c. insulators, has found that the value of the flashover voltage decreased with the increase in the temperature for the range 5 to about 35 degrees Centigrade. The findings were variable and in, some cases, this decrease in voltage was more than 20% of the lowest-temperature value. An example of the results is shown in Figure 6-2 281 . It is reasoned that this general trend is caused by the increase in conductivity of the polluted layer as the temperature increases 37. A similar phenomenon has been observed for a.c. voltages by Moreno et al Mizuno et al when employing the Clean-Fog procedure 281.

282

when using the Salt-Fog procedure and by

In the standard contamination tests, the influence of temperature has so far been disregarded.

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6.6.1.3 Effect of ambient pressure The effect of ambient pressure on the flashover voltage is important for pollution laboratories situated at high altitude and has been investigated in both variable-pressure chambers and at special outdoor facilities at high altitude. This topic is discussed in Section 3.3.8, where a general overview of the air density correction factors is given.

6.6.1.4 Effect of Ambient Fog It is well-accepted that the flashover voltage and the minimum surface resistance depend on the wetting method and the parameters of the fog. The artificial fog used to wet polluted insulators in laboratory tests can be produced by different means (i.e. cold fog, steam fog, evaporated fog, etc.). Not every type of fog is, however, suitable for use in Clean-Fog artificial pollution tests. On the realisation that good wetting is achieved on insulators by condensation, only fog produced by boiling water has been accepted for conventional tests. The wetting is uniform, the wetting-rate is slow and the washing-effect is small. The fog density can be controlled by regulating the capacity of the boiler element. However, an increase in chamber-temperature is unavoidable after some time of fog generation - due to the use of steam. The result is that the flashover voltage tends to be lower as the temperature increases.283 The comparison of results between different laboratories is difficult to make, because the flashover values differ markedly for the same insulator and pollution level. This may be ascribed to a significant difference in wetting achieved in the various arrangements. However, to simulate more accurately the natural low-temperature wetting process on polluted insulators - e.g. due to high altitude - an alternative humidifying technique using an ultrasonic clean-fog system, has been proposed for a.c. testing284. Karady 68 has analysed the wetting process during the testing of artificially contaminated insulators. It was found that the flashover voltage depends on the fog condition. Different fog-generation methods (cold, warm, and steam) were also analysed. It was concluded that the pollution test results for an artificially contaminated insulator depend on the fog parameters and the fog-generation method. The operation of the fog chamber can be optimised by adjusting the fog parameters to achieve the minimum flashover voltage. Arai 276 has established the correlation between the steam flow-rate and fog density and has suggested that, for the fog withstand test using steam fog, the ideal fog condition would be about 3 to 7 g/m3 for the maximum liquid water-content of the fog. Parameters like the temperature-change after fog generation, the liquid-water content of the fog and the water depositdensity on the insulator surface were measured. The results show that the initial temperature and the steam flow-rate greatly influenced the characteristics of the fog chamber. The results also show that the faster the steam flow-rate, the higher the temperature rise for a given wetting time. According to the results obtained, a higher initial temperature resulted in a slightly smaller temperature rise at the same steam flow-rate. With regard to the effect of the steam flow-rate on the a.c. fog withstand voltage, Arai 276 has shown that the withstand voltage tended to be higher at a lower steam flow-rate of each initial temperature. He concluded that the value of the steam flow-rate could not be defined as merely the steam-fog conditions. Arai 276 also reported on the effect of maximum liquid water content of the fog on the fog withstand voltage; the main points are: • When the maximum water content of the fog was smaller than a certain value, of some 3g/m3, the withstand voltage tended to become higher regardless of the initial temperature. • The withstand voltage was almost unchanged, within 5 to 7% of the dispersion for a certain range of the maximum liquid-water content of the fog. • When the liquid-water content of the fog was extremely high, the results tended to show a large degree of dispersion because of the washing effect of the fog. The influence of the fog parameters on withstand voltage of contaminated insulators has been investigated by Naito et al 278. The optimum fog conditions of the fog withstand method were mainly investigated on the basis of the comparison between natural and artificial fog conditions and the influence of fog conditions on the withstand voltage. Their conclusions are as follows: a)

The fog density of 3 to 7g/m3, under which withstand voltages with a small scatter of values was obtained, was several orders of a magnitude higher than the density of natural fog. This is because the artificial fog is used to wet the contaminated insulator in a reasonably short period of time.

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b) The droplet size distribution, which influences the wetting process by collision under the artificial fog, was almost the same as that of natural fog. c) By using steam or hot water, the temperature-difference between the insulator and the fog-chamber was 6 to 7°C. This value was higher than that of natural fog. Therefore, the artificial wetting process is accelerated from the viewpoint of the condensation. NGK has reported 44 measurements of fog-density in the range of 2 to 5 g/m3 for steam injection and 0.5 to 1.8 g/m3 for evaporation-fog. Similar measurements with evaporation-fog at HVTRC gave 0.3 to 1.5 g/m3. In their conclusions they have reported that, for fog densities higher than 0.3 - 0.4 g/m3, both the evaporation-fog and the fog produced by steam injection gave the same level of flashover voltage. The wetting rates were also quite similar. The authors have suggested the need to investigate the performance of insulators under very light fog condition, characterised by fog densities of less than a 0.3 g/m3. This is because the uneven wetting along the string may cause a non-uniform voltage distribution - which, in turn, may affect the flashover voltage.

6.6.1.5 Reproducibility of artificial tests Reproducibility 277 is defined as the extent to which a specified test gives the same result when performed in different laboratories. In other words, reproducibility describes the degree to which a test can be made in different laboratories and still achieve the same result. This requirement for artificial pollution methods is important for all the testing laboratories located in different parts of the world. The Salt-Fog and Clean-Fog methods for HVAC have been shown to meet the requirement of reproducibility 277. However, for HVDC, the Salt-Fog method has been unsatisfactory 285 and the variants of the Clean-Fog test-procedure have given different results when performed in different laboratories. To investigate this problem, a comparative programme for the HVDC contamination test was performed by NGK (HV Lab) and EPRI (HVTRC). It was concluded that the flashover voltage obtained in these two different laboratories agree very well when some important test parameters are controlled carefully 44. Recently, a worldwide round-robin test of HVDC insulators was carried out in six laboratories 285. It was aimed at the standardisation of the method for artificial contamination tests on HVDC insulators. The results are summarised as follows: 1.

2.

3.

The test results of the Clean-Fog procedure seem to be reproducible because the scatter among different participants is about that obtained in artificial contamination tests on HVAC insulators, for which the test-procedure has already been standardised. The reproducibility of the results obtained by the Salt-Fog procedure is not very satisfactory. Further investigation seems necessary, in terms of reproducibility and repeatability, to standardise the procedure of artificial contamination testing on HVDC insulators. It seems that sufficient information is available to allow the preparation of provisional international specifications for artificial contamination testing of HVDC insulators.

6.6.2 Leakage current measurement The leakage current that flows during a pollution test gives information on the development of an arc bridging over a certain part of the insulator length 198 286 267 287 153. The highest leakage current that occurs during a laboratory withstand test is, therefore, a characteristic value for a particular insulator at the given severity and the given specific creepage distance. Figure 6-3 shows an example of the leakage current characteristic of the longrod insulator L 75/22/150 at the a.c. test voltage of 72 kV rms. If leakage current measurements are performed on an insulator in service at a particular site, these measurements may be used to judge the insulator’s electrical strength of that site. This is achieved by comparing these site-measurements with the leakage current characteristic determined in the laboratory - provided of course, that the specific leakage path length of the insulator in service is the same as that used in the laboratory test. Maintenance measures like cleaning, washing or greasing may also be initiated by measuring the leakage current on site 288. This measurement of current is used only for glass and porcelain insulators and does not apply to hydrophobic polymeric insulators. This is because for the latter, flashover occurs without a clearly pronounced development of the leakage current with time. Another advantage of the leakage current measurement made during laboratory tests has been identified 267. In the case of small clearances between insulator sheds, the bridging over of these air gaps can be indicated by the current measurement.

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Such an insulator has a characteristic like that of an insulator with a shorter creepage distance, provided the applied stress on the latter does not lead to bridging over between the sheds. 2 A

Leakage current

1,5

1

0,5

0 2,5

5

10

20 kg/m³ 40

Salinity Highest leakage current from 1 hour withstand test; Current in the halfcycle before flashover;

Figure 6-3: Leakage current characteristic of the longrod insulator L 75/22/150 (test voltage 72 kV rms, creepage distance 2480 mm).

6.6.3 Testing of insulators for the UHV range up to 1100 kV Pollution tests on insulators for the UHV range require a large test-chamber and the corresponding polluting and wetting equipment. To fulfil the requirement of minimum short-circuit current in artificial pollution tests, a test-transformer and regulator with low short-circuit impedance are needed. The question of full-scale testing depends on whether or not the dielectric strength of polluted insulators is proportional to the insulator length at the same degree of pollution. If so, the results at lower voltages could be extrapolated to the UHV level. Verma 289 has conducted a critical analysis of several research projects 290 113 291 251 292 293, taking into account the practical range of UHV insulation dimensioning and the influence of the voltage-drop on the test results. Essentially he concluded that: Considering reasonable high dispersion of pollution test results in general and the relevance of the pollution performance of long insulator chains to practical insulation levels, linearity can be assumed for all practical purposes. Even if a non-linearity of 10% is claimed, it should not be forgotten that inaccuracy in insulation design due to a lack in knowledge of the actual site severity is greater than that resulting from assuming linearity for insulation design showing satisfactory performance. The insulation design data for 1100 kV can, therefore, be obtained by extrapolating the results already obtained and used for 400 kV systems.

6.6.4 Comparison of test results obtained with different pollution test methods Each of the two test methods, the Salt-Fog method and the Solid-Layer method, simulates different pollution conditions that lead to a pollution flashover. This difference may lead to different rankings for several insulators, using these two test methods. For different insulators, there is no direct relationship between the severity parameters of the test methods. For one insulator type and the same electrical stress, a correlation between the test methods is possible - using either the flashover voltage or the leakage-current characteristic.

6.6.5 Comparison of test results obtained from test stations In Figure 6-4, the a.c. flashover-voltage data obtained at 3 different natural test stations are compared with those of artificially polluted insulators under a Clean-Fog test. The smaller dispersion of the artificial contamination test results is due mainly to the more uniform spread of the pollution on the insulator surface. The lower flashover values obtained with the artificial tests, as compared to the insulators polluted naturally, can be ascribed to the use of pure NaCl in the test. Naturally polluted insulators may contain low solubility salts that will lead to higher fog withstand values.

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Figure 6-4: Results of a.c. natural contamination tests compared with Clean-Fog tests294. A similar tendency as reported above for a.c. energisation has been obtained for a comparison of d.c. results - as is shown in Figure 6-5.

Figure 6-5: Results of d.c. natural contamination tests compared with Clean-Fog tests 252.

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7. INSULATOR SELECTION AND DIMENSIONING 7.1 Introduction External insulation should be properly selected and dimensioned so that the resultant risk of flashover is reasonable. It may be worthwhile to do a probabilistic, or risk-of failure, assessment. This section starts off with a discussion on how insulator characteristics can best be selected, followed by a comparison of the traditional deterministic design philosophy and the more recent probabilistic approach. The difficulties in obtaining enough data for the statistical approach will also be highlighted. Finally, a summary of available literature related to the probabilistic approach to insulator design is given.

7.2 Selection of Insulator Characteristics When insulator characteristics are selected, the complete flashover process should be borne in mind. Both the environmental and electrical aspects thereof should be incorporated. In Figure 7-1 an approach is given that can be utilised in selecting the insulator characteristics. Frequency and type of wetting

Type of pollution

Active type Conductive Dissolving Inert (effect of )

Prediction of critical wetting conditions

Mechanism of pollution deposit

Precipitation Wind borne Electrical

Amount Density Particle size

Insulator application

Estimation of pollution distribution on the insulator

Identify possibility of self cleaning and required insulator properties or need for maintenance

Test and service experience

Identify optimal profile & material for insulator

Profile criteria from experience and supplier’s data

Creepage Estimation Insulator selection and length

Figure 7-1: A structured approach to the selection of insulator characteristics. Figure 7-1 complements Figure 1-2 in that it shows how the information collected, through the process of insulator selection as outlined in Figure 1-2, is applied to select the insulator profile, axial length and creepage path length. Referring to Figure 7-1, the selection process is outlined as follows:

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7.2.1 Selection of profile From a study of the environment in which the insulators must operate, the pollution is characterised together with the identification of both the most likely mechanism of pollution deposit and the type of wetting conditions. From the pollution type - e.g. conductive, dissolving etc. - and the different types of wetting that occur, a prediction is made of the critical wetting conditions. That is, the wetting conditions under which flashovers are deemed to be the most likely. In parallel with this procedure, the likely spread, uniformity and density of the pollution layer on the insulator is determined from the following: • The identified mechanism of the pollution deposit; whether it is by precipitation, wind or electrical forces. • The physical characteristics of the pollution; i.e. density, particle size etc. • The location of pollution sources and prevailing wind-direction. • The amount of pollution present. In areas where the mechanism of the pollution-deposit is mostly by precipitation, insulators with large horizontal surfaces may collect more pollution than do those with small horizontal surfaces - but perhaps with more shed under-ribs. On the other hand, if the deposit mechanism is by wind aerodynamically shaped insulators may again collect less pollution than do the ones with a more convoluted shape. More information and measurement results are contained in Sections 2.3.3 and 2.3.7. The severity of the pollution can be estimated by using one of the methods listed in Section 5. The results of such measurements should be compared with the corresponding service experience to obtain an indication of the site severity. From the type of wetting - as obtained from weather data - and the identified critical wetting conditions (Section 2.3.6), the possibility of self-cleaning is then determined. For instance, if the critical wetting condition is identified as being mist or fog plus the presence of marine salt, self-cleaning can then only occur if the cleaning action of the wetting outweighs its pollutionwetting action. Therefore, significant self-cleaning will only occur under a heavier wetting condition; in this case, rain. Similarly if heavy rain is identified as the critical wetting condition, it can be concluded that self-cleaning by wetting can not be relied upon. Another self-cleaning mechanism that is worth investigating is that of “wind blasting”. More details are provided in Sections 2.3.3 through 2.3.7. If the possibility of self-cleaning without the risk of flashover can be ruled out, the need for insulator maintenance should be investigated. By taking into account the pollution type, the critical wetting and the distribution of pollution, the appropriate maintenance procedures can be identified together with the insulator profiles that facilitate such maintenance. Once all the above factors have been investigated, the optimal profile and material can be selected. If self-cleaning is necessary, insulators with an aerodynamic shape can prove beneficial. If no self-cleaning possibility exists, insulator shapes with less accessible profiles might be more beneficial. In selecting profiles, it is necessary to rely on the results of artificial tests and/or service experience. The limitation of profile designs for station post insulators are also set out in IEC publication 815. Polymeric insulators may be considered, for reasons given in the introduction to Section 3.

7.2.2 Selection of insulator dimensions The findings provided in Section 3 can then be applied to estimate the insulator dimensions; i.e. axial length and creepage path length. Correction factors for large diameter insulators, both with regards to pollution deposit (Section 2.3.7.3) and flashover strength (Section 3.3.1.4) can be considered. Insulator diameter and shed spacing may be significant factors in determining pollution performance in outdoor stations - particularly for equipment such as bushings, circuit breakers, and measuring devices. The application of glass and ceramic insulators for a.c. voltages above 525 kV, as well as for high d.c. voltages, raises the question of linearity of insulator flashover voltage with insulator length. Although such data are quite limited at this time, because of the large test objects and laboratory equipment involved, it appears that the flashover voltage is nearly a linear function of insulator length. However, at system voltages reaching levels of 1200 kV a.c., or 800 kV d.c., even a slight nonlinearity of such will require longer insulator assemblies in polluted areas (see also Section 3.3.1.3.). The possible adverse effect of a non-uniform pollution deposit should also be considered; this has been discussed in Section 3.3.4. If constraints on insulator length prohibit sufficient creepage distance with the chosen profile, it becomes necessary to choose an alternative profile or to consider utilising a different type of insulator material. Again service experience and artificial test results are of the utmost importance.

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In the case of d.c. energisation, the accumulation of pollution is generally higher than that on an insulator for a.c. in the same environment. Consequently, the required creepage distance to withstand pollution for d.c. must be suitably increased over that recommended for a.c. to obtain the equivalent performance. For d.c. substation insulators, such as wall bushings, insulator selection must take into account the behaviour of these insulators in relatively clean areas with non-uniform wetting. Section 3.4.2 discusses this topic in more detail.

7.2.3 Deterministic method The deterministic method has generally been used for the design and maintenance of electrical and mechanical components, apparatus, systems etc. The component is then designed according to material selection, dimensioning etc. to achieve a withstand value “W” of the component with a certain acceptable margin of safety between “W” and “S” - where the latter is the probability relationship associated with the environment.

Probability Insulation (W)

Environment (S)

Margin

Site severity Figure 7-2: An example of the deterministic method. In Figure 7-2, the deterministic approach is illustrated by using an example for obtaining the design withstand pollution severity of an insulator with respect to the maximum pollution severity of the environment in which the insulator must operate. In this example, the operating voltage of the insulator, Vs, is known. The maximum withstand pollution severity (ESDD) that the insulator must withstand is then calculated by assuming complete wetting of the pollution layer. The design withstand pollution severity, or the corresponding withstand voltage, Vw, is determined with an acceptable margin; e.g. 10%, between Vw and Vs. The following problems exist with this approach: 1. 2. 3.

The pollution severity, insulator withstand voltage and the degree of wetting are all probabilistic values. The selected margin depends on the judgement of the design engineer and has, therefore, no statistical significance. Only a single insulator string, or stack, is considered in this approach; but, in the actual design, many such insulators are connected in parallel.

7.2.4 Probabilistic method. In the probabilistic method, the principal parameters are considered as variables; this is markedly different from the deterministic method, where the variables are assumed to be constant. Figure 7-3 shows the principle of the electrical design of insulators against switching overvoltages, which is described in IEC Publication 71295 296. The probability density function of the expected switching overvoltage is considered a variable and is denoted as “f” in the figure. Generally, it follows a normal distribution. The flashover probability of the insulator is shown by curve P in the accompanying figure. The probability of flashover, logically, increases for higher voltages “U”. The risk-offailure is calculated by integrating the probability density function, f*P; it is shown in the figure as the shaded area.

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If the insulation strength is increased, the “P” curve moves to the right of the “f” curve and the risk-of-failure decreases as shown in Figure 7-3b; but such a change can be costly. The optimum design is, therefore, obtained by optimising the cost against the risk-of-failure.

P

P

f

f

(a)

U

U

(b)

Figure 7-3: An example of the probabilistic method; the effect of increasing insulation strength. The probabilistic approached is considered in a similar fashion for the mechanical design of an overhead line support in IEC Publication 826297, where the strength of the support and the load applied to it are considered as variables.

7.2.5 Static and dynamic methods in the probabilistic approach. Two methods can be used in the probabilistic approach. One is the static method that is described in the previous section, and the other is a dynamic approach. The former is relatively easy to follow, but the risk-of-failure can only be calculated over a long period; i.e. annually, over 50 years, etc. In contrast to this approach, instantaneous risk-of failure can be calculated using the dynamic approach; however, the calculation is quite complex and data relevant to that moment must be available. The dynamic method is, therefore, currently not in general use. Table 7-2 summarises the two methods of the probabilistic approach in selecting insulators in a polluted environment298 299. In the static method 298 299 300 301 302 151 303 304 305 306 307, the probabilities of flashover voltage and other factors are combined in a reliability-calculation. In the dynamic method 67 306 308 309, the instantaneous changes in various factors, such as the weather, are taken into account for making a reliability calculation. Table 7-2: Summary of probabilistic approaches for selecting insulators in a polluted environment. ITEM Description

STATIC METHOD Obtain risk of failure, “R”, by integrating the product of “F(w)”, distribution function of ESDD, and “P(w)”, Flashover probability.

Advantage

Easier calculation and survey because the required input data are only distributions of ESDD and flashover probability. However, data for this calculation are not readily available due to cost and time constraints. Only an overall risk-of-failure in a certain period is available.

Disadvantage Possible improvement

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DYNAMIC METHOD Obtain risk of failure “R(w)” in a certain period, by summing up the product of “w(ti)”, ESDD at a time and “P(w)”, flashover probability. Possible to obtain risk-of-failure at any time and, thus, may be utilised as 'an alarm' of pollution for a system.

Necessary to input instantaneous weather data, and the calculation is more complicated. A method for calculating of risk-of-failure that is not influenced by the sampling time.

7.2.6 Present status of the probabilistic approach One of the first practical applications of the probabilistic approach was carried out by Karady et al 302. They showed that the distribution of Equivalent Salt Deposit Density (ESDD) on insulators at the coast over a period of a year follows a Gamma distribution, as is shown in Figure 7-4. The flashover probability of the insulators was assumed to be a normal distribution and the fifty percent flashover voltage and standard deviation were obtained as a function of ESDD by performing artificial laboratory tests. The risk-of -failure was then calculated by using the two distribution functions. In Figure 7-5 the resultant risk-of-failure for 45 parallel insulator strings for a 340 kV transmission line is shown as a function of the voltage per insulator.

Cumulative probability [%]

100

80 no pollution 60 very light pollution

light pollution

40

20

1.0

0

2.0

3.0

4.0

5.0

ESDD [mg/cm2 x 10-2] Figure 7-4: An Example of cumulative probability of ESDD 302.

100

Risk of failure (%)

80 60 40 20

0

4

8

12

16

20

Voltage per unit, kV

Figure 7-5: Risk-of-failure as a function of voltage per unit 302. Lambeth 306 307 deals with statistical factors theoretically to determine the suitable insulator length for polluted conditions. In his documents, pollution severity and flashover stress are considered as variables. Sforzini et al 303 apply the statistical approach for the selection of the type of insulator. The statistical distribution of pollution severity is approximated by using a Gaussian distribution, as is shown in Figure 7-6 - this distribution is based on measurement of surface conductance made on insulators at three sites. An acceptable value of the risk-of-failure is then

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assumed by considering the tolerable number of events per year. For this risk of failure value, the required flashover value at the equivalent severity of the pollution on the insulator is determined. A suitable insulator is selected from the standpoint of leakage path length. The standardisation of insulators for polluted areas is also discussed. CAIRO MONTENOTTE Surface conductivity ( Aug: 77 - Oct: 81 ) No of critical events: 125

Cumulative probability (%)

99.8 99.5 99.0

95.0 90.0

PORTO EMPEDOCLE Salinity - ( Jan: 79 - Oct: 81 ) No of critical events: 105

70.0 50.0 30.0

PORTO MARGHERA ESDD -( Aug: 77 - Oct: 81 ) No of critical events: 102

10.0 1.0 1

2

4

6

Insulator Y

8 10

20

40 60 80 100 200 Surface conductivity (µS)

Figure 7-6: Examples of cumulative frequency distributions of the maximum values of pollution severity recorded in the various events at three typical sites (values are expressed in terms of the equivalent severity relevant to the laboratory method deemed more valid for each site) 303. Figure 7-7 shows an example design-standard for 132 - to 150 kV lines. 320

Withstand Salinities (kg/m 3)

160

132 kV lines 150 kV lines

80 40 20 10 5 2.5 9 (10)(11)(12) 9 10 11 12 Standard units Antifog units

Figure 7-7: ENEL standardisation; dimensioning of insulator strings for 132 kV and 150 kV lines 303. Naito et al 299 have extended the approach into three dimensions. They calculated the static risk-of-failure on 800 kV transmission lines by treating the flashover voltage, pollution severity and degree of wetting as probabilistic values. A regression curve for relative humidity (RH) was proposed, as shown in Figure 7-8, which is based on hourly observations. The corresponding probability of simultaneous occurrence of ESDD and RH is shown in Figure 7-9.

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Probability exceeding abscissa value [%]

99.9

100 points

99.

8760 points total 90. 80. 70. 60. 50. 40. 30. 20.

1. 0.1

10

20

30

40

50

60

70

80

90

100

RH [%] Figure 7-8: Cumulative probability of Relative Humidity 299.

Probability of occurrence (%)

The flashover probability, as a function of RH and ESDD, is shown in Figure 7-10, for 200 parallel insulator strings.

3

2

1 1.5 1. 0.1

0 0

20

40 RH [% ]

60

80

0.01 g/c m [ 0.05 DD 100 ES

2]

m

Figure 7-9: Probability of simultaneous occurrence of ESDD and RH 299. The risk-of-failure is calculated as the volume indicated in Figure 7-11 and a value of about 0.03 per year was obtained, thereby implying that there are 11 days of flashover per year.

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Flashover probability (%)

100 80 60 40 20

1.5 1.

0

0.1 0

20

40

60

RH [% ]

80

0.01 0.05 SDD E 100

2]

m g/c [m

Figure 7-10: Flashover probability, Pn, as a function of RH and ESDD (N=200) 299.

Risk of failure (%)

80 60 40 20

1.5 1. 0.1

0 0

20

40 60 RH [% ]

80

0.01 [m 0.05 D D 100 ES

2]

m g/c

Figure 7-11: Risk-of-failure obtained (N=200) 299.

7.2.7 Dynamic method Rizk et al 67 have described a dynamic statistical method to evaluate transmission line performance. The line was divided into several sections, each of which was assumed to be exposed to uniform conditions of pollution build-up and wetting events. The total number of flashovers expected over a certain period of time were determined from the sum of the flashovers of the different sections. In any given line-section and exposure-period, the statistical variation of the string flashover voltage for a given pollution severity - as well as the statistical variation of the pollution severity itself - were considered. It was shown that the most important parameters to determine line performance are: the ratio of the operating voltage to the 50% flashover voltage of the string, the resultant coefficient of variation and the number of wetting events 67. Lambeth 306 has also suggested the need to consider the change with time of the pollutant deposit, the wetting etc. Yamada et al 308 have extended the static model of flashover risk - by Naito et al 299 - into a dynamic model. According to this model, the instantaneous change in climatic data produces a change in the ESDD value and the wetting-rate. These, in turn, affect the flashover probability and risk-of-failure. Figure 7-12 shows an example of the results. A similar approach of dynamic-risk prediction under snow/ice conditions is used in Canada 180 310.

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15 10

Wind velocity (m/s)

5 0 3

Rainfall (mm/10min)

2 1 0 100

ESDD (mg/cm2) 50 0 100 RH (%)

50 0 100

Degree of wetting (%)

50 0 0.6

Absorption density of moisture (mg/cm2)

0.4 0.2 0.0 60

Flashover probability (%)

Actual flashover

40 20 0 0

6

12

18

0

6

12

18

0

6

Time of day Figure 7-12: A sample simulation of flashover probability311.

7.2.8 Truncation of the distribution In almost all cases, the studies that have been made assume that the flashover voltage, pollution severity etc. follows a normal distribution. In reality, however, the distribution of relative humidity is truncated - as shown in Figure 7-8. Houlgate et al126 have reported that, in a natural pollution test station, the distribution of flashover voltage is truncated - as shown in Figure 713. The values of V50 and sigma derived from this curve are considered different from those obtained from the results obtained by artificial pollution tests. A statistical flashover study312, comprising 2800 tests on artificially polluted insulators, also indicates that a truncation of the distribution exists.

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100

EHV UHV

160

 E − Eo  N = k   Eo 

150

90

n

Eo = 99 . k = 161 n = 2.1

140 130

80 70

120 110

60

100 90

kV actual, m-1, overall length

Normalised Flashover Stress kV,system m-1, overall length

170

50 0.01

0.1

1.0

10

Cumulative Frequency, Flashover/insulator/year Figure 7-13: Cumulative frequency distribution of EHV and UHV normalised flashover stresses for the total test period at Brighton insulator testing station 126.

7.2.9 Conclusions Many probabilistic approaches have been reported for designing insulators under polluted conditions. From a methodological point of view, a considerable amount of work is still necessary before this type of approach can be internationally accepted. In addition, for such an approach to be successful, reliable statistical data of both the pollution severity and the insulation strength are required. The statistical approach is, therefore, not yet sufficiently advanced to be applied in the design or maintenance of insulators in a polluted environment. However, such a method can give a clear indication of the critical conditions that will lead to insulator flashover.

7.3 Selection of insulators for application under ice and snow On the basis of laboratory results, it is possible to employ either a deterministic or a probabilistic approach in selecting insulators for use under ice or snow conditions. The following points need to be considered: a) The maximum electrical stress on insulators for transmission lines and substations should be kept below the corresponding withstand value determined for ice and snow conditions in the laboratory. Some authors 313 314 indicate a stress limit of 75 kV/m for both a.c. (rms value) and d.c. A value of 200 kV/m (peak) is suggested for the switchingsurge stress limit where the axial length of the insulator is used to calculate the stress. However, it is still necessary to take account of other effects and conditions on the insulator - such as non-linearity effects on long strings, diameter of the insulator, shed profile and insulator surface condition - to achieve a successful design. In environments having a moderate pollution level - i.e. 0.1 to 0.2 mg/cm2 - and where cold fog conditions are expected, the design withstand-level should be reduced to about 60 kV/m. This value is based on the results obtained for 1.85 m, 230 kV insulators; thereby indicating a 75 kV/m CFO, with a 5% standard deviation. Under ice and snow conditions, the lightning impulse level of insulators may be reduced by up to 50%. Therefore, the designer must consider whether it is necessary to take ice and snow effects into account when considering the lightning performance. The factors to consider are the probability of simultaneous occurrence of snow or ice and lightning and the amount of snow and ice that is expected to accumulate. b) The probabilistic method is based on the calculation of the insulator length, or the number of discs in the string to withstand flashovers - as considered from the U50. The latter being obtained from ice and snow test results, assuming an expected flashover probability of less than 0.2. The calculation should also take into account the presence of other strings - i.e. parallel gaps - on the line subjected to the same icing conditions.

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7.4 Selection of insulators for d.c. energisation 7.4.1 Introduction Several specific characteristics are necessary for effective d.c. insulation: 1. 2. 3.

A correct insulator profile is required to enhance the withstand characteristics and to reduce pollution build-up. High resistance / high purity dielectrics are necessary to reduce the risk of ion migration / accumulation. Sacrificial electrodes on metal fittings are necessary to avoid the effects of unidirectional current flow, especially in humid environments. Points 2 and 3 are covered in detail in IEC 61245 that gives minimum values and test methods to check these parameters. Point 1 is more difficult to specify. For glass and ceramic cap and pin designs and post and bushing insulators, the optimal profiles are well known315. However for polymeric insulators, the lack of service experience - especially for d.c. - means that the profiles which are currently used are based on laboratory artificial pollution tests only and do not take into account pollution deposition mechanisms found in service. Hopefully the growing use of polymeric insulators for d.c. applications can remedy this lack of knowledge and experience.

7.4.2 Selection of a site severity correction factor When dimensioning outdoor insulators for d.c. lines or stations, the pollution level measured from the nearby a.c. lines or stations provides important indications for the possible pollution levels of the d.c. lines or stations. Since insulators energised at d.c. voltage may attract more contaminants than occurs at a.c. voltage, a correction factor is sometimes needed 316. This correction factor, referred to in the following as Kp, is the ratio of the pollution level at d.c. voltage, Pdc to the corresponding value Pac at a.c. voltage; i.e. Kp = Pdc/Pac. Various researchers have reported measurements, from which could be determined the values of Kp 317 59 318 319 320 81 321 322 323 324. As has been discussed in Section 2.3.3.1, the main cause of the difference between the contamination accumulation at d.c. voltage and that at a.c. voltage is the electrostatic force. However, the force that can outweigh 323 the effect of this electrostatic force is wind. Therefore, in areas where wind is the dominant force that brings contaminants onto the insulator, the difference between the d.c. and a.c. conditions is small. In areas where wind is not the only major force that brings contaminants onto the insulator, differences are seen between the contamination accumulation for d.c. and a.c. conditions. The extent of this difference depends on the wind speed, the type of pollution source and the distance to the pollution source. Contaminants from natural sources - such as sea salt, desert sand or earth particles from open dry land - are mainly generated and transported by the wind. The amount of contaminants and the transportation distance are the function of the wind-speed and duration. In areas where these types of pollution are the major sources, a lower Kp value will be appropriate. Some other types of pollution sources are: highways, industrial release, residential areas (especially when coal and wood are used for cooking and heating), mining and construction work. These are the man-made pollution sources. Contaminants from these sources are “self” generated rather than wind generated. The amount of contaminants produced bears little relation to the wind-speed. The contaminants can spread from the pollution sources over a distance that ranges from a few hundred metres to one or two kilometres at low wind-speed. If a d.c. station is located near such pollution sources or a d.c. line is passing through such areas, there is a larger difference between the pollution levels of d.c. and a.c. insulators, i.e. a higher Kp value may be expected. During high wind, the contaminants from some of the industrial sources may be transported over a few kilometres. However, the reduction in the amount of contaminants with distance from the source is greater for the selfgenerated pollution than it is for the wind-borne types. In some exceptional weather conditions, industrial pollution - released as gases - can be carried over hundreds to thousands of kilometres181. In areas that are considered as clean from the viewpoint of a.c. voltage, few measurements have been made. However, a significant difference between d.c. and a.c. pollution levels has been observed in some areas 324 317, whilst no difference has been found for some other areas. Pollution sources may exist, but their effects may not be discernible because the pollution level is low. In this case, a high Kp value is to be adopted. Further investigations are necessary to characterise the clean areas. As a rough approximation, the value of this correction factor Kp is given Table 7-3325

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Table 7-3: Correction factor, Kp, that provides the ratio between pollution levels at d.c. and a.c. voltage 325. KP 1 - 1.2 1.3 - 1.9 2-3

SITE CONDITIONS areas influenced only by natural pollution sources, such as sea and desert areas influenced both by natural pollution sources and by industrial pollution sources but at a few kilometres distance from the industrial pollution sources areas close to (within a few kilometres) industrial pollution sources and are considered as clean from the viewpoint of a.c. voltage

A further parameter that may intensify the accumulation of contamination at d.c. voltage is the electrical charging of the contaminants by industrial processes or by corona discharges from high-voltage equipment.

7.5 Insulator pollution design of Phase-to-Phase Spacers 7.5.1 Introduction Phase-to-phase spacers are mainly used to prevent mid-span flashovers occurring during conditions of galloping, conductor jumping following ice release etc. on transmission lines. These spacers may be either porcelain or polymeric ones. In addition, phase spacers may be required for compact line designs, reduced phase spacing to decrease magnetic field levels, or to improve the aesthetics of the line. The design of phase-to-phase spacers may be different from that of phase-to-ground insulators.

7.5.2 Design Practice The fundamental procedure for the design, from the pollution viewpoint, of phase-to-phase spacers is the same as that for phase-to-ground insulators except that the withstand voltage is √3 times that for the phase-to-ground voltage 326 327. Not only are the design procedures the same for phase-to-phase and phase-to-ground insulators but so are the design parameters such as ESDD, specific leakage distance, effect of average diameter etc. However, considering the consequence of a phase-to-phase flashover on the operation of a transmission line, an additional safety margin may need to be included. This is especially so in the case of polymeric phase spacers because of uncertainties such as ageing deterioration, unknown performance under various conditions etc. In these cases, longer leakage distances are normally adopted than would be in the case for the corresponding porcelain insulators.

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8. PALLIATIVES AND OTHER MITIGATION MEASURES 8.1 Introduction In the event that the performance of the insulators selected for a specific application does not meet the design criteria, remedies may be required to improve theis performance to an acceptable level. Although not usually possible, the most obvious remedy is to change the insulators either by adding additional units or by changing the type. For example, insulators with higher specific creepage distance may be chosen to replace the original design within the same physical spacing. Insulators with semiconducting glaze may form a reasonable alternative if replacement is allowed. Such insulators have had considerable application in substations for bus support insulators, but recently new designs of suspension insulators have also become available. More than likely, some type of maintenance will be needed if pollution flashovers become unacceptable and the replacement of insulators is not possible. Maintenance procedures can be classified into “periodic” and “semi-permanent”. The most common type of periodic maintenance consists of insulator washing. Care must be taken to use appropriate procedures, including direction of washing and low conductivity water, to prevent flashovers during this maintenance procedure. The most difficult question to address is: "What is the necessary frequency of washing?" That is, some type of pollution monitoring will be required. A second type of periodic maintenance is greasing. Although the petroleum version was used in the first introduction of greases - and continues to be chosen in some cases, silicone grease has better characteristics for the higher ambient temperatures. Greasing must be repeated, with appropriate cleaning, and the intervals are determined by the service environment. Intervals from one to five years have been found to be acceptable. If re-greasing is not needed for five years, the maintenance procedure could be considered as “semi-permanent”. Obviously, this is a qualitative judgement and will vary with utility perspectives. Finally, the use of insulator coatings other than grease may be a semi-permanent or permanent remedy. Such coatings consist, for example, of room temperature vulcanised silicone rubber and have had success in many substation applications. The options for correcting the performance of polymeric insulators are more restricted than for those made of glass or ceramic. Obviously, if pollution flashovers become unacceptably frequent, replacement should be considered. Maintenance procedures must take into account the design of the insulator and the recommendations of the manufacturer.

8.2 Maintenance procedures 8.2.1 Live-insulator washing of ceramic insulators 8.2.1.1 Introduction The growing attention to system reliability implies the necessity of adopting cost-effective measures to reduce outages of service. Among the various options, live-insulator washing - sometimes referred to as “hot-line washing”- is often employed. Herein are reviewed the methods and techniques presently used in live-insulator washing, with special reference to the related insulation aspects. In particular, after a short description of the main washing techniques and equipment, electrical aspects related to washing safety and performance are considered - thereby deriving indications useful for the standardisation of this practise.

8.2.1.2 Cleaning procedures 8.2.1.2.1 Methods used The main solutions available for the live-line cleaning of insulators are: •

Use of brushes.

•

Projection of solid vegetable particles.

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• Application of water jets. Cleaning by water projection is nowadays the most widespread solution adopted and the analysis in the following will concentrate on this solution; it is referred to as live-insulator washing. Four methods of live-insulator washing are most often used 328. They differ mainly in the type of nozzle arrangement adopted, and namely are: − Portable Hand-Held Jet Nozzles. − Helicopter Mounted Nozzles. − Remote-controlled Jet Nozzles, often automated by using robots. − Fixed-Spray Nozzles. Portable Hand-Held Jet Nozzles are operated by qualified workers on the ground or at ground potential at relatively large distances from the insulator, as required by safety conditions 328 329 330 331. The method is the one most adopted to date. Fixed Spray Nozzles can be used for special applications and are installed at ground potential in fixed locations at relatively large distances from the insulators, as in the previous method 328 332. This technique is, however, not economic for widespread application and requires an excessive amount of water. Helicopter-Mounted Nozzles are particularly useful when access to insulators is difficult, e.g. in rugged or remote terrain or when high mobility is required for rapid washing operations over long distances. The system is controlled by a wash-operator or by the pilot. With this self-contained, isolated and ungrounded system, the nozzle can be safely positioned closer to the insulators than is the situation for the hand-held jet nozzle method. Remote-Controlled Jet Nozzles. This method, often automated, has been recently proposed 333 334. The equipment generally consists of a nozzle fixed to an extendible truck-mounted boom or of nozzles carried by robots that are self-moving systems after being placed on the insulator to be washed. Today, many reasons justify the introduction of automated live maintenance; such as, the technological advancement in this field, the increasing requirement for a better quality of work and higher safety. Robotic-devices can allow mobile washing nozzles to be brought relatively close to the surface of the insulator; thereby achieving uniform washing with a small amount of water.

8.2.1.2.2 Water pressure In relation to the water pressure 328, the methods for hot-line washing can be subdivided into: • High-pressure water. A high-pressure system is mainly used in connection with hand-held, remote controlled and helicopter-mounted nozzles. High-pressure washing utilises a narrow stream of water, with a typical pressure ranging from about 3000 kPa to 7000 kPa at the nozzle. • Medium-pressure water. Medium-pressure systems are mainly used in the portable hand-held and remote-controlled jetnozzle methods. The pressure range is from 2000 kPa to 3000 kPa. • Low-pressure water. A low-pressure system is mainly used for fixed-spray nozzle methods. The pressures are in the range from 300 kPa to 2000 kPa at the nozzle.

8.2.1.2.3 Water resistivity Water having a resistivity greater than 1500 Ωcm (e.g. from hydrants) is widely used. Demineralised water of 50000 Ωcm, or even greater, resistivity is also used. It is obtainable from steam power plants or from mobile demineralised equipment.

8.2.1.3 Requirements for live-washing operation 8.2.1.3.1 Safety requirements When using the Portable Hand-Held Jet Nozzle, where the water jet is directly controlled by the operator, a high degree of safety must be secured by having a relatively large distance between the operator and the insulator; as dictated by the specific standards 328 and by the general safety requirements related to live maintenance 329 330 331. In particular, the following requirements need to be met: • The current that flows in the water stream (‘leakage current’) must be less than a certain value (e.g. 2 mA 328) when an operator at earth potential uses the equipment.

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• The water stream should withstand the electrical stress under the a.c. system voltage and the corresponding overvoltages; as per the general requirements for live-line maintenance 329 330 331. The requirements to satisfy these two conditions are analysed in the following section, by making reference to the most critical condition of the water stream impinging on the energised part. The second requirement discussed also applies to the Fixed-Spray Nozzles method. In the case of Helicopter-Mounted Nozzles and of the Remote-Controlled Jet Nozzles methods, no harm to the personnel must occur following capacitive charging of, or arcing along, the water stream. The other aspects that should be considered in this case are related to the dielectric strength of the overall configuration with the helicopter, or tool, at “floating” potential. Also, when they are possibly at line potential, discharges from the line-electrodes to the object at floating potential may occur. These aspects are similar to those analysed in the literature 329 330 331 and so will not be considered further herein.

8.2.1.3.2 Performance requirements From the performance point of view, the following requirements must be met: • The insulator should withstand the applied stress under service voltage and overvoltages. This aspect may be of concern from the safety point of view, especially when an operator is relatively close to the insulator during the washing operation. • The procedure should be highly effective with respect to washing of the insulator.

Figure 8-1: Leakage current I on the water stream in relation to the voltage and the length of the water stream 330.

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Figure 8-2: Leakage current I on the water stream in relation to various parameters 330. a) Influence of water resistivity. b) Influence of water pressure. c) Iinfluence of nozzle orifice diameter.

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8.2.1.3.3 Influencing parameters Safety and performance have been investigated taking into account the influencing parameters, such as voltage applied, nozzle-conductor distance, water resistivity, water pressure and diameter and shape of the nozzle orifice 328 330 335 336 213 337 338 339 340 341 .

8.2.1.4 Electrical requirements from the safety point of view 8.2.1.4.1 Leakage current in the wash water stream The dependence of leakage current, I, along the water stream on the stream-length is given, as an example, in Figure 8-1 - for different phase-to-ground voltages for a pressure at the nozzle of 3000 kPa, a nozzle diameter of 6.4 mm and a water resistivity of 2.5 Ω.cm 330. For a given applied voltage, I decreases when the stream-length is increased. For a fixed streamlength, the current increases more than linearly when the applied voltage is increased. The influence of water resistivity, water pressure and diameter of the nozzle orifice, are shown in Figure 8-2 a, b and c respectively - which refer to a stream-length of 4 m and to an applied voltage U of 245 kV 330. The leakage current decreases when the resistivity is increased. This dependence is, however, rather limited. I reduces by about 40 % for a variation of the resistivity from 2.5 to 50 kΩ.cm. The leakage current increases greatly when the water pressure is increased. It also rises appreciably when the diameter of the nozzle orifice is increased beyond a certain value. The above trends conform to the other ones reported in the literature and particularly to those derived from the experimental data 328 336 213.

8.2.1.4.2 Flashover voltage along the water stream For the power frequency case, Figure 8-3 shows the flashover voltage as a function of the clearance between the nozzle and the energised part - for different water-stream parameters 328 330 213.

Figure 8-3: 50% flashover voltage under a.c. energisation as a function of the stream-length for different water-stream parameters 328 330 213. As far as impulse voltages are concerned, the dependence of the 50% flashover voltage on the polarity and shape of the impulse is given in Figure 8-4 330. It shows the flashover voltage in relation to the time-to-crest of the applied voltage for a water-stream length of 4m. In these tests, negative polarity was the more critical. For switching impulse (SI) waveforms, a

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front time of about 1200 µs gave the lowest level of flashover voltage. This value was about 25% smaller than the corresponding one obtained with a standard SI of positive polarity - which is usually considered the more onerous in other experiments 336 213.

Figure 8-4: 50% flashover voltage along the water stream under impulse voltages in relation to the time-to-crest of the applied impulse 330. The 50% flashover voltage under switching impulse and standard lightning impulse wave (LI) is compared to the a.c. energised one in Figure 8-5 330. In this example, all of the stresses are given in peak value to facilitate the comparison. From comparing the results with the corresponding ones for pure air gaps331, it appears that the reduction in the flashover voltage due to the water jet is marked with a.c. and SI, while it is minor with LI. Furthermore, the flashover value under SI is close to that of the peak value under a.c. voltage.

Figure 8-5: 50% flashover voltage along the water stream: comparison of the dielectric strength under different stresses330.

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Figure 8-6: Average flashover gradient along the water stream in relation to various parameters 328 330 213. a) Influence of water resistivity. b) Influence of water pressure. c) Influence of nozzle orifice diameter.

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The flashover voltage of the water jet is almost a linear function of the stream length. The dependence of the average flashover gradient along the water stream on water resistivity, water pressure and nozzle orifice diameter is shown in Figure 8-6 a), b) and c) respectively 328 330 213. The flashover gradient increases when the water resistivity is increased. It decreases when the diameter of the nozzle is increased and has a U-curve relationship to pressure; thereby indicating a critical pressure that causes a minimum in the flashover strength - which depends on nozzle characteristics.

8.2.1.4.3 Minimum working distances A case study was considered by Perin et al 330 to obtain indications about the relative severity of the criteria based on leakage current 328 and on dielectric withstand. In this case study, the conditions considered were: a pressure at the nozzle of 3000 kPa, an orifice diameter of 6.4 mm and water resistivity of 2.5 kΩ.cm. The comparison is shown in Figure 8-7, where the safe distances satisfying the limiting current criterion of 2 mA are given in relation to the system voltage U by taking into consideration the continuous operating voltage and the temporary overvoltages of 1.3 and 1.5 p.u. These distances are compared to the distances chosen so as to limit the risk of flashover under switching overvoltages, which are the most critical stresses among the conditions examined from the flashover point of view. The evaluation was made with reference to the Statistical Overvoltage U2 - which is the overvoltage having a 2% probability of being exceeded - when the p.u. values are 2, 2.5 and 3, with reference to a defined risk of flashover 330. This comparison indicates that, in some cases, the SI requirement can be the more critical.

Figure 8-7: Minimum washing distance in relation to the system voltage; portable hand-held jet nozzle; comparison with distances recommended according to common practice 328 330. It has to be stressed that the data in Figure 8-7 refer to a particular set of parameters in terms of resistivity, water pressure and nozzle diameter. Larger distances need to be employed when the resistivity is reduced. As an example, with reference to a 420 kV system, a decrease of the resistivity from 2.5 to 1.3 kΩ.cm (which corresponds to the minimum value considered in the ANSI standard 328) would lead to an increase of 10% to 15% in the minimum required distance. The influences of the nozzle orifice diameter and water pressure also need to be considered. The distances shown in Figure 8-7 are the values derived from solely the electrical requirement. The minimum approach distances under SI is evaluated, in a way similar to that employed in the IEEE standard 329 and by Perin et al 330. This is achieved by adding the so-called “ergonomic distance” - i.e. a sort of safety feature - to the above values, to take into account the uncertainties in the operation. A typical value for this ergonomic distance is 0.5 m. The distances evaluated are generally lower than those adopted in common practice triangle) - thereby supporting the safety procedures adopted up to now.

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328

, as shown in Figure 8-7 (black

8.2.1.5 Aspects related to washing performance 8.2.1.5.1 Withstand voltage of insulator under washing The dependence of U50 on the water resistivity is shown in Figure 8-8 339. The data indicate that the flashover voltage increases when the resistivity of the water increases. The influence is greater for low levels of contamination on the insulators. In general, provided water of sufficiently high resistivity is used, the flashover voltage under washing is higher than that under standard pollution tests of the same pollution severity.

Figure 8-8: Flashover voltage in relation to water resistivity 339. The above conclusions apply when washing is done correctly. When washing is too fast, or when the wash-cycle is not started from the bottom of the insulator, flashover at lower voltages may occur.

Figure 8-9: Flashover voltage along the insulator string in relation to water pressure for various nozzle diameters 330. As far as SI flashover voltage is concerned, rather low withstand values are obtained during washing - as is shown in Figure 89 330. This information refers to standard switching impulses of negative polarity, giving - in this case - results close to the

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critical one (i.e. the minimum on the U-curve). However, the performance under SI is not very critical from the risk viewpoint; because of the low probability of having a high overvoltage during a washing operation. Thus, the corresponding risk of flashover can essentially be neglected. The dielectric performance during washing is also influenced by water pressure and nozzle-orifice diameter, as may be seen from Figure 8-9. In general, the flashover voltage increases when the pressure is increased and the orifice diameter is decreased. Finally, it is worthy of note that the flashover voltages measured in tests simulating washing from a helicopter, were slightly higher than those obtained by using the portable hand-held jet nozzle - for these parameters considered by Perin et al 330. This finding can be easily explained if one considers that the orifice diameter, and thus the quantity of water employed, was much lower in the former case.

8.2.1.6 Washing effectiveness Indications concerning the efficiency of two of the most common washing methods can be obtained from the tests results reported by Perin et al 330. These results are summarised in Figure 8-10.

Figure 8-10: Residual salt deposit density in relation to the washing time; portable hand-held jet nozzle and helicopter nozzle 330. These tests were carried out on a vertical insulator string for a 420 kV system, with a total length of 3 m. The following washing parameters applied: • Portable hand-held jet nozzle; orifice diameter of 6.4 mm, pressure of 3000 kPa and a minimum distance to the conductor of 5 m. • Helicopter simulation; nozzle with an orifice diameter of 1.7 mm, pressures of 4000 to 8000 kPa and minimum distance to the conductor of 1 m. The tests were made by contaminating the insulator string with an almost standard suspension and a non-standard one. The almost standard suspension differed from the standard one by the quantity of kaolin used (100 g per litre). In the nonstandard suspension, glue was added (10 g of metylan per litre) to increase the adhesion and the thickness of the layer, with the aim of simulating conditions typical of industrial areas. The test results provided in Figure 8-10 show that the washing efficiency improves when the washing time is increased. Furthermore, the value of the effective washing time depends on the type of contamination. The time needed for an efficient

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wash using portable hand-held jet nozzles was shorter than that with helicopter-mounted jet nozzles, for a similar water pressure. Better agreement could be obtained by increasing the water pressure in the helicopter case.

8.2.1.7 Conclusions 8.2.1.7.1 Safety aspects • The safe working distances for live-line insulator washing made by an operator at earth potential, with a portable handheld jet nozzle, must be determined with reference to a limiting value of the leakage current along the water jet. It should also be verified from the point of view of the withstand voltage under SI, as is the situation for any other live-line working operation. To this end, the most critical SI is that of negative polarity with a long front time. • The same requirements may be used conservatively when fixed spray nozzles at ground potential are used. • Safe working from a helicopter, implying the use of isolated metallic tools, must be determined by considering the dielectric strength of the arrangement with the object at floating potential (or possibly momentarily at live potential, if a discharge from the live electrode to the object at floating potential occurs). For this aspect, reference to the general requirements for live-line maintenance can be usefully made. • When automated procedures are used, without the presence of people in the vicinity, electrical safety requirements are of concern only to the equipment.

8.2.1.7.2 Performance aspects • The washing operation does not reduce the system’s reliability, since no flashover is to be expected, provided the washing operation is performed correctly. The flashover voltage in the helicopter-simulation test was found to be higher than that applying in the hand-held jet nozzle case, for the water-parameters considered. • To obtain efficient washing, very different washing times may be required that depend on the type of contaminant. The time needed for an efficient wash using portable hand-held jet nozzles was shorter than that found with helicoptermounted jet nozzles, for the same pressure. Better agreement between these two cases can be obtained by increasing the washing pressure at the helicopter nozzles. • Washing is influenced by many parameters. High resistivity water is beneficial with regards to safety and reliability, since - by increasing this resistivity - both the dielectric withstand of the water jet and that of the washed insulator are significantly increased. Washing is obviously very much affected by water pressure and nozzle diameter.

8.2.2 Live-insulator washing of polymeric insulators Polymeric insulators, generally, have high pollution withstand voltage characteristics when compared with their ceramic counterparts. This is due to their high surface hydrophobicity, especially when they are new. Nonetheless, the polymeric insulators in the field occasionally flash over due to heavy pollution and wetting 342. It has been reported that the accumulated pollutant on the polymeric insulators could be more than that on their ceramic counterparts - see Figure 2-26 86 - for the same atmospheric conditions. Thus, live-line washing using pressurised water is sometimes considered necessary. Live-line washing of polymeric insulators should only be done after considering the following points: 1.

2.

Wash withstand voltage. An effective insulation length shorter than that for ceramic insulators is sometimes used because of the higher pollution withstand voltage. Since the withstand voltage under washing is mainly affected by water cascading down the sheds, hydrophobicity is then not the dominant factor. Therefore, the effective insulation length is the same as that of the corresponding ceramic one. In the case of insulators having a large diameter, such as bushing shells, the amount of cascading water is larger than that of line insulators. In such a case, the fitting of some special sheds - such as booster sheds - is recommended to break up the cascading stream of water. Mechanical damage to material. It is reported that the shed material can suffer damage, such as tearing, or puncture in the case of high water pressure 343 344. Therefore, the water pressure must be carefully specified; mainly taking the following aspects into consideration, • Shed material (e.g. silicone rubber, EPDM etc).

• Manufacturing method (e.g. moulded, bonded, un-bonded, etc). However, it is not wise to clean some types of polymeric insulators by using pressurised water, and so recommendations from the manufacturer are to be followed. It is important to note that washing by pressurised water does not always achieve the

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best cleaning. This is especially so when the pollution layer adheres strongly to the insulator surface; e.g. cement or gypsum, and when the water stream can not reach the entire insulator surface 345.

8.3 Use of greases and RTV coatings 8.3.1 Introduction The performance of glazed porcelain insulators can be considerably improved by the application of hydrocarbon (petroleum jelly) or silicone grease or a RTV silicone rubber coating to its surface346 347. Silicone greases and RTV coatings of different types are widely used today. Both the greases and silicone rubber coatings reduce the surface energy of the insulator and inhibit the formation of a water film. In addition, the greases encapsulate contaminant particles in a thin grease film, thereby isolating them from each other and ensuring that the surface remains hydrophobic. In the case of the silicone rubber coating, low-molecular weight silicone components within the body of the material diffuse to the surface and impart hydrophobic properties to the contaminant layer 105. The inclusion of arc resistant components, such as alumina trihydrate, in the silicone grease and RTV coatings stabilise their performance under heavy wetting and contribute to their longer useful life. The use of these measures with porcelain insulators is well proven. Their use with polymeric insulators is not generally recommended and should be discussed in detail with the insulator manufacturer if it is being contemplated. Based on some experience in North America, a review has been prepared under the auspices of the IEEE 347 348. A further document contains practical information on the preparation of insulators prior to greasing or coating and the techniques for grease or coating application 328.

8.3.2 Hydrocarbon and silicone greases Hydrocarbon (petroleum jelly) and silicone greases have been used as protective coatings on insulators for about 40 years and experience has shown that, as long as they maintain their hydrophobicity, they provide substantially improved protection against flashover when compared with the corresponding bare insulators. Comparisons of the hydrocarbon and silicone greases have been made by both Lambeth et al 346 and an IEEE committee 347. Some of the practical characteristics are set out in Table 8-1 347. Table 8-1 Comparison of Hydrocarbon (petroleum Jelly) and silicone greases 347. PARAMETER

HYDROCARBON (PETROLEUM JELLY)

SILICONE

Basic constituents

Hydrocarbon oils, petroleum and synthetic waxes

Dimethyl or phenyl-methyl siloxane fluid, coupling agents, fillers and solvents

Useful temperature

0 to 60°C

-50 to 200°C

Melting point

60 to 90°C

Does not occur inside useful temperature range

Recommended spraying temperature

90 to 115°C

Ambient (-30 to 30°C)

Encapsulation rate, ambient temp.

Slow

Rapid

Ease of Application

Difficult, esp. in cold weather

Good

Ease of Removal

Labour intensive

Labour intensive

Arc resistance (ASTM D 495)

Not available

80 to 150s, depending on formulation, fluid & filler

Material cost

Low

Moderate

Application cost

Moderate

Moderate

Cleaning cost

High

High

Water erosion, excessive exposure to corona, UV light and significant contaminant encapsulation reduce water repellency. Once hydrophobicity is lost, leakage currents will commence flowing and, in time, dry band discharges will also commence. These discharges cause the grease to decompose and the filler in the grease adds to the contaminant. Channels begin to develop resulting in local hot spots and further degradation of the grease and possible damage to the insulator. Once channels have begun to form, flashover of the insulator is imminent 347. Regreasing should be implemented as soon as dry band arcing is observed.

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The frequency of regreasing depends on the type of grease and the severity of the degrading influences mentioned above. Service experience with both a.c. and d.c. systems, has shown that the useful life of a grease coating can vary from less than one year to 10 years. Greases are normally applied by hand, brush or spray. Although application on de-energised systems is simpler, application on live systems is also possible. The application of fresh grease over contaminated grease is not recommended. There are several tests that can be made to assess the suitability of grease as an insulator coating. The most significant are an arc endurance test under wetting and the water repellency tests in a Salt-Fog chamber or using a tracking wheel. Unfortunately, the laboratory tests suffer from a lack of correlation with field experience. Field-testing has proved to be the only reliable method for evaluating the performance of different greases 347. The pollution flashover performance of a 132kV epoxy-resin crossarm, which has been used in the UK to achieve an inconspicuous overhead line in areas of outstanding natural beauty, has been assessed using both the artificial salt-fog test and by exposure to natural marine pollution at the Brighton Insulator Testing Station249. The findings from the salt-fog test are shown in Table 10-39. Although there was a large reduction - up to 50% of the new value - in the flashover voltage of the service-aged insulator, the performance of such insulators was substantially restored by the application of a hydrophobic coating; e.g. silicone oil, restored the withstand voltage to 70% of the original value. An even larger improvement was obtained by using hydrocarbon grease but, because it tends to promote tracking on the insulator surface, it is not recommended for practical use. The follow-up tests at Brighton showed the benefit of using a silicone oil of as high a viscosity as possible. In a practical application, a flashover problem was alleviated to a large extent by coating the surface with a viscous silicone oil - applied yearly by linesmen with paintbrushes. In this case, the severity of the marine pollution estimated ESDD of 0.6 mg/cm2 - is even greater than that at Brighton and where flashovers had occurred on such insulators having a specific creepage of 25 mm/kV system.

8.3.3 RTV rubber coatings The excellent experience with silicone rubber as an outdoor insulating material has prompted the development of these coatings. Service experience with RTV coatings has, in general, been very good. They were first applied in the early 1970’s and some utilities have had over 30 years experience with their use in a.c. systems and over 13 years with d.c. systems. All known commercially available coatings consist of polydimethylsiloxane (PDMS) polymer, alumina trihydrate or alternate filler for increased tracing and erosion resistance, a catalyst and a cross-linking agent. Several systems also contain a condensation catalyst, an adhesion promoter, a reinforcing filler or a pigment. These systems are dispersed in either a naphtha or trichlorethylene solvent. The solvent acts as a carrier to transfer the RTV rubber to the insulator surface. It should be noted that the solvent is slightly poisonous. As the solvent evaporates, moisture in the coating triggers a vulcanising action and the formation of a solid rubber layer. The speed of vulcanisation depends on the type of solvent, the cure-system chemistry and the relative humidity 349. Insulators need to be thoroughly cleaned prior to the application of a RTV coating. In some cases, the use of a high-pressure water jet is sufficient. If cement like material is present, a dry abrasive cleaner - such as crushed corncobs or walnut shells mixed with limestone - must be used. If the insulators have been previously greased, hand cleaning is necessary to remove the bulk of the grease and a solvent must be used to remove any residual film347. The silicone coating is applied by brush or by spray. Live application is possible provided a combustible carrier, such as naphtha, is not present. When a RTV coating looses some of its water repellency it may be washed and the hydrophobicity may be restored. To recoat, cleaning using a dry abrasive is recommended. A new coat can be applied over an existing coat after some cleaning347 - provided the existing coat is well adhered to the ceramic insulator. Similarly to that described in Section 8.3.2, surface discharges and corona will cause the coating to degrade 347 350 351 and may then lead to flashover. The frequency of re-coating, or washing, depends on the type of RTV and the severity of the degradation. Service experience with both a.c. and d.c. systems has shown that the useful life of a RTV coating can vary from less than one year up to ten years 347 348 352 353 . Experience has also shown that if a coating is applied in situations where the leakage distance is reduced and/or corona occurs, the coating looses its hydrophobic properties and flashover follows 347. There is no established laboratory test that can predict the performance of a coating in service. Important initiatives are underway 354, but to date, field-testing is the most reliable assessment procedure 347.

8.3.4 Summary As a summary, a comparison of silicone greases and RTV coatings is given in Table 8-2.

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Table 8-2: Comparison of silicone greases and RTV Coatings. SILICONE GREASES Effectiveness Market price Lifetime

RTV COATINGS excellent in lifetime

Low

High

Environment and quality dependent, a few months to several years

Unsuitable environmental conditions

very high concentration of dust in air resulting in fast saturation

very high concentration of dust in air resulting in the loss of hydrophobicity in a short time, Continuous raining or humid weather

Preparation before application

Low demands

High demands

Application equipment and technique

Simple if applied by hand Sophisticated if applied by spray

Handling character

Dirty and messy, if applied by hand Solvent is slightly poisonous but needed if applied by spray

Monitoring

needed

maintenance before replacement

no

washing and cleaning

removal

difficult if not done in time, simplified if done timely and with right tools

very difficult if adhesion of old layer is still good

disposal Reapplication

varies form country to country direct after a rough cleaning

directly, after cleaning, over the old layer if it is still in good adhesion.

8.4 Booster sheds Booster sheds were invented in the UK for the prevention of the flashover of polluted insulators caused by heavy wetting 262. They are made from a radiation-crosslinked copolymer of silicone rubber and polyethylene; their form and installed position on the insulator are shown in Figure 8-11. Such sheds have been successfully and widely applied on a.c. systems since 1975.

Figure 8-11: Form and installed position of booster sheds 355. A variant of the Salt-Fog test was developed to quantify their efficacy, which was measured as a withstood pre-applied salinity (WPS) if flashover did not occur in three out of four identical tests. Some results for 400 kV substation insulators when fitted with booster sheds are presented in Table 8-3 for various types of wetting that simulate conditions which are known to have caused flashover in service355. These tests show that, with 7 booster sheds on a multiple cone post insulator and 10 on a barrel type insulator, an improvement of never less than a factor 2 was obtained in the tolerable pollution level. In one case, this factor was as much as 128.

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Table 8-3: Improvement in performance of a 400 kV substation insulator from fitting booster sheds 355. Test Procedure

Insulator

Angle of tilt, Degrees

20 second wash

Multiple cone post Plain shed cylindrical Plain shed taper Plain shed taper Antifog shed taper Multiple cone post Plain shed cylindrical Plain shed taper Plain shed taper Antifog shed taper Multiple cone post Plain shed cylindrical Multiple cone post Plain shed cylindrical Plain shed taper Plain shed taper Plain shed cylindrical Plain shed taper Plain shed taper Antifog shed taper

0 0 0 10 10 0 0 0 10 10 0 0 0 0 0 10 0 0 10 10

2 second wash

Side spray Impulse wash

Rain

No. of Booster sheds 7 10 10 10 10 7 10 10 10 10 7 10 7 10 10 10 10 10 10 10

Performance, WPS, kg/m3

Factor of improvement over bare insulator.

113 40 56 80 40 40 28 40 28 40 ≥240 160 40 40 40 ≥56 ≥240 ≥240 160 40

2.8 2.8 4 4 2.8 2 4 5.6 5.6 8 ≥16 16 4 5.6 5.6 ≥4 ≥2 ≥4 128 8

Investigations for their use under d.c. voltage have shown that by installing booster sheds on a HVDC wall bushing, its dielectric strength under uneven rain or polluted conditions can be improved by up to 80 % 202. Laboratory tests have also been performed on vertically installed d.c. station post insulators with booster sheds 110. By fitting 20 booster sheds on a stacked station post insulator of 8.8 m overall length, the dielectric strength of this post insulator was increased by 30 % at a pollution level of 0,02 mg/cm2, as compared to that of the insulator without such booster sheds.

8.5 Methods for increasing insulator reliability under ice and snow conditions For reliable operation of insulation under ice or snow conditions, it is generally necessary to use insulators with a long dry arc-distance. As ice and snow flashovers are relatively infrequent, it is reasonable to restrict the use of special insulator designs to only selected parts of overhead lines. For example, fit them only on that part of a line that experiences regular icing or that runs close to cooling towers etc. On other parts of the line, more economical measures to improve their operational reliability should be considered.

8.5.1 Some measures to prevent flashovers during ice conditions Some measures to prevent flashovers during ice conditions are: 1)

Prevention of icicle bridging;

• Utilising “V” or horizontal strings. V-strings offer a substantial improvement over suspension (i.e. vertical) strings with regard to the ice-flashover strength as water does not easily drip down the string to form an ice bridge 111. This effect is even more pronounced on horizontal strings 356 357. • Booster sheds. The use of 3 booster sheds per metre of insulator can increase the flashover voltage under icing conditions by 20% for a system voltage of 110 kV and 40% for 400 kV183 358. However, booster sheds tend to restrict natural washing.

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• Special insulator shapes or different types of disc insulators in the same string. For post insulators, it is possible to use designs with alternate long and short sheds. The difference between the shed diameters must be sufficient to prevent icicle bridging. The same effect can be achieved on suspension insulator strings by building up the string with insulators of different diameters; e.g. an arrangement of alternate normal and aerodynamic discs. The use of vertical polymeric insulators may prove to be ineffective if the sheds are spaced closer together than is the case for the discs of the equivalent ceramic insulator string. In this situation, the ice-flashover voltage may actually be lower than that for a ceramic string of the same length. An improvement may be achieved by using the polymer insulator in “V” or horizontal configuration or by having an alternate long and short shed-profile with sufficient inter-shed spacing 111 . • Semiconducting glaze insulators. Semiconducting glazed porcelain insulators usually provide a resistive current of approximately 1 mA. This steady current improves the voltage grading and warms the insulator surface slightly. Semiconducting glazed post insulators have shown the highest withstand voltage under icing conditions among the various insulators tested - including conventional ceramic and polymeric insulators 180. However, there is no common agreement on the effectiveness of this method. • Shielding insulators from water melted from ice.

2)

By having shields places between the tower and insulator strings, the water released from the ice during melting will be drained away from the insulators. Increasing the dry arc-distance of insulators: Please refer to Section 7.3

3)

Lowering the operating voltage: If provided for in the design of the system, the operating voltage may be lowered sufficiently to reduce the stress on the insulator below the flashover value during the critical conditions - i.e. ice melting358.

4)

Reducing the number of parallel insulators: In areas with heavy ice accretion (for example close to cooling towers), the number of parallel vertical insulators (insulator posts, equipment etc) should be limited to reduce the probability of flashover 358.

5)

Installing stress rings: The performance of long insulator strings under ice conditions can be improved by using stress rings that even out the grading of the electric field along the insulator, thereby preventing a high gradient at the live end 359.

8.5.2 Some measures to prevent flashovers during snow conditions These measures are aimed at preventing the build-up of snow on horizontal or tension insulators. 1)

Vertical arrangement of twin or triple tension insulator strings: A vertical arrangement of strings in lieu of the normal near-horizontal strings presents a smaller collection area for snow accumulation, thereby preventing the build-up of a large amount.

2)

Insertion of a extension rod: An extension rod of about 1 m length can be inserted between the tower and the insulator string to prevent enhanced snow accumulation due to snow bridging from the tower cross-arm to the insulator.

3)

Semiconducting glaze insulators: Please refer to the discussion in Section 8.5.1 for more information.

4)

Increase the spacing between adjacent insulator strings: A bigger spacing between parallel tension strings prevents snow from bridging across one insulator string to another.

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9. THERMAL EFFECTS OF CONTAMINATION ON METAL OXIDE ARRESTERS (MOA) 9.1 Introduction The effect of contamination on metal oxide surge arresters with porcelain housings has already been the subject of numerous investigations, mostly made during the last ten years 360 361 362 363 364 365 366 367 368 369 370 371 372. Work on MOA with polymeric housings is still in progress and will not be referred to herein. It is generally accepted that contamination of the arrester housing can have three effects: 1. 2.

Pollution flashover of the housing when the critical severity is reached. Overheating of the varistor blocks if significant energy is dissipated internally, due to either capacitive coupling to the housing or redistribution of current at intermediate flanges of multi-unit arresters. 3. Ageing, or even failure, due to internal partial discharges triggered by transient radial fields between the blocks and the arrester housing - particularly during dry band formation and sparkover. Both the ANSI/IEEE Standard C62.11373 and the Amendment 1 to IEC standard 60099-4374 specifies a pollution test for metal oxide arresters. The present review deals mostly with the aspect of the temperature rise in metal oxide arrester blocks due to external pollution.

9.2 Operational Experience and Field Tests General use of MOAs started on a large scale in the early eighties. Although the experience is generally satisfactory, several arrester failures due to pollution were reported in Europe for voltage levels from 63 kV to 420 kV 363. It was noted that arresters could fail at extremely low levels of pollution and without excessive energy stress from the network 363. These failures were mostly attributed to internal discharges resulting from contamination on the arrester housing. Such internal discharges manifest themselves by: • Excessive loss of oxygen inside the arrester. • Substantial degradation of varistors, as evidenced by decreasing reference voltage and increased resistive current and power loss. • Salt formation on the varistor surface. The problem appeared to be confined to the first generation of varistor blocks that had inadequate protective coating. The provision of an adequate coating, together with the reduction of radial stress and the filling with a passive medium, were the recommended measures for solving the problem. Nevertheless, several natural-pollution test programmes were launched and supplemented by extensive laboratory tests, which went beyond the investigation of the problem of internal discharges. At Brighton Insulator Testing Station, CERL conducted natural pollution tests - for more than five years - on a 1-unit 132 kV arrester, several 3-unit 275 kV arresters and three 3-unit 400 kV arresters. In these tests, as well as in other tests at Martigues conducted by EdF - referred to below - both external current and internal current at the base unit were measured. Measurement of the mean temperature of the varistor blocks of the 3-unit 275 kV arrester at Brighton yielded 40°C, 107°C and 124°C in the top, middle and bottom units respectively. In another arrester, these temperature were 57°C, 132°C, and 129°C and, in a third arrester, 40°C, 40°C and 143°C. Within the latter arrester, the varistors were punctured near their centre and had been permanently damaged in the base unit 363. These results showed that the location of maximum temperature rise was random and could occur in any unit : bottom, medium or top. The field tests at Martigues367 included two 2-unit 245 kV arresters, one 2-unit and one 3-unit 420 kV arrester as well as two 2-unit 300 kV arresters. The specific leakage path varied between 18 and 30 mm/kV system voltage and the housing diameter varied between 267 and 386 mm. Here again, the internal and external currents were measured at the base of the bottom unit. Temperature measurements were carried out with fibre optic sensors and thermostrips. During a 10-month period at Martigues, the monthly-recorded maximum temperature rise - although significant - was much more modest than those reported above from Brighton. The following interesting conclusions could be reached: • For most pollution events, a significant temperature rise occurs in 6 hours or less.

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• The external charge/h rose to 11 C/h for a 2-h period and 9 C/h for 6-h period, both were for the 2-unit 420 kV arrester. • The temperature rise in the bottom unit correlates rather well with the internal charge flow, per 5-min period, through that unit. • To a first approximation, the external charge was found to be proportional to the arrester diameter. • The external charge, scaled to the housing diameter, appears to be representative of the discharge activity on the arrester. • The magnitude of the internal current cannot be linked to a block-temperature rise. Similar field tests were reported from a 300 kV switchyard at Lista, Norway. No temperature rise measurement was undertaken, since the arresters were connected to the network. It was stated that no correlation was found between internal and external charge activity. To avoid confusion, however, it must be underlined that this statement applies only to charges of just one arrester unit.

9.3 Artificial Pollution Tests of Lightning Arresters 9.3.1 Test Techniques Several techniques have already been used in the laboratory to simulate conditions leading to varistor block overheating. These techniques include: • Salt-Fog • Solid-Layer • Slurry cycles • Partial wetting Salt-Fog tests on surge arresters have been carried out in accordance with IEC Publication 507 22, sometimes with prolonged duration - e.g. 2 h instead of 1 h. The Solid-Layer test was also carried out with layer preparation and application made according to IEC Publication 507 22, although the steam-input rate was sometimes different from that of the standard - e.g. 0.8 1/h/m3 In the slurry test - which is not standardised - the contaminant was a slurry of water, betonite, non-ionic detergent and sodium chloride prepared according to ANSI/IEEE C62.11 1987 362. The volume resistivity was between 400 and 500 Ω cm. The contaminant was applied to the complete arrester. Several test cycles were performed, each consisting of slurry application, a dripping period (3 min.) followed by an energisation period. The latter being, usually, 15 minutes although it can apparently be shorter without significant effect on the test results 372. In the partial-wetting test conducted according to ANSI/IEEE C62.11-1987 373, the slurry was prepared as per that mentioned above but was applied only to the lower half of the surge arrester. The maximum “voltage-off” time for the contaminant application was 10 minutes, with a “dripping off” time of less than 3 minutes. The energisation time was 15 minutes. The test comprised two cycles, followed by a 30-minute interval at MCOV to demonstrate thermal stability. The arrester was deemed to have passed the test if it demonstrated thermal stability, no complete or unit flashovers occurred and no visual physical damage of internal parts could be found. Some variants of the above tests have also been used. For example 365, arresters were contaminated according to the SolidLayer method but an artificial dry zone was created, having a length equal to approximately 10% of the leakage path. Wetting under voltage took place in air with relative humidity > 85%. The control of the test parameters and the calibration needed to fit field conditions will be dealt with, following the section on laboratory test results.

9.3.2 Laboratory Test Results In 1984, Lenk reported on pollution tests carried out on 2-unit and 3-unit arresters with MCOV of 140 and 210 kV 360. The test techniques comprised salt-fog, 5-h slurry and partial wetting. The 1-h Salt-Fog test was carried out at FGH according to IEC Publication 507. The slurry test comprised 20 cycles, each with a 15-minute voltage application. The partial-wetting test consisted of applying a slurry made according to ANSI C62.1-1981, with a resistivity of 425-440 Ωm. It was applied to the bottom unit housing. Usually, there were 3 cycles of tests for each arrester. The voltage was applied for 15 minutes.

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Only a moderate temperature rise was recorded for the Salt-Fog test (< 30°C) and the slurry test (< 35°C) 360. The partial wetting test was found to be the most severe, yielding a temperature rise of up to 79°C. This paper served as a basis for the standardisation of the partial-wetting method referred to in C62.11-1987 373 The results of a Salt-Fog test on the arresters described in Section 9.2 were reported by Vitet et al. 366, for salinities in the range 1.2-80 kg/m3. Typical temperature rise curves - as a function of the test duration for different salinities - are shown in Figure 9-1 366. The variation of the varistor temperature of the bottom unit as well as that of the internal current and of the energy are shown in Figure 9-2 as functions of the salt-fog duration. Figure 9-3 shows the flow of external charge as a function of the test duration 366.

Figure 9-1: Typical temperature during a Salt-Fog tests of 1.2 to 80 g/l salinity 366.

Figure 9-2: Bottom unit temperature, internal energy and internal current peaks in a Salt-Fog test 366. From the aforementioned test, the following observations can be made 366: • No correlation was found between the maximum varistor-temperature and fog salinity. • A somewhat contradictory finding is that the external charge per hour correlates well with fog salinity and, moreover, increases almost linearly with the test-duration. • Current peaks cannot be used to determine the thermal stress on the arrester blocks.

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• Breaks in the duration of the fog spray have no effect because discharge activity ceases during such breaks. Solid-Layer tests conducted by Vitet et al. 366 - with ESDD in the range 0.2∼0.7 mg/cm2 - yielded a negligible temperature rise in the bottom unit and a maximum temperature rise in the top unit of 26°C; which are much less than the corresponding values with the Salt-Fog test. Good correlation was reported between the external charge on the bottom-unit and the temperature rise of the top-unit varistor.

Figure 9-3: External charge build-up during a Salt-Fog test. 366 Figure 9-4 shows the varistor temperature variations with test-time of the slurry test 366. In this case, the test comprised 6 cycles and the maximum temperature rise occurred with equal probability on the top or bottom unit of a 2-unit arrester. It was found that the temperature rise in the slurry test was practically independent of the resistivity of the slurry or of the specific leakage path. The temperature rise in the bottom unit correlated well with its internal charge. Figure 9-5 shows the temperature variation of the top varistor and the external charge measured on the bottom unit during a partial-wetting test 366. Note, that here, the external charge corresponds also to the internal charge of the top unit and, therefore, correlates quite well with the top-varistor temperature rise.

Figure 9-4: Temperature and charge flow during a slurry test with six test cycles 366.

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A comparison was made 366 between the flow of external charge and the test-time for the above four test techniques. The slurry test, after six cycles, resulted in an external charge that was slightly larger than the corresponding charge of a 2-h SaltFog test. The charge associated with the Solid-Layer test, or that of a 2-cycle partial-wetting test, was significantly lower than that of the slurry test. Work by ENEL-CESI on pollution testing of metal oxide surge arresters has been reported in an initial paper361 and in more detail in two subsequent publications 370 371. It was concluded 361 that, from the point of view of thermal effects, the Salt-Fog test was more severe than the standard SolidLayer test. The standard Salt-Fog withstand test did not yield a significant varistor-temperature rise. On the other hand, a significant temperature rise was obtained after repeated cycles of a salt-fog at salinities much below the withstand level. With a block temperature up to 130°C, a significant change in the arrester parameter (degradation) can result, particularly manifested by increased resistive current and additional power loss.

Figure 9-5: Temperature and external charge flow during a partial wetting test366. It was also found that, contrary to the finding thermal stresses in the arrester blocks 361.

366

discussed above, drying periods under voltage can significantly accelerate

Temporary overvoltages led to a significant temperature rise (116°C instead of 38°C in one case). Finally, it was reported that a better correlation exists between temperature rise and internal current than that with external current. Garasim et al 371 have conducted pollution tests on 2-unit arresters that included measurement of internal and external currents in both top and bottom units. This permits a more directly relevant correlation to be made between the test parameters and the thermal stresses. The tests included the following techniques, as designated in the paper: a) Partial-wetting test, with 2-cycle application according to ANSI/IEEE C62.11 1987 373. b) Slurry test, with 6-cycle application. c) Solid-Layer test according to IEC Publication 507, but with only one arrester unit contaminated with ESDD-0.015 mg/cm2. d) Solid-Layer test as above, but applied to the complete arrester. e) Salt-Fog test according to IEC 507, but with a 2-h duration and salinities in the range 2.5-40.9 kg/m3. This paper leads to the following conclusions: • The test severity is determined by non-uniformity of the pollution rather than by the contamination level. • Pollution methods with forced non-uniformity have better repeatability. This is particularly so for technique (a) “partial wetting”. • Block heating is closely related (almost proportionally) to inner charge flow but only loosely correlated to external charge, except - of course - when the two are identical.

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• Inner charge in the partial-wetting technique is a function of insulator geometry and wetting conditions (quantity of water to be evaporated). • The proportionality constant between temperature rise and inner charge is generally in the range 7-10°C/Coulomb. From pollution tests conducted on surge arresters in the UK, reported by Sparrow 364, it was found that: • The rate of wetting has an important effect on the rate of external charge flow. • An increase of the applied voltage (thereby decreasing the specific leakage path) led to a significant decrease in the rate of external charge flow. • Salinity had little effect on the charge flow per hour. • ESDD measurement does not appear to be a good basis for site severity as far as arrester heating is concerned. • The aim of an artificial pollution test should be to obtain a value of external charge per hour that is in accordance with that at natural sites. Some of the above points are confirmations of previous findings 362. Verma et al. 369 reported on field experience in Germany and Salt-Fog tests on metal oxide arresters at FGH. The major concern appears to be internal partial discharges caused by external pollution - with their associated varistor degradation and, even, failure as referred to above. To alleviate that concern, German utilities require a 2000-h Salt-Fog test at phase-toground voltage with a salinity of 1 kg/m3. Salt-Fog tests were also reported in Verma’s work 369. It was concluded that, if the ratio of the test voltage Ut (phase-toground) to the arrester reference voltage Ur is less than 0.54, pollution will have no significant thermal effect on the varistors. It is noted, however, that such a low ratio may not be practical, owing to the protective-level requirements. This work also confirmed that a high temperature rise can be obtained at salinities much below the withstand level. It also showed that higher temperatures are generally encountered with multi-unit rather than with single-unit arresters and that higher temperatures occur on the top rather than on the bottom unit. Feser et al. 365 found that for both single- and multi-unit arresters, an artificial single dry band - representing approximately 10% of the leakage path, particularly in the vicinity of the flange - can lead to a significant temperature rise of the varistor blocks. A solid-layer contaminant was applied during those tests and wetting took place in air with a relative humidity > 85%. In single units, the temperature rise was attributed to capacitive coupling between the varistor column and the housing and temperatures as high as 85°C were recorded. In a 2-unit arrester, temperatures as high as 105°C were measured. In a report on Solid-Layer tests (18-26 µS) 368 of 110 kV and 220 kV ZnO arresters, a temperature rise of up to 46°C occurred. It was found that this temperature rise did not depend on the leakage path or the form factor of the arrester housing but, rather, on the specific capacitance along the resistor stack. The temperature rise proved to be a statistical variable, which can be represented by an exponential distribution. For clean and dry conditions, the calculations of overheating of the arrester elements, as a function of input power, were provided.

9.4 Standardisation of a Laboratory Test The purpose of this discussion is to emphasise the factors that could influence the selection of a standard laboratory test. It is not intended to constitute an endorsement for one technique or another. It was established in the research referred to above, that a high temperature rise of varistor blocks occurs at a pollution severity far below the withstand level. It also follows that conventional severity measurements, such as ESDD or leakage current peak-values, can not be used to relate field and laboratory conditions. A quantity that has served that purpose 366 367 372 is the amount of external charge on a reference insulator, preferably a longrod or an arrester housing, that flows during a 2-h or 6-h duration. In one investigation 372, the requirements made of a laboratory test method were perceived as follows: 1.

It should establish an external charge activity of sufficient intensity and duration - e.g. up to 6 C/h on a small-diameter housing using a current threshold of 2 mA peak. 2. An appreciable temperature rise should appear in any unit of a multi-unit arrester. 3. External charge accumulation should be essentially independent of the specific leakage path. These investigations 372 concluded that only the Salt-Fog and the slurry methods fulfil the above requirements.

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Concerning the first requirement, the effect of selecting a value of threshold current based on the charge flow per hour should be clarified. It would be even better to eliminate that quantity altogether. Instead, the real charge rate should be determined by excluding the capacitive component from the total current. As for the second point, only the slurry method fulfils that requirement; because in the Salt-Fog test, the top unit is the hottest in most cases 362 367. The third point is not always satisfied by the Salt-Fog test since, as reported by Sparrow 362, the charge flow-rate increases with the increase of the specific leakage path - particularly at 10 kg/m3 salinity. Furthermore, Lenk 360 found that - from the thermal point of view - the partial-wetting method was the most severe. However, this condition is, admittedly, infrequent. In practice, some examples are malfunction of the transformer deluge system (fire protection) and stratified fog. Bargigia et al. 371 have found that this method provides the best repeatability of all the test techniques investigated. A comparison between the major laboratory techniques is shown in Table 9-1. Also included are the controlling parameters to achieve the required charge rate, the thermal effect of the test, the representativity (i.e. simulation of field conditions), the repeatability and existing standardisation experience for each method. It should be noted that while the salt-fog technique is known to have excellent repeatability for insulator pollution tests, Vitet et al 366 have found large variations in the maximum varistor-temperature under tests with identical salinity. However, these authors provided no satisfactory explanation for such a large dispersion of the test results. The final column includes some possible modifications to make the method more versatile, if deemed necessary. As already mentioned, the effect of the drying periods in the Salt-Fog test is somewhat controversial. Furthermore, the repetition of the partial wetting test - with the wet contaminant applied to the upper half whilst keeping the lower half clean and dry - would cause a temperature rise in different units. This practise would remove one of the major objections against this test. Table 9-1: Comparison of pollution test techniques to model pollution stress for varistor block heating. TEST TECHNIQUE

CONTAMINANT

CONTROLLING

THERMAL

REPRESENT-

REPEAT-

STANDARDISATION

POSSIBLE

APPLICATION

PARAMETERS

EFFECTS

ATIVE

ABILITY

EXPERIENCE

MODIFICATIONS

Salt-Fog

Complete arrester

Substantial

Good

Good

Complete arrester

Mild

Good

Good

Slurry

Complete arrester

Substantial

Fair

Good

Partial Wetting

Lower half

-Cycle duration -Cycles per test - Slurry resistivity -Cycle duration -Cycles per test - Slurry resistivity

IEC Std 507 (Polluted insulators only) IEC Std 507 (Polluted insulators only) JEC-217

Inclusion of drying periods

Solid-Layer

-Nozzle pressure -Liquid flow rate -Test duration -Steam flow rate -Test duration

Substantial

Fair

Very Good

ANSI/IEEE C62.11-1987

Test repetition with pollution applied to the upper half

In April 1998, the IEC issued Amendment 1 to IEC standard 60099-4: "Artificial pollution test with respect to the thermal stress on porcelain-housed, multi-unit metal-oxide surge arresters"374. A brief summary of the salient features of that document is given below. A basic feature of this document is contained in a table that correlates the flow of external charge - qz per hour per metre of arrester housing diameter - to the minimum creepage distance, for the range 16-31 mm/kV - which correspond to the different pollution zones specified in IEC guide 815. For a 2h-event, qz varies in the range 0.5 to 55 C/h.m, while for a 6h-event it varies in the range 0.24 to 36 C/h.m. The implicit assumptions here are that the external charge is determined by the specific leakage path for all climatic and pollution conditions - e.g. industrial, marine, desert etc - and that the external charge flow is proportional to the arrester housing diameter. An estimate of the upper limit of the arrester block temperature rise is first made, assuming that all the expected charge will flow internally. If this estimated temperature rise ∆Tzmax is below 40 oC, no pollution test is required. If ∆Tzmax is equal to or greater than 40 oC, there are two options: either carry out a pollution test or omit that test and carry out the duty-cycle test by preheating the arrester to 20 oC + ∆Tzmax. If carried out, the purpose of this pollution test will be to determine the ratio of the internal- to the external-charge flow for the different arrester units. The temperature of the internal parts may be measured instead of the internal charge. Two options for the pollution-test technique are permitted in IEC 60099-4, Amendment 1: the slurry method and the Salt-Fog method. In effect, the slurry test that is described comprises a wet contaminant - having a volume resistivity in the range 400 to 500 Ωcm - that is applied uniformly to the whole arrester housing surface and with no wetting subsequent to the application of the voltage.

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140

The Salt-Fog test that is prescribed is performed at two steps below the withstand salinity of the arrester housing. The test cycle comprises 15 minutes of fog application under voltage followed by 15 minutes of energisation without fog (drying period). As mentioned previously, the drying period under voltage can be an important factor 361. With the so determined division of the charge flow between the external and the internal paths, and by using the external charge severity table referred to above, a new estimate ∆Tz of the block temperature is calculated. If ∆Tz < 40 oC, the arrester is preheated to 60 oC to carry out the duty cycle test. Otherwise, preheating will be to 20 oC + ∆Tz.

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141

10. ADITIONAL INFORMATION AND RESULTS 10.1 Insulator profiles and dimensions Table 10-1: Details for line insulators; Refer Table 10-24. TYPE

PIN CAVITY

OVERALL

AXIAL

LEAKAGE

FORM

DIAMETER

DIAMETER

SPACING

PATH

FACTOR

(mm)

(mm)

(mm)

(mm)

34

297

140

426

CEGB 374 kN

381

200

565

124

ENEL 120 kN

280

145

410

124

Cap & Pin Designs Bullers 54260

PROFILE

0.78

REF.

376

Doulton 6672

47

380

190

611

0.9

377

IEEE

39

254

146

305

0.62

378

NGK 820 kN

460

290

800

379

NGK 680 kN

440

280

750

379

394

210

592

LEAKAGE PATH /

CERL Reference A

29

Longrod designs

CORE

SHED

DIAMETER

SPACING

0.86

378

SHED

L7524SN/1360 1.15m length, 24 sheds

1999-09-01

75

200

142

46

164

197

Table 10-2: Details for substation insulators (Tapered Barrel/Post); Refer Table 10-24. TYPE

PROFILE

CORE DIAMETER (AVERAGE) (mm)

OVERALL DIAMETER

AXIAL LENGTH (m)

LEAKAGE

FORM

PATH

FACTOR

REF .

Plain Shed

790

(mm) min 810

3-skirt a.f. shed abcb support

496

890

650

3.2

12.90

0.28

376

3-skirt a.f. shed sealing end

405

800

490

3.07

10.82

0.37

376

2-skirt a.f. shed abcb support

496

870

630

3.50

11.94

0.30

376

2-skirt a.f. shed oil filled c.t.i.

716

1160

780

2.94

10.16

0.23

376

Notes: a.f. : antifog c.t.i. : current transformer insulator abcb : air blast circuit breaker

1999-09-01

143

(m)

max 570

3.5

10.29

0.15

376

Table 10-3: Details for substation insulators (Parallel Barrel / Post); Refer Table 10-24. TYPE

CORE DIAMETER (AVERAGE) (mm) 628

OVERALL

LEAKAGE

FORM

PATH

FACTOR

(mm) 920

AXIAL LENGTH (m) 3.39

(m) 13.60

0.21

376

2-unit plain shed

314

450

3.65

8.69

0.17

376

2-skirt a.f. shed SF6-filled c.t.i.

868

1090

3.73

11.86

0.17

376

2-skirt a.f. shed abcb support 1

498

740

3.46

11.02

0.29

376

2-skirt a.f. shed abcb support 2

623

877

3.40

11.72

0.24

376

Italian 2-unit plain shed

740

920

3.37

7.95

0.17

376

National Grid V1 interrupter head

260

384

1.25

3.52

0.16

129

Easy Grease shed abcb support

1999-09-01

PROFILE

DIAMETER

144

REF.

Table 10-3: Continued. TYPE

PROFILE

CERL Reference Post

CORE DIAMETER (AVERAGE) (mm) 230

OVERALL

AXIAL LENGTH (m) 3.80

DIAMETER

(mm) 484

LEAKAGE

FORM

PATH

FACTOR

REF.

(m) 12.67

0.32

375

Notes: a.f. : antifog c.t.i. : current transformer insulator abcb : air blast circuit breaker Table 10-4: Details for substation insulators (Parallel Barrel / Post alternating long and short shed); Refer Table 10-24. TYPE

PROFILE

CORE DIAMETER (AVERAGE) (mm)

OVERALL DIAMETER

AXIAL LENGTH (m)

LEAKAGE

FORM

PATH

FACTOR

REF.

CEGB 70/60 profile

260

(mm) Long 400

CEGB 70/50 profile

260

400

360

1.85

6.70

0.31

375

New Circuit Breaker P1

230

410

350

3.80

14.21

0.40

375

New Circuit Breaker P2

230

356

314

3.80

14.01

0.34

375

National Grid P1

234

376

336

1.30

4.30

0.34

129

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145

(m)

Short 380

1.85

7.42

9.34

375

Table 10-5: Details for post and cap and pin insulators; Refer Table 10-25. From reference 125. TYPE

PROFILE

PIN CAVITY

OVERALL

AXIAL

DIAMETER

SPACING

LEAKAGE PATH (mm)

FORM

DIAMETER

(mm) 317

(mm) 527

(mm) 110

352 to 385

0.28

IV Standard disc Cap and pin

14

254

140

298

0.8

V a.f. Cap and pin

24

381

186

587

1.01

VI Long creepage a.f. Cap and pin

27

415

170

636

1.08

III Multiple cone Post

Notes: a.f. : antifog

Table 10-6: Details for cap and pin and pedestal post insulators; Refer Table 10-26. From reference 197. TYPE

PIN CAVITY DIAMETER

OVERALL

SHED

DIAMETER

SPACING

LEAKAGE PATH (mm)

6a, Cap and pin

(mm) -

(mm) 263

(mm) -

-

6b, Cap and pin

-

319

-

-

7, Cap and pin

-

250

-

-

6c, Cap and pin

-

250

-

-

2a, Pedestal post

-

438

-

-

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PROFILE

146

FACTOR

Table 10-7: Details for barrel insulators; Refer Table 10-26. From reference 197. TYPE

CORE

OVERALL

SHED

DIAMETER

DIAMETER

SPACING

1a

(mm) 113

(mm) 269

(mm) 53

1b

69

163

50

2b

100

181

56

2c

113

213

50

2d

125

225

56

2e

113

244

38

4a

138

250

56

4b

75

200

50

5a

75

156

31

5b

88

169

31

8a

125

263

69

9c

300

400

62

8b (Alternating long and short shed)

119

256

31 / 73

9b (Alternating long and short shed)

250

375

25/38

1999-09-01

PROFILE

147

LEAKAGE PATH (mm)

Table 10-8: Details for cap and pin insulators; Refer Table 10-27 and Table 10-28. From reference 380. TYPE

PIN CAVITY

OVERALL

AXIAL

DIAMETER

DIAMETER

SPACING

LEAKAGE PATH (mm)

I 4-skirt, a.f.

(mm) 50

(mm) 321

(mm) 165

508

II 5-skirt

40

318

165

508

III Bell shape

42

275

146

356

IV 1 very long skirt

-

356

171

566

V

46

381

187

478

VI 5-skirt

49

321

175

502

VII 4-skirt, 2 long

-

267

159

483

VIII 5-skirt

49

321

165

508

IX

43

282

149

457

X 6-skirt

40

267

146

406

XI 4-skirt, 1 long

-

356

171

566

XIV Aerodynamic profile

39

425

159

356

1999-09-01

PROFILE

148

Table 10-9: Details for post and longrod insulators, Refer Table 10-27. From reference 380. TYPE

CORE

OVERALL

SHED

DIAMETER

DIAMETER

SPACING

LEAKAGE PATH (mm)

XII Longrod

(mm) 97

(mm) 289

(mm) 64

210

XXI Parallel Post

165

283

84

180

XXII Parallel Post

146

260

57

188

XXIII Parallel Post

125

233

54

149

XXV Parallel Post

165

254

50

161

XXVI 3-shed Pedestal Post

-

432

-

864

XXX Multiple cone Post

165

337

88

252

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PROFILE

149

Table 10-10: Details for cap and pin insulators; Refer Table 10-29. From reference 315. TYPE*

*

PROFILE

PIN CAVITY

OVERALL

AXIAL

DIAMETER

DIAMETER

SPACING

LEAKAGE PATH (mm)

V1 Flat profile

(mm) 37.5

(mm) 380

(mm) 130

340

V2 Standard

37.5

280

146

386

V3 Long leakage

44

320

170

534

V4 Very long leakage

47.5

355

171

571

P1 Long leakage

45

292

149

470

P2 Standard

39

254

146

305

Insulator designation as used in reference

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150

Table 10-11: Details for cap and pin insulators; Refer Table 10-30. From reference 380. TYPE

PIN CAVITY

OVERALL

AXIAL

DIAMETER

DIAMETER

SPACING

LEAKAGE PATH (mm)

(mm) P3, 4-skirt

(mm) 321

(mm) 171

546

A, 4-skirt

254

146

394

B, 4-skirt

320

170

530

D, 4-skirt

400

159

603

E, 5-skirt

380

195

690

G, 4-skirt

254

159

432

H, 5-skirt

330

170

546

J, 5-skirt

267

146

457

K, 4-skirt

321

165

508

M, 5-skirt

290

160

470

N, 5-skirt

260

160

621

1999-09-01

PROFILE

151

Table 10-12: Details for post and longrod insulators; Refer Table 10-30. From reference 381. INSULATOR NO *

INSULATOR TYPE ***

CORE

OVERALL

SHED

LEAKAGE

DIAMETER

DIAMETER

SPACING

PATH

(mm) 41 37 48 66 63 56 84 50 62 62 62 95 19/64 19/64

(mm)** 120 149 159 174 224 237 253 227 242 273 323 355 215/87 214/62

(mm) (mm) 0 Long rod 73 200 1 I, Plain shed, post 233 360 1A I, Plain shed, post 233 360 2 I, Plain shed, post 233 360 3 I, Plain shed, post 235 400 4 I, Plain shed, post 230 420 5 I, Plain shed, post 250 420 6 II, 3 skirt, post 237 370 7 II, 3 skirt, post 237 370 8 II, 3 skirt, post 235 400 9 II, 3 skirt, post 240 430 10 II, 3 skirt, post 240 430 11 III, ALS shed, post 236 420 12 III, ALS shed, post 236 420 Notes: * : Insulator designation as used in reference ** : Leakage path per shed; i.e. for quoted shed spacing *** : Profiles of Insulator type I, II, II are given below I, Plain shed, post

II, 3 skirt, post

III, ALS shed, post

Table 10-13: Details for cap and pin insulators; Refer Table 10-31 and Table 10-32. From reference 199. TYPE

PIN CAVITY

OVERALL

AXIAL

LEAKAGE

DIAMETER

DIAMETER

SPACING

PATH

A, standard

(mm) -

(mm) 254

(mm) 146

(mm) 280

B1, Fog B2, Fog

-

254 320

146 170

430 550

C1, C2, C3, C4,

-

280 320 320 400

146 165 170 195

445 512 545 635

-

180

875

2085

d.c. d.c. d.c., extra creepage d.c., very long creepage

D, Longrod

1999-09-01

PROFILE

152

Table 10-14: Details for post insulators; Refer Table 10-32. From reference 199. TYPE

PROFILE

CORE

OVERALL

SHED

LEAKAGE

DIAMETER

DIAMETER

SPACING

PATH

(mm)

(mm)

Deep-rib profile

(mm) 65

(mm)* 236

Under-rib profile

50

157

Table 10-15: Details for polymeric longrod insulators; Refer Table 10-34, Table 10-35 and Table 10-40. From references 126 and 127. TYPE *

PROFILE

CORE

OVERALL

SHED

LEAKAGE

DIAMETER

DIAMETE R (mm)

SPACING

PATH

110

(mm) 66

(mm)*** 158

V

EPDM

(mm) 24

VI

EPDM **

31

134/102

36/90

216

VII Silicone rubber

35

134

49

118

VIII EPR

38

171

61

146

Notes: * : Description as used in reference ** : Alternate long and short shed design *** : For quoted shed spacing; i.e. between two large sheds for design VI

1999-09-01

153

Table 10-16: Details for polymeric longrod insulators; Refer Table 10-36. From reference 381. TYPE

PROFILE

CORE

OVERALL

SHED

LEAKAGE

DIAMETER

DIAMETER

SPACING

PATH

R

(mm) 34

(mm) 92

(mm) 32

(mm) 79

S

42

164

55

139

T

43

127

66

155

V

44

123

60

222

W

40

178

65

156

Table 10-17: Details for polymeric longrod insulators; Refer Table 10-37. From reference 380. TYPE

PROFILE

CORE

OVERALL

SHED

LEAKAGE

DIAMETER

DIAMETER

SPACING

PATH

XIII

(mm) 61

(mm) 222

(mm) 100

(mm) 200

XXVII

25

130

40

110

Table 10-18: Details for polymeric longrod insulators; Refer Table 10-38. From reference 315. INSULATOR NO * AND PROFILE

INSULATOR TYPE

CORE

OVERALL

SHED

LEAKAGE

DIAMETER

DIAMETER

SPACING

PATH

(mm)

(mm)

(mm)

(mm)**

Low slope

35

160

35

134

Low slope with rib

35

160

45

158

Mean slope

35

160

55

167

Mean slope with rib

35

160

45

169

High slope

35

160

45

172

High slope with rib

35

160

55

200

A B E F I J Notes: * **

: Description as used in reference : For quoted shed spacing

1999-09-01

154

Table 10-19: Details for cap and pin insulators; Refer Figure 10-1. From reference 111. TYPE

PROFILE

PIN CAVITY

OVERALL

AXIAL

DIAMETER

DIAMETER

SPACING

LEAKAGE PATH (mm)

A-11

(mm) -

(mm) 254

(mm) 146

305

A-12

-

254

130

305

A2

-

290

178

395

B2

-

280

165

370

B3

-

320

198

425

C2

-

280

172

370

C4

-

400

244

535

D5

-

380

220

495

Table 10-20: Details for cap and pin insulators; Refer Figure 10-2. From reference 382. TYPE

PIN CAVITY

OVERALL

AXIAL

DIAMETER

DIAMETER

SPACING

LEAKAGE PATH (mm)

A

(mm) -

(mm) 254

(mm) 146

280

B

-

280

170

370

C

-

320

195

425

1999-09-01

PROFILE

155

Table 10-21: Details for cap and pin insulators; Refer Figure 10-3. From references 22, 124 and 143. TYPE

PIN CAVITY

OVERALL

AXIAL

DIAMETER

DIAMETER

SPACING

LEAKAGE PATH (mm)

A (A’)

(mm) -

(mm) 254

(mm) 146

305

B (B’)

-

254

146

390

C

-

254

130

270

D

-

279

140

433

1

-

381

200

560

2

-

355

171

530

3

-

280

145

300

4

-

280

145

400

1a

-

254

146

290

1b

-

254

146

290

2a

-

254

146

390

2b

-

254

146

390

1999-09-01

PICTURE

156

Table 10-22: Details for cylindrical Insulators (Parallel Barrel); Refer Figure 3-11. From reference 85. TYPE

PROFILE

CORE

SHED

SHED

DIAMETER

PROJECTION

SPACING

LEAKAGE PATH PER SHED (mm)

B

(mm) Various

(mm) 70

(mm) 70

238

C

Various

65

65

250

H

Various

70

70

190

I

Various

70

70

203

J

Various

120

92

407

Table 10-23: Details for interrupter head insulators (Parallel Barrel); Refer Figure 3-17. From reference 129. TYPE

PROFILE

CORE

V1

(mm) 260

OVERALL DIAMETER (mm) 384

(mm) 52

AXIAL LENGTH (mm) 1250

(mm) 3520

H1

340

426

36

1500

4800

H2

380

616

70

1100

3600

H3

380

500

34

1100

4000

H4

380

584

70

1500

4650

DIAMETER

1999-09-01

157

SHED SPACING

LEAKAGE PATH

10.2 Ranking of insulators 10.2.1 Ceramic Insulators Table 10-24: Critical a.c. flashover strength of ceramic insulators vertically mounted; performance in artificial pollution test of Very Heavy severity *. Ranking No 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27

Insulator Type ** National Grid P1, CEGB 70/60 profile, CEGB 374 kN, New Circuit Breaker P2, 3-skirt a.f. shed abcb support, New Circuit Breaker P1, L75/24SN/1360, ‘Easygrease’ shed abcb support, CEGB 70/50 profile, ENEL 120 kN, Allied 54656, National Grid V1 Interrupter Head, 3-skirt a.f. shed sealing end, 2-skirt a.f. shed SF6-filled c.t.i., 2-skirt a.f. shed abcb support 1, 2-skirt a.f. shed Oil c.t.i., Doulton 6672, 2-skirt a.f. shed abcb support 2, 2-skirt a.f. shed abcb support, Italian 2-unit plain shed, Plain shed, IEEE, NGK 820 kN, 2-unit plain shed, NGK 680 kN, CERL Reference, CERL Reference A,

Ref. Post Post Cap & pin Parallel Post Tapered barrel Parallel Post Longrod Parallel barrel Post Cap & pin Cap & Pin Parallel Barrel Tapered barrel Parallel Barrel Parallel Barrel Tapered Barrel Cap & pin Parallel Barrel Tapered Barrel Parallel Barrel Tapered Barrel Cap & Pin Cap & Pin Parallel Barrel Cap & Pin Parallel Post Cap & Pin

129 375 124 375 376 375 197 376 375 124 376 129 376 376 376 376 377 376 376 376 376 378 379 376 379 375 378

Axial Stress kV/m *** 91 84 76 76 74 73 73 71 70 69 66 68 66 60 60 59 58 58 58 53 53 51 47 47 46 46 44

Surface Stress kV/m **** 28 21 27 21 18 20 21 17 19 24 22 24 19 19 19 17 18 17 17 23 18 24 17 20 17 14 16

Notes: * ** *** **** a.f. c.t.i. abcb

1999-09-01

All tests made with a salt-fog of 80 kg/m3 except those reported in reference 197 which were at an ESDD of 0.6 mg/cm2 Name by which the insulator is specified in the relevant reference Axial stress is voltage divided by axial distance between metal fittings Surface stress is voltage divided by leakage path length antifog current transformer insulator air blast circuit breaker

158

Table 10-25: a.c. Ceramic insulators, vertically mounted; flashover performance under marine pollution at BITS *. Ranking No 1 2 3 4 5 Notes: * ** ***

****

Insulator Type ** VI Long creepage a.f. Cap & Pin V a.f. Cap & pin III Multiple cone Post IV Standard disc Cap & Pin I a.f. Cap & Pin (CERL Reference A)

FOM *** (Average) 1.19 1.08 1.07 1.00 1.00

LPR **** 0.89 0.79 0.93 1.32 1.00

Data from reference 125 a.f. is antifog Measure of flashover performance, from the viewpoint of axial length when compared to that of a vertical string of reference insulators (i.e. CERL Reference A in Table 10-24); an average of all values for same insulator type LPR is leakage path ratio, determined as leakage path of CERL Ref. A insulator divided by that of the test insulator, for the same pollution flashover performance

Table 10-26: a.c. Ceramic insulators, vertically mounted; flashover performance under natural pollution in Sweden *. Ranking No 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Notes: * ** ***

1999-09-01

Insulator Type 6a, 8a, 1a, 6b, 2b, 7, 6c, 1b, 2e, 9c, 8b1, 2c, 2a, 4a, 4b, 5a, 2d, 8b2, 9b, 5b,

Specific Leakage (mm/kV, System) ** 10.4 10.8 11.7 11.7 11.8 11.8 11.8 12.2 13.1 13.4 13.9 14.5 14.6 15.2 15.5 15.6 15.9 15.9 16.7 19

Cap & Pin Barrel Barrel Cap and Pin Barrel Cap & Pin Cap & Pin Barrel Barrel Barrel Barrel Barrel Pedestal post Barrel Barrel Barrel Barrel Barrel Barrel Barrel

Volt/LP (kV/m) *** 56 54 50 50 49 49 49 48 44 43 42 40 40 38 37 37 37 37 35 31

Data from reference 197 Specific leakage for same number of flashovers at the same location over same time period Actual stress along the insulator surface

159

Table 10-27: Critical d.c. flashover strength of ceramic insulators, vertically mounted; negative polarity; performance in artificial pollution, using spray fog and Portland cement *. Ranking No 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 Notes: * ** a.f.

No ** XI VIII I IV II XXX XXVI XIV VI X VII XII XXII XXIII XXI III XXV

Insulator Type 4-skirt, 1 long, Cap & Pin 5-skirt, Cap & Pin 4-skirt, a.f., Cap & Pin 1 very long skirt, Cap & Pin 5-skirt, Cap & Pin Multiple cone, Post 3-shed, Pedestal Post Aerodynamic Profile Cap & Pin 5-skirt, Cap & Pin 6-skirt, Cap & Pin 4-skirt, (2 long), Cap & Pin Longrod Parallel Post Parallel Post Parallel Post Bell shape, Cap & Pin Parallel Post

Axial Stress kV/m 178 158 149 149 146 143 141 139 139 132 129 125 123 113 111 110 103

Surface Stress kV/m 54 51 48 45 47 57 60 63 48 47 43 57 44 45 41 46 43

Data from reference 380 Numbers as used in reference 380 antifog profile

Table 10-28: Critical d.c. flashover strength of ceramic insulators, vertically mounted; negative polarity; performance in artificial pollution, using spray fog and kaolin plus salt at ESDD = 0.2 mg/cm2 *. Ranking No 1 2 3 4 Notes: * ** a.f.

No ** I VI IV VIII

Insulator Type 4-skirt, a.f., Cap & Pin 5-skirt, Cap & Pin 1 very long skirt, Cap & Pin 5-skirt, Cap & Pin

Axial Stress kV/m 236 209 185 171

Surface Stress kV/m 76 72 56 55

Data from reference 380 Numbers as used in reference 380 Antifog profile

Table 10-29: Critical d.c. flashover stress for ceramic insulators, vertically mounted; positive polarity; performance in artificial pollution using (a) Salt-Fog test and (b) Clean-Fog test *.

No

***

Insulator ** Type of Cap & Pin unit

Ranking No

Salt-Fog test Axial Surface Stress Stress kV/m kV/m 102 32 80 24 67 26 63 24 54 17 44 21

Ranking No

Clean-Fog test Axial Surface Stress Stress kV/m kV/m 99 32 102 31 113 45 103 40 88 28 71 34

V3 Long leakage 1 4 V4 Very long leakage 2 3 V2 Standard 3 1 V1 Flat profile 4 2 P1 Long leakage 5 5 P2 Standard 6 6 Notes: * Data from reference 315 ** Insulator number and description are those used in reference 315 *** ‘V’ in number designates glass insulator; ‘P’ in the number designates porcelain insulator

1999-09-01

160

Table 10-30: Critical d.c. flashover strength of ceramic insulators, vertically mounted; negative polarity; performance in artificial pollution, using clean-fog and kaolin plus salt at ESDD = 0.05 mg/cm2 *. Ranking No 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Notes: * ** *** P3

No ** K E D B J 0 P3 N H A M 10 12 9 8 11 7 G 3 1A 6 2 5 1 4

Insulator Type 4-skirt, Cap & Pin 5-skirt, Cap & Pin 4-skirt, Cap & Pin 4-skirt, Cap & Pin 5-skirt, Cap & Pin Longrod 4-skirt, Cap & Pin 5-skirt, Cap & Pin 5-skirt, Cap & Pin 4-skirt, Cap & Pin 5-skirt, Cap & Pin II, 3-skirt, Post III, ALS shed, Post II, 3-Skirt, Post II, 3-skirt, Post III, ALS shed, Post II, 3-skirt, Post 4-skirt, Cap & Pin I, plain shed, Post I, plain shed, Post II, 3-skirt, Post I, plain shed, Post I, plain shed, Post I, plain shed, Post I, plain shed, Post

Axial Stress kV/m 81 80 80 77 77 74 68 67 63 62 61 59 59 59 57 55 54 53 53 52 51 50 50 50 47

Surface Stress kV/m 26 23 21 25 25 26 21 17 20 23 21 20 18 15 17 15 19 20 20 21 16 24 20 17 15

Data from reference 381 Insulator designation as used in reference 380 ALS is alternate long and short shed is a reference insulator, that was tested simultaneously with each other type of line insulator so as to provide a correction factor

Table 10-31: d.c. Flashover performance of ceramic line insulators; vertically mounted; natural saline pollution *. Ranking No ** 1 2 3 4 5 Notes: * ** *** **** *****

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Insulator *** No C2 B1 B2 A D

Type d.c. Cap & Pin Fog Cap & Pin Fog Cap & Pin, Extra creepage Standard Cap & Pin Longrod

Axial length ratio **** 0.74 0.77 0.79 1.0 1.0

Leakage path ratio ***** 1.42 1.18 1.49 1.0 1.24

Data determined from reference 199 Based on performance at 3 test stations, for both positive and negative polarity Insulator number and description are those used in reference 199 Mean value of axial length of test insulator divided by axial length of reference insulator (i.e. type A, standard Cap & Pin) for same flashover performance Leakage path of test insulator divided by that of reference insulator for same flashover performance

161

Table 10-32: Critical d.c. flashover stress for ceramic insulators, vertically mounted; performance in artificial pollution, using Clean-Fog test with Tonoko plus NaCl at ESDD = 0.05 mg/cm2 *. Ranking No 1 2 3 4 5 6 Notes: * **

No ** C4 C3 C1 A

Insulator Type d.c. Cap & Pin very long creepage d.c. Cap & Pin extra creepage Post, Deep-rib profile d.c. Cap & Pin Post, Under-rib profile Cap and Pin, Standard Profile

Axial Stress kV/m 92 90 90 86 68 65

Surface Stress kV/m 28 28 25 29 22 34

Data from reference 199 Insulator number and description as used in reference 315

Table 10-33: d.c. Withstand stress for a porcelain housing, vertically mounted, as a function of its average diameter; performance in artificial pollution using Clean-Fog test with ESDD of 0.12 mg/cm2 *. Average diameter, mm 200 270 400 560 Axial Stress, kV/m 67 54 48 42 Surface Stress, kV/m ** 23 19 17 15 Notes: * Data from reference 199 ** Average values for a normal profile and an under-rib profile

680 36 13

10.2.2 Polymeric insulators Table 10-34: a.c. Polymeric insulators, vertically mounted; flashover performance under marine pollution at BITS *. Ranking No 1 2 3 4 5 Notes: * ** ***

****

Insulator Type **

FOM *** (Average) >1.53 1.21 1.17 1.12 0.9

VII Silicone rubber V EPDM VIII EPR VI EPDM Epoxy resin

LPR **** 134

Rapid loss of water repellency during test

Non-oily appearance, but still water repellent at end of test

Evidence of tracking on insulator surface on completion of test

Notes: *

Data from reference 249

Table 10-40: a.c. Flashover stress of new and aged polymeric insulators in artificial salt-fog pollution *. Flashover stress at 80 kg/m3 salinity, kV/m Insulator type ** New Aged 6 months Aged 4 years EPDM VI 89 88 79 Silicone rubber, VII 75 61 Notes: * Data from reference 378 ** Insulator number as used in reference 378

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