As-NZS 7000 2010 Overhead Line Design - Detailed Procedures - DRAFT

COMMITTEE EL-052

DR 08170 (Project ID: 8326)

Draft for Public Comment Australian/New Zealand Standard LIABLE TO ALTERATION—DO NOT USE AS A STANDARD

BEGINNING DATE FOR COMMENT:

13 August 2008

CLOSING DATE FOR COMMENT:

15 October 2008

Overhead line design Part 1: Detailed procedures

COPYRIGHT

Draft for Public Comment Australian/New Zealand Standard

The committee responsible for the issue of this draft comprised representatives of organizations interested in the subject matter of the proposed Standard. These organizations are listed on the inside back cover. Comments are invited on the technical content, wording and general arrangement of the draft. The preferred method for submission of comment is to download the MS Word comment form found at http://www.standards.com.au/Catalogue/misc/Public Comment Form.doc .  This form also includes instructions and examples of comment submission. When completing the comment form ensure that the number of this draft, your name and organization (if applicable) is recorded. Please place relevant clause numbers beside each comment. Editorial matters (i.e. spelling, punctuation, grammar etc.) will be corrected before final publication. The coordination of the requirements of this draft with those of any related Standards is of particular importance and you are invited to point out any areas where this may be necessary. Please provide supporting reasons and suggested wording for each comment. Where you consider that specific content is too simplistic, too complex or too detailed please provide an alternative. If the draft is acceptable without change, an acknowledgment to this effect would be appreciated. When completed, this form should be returned to the Projects Manager, Brian Lester  via   via email to [email protected]. Normally no acknowledgment of comment is sent. All comments received electronically by the due date will be put before the relevant drafting committee. Because Standards committees operate electronically we cannot guarantee that comments submitted in hard copy will be considered along  wi th tho se subm itt ed ele ctroni ctr onical cal ly. Where approp app rop riate, ria te, cha nges nge s w ill be incorp inc orp orated ora ted bef ore the Standard is formally approved. If you know of other persons or organizations that may wish to comment on this draft Standard, could you please advise them of its availability. Further copies of the draft are available from the SAI Global Customer Service Centre listed below and from our website at http://www.saiglobal.com/ .

SAI GLOBAL Customer Service Centre

Telephone: 13 12 42 Facsimile: 1300 65 49 49 e-mail:

mailto:[email protected]

Internet:

http://www.saiglobal.com/shop

Draft for Public Comment STANDARDS AUSTRALIA/STANDARDS NEW ZEALAND Committee Committee EL-052—Electrical Energy Networks, Construction and Operation Subcommittee Subcommittee EL-052-05 — Design of Overhead Electrical Lines DRAFT Australian/New Zealand Standard Overhead line design Part 1: Detailed procedures (To be AS/NZS XXXX:200X)

Comment on the draft is invited from people and organizations concerned with this subject. It would be appreciated if those submitting comment would follow the guidelines given on the inside front cover. This document is a draft A ustralian/New Zealand Standard only and is liable to alteration in the light of comment received. It is not to be regarded as an Australian/New Zealand Standard until finally issued as such by Standards Australia/Standards Australia/Standards New Zealand.

DRAFT ONLY

7

DRAFT ONLY

PREFACE This Standard was prepared by the Joint Standards Australia/Standards New Zealand Committee EL-052-05, Electrical Energy Networks, Construction and Operation—Design of Overhead Electrical Lines. The objective of this Standard is to provide Electricity Industry network owners, overhead line maintenance service providers, design consultants, construction contractors, structure designers, and pole manufacturers with an industry standard, that replaces all previously used reference guidelines. This Standard is Part 1 of a series of four document— Part 1: Overhead line design Standard—Detailed procedures, which is a Standard that sets the detailed design requirements for overhead lines. Part 2: Overhead line design Standard—Simplified procedure, which is a Standard that sets simplified design requirements for overhead lines, which are typically at distribution voltages and applying to commonly used pole construction. Part 3:  Applic  App licati ation on guide gui de for the design des ign of overhe ove rhead ad lines, lin es, which is a Handbook providing supporting information, commentary, worked examples and supporting software (where applicable) for the design of overhead lines. gui deline iness for the constr con str uction uct ion,, maint mai ntena enance nce and work wor k practi pra cti ces of overhe ove rhead ad Part 4:  ENA guidel lines, which is an Electricity Industry guideline for the purpose of facilitation of standard work practices throughout the electricity supply industry.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY

8

DRAFT ONLY

CONTENTS  Page

SECTION 1 SCOPE AND GENERAL 1.1 SCOPE AND GENERAL ................................................................... .......................................................................................... ....................... 12 1.2 REFERENCED AND RELATED DOCUMENTS........................................ DOCUMENTS..................................................... ............. 12 1.3 DEFINITIONS....................... DEFINITIONS....................................................... ................................................................ .................................................... .................... 12 1.4 NOTATION............................................ NOTATION............................................................................ ................................................................. ................................... .. 21 SECTION 2 DESIGN PHILOSOPHIES 2.1 GENERAL..................................... GENERAL....................................................................... ................................................................... .......................................... ......... 24 2.2 LIMIT STATE DESIGN............................................ DESIGN.............................................................................. ................................................ .............. 24 2.3 DESIGN LIFE OF OVERHEAD LINES ................................................................. ................................................................... .. 26 2.4 OPERATIONAL CHARACTERISTICS OF AN OVERHEAD LINE....................... 26 2.5 OPERATIONAL PERFORMANCE OF OVERHEAD LINES.................................. 26 2.6 RELIABILITY............. RELIABILITY................................................. ....................................................................... .......................................................... ....................... 26 2.7 COORDINATION OF STRENGTH............................................................ STRENGTH.......................................................................... .............. 26 2.8 ENVIRONMENTAL CONSIDERATIONS....................... CONSIDERATIONS....................................................... ........................................ ........ 27 SECTION 3 ELECTRICAL REQUIREMENTS 3.1 GENERAL CONSIDERATIONS ................................................................... .............................................................................. ........... 28 3.2 CURRENT CONSIDERATIONS ................................................................... .............................................................................. ........... 28 3.3 INSULATION SYSTEM DESIGN ................................................................... ........................................................................... ........ 28 3.4 LIGHTNING PERFORMANCE OF OVERHEAD LINES................................ LINES........................................ ........ 28 3.5 ELECTRICAL CLEARANCE DISTANCES TO AVOID FLASHOVER ................. 29 3.6 DETERMINATION OF STRUCTURE GEOMETRY.............................. GEOMETRY............................................... ................. 31 3.7 SPACING OF CONDUCTORS ............................................................. ................................................................................. .................... 34 3.8 INSULATOR AND CONDUCTOR MOVEMENT AT STRUCTURE ................... 45 3.9 LIVE LINE CLEARANCES................................... CLEARANCES................................................................... ................................................... ................... 48 3.10 CLEARANCES TO GROUND AND AREASREMOTE AREASREMOTE FROM BUILDING, BUILDING, ROADS, RAILWAYS AND NAVIGABLE WATERWAYS WATERWAYS ................................... ................................... 48 3.11 POWER LINE EASEMENTS........................... EASEMENTS............................................................. ......................................................... ....................... 53 3.12 CORONA EFFECT ...................................................................... ................................................................................................... ............................. 53 3.13 ELECTRIC AND MAGNETIC FIELDS ................................................................. ................................................................... .. 54 3.14 SINGLE WIRE EARTH RETURN (SWER) POWERLINES.................................... 54 SECTION 4 CONDUCTORS AND OVERHEAD OVERHEAD EARTHWIRES (GROUND WIRES) WITH OR WITHOUT TELECOMMUNICATION CIRCUITS 4.1 ELECTRICAL REQUIREMENTS .............................................................. ............................................................................ .............. 56 4.2 MECHANICAL REQUIREMENTS ............................................................... .......................................................................... ........... 58 4.3 ENVIRONMENTAL REQUIREMENTS .......................................................... .................................................................. ........ 63 4.4 CONDUCTOR CONSTRUCTIONS......................... CONSTRUCTIONS......................................................... ................................................. ................. 64 4.5 CONDUCTOR SELECTION ............................................................ .................................................................................... ........................ 64 SECTION 5 INSULATORS 5.1 INSULATION BASICS..................................... BASICS...................................................................... ........................................................ ....................... 66 5.2 LINE AND SUBSTATION INSULATION COORDINATION ................................ ................................ 66 5.3 ELECTRICAL AND MECHANICAL DESIGN ....................................................... ....................................................... 67 5.4 RELEVANT STANDARDS, TYPES AND CHARACTERISTICS OF INSULATORS................................................................ INSULATORS.............................. .................................................................... ........................................... ......... 68

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY

9

DRAFT ONLY

 Page

SECTION 6 BASIS OF STRUCTURAL DESIGN 6.1 GENERAL................................................................................................................. 69 6.2 REQUIREMENTS..................................................................................................... 69 6.3 LIMIT STATES......................................................................................................... 71 6.4 ACTIONS .................................................................................................................. 75 6.5 MATERIAL PROPERTIES....................................................................................... 76 6.6 MODELLING FOR STRUCTURAL ANALYSIS AND RESISTANCE................... 76 SECTION 7 ACTION ON LINES 7.1 INTRODUCTION ..................................................................................................... 78 7.2 ACTIONS, GENERAL APPROACH ........................................................................ 78 7.3 LOAD CASES ........................................................................................................... 82 SECTION 8 SUPPORTS 8.1 INITIAL DESIGN CONSIDERATIONS................................................................... 85 8.2 MATERIALS AND DESIGN .................................................................................... 85 8.3 CORROSION PROTECTION AND FINISHES........................................................ 86 8.4 MAINTENANCE FACILITIES................................................................................. 87 8.5 LOADING TESTS .................................................................................................... 87 SECTION 9 FOUNDATIONS 9.1 GENERAL................................................................................................................. 91 9.2 DESIGN PRINCIPLES.............................................................................................. 91 9.3 POLE AND TOWER FOUNDATIONS ................................................................... 92 9.4 SOIL INVESTIGATION ........................................................................................... 92 9.5 BACKFILLING OF EXCAVATED MATERIALS ................................................... 92 9.6 FOUNDATION DISPLACEMENTS......................................................................... 92 9.7 LOAD TESTING OF FOUNDATIONS .................................................................... 92 9.8 CONSTRUCTION AND INSTALLATION .............................................................. 93 SECTION 10 EARTHING SYSTEMS 10.1 GENERAL PURPOSE............................................................................................... 94 10.2 EARTHING MEASURES AGAINST LIGHTNING EFFECTS................................ 94 10.3 DIMENSIONING WITH RESPECT TO CORROSION AND MECHANICAL STRENGTH ............................................................................................................. 94 10.4 DIMENSIONING WITH RESPECT TO THERMAL STRENGTH .......................... 95 10.5 RISK BASED EARTHING - PERMISSIBLE VALUES ........................................... 95 10.6 ELECTRICAL ASPECTS OF STAYWIRE DESIGN ............................................. 100 10.7 CHOICE OF EARTHING MATERIALS ................................................................ 101 SECTION 11 LINE EQUIPMENT—OVERHEAD LINE FITTINGS 11.1 GENERAL............................................................................................................... 102 11.2 ELECTRICAL REQUIREMENTS .......................................................................... 102 11.3 RIV REQUIREMENTS AND CORONA EXTINCTION VOLTAGE..................... 102 11.4 SHORT-CIRCUIT CURRENT AND POWER ARC REQUIREMENTS ................ 102 11.5 MECHANICAL REQUIREMENTS ........................................................................ 102 11.6 DURABILITY REQUIREMENTS .......................................................................... 103 11.7 MATERIAL SELECTION AND SPECIFICATION................................................ 103 11.8 CHARACTERISTICS AND DIMENSIONS OF FITTINGS ................................... 103 11.9 TYPE TEST REQUIREMENTS.............................................................................. 105 11.10 SAMPLE TEST REQUIREMENTS ........................................................................ 105 11.11 ROUTINE TEST REQUIREMENTS....................................................................... 105 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY

10

DRAFT ONLY

 Page

SECTION 12 LIFE EXTENSION (REFURBISHMENT, UPGRADING, UPRATING) UPRATING) OF EXISTING OVERHEAD LINES 12.1 GENERAL..................................... GENERAL....................................................................... ................................................................... ........................................ ....... 106 12.2 ASSESSMENT OF STRUCTURES ................................................................ ....................................................................... ....... 106 12.3 COMPONENT CAPACITY .............................................................. .................................................................................... ...................... 107 12.4 PROOF LOADING................................... LOADING..................................................................... ............................................................... ............................. 107 12.5 GUIDELINES FOR UPGRADING OF OVERHEAD LINE STRUCTURES.......... 107 SECTION 13 PROVISIONS FOR CLIMBING AND WORKING AT HEIGHTS SECTION 14 CO-USE OF OVERHEAD LINE SUPPORTS (SIGNAGE, BANNERS, COMMUNICATIONS CARRIER CABLES, TELECOMMUNICATIONS REPEATERS) 14.1 SIGNS AND BANNERS AND TRAFFIC MIRRORS ......................................... ......................................... 109 14.2 COMMUNICATIONS CARRIER CABLES ........................................................... ........................................................... 111 14.3 TELECOMMUNICATIONS REPEATERS EQUIPMENT ANDTRAFFIC MIRRORS ............................................................... ................................................................................................ ............................................... .............. 111 APPENDICES A REFERENCE AND RELATED DOCUMENTS ..................................................... ..................................................... 113 B WIND LOADS ................................................................ ................................................................................................ ....................................... ....... 120 C SPECIAL FORCES ............................................................... ............................................................................................... .................................. .. 137 D GUIDELINES ON SERVICE LIFE OF OVERHEAD LINES................................. LINES................................. 145 E DESIGN FOR LIGHTNING PERFORMANCE ..................................................... ..................................................... 154 F TIMBER POLES ................................................................... ..................................................................................................... .................................. 156 G LATTICE STEEL TOWERS (SELF SUPPORTING AND GUYED MASTS)........ 162 H ELECTRICAL DESIGN ASPECTS ................................................................. ....................................................................... ...... 167 I CONCRETE POLES .................................................................... ............................................................................................... ........................... 170 J COMPOSITE FIBRE POLES .................................................................. .................................................................................. ................ 173 K STEEL POLES ................................................................... ..................................................................................................... ..................................... ... 174 L STRUCTURE FOOTING DESIGN AND GUIDELINES FOR THE GEOTECHNICAL PARAMETERS PARAMETERS OF SOILS AND ROCKS ROCKS ............................... ............................... 177 M GUIDELINES ON APPLICATION OF STANDARDIZED WORK METHODS FOR CLIMBING CLIMBING AND WORKING WORKING AT HEIGHTS ................................................ ................................................ 204  N GUIDELINES GUIDELI NES ON UPGRADING UPGRADI NG OVERHEAD OVE RHEAD LINE LI NE STRUCTURES STRUC TURES ............... ........ ....... 209 O WATER ABSORPTION TEST ............................................................. ............................................................................... .................. 218 P INSULATION GUIDELINES ............................................................... ................................................................................ ................. 221 Q MID SPAN SEPARATION CALCULATIONS ..................................................... ..................................................... 224 R INSULATION SWING ANGLE CALCULATIONS ............................................. ............................................. 226 S CONDUCTOR SAG AND TENSION CALCULATIONS ...................................... ...................................... 230 T CONDUCTOR TEMPERATURE MEASUREMENT AND SAG MEASUREMENT ........................................................................................... .................................................................................................. ....... 240 U RISK BASED APPROACH TO EARTHING ......................................................... ......................................................... 243 V CONDUCTOR PERMANENT ELONGATION ...................................................... ...................................................... 257 W CONDUCTOR MODULUS OF ELASTICITY ....................................................... ....................................................... 260 X CONDUCTOR COEFFICENT OF THERMAL EXPANSION.......................... EXPANSION................................ ...... 263 Y CONDUCTOR DEGRADATION and SELECTION FOR DIFFERING ENVIRONMENTS ................................................................. .................................................................................................. ................................. 264 Z CONDUCTOR STRESS AND FATIGUE ............................................................ ............................................................... ... 268

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY

AA BB CC DD EE FF

11

DRAFT ONLY

 Page CONDUCTOR TENSION CHANGE OF STATE EQUATION .............................. .............................. 274 CONDUCTOR SHORT TIME AND SHORT-CIRCUIT RATING ......................... ......................... 277 CONDUCTOR ANNEALING................................................................ ANNEALING................................................................................. ................. 280 MECHANICAL DESIGN OF INSULATOR - LIMIT STATES.............................. 284 EASEMENT WIDTH ................................................................ .............................................................................................. .............................. 285 SNOW AND ICE LOADS............................... LOADS ............................................................... ........................................................ ........................ 286

8326-PDR - 24/07/2008 14:25:50

12

DRAFT ONLY

DRAFT ONLY

STANDARDS AUSTRALIA/STANDARDS NEW ZEALAND Overhead line design Part 1: Detailed procedures S E C T I O N

1

S C O P E

A N D

G E N E R A L

1.1 SCOPE AND GENERAL

This Standard specifies the general requirements that shall be met for the design and construction of new overhead lines to ensure that the line is suitable for its intended  purpos ur pose, e, and provide prov ide accept acc eptabl ablee level lev elss of safety saf ety for constr con struct uction ion,, mainte mai ntenan nance, ce, operat ope ration ion,, and meets requirements for other environmental considerations. This Standard is only applicable to new overhead lines and is not intended to be retrospectively applied to the routine maintenance, and ongoing life extension of existing overhead lines constructed prior to the issue of this Standard. Such maintenance and life extension work ensures that lines continue to comply with the original design standards and remain safe and ‘fit for purpose’ However, where existing overhead lines are proposed to be upgraded or refurbished including installation of larger conductors, modified to provide tee-offs, diversions or the erection of additional communication cables and antennae, such that the original structure design loadings are increased to a point that elements of the support structures may be overloaded or overstressed; then the overhead line structures shall be required to be structurally assessed by a competent person for compliance with the provisions of this Standard. This Standard is applicable to overhead lines supporting telecommunication systems or where they are used on overhead lines either attached to the line conductor/earth wire systems or as separate cables supported by the supports such as optical ground wires (OPGWs) and optical conductors or all dielectric self supporting (ADSS) conductors. It is also applicable to overhead line structures supporting telecommunications equipment. This Standard does not apply to catenary systems of electrified railways. 1.2 REFERENCED AND RELATED DOCUMENTS

See Appendix A for a list of documents referenced in this Standard and for a list of related documents. 1.3 DEFINITIONS

For the purpose of this Standard the definitions below apply. 1.3.1 Accidental action

Action, usually of short duration, which is unlikely to occur with a significant magnitude during the design working life.  NOTE: OT E: An accide acc identa ntall action act ion can be exp ected ect ed in many man y cases cas es to cau se severe seve re conseq con sequen uences ces unless unl ess special measures are taken.

1.3.2 Action

(a)

Force (load) applied to the (mechanical) system (direct action).  NOT E: An act ion can be per manent man ent,, vari v ari able abl e or o r a cci dental den tal .

8326-PDR - 24/07/2008 14:25:50

13

DRAFT ONLY

(b)

DRAFT ONLY

An imposed or constrained deformation or an imposed acceleration caused for example, by temperature changes, moisture variation, uneven settlement or earthquakes (indirect action).

1.3.3 Aerial bundled cable

Two or more cores twisted together into a single bundled cable assembly. Two types of aerial bundled cable are used— (a)

low voltage aerial bundled cable (LVABC) means a cable which meets the requirements of either AS/NZS 3560.1 or AS/NZS 3560.2 as applicable; and

(b)

high voltage aerial bundled cable (HVABC) means a cable which meets the requirements of either AS/NZS 3599.1 or AS/NZS 3599.2 as applicable.

1.3.4 Aerial cable

Any insulated or covered conductor or assembly of cores with or without protective covering, which is placed above ground, in the open air and is suspended between two or more supports. 1.3.5 Aerial conductor

Any bare conductor which is placed above ground, in the open air and is suspended between two or more supports. 1.3.6 Bonding conductor

Conductor providing equipotential bonding. 1.3.7 Calculated breaking load (CBL)

In relation to a conductor, means the calculated minimum breaking load determined in accordance with the relevant Australian/New Zealand Standard. 1.3.8 Characteristic value of a material property

Value of a material property having a prescribed probability of not being attained in a hypothetical unlimited test series. This value generally corresponds to a specified fraction of the assumed statistical distribution of the particular property of the material. A nominal value is used as the characteristic value in some circumstances. 1.3.9 Clearance

Distance between two conductive parts along a string stretched the shortest way between these conductive parts. 1.3.10 Coefficient of variation

Ratio of the standard deviation to the mean value. 1.3.11 Component

One of the different principle parts of the overhead electrical line system having a specified  purpos ur pose. e. Typical components are supports, foundations, conductors, insulator strings and hardware. 1.3.12 Conductor temperature

Means the temperature assumed for the purpose of calculation, the temperature determined  by the use of ESA A docume doc ument nt D(b)5 D(b )5 or other oth er an approp app ropria riate te Standa Sta ndard, rd, or the temper tem peratu ature re measured at the surface of a conductor by means of a contact thermometer or similar, whichever is applicable.

8326-PDR - 24/07/2008 14:25:50

14

DRAFT ONLY

DRAFT ONLY

1.3.13 Covered conductor

Means a conductor around which is applied a specified thickness of insulating material. AS/NZS 3675 specifies two types of covered conductor— (a)

CC

where the nominal covering thickness is independent of working voltage; and

(b)

CCT

where the nominal covering thickness is dependent on the working voltage.

1.3.14 Conductor (of an overhead line)

A wire or combination of wires not insulated from one another, suitable for carrying an electric current. 1.3.15 Corona

Luminous discharge due to ionisation of the air surrounding an electrode caused by a voltage gradient exceeding a certain critical value.  NOTE: OT E: Ele ctr odes ode s may m ay be conduc con ductor tor s, har dware, dwa re, accesso acc essorie rie s or o r i nsu nsulat lat ors

1.3.16 Design working life or design life

Assumed period for which a structure is to be used for its intended purpose with anticipated routine maintenance but without substantial repair being necessary. 1.3.17 Earth

Term for the earth as a location as well as for earth as a conductive mass, for example types of soil, humus, loam sand, gravel and stone. 1.3.18 Earth current

Current flowing to earth via the impedance to earth. 1.3.19 Earth electrode

Conductor which is embedded in the earth and conductively connected to the earth, or a conductor which is embedded in concrete, which is in contact with the earth via a large surface (for example foundation earth electrode). 1.3.20 Earth fault

Conductive connection caused by a fault between a phase conductor of the main circuit and earth or an earthed part. The conductive connection can also occur via an arc. Earth faults of two or several phase conductors of the same electrical system at different locations are designated as double or multiple earth faults. 1.3.21 Earth fault current

Current which flows from the main circuit to earth or earthed parts if there is only one earth fault point at the fault location (earth fault location). 1.3.22 Earthing

All means and measures for making a proper conductive connection to earth. 1.3.23 Earthing conductor

Conductor which connects that part of the installation which has to be earthed to an earth electrode as far as it is laid outside of the soil (earth wire) or buried in the soil. 1.3.24 Earthing system

Locally limited electrical system of conductively connected earth electrodes or earthing conductors and of bonding conductors, [or metal parts effective in the same way, for example tower footings, armourings, metal cable sheaths].

8326-PDR - 24/07/2008 14:25:50

15

DRAFT ONLY

DRAFT ONLY

1.3.25 Earth potential rise (EPR)

Voltage between an earthing system and reference earth. 1.3.26 Earth rod

Earth electrode which is generally buried or driven in vertically to a greater depth. For example it can consist of a pipe, round bar or other profile material. 1.3.27 Earth surface potential

Voltage between a point on the earth surface and reference earth. 1.3.28 Earth wire

A conductor connected to earth at some or all supports, which is suspended usually but not necessarily above the line conductors to provide a degree of protection against lightning strokes.  NOT E: An earth ear th wir e may m ay also als o cont c ontain ain metall met all ic wir es for tel ecommu eco mmunic nic ation ati on purpos pur poses. es.

1.3.29 Effective field strength

Square root of the sum of the squares of the three root mean square (r.m.s.) mutually orthogonal components of the field. 1.3.30 Electrical power frequency clearance condition

A uniform wind pressure of 500 Pa applied to the projected area of the conductor without any allowance for span reduction factors with the conductor at the every day temperature  plus lu s 10°C 1 0°C.. 1.3.31 Electric field

The electric field created in the vicinity of a charged conductor is the vector quantified by the electric field strength,  E . This quantity is the force exerted by an electric field on a unit charge and is measured in volts per metre (V/m). 1.3.32 Element

One of the different parts of a component. For example, the elements of a steel lattice tower are steel angles, plates and bolts. 1.3.33 Equipotential bonding

Conductive connection between conductive parts, to reduce the potential differences  betwee et ween n thes t hesee part p arts. s. 1.3.34 Every day temperature (EDT)

The average of the daily mean maximum temperature and the daily mean minimum temperature. 1.3.35 Exclusion limit probability of a variable

Value of a variable taken from its distribution function and corresponding to an assigned  probab ro babili ili ty of not being bei ng exceed exc eeded. ed. 1.3.36 Failure

State of a structure whose purpose is terminated, i.e. in which a component has failed by excessive deformation, loss of stability, overturning, collapse, rupture, buckling, etc. 1.3.37 Highest system voltage

Highest (r.m.s.) value of voltage which occurs at any time and at any point of the overhead line under normal operating conditions and for which the overhead electrical line shall be designed.

8326-PDR - 24/07/2008 14:25:50

16

DRAFT ONLY

DRAFT ONLY

1.3.38 Horizontal earth electrode

Electrode which is generally buried at a low depth. For example it can consist of strip, round bar or stranded conductor and can be carried out as radial, ring or mesh earth electrode or as a combination of these. 1.3.39 Impedance to earth of an earthing system

Impedance between the earthing system and reference earth. 1.3.40 Insulated conductor

A conductor surrounded by a layer of insulation which provides resistance to the passage of current, or to disruptive discharges through or over the surface of the substance at the operating voltage, or injurious leakage of current. For clearance purposes a distinction is made between insulated conductors with and without earthed screens operating at voltages in excess of 1000 V. 1.3.41 Insulated with earthed screen

Includes aerial bundled ca ble (A BC) comply ing wi th eit her AS /NZS 3599.1 or AS/NZS 3599.2 as applicable. 1.3.42 Insulated without earthed screen

Includes CCT cable complying with AS/NZS 3675. 1.3.43 Limit state (structural)

State beyond which the structure no longer satisfies the design performance requirements. 1.3.44 Load case

Compatible load arrangements, sets of deformations and imperfections considered simultaneously with defined variable actions and permanent actions for a particular structure analysis. 1.3.45 Low velocity every day wind

Wind velocity be tween approximately 0.5 m. s-1 and 7 m. s-1 which results in vortices  being ei ng detach det ached ed from fro m the top and bottom bot tom a conduc con ductor tor at regula reg ularr and altern alt ernati ating ng interv int ervals als inducing a vertical force in the conductor which is translated into vertical movement and conductor vibration with varying frequency depending on the conductor diameter and the wind velocity. 1.3.46 Maximum design temperature

The maximum steady state temperature under the influence of either steady state current or short time current for a phase conductor or short circuit current for overhead earth wires. 1.3.47 Maximum load wind

Three second gust wi nd speed in accordance wi th AS/NZS 1170.2 corresponding to the overhead line design return period. 1.3.48 Maximum operating temperature

The overhead line maximum temperature— (a)

 based as ed on the proper pro pertie tiess of o f the t he conduc con ductor tor shall sha ll not exceed exc eed— — (i)

the permissible temperature rating of the conductor with appropriate consideration of differential expansion of dissimilar materials (known as  birdca ir dcagin ging); g); or

(ii)

for covered and or insulated conductors the insulation temperature rating shall  be in accord acc ordanc ancee with w ith the approp app ropria riate te Austra Aus tralia lian n or o r New N ew Zealan Zea land d Stan S tandar dard; d; or

8326-PDR - 24/07/2008 14:25:50

17

DRAFT ONLY

(b)

DRAFT ONLY

(iii)

the temperature rating of fibre optic cores; or

(iv)

the permissible loss of strength due to annealing as specified in Appendix CC; or

(v)

the drop point any grease applied to the conductor; and

design shall not result in an infringement of the required electrical clearance specified in Section 3.

1.3.49 Magnetic field

The magnetic field is a vector quantity. The magnetic field strength, H, is expressed in amperes per metre (A/m). 1.3.50 Magnetic flux density

The magnetic flux density, also known as the magnetic induction, is the force exerted on a charge moving in the field and has the unit tesla (T). One tesla is equal to 1 V.s/m2 or 1 weber per square metre (Wb/m2). 1.3.51 Maintenance

Total set of activities performed during the design working life of the system to maintain its  purpos ur pose. e. 1.3.52 Nominal voltage

Voltage by which the overhead electrical line is designated and to which certain operating characteristics are referred. 1.3.53 Optical conductor (OPCON)

Conductor containing optical telecommunication fibres. 1.3.54 Optical groundwire (OPGW)

Optical conductor used solely as an earth wire. The conductor component may be stranded or may be tubular or a combination of both. 1.3.55 Overhead ground wire (aerial earth conductor)

An aerial conductor which is grounded or earthed at multiple points. 1.3.56 Overhead line

Aerial conductors or cables together with associated supports, insulators and apparatus used for the transmission or distribution of electrical energy. 1.3.57 Overhead service line

An overhead line operating at a voltage less than 1000 V owned by an electricity supply authority and located or to be located between the electricity supply authority’s overhead line and the point of connection to an electrical installation. 1.3.58 Permanent action

Means an action which is likely to act throughout a given design situation and for which the variation in magnitude with time is negligible in relation to the mean value, or for which the variation is always in the same direction (monotonic) until the action attains a certain limit value. 1.3.59 Potential grading

Influencing of the earth potential, especially the earth surface potential, by means of earth electrodes.

8326-PDR - 24/07/2008 14:25:50

18

DRAFT ONLY

DRAFT ONLY

1.3.60 Potential grading earth electrode

Conductor which due to shape and arrangement is principally used for potential grading rather than for establishing a certain resistance to earth. 1.3.61 Pre-stressed concrete

Means concrete containing reinforcing steel, some or all of which has been tensioned prior to the application of external working loads. 1.3.62 Prospective step voltage

Means the prospective or open circuit voltage that may appear between any two points on the surface of the ground spaced one metre apart (measured with two driven electrodes and a high impedance voltmeter). 1.3.63 Prospective touch voltage

Means the prospective or open circuit voltage (measured with a driven electrode and a high impedance voltmeter) which may appear between any point of contact with uninsulated metalwork located within 2.4 m of the ground and any point on the surface of the ground within a horizontal distance of one metre from the vertical projection of the point of contact with the uninsulated metalwork. 1.3.64 Radio interference

Any effect on the reception of a required radio signal due to an unwanted disturbance within the radiofrequency spectrum. Radio interference is primarily of concern for amplitude-modulated systems (AM radio and television video signals) since other forms of modulation (such as frequency modulation (FM) used for VHF radio broadcasting and television audio signals) are generally much less affected by disturbances that emanate from overhead lines. 1.3.65 Reinforced concrete

Means concrete containing more than 0.6% by volume of reinforcing steel in the form of  bar, ar , rod or mesh. mes h. Tensil Ten sil e forces for ces wit hin the concre con crete te sec tion tio n are usu usuall ally y assume ass umed d to be resisted by the reinforcement. 1.3.66 Reliability (electrical)

Ability of a system to meet its supply function under stated conditions for a given time interval. 1.3.67 Reliability (structural)

Probability that a system performs a given purpose, under a set of conditions, during a reference period. Reliability is thus a measure of the success of a system in accomplishing its purpose. 1.3.68 Return period

Mean interval between successive recurrencies of a climatic action of at least defined magnitude. The inverse of the return period gives the probability of exceeding the action in one year. 1.3.69 Road

Means a public thoroughfare ordinarily used by motor vehicles. 1.3.70 Ruling span

Also known as the equivalent span or the mean effective span (MES), means that level dead-end span in which the behaviour of the tension closely follows that of the tension in every span of a series of suspension spans under the same loading conditions.

8326-PDR - 24/07/2008 14:25:50

19

DRAFT ONLY

DRAFT ONLY

1.3.71 Safety

Ability of a system not to cause human injuries or loss of lives during its construction, operation and maintenance. 1.3.72 Security

Ability of a system to be protected from a major collapse (cascading effect) if a failure is triggered in a given component. This may be caused by electrical or structural factors. 1.3.73 Serviceability limit state

State beyond which specified service criteria for a structure or structural element are no longer met. 1.3.74 Soil resistivity

Specific electrical resistance of the earth. 1.3.75 Span length

Means the centre-line horizontal distance between two adjacent supports. (For short spans, when determining the horizontal distance of the fixing points of a conductor, the angle of the crossarm to the line should be considered accordingly.) 1.3.76 Step voltage

That part of the earth potential rise which can be picked up by a person with a step-width of 1 m, i.e. the current flowing through the human body from foot to foot. 1.3.77 Strength

Mechanical property of a material, usually given in units of stress. 1.3.78 Structure

Organized combination of connected elements designed to provide some measure of rigidity. 1.3.79 Support

General term for different types of structure that support the conductors of the overhead electrical line. 1.3.80 Support, suspension

Support equipped with suspension insulator sets. 1.3.81 Support, tangent

Suspension or tension support used in straight line. 1.3.82 Support, tension

Support equipped with tension insulator sets. 1.3.83 Support, terminal (dead-end)

Tension support capable of carrying the total conductor tensile forces in one direction. 1.3.84 System (electrical)

All items of equipment which are used in combination for the generation, transmission and distribution ofelectricity. 1.3.85 System (mechanical and structural )

Set of components connected together to form an overhead electrical line.

8326-PDR - 24/07/2008 14:25:50

20

DRAFT ONLY

DRAFT ONLY

1.3.86 System with isolated neutral

System (electrical) in which the neutrals of transformers, generators and earthing transformers are not intentionally connected to earth, except for high impedance connections for signalling, measuring or protection purposes. 1.3.87 System with low-impedance neutral earthing

System (electrical) in which at least one neutral of a transformer, earthing transformer or generator is earthed directly or via an impedance designed such that due to an earth fault at any location the magnitude of the fault current leads to a reliable automatic tripping. 1.3.88 System with low-impedance neutral or phase earthing

System (electrical) with isolated neutral or resonant earthing, in which in case of a non-selfextinguishing earth fault a neutral or phase conductor of the main circuit is earthed directly or via low impedance a few seconds after the occurrence of an earth fault. 1.3.89 System with resonant earthing

System (electrical) in which at least one neutral of a transformer or earthing transformer is earthed via an arc suppression coil and the combined inductance of all arc suppression coils is essentially tuned to the capacitance of the system to earth for the operating frequency. 1.3.90 Television interference

Special case of radio interference for disturbances affecting the frequency ranges used for television broadcasting. 1.3.91 Touch voltage

That part of the earth potential rise across the human body from hand to feet (assumed to be at a horizontal distance of 1 m from the exposed part of the installation). 1.3.92 Transferred potential

Potential rise of an earthing system caused by a current to earth transferred by means of a connected conductor (for example cable metal sheath, pipeline, rail) into areas with low or no potential rise to reference earth. 1.3.93 Ultimate limit state

State associated with collapse, or with other forms of structural failure which may endanger the safety of people. It corresponds generally to the maximum load-carrying resistance of a structure or a structural element. 1.3.94 Variable action

Action which is unlikely to act throughout a given design situation or for which the variation in magnitude with time is neither negligible in relation to mean value nor monotonic. 1.3.95 Voltage

Means nominal potential difference between conductors or the nominal potential difference  between a conductor and earth, whichever is applicable. 1.3.96 Weight span

For a support, means the equivalent span which gives the vertical component of the conductor load and equals the span between the lowest points on the catenary curve of the conductor on either side of that support.

8326-PDR - 24/07/2008 14:25:50

21

DRAFT ONLY

DRAFT ONLY

1.3.97 Wind span

For a support, means the equivalent span which gives the horizontal lateral component of the conductor load caused by wind and equals one half of the sum of the spans on either side of that support. 1.4 NOTATION

The quantity symbols used in this Standard shall have the meanings ascribed to them below. Symbol

α φ

Signification

= angle of wind to conductor = the strength factor which takes into account variability of material, workmanship etc.

η δ

=

shielding factor

=

solidity factor

γ 

=

soil density

φ  s

=

soil angle of friction

γx

= load factors which take into account variability of loads, importance of structure, safety implications etc.

(kN/m2)

γx

=

load factors which take into account variability of loads, importance of structure, safety implications etc.

 A

=

is the projected area of one structure section (panel) under (m²) consideration in a vertical plane along the face for square towers

 A*

=

is the projected area of the structure section under consideration (m²) in a plane normal to the wind direction

 A1,  A3

=

projected areas of the longitudinal faces on lattice structures in a (m²) vertical plane along the face

 A2,  A4

=

projected areas of transverse faces on lattice structures in a (m²) vertical plane along the face

C

=

drag coefficient of wire

c

=

soil cohesion

C d

=

drag force coefficient for member

COV

=

coefficient of variation

CRF

=

component reliability factor

d

(kPa)

= conductor diameter (mm)

d

=

conductor diameter

(mm)

 D

=

‘effective diameter’ of foundation

(m)

 E n

Earthquake load corresponding to an appropriate return period

 F  b

= load on structure due to unbalanced conductor tensions resulting from abnormal conditions e.g. a broken conductor (kN)

 F c

= conductor loads resulting from wind action on the projected area of conductors (Area = Ld)

8326-PDR - 24/07/2008 14:25:50

(kN)

22

DRAFT ONLY

Symbol

 F c  F s  F s

Signification

=

 F t

conductor tension load

(kN)

= load on structures due to wind action =

force on structural sections (panel) in the direction of the wind

= load on the structure due to the intact horizontal component of conductor tension in the direction of the line for the appropriate wind load =

intact conductor tension loads for the appropriate wind load

(kN)

Load on the structure due to intact conductor tension loads for (kN) the appropriate wind load

 F T G

=

Gc

= vertical dead loads resulting from conductors

vertical dead loads

Vertical dead load related to conductors

Gc Gs

(kN)

force on structural sections (whole tower) in the direction of the (kN) wind

 F sθ  F t

DRAFT ONLY

(kN)

= ve rtical dead loads resulting from non-conductor loads

Gs

Vertical dead load not related to conductors (e.g. poles, cross (kN) arms etc)

 H

=

ground line lateral load

(kN)

 H calc

=

calculated value using recommended method

(kN)

 H L

=

nominal failure load

(kN)

 H max.

=

maximum lateral load

(kN)

k θ

=

factor for angle of incidence

 K i

=

factor that is function of soil modulus of elasticity and foundation geometry

 K q , K c

=

factors that are a function of z/D and

 K x

=

represents factors accounting for aspect ratio, wind direction and shielding of the member

 L

θ of wind to frames

(kN)

φ

= conductor length under consideration for determining conductor loads due to wind action e.g. the wind span for a structure

 L

=

conductor length under consideration for determining conductor (m) loads due to wind action e.g. the wind span for a structure

 L

=

trial embedment depth

 LR

=

line reliability

 M

=

bending moment at ground line

 M d

=

wind direction Clause 3.3

multiplier.

(m)

Refer

(kNm) to

AS/NZS 1170.2:2002,

Reliability based load multiplier

 M rel  M t

=

topographic multiplier for gust AS/NZS 1170.2:2002, Clause 4.4

wind

 M z,cat

=

gust winds speed multiplier for terrain category at height  z . Refer 8326-PDR - 24/07/2008 14:25:50

speed.

Refer

to

23

DRAFT ONLY

Symbol

 p

Signification AS/NZS 1170.2:2002, Clause 4.2

=

ultimate soil pressure

 P c

conductor natural and forced convection cooling

 P  j

conductor joule heating due to the resistance of the conductor

 P r 

conductor radiation cooling.

 P s

conductor solar heat gain

Q

DRAFT ONLY

(kPa)

= maintenance loads

qz

=

dynamic wind pressure

(kPa)

qz

=

vertical overburden pressure at depth z, qz = γz

(kPa)

 Re

=

component design strength based on the nominal strength of the (kN) component for the required exclusion limit ‘e’

 Rm

=

mean strength of the component

 Rn

= the nominal strength of the component

 Rn

=

 Rn  RP

=

S γ

nominal strength of the component

(kN)

The nominal strength of the component

(kN)

return period

(years)

The return period of the storm event being considered

 RP S

(kN)

=

snow and ice loads

(kN)

= snow and ice loads corresponding to an appropriate return  period

SRF

=

span reduction factor to provide for spatial variation in wind

V R 

=

regional wind speed. Refer AS/NZS 1170.2

V x

=

desi gn site wind velocity. Refer AS/NZS 1170., Clause 2.2

W n

=

wind load acting on all structures and line components pertinent (kN) to each loading condition based on the appropriate 3 second gust site wind speed as defined in AS/NZS 1170.2:2002 and corresponding to the selected return period. This load may have an influence on other loads for each specific load case under consideration.

 X

=

the applied loads pertinent to each loading condition

(kN)

 z

=

depth below the ground surface

(m)

 zr

=

point of rotation at an unknown depth below the surface

(m)

8326-PDR - 24/07/2008 14:25:50

(m/s) (m/s)

24

DRAFT ONLY

S E C T I O N

2

D E S I G N

DRAFT ONLY

P H I L O S O P H I E S

2.1 GENERAL

The design of overhead lines requires that the total system including supports, foundations, conductors, insulators and fittings, has operational characteristics that provides for the safe operation and insulation of the energized components, for a planned design service life, and meets or exceeds design levels of reliability. The overhead line design process is an iterative one and needs to apply principles in related design fields (electrical, structural and mechanical) whilst incorporating regulatory, environment and maintenance requirements. The overhead line design shall achieve a number of objectives and some of these may be competing between the related design fields. The objectives which need to be considered are— (a)

safety (designed to relevant regulatory, Australian and International Standards);

(b)

security (minimal structural or component failures);

(c)

reliablity (appropriate outage rates);

(d)

meeting of environmental requirements (EMF, visual, RIV, TIV and audible noise);

(e)

whole of life cost;

(f)

 practi cality to construct;

(g)

ablility to be maintained (provide for climbing corridors, access for Elevating Work Platform vehicles, live line, helicopter maintenance);

(h)

meeting of regulations and codes of practice; and

(i)

satisfaction of power rating requirements.

2.2 LIMIT STATE DESIGN

The design of overhead lines shall be based on limit state principles for serviceability and strength limit states for the various line components. Limit state design uses a load and resistance format, which separates the effects of component strengths and their variability from the effects of external loadings and their uncertainty. 2.2.1 Limit states on line components

The overhead line is considered intact when its structure, insulators, conductors and fittings are used at stresses below the damage limit. 2.2.1.1 Structure design limit states

Limit states to be considered in the design of overhead lines are— (a)

ultimate strength limit state in which the structure’s or component’s design capacity exceeds the design load; and

(b)

serviceability limit state in which the performance of the structure or component under commonly occurring loads or conditions will be satisfactory.

8326-PDR - 24/07/2008 14:25:50

25

DRAFT ONLY

DRAFT ONLY

Serviceability limit states include support deflections. Exceeding the serviceability design load may cause damage to some components.  NOT E: A structure or part thereof or comp onent may be designed to fail or undergo high deflections under some loading situations in order to relieve loads on other parts of the structural system. When this occurs, serviceability limit states may not be maintained.

2.2.1.2 Conductors (including earthwires) limit states

When the conductor is subjected to increasing loads, conductors may exhibit at some level a  permanent deformation particularly if the failure mode is ductil e or may exhibit wire and or whole conductor fracture when subjected to wind induced aeolian vibration. These conditions are defined as the damage or serviceability limit state. If the load is further increased, failure of the conductor and or tension fittings occurs at a level called the failure or ultimate limit state. Finally the conductors and or tension fittings are considered to have failed if the conductors and or fittings have reached their failure limit. The state of system and the damage and failure limits are illustrated in Figure 2.1.

state of system

intact state

damaged state

failed state

conductor strength limits

FIGURE 2.1 LIMIT STATES OF CONDUCTOR

2.2.1.3 Insulator limit states

There are three states for the mechanical design of insulators, these being the— (a)

everyday load;

(b)

serviceable wind load; and

(c)

failure containment load.

The serviceable load is the maximum load that can be applied without causing damage to the insulator or exceeding the desired deflection limit. The failure containment load is the mechanical failure load of the conductor. For line post insulators, the everyday load is a relevant consideration to determine long term deflection of the insulator. 2.2.1.4 Electrical structure clearances limit states

Three serviceability states shall be considered—

•

Condition (a)—Low or still wind

Under low wind conditions the clearance shall be sufficient for maintenance activities. If provision is to be made for live line work, then the clearance shall also  be adequate to maintain safe working distances at a wind pressure of 100 Pa.

•

Condition (b)—Moderate wind

Under moderate wind of 300 Pa the clearance shal l be suffi cient to withstand lightning and switching over-voltages.

8326-PDR - 24/07/2008 14:25:50

26

DRAFT ONLY

•

DRAFT ONLY

Condition (c)—High wind

Under high wind pressure of 500 Pa and at maximum swing position of the insulators, the clearance shall withstand highest power frequency temporary (dynamic) voltages which are normally taken as between 1.4 (solidly earthed) to 1.7 (non-effectively earthed) times the ‘per unit’ voltage. 2.3 DESIGN LIFE OF OVERHEAD LINES

The design life, or target nominal service life expectancy, of a structure is dependent on its exposure to a number of variable factors such as solar radiation, temperature, precipitation, wind, ice, and seismic effects. The service life of an overhead line is the period over which it will continue to serve its intended purpose safely, without undue maintenance or repair disproportionate to its cost of replacement and without exceeding any specified serviceability criteria. This recognizes that cumulative deterioration of the overhead line will occur over time. Therefore, due maintenance and possible minor repairs will be required from time to time to maintain the structure in a safe and useable condition over its service life. 2.4 OPERATIONAL CHARACTERISTICS OF AN OVERHEAD LINE

Each overhead line shall be designed to be capable of transferring a prescribed electrical load, at a selected maximum operating temperature, and with acceptable levels of electrical effects of corona, radio and television interference and electric and magnetic fields. It shall also be capable of safe operation at a serviceability limit states of minimum temperature, as well as everyday temperature with wind. 2.5 OPERATIONAL PERFORMANCE OF OVERHEAD LINES

The operational performance of a line is dependant on each component of a line being able to meet its assumed performance criteria and to achieve a target reliability level under the serviceability and ultimate strength limit state conditions. 2.6 RELIABILITY

All overhead lines shall be designed for a selected reliability level relevant to the lines importance to the system (including consideration of system redundancy), its location and exposure to climatic conditions, and with due consideration for public safety. 2.7 COORDINATION OF STRENGTH

Overhead lines should be regarded as a total spatial structural system that requires coordination of the relative strength of the components constituting the line as set out  below; e.g. this is a mechanism to est ablish a desired sequence of compone nt failure to minimize overall damage. This approach provides a hierarchical control of the sequence of failure of components within an overhead line system, thereby enables the designer to coordinate the relative strengths of components and recognises the fact that an overhead line is a series of components where the failure of any component could lead to the loss of power transmission capability. The four major components of the overhead line are shown in Table 2.1

8326-PDR - 24/07/2008 14:25:50

27

DRAFT ONLY

DRAFT ONLY

TABLE 2.1 OVERHEAD LINE SYSTEM, COMPONENTS AND ELEMENTS Structural system

Components

Elements

Steel sections, wood poles cross arms etc. Supports

Plates, bolts etc. Guys and fittings Anchor bolts, piles, cleats etc.

Foundations

Concrete footing Soil

Overhead line

Wires Conductors

Joints Hardware, shackles etc. Insulator elements

Insulators

Brackets, bolts etc. Fittings

2.8 ENVIRONMENTAL CONSIDERATIONS

All overhead lines should be designed and constructed with consideration of their environmental impact.

8326-PDR - 24/07/2008 14:25:50

28

DRAFT ONLY

S E C T I O N

3

E L E C T R I C A L

DRAFT ONLY

R E Q U I R E M E N T S

3.1 GENERAL CONSIDERATIONS

The electrical design for an overhead line covers the following: (a)

Design of conductor to minimize losses and meet required voltage drop, and RIV, TVI and audible noise levels.

(b)

Power frequency, switching and lightning overvoltages.

(c)

Determination of current rating to meet power requirements.

(d)

Electrical clearances.

(e)

Selection of insulation.

(f)

Lightning performance.

(g)

Design of earthing system.

(h)

Electric and magnetic fields.

3.2 CURRENT CONSIDERATIONS

The cross-section of the phase conductors shall be chosen so that the design maximum temperature for the conductor material is not exceeded under operating conditions. Once a conductor and its maximum operating temperature have been chosen, the conductor rating can be calculated. Various methods of determining conductor rating are given in Section 4. The overhead line and the earthing system (refer Section 10 ) shall be designed to withstand without damage the mechanical and thermal effects due to the fault currents. It is important to take into account the actual duration which is dependent on the tripping time of the  protection syst em for the overhead line. 3.3 INSULATION SYSTEM DESIGN 3.3.1 General

Overhead equipment will be subjected to the effects of lightning. The insulation system comprises air gaps and insulators. All overhead lines shall be designed to coordinate insulation protection schemes to protect sensitive plant and equipment, such as substations, and to provide the desired outage performance rate. These issues are discussed further in the following sections. 3.3.2 Coordination with substations

Precautions should be taken to ensure that lightning strikes close to the substation are attenuated to levels which do not cause damage to substation equipment. The principles and rules of insulation co-ordination are described in AS 1824. The  procedure for insulation co-ordination consis ts of the sel ection of a set of standard withstand voltages which characterize the insulation. 3.4 LIGHTNING PERFORMANCE OF OVERHEAD LINES

Overhead lines are designed for a lightning performance outcome and recommended outage rates for a range of voltage levels are given in Table 3.1 The recommended reliability in terms of outage rates need to be varied in accordance with the importance of the line. In the far northern parts of Australia where there are high lightning activity levels, it may not be practical to achieve the recommended rates. 8326-PDR - 24/07/2008 14:25:50

29

DRAFT ONLY

DRAFT ONLY

Computer programs developed by IEEE, CIGRE and EPRI are available for estimating the lightning outage rates. TABLE 3.1 RECOMMENDED LIGHTNING OUTAGE RATE Voltage kV

Recommended lightning outage rate (per 100 km per year)

Less than 11

Not applicable

11 to 33

5 to 10

66 to 132

1 to 2

220 to 330

0.3 to 0.6

500

<0.3

 NOT E: Gro und flash density maps of Australia and New Zealand are given in AS/NZS 1768.

For detail procedure in assessing design for lightning performance refer to Appendix E. 3.5 ELECTRICAL CLEARANCE DISTANCES TO AVOID FLASHOVER 3.5.1 Introduction

Overhead lines shall be designed with electrical clearances from the energized conductor to surrounding objects to provide safe and reliable operation. These objects can be other energized conductors, structures, constructions, plant, vehicles or vessels (water craft). The  basic approach to electrical cle arances is to combine an electrical air gap wit hstand distance, ( G w) with a safety margin ( S m). Gw   is dependent on the electrical breakdown voltage of air (around 300 kV per metre), Relative air density (RAD), the air gap geometry. S m  is dependent on the type of object, the movement of the object and the exposure of  persons i n the vicinity of the energized conductor. The electrical clearances which are outlined in this Standard set the minimum acceptable standards for the safe operation and reliable electrical performance of the overhead line. These clearances are classified as— (a)

(b)

Internal, which include the following: (i)

Clearance at the structure

(ii)

Clearance for inspection and maintenance

(iii)

Mid span phase conductor to phase conductor

(iv)

Phase conductor to earthwire

External, which include the following: (i)

Phase conductor to ground.

(ii)

Phase conductor to objects.

(iii)

Circuit to circuit (attached to same structure or unattached).

3.5.2 Clearances to objects and ground

The designer shall have regard for state based Electricity Safety Regulations which may specify additional or more onerous clearances. Where regulations set line design clearances above road pavement these will typically be  based on a minimum electrical clearance (flash over clearance plus margin) plus provision for the maximum likely vehicle height.

8326-PDR - 24/07/2008 14:25:50

30

DRAFT ONLY

DRAFT ONLY

The designer should consider the requirement for any over-dimensional vehicle or machinery and make provision, where necessary, for construction of future subsidiary circuits or under crossings of distribution/sub-transmission lines. The resulting clearance will be above the clearance normally accepted for road purposes. 3.5.3 Inspection and maintenance clearances

The designer needs to be aware of the different methods used for line maintenance and the impact this may have on circuit availability, particularly for multi-circuit construction. Inspection and maintenance activities include— (a)

deadline inspection and/or maintenance  —wi th the line de-energized or earthed for safe access;

(b)

live line inspection  —by provision of a safe access corridor on the structure to inspect components. The designer should have regard, in selecting corridor width, to the available freedom or constraint on body movement and the consequence of inadvertent movement in managing risk; and

(c)

live line maintenance  —this could include sti ck or bare hand work eit her from the structure or insulated elevated work platform or helicopter (in-span if clearances are appropriate).

For safe approach and live line clearances refer to Electricity Networks Association (Australia) publications, Electricity Engineers’ Association (New Zealand) publications, Australian Standards and New Zealand Codes of Practice. 3.5.4 Live access clearance

During tower structure access, there is a greater risk of lapse of control than with deliberate approach which may be applied at a working position. Climbing corridors should be dimensioned to— (a)

accommodate the natural climbing action without requiring the constrained movement  by the climber to maintain safe electrical distances (refer climbing space tes t in Figure 3.1); and

(b)

maintain at least power frequency flashover distance in the event of a momentary lapse of controlled movement by the climber. (refer full reach test in Figure 3.1).

Power frequency flashover distance Safe approach distance

FIGURE 3.1 ACCESS CLEARANCE TEST

8326-PDR - 24/07/2008 14:25:50

31

DRAFT ONLY

DRAFT ONLY

3.5.5 General considerations and cases 3.5.5.1 States for calculation of clearances 3.5.5.1.1 Maximum design temperature

Based on the properties of the conductor the maximum design temperature shall not exceed— (a)

the permissible temperature rating of the conductor with appropriate consideration of differential expansion of similar materials (known as birdcaging); and/or

(b)

for covered and or insulated conductors the insulation temperature rating shall be in accordance with the appropriate Standard; or

(c)

the temperature rating of fibre optic cores; and/or

(d)

the permissible loss of strength due to annealing as specified in Clause CC; and/or

(e)

the drop point any grease applied to the conductor.

The design temperature shall not result in an infringement of the required electrical clearance specified in Section 3. 3.5.5.2 Ice load for determination of electrical clearance

The characteristic ice load to be applied shall be specified directly based on regional experience. 3.5.5.3 Combined wind and snow/ice loads

Combined wind and snow/ice loads should be considered in certain regions of Australia and  New Zealan d, based on regional experience. 3.5.6 Clearances at the structure

The three serviceability clearance states which shall be considered are given in Section 2 and include— (a)

low or still wind;

(b)

moderate wind; and

(c)

high wind.

3.6 DETERMINATION OF STRUCTURE GEOMETRY

Structures shall be designed with adequate air clearances to provide a reliable performance and to allow maintenance to be performed safely. The electrical design determines the structure geometry and shall be coordinated with the structural design. 3.6.1 High wind serviceability state

The power frequency clearance is the distance between the structure and the conductor when the conductor is subjected to the high wind serviceability wind pressure. Any insulator swing shall be taken into account when determining the structure geometry. 3.6.2 Moderate wind serviceability state

Switching and lightning impulse clearances shall be provided for moderate wind pressure. Any insulator swing shall be taken into account when determining the structure geometry.

8326-PDR - 24/07/2008 14:25:50

32

DRAFT ONLY

DRAFT ONLY

3.6.3 Low wind serviceability state

The method of access to the structure needs to be considered and then climbing corridors and work positions defined. The structures shall be designed with consideration given to the types of maintenance activities used, such as climbing patrols, helicopter patrols and live line and bare hand working crews. Adequate clearances between the workers and live equipment shall be provided for the various maintenance activities to be performed safely. For inspection and maintenance activities, a maintenance approach distance between  personnel and live parts shall be provided under light winds, typically in range 60 P a to 100 Pa wind pressure. Clearances are required to be considered for the following cases: (a)

Maintenance approach distance for climbing and inspection.

(b)

Live line working.

(c)

Hand reach clearance.

For maintenance approach distances refer to ENA NENS 04. Refer to the following documents for live working distances: (i)

ENA LLM 03 for glove and barrier.

(ii)

ENA LLM 02 for live line sticks.

(iii)

ENA LLM 01 for barehand.

In New Zealand the relevant references are— 1

EEA SM-EI

2

 NZECP 34

Figure 3.2 shows how the working dis tances and wind spee ds are used to establi sh an example 110 kV structure geometry. The wind pressure assumed for maintenance and live line working is— (A)

100 Pa for power frequency flashover

(B)

300 Pa for switching and lightning impulse flashover

(C)

500 Pa for the maximum working wind for a non-cyclonic area.

8326-PDR - 24/07/2008 14:25:50

33

DRAFT ONLY

DRAFT ONLY

34.5˚  2500

1600

35

1668 (9 fog type insulators) 1400 Impulse clearance 100 Pa

20 ˚ 

1592 (9 normal insulators)

900 min. live line air gap

952

3700

1400 normal maintenance approach limit

Live line maintenance equipment in extreme position 35

1020

23

500-50 Hz Withstand

500 Pa and 660 Pa 5.5˚ 

70 ˚  0 Pa

Pole centre line

1400 Live line working distance 700 Live line working corridor 50 0

1000 square climbing corridor  AC CESS ON T R AV ER SE FA CE

50 0

Climbing corridor SUSPENS I ON STR UCT U RE

FIGURE 3.2 STRUCTURE GEOMETRY SHOWING ELECTRICAL CLEARANCES

Hand reach clearance—for a typical tower where the climbing corridor is 700 mm from the face the recommended hand reach clearance is 1.7 metre from the tower face. For a pole , the hand reach clearance is 100 mm from the pole centre line.

8326-PDR - 24/07/2008 14:25:50

34

DRAFT ONLY

DRAFT ONLY

3.7 SPACING OF CONDUCTORS 3.7.1 Conductors of different circuits on different supports (unattached crossing) 3.7.1.1   General

This clause provides the minimum requirements to prevent circuit to circuit flashover, under both normal operating and fault conditions, between aerial conductors or cables of different circuits that cross each other and are not attached to the same pole or support at the point of crossing (see Figure 3.3)— (a)

Where a circuit operates at a voltage below 1000 V it should be placed below any other circuit operating at a higher voltage.

(b)

The vertical separation any conductor or cable of the higher circuit and any conductor or cable of the lower circuit should satisfy both of the following:

(i)

 Normal conditions clearance  —The vertic al separation should be not less than that specified in Table 3.2.

(ii)

 Dynamic loading clearance  —Refer to Figure 3.4.

If conditions are such that it is likely that the lower circuit can flick up into the higher circuit, the vertical separation at the crossing point should be twice the sag of the lower circuit when both conductors or cables are at their maximum design temperature. (This is a simplified calculation method).  NOT E: Dyn amic load can be caused by vegetatio n falling on conductor s or ice shedding

FIGURE 3.3 UNATTACHED CROSSING

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY

35

DRAFT ONLY

FIGURE 3.4 SIMPLIFIED UNATTACHED CROSSINGS FOR FAULT CONDITIONS (DOUBLE ENVELOPE METHOD)

8326-PDR - 24/07/2008 14:25:50

TABLE 3.2 VERTICAL SEPARATION FOR UNATTACHED CROSSINGS (IN METRES) UPPER CIRCUIT

330 kV
≤ 500 kV

Bare

≤ 330 kV

275 kV < U

Bare

L O  8   3  2   6  P  D R

W

Bare 66 kV < U

E R

≤ 275 kV

132 kV < U

≤ 132 kV

C I

≤ 66 kV

R C U I T

1000 V < U

≤ 33 kV

Bare or covered 1000 V < U

U

 275 kV

U  132 kV

U  66 kV

U > 330 kV

U > 275 kV

U >132 kV

U > 66 kV

U > 33 kV

Bare

Bare

Bare

Bare

Bare

≤ 33 kV

Insulated

≤ 1000 V

U  33 kV U > 1000 V Bare or covered

U

 33 kV

U > 1000 V Insulated

Wind

5.2 3.6

No wind

5.2

3.8

Wind

3.6

2.6

No wind

5.2 3.6

3.8 2.6

2.8 2.2

5.2 3.6

3.8 2.6

2.8 2.2

2.4 1.5

Wind

5.2 3.6

3.8 2.6

2.8 2.2

2.4 1.5

1.8 0.8

No wind

5.2

3.8

2.8

2.4

1.8

1.2

Wind

3.6

2.6

2.2

1.5

0.8

0.5

No wind

5.2 3.6

3.8 2.6

2.8 2.2

2.4 1.5

1.8 0.8

1.2 0.5

0.6 0.4

No wind

No wind Wind

Bare

2  4   /    0  7   /   2   0   0   8  1  4  :  2   5  :   5   0 

U  330 kV

Wind

Bare 33 kV < U

U  500 kV

No wind

Wind

U < 1000 V Bare,

covered and (Conductive) insulated

Wind

5.2 3.6

3.8 2.6

2.8 2.2

2.4 1.5

1.8 0.8

1.2 0.5

0.6 0.4

0.6 0.4

No wind

cables (Nonconductive)

 3   7 

Bare, covered and insulated

U

Other Other cables

D R A F  T  O  N L Y

Other cables

No wind

5.2

3.8

2.8

2.4

1.8

1.2

0.6

0.6

0.6

0.4

(Conductive)

Wind

3.6

2.6

2.2

1.5

0.8

0.5

0.4

0.4

0.4

0.2

Other cables

No wind

(Non conductive)

Wind

5.2 3.6

3.8 2.6

2.8 2.2

2.4 1.5

1.8 0.8

1.2 0.5

0.6 0.4

0.6 0.4

0.4 0.2

0.4 0.2

 NOTE S: 1

The above clearances may need to be increased due to local factors such as in Note 7 of Clause 3.7.

2

The clearances in this table may need to be increased to account for safe approach distances required for construction, operation and maintenances and for conductor blow out on large spans.

3

The above clearances are based on the top circuit being at maximum conductor temperature and the bottom circuit at ambient temperature.

4

These clearances apply to heights up to 1000 m.

D R A F  T  O  N L Y

38

DRAFT ONLY

DRAFT ONLY

3.7.1.2 Determination of conductor separation

Vertical separation between circuits is determined by establishing the conductor positions with reference to— (a)

conductor temperatures of each circuit; and

(b)

wind conditions.

The following should be used as a guide for selecting appropriate conductor temperatures and wind pressures: 3.7.1.3 Separation in still air

The conductor temperature of the higher circuit should be the maximum design temperature. In the case of a bearer wire supporting a conductor bundle (e.g. as in Aerial Control Cable to AS/NZS 2373 or HVABC to AS/NZS 3599) the maximum design temperature would be the maximum temperature the bearer wire may reach under the influence of ambient temperature of the air, solar radiation and heat transferred to it from the phase conductors, if applicable. 3.7.1.4 Separation under wind

The conductor temperature of higher circuit should be taken as t °C with conductors hanging in the vertical plane, i.e. the wind direction is along the span, e.g. conductors not displaced  by wind, and Temperature t °C is the conductor temperature applicable to the wind load conditions specified in Appendix B. The conductor temperature of lower circuit should be taken as t °C with conductors displaced by P wind pressure, i.e. the wind direction is normal to the span, and Temperature t °C is the conductor temperature applicable to the wind load conditions specified in Appendix B.  NOT E: This assumes that the conductor temperatures of both cir cuits are at the temp eratur e at which wind pressure occurs, e.g. conductors have cooled to the air temperature.

Table 3.3 gives the temperat ure and electrical conditions for determinin g the electrical clearances TABLE 3.3 AMBIENT CONDITIONS FOR DETERMINING CLEARANCES Condition

Top Conductor

Bottom Conductor

Clearance

 No wind

Ambien t t emp

Ambien t t emp

Impuls e

High wind on lower conductor (500 Pa)

Ambient temp

Ambient temp

Power frequency

3.7.2 Conductors of different circuits on the same support (attached crossing)

This Clause provide the minimum requirements to prevent circuit to circuit flashover, under operating conditions, between aerial conductors or cables that are attached to the same support and cross each other (see Figure 3.5). Where two circuits of different or similar voltage cross each other and are attached to the same support, conductors of a higher voltage circuit should be placed above a lower voltage circuit and the vertical separations between the different circuits at any point on the support under normal working conditions should not be less than specified in Table 3.4.  NOT E: For voltages in excess of 132 kV separation s should be determined by the designer.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY

39

FIGURE 3.5 ATTACHED CROSSINGS

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY

D R A F  T  O  N L Y

TABLE 3.4 VERTICAL SEPARATION FOR ATTACHED CROSSINGS (IN METRES)

UPPER CIRCUIT U  132 kV U > 66 kV Bare

66 kV
U  66 kV U > 33 kV Bare

U  33 kV U > 1000 V Bare or covered

U  33 kV U > 1000 V Insulated

U < 1000 V Bare and covered

U < 1000 V Insulated

Other cables (Conductive)

Other cables (Nonconductive)

2.4

Bare  8   3  2   6  P  D R 2  4   /    0  7   /   2   0   0   8  1  4  :  2   5  :   5   0 

L

33 kV < U ≤   6 6 kV

O

Bare (Note 1)

W

1000 kV < U ≤   3 3 kV

E

Bare or covered

R

1000 kV < U ≤   3 3 kV

2.4

1.5

2.4

1.5

0.9

0.9

2.4

1.5

0.9

0.2

2.4

1.8

1.2

0.6

0.3

0.3

2.4

1.8

1.2

0.6

0.3

0.2

0.3

2.4

1.8

1.2

0.6

0.3

0.3

0.2

0.2

0.2

1.8

1.2

0.6

0.3

0.2

0.2

0.2

4   0 

Insulated C

U < 1000 V

I

Bare and covered

R

U < 1000 V

C

Insulated

U

Other cables

I

(Conductive)

T

Other cables (Non conductive)

 NOTE S: 1

The clearances in the table are based on the lower circuit conductors being attached to pin or post insulators. Additional clearance is required to allo w for conductor movement, if the lower circuit is attached by suspension or strain insulators.

2

The clearances in this table may need to be increased to account for safe approach distances required for construction, operation and maintenances.

D R A F  T  O  N L Y

41

DRAFT ONLY

DRAFT ONLY

3.7.3 Conductors on the same supports (same or different circuits and shared spans)

This Clause provides the minimum requirements between aerial conductors or cables attached to the same support, and sharing the same span to prevent circuit to circuit or  phase to phase flashover under operating conditions. Where aerial conductors or cables are carried on the same pole or support as those of a higher voltage the lower voltage conductors should be placed below the higher voltage conductors. Any two bare aerial conductors having a difference in voltage with respect to each other should have vertical, horizontal or angular separation from each other in accordance with the values required by Clause 3.7.3.1 (refer to Figure 3.6), provided that the clearance at the support or at any part in the span is not less than the separation nominated in Item (b) (refer to Figure 3.7). The separation given by Clause 3.7.3.1 is intended to cater for differential (out of phase and in phase) movement of conductors under wind conditions with minimum turbulence. The separation given by Clause3.7.3.2 is a minimum under any circumstances. 3.7.3.1 At mid span (Refer to Figure3.6)

FIGURE 3.6 CONDUCTOR SEPARATION AT MID SPAN (ONE CIRCUIT)

 X 2

= (1.2Y ) 2 ≥

u

150

+k

D

= I i

. . .(3.1)

where  X 

is the projected horizontal distance in metres between the conductors at mid span; ( X  =  X 1 +  X 2)/2) where  X 1   is the projected horizontal distance in metres between the conductors at one support and  X 2   is the projected horizontal distance in metres between the conductors at the other support in the same span

Y 

is the projected vertical distance in metres between the conductors at mid span; ( Y  = ( Y 1 + Y 2)/2) where Y 1  is the projected vertical distance in metres between the conductors at one support and Y 2  is the projected vertical distance in metres between the conductors at the other support in the same span

8326-PDR - 24/07/2008 14:25:50

42

DRAFT ONLY

DRAFT ONLY

U 

is the r.m.s. vector difference in potential (kV) between the two conductors when each is operating at its nominal voltage. In determining the potential between conductors of different circuits, regard should be  paid to any phase differenc es in the nominal voltages

k 

is a constant, normally equal to 0.4. Where experience has shown that other values are appropriate, these may be applied. Refer also to Note 5 of this Clause

 D

is the greater of the two conductor sags in metres at the centre of an equivalent level span and at a conductor operating temperature of 50°C in still air

l i

is the length in metres of any free swing suspension insulator associated with either conductor.

For the purposes of this Clause an equivalent level span shall mean a span— (i)

which has the same span length in the horizontal projection as the original span;

(ii)

in which conductor attachments at supports are in the same horizontal plane; and

(iii)

in which the horizontal component of conductor tension is the same as in the original span.

As this Equation 3.1 is intended to cater for out-of-phase movement of conductors under wind conditions with minimum turbulence, the conductor sags are calculated at 50°C and the effect of different load currents are ignored (because of the significant cooling effect of the wind in these conditions). The wind is not sufficient to increase the sag, and therefore sag can be calculated assuming still air. U   can be determined by using the formula— U

=

Va2

+ Vb2 − 2 Va Vb Cos  φ 

. . .3.2

where V a

=

upper circuit nominal voltage phase to earth value (kV)

V  b φ 

=

lower circuit nominal voltage phase to earth value (kV)

=

phase angle difference between circuits (degrees)

3.7.3.2 At any point in the span

Where U  ≤ 11 kV . . . . . . . . . . 0.38 m Where U  > 11 kV . . . . . . . . . . (0.38 + 0.01 ( U  −  11))

8326-PDR - 24/07/2008 14:25:50

. . .3.3

43

DRAFT ONLY

DRAFT ONLY

(a ) (b ) (a) (b)

(b )

(a)

(a) Mid span separation equation 3.1 applies (b) Any point in span equation 3.3 applies

FIGURE 3.7 CONDUCTOR SEPARATION—ATTACHED ON SAME STRUCTURE  NOT ES: 1

When conductors of different circuits are located vertically one above the other, consideration should be given to the need to prevent clashing of conductors of different circuits under the influence of load current in one or both circuits. Refer to Figure 3.8.

2

This clause is not intended to apply to insulated conductors (with or without earthed screens) of any voltage.

3

The spacing for covered conductors may be reduced providing the covering is adequate to  prevent electr ical breakdown of the covering when the conductor s clash and a risk management strategy is in place to ensure that conductors do not remain entangled for periods  beyond that the covering can withstand.

4

Where spacers are used, spacing may be less than those specified. It is suggested that the spacer be taken to be a conductor support for the purpose of calculating conductor spacing.

5

The above empirical formula is intended to minimize the risk of conductor clashing; however, circumstances do arise where it is not practicable to give guidance or predict outcomes. Some of these situations involve— (a)

extremely turbulent wind conditions;

(b)

the different amount of movement of conductors of different size and type under the same wind conditions; and

(c)

conductor movement under fault conditions (particularly with horizontal construction).

The following k   factors are recommended for overhead power lines which have phase to  phase clearances at 1200 mm or less at midspan: (i)

Extremely turbulent wind conditions— k to be in range 0.4 to 0.6.

(ii)

High to Extreme Bushfire prone areas—  k  to be in range 0.4 to 0.6

(iii)

under high phase to phase fault conditions—  k   = 0.4 for fault currents up to 4,000 A, 0.5 for fault currents from 4,000 A to 6,000 A and 0.6 for fault currents above 6,000 A

(iv)

Conductors of different mass/diameter ratios and at different heights—  k  = 0.4 to 0.6

In all other situations a k   factor of 0.4 is recommended. 6

Mid span clearances will need to be increased in situations where the conductor transition from horizontal to vertical or where the adjacent conductors are of different characteristics (diameter, weight) which can cause out of phase movement..

8326-PDR - 24/07/2008 14:25:50

44

DRAFT ONLY

7

8

DRAFT ONLY

The following situations may also need to be taken into account when considering spacing of conductors but it is not practicable to provide guidance in this document. Knowledge of local conditions would be required to make design decisions. (a)

Aircraft warning devices.

(b)

Large birds which may collide with conductors, causing them to come together, or whose wingspan is such as to make contact between bare conductors and conducting crossarms.

(c)

Flocks of birds resting on conductors are known to ‘lift off’ simultaneously, causing violent conductor movement.

(d)

Ice and snow loading and ice shedding.

(e)

Terrain factors that may contribute to aerodynamic lift and/or random motion.

(f)

Spray irrigators.

(g)

Safety approach clearances for construction, operation and maintenance

Spacing may need to be increased in locations where bridging of the spacing by birds or animals is experienced or probable.

FIGURE 3.8 CONDUCTOR SEPARATION—INFLUENCE OF LOAD CURRENT—  ATTA CHED ON SAME STRUCTU RE

3.7.4 Clearance to inter-span poles

Poles may be installed in between spans to accommodate street lights or low voltage services and electrical clearance needs to be provided for maintenance personnel. The minimum separation between the circuit at maximum operating temperature and interspan  pole for 11 kV and 33 kV shall be 1.5 metres (as shown in Figure 3.9).

8326-PDR - 24/07/2008 14:25:50

45

DRAFT ONLY

 Top ci rc ui t at ma x. design temp

In span clearance

DRAFT ONLY

Derivation of in span clearance Lowest superscript conductor (up to 33kV)

1.5 m

Botom circuit at ambient temp

0.7 m  Ap p ro a c h l i mi t to closest bare live conductor 0.8 m Working zone

Power DR streetlight pole

FIGURE 3.9 CLEARANCE TO INTER-SPAN POLES

3.8 INSULATOR AND CONDUCTOR MOVEMENT AT STRUCTURE 3.8.1 General

This clause provides the minimum requirements for the separation between aerial conductors or cables and any earthed structure to prevent flashover under operating conditions. This clause applies to all transmission and distribution lines using bare aerial conductors and suspension insulators. It is intended to provide guidance in the selection of suitable air gap clearances between conductors and the structure. Guidance in the selection of solid insulation levels is not covered here and should be considered separately. Insulation at the structure is provided by a combination of solid insulators such as  porcelain, glass or other composite materials and also by wood crossa rms, air, or a combination of these. This insulation is subjected to electrical stresses resulting from power frequency voltages, switching surges and lightning impulse voltages. The insulation levels and air gap clearances should be selected to withstand these overvoltages so that the desired operational performance is achieved. A good design should also  provide for insulation coordination between the line insulation and terminal station insulation so as to avoid damage to station equipment from over-voltages. If provision is to be made for live line maintenance, or for access or inspection under live conditions, then the physical distances to access and working positions should be adequate for the safe conduct of this work and to meet any statutory requirements where specified. To the extent practicable, hazards under live conditions should be mitigated by provision of adequate air gap clearances in preference to reliance on procedural precautions. These clearances should encompass the ergonomic and electrical distances necessary to safely  provide for both natural and inadvertent move ment s of persons, together with the movement of conductors possible under the range of working conditions permitted. With suspension insulator strings, the air gap clearances change as the insulator string swings from its position at rest, due to wind action. Consequently the insulation strength of the air gap also changes. The air breakdown strength at any moment will depend on the  physical gap, the shape of the electrodes, atmospheric conditions and altitude. Hence the ability to withstand different over-voltages resulting from power frequency, lightning impulse and switching surges constantly changes.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY

46

DRAFT ONLY

Thus for a freely suspended conductor, both the air gap and the over-voltages are random variables and probabilistic processes need to be used to determine the optimum coordination. Statistical considerations indicate that lightning or switching impulses combined with high swing angles of the insulator string (i.e. smaller air gaps to the structure) have a very low probability of occurrence. The angle of swing itself depends on several variables such as wind velocity, time and space distribution of wind, wind direction, topography and ratio of the wind to weight span. 3.8.2 Structure clearances

Based on operational experience and probabilistic considerations discussed in Clause 3.8.1, a simplified approach consisting of a three envelope system is recommended for the determination of conductor clearances on structures. Condition (a)—Low wind Condition (b)—Moderate wind Condition (c)—High wind Table 3.5 provides recommended structure and conductor clearances for conditions (b) and (c) for different system and impulse withstand voltages. These are suitable for most applications. Where unusual or extreme weather and climatic conditions exist, local knowledge and experience should be used to modify the clearances.

Crossarm

Refer  Ta b l e 3.5

Refer  Ta b le 3. 5

 A ng le of swi ng Ø

Clearance zone

Clearance zone

FIGURE 3.10 CLEARANCE TO STRUCTURES SWING ANGLE—CONDITION (B)

8326-PDR - 24/07/2008 14:25:50

47

DRAFT ONLY

DRAFT ONLY

TABLE 3.5 CLEARANCES TO EARTHED STRUCTURES (IN METRES) Nominal system voltage

kV (r.m.s.)

Lightning/switching impulse withstand voltage

kV (peak)

Clearance to earthed structure in metres for altitudes up to 1000 m Moderate wind

High wind or maximum swing

Condition (b)

Condition (c)

11 95

0.16

0.10

150

0.28

0.13

200

0.38

0.18

350

0.69

0.28

550

1.1

0.40

650

1.3

0.50

950

1.9

0.75

1050

2.2

0.90

1175

2.6

1.10

1250

2.8

1.5

1300

3.1

1.75

1550

4.2

1.75

22

33

66

110

132

220

275

330

400

500  NOTE S: 1

For structures with line post or pin insulators, the moderate wind distances recommended can be used to establish structure clearances.

2

For voltages up to 66 kV, clearances may need to be increased in locations where bridging of insulators  by bir ds or ani mal s i s e xpe rie nce d o r prob abl e.

3

For altitudes in excess of 1000 m – refer to altitude table (BS EN 50341-1).

4

Condition (b) relates to lighting impulse distance and conditions (c) to power frequency flashover distance.

3.8.3 Calculation of swing angles

The conductor tension  H   for insulator swing angle should be based on the relevant reference wind pressure and temperature. The estimation of swing angles may be made using a simplified deterministic approach or a detailed procedure using meteorological data. The latter method should be used when greater precision is required or where unusual and/or extreme local conditions prevail.

8326-PDR - 24/07/2008 14:25:50

48

DRAFT ONLY

DRAFT ONLY

There are other alternative insulator assemblies and appropriate clearances and line actions need to be considered. These alternative types include— (a)

 bridging insulators;

(b)

strain insulators;

(c)

line post insulators;

(d)

vee strings; and

(e)

horizontal vee assemblies.

The swing angles of suspension insulator strings for both low and high wind conditions can  be estimated using the approach in Appendix R. 3.9 LIVE LINE CLEARANCES

Structures shall be designed to provide for live line maintenance. Relevant minimum live line approach clearances are provided in Table 3.6 Reference should also be made to the provisions set out in Clause 3.6.3 Relevant NZ references include NZECP 46 and EEA Guide to Use of Helicopters in Power Company Work . TABLE 3.6 HVAC LIVE LINE APPROACH DISTANCES Nominal phase to phase a.c. voltage

Phase to earth selected distance A/R on

Phase to earth selected distance A/R off

Phase to phase selected distance A/R on

Phase to phase selected distance A/R. off

kV

mm

mm

mm

mm

11

500

500

600

600

22

500

500

600

600

33

500

500

600

600

50

600

550

750

700

66

700

600

900

800

88

850

700

1100

1000

110

950

800

1300

1200

132

1100

900

1500

1300

220

1600

1300

2300

2000

275

2100

1600

3100

2400

330

2700

1900

3900

3000

400

3000

2400

4600

3900

500

3500

2400

5600

3900

3.10 CLEARANCES TO GROUND AND AREASREMOTE FROM BUILDING, ROADS, RAILWAYS AND NAVIGABLE WATERWAYS 3.10.1 Clearances to ground 3.10.1.1 Lines other than insulated service lines

This clause covers all overhead lines except insulated conductors of an overhead service line and facade mounted insulated cable systems.

8326-PDR - 24/07/2008 14:25:50

49

DRAFT ONLY

DRAFT ONLY

The aerial conductors or cables of an overhead line should be located so that the distances to level or sloping ground in any direction from any position to which any part of such conductors may either sag at maximum design temperature or move as a result of wind  pressure, should not be less than the distances specified in Table 3.7. Departures from these specified distances are permissible where a comprehensive risk management assessment has been carried out using the methodology outlined in Appendix U or similar. TABLE 3.7 CLEARANCE FROM GROUND, LINES OTHER THAN INSULATED SERVICE LINES Distance to ground in any direction m Nominal system voltage

U

Over the carriageway of roads

Over land other than the carriageway of roads

Over land which due to its steepness or swampiness is not traversable by vehicles more than 3 m in height

Bare or insulated conductor or any other cable U  ≤   1 000 V OR

5.5

5.5

4.5

6.0

5.5

4.5

1000 V
6.7

5.5

4.5

33 V < U  ≤132 kV

6.7

6.7

5.5

132 kV
7.5

7.5

6.0

275 kV
8.0

8.0

6.7

330 kV
9.0

9.0

7.5

400 kV
9.0

9.0

7.5

Insulated conductor with earthed screen U   > 1000 V Insulated conductor without earthed screen U   > 1000 V Bare or covered conductor

 NOT ES: 1

For the purpose of this Clause, the term ‘ground’ includes any unroofed elevated area accessible to plant or vehicles.

2

In the case of cliff faces or cuttings the clearances specified in the column headed ‘Over land which due to its steepness or swampiness is not traversable by vehicles’ shall apply.

3

In the case of waterways, flood plains and snowfields, the clearances should be determined having regard to local conditions and requirements.

4

Where the usage of land is such that vehicles of unusual height are likely to pass under an overhead line, the clearances given in this clause may need to be increased.

5

The distances specified are final conditions for conductors which have ‘settled in’. When conductors are first erected, an allowance should be made for ‘settling in’ and ‘conductor creep’. Refer to Appendix S.

6

The distances specified in are designed to protect supports from damage from impact loads on conductors as well as protecting vehicles from contact with conductors

7

The above values are based on vehicles with a maximum height of 4.6 m.

8326-PDR - 24/07/2008 14:25:50

50

DRAFT ONLY

DRAFT ONLY

3.10.1.2 Insulated service lines

Insulated conductors of an overhead service line should be located so that the distance to level or sloping ground in any direction from any position to which any part of such conductors may either sag at maximum design temperature or move as a result of wind  pressure, should not be less than the distances specified in Table 3.8. TABLE 3.7 CLEARANCE FROM GROUND, INSULATED LV SERVICE LINES Service line location

Distance to ground in any direction m

Over the centre of a road

5.5

Over any other part of a road

4.6

Over a footway or land which is likely to be used by vehicles

3.0

Elsewhere

2.7

 NOT ES: 1

For the purpose of this Clause, the term ‘ground’ includes any unroofed elevated area accessible to plant or vehicles.

2

In the case of waterways, flood plains and snow fields, the clearances should be determined having regard to local conditions and requirements.

3

Where the usage of land is such that vehicles of unusual height are likely to pass under an insulated overhead service line, the clearances given in this clause may need to be increased.

4

The clearances specified in Table 3.8 are final conditions for conductors which have ‘settled in’. When conductors are first erected, an allowance should be made for ‘settling in’ and ‘conductor creep’. Refer to Appendix S.

3.10.2 Clearances to buildings, traffic routes, other lines and recreational areas 3.10.2.1

Structures and buildings

This clause specifies the minimum clearance from any structure, building, post or line support (other than a support to which the line under consideration is attached or a support of another overhead line which crosses the line under consideration) to any position to which a conductor in an overhead line may swing under the influence of wind as defined in Appendix B or sag under the influence of load current and solar radiation, should be as specified in Appendix S.  NOT ES: 1

The clearances to be maintained at the outer extremities of those parts on any structure on which a person can stand are defined by an arc of radius A or B as appropriate. This arc has its centre at the outer extremity of the structure and extends outward from a point vertically above its centre to its intersection with a vertical line that is located at a horizontal distance specified in C, from the outer extremities of those parts of any structure on which a person can stand.

2

Table 3.8 does not apply to cable systems supported along the facade of a building.

3

Figure 3.12 illustrates the application of Table 3.8 to a particular building. The letters A to D refer to distances A to D as set out in Table 3.8. The letter G refers to distance to ground.

3.10.2.2   Easements

When considering the width of an easement to provide clearance from structures, the  position of the conductors or cables under the influence of wind at any point along the span should be taken into account. A safety clearance should also be included. (Refer to Figure 3.13).

8326-PDR - 24/07/2008 14:25:50

51

DRAFT ONLY

DRAFT ONLY

FIGURE 3.11 STRUCTURE CLEARANCES FOR TABLE 3.9

3.9

3.9

FIGURE 3.12 EASEMENT CLEARANCES

8326-PDR - 24/07/2008 14:25:50

TABLE 3.8 CLEARANCES FROM STRUCTURES

U Clearance

U > 1000 V

1000 V
33 kV
132 kV
275 kV
330 kV
Insulated with Insulated without earthed screen earthed screen

Bare or covered

Bare

Bare

Bare

Bare

m

m

m

m

m

1000 V

Insulated

Bare neutral

Bare active

m

m

M

m

2.7

2.7

3.7

2.7

3.7

4.5

5.0

6.5

7.0

8.0

0.1

2.7

2.7

2.7

2.7

3.7

4.5

6.0

6.5

7.5

m

D R A F  T  O  N L Y

A  8   3  2   6  P  D R 2  4   /    0  7   /   2   0   0   8  1  4  :  2   5  :   5   0 

Vertically (1)   a bove those parts of any structure normally accessible to persons B (1)

Vertically   a bove those parts of any structure not normally accessible to  per son s but on which a p ers on can stand

 5  2 

C In any direction (other than vertically above) from those parts of any structure normally accessible to persons, or from any part not normally accessible to  per son s but on which a p ers on can stand

0.1

0.9

0.1 (2)

0.3

1.5

1.5

1.5

2.1

3.0

4.5

5.0

6.0

0.1

0.6

1.5

2.5

3.5

4.0

5.0

D In any direction from those parts of any structure not normally accessible to  per son s G In any direction from ground

(2)

Refer to Table 3.8

0.6

(2)

Refer to Table 3.8

Refer to Table 3.8

(1)

  T his should not be taken as meaning only the literal vertical. The actual clearance may also extend outwards in an arc until it intersects with the relevant ‘C’ dimension clearance, as indicated on Figure 3.12. See also Note 1 in Clause 3.10.2.1. (2)   T his clearance can be further reduced to allow for termination at the point of attachment.  NOTE: The int erp ret ation/ con firmat ion of cle ara nce s tha t app ly for dif ferent sit uation s out lin ed in thi s Tab le may in som e ins tan ces onl y be mad e follow ing refere nce to Figure 3.12 to determine an actual clearance that is relevant for a particular application.

D R A F  T  O  N L Y

53

DRAFT ONLY

DRAFT ONLY

3.11 POWER LINE EASEMENTS

An easement is legally described as an encumbrance on the title of land limited in width and height above or below the land conferring a right to construct, operate and maintain an electricity power line, cable, or apparatus. Easements are usually obtained or created to ensure electricity utilities can gain ready access to assets for maintenance, repair and upgrading the power lines and for the safety of  persons l iving, working or playing near overhead lines. An easement width can be established to accommodate an overhead energized line asset which ensures adequate safe electrical and mechanical spatial clearances are provided. The easement width may be influenced by other factors such as audible noise, radio and television interference, or electric and magnetic fields. 3.11.1 Typical easement widths

Appendix EE provides typical easement widths for a range of voltages. 3.12 CORONA EFFECT

The surface voltage gradient on the conductor should be limited to less than 16 kV/cm to limit the generation of corona discharges. For higher surface voltage gradients, all surfaces on hardware should be smooth and the corners rounded. At the higher voltage levels, the use of corona rings should be considered around the hardware to reduce corona. 3.12.1 Radio and television interference

Corona generates interference over a wide band of frequencies. The degree of annoyance caused by radio and television interference is determined by the so-called ‘signal-to-noise ratio’ at the receiving installation. When establishing limits for the emission of radio noise, the radio and television signal strengths to be protected have to  be determined. The allowable levels of Radio Interference Voltage (RIV) and Television Interference (TVI) are given in AS/NZS 2344. For New Zealand, the applicable standard is NZS 6869. 3.12.2 Audible noise

The most common form of audible noise is a hissing or frying sound (broadband crackle) audible in wet weather. During fair weather a constant low frequency (100 Hz) hum may also be heard. Designers need to ensure that audible noise levels comply with relevant EPA or local council regulations. The total random audible noise consisting of both broadband and 100 Hz hum need to be addressed in the design process. 3.12.3 Corona loss

In cases where the surface voltage gradient is very high there can be a power loss along the conductor due to corona emission. On overhead power lines, corona loss is expressed in watts per metre (W/m) or kilowatts per kilometre (kW/km). The power loss due to corona is typically less than a few kilowatts/kilometre in fair weather but, it can amount to tens of kilowatts/kilometre during heavy rain and up to one hundred kilowatts/kilometre during frost. In general if the surface vol tage gradient is kept below 16 kV/cm, corona loss wi ll be negligible compared to joule losses.

8326-PDR - 24/07/2008 14:25:50

54

DRAFT ONLY

DRAFT ONLY

3.13 ELECTRIC AND MAGNETIC FIELDS 3.13.1 Electric and magnetic fields under a line

The design of overhead lines can be influenced by the necessity to limit power frequency electric and magnetic fields produced by energized conductors. Limit values for electric and magnetic fields are not provided in this Standard. For such limits, reference shall be made where relevant to— (a)

 for Australia  —to ARPANSA, Draft Radiation Protection Sta ndard for Exposure Limits to Electrical and Magnetic Fields 0 Hz–3 kHz; and

(b)

 for New Zealand  —to ICNIRP Guidelines for Limiting Exposure to Time-Varying Electric, Magnetic, and Electromagnetic Fields (Up To 300 Ghz).

3.13.2 Electric and magnetic field induction

Electric and magnetic fields near an overhead line may induce currents in and voltages on adjacent conductive objects such as long metal structures (e.g. communication installations, fences, lines or pipes) or bulky objects (e.g. conductive roofs, tanks or large vehicles) in  proximity to power lines. Mitigation measures should be considered to reduce these effects to acceptable levels contained in releva nt Standards and Codes . Relevant Standards and Codes are HB 102 (CJC 6 ), and AS/NZS 4853. 3.13.3 Interference with telecommunication circuits

Telecommunication circuits can suffer electrical interference from power lines. For interference calculations and measures to be taken to eliminate the effects or reduce them to acceptable levels, reference shall be made to relevant International and National Standards and/or to qualified Codes of Practice (i.e. ITU Directives (CCITT) Vol. VI and/or to particular agreements between the parties concerned. . Relevant standards and codes are HB 102 ( CJC 6 ). 3.13.4 Electrostatic induction

Electrostatic induction is caused by the electric field surrounding the powerline and these fields can induce charges on nearby metallic objects. This effect is generally only significant at voltages above 200 kV and may influence the minimum ground clearance over  parking areas. For a person the thresholds for perception is given in Appendix H. 3.14 SINGLE WIRE EARTH RETURN (SWER) POWERLINES 3.14.1 General

Single wire earth return (SWER) are distribution powerlines that utilize the earth as a return circuit instead of a conventional conductor. These distribution lines are economical to construct in lightly loaded rural areas where long spans can be constructed. A more detailed discussion on SWER distribution systems is found in The Electricity Authority of New South Wales document,  High Voltage Earth Return for Rural Areas.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY

55

DRAFT ONLY

3.14.2 Types of SWER distribution systems

The ‘isolated’ single wire system is the most common form. This type of SWER distribution system consists of an isolating supply transformer with the secondary winding connected to a medium voltage single wire pole line and earth. Local customer supply poletype transformers are connected between the single conductor line and earth. The primary winding of the isolating transformer is connected to a conventional medium voltage distribution system. SWER distribution systems are utilized in the following arrangements: (a)

The ‘isolated’ single wire system as described above. This is the most common SWER distribution system.

(b)

The ‘duplex’ system that uses an isolating transformer with the secondary earthed at the centre tap. The transformer supplies a two-wire backbone line to which single  phase tee-offs are connected and

(c)

The ‘un-isolated’ system that uses a conventional 3-phase backbone from which single wire tee-off lines emanate.

The design issues to be considered for SWER systems are— (i)

earthing systems need to be designed to take into account broken or poor earth conductor connections;

(ii)

limited capacity due to the low conductivity of the conductor commonly used as well as the limited sizes of isolating and customer transformers;

(iii)

interference with Telecommunications Circuits—there is a limit of 8 A earth current as stipulated in various Codes of Practice for Telecommunications including New Zealand Code of Practice for SWER Systems and NZECP 41;

(iv)

interference with railway telecommunications and signalling circuits;

(v)

harmonics caused by customer’s equipment overloading SWER system and some 3-phase converting devices; and

(vi)

reduced visibility to low flying aircraft (which may be involved in crop dusting or fire fighting).

8326-PDR - 24/07/2008 14:25:50

56

DRAFT ONLY

DRAFT ONLY

S E C T I O N 4 C O N D U C T O R S A N D O V E R H E A D E A R T H W I R E S ( G R O U N D W I R E S ) W I T H O R W I T H O U T T E L E C O M M U N I C A T I O N C I R C U I T S 4.1 ELECTRICAL REQUIREMENTS 4.1.1 DC resistance

The conductor DC resistance is a function of the conductor construction and stranding, material properties and temperature. The resistance shall be determined from either— (a)

a mathematical determination using the known properties of the conductor materials and construction as described in relevant Australian and New Zealand Standards on conductors; or

(b)

 publis hed values in relevant Australian and New Zealand Standards on conductors.

4.1.2 AC resistance

The conductor AC resistance is a function of the conductor DC resistance, construction and stranding, material properties, temperature, frequency and magnitude of the current. The resistance shall be determined from mathematical determination using the known properties of the conductor materials and construction as described in relevant Australian and New Zealand Standards on conductors. A recommended method and guidance to determine the AC resistance is given in IEC TR 61597. Appendices BB and CC provide guidance on conductor maximum operating temperature. 4.1.3 Steady state thermal current rating

The steady state thermal current rating of a conductor is the maximum current inducing the maximum steady state temperature for a given ambient condition and is based on conductor heat gain equals conductor heat loss that is—  P  j  +  P s =  P r +  P c

where the heat gain terms are  P  j   which is the joule heating due to the resistance of the conductor and  P s  is the solar heat gain The heat loss terms are  P c  which is natural and forced convection cooling and  P r   is the radiation cooling. The terms for heat gain for cyclic magnetic flux which is causes by eddy currents, hysteresis and magnetic viscosity; and corona heat gain are not considered. The evaporative cooling heat loss term is also not considered. A recommended methodology to establish the steady state thermal ratings for bare conductors is given in IEC TR 61597. For insulated conductors, the steady state thermal rating shall be in accordance with the appropriate Australian and New Zealand Standards. The steady state thermal current rating shall be determined for coinciding wind velocity and incident angle, daily solar radiation, ambient temperature and conductor surface condition. 4.1.4 Short time thermal current rating

The short time thermal current rating of a conductor is the maximum current inducing the maximum steady state temperature for a given ambient condition and occurs when a step change in current flow results in a short term conductor temperature change and the conductor stored heat = heat gain −  heat loss

8326-PDR - 24/07/2008 14:25:50

57

DRAFT ONLY

DRAFT ONLY

The time constant for short time ratings is generally less than 20 min and meteorological conditions other than solar heat gain will generally not have a significant influence on final conductor temperature. Initial conductor conditions shall be assumed and include initial conductor operating temperature. Short time current and associated conductor temperature rise is illustrated in Figure 4.1.

   E    R    U    T    A    R    E    P    M    E    T

   T    N    E    R    R    U    C

final

initial

I2

I1  T I M E

FIGURE 4.1 SHORT TIME CURRENT RATING AND TEMPERATURE

The final conductor temperature shall not exceed the maximum operating temperature. Appendix BB provides guidance on establishing the short time thermal current rrating for  bare ar e conduc con ductor tors. s. For cove red and ins ulated ula ted conduc con ductor tor the maximu max imum m sho short rt term ter m therma the rmall rating shall be in accordance with the relevant Australian and New Zealand Standards. 4.1.5 Short-circuit thermal current rating

The short-circuit thermal current rating shall be based on adiabatic heating, that is due to the transient nature of the current flow the conductor heat gain and loss at the surface of the conductor shall be ignored. The rating is a function of the conductor cross sectional area, the thermal conductivity of the conductor, the specific heat capacity of the conductor, the conductor resistivity, the conductor temperature coefficient of resistance, the duration of the transient current, the conductor initial temperature, the magnitude of the current and maximum permissible temperature. In determining the rating for circuits where— (a)

the reactance to resistance ratio is greater than 10 then the d.c. asymmetrical heating component of the current shall be taken into account; and

(b)

auto reclose protection is employed then the short-circuit duration shall be the sum of the initial fault duration and the successive auto reclose fault durations and the combined conductor heating shall be cumulative.

The conductor short-circuit thermal rating shall not result in exceeding— i)

any specified permissible temperature rating of the conductor including appropriate consideration of short time differential expansion of dissimilar materials (known as  birdca ir dcagin ging); g);

ii)

for covered and or insulated conductors the insulation temperature rating as specified in the appropriate Australian and New Zealand Standards;

8326-PDR - 24/07/2008 14:25:50

58

DRAFT ONLY

DRAFT ONLY

iii)

the temperature rating of fibre optic cores;

iv)

the permissible loss of strength due to annealing as specified in Appendix CC;

v)

0.5 times, 0.3 times and 0.2 times the melting point of zinc, aluminium and copper respectively; and/or

vi)

the drop point of any grease applied to the conductor.

Appendix BB provides guidance on establishing the short time thermal current rating for  bare ar e conduc con ductor tors. s. For cove red and ins ulated ula ted conduc con ductor tor the maximu max imum m sho short rt term ter m therma the rmall rating shall be in accordance with the relevant Australian and New Zealand Standards. 4.2 MECHANICAL REQUIREMENTS 4.2.1 Limit states

The overhead line is considered intact when its conductors and or tension fittings are used at stresses below their damage limit. When subjected to increasing loads, conductors and or tension fittings may exhibit at some level, permanent deformation particularly if the failure mode is ductile; or for wind induced aeolian vibration, conductors may exhibit wire and or whole conductor fracture. This level is called the damage limit and conductors and or tension fittings will be in damaged state if the conductors and or tension fittings have exceeded the damage limit. If the load is further increased, failure of the conductor and or tension fittings occurs at a level called the failure limit. The conductors and or tension fittings will be in a failed state if the conductors and or tension fittings have exceeded the failure limit. The state of system and the damage and failure limits are illustrated in Figure 4.2.

s t a te o f s y s t e m

conductor strength limits

in ta c t st ate

damaged state

damage limit

f a ile d s ta te

failure limit

FIGURE 4.2 LIMIT STATES OF CONDUCTOR DESIGN

Indicative damage and failure limits of conductors and tension fittings are illustrated in a typical conductor stress strain characteristic illustrated in Figure 4.3.

8326-PDR - 24/07/2008 14:25:50

59

DRAFT ONLY

   d   a   o    l   g   n    i    k   a   e   r    b    d   e    t   a    l   u   c    l   a    C

DRAFT ONLY

Tension fitting failu re region

Permanent el on gation  r eg io n

Elastic elongation region

Strain (% elongation)

FIGURE 4.3 LIMIT STATES OF CONDUCTOR DESIGN

The damage and failure limits of conductors and tension fittings shall be in accordance with Table 4.2 for the direct applied variable action consisting of the imposed loads specified in Clause 7.2.2 plus the everday low velocity wind condition (defined in Clause 1.35).

8326-PDR - 24/07/2008 14:25:50

60

DRAFT ONLY

DRAFT ONLY

TABLE 4.2 DAMAGE AND FAILURE LIMITS OF CONDUCTORS Conductors and tension fittings

Damage limit

Failure limit

Lowest of— Bare

 – vib rat ion lim it (se e Note N ote 1); or

0.7 conductor CBL (see Note 3)

 – 0.5 con duc tor CBL (se e Note N ote 2)

ABC and CC

 Not gre ate r t han the spe cif ied maximum working tension as described in relevant Australian and New Zealand Standards

0.7 conductor CBL (see Note 3)

Lowest of—  – vib rat ion lim it (se e Note N ote 1); or OPGW

 – 0.5 con duc tor CBL (se e Note N ote 2)  – max imu m t ens ion corresponding to the optical fibre strain free condition

 – opt ica l f ibr e f ail ure (ru ptu re)  – 0.7 con duc tor CBL (see (se e Note Not e 3 )

Lowest of—

ADSS

 – as agr eed with wit h t he manufacturer; or  – max imu m t ens ion corresponding to the optical figure strain free condition

 – opt ica l f ibr e f ail ure (ru ptu re)  – opt ica l t ensile ens ile stress str ess (ru ptu re)

 NOTE S: 1

Long term wind induced aeolian vibration causes permanent conductor damage, wire fatigue and in some cases complete conductor fracture. Conductor vibration limit is a function of wind velocity and direction, temperature, terrain, conductor construction, the type of conductor fittings, conductor tension and conductor vibration control. The conductor vibration limit shall be based on determining maximum static conductor tension with or without any dynamic stress control that will result in fatigue free endurance for the design life of the overhead line. The maximum static conductor tension shall be determined for the low velocity every day wind direct applied variable action condition defined in Clause 1.35. Consideration shall be given in determining the damage limit state to any prestressing, over tensioning or temperature allowances to compensate for initial radial wire movement and longer term metallurgical creep of the conductor material. In most situations the governing criteria for conductor tension will be the vibration limit state. Appendix S provides guidance on conductor sag and tension calculations.

2

Damage strength limit state is 0.5CBL for the linear model and shall not be exceeded for the maximum wind direct applied variable action condition specified in Section 7. The factor of 0.5 may be increased to 0.7 by application of a non linear stress strain model. Additional allowance for loss of strength due to conductor annealing is not required. Damage limit may be the governing criteria for a small diameter conductor subject to ice and or high wind loadings.

3

The 0.7 factor is based on the failure performance of tensions fittings. Factors greater than 0.7 may be used based on statistical analysis of tension fitting rupture tests and considerations of installation quality control. Additional allowance for loss of strength due to conductor annealing is not required.

4.2.2 Conductor tension

Conductor tension change behaviour for any given span length and or equivalent span, is a function of the conductor mass, initial conductor tension, conductor cross sectional area, conductor modulus of elasticity and coefficient of thermal expansion, permanent elongation and loading conditions such as temperature, wind loading, and or ice loading. Conductor tension changes shall be determined in accordance with Table 4.3.

8326-PDR - 24/07/2008 14:25:50

61

DRAFT ONLY

DRAFT ONLY

TABLE 4.3 CONDUCTOR TENSION DETERMINATION MODELS Model

 Non linea lin earr stre s tre ss strain str ain

Linear stress strain

Application

 –

con duc tor s wi th max imu m o per ati ng tem per atu res greate gre ate r t han 120 °C

 –

ult ima te des ign ten sio ns exc eed ing the dam age limit lim it

 –

con duc tor s wi th max imu m o per ating ati ng tem peratu per atu res less les s t han 120 °C

 –

ult ima te des ign ten sions sio ns not exc eedin ee din g t he damag dam agee l imi t

 –

ste el con duc tors tor s

 –

aeria ae ria l b und led con duc tors tor s

Conductor creep shall be taken into account in the determination of conductor tension change for conductors under every day conditions with catenary constants greater than 1000 m. Appendix AA provides guidance on conductor change of state determination. 4.2.3 Conductor stress and fatigue

Conductor stress is a combination of the static stress and dynamic stress. Static stress is a function of conductor tension, bending stress over conductor support fittings and compressive stress caused by conductor fittings. Dynamic stress is a function of conductor vibration amplitude and frequency. Elevated conductor static stresses combined with elevated dynamic stress caused by wind induced aeolian vibration will result in permanent conductor fatigue damage, wire fracture and in some cases complete conductor fracture. Fatigue damage generally occurs at points where the conductor is secured to fittings and the combined static and dynamic stresses are a maximum. The conductor vibration limit shall be based on limiting the static and dynamic stresses to less than conductor fatigue endurance limit for the design life of the overhead line. Proven  perfor er forman mance ce of overhe ove rhead ad lines lin es with wit h conduc con ductor tor damage dam age free fre e endura end urance nce based bas ed on a servic ser vicee history with similar conductors, conductor fittings, vibration control, terrain and climates may be used to validate the conductor vibration limit. Appendix S provides guidance on determining conductor static tensions. 4.2.4 Conductor permanent elongation

Conductor permanent elongation consists of strand settling and metallurgical creep. Permanent elongation begins at the instant of applied axial tensile load and continues at a decreasing rate providing tension and temperature remain constant. Conductors operating at continuous elevated temperatures and or tensions are subject to elevated levels of metallurgical creep. Metallurgical creep is plastic deformation that is a logarithmic in behaviour and a function of the conductor type, conductor construction, conductor stress, conductor temperature and time. Conductor constants used to predict creep for the specific conductors shall be determined in accordance with AS 3822 or equivalent Standards. Conductor creep will result in changes in conductor sag and tension with time. Conductor creep shall as a minimum be determined for the average conductor temperature and tension for the design life of the overhead line. For multiple predicted load cases conductor creep shall be considered cumulative.

8326-PDR - 24/07/2008 14:25:50

62

DRAFT ONLY

DRAFT ONLY

Allowance shall be made for permanent elongation to ensure that the required electrical clearance specified in Section 3 is maintained for the design life of the overhead line. The allowance shall consider independently, strand settling at the damage limit and cumulative metallurgical creep. Appendix V provides guidance on conductor permanent elongation. 4.2.5 Conductor annealing

Annealing damage is caused by the heating excursions of the conductor. During the annealing process the conductor material experiences a change in its microstructure which results in a loss of tensile strength, an increase in conductivity and an improvement in material ductility. Annealing damage is cumulative and shall be determined by summing the loss of tensile strength for temperatures arising from the steady state, short time and shortcircuit thermal ratings and associated durations for the design life of the overhead line. The permissible conductor cumulative annealing damage shall not exceed 15% of the CBL for the design life of the overhead line. No allowance is made in the conductor capacity factor for annealing. Annealing shall be considered for copper, aluminium and steel conductors operating at termpeatures greater than 70°, 80° and 200°C respectively. Appendix CC provide guidance on conductor annealing. 4.2.6 Conductor final modulus of elasticity

The final modulus of elasticity of a conductor is a function of a number of factors including the conductor construction and stranding and material properties. The final modulus of elasticity shall be determined from either— (a)

a stress strain test carried out in accordance with AS 3822 or equivalent by which a complete understanding of the conductor stress strain behaviour may be derived; or

(b)

mathematical determination using the known properties of the conductor materials and construction as described in relevant Australian and New Zealand Standards on  bare conductors; or

(c)

 publis hed values in relevant Australian and New Zealand Standards on ins ulated conductors.

Appendix W provides guidance on the determinati on of conductor final modulus of elasticity. 4.2.7 Conductor coefficient of thermal expansion

The coefficient of thermal expansion (CTE) of a conductor is a function of the conductor construction and stranding and material properties. The CTE shall be determined from either— (a)

a thermal elongation test carried out in accordance with AS 3822 or equivalent; or

(b)

a mathematical determination using the known properties of the conductor materials and construction as described in relevant Australian and New Zealand Standards on conductors; or

(c)

 publis hed values in relevant Australian and New Zealand Standards on ins ulated conductors.

Appendix X provides guidance on the determination of conductor coefficient of thermal expansion. 4.2.8 Conductor cross sectional area

The conductor cross sectional area shall be the total area of the mechanical load bearing wires. 8326-PDR - 24/07/2008 14:25:50

63

DRAFT ONLY

DRAFT ONLY

4.2.9 Conductor diameter

The mean of two measurements at right angles is taken at one cross section. For nonsymmetrical sections, the largest section shall be one of the two measurements. 4.2.10 Conductor drag coefficient

For uniform round wires symmetrically stranded and wind velocities less than 60 m. s − 1  the conductor drag coefficient shall be equal to 1.0. For other than uniform round wires, symmetrically stranded and or wind velocities greater than 60 m. s −1  the conductor drag coefficient shall be shall be either measured of calculated. 4.2.11 Conductor calculated breaking load

The calculated breaking load (CBL) of a conductor shall be determined from the relevant Australian and New Zealand Standards for bare conductors and or insulated conductors. 4.2.12 Conductor vertical and horizontal sag

Conductor vertical sag, S y  is a function of the conductor tension, conductor equivalent mass and span length. Conductor equivalent mass is a function of the conductor mass, aerial warning markers, conductor spacers and any contributing ice load. Conductor vertical sag for low tension spans is also influenced by the length and mass of supporting insulators. In addition, over time conductor vertical sag changes and is a function of conductor permanent elongation. Conductor permanent elongation and ice load shall be determined in accordance with Clauses 4.2.4 and 7.2.3 respectively. Conductor vertical sag shall be determined for the maximum operating temperature of the overhead line to ensure that the required electrical clearance specified in Section 3 is maintained. Conductor horizontal sag, S z  or ‘blow out’ is a function of the conductor tension, conductor equivalent diameter, aerial warning markers, direct applied action and span length. Conductor equivalent diameter is a function of the conductor diameter and any increase in diameter from deposited ice. Conductor horizontal sag inclusive of any insulator swing component shall be determined for the electrical power frequency clearance condition specified in Section 3. Conductor inclined sag inclusive of any insulator swing component shall be determined using the same applied action for the vertical and horizontal sag to ensure that the required electrical clearance specified in Section 3 is maintained. Appendix S provides guidance on conductor sag determination. 4.3 ENVIRONMENTAL REQUIREMENTS 4.3.1 Conductor damage risks

Consideration shall be given to the potential damage arising from bushfires, sugar cane fires, lightning impact and cyclones, which may result in conductor being in a damaged or failure limit. The conductor selection shall consider the risk and damage arising from exceeding the damage limit of the conductor. 4.3.2 Conductor degradation

Consideration shall be given to conductor degradation arising from surface pit corrosion of wires and in the case of non-homogeneous conductors and or conductors in contact with dissimilar metal fittings, galvanic corrosion. Pit corrosion particularly for aluminium wires may arise in atmospheres of elevated chloride and sulphur. Copper wires are also susceptible to pit corrosion in the presence of elevated levels of atmospheric ammonia or where aerial crop dusting is common.

8326-PDR - 24/07/2008 14:25:50

64

DRAFT ONLY

DRAFT ONLY

Conductors shall be selected to minimize pit and or galvanic corrosion and where considered appropriate conductor protective coatings such as partly or fully greased conductors shall be used. Appendix Y provides guidance on the selection for various environments. 4.4 CONDUCTOR CONSTRUCTIONS 4.4.1 Conductor types and standards

Conductors shall be designed, selected and tested to meet the electrical, mechanical, environmental and telecommunication requirements of the overhead line. 4.4.1.1 Bare conductors

Bare conductors shall be supplied and manufactured in accordance with AS/NZS 1222.1, AS/NZS 1222.2, AS/NZS 1531, AS/NZS 1746, AS/NZS 3607 or an equivalent International Standard. 4.4.1.2 Insulated conductors and cable systems

Insulated conductors and cable systems shall be supplied and manufactured in accordance with AS/NZS 3560.1, AS/NZS 3560.2, AS/NZS 3599.1, AS/NZS 3599.2 or an equivalent International Standard. 4.4.1.3 Covered conductors

Covered conductors shall be supplied and manufactured in accordance with the AS/NZS 3675 or an equivalent International Standard. 4.4.1.4 Optical fibres

Optical fibre conductors shall be supplied and manufactured in accordance with international standard description and numbers IEC 60794-4. 4.4.1.5 Low-voltage aerial bundled cables (LVABC)

The following considerations apply: (a)

The tangential tension in the cable should not exceed 28% CBL. This is based on maximum working conductor stress of 40 MPa on 95 mm 2  LVABC. This is the limit for transferring the conductor tension through the insulation to the strain clamp and is  based on French experience with heavily filled XLPE compound.

(b)

The highest horizontal tension used for the everday load should take into account the working ratings of cable tensioning equipment such as lugalls, comealongs, etc. Also for 3 or 4 core cables experience has shown that the cores are difficult to separate to fit insulation piercing connectors at cable tensions exceeding 4.5 kN.

4.5 CONDUCTOR SELECTION

Conductor selection consists of consideration of wire size and material, electrical, mechanical, environmental and economic factors. Conductor selection shall satisfy the— (a)

electrical requirements for steady state and transient current ratings, corona discharge, audible noise and radio and televisions interference, I2R losses;

(b)

mechanical requirements annealing, drag coefficient, operating temperature, constructability (no birdcaging or unravelling), permanent elongation fatigue endurance, conductor diameter, sag and strength relationship;

(c)

environmental requirements for corrosion and lightning damage; and

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY

(d)

65

DRAFT ONLY

economic requirements for cost of losses, capital costs, load profile, interest rate, load growth, inventory costs and construction costs (ratio of tension to suspension structures)

Factors to be considered in the selection are wire materials, wire shape, wire sizes and conductor constructions.

8326-PDR - 24/07/2008 14:25:50

66

DRAFT ONLY

S E C T I O N

5

DRAFT ONLY

I N S U L A T O R S

5.1 INSULATION BASICS

Insulation is required to withstand the electrical and mechanical stresses applied to it during its lifetime. The electrical stresses include power frequency, switching and lightning overvoltages and the mechanical stresses include the tensile, compressive or cantilever loadings from conductor tension and weight. When assessing the ability of insulation to withstand power frequency voltages, consideration is given to the contamination of the insulator surfaces. Contamination will  build up on insulator surfaces over time and whe n the surfaces are lightly wetted as a result of high humidity, light rain, fog or dew, the leakage current increases and can result in the following undesirable outcomes: (a)

Visual sparking, audible noise; RIV and TIV interference causing annoyance to the  public .

(b)

Degradation of the insulator surface, thereby reducing its life expectancy.

(c)

Power frequency flashover and subsequent outage.

The flashover performance of an overhead line is dependent on the electrical withstand of the insulator and the air gap distances. Proper co-ordination is required to ensure acceptable flashover performance, in particular the arc distance on the insulator should be comparable to the air gap distance. 5.2 LINE AND SUBSTATION INSULATION COORDINATION

Substation insulation incorporates paper, oil and solid dielectric systems where any flashover may be destructive. This is termed non self restoring insulation and must be  protected from over voltages. Substation plant is available in standardized impulse insulation levels. Line insulation is self restoring and is designed for some low probability of flashover, not zero probability of flashover. Often line insulation levels exceed that of the substation equipment connected at either end. Lightning impulses and switching surges exceeding the capability of the substation plant can be conducted into the substation. A lightning backflashover or direct strike close to the substation can create a large voltage transient that may damage insulation in substation plant, particularly transformers. It should  be noted that lightning causes corona around the conductor, up to around 1 m in diameter. This corona envelope dissipates energy and reduces the rise time and peak voltage as the transient travels along the conductor. In high lightning areas or for high reliability lines, precautions should be taken to ensure that lightning strikes close to the substation are attenuated to levels which do not cause damage to substation equipment (close to the substation is in the range 800 m to 5 km). Lightning protection for transmission lines may include one or more overhead earthwires and low structure earthing values, say below 5 ohms, for the first 2.5 km of any line from a substation to prevent back flashovers. To ensure protection of the substation plant, a transient impulse study including line entry is required to determine the placement and number of surge arresters required to protect substation plant from lightning and switching overvoltages.

8326-PDR - 24/07/2008 14:25:50

67

DRAFT ONLY

DRAFT ONLY

5.3 ELECTRICAL AND MECHANICAL DESIGN 5.3.1 General

The insulators shall be designed to meet the general requirements for reliability and life for the overhead line. In particular, the design shall consider the relevant electrical and mechanical requirements as follows: (a)

Pollution.

(b)

Power frequency voltage.

(c)

Switching surge voltage.

(d)

Lightning performance.

(e)

Mechanical strength.

5.3.2 Design for pollution

When determining the insulation requirements for an overhead power line or an outdoor substation in a contaminated environment, the following criteria need to be considered: (a)

Creepage (or leakage) distance.

(b)

The ability of the material to endure the electrical activity without being degraded.

(c)

The shape of the insulator to assist in reducing the likelihood of contamination collection and facilitate washing.

AS 4436 provides guidance on the selection of insulators for polluted conditions. The basic concept is to increase the surface creepage distance so that it is long enough to prevent a  pollution flashover across the surface. 5.3.3 Design for power frequency voltages (wet withstand requirement)

The line insulation should withstand the maximum voltage expected on the line. Overhead  powerlines can operate continuously up to 1.1 per unit voltage and up to 1.4 per unit for effectively earthed systems during system disturbances, such as faults and load rejection. This voltage is regarded as the maximum dynamic overvoltage. The wet power frequency withstand voltage of the line insulation should be selected to exceed this maximum dynamic overvoltage. 5.3.4 Design for switching surge voltages

Switching surge overvoltages up to 3 per unit peak voltage can arise when overhead lines are switched. The extent of this overvoltage is dependent on— (a)

the point of voltage wave when the line is switched;

(b)

the capacitance or amount of trapped charges on the line; and

(c)

other equipment connected to the line.

When high speed autoreclosing is installed, overvoltage can exceed 3 per unit voltage,  partic ularly on transmiss ion lines. In these cases, it would be common to install surge arresters on the line to limit the overvoltages to the designed line insulation. 5.3.5 Insulator mechanical design

The loads on an insulator shall be calculated using the limit state methodology outlined in Section 6. The recommendations for the insulator strength factor are given in Table 6.5. A simplified approach to the design of insulators is given in Appendix DD.

8326-PDR - 24/07/2008 14:25:50

68

DRAFT ONLY

5.4 RELEVANT INSULATORS

STANDARDS,

TYPES

DRAFT ONLY

AND

CHARACTERISTICS

OF

The Standards which are used to specify the various types of insulators in usage in Australia are shown in Table 5.2.

TABLE 5.2 STANDARDS FOR THE DESIGN, MANUFACTURE AND TESTING OF INSULATORS STANDARD

TITLE

AS 1154

Insulator and conductor fittings for overhead power lines

3608

Insulators—Porcelain and glass, pin and shackle type—Voltages not exceeding 1000 V a.c.

3609

Insulators—Porcelain stay type—Voltages greater than 1000 a.c.

4398

Insulators—Ceramic or glass—Station post for indoor and outdoor use—Voltages greater than 1000 V a.c.

4435.1

Insulators—Composite for overhead lines—Voltages greater than 1000 V a.c—  Definitions, test methods and acceptance criteria for string insulatr units

4436

Guide for the selection of insulators in respect of polluted conditions. (Identical to the IEC 60815 standard).

AS/NZS 2947

Insulators—Porcelain and glass for overhead power lines—Voltages greater than 1000 V a.c.

4435.2

Insulators—Composite for overhead lines—Voltages greater than 1000 V a.c—  Standard strength classes and end fittings for string insulator units

IEC 60305

Insulators for overhead lines with a nominal voltage above 1000 V—Ceramic or glass insulator units for a.c. systems—Characteristics of insulator units of the cap and pin type

60433

Insulators for overhead lines with a nominal voltage above 1000 V—Ceramic or glass insulator units for a.c. systems—Characteristics of insulator units of the long rod type

60575

Thermal-mechanic al performance test and mechanical performance test on string insulator units

60720

Characteristics of line post insulators

61466-2

Composite string insulator units for overhead lines with a nominal voltage greater than 1000 V – Part 2: Dimensional and electrical characteristics

8326-PDR - 24/07/2008 14:25:50

69

DRAFT ONLY

S E C T I O N

6

B A S I S

O F

DRAFT ONLY

S T R U C T U R A L

D E S I G N

6.1 GENERAL

This Section of the Standard provides the basis and the general principles for the structural, geotechnical and mechanical design of overhead lines. This clause should be read in conjunction with the relevant Australian and New Zealand Standards where applicable. The general principles of structural design are based on the limit state concept used in conjunction with a load and material strength factor appropriate to the reference limit state. The values of the factors for actions and material properties depend on the degree of uncertainty for the loads, resistances, material properties, geotechnical parameters, geometrical quantities, design model, the type of structure and the type of limit state. These factors can also depend on the strength co-ordination principles envisaged for the line. The structural design methods are based on ‘limit state’ concepts. Any element of an overhead line which carries structural load, or is a secondary structural or framing element should be considered as a ‘structural element’ of the line support structure in the context of this clause. Structures and components should be designed using a reliability-based (risk of failure) approach. The selection of load factors, in particular for weather related loads, and component strength factors are based on achieving an acceptable risk of failure and operational performance for the line. The performance of the structural system shall be evaluated for an appropriate combination of serviceability and strength limit states as set out in the following clauses. In practice supporting structures and foundations designed to their ultimate strength limit, will be governed to a major extent by conductors, insulators and fittings serviceability requirements.  NOT E: Some states and territ ories of Australia and New Zealand may have Acts and Regu lations which may have requirements in excess of this Standard

6.2 REQUIREMENTS 6.2.1 Basic requirements

An overhead electrical line shall be designed to withstand the ultimate load case combinations for the selected security level as defined below, based on the lines importance to the system (including system redundancy), its location and exposure to climatic conditions, and public safety and design working life. 6.2.2 Security levels

Security levels shall be distinguished as follows: Level I

Applicable to overhead lines where collapse of the line may be tolerable with respect to social and economic consequences. (Normal distribution lines)

Level II

Applicable to overhead lines where collapse of the line would cause negligible danger to life and property and alternative arrangements can  be provided if loss of support services occurs. (Higher security distribution lines and normal transmission lines)

8326-PDR - 24/07/2008 14:25:50

70

DRAFT ONLY

Level III

DRAFT ONLY

Applicable to overhead lines where collapse of the line would cause unacceptable danger to life or significant economic loss to the community and sever vital post disaster services. (Higher security transmission lines)

6.2.3 Reliability load multiplier and security requirements

Reliability load multipliers for an expected design working life and security levels are  provided in Table 6.1. The design loads for an overhead line shall be based on 50-year return period wind speeds as defined in AS/NZ 1170.2. The calculated loads shall be then multiplied by an appropriate reliability load multiplier based on the required security level and reliability load multiplier as selected from Table 6.1 TABLE 6.1 RELIABILITY MULTIPLIER FOR DESIGN WORKING LIFE AND LINE SECURITY LEVELS Minimum reliability load multiplier  M rel Line security level Design working life

Level I

Level II

Level III

Temporary construction and construction equipment, e.g. hurdles, scaffolding and temporary line diversions with design life of less than 6 months

0.67

0.67

0.77

< 5 years

0.77

0.9

1.0

25 years

0.9

1.0

1.2

50 years

1.0

1.2

1.4

100 years

1.2

1.4

1.4

 NOTE S: 1

When selecting the appropriate security level, additional factors such as the line length, number of circuits and proximity to other lines or infrastructure should be considered.

2

For special exposed locations such as long span water or valley crossings, or difficult to access locations (where time and cost to restore the construction can be high), a higher security level may  be ado pte d for a p articu lar struct ure or short sec tio ns of the lin e.

6.2.4 Security requirements

Security requirements shall be provided in all designs to prevent or limit progressive or cascading structure failures in the event of collapse or failure of a support structure resulting from any external cause. In general longitudinal design loads relevant to withholding loads for broken or terminated  phase conductor are provided to meet t his requirement. On distribution overhead pole lines, pole deflection combined with partial foundation failure may provide adequate containment. 6.2.5 Safety requirements during construction and maintenance

Safety requirements are intended to ensure that construction and maintenance operations do not pose safety hazards to people. The safety requirements in this Standard consist of special loads, as defined in Clauses 6.2.6 and 7.2.6 for which line components have to be designed.

8326-PDR - 24/07/2008 14:25:50

71

DRAFT ONLY

DRAFT ONLY

6.2.6 Additional considerations 6.2.6.1 Dynamic load effects—Seism ic loads

In general, transmission/distribution lines are largely unresponsive to the dynamic forces associated with seismic activity, however, due consideration should be given to structures where the normal dynamic response is altered; e.g. ancillary devices such as pole mounted transformers, etc. 6.2.6.2 Environmental considerations

Consideration shall be given to any environmental and legal requirements that may exist. Safety of human beings and protection of wild life and livestock, for example birds, cattle, etc. shall be properly considered. This may require the installation of special deterrent devices for birds and reptiles: aerial markers for aircraft and ground based vehicle warning and deflection devices. Structure loading for such devices shall be considered in design. Vehicle impact, and the effects of falling trees and airborne vegetation during high winds are accidental loads beyond the scope of this Standard. Their effects can however be mitigated by care in placement of support structures and the ongoing management of the overhead line corridor. 6.2.7 Design working life

The design working life is the assumed period for which an overhead line could be expected to be used for its intended purpose with anticipated maintenance but without substantial repair being necessary.  NOT E: The operating lif e of an overhead lin e can be normally be expected be in the range of 30 to 80 years, depending on a number of factors including the level of preventative and corrective maintenance carried out on the total asset during its life.

Appendix D provides guidance on the service life of overhead lines. 6.2.8 Durability

The durability of an overhead line support or part of it in its environmental exposure shall  be such that it remains fit for use during the design working life given an appropriate level of maintenance. The environmental, atmospheric and climatic conditions shall be appraised at the design stage to assess their significance in relation to durability and to enable adequate provisions to be made for protection of the materials for the target design life. 6.3 LIMIT STATES 6.3.1 General

The structural design methods provided by this Standard are based on ‘limit state’ concepts. Structures and components shall be designed using a reliability-based (risk of failure) approach, and the selection of load factors, in particular for weather related loads, and component strength factors are based on achieving an acceptable risk of failure for the loading condition being considered.

8326-PDR - 24/07/2008 14:25:50

72

DRAFT ONLY

DRAFT ONLY

The performance of the structural system can be evaluated for different circumstances, known as limit states with the following general limit state design equation for overhead lines: φ  Rn  > effect of loads (

γx W n + Σγ x X )

where  X 

=

the applied loads pertinent to each loading condition

γx

=

are load factors which take into account variability of loads, importance of structure, stringing, maintenance and safety considerations etc.

=

wind load based on a 50 year return period scaled by the appropriate reliability load factor or specified design wind pressure

φ 

=

the strength factor which takes into account variability of material, workmanship etc.

 Rn

=

the nominal strength of the component

W n

Limit states are states beyond which the overhead line no longer satisfies the design  performance requirements. All support structures shall be designed for both ultimate limit states and serviceability limit states. 6.3.2 Strength limit states

Ultimate strength limit states are those associated with collapse or with other similar forms of structural failure due to excessive deformation, loss of stability, overturning, rupture,  buckling, or localized failure. Damage states prior to structural collapse, such as plastic deformation or local buckling of redundant structural elements, which, for simplicity, are considered in place of the structural collapse itself, are also to be treated as ultimate limit states. Ultimate strength limit states concern— (a)

the reliability and security of supports, foundations, conductors and equipment; and

(b)

the safety of people.

Structural elements that fail essentially in buckling, or brittle fracture with little warning of impending failure, should be designed to withstand the design load without permanent distortion. Structural elements that fail essentially by ductile yielding may, in accordance with the appropriate standard, at the discretion of the designer, be allowed to exhibit elastic-plastic yielding prior to failure, in accordance with the relevant Standard. 6.3.3 Serviceability limit states

Serviceability limit states shall provide for the following defined conditions beyond which specified service requirements for an overhead line are no longer met: (a)

Mechanical and structural functioning of supports, foundations, conductors and equipment.

(b)

Maintaining prescribed electrical clearances.

In addition, serviceability limit states which require consideration include— (i)

deformations and displacements which affect the appearance or effective use of the support;

(ii)

a reduction of critical electrical clearances;

8326-PDR - 24/07/2008 14:25:50

73

DRAFT ONLY

DRAFT ONLY

(iii)

vibrations which cause damage to conductors, supports or equipment or which limit their functional effectiveness;

(iv)

damage (including cracking) which is likely to affect the durability or the function of the supports; and

(v)

conductors, insulators and line accessories adversely affected.

6.3.4 Limit state design

Limit state design shall be carried out by— (a)

setting up structural and load models for the relevant ultimate and serviceability limit states to be considered in the various design situations and load cases; and

(b)

verifying that the limit states are not exceeded when design values for actions, material properties and geometrical data are used in the models.

Design values are generally obtained by using characteristic or combination values (as defined in this Standard) in conjunction with strength and load factors as defined in this Standard and other Australian and New Zealand Standards. 6.3.4.2 Strength factors ( φ ) 

Table 6.5 provides strength factors ( φ ) which takes into account variability of material and workmanship for structural components used in overhead lines. These φ   values reflect accepted industry practice. TABLE 6.5 STRENGTH FACTOR Part of overhead line ( Rn )

Lattice steel towers

Component

FOR COMPONENT STRENGTH Limit state

Steel angle member elements

Strength

Strength factor

Refer Appendix G

ASCE 10-97 AS/NZS 3995

Refer Appendix K

AS/NZS 4600 ASCE 48-05 EN 50341

Tubular steel structures Tubular structure Fasteners

Reinforced or  pre stressed con cre te structures and members. Design based on design Standards

Bolts nuts and washers

Poles Cross arms

≤0.9 Strength

Strength

Reference Standard

Unless otherwise specified

AS4100 AS/NZS 1559 ASCE 10-97

Refer Appendix I

AS 3600 AS/NZS 4065  NZS 310 1 AS/NZS 4676

Concrete or steel structures and members. Design based primarily on testing, e.g. concrete  pol es (see N ote 2)

Poles Cross arms

Strength

0.9 (max)

AS 3600 AS/NZS 4065  NZS 310 1 AS/NZS 4676

Wood structures, poles or members (not  pre served by ful l l eng th treatment) (see Note 3 and Appendix F)

Poles Cross arms

Strength

0.3 to 0.9

AS 2209 AS 1720

( continued )

8326-PDR - 24/07/2008 14:25:50

74

DRAFT ONLY

DRAFT ONLY

TABLE 6.5 (continued ) Part of overhead line ( Rn )

Component

Limit state

Strength factor

Reference Standard

Wood structures, poles or members (not  pre served by full l eng th treatment)

Poles Cross arms

Serviceability

0.3

AS 2209 AS1720

Wood structures, poles or members (preserved  by ful l l eng th treatmen t) (see Note 3 and Appendix F)

Poles Cross arms

Strength

0.6 to 0.8

AS 2209 AS 1720

Wood structures, poles or members (preserved  by ful l l eng th treatm ent)

Poles Cross arms

Serviceability

0.4 (see Note 3)

AS 2209 AS 1720

Poles Cross arms

Strength

0.9

Fittings and pins, forged or fabricated

Strength

0.8

AS 1154

Fittings, cast

Strength

0.7

AS 1154

Porcelain or glass cap and pin string insulator units

Strength

0.8 (electro-mechanical strength)

AS 3608

Porcelain or glass insulators other than cap and pin string insulator units

Strength

0.8

AS 3608

Strength

0.5 (one minute mechanical strength)

AS 4435.1

Synthetic composite line  post i nsu lat ors (See Note 2)

Strength

0.9 (maximum design cantilever load)

AS 4435.4

Other synthetic composite insulators

Strength

Subject to further research

Foundations relying on strength of soil (with conventional soil testing)

Strength

0.4 to 0.7 Refer Appendix L

AS 2159

Foundations relying on strength of soil based on empirical assessment

Strength

0.4 to 0.6 Refer Appendix L

AS 2159 and AS1726

Foundations relying on weight of soil

Strength

0.8 Refer Appendix L

Conductors

Strength

0.7

Conductors

Serviceability

Refer Section 4

Strength

0.7

Fibre reinforced composite poles. Design  based pri marily on testing (see Note 7 and Appendix J)

Synthetic composite suspension or strain insulators (See Note 2)

Stay or guy and termination (cable) members

8326-PDR - 24/07/2008 14:25:50

AS 1222 AS 3995 ASCE 10-97

DRAFT ONLY

75

DRAFT ONLY

 NOTE S T O TABLE 6.5 1

Design Standards based on limit state formats (usually) take into account exclusion limits and the coefficient of variation of structural members. When the φ   factor is part of the code’s design equations it should not be applied again.

2

Where design Standards are used that do not employ similar strength factors, designers should decide where further application of relevant factors from the above table is appropriate to achieve the desired reliability level. If sufficient material or product data is available to support ±   variation of these tabulated values then alternative values may be adopted.

3

For laminated timber cross-arms, refer to AS/NZS 1328.

4

Where there are sufficient material property tests of components to provide reasonable statistical data, the φ   f actor may be based on statistical analysis. All data from testing of similar designs should be included in the statistical analysis.

5

Where component manufacturers have included appropriate strength factors in their designs, the φ   factor should not be applied again.

6

Where the design of wood stru ctures is based on AS 1720.1, the stren gth factor may be b ased on the requirements of that code, however the following should also be taken into account: (a) The recommended conductor wind loads in this document incorporate a span reduction factor that has the effect of increasing the duration of the wind load being considered. (b) Tests of poles and cross-arms that have been in service for long periods show a wide variation in the ratio of calculated to actual strength. Due to this uncertainty it is recommended that a strength factor at the lower end of the range be used in the absence of specific data suggesting high confidence

7

Composite fibre poles are highly flexible and serviceability limit due to deflection at working load may be limiting factor.

6.4 ACTIONS 6.4.1 Principal classifications

An action  F , can be either— (a)

a direct action, i.e. force (load) applied to the supports, conductors, foundations, and other line components; or

(b)

an indirect action, i.e. an imposed or constrained deformation, caused, for example,  by temperature changes, ground water variation or uneven settle ment .

Actions are classified by their variation in time— (i)

 Permanent action (G), i.e. self-weight of supports including foundations, fittings and  fixed equipment 

Self-weight of conductors and the effects of the applicable conductor tension at the reference temperature, as well as uneven settlements of supports are regarded as  permanent actions.  NOT E: The vertical reaction fro m self-w eight of the conductor at the support (in oth er wor ds the weight span) is affected by deviations from the reference state of the conductor tension due to conductor creep temperature variations and wind action. Where critical for the design, especially if no other climatic conditions are present, the uncertainty in such a variation, unfavourable or favourable, should be considered by use of a factor on the self-weight (or on the weight span).

(ii)

 Imposed actions (Q), i.e. wind loads , ice loads or other imposed loads

Wind loads and ice loads as well as applicable temperatures are climatic conditions which can be assessed by probabilistic methods (reliability concept) or on a deterministic basis. Conductor tension effects due to wind and ice and temperature deviations from the reference temperature are variable actions.

8326-PDR - 24/07/2008 14:25:50

76

DRAFT ONLY

DRAFT ONLY

Imposed loads arising from conductor stringing, climbing on the structures, etc. are assessed on a deterministic basis and refer to the safety aspect. (iii)  Accidental actions (A), i.e. failure containment loads, flood debris loads, aval anches, etc. These relate to the security aspect of the overhead line Exceptional ice loads in alpine/sub-alpine regions including unbalanced ice loads can  be treated as accidental actions by t heir nature and/or the structural response— (A)

static actions, which do not cause significant acceleration of the components or elements; and

(B)

dynamic actions, which cause significant acceleration of the components or elements

It is usually sufficient to consider the equivalent static effect of quasi-static actions, such as wind loads, in the design of overhead line supports (including foundations). Special attention should be paid to extraordinarily high and/or slender supports. 6.5 MATERIAL PROPERTIES

As general principle, a material property is represented by a characteristic value, which corresponds to that value of the material property having a prescribed probability of not  being attained in a hypothetical unlimited test series. It generally corresponds to a specified exclusion limit of the assumed statistical distribution of that property of the material. These values are used to determine the nominal strengths of the components ( R n) values discussed in Clause 6.3.1. A material property value shall normally be determined from standardized tests performed under specified conditions. A conversion factor shall be applied where it is necessary to convert the test results into values, which can be assumed to represent the behaviour of the material in the overhead line.  NOT E: Material properties specif ied in oth er Australian/New Zealand Standards and in particular standards referred to herein may generally be applied if not determined otherwise in this Standard.

6.6 MODELLING FOR STRUCTURAL ANALYSIS AND RESISTANCE 6.6.1 General

Calculations shall be performed using appropriate design models for the type of structure  being analysed. In the case of three dimensional space frames, such as lattice steel towers, it is normal  practice to create geometrical models for the full range of heights and base leg combinations. These models normally simulate a fixed or pinned nodal base and should include the effects of settlement of foundations, and any vertical eccentricities that may be applied. Full scale load testing may be applied to verify experimentally, the structural capacity, or assumed force distribution and adequacy of structural element connectivity for a given structural geometry in the case of space frame structures; and to verify flexural bending, axial load and shear capacity strengths for pole elements. (Refer also to Clause 8.5). It should be understood that such tests constitute a sample test for a particular height tower or length of a particular batch of pole. Different configuration of towers and poles may not necessarily perform to the same characteristics.

8326-PDR - 24/07/2008 14:25:50

77

DRAFT ONLY

DRAFT ONLY

6.6.2 Interactions between support foundations and soil

Special attention shall be paid to the interaction of the following: (a)

Loads deriving from the support.

(b)

Loads resulting from active soil pressures and the permanent weight of foundation and soil.

(c)

Buoyancy effects of ground water on soil and foundation.

These, together with the reaction forces of the soil strata shall be taken into account in the calculation of the support foundations. In the limit state the following criteria shall be taken into consideration: (i)

Acceptable/unaccepta ble settlement.

settlement

of

the

foundation

(ii)

Imposed deformations on the support or support members.

(iii)

Inclinations of the support.

(iv)

Load duration.

including

differential

Provisions regarding the interaction of loads and recommendations on limit state criteria are given in Sections 7 and 8.

8326-PDR - 24/07/2008 14:25:50

78

DRAFT ONLY

S E C T I O N

7

A C T I O N

DRAFT ONLY

O N

L I N E S

7.1 INTRODUCTION

The following clauses are based on well established principles supported by experience and long-term operation of overhead lines within Australia and New Zealand. 7.2 ACTIONS, GENERAL APPROACH 7.2.1 Permanent loads

Self-weight of structures, insulator sets, other fixed equipment and conductors resulting from the adjacent spans act as permanent loads. Aircraft warning spheres and similar elements are to be considered as permanent dead loads. These vertical loads are designated as Gs  and G c Gs   represents the vertical loads on poles, towers, foundations, crossarms, insulators and fittings and shall be the vertical force due to their own mass plus the mass of all ancillaries and attachments. Gc  represents the vertical loads of conductors/cables and attachments such as marker balls, spacers and dampers and forms the design weight span.

These are loads on the structural system with a conductor temperature equivalent to the mean of the winter season temperatures with negligible wind loads, i.e. in still air. This temperature generally varies between 0°C and +15°C depending on the location within Australia and New Zealand. In tropical areas, while there may be only small seasonal variations in temperatures, the daily variation may be appreciable between night and day and the mean of the night temperature may be more suitable. This condition may be the limiting serviceability condition on conductors and insulators and may set the lower limit on cracking criteria for pre-stressed concrete poles. 7.2.2 Imposed loads 7.2.2.1 Wind loads

Wind loadings shall be applied to all elements of an overhead line as determined in accordance with Appendix B Consideration shall be given to the design of structures for wind attack for a range of directions and shall include transverse, longitudinal and oblique directions. 7.2.3 Snow and ice loads ( S )

Snow and ice loadings shall be applied to all elements of an overhead line in appropriate regions, as determined in accordance with Appendix FF. 7.2.4 Conductor tensions 7.2.4.1   General

The horizontal component of the conductor tensions  F t  used for design shall be based on the lowest temperature likely to coexist with the design wind pressure as provided in the following conditions. Unless otherwise required by the climatic zone under consideration and proven utility practice, a temperature of 15°C shall be used. 7.2.4.2 Maximum wind condition Ft w

 Ft w is the horizontal component of the conductor tensions int eh direction of the line when subject to wind

8326-PDR - 24/07/2008 14:25:50

79

DRAFT ONLY

DRAFT ONLY

Due to the spatial variation of wind velocities within a wind storm, an extreme 3 s peak wind gust, will not affect all spans between tension structures simultaneously. 7.2.4.3 Maintenance condition Ft m

 Ft m is the horizontal component of the conductor tensions in the direction of the line when subject got maintenance conditions.

This condition provides the maximum conductor tension under which it can be reasonably expected for workmen to be expected to work transferring loads of conductors during construction or maintenance activities. This tension is calculated based on a maximum transverse wind pressure of 100 Pa. 7.2.4.4 Everyday condition Ft e

 Ft e  is the horizontal component of the conductor tension in the direction of the line under no wind.

This condition provides the nominal tension that can be expected to occur at the everyday temperature ( T e) for the line location. This tension is calculated in still air and an average ambient temperature for the region. 7.2.5 Coincident temperatures

Temperature effects for the following conditions shall be considered in the design of overhead lines: (a)

T m —A minimum temperature condition to be considered with no other climatic action for the particular regional location, if relevant. Particular attention is to be given for short spans cases and minimum overnight winter temperatures

(b)

T e —The everyday temperature ass umed for the ultimate wind speed condition.

(c)

T w —A reduced wind speed combined with a mini mum temperature condition to be considered, if relevant. Particular attention is to be given in sub-alpine and alpine regions.

(d)

T i —A temperature to be assumed with icing. For both of the main types of icing a temperature of 0°C may be used, if not otherwise specified. A lower temperature should be taken into account in regions where the temperature often drops significantly after a snowfall.

(e)

T c —A maximum conductor temperature to be ass umed for the calculation of electrica l clearances.

7.2.6 Construction and maintenance loads 7.2.6.1   General

The supports shall be able to withstand all construction and maintenance loads, Q m, which are likely to be imposed on them with an appropriate load factor, taking into account working procedures, temporary guying, lifting arrangement, etc. Overstressing of the support should be prevented by specification of allowable procedures and/or load capacities. The conditions should be based on the worst weather conditions (wind and temperature) under which maintenance will be carried out. The limiting design wind pressure for general maintenance work shall be 100 Pa. The designer needs to consider all potential aspects that may arise from maintenance practices affecting Gc, e.g. lowering the conductor at the adjacent structure may result in the doubling of the weight span on the structure under consideration.

8326-PDR - 24/07/2008 14:25:50

80

DRAFT ONLY

DRAFT ONLY

7.2.6.2 Loads related to line maintenance/construction personnel

The vertical maintenance load to be applied to a structure for a single person shall be 1.0 kN acting together with the permanent loads and other imposed loads resulting from the maintenance work method. For lattice steel structures, these forces shall act at any point of structural elements. For pole type structures these forces shall act at any point on the superstructure to which it could be reasonably expected that construction or maintenance loading may be applied. In particular the following minimum loading allowances shall be made: (a)

(b)

Transmission structures ( including lattice steel towers and steel and concrete  poles)— (i)

 Earthwire peaks  —provision for two persons plus 100 kg of tools and equipment

(ii)

Crossarms  —provision for 4 persons plus 500 kg of tools and e quipment

Distribution structures (including wood and concrete pole structure if climbing  provision is required)— (i)

 Pole head and crossarm  —provision for two persons plus 100 kg of tools and equipment.

(ii)

 Pole —component load of l adder with one person cli mbing

In addition, provision is to be considered for all structures required to be climbed for the  provision of anchorage from any structural node point for the attachment of fall arrest system anchorage with a load capacity of 21 kN. Under this condition structural elements must be able to restrain this load in an elastic or plastic deformed state without release of the attached tackle system. Where walkways or working platforms are installed, they shall be designed for the maximum loads required under the relevant code but provide not less than the provision for two men at any point; i.e. 2.8 kN point load. For all structural elements that can be climbed and are inclined with an angle less than 30 to the horizontal, a characteristic load of 1.4 kN acting vertically in the centre of the member shall be assumed without any other co-existent loads. Climbing steps (of any kind) shall be capable of supporting a concentrated load of 1.4 kN acting vertically at a position 50 mm horizontally from the underside of the extended step  bolt head or s tep iron end sli p restraint. 7.2.7 Security loads

Security loads in this Standard are specified to give minimum requirements on the torsional and longitudinal resistance of the supports by defining failure containment loads. The loads considered are the one-sided release of static tension in a conductor and unbalanced longitudinal loads. 7.2.7.1 Torsional loads

Where temporary termination or single termination conditions can be expected to occur during the service life of the overhead line, a loading assumption shall be applied to the design. Loads and conductor tensions shall be calculated at the normal ambient reference temperature and serviceability maintenance wind loading. 7.2.7.2 Longitudinal conductor loads

Longitudinal loads from terminated conductors equivalent to a particular load condition shall be applied simultaneously at all attachment points. 8326-PDR - 24/07/2008 14:25:50

81

DRAFT ONLY

DRAFT ONLY

Where double circuit towers are designed to be strung single circuit only, provision shall be made for the termination of any one circuit as well as all circuits. For maintenance load cases the longitudinal conductor loads shall be calculated at the normal ambient reference temperature with a serviceability maintenance wind load. Consideration shall be given to differential longitudinal loads on the structure. These are caused by the spatial variation in wind velocities across adjacent spans on either side of a support structure. Where adjacent spans have considerably different span lengths (generally 3:1 or greater ) the effects of winds and/or temperature change will produce differential tensions across the supporting structure. If the insulator type does not allow equalization of conductor tensions across the structures in these situations, allowance for differential conductor tension loads shall be provided in designs. 7.2.7.3 Failure containment loads F  b

The loads on a structure arising from the failure of an adjacent structure are unpredictable. Consequently, the design approaches to failure containment are largely based on empirical observations and on reducing the effects of longitudinal loads. If the initial (primary) failure is caused by extreme winds, the structures adjacent to the collapsing structure may  be subjec ted to both longitudinal loads and high winds. In the case of direct buried pole type structures, sufficient rotational release from applied torsional loads, and translational deformation of the supporting soil can occur in most cases at the structure directly impacted by overload conditions; such that the load impacts are dissipated and contained within 1 or 2 structures. The possibility of a structure failure initiating conductor breakages should also be considered. This is particularly relevant to AAC and AAAC type conductors when used on high voltage transmission where conductors may be severed by falling sharp edged metal structure components. For the failure containment condition, supports shall be designed for the equivalent longitudinal loads resulting from conductors on the structure being broken with a minimum coincident wind pressure of 0.25 times the ultimate design wind. The unbalance tension ( F  b ) resulting from these broken conductors is the residual static load (RSL) in the phase conductor after severance of a conductor, or the collapse of a conductor support system. Intact conductor tensions ( F t) shall be used for all other conductors.  F  b   and  F t   tensions for conductors shall be based on the temperature corresponding to the everyday load condition with a minimum nominal wind pressure of 0.25 times the ultimate design wind pressure.

In distribution systems using pin or post insulators with wire ties or equivalent fixing, and relatively flexible structures and their foundations, it is not necessary to design suspension (tangent) structures for the RSL . Tension and terminal distribution pole structures however, shall be designed for the RSL. In absence of a more detailed assessment an RSL factor of 0.70 should be adopted for phase conductors supported by suspension strings. The RSL load applies to all sub conductors in a  phase.  NOTE: While the equivalent span may be used to calculate tensions in a section of lin e, designers should be aware that if the span lengths in a line section have considerable variation, a RSL based on the equivalent span may underestimate broken conductor tensions for some spans.

8326-PDR - 24/07/2008 14:25:50

82

DRAFT ONLY

DRAFT ONLY

7.2.8 Forces due to short-circuit currents

Consideration should be given to the effects of the forces imposed on those overhead lines forming part of an overhead line system with very high short-circuit characteristics, typically within 1 span of a substation. These fault currents generally occur for very short durations. Appendix C provides guidance on forces caused by short-circuit currents. 7.2.9 Other special forces 7.2.9.1 Avalanches and creeping snow loads

When overhead lines are to be routed in or through mountainous regions where they may be exposed to avalanches or creeping snow on hill slopes consideration shall be given to the  possible additional loads which may act on the supports, foundations and/or conductors. Guidance information on this subject is given in Appendix C. 7.2.9.2   Earthquakes

When overhead lines are to be constructed in seismically active regions, consideration shall  be given to forces on lines due to earthquakes and/or seismic tremors. Guidance information on this subject is given in Appendix C. 7.3 LOAD CASES 7.3.1 General

In the design of an overhead line, a range of loading conditions shall be considered that will  provide due consideration for all possible service conditions that the line may be subjected to through out its service life.

8326-PDR - 24/07/2008 14:25:50

83

DRAFT ONLY

DRAFT ONLY

7.3.1.1 Limit states loading conditions TABLE 7.3 LOAD COMBINATIONS AND LOAD FACTORS Loading condition

Maximum wind Maximum wind and uplift

Load factor and application

W n

S

1.0 (see  Not e 2 )

Gs

1.1

Gc

 Ft m

1.25

Everyday condition (sustained loads) 1.0

1.25

1.1

1.25

1.25 1.25

1.0

Failure containment

1.0

1.1

1.25

Serviceability—  deflection limit

1.0

1.1

1.1

Serviceability—  damage limit

1.0

1.1

1.1

Maintenance

1.0

1.1

1.5

Seismic

1.3 (see  Note 3 )

 Fb

Q

1.25

0.9

Snow and ice

 Ft e

1.25

+1.0 or − 0.5 (see Note 1)

1.0

 Ft w

1.1

1.25 1.1

1.0 1.5

1.3

2.0 1.25

 NOTE S: 1

Adequate allowance shall be made for differential loadings that can occur between adjoining spans at a structure, particularly in mountainous terrain to allow for uplift loads under normal service conditions including low temperature effects.

2

Wind loads from opposite directions shall be considered.

3

Due considerations for vertical load effects, range from 0.8 to 1.3.

Ultimate and derviceability limit state loads are to be considered in determining structure deflections and conductor, insulator and fitting strength ratings. The serviceability deflection limit loading condition is to be used for setting deflection limits of structures, such as poles, in situations where the electrical clearances will not be infringed. This condition may also be used as an upper limit for cracking criteria in prestressed concrete poles. The serviceability damage limit loading condition shall be used where the damage is of a ductile nature. 7.3.2 Loading combinations 7.3.2.1   General

All overhead line support structures shall be designed for loading conditions that reflect the construction, operational service and maintenance conditions to ensure reliability of supply and the safety of personnel constructing and maintaining the line and the public. The following provisions shall be made in the application of the loading conditions summarized in Clause 7.3.1.1.

8326-PDR - 24/07/2008 14:25:50

84

DRAFT ONLY

DRAFT ONLY

7.3.2.2 Loading combinations for all supports

(a)

Synoptic and downdraft wind (i)

Transverse direction Apply full transverse wind load on the conductors, insulators and fittings and support, together with deviation loads at maximum wind tension and all relevant vertical loads.

(ii)

Longitudinal direction Apply full longitudinal wind load on the support and insulators and fittings together with every day deviation loads and all relevant vertical loads.

(iii)

Oblique (or yawed) wind—Refer Appendix B) Apply full oblique wind at an angle to the transverse axis on the conductors. insulators, fittings and support, together with deviation loads at maximum wind tension and all relevant vertical loads.

(b)

Tornado wind (applicable to high security lines—Refer Appendix B (i)

Apply maximum wind load to the structure only to act from any direction, together with every day deviation loads and all relevant vertical loads.

(ii)

Torsional (for wide transverse structures, e.g. horizontal single circuit towers) Apply maximum wind torsion with rotation about the support centre. Each tower body face is subjected to in-plane wind, and each crossarm face to  projected perpendicular wind in a consistent rotational direction, together with every day deviation loads and all relevant vertical loads.

(c)

Failure containment Apply broken conductor loadings to the following conductor attachment positions with the remaining conductors intact. This out of balance load is to be applied together with 0.25 times the full transverse wind load on the conductors, insulators and fittings and support, and deviation loads at the corresponding wind conductor tension and all relevant vertical loads. For a single circuit line the number of conductors to be considered is one phase (with allowance for bundles) or the earthwire. For a double circuit line, the number of conductors to be considered is the worst loading combination of either any two phases, or any phase and the earthwire. For structure types having limited longitudinal strength containment methods need to be applied (e.g. use of guys).

alternative

failure

In addition for termination structures apply longitudinal loads for the termination of one or two earthwires together with any one or all circuits. (d)

Maintenance and construction Apply 100 Pa wind l oadings, every day deviation loads, and vertical l oads from conductors, insulators and fittings. In addition allowance is to be made for men and equipment as provided in Claus e 7.2.6.2, and for the increase in vertical and longitudinal load from lowering conductors.

In addition for deviation and strain structures, apply longitudinal loads for the termination of one earthwire any one circuit with no other phase conductors attached.

8326-PDR - 24/07/2008 14:25:50

85

DRAFT ONLY

S E C T I O N

8

DRAFT ONLY

S U P P O R T S

8.1 INITIAL DESIGN CONSIDERATIONS

Designs of overhead line structures shall be carried out in accordance with this Standard and referenced Standards Australian/Standards New Zealand, IEC and ASCE documents. Materials used in the fabrication of overhead line supports should comply with the requirements of the relevant Australian and New Zealand material Standard or equivalent International Standards. 8.2 MATERIALS AND DESIGN 8.2.1 Lattice steel towers and guyed masts.

Lattice st eel tower designs shall be carried out in accordance with AS 3995, AS 4100, ASCE 10-97and Appendix G. 8.2.2 Steel poles

Steel poles shall be designed in accordance with AS/NZS 4677, AS 4600, AS 4100, ASCE 48-05 and Appendix K. 8.2.3 Concrete poles

Concrete poles shall be designed in accordance with the requirements of AS/ NZS 3600, AS/NZS 4065 and Appendix I. 8.2.4 Timber poles

Timber poles shall be designed in accordance with the requirements of AS 1720.1, AS/NZS 1328 or AS 2209 and Appendix F. 8.2.5 Other materials

For all other materials, the material characteristics should be in accordance with the  performance requirements of the finished product and shall also meet the functional requirements regarding both strength and serviceability (deformation, durability and aesthetics) and be in accordance with the relevant Australian, New Zealand, IEC or equivalent International Standard. Where composite materials are used in pole elements, such as fibre reinforced resin or  polymer, fibre reinforced concrete, using fibreglass, carbon or ste el microfilament fibres; the design and performance characteristics of the pole element shall be supported by load tests. 8.2.6 Guyed structures 8.2.6.1   General

A guyed support can be any type of structure that is supported by guy wires for stability . Various types of configurations exist such as V-tower, portal, column, catenary, guyed timber poles, double guyed timber leg structures, multi-level guyed tubular leg structures, etc. The following additional requirements shall apply. 8.2.6.2 Second order analysis

In larger more complex guyed structures where a second order analysis is justified the following aspects shall be taken into account: (a)

An initial out of straightness shall be assumed for sections hinged at both ends (tower legs), a normal design value of L/1000 shall be considered. 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY

(b)

86

DRAFT ONLY

The slackening of one or more guys at different loading conditions shall be taken into consideration.

8.2.6.3 Design details for guys

The characteristic resistance of the guy shall be the nominal value for ultimate breaking strength specified in appropriate standards with due consideration of the method of termination. The effective elastic modulus of the guy determined from a Standard, manufacturer or test may be used in analysis. For guyed tower structures, galvanised steel wire strands or steel ropes with steel core shall  be used for the guys , and shall be equipped wit h devices for retightening during the service life of the structure. The connection between the guy rope and the anchor device shall be readily accessible, and the connections and tightening devices shall be secured against loosening in service. On guyed tower structures, the guys shall be pre-tensioned to an appropriate force (5-10% CBL) after the erection of the structure, in order to reduce the deformation at extreme loads. The angle or termination structures shall be vertical after the stringing of the conductors at the every day temperature. Special attention shall be paid to preventing possible vibration, galloping and fluttering  phenomena if this is a known characteristic of the region. Regions with constant low velocity prevailing winds and low temperatures need investigation. Where cast steel sockets or cast wedge sockets are used in the guy terminations, freedom from defects in the casting should be ensured by an acceptable non-destructive test or manufacturer's certificate. For a multi-level guyed support, instructions for the erection work are needed because the structure is sensitive to the pre-tensioning of the guys. Due care shall be taken for protection of the guy in populated areas for possible galvanic corrosion and flashover. Insulation of the guy above a point accessible from the ground by the public should be  provided if a risk of failure of the energized conductors may exist, such that a guy wire could become energized. Where no insulation in guy wires is used, appropriate step and touch potential mitigating systems shall be adopted. In order to minimize the possibility of aerodynamic guy vibrations in stabilizing guy wires the pretension should be less than 10%. For permanently loaded structural load carrying guy wires this requirement is not applicable, however if service experience indicates that aerodynamic vibrations are significant, then vibration damping protection should be considered. 8.3 CORROSION PROTECTION AND FINISHES 8.3.1 General

Metallic components of supports shall be protected against corrosion in order to meet their design service life, taking into account the planned maintenance regime. The following clauses set minimum requirements that should be provided. Refer to AS/NZS 2312. 8.3.2 Galvanizing

All galvanized steel material and fastenings used in support structures shall be hot-dip galvanized and tested in accordance wit h AS/NZS 4680 or equi valent Internati onal Standard unless an alternative anti-corrosion coating system is utilized. 8326-PDR - 24/07/2008 14:25:50

87

DRAFT ONLY

DRAFT ONLY

8.3.3 Metal spraying

Where required by design considerations or where steel materials are too large or difficult to galvanize, they may be protected against corrosion by thermal spraying a zinc or zinc/aluminum coating over the base metal, performed in accordance with ISO 14713 to  provide zinc deposi t thickness not les s than 200 μm. When this system is used, the inside surface of hollow sections shall also be protected against corrosion. 8.3.4 Paint over galvanizing (duplex system )

When an enhanced coloured cosmetic surface treatment paint coating is to be applied after hot-dip galvanizing of steel structures, this coating shall be applied in accordance with a coating manufacturers recommendations. 8.3.5 Use of weather-resistant steels

The use of weather resistance steels requires special design considerations and full-scale experience. They should be used with caution in environmentally sensitive areas or in areas where excessive corrosion is likely. 8.4 MAINTENANCE FACILITIES 8.4.1 Climbing and working at heights

Where climbing and working at heights from the structure is required, by authorized  personnel, suitable facilities shall be incorporated in the designs of supports. Reference should be made to Appendix M for guidance on industry standards. 8.4.2 Maintainability

In addition to climbing attachments, the provision of rigging and load transfer attachments, holes or fittings for the installation and use of maintenance equipment shall be provided in designs. Reference should be made to Appendix M for guidance on industry standards. 8.4.3 Safety requirements

Provision shall be made on all climbable structures for the fixing of signage and devices to ensure the protection of the public from hazards associated with access to electrical works, and to provide public awareness of operational safety issues. This may include— (a)

 provis ion of safety information for the general public (e.g. warning signs, telephone number for emergency contact);

(b)

 prevention of unauthorized cli mbing;

(c)

 provis ion of aids to authorized personnel to enable them to correctly identify energized and de-energized conductors (e.g. circuit identification markings);

(d)

 provis ion for bonding of e arthwire and earthing of the support structure; and

(e)

equipotental bonding.

8.5 LOADING TESTS

Full scale loading tests on overhead lines supports, when carried out, shall be generally in accordance with IEC 60652 and the following provisions.

8326-PDR - 24/07/2008 14:25:50

88

DRAFT ONLY

DRAFT ONLY

8.5.1 Tower structures

Full scale load testing may be carried out to verify experimentally, the force distribution and efficiency of structural element connectivity for a given structural geometry, and for confirming force distribution in redundant bracing elements. It should be understood that such tests are a sample test for a particular height tower. Taller or shorter towers of the same structure type, may not have identical performance characteristics. 8.5.2 Pole type structures

Load testing of prototype poles may be used as an acceptable alternative to strength calculations to verify flexural bending and shear capacity strengths for pole type elements. Routine sample poles shall be tested to determine whether structurally similar poles are deemed to comply with the requirements for strength and serviceability of this Standard. Deflection characteristics of repetitive sample pole tests compared to prototype test deflections provides a useful tool for monitoring quality of pole product manufacture. 8.5.2.1 Test specimens

Specimen poles for prototype testing shall be manufactured, as a group for a normal  production run, in sufficient numbers so that each required tes t can be carried out on a pole that is unaffected by any previous testing. However, serviceability and strength testing may  be carried out sequentially, in that order, on the same pole. The manufacture of the test specimens shall take into account the intended production  procedures and the quality of materials and workmanship to be used during normal  production. The specimens shall be chosen to represent poles of similar structural design and may include poles of different nominal sizes. 8.5.2.2 Test requirements

Test loads shall be determined to reflect as close as possible design loadings. Loading devices shall be properly calibrated and care exercised to ensure that no artificial restraints to pole deformations are imposed by the loading systems. Test loads shall be applied to the test specimen at a rate that is as uniform as practicable. Test loading and support conditions shall simulate the relevant design conditions as closely as is practicable. Test arrangements depend on whether the pole elements are tested horizontally or in a vertical mode. Performance indicators shall be measured and recorded, as a minimum, at least at the following times: (a)

Immediately before the application of the test load.

(b)

When the test load is reached.

(c)

Immediately after the entire test load has been removed.

8.5.2.3 Testing and acceptance

Test loads shall reproduce at critical cross-sections not less than the design action effect at the relevant limit state, multiplied by the appropriate factor given in Table 8.1, unless a reliability analysis shows that a smaller factor can be adopted safely. The value of the coefficient of variation to be used in Table 8.1 shall be obtained from historical test data for the material, manufacturing method and action effect being considered. In the absence of such data the values given in Table 8.2 may be adopted.

8326-PDR - 24/07/2008 14:25:50

89

DRAFT ONLY

DRAFT ONLY

Load testing of prototype poles may be used as an acceptable alternative to strength calculations to verify flexural bending and shear capacity strengths for pole types. Regular full scale load testing may be applied to verify the structural capacity, in the case of poles to verify strengths and quality of materials and workmanship. Where routine samples of poles are load tested to determine their quality and strength conformance, the lowest test result shall be divided by the COV factor in Table 8.1. All  previously tested poles of simila r types and len gths shall be included in the numbers of  poles tes ted to sel ect the correct COV factor. Deflection characterist ics of repetitive sample  pole tes ts compared to prototype test deflections provides a useful tool for moni toring quality of pole product manufacture. TABLE 8.1 VALUES OF MULTIPLIER FOR TEST LOAD FOR ESTIMATED COEFFICIENT OF VARIATION Coefficient of variation of structural characteristics

No. of similar units tested (1)

5%

10%

15%

20%

25%

30%

1

1.20

1.46

1.79

2.21

2.75

3.45

2

1.17

1.38

1.64

1.96

2.36

2.86

3

1.15

1.33

1.56

1.83

2.16

2.56

4

1.14

1.30

1.50

1.74

2.03

2.37

5

1.13

1.28

1.46

1.67

1.93

2.23

10

1.10

1.21

1.34

1.49

1.66

1.85

30

1.07

1.15

1.24

1.34

1.46

1.60

50

1.05

1.10

1.17

1.24

1.33

1.42

100

1.00

1.00

1.00

1.00

1.00

1.00

 NOTE S: 1

The cumulative number of tested poles having the same characteristics, not per batch.

2

The coefficient of variation is equal to the standard deviation divided by the mean and usually expressed as a percentage.

3

Design strength by testing = lowest test result divided by the multiplier.

TABLE 8.2 MINIMUM VALUES OF COEFFICIENT OF VARIATION (COV) FOR DIFFERENT MATERIALS AND ACTION EFFECTS Minimum COV%

Material

Method of manufacture or assembly Bending

Steel

Concrete

Timber

All welded

Spun or cast

Stress graded

Visually graded

5

5

25

30

 NOTE : F or on-sit e weld ed con nec tio ns, a h igh er coe fficie nt of variat ion may be app rop ria te.

8.5.3 Acceptance criteria

The acceptance criteria for strength and serviceability shall be as follows: (a)

For serviceability, the test specimen shall be deemed to comply with the serviceability requirements of this Standard if, under the serviceability limit-state test load, the measured serviceability indicators are within the specified limits appropriate to the pole application. 8326-PDR - 24/07/2008 14:25:50

90

DRAFT ONLY

(b)

DRAFT ONLY

For strength, the test specimens shall be deemed to comply with the strength requirements of this Standard if the specimens are able to withstand the strength limit-state test load for not less than 2 min.

8.5.4 Test reports

The results of the tests on each test specimen shall be recorded in a report. The report shall contain at least the following information: (a)

A clear statement of the conditions of testing, including the methods of supporting and loading the specimen and the methods of measuring serviceability indicators.

(b)

Identification of the test specimen.

(c)

The values of the relevant test loads and, where appropriate, measured performance indicators.

(d)

A statement as to whether or not the specimen satisfied the acceptance criteria.

If a specimen fails to satisfy an acceptance criterion, the load at which such failure occurred shall be recorded and reported.

8326-PDR - 24/07/2008 14:25:50

91

DRAFT ONLY

S E C T I O N

9

DRAFT ONLY

F O U N D A T I O N S

9.1 GENERAL

Foundations for supports may take the form of single foundations in the case of pole type structures and guy anchors or separate footings for each leg of towers. The loading on single footings is predominantly in the form of overturning moment, which is usually resisted by lateral soil pressure, together with additional shear and vertical forces resisted by upwards soil pressure. Common types of single foundations are direct buried poles, bored caissons, mono-bloc footings, pad or raft footings, bored pier foundations, and single pile or pile group foundations. When separate footings are provided for each leg the predominant loadings are compression and uplift forces, however, shear forces should be considered. Uplift and compression forces are usually resisted by combinations of dead weight of the foundation bulk, earth surcharges, shear forces and bearing in the soil. This also applies to guy foundations. Common types of separate footing foundations are (stepped) block footings with or without undercut (pad and chimney, spread footings); auger bored footings with or without expanded base; pier or caisson foundations; grillage foundations; and vertical or raked pile foundations. 9.2 DESIGN PRINCIPLES

Foundations for structures and the anchor of any stays or guy wires shall be capable of withstanding loads specified for the ultimate strength limit state and serviceability limit states conditions. Foundation design should be based on appropriate engineering soil properties. Where soil test information is not available an estimate of soil parameters should be made based on an appraisal of site conditions, soil types and geological structure. Construction personnel shall be made aware of the assumed parameters and guidelines should be issued that will allow recognition of soils not conforming to the adopted design  parameters. In calculating the strength of foundations, recognition should be given for the different strength characteristics of soil under short-term and long term loads, and the difference in saturated and dry properties of the soil. Failing the availability of soil tests, Appendix L provides guidance on various soil  propertie s. As a general principle, the foundation should not have component reliability less than that of the structure. The consequences of foundation failure (excessive movement or differential settlement) on rigid structures may induce high stress levels in the structure. The φ   values provided in Table 6.5 are based on a component reliability factor of 1.0, and take into account the normal high coefficient of variation (COV) of soil generally.

8326-PDR - 24/07/2008 14:25:50

92

DRAFT ONLY

DRAFT ONLY

The consequences of partial foundation failure for pole structures or flexible guyed structures are not normally as severe. Designers should assess the cost of providing foundations that will remain elastic for all design loads versus the cost of straightening  poles (or re-tensioning stays) that have been subjected to extreme weather events. It should  be noted that the deflection of foundations of deviation structures most likely will reduce conductor tension loadings. Pole head offsets provide a convenient means of negating this effect. Permanent deflections due to extreme windstorm or floodwater events and long term creep of materials will increase stresses in the structure and its foundation due to the eccentricity of the structure vertical loads relative to the foundation centre (p Δ  effect). This can cause foundation failure. 9.3

POLE AND TOWER FOUNDATIONS

Structure foundation design methods together with typical soil parameters are provided in Appendix L. 9.4 SOIL INVESTIGATION

Where carried out, soil investigations shall be to a depth that include all layers which significantly influence the foundation strength. The type, condition, extent, stratification and depth of the soil layers as well as groundwater conditions can be examined by boring and/or testing such as cone penetration test (CPT), standard penetration test (SPT), penetrometer, trial pits or other standardized tests, if available knowledge base does not provide sufficient information. The results of the soil investigations shall be recorded, in accordance with relevant standards or codes of practice. In the absence of better information from soil investigations, the soil parameters provided in Appendix L may be used as a guideline for design. However it should be confirmed by inspection or testing, during construction, that the soil parameters used are appropriate. 9.5 BACKFILLING OF EXCAVATED MATERIALS

When backfilling is used, sufficient compaction shall be carried out to ensured foundation actions can be developed as designed. In certain circumstances a possible reduction of consistency of cohesive soils should be taken into account in the calculations if compaction standards are to be relaxed. When backfilling with granular soil in cohesive soil, the tendency of water to accumulate in the backfill shall be considered or lower values shall be used. 9.6 FOUNDATION DISPLACEMENTS

The design values for the limiting displacement of foundations will depend on the type of foundations, the type of structure, and the serviceably criteria assumed.  NOT E: As a guid e, damage and failur e limits giv en in IEC 60 826 may be adopted.

9.7 LOAD TESTING OF FOUNDATIONS

Loading tests or tests on experimental models form a valuable method for justifying the design of foundations or to test the strengths of individual foundations, whether test or  production foundations. There are two categories of tests normally performed, i.e. proof tests, or design and research tests.

8326-PDR - 24/07/2008 14:25:50

93

DRAFT ONLY

DRAFT ONLY

9.7.1 Proof tests

These tests are undertaken on production foundations and they shall successfully pass the test at a percentage of the design load (nominally 85%) such that they remain fully serviceable after testing. 9.7.2 Design and research tests

These tests are carried out on specially installed foundations typically up to failure and are intended to verify specific design approaches or assumptions for the geotechnical  parameters. Such tests require efforts for ensuring accuracy of installation and monitoring the test. Provision for the following factors should be included: (a)

Design loading conditions.

(b)

Difference in the ground conditions between the test and the actual construction.

(c)

Duration of test loading.

(d)

Scale effects, especially if smaller models are used.

(e)

Climatic effects.

Details concerning the preparation of the tests, the testing arrangement, the test procedure and evaluation of results are given in AS 2159. 9.8 CONSTRUCTION AND INSTALLATION

Details of the proposed method of interconnection between the support and the foundation shall be incorporated in the design. Designs of foundations should include consideration of the method of construction and installation of foundations to ensure the assumed or designed geotechnical parameters are able to be realised.

8326-PDR - 24/07/2008 14:25:50

94

DRAFT ONLY

S E C T I O N

1 0

E A R T H I N G

DRAFT ONLY

S Y S T E M S

10.1 GENERAL PURPOSE

An earthing system of overhead earthwires, earth down leads, grading rings and counterpoise earthing addresses the following objectives: (a)

Ensure protective equipment will operate in faulted situations.

(b)

Provide acceptable reliability (lightning performance) on the line.

(c)

Control touch and step potentials around the base of the structure.

(d)

Provide a conductive path for fault current.

(e)

Avoid damage to properties and equipment.

The dimensioning of earthing systems shall consider the following requirements: (i)

To ensure mechanical strength and corrosion resistance.

(ii)

To withstand, from a thermal point of view, the highest fault current as determined by calculation

(iii)

Limit lightning induced voltages on earth down leads

The transfer of potential by nearby metallic objects may occur due to fault currents flowing in the earth system. Guidelines on individual cases should be determined by the utility. These effects shall be reduced to acc eptable levels contained in AS/NZS 3835 and HB 101(CJC5). 10.2 EARTHING MEASURES AGAINST LIGHTNING EFFECTS

The footing resistance values have an influence on the backflashover rate of the line and therefore affect the reliability. A low resistance provides good lightning performance and recommended values for high reliability lines are an average of 10 ohms in middle of the line and 5 ohms close to the substation. 10.3 DIMENSIONING WITH RESPECT TO CORROSION AND MECHANICAL STRENGTH 10.3.1 Earth electrodes

The electrodes, being directly in contact with the soil, shall be of materials capable of withstanding corrosion (chemical or biological attack, oxidation, formation of an electrolytic couple, electrolysis, etc.). They shall resist the mechanical influences during their installation as well as those occurring during normal service. Mechanical strength and corrosion considerations dictate the minimum dimensions for earth electrodes given in EN 50341. If a different material, for example stainless steel, is used, this material and its dimensions shall meet the requirements of (a) and (b) in Clause 10.1.  NOTE: It is acceptable to use steel reinforcing bars embedded in concrete fou ndatio ns and steel  pil es as a part of the earthing system.

10.3.2 Earthing and bonding conductors

For mechanical and electrical reasons, the minimum cross-sections shall be— (a)

copper

16 mm 2 . 8326-PDR - 24/07/2008 14:25:50

95

DRAFT ONLY

(b)

aluminium

35 mm 2.

(c)

steel

50 mm2.

DRAFT ONLY

 NOT E: Composite conductor s can also be used for earthing pro vided that their resistance is equivalent to the examples given. For aluminium conductors corrosion affects should be considered. Earthing and bonding conductors made of steel require protection against corrosion.

10.4 DIMENSIONING WITH RESPECT TO THERMAL STRENGTH 10.4.1 General

Because fault current levels are governed by the electrical system rather than the overhead line the values should be provided by the network utility. 4

In some cases steady-state zero-sequence currents should be taken into account for the dimensioning of the relevant earthing system.

5

For design purposes, the currents used to calculate the conductor size should take into account the possibility of future growth.

The fault current is often subdivided in the earth electrode system; it is, therefore, possible to dimension each electrode for only a fraction of the fault current. The final temperatures involved in the design and to which reference is made in the following subclause shall be chosen in order to avoid reduction of the material strength and to avoid damage to the surrounding materials, for example concrete or insulating materials.  No permissible temperature ris e of the soil surrounding the earth electrodes is given in this Standard because experience shows that soil temperature rise is usually not significant. 10.4.2 Current rating calculation

The calculation of the cross-section of the earthing conductors or earth electrodes depending on the value and the duration of the fault current is given in EN 50341. There is a discrimination between fault durat ion lower than 5 s (adiabatic te mperature rise) a nd greater than 5 s. The final temperature shall be chosen with regard to the material and the surroundings.  Nevertheless, the minimum cross-s ections in Clause 10.3.2 shall be observed. 10.5 RISK BASED EARTHING - PERMISSIBLE VALUES

Overhead lines shall comply with the respective touch voltage curves shown in Figures 10.1 and Figure 10.2 or be based on a risk based approach.

8326-PDR - 24/07/2008 14:25:50

96

DRAFT ONLY

DRAFT ONLY

100,000

   )    V    (   s   e 10,000   g   a    t    l   o   v    h   c   u   o    t   e 1,000   v    i    t   c   e   p   s   o   r    P

 As pha lt Crushed rock 1000

-m

500

-m

200

-m

50

-m

10 0

10 10

100

1,000

10,000

Fault duration (ms)

 NOTE: For the curves in Figure 10 1 and Figure 10. 2, a resistivity value of 3,000 Ω-m has been used for crushed rock and 10,000 Ω-m for asphalt.

FIGURE 10 1 PROSPECTIVE TOUCH VOLTAGE CURVES EXCLUDING FOOTWEAR RESISTANCE

100,000

   )    V    ( 10,000   s   e   g   a    t    l   o   v    h   c   u   o    t 1,000   e   v    i    t   c   e   p   s   o   r    P

 Asp ha lt Crushed rock 1000 -m 500

-m

200

-m

50

-m

100

10 10

100

1,000

10,000

Fault duration (ms)

 NOTE: For the curves in Figure 10 1 and Figure 10. 2, a resistivity value of 3,000 Ω-m has been used for crushed rock and 10,000 Ω-m for asphalt.

FIGURE 10. 2 PROSPECTIVE TOUCH VOLTAGE CURVES INCLUDING 2,000 Ω FOOTWEAR RESISTANCE

8326-PDR - 24/07/2008 14:25:50

97

DRAFT ONLY

DRAFT ONLY

10.5.1 Risk based approach to earthing 10.5.1.1   Introduction

Risks associated with earthing include the possibility of human and livestock fatalities, equipment damage and property loss. All these risks shall be assessed on the basis of cost and benefit. For human fatalities a probability based approach is recommended. 10.5.1.2 Risk of fatality approach

Design of an earthing system based on a risk approach to human fatalities can be accomplished by the process outlined in Figure 10.3 and described in the points following: (a)

Identify the scenarios and the risks (e.g. a person touching a substation fence at the time of a fault).

(b)

Based on the likely proportion of total earth fault currents flowing into the local earthing system and durations), determine the minimum earthing system that could meet the functional requirement. Detailed design is necessary to ensure that all exposed conductive parts, are earthed. Extraneous conductive parts shall be earthed, if appropriate. Any structural earth electrodes associated with the installation shall be  bonded and form part of the earthing sys tem. If not bonded, verification is necessary to ensure that all safety requirements are met.

(c)

Determine the zone of interest. If it cannot be demonstrated that interconnection via either the primary or secondary supply systems is sufficient, then determine the soil characteristics of the zone of interest, taking into account the seasonal variation of the soil parameters.

(d)

Based on soil characteristics and the estimated fault current discharged into the soil  by the earthing system of the installation sit e, determine earth potention ris e (E PR).

(e)

Determine the tolerable step and touch voltages (see Appendix U).

(f)

If the EPR is below the tolerable step and touch voltages, the design is completed.

(g)

If not, determine if step and touch voltages inside and in the vicinity of the earthing system are below the tolerable limits.

(h)

If not, assess the risk as detailed in Appendix U and as summarized below— (i)

estimate the frequency and duration of the fault events;

(ii)

estimate the extent of hazard areas or zones;

(iii)

estimate the total length of time per year that individuals are within hazardous areas or zones;

(iv)

calculate the probability of individuals being at risk through exposure to hazardous voltages; and

(v)

compare the level of probability of an event against the risk criteria and establish the cost benefit of reducing the level of probability to below acceptable levels (if required). Refer to Appendix U for definitions of the High, Intermediate and Low risk categories and associated actions required.

(i)

Identify and implement appropriate risk treatment measures (if required) and then re calculate the residual risk level following treatment. Typical treatment measures are discussed in Appendix U.

(j)

Determine if transferred potentials present a hazard outside or inside the high voltage installation. If yes, proceed with risk treatment at exposed location.

(k)

Determine if low voltage equipment is exposed to excessive stress voltage. If yes,  proceed wit h mitigation measures, which can include separation of HV and LV earthing systems. 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY

98

DRAFT ONLY

(l)

Determine if the circulating transformer neutral current can lead to excessive  potential differences between different parts of the earthing system. If yes , proceed with mitigation measures.

(m)

Assess and manage any inductive and conductive interference with other utility plant and personnel (e.g. telecommunications, pipelines, rail).

(n)

Consider the need to implement any particular precautions against lightning and other transients.

(o)

Once the above criteria have been met, the design can be refined, if necessary, by repeating the above steps.

(p)

Provide installation support as necessary to ensure design requirements fulfilled and staff safety risk effectively managed.

(q)

Review installation for physical and safety compliance following the commissioning  programme.

(r)

Documentation to include physical installation description, e.g. drawing, as well as electrical assumptions, design decisions, commissioning, data and supervision and maintenance requirements.

The risk assessment can also be formulated as, given a tolerable level of risk of fatalities, what is the maximum allowable number of contact events by people per unit time?

8326-PDR - 24/07/2008 14:25:50

99

DRAFT ONLY

DRAFT ONLY

)

1. Refer to Appendix U for definitions of the high, intermediate and low risk outcome categories and associated actions required. 2. For low risk category, the risk is generally acceptable . However, risk treatment should be applied if the cost of the risk treatment was small compared to the overall project cost. A cost benefit analysis may be required to assess the cost of the risk treatment against the overall project cost.

FIGURE 10.3 EARTHING SYSTEM DESIGN FLOW CHART

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

100

DRAFT ONLY

10.6 ELECTRICAL ASPECTS OF STAYWIRE DESIGN

Important electrical considerations to be incorporated into the design for structure staywires consist of— (a)

corrosion of staywires and foundation steelwork due to leakage currents; and

(b)

control of touch potentials on structure staywires.

10.6.1 Corrosion and leakage currents

The net flow of leakage current off a staywire will lead to eventual corrosion of the staywire, or the reinforcing steel in the staywire foundation. For most transmission and distribution applications, the provision of a stay insulator in the stay wire assembly will mitigate corrosion issues related to leakage current flow. Typical examples of staywire insulators are outlined in AS 3609. However, corrosion at the ground line interfaces between stay rods, soil and concrete encasement interfaces may still be an issue even with stay insulator fitted and these aspects should be considered in the structural design aspects of the stay assembly foundation. There may be applications were a stay type insulator cannot be used. One example may be the use of high tensile stay wires with loads in excess of the specified mechanical rating of stay type insulators. For these instances, the structural design of the stay will need to account for corrosion, possible degradation and reduction in mechanical rating of the stay over the design lifetime of the staywire. 10.6.2 Stay earthing for control of touch potentials 10.6.2.1 Distribution and sub transmission lines

The addition of the stay insulator for leakage current, can also mitigate touch voltage hazards on stay wires. Common examples that can cause hazards in stay wires consist of  power follow currents flowing to earth via the stay on a conductive structure, which are not sufficient to operate protection systems, or a dropped conductor directly onto the structure stay. Stay insulators should be positioned such that the staywire on the structure side of the stay insulator cannot be accessed from the ground by the general public when intact or when in a  broken stay wire sta te and also positioned such to maximise the ability to insulate the stay to ground in the event of a fallen conductor directly onto the stay. 10.6.2.2 Transmission lines

The addition of the stay insulator for leakage current, may only partly address touch voltage hazards on stay wires for transmission applications. There may be some situations, due to high prospective fault currents, that the stay insulator is insufficient to control touch voltages in the event of a fault occurring at this structure. Therefore, additional safety measures in the form of stay earthing, and installation of buried grading control conductors may need consideration by the designer. Stay insulators should be positioned such that the staywire on the structure side of the stay insulator cannot be accessed from the ground by the general public. Stay wires which do not utilize insulators shall require by default additional safety measures in the form of stay earthing, and installation of buried grading control conductors to control touch voltages. In addition to the specified mechanical requirements for the stay, an evaluation of electrical capability of the stay wire should also be considered. Fault currents shall be allowed to flow to earth via the structure and its associated stay wires, without damage being caused to the stay wire due to flow of fault current.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

101

DRAFT ONLY

10.7 CHOICE OF EARTHING MATERIALS

Where additional earthing and installation of buried grading conductors are used , consideration should be given to the suitability of the various earthing materials. The  performance of earthing materials when bonded and installed in proximi ty to stay wires and their foundations shall be considered. Problems with dissimilar metals and galvanic corrosion should be avoided.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

S E C T I O N

102

1 1

DRAFT ONLY

L I N E E Q U I P M E N T — O V E R H E A D L I N E F I T T I N G S

11.1 GENERAL

Overhead line fittings shall be designed, manufactured and erected in such a way as to meet the overall performance requirement for the operation and maintenance for the line. The design life of fittings and components shall be 50 years or as otherwise determined. 11.2 ELECTRICAL REQUIREMENTS 11.2.1 Requirements applicable to all fittings

The design of all fittings shall be such that they are compatible with the specified electrical requirements for the overhead line. Grading rings or similar devices shall be used where necessary to reduce the electric field intensity at the line end of insulator sets, including the compression terminations of composite insulators. 11.2.2 Requirements applicable to current carrying fittings

Conductor fittings intended to carry the operating current of the conductor shall not, when subjected to the maximum continuous current in the conductor or to short-circuit currents, exhibit corresponding temperature rises greater than those of the associated conductor. Also the voltage drop across current carrying conductor fittings shall not be greater than the voltage drop across an equivalent length of conductor. 11.3 RIV REQUIREMENTS AND CORONA EXTINCTION VOLTAGE

Fittings, including spacers and vibration dampers, for overhead lines shall be designed such that under test conditions the levels of radio interference are consistent with the overall level specified for the installation. 11.4 SHORT-CIRCUIT CURRENT AND POWER ARC REQUIREMENTS

Fittings shall, when required, comply with the specified short-circuit current or power arc requirements. In particular insulator set fittings shall be such that if a short-circuit current or power arc test is required they retain, at least 80 % of their specified mechanical failing load on completion of the test. Arcing horns shall be capable of safely carrying the anticipated fault level current for the anticipated duration of the fault without adverse effect on the safety aspects of overhead line maintenance. 11.5 MECHANICAL REQUIREMENTS

Conductor termination fitting and all component fittings in insulator string assemblies shall  be capable of transferring the structure design failure containment load  F  b   to the structure termination point, for the complete design service life of the fittings. Where accelerated corrosion due to electrical effects exists, or if there is a high potential for mechanical abrasion and wear of fittings, due allowance shall be made in the design or in the planned maintenance of the line to ensure the integrity of the line reliability.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

103

DRAFT ONLY

11.6 DURABILITY REQUIREMENTS

All materials used in the construction of overhead line fittings shall be inherently resistant to atmospheric corrosion which may affect their performance. The choice of materials and/or the design of fittings shall be such that bimetallic corrosion of fittings or conductor is minimized. All ferrous materials, other than stainless steels, used in the construction of fittings shall be  protected against atmosp heric corrosion by hot dip galvanizing or other methods specified in the project specification or agreed by the purchaser with the supplier. Fittings subjected to articulation or wear shall be designed, including material selection, and manufactured to ensure maximum wear resistant properties. 11.7 MATERIAL SELECTION AND SPECIFICATION

Materials used in the manufacture of overhead line fittings shall be selected having regard to their relevant characteristics. The manufacturer shall ensure that the specification and quality control of materials is sufficient to ensure continuous achievement of the specified characteristics and performance requirements. Locking devices used in the assembly of fittings with socket connectors shall comply with the requirements of IEC 60372.  NOT E: When selecting metals or alloys for line fit tin gs the possible effects of low temperature should, where relevant, be considered. When selecting non-metallic materials their possible reaction to temperature extremes, UV radiation, ozone and atmospheric pollution should be considered.

11.8 CHARACTERISTICS AND DIMENSIONS OF FITTINGS

The mechanical characteristics of insulator set fittings shall comply with the mechanical strength requirements of AS 1154.1 or IEC 60471. 11.8.1 Termination fittings

Termination fittings include deadends and joints. Termination fittings shall be generally designed and manufactured in accordance with AS 1154.1 or AS 1154.3 for helical fittings or equivalent International Standards. Termination fittings shall be designed to hold the strength nominated in the relevant standard. Terminations shall be designed to carry the steady state thermal conductor current rating, short time thermal current rating and shortcircuit current rating for the design life of the overhead line. 11.8.2 Suspension and support fittings

Suspension and support fittings include bolted suspension clamps, armour grip suspensions and wire ties. Suspension and support fittings shall be designed and manufactured in accordance AS 1154.1 or AS 1154.3 for helical fittings or equivalent International standards. Suspension and support fittings shall be designed to— (a)

achieve the mechanical strength nominated by the manufacturer or required by the  purchaser;

(b)

hold the slip strength nominated by the manufacturer or required by the purchaser; and

(c)

 be undamaged by the passage of the steady state thermal conductor current rating, short time thermal current rating and short-circuit current rating for the design life of the overhead line.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

104

DRAFT ONLY

11.8.3 Repair fittings

Repair fittings shall be des igned and manufactured in accordance w ith AS 1154.3 or equivalent International Standards. Repair fittings shall be designed to make good conductors of which not more than half of the wires in the outermost layer have been fractured or have other equivalent damage to that outermost layer. Repair fittings shall not  be used to make good damaged steel wires. 11.8.4 Spacers and spacer dampers

Spacers and Spacer Dampers shall be designed and manufactured in accordance with AS 1154.1 or equivalent International Standards. Spacers and spacer dampers shall— (a)

 be designed to maintain the nomi nated sub-conductor separation;

(b)

 be designed to minimize dama ge caused to the conductors by the action of the wind;

(c)

withstand the compressive forces associated with short-circuit currents;

(d)

withstand the fatigue loads imparted by the conductors as a result of the action of the wind; and

(e)

 be installed in accordance with the recommendations of the manufacturers.

11.8.5 Vibration dampers

Vibration dampers shall be designed and manufactured in accordance with AS 1154.1 or equivalent International Standards. Vibration dampers shall be installed on all conductors in accordance with Appendix Z. Vibration dampers shall be designed to minimize damage to the conductors, suspension clamps and other hardware cause by wind induced aeolian vibration. Vibration dampers shall be installed in accordance with the recommendations of the manufacturers. 11.8.6 Conductor fittings for use at elevated temperatures

Conductor fittings for high temperature conductors shall be selected to meet the steady state thermal conductor current rating, short time thermal current rating and short-circuit current rating for the design life of the overhead line. In particular, fittings such as armour grip types of suspension clamps which use rubber inserts shall be selected to ensure the rubber components shall withstand the steady state current rating. Fittings to be used for high temperature conductors manufactured from aluminium or aluminium alloys should be designed so that any parts of the fittings subject to mechanical stresses including fittings for support or suspension as well as termination or jointing will experience a maximum temperature of approximately 100°C when the conductor is at the steady state thermal current rating. The fittings shall be designed so the fitting is not prone to loosening as a result of thermal ratcheting.  NOT E: Thermal r atcheting can occur when dissimilar metals are used together such as a steel b olt in an aluminium clamp where the expansion coefficient of the aluminium is much higher than the steel and loosening of the bolt can occur as a result of the differential movement of each material during heating and cooling.

11.8.7 Conductor fittings used at near freezing temperatures

Conductor fitting shall be designed and manufactured to ensure the ingress of moisture and subsequent freezing does not compromise mechanical performance.  NOT E: Should moisture ingress occur in enclosed fit tin gs such as termination fit tin gs, the moisture may freeze and expand and cause the fitting to loosen on the conductor or fracture of the fitting.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

105

DRAFT ONLY

11.9 TYPE TEST REQUIREMENTS 11.9.1 Standard type tests

When required type tests on overhead line fittings shall be carried out in accordance with the requirements of AS 1154 and IEC 60471. 11.9.2 Optional type tests

Type tests may be carried out to confirm the performance of insulator set fittings under  power arc conditions. Information relating to such tests is given in IEC 61467. 11.10 SAMPLE TEST REQUIREMENTS

Sample tests shall be carried out in accordance with AS 1154 and IEC 60471. 11.11 ROUTINE TEST REQUIREMENTS

Routine tests shall be carried out in accordance with AS 1154 and IEC 60471.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

106

DRAFT ONLY

S E C T I O N 1 2 L I F E E X T E N S I O N ( R E F U R B I S H M E N T , U P G R A D I N G , U P R A T I N G ) O F E X I S T I N G O V E R H E A D L I N E S 12.1 GENERAL

All overhead lines shall have ongoing planned maintenance to ensure they remain in an operationally serviceable condition without jeopardizing public safety. If it is identified that an overhead line is no longer meeting its operational performance standard; or has exhibited degradation to a level that raises question concerning any component of the overall lines’ serviceability, or safety to the public or ongoing maintenance - it shall be subjected to a complete engineering assessment. This assessment shall consider the following: (a)

Whether the support structures are no longer safe to the public or their ongoing maintenance as determined by further structural analysis and detailed assessment.

(b)

Whether the support structures are able to economically be refurbished.

(c)

Whether the overall line performance can be improved to an acceptable level by modification or replacement of line components.

(d)

Whether the line should be taken out of service and decommissioned.

Where the line is to be refurbished by modification of the support structures, replacement of conductors and insulation, it shall be subjected to a complete engineering assessment. 12.2 ASSESSMENT OF STRUCTURES

Current design requirements provide a useful ‘bench mark’ for existing construction, but it is often appropriate to adopt a lower standard consistent with the ‘fitness for purpose’ for the overall network. The reasons for a lower standard being appropriate are— (a)

most asset owners have overhead lines which have undergone ‘piecemeal’ replacement of individual supports since original construction;

(b)

legislation has changed since original construction (i.e. the design requirements have increased over time); or

(c)

this approach will achieve a more favourable network assessment outcome.

This reduced standard could be achieved using one or a combination of factors mentioned  below. 12.2.2 Line importance

Asset owners often adopt a uniform risk profile throughout the network, hence allowing reduced loads to reflect the reduced remaining life of the assets. This ensures that all assets have the same likelihood of failure during their remaining lives. However there is a minimum limit required to provide adequate safety to both the public and line personnel working on the structure. This reliability level is not related to remaining life, functional or economic loss, but protection of life. 12.2.3 Inspection

An inspection of the complete line shall be carried out as part of the evaluation process.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

107

DRAFT ONLY

It shall involve at least the following: (a)

An assessment of the condition of materials and elements including extent and significance of any deterioration found by physical measurement.

(b)

Material sampling, if required.

(c)

Verification of dimensional information.

(d)

Assessment of design loads.

(e)

Identification of any defective and unsafe components.

12.2.4 Material properties

The material properties assumed for analysis shall be based on one of the following methods: (a)

From drawings, specifications or other construction records.

(b)

From nominal historical values.

(c)

From cores or samples removed from the pole or component.

In order to obtain the characteristic value for calculation purposes, the results of the testing need to be adjusted using statistical methods. Any sampling shall be representative of the structure or entire group of similar components. The statistical adjustment factor is usually based on— (i)

The number of units

(ii)

The coefficient of variation (COV) of structural property

(iii)

The minimum structural property value ( Rmin )

12.3 COMPONENT CAPACITY

Each component strength capacity shall be based on the appropriate material standard and take into account the observed condition including effects of deterioration and reduction in gross section properties. It shall also allow for any deterioration likely to take place before the next inspection or modification or replacement. 12.4 PROOF LOADING

Proof loading may be undertaken to either verify the calculations and assumptions made or to increase the load limit. Proof loading shall be carried out in accordance with this Standard or the relevant material Standard. 12.5 GUIDELINES FOR UPGRADING OF OVERHEAD LINE STRUCTURES

Reference should be made to Appendix N for guidelines on the upgrading of structures for service life extension.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

108

DRAFT ONLY

S E C T I O N 1 3 P R O V I S I O N S F O R C L I M B I N G A N D W O R K I N G A T H E I G H T S All overhead line structures shall be designed from a whole of life concept and where necessary the provision shall be made in the design to provide facilities for climbing and working at heights from the support structure. Where a design decision has been taken to provide no climbing facilities, then information to this extent should be clearly identified on the design documents. In addition provision should be made in the line layout design to provide means for access of mobile plant to maintain the facility. Reference should be made to Appendix M for guidelines on climbing and working at heights on overhead lines.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

109

DRAFT ONLY

S E C T I O N 1 4 C O - U S E O F O V E R H E A D L I N E S U P P O R T S ( S I G N A G E , B A N N E R S , C O M M U N I C A T I O N S C A R R I E R C A B L E S , T E L E C O M M U N I C A T I O N S R E P E A T E R S ) 14.1 SIGNS AND BANNERS AND TRAFFIC MIRRORS

While the design of flagpoles is outside the scope of this Standard, the attachment of  banners to roadside poles is not uncommon for the purpose of promoting special civic or community activities. As the presence of banners may add appreciable lateral loads to these  poles under wind conditions, designers should make allowance for increased loadings, where it is likely to occur. eg along main thoroughfares and selected streets. In order to make this practicable, it is incumbent on the designer to place limitations on the location, size and duration of banner attachments to these poles. 14.1.1 Location

(a)

The positioning of a banner on a pole should be not greater than 6 m above ground level.

(b)

Double banners should be located diametrically opposite one another and in a vertical  plane, which minimi zes torsion effects with respect to any outreach arms.

14.1.2 Attachments

Where banners are attached at top and bottom to their mounting arms, the bottom attachment should be designed to release as soon as the design serviceability wind pressure is exceeded. The attachment of all banners should be capable of retaining the banner on its top-mounting arm at the ultimate design wind pressure. 14.1.3 Size of banners

The area of one face of any single banner should not exceed 0.8 m 2  and the total face area of banners on any single pole should not exceed 2.0 m 2. 14.1.4 Duration of attachment

Banners or flags attached to poles may induce an undue aerodynamic response in the structure. This could result in the development of excessive stresses or fatigue stresses which could lead to catastrophic failure. Unless pole structures are specifically designed for banner loadings, the risk of premature failure should be minimized by limiting the duration of the banner attachment. For example, attachment for 10 to 15 weeks in any 12 consecutive months may provide an acceptable level of control. 14.1.5 Wind loads on signs and banners 14.1.5.1 Strength limit state

At the strength limit state, all banners are assumed to be attached only to the top mounting arm and almost horizontal. In these circumstances they resemble flags in a strong wind for which the total wind force on the flag may be determined from the following equation:  Fwf

⎛ =⎜ ⎝

Cff

+ Cdf ×  G ⎞ ⎟ pd × Af b × κ  ⎠

 

where  F wf 

=

total force on the banner (  N ) 8326-PDR - 24/07/2008 14:25:50

. . .14.1

DRAFT ONLY  

110

DRAFT ONLY

=

a friction factor

=

0.024

C df 

=

a drag factor determined from Table 14.1

G

=

unit mass of wet banner material (kg/m 2)

b

=

dimension of banner at right angles to wind direction (m)

κ

=

density of air, taken as 1.23 kg/m

 p d

=

design wind pressure at the strength limit state (Pa)

 Af 

=

area of (one) banner face (m 2)

C ff 

3

The mass per unit area of cloth materials, in a similar manner to paper, is usually quoted in grams per square metre (g/m 2). Making this substitution, substituting the numerical values for C ff and κ, and  p u K z for  p d, and converting to units consistent with Clause 1.4, Equation 14.1 becomes—  Fwf

⎡ ⎛ 0.008Cdf wg ⎞ ⎤ = ⎢0.024 + ⎜ ⎟ ⎥ pd K Z KT Af b ⎝ ⎠ ⎥⎦ ⎣⎢

. . .14.2

 

where  F wf 

=

total force on the banner (kN)

C df 

=

a drag factor obtained from Table 14.1

wg

=

mass per unit area of wet flag material (g/m2)

b

=

Dimension of banner at right angles to wind direction (m)

 Af 

=

area of one face of the banner

and  p d,  K z  and  K T are obtained from Appendix B for the strength limit state. It is assumed that  F wf    acts horizontally at the level of the support arm where the arm intersects a vertical plane through the centroid of area of the banner. TABLE 14.1 DRAG FACTORS FOR BANNERS  Af / b2   C df 

0.1 10

0.2

0.4

0.6

1.0

2.0

4.0

6.0

4.6

2.2

1.4

0.8

0.36

0.17

0.11

 NOTE :Se e F igu re 14. 1.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

111

DRAFT ONLY

FIGURE 14.1 BANNER DIMENSIONS

14.1.5.2 Serviceability limit state 14.1.5.2.1   General

For the serviceability limit state, there is a need to differentiate between banners attached at the top only and those attached at the top and bottom to mounting arms. 14.1.5.2.2 Top attached banners

For top attached banners,  F wf    is calculated from Equation 14.2 by substituting  ps  for pu, when pd is obtained from Appendix B for the serviceability limit state. 14.1.5.2.3 Top and bottom attached banners

For banners attached at both the top and bottom, each banner can be treated for wind load in a manner similar to any other attachment to the pole. The total force  (F wf  ) is calculated from the following equation:  F wf 

=

1.6  pd ×  K z ×  K T ×  Af 

. . .14.3

where 1.6 is the drag factor for a sharp-edged flat surface. 14.2 COMMUNICATIONS CARRIER CABLES 14.2.1 General

Where it is a likely requirement that an overhead line may be required to support aerial communications carrier cables that are owned by third parties, provision shall be made for their safe placement on the supports preferably in an under built mode. These cables may be of an insulated self supporting type (ADSS ) or as a catenary cable supported system. On existing overhead lines, where such cables are to be installed the structure designs shall  be subj ect to a full engineering asse ssment. 14.3 TELECOMMUNICATIONS MIRRORS

REPEATERS

EQUIPMENT

AND

TRAFFIC

14.3.1 General

Telecommunications repeater installations on overhead line supports normally require the installation of microwave dishes, multiple cellular telephone antennae, antennae mounting support steelwork, and cables to a ground level relay station. Traffic mirrors are installed to aid motorists in viewing around visually obstructed locations. The size of these mirrors can vary significantly. 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

112

DRAFT ONLY

All overhead line structures to be fitted with these devices shall be subject to a full engineering assessment. In the case of telecommunication repeater sites the performance of the telecommunications facility may be sensitive to rotational deflection limits, and these should be checked. 14.3.2 Safety considerations

Radiation effects from antennae are an operational and maintenance issue that must considered and appropriate safety measures deployed.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

113

DRAFT ONLY

APPENDIX A

REFERENCE AND RELATED DOCUMENTS (Informative) A1 REFERENCED DOCUMENTS

This Standard incorporates, by either normative or informative reference, provisions from other publications. These references are cited at the appropriate places in the text together with a statement indicating whether the reference is normative in this Standard or informative. All references are undated and the latest edition of the publication referred to applies. AS 1154 1154.1 1154.3

Insulator and conductor fittings for overhead power lines Part 1: Performance, material, general requirements and dimensions Part 3: Performance and general requirements for helical fittings

1222 1222.1 1222.2

Steel conductors and stays Part 1: Bare overhead—Galvanized (SC/GZ) Part 2: Aluminium clad (SC/AC)

1604

Specification for preservative treatment - Sawn and round timber

1531

Conductors—Bare overhead—Aluminium and aluminium alloy

1720 1720.1 1720.2

Timber structures Part 1: Design methods Part 2: Timber properties

1726

Geotechnical site investigations

1746

Conductors—Bare overhead—Hard-drawn copper

1824 1824.2

Insulation coordination Insulation coordination (phase-to-earth and phase-to-phase, above 1 kV)—Application guide

2067

Switchgear assemblies and ancillary equipment for alternating voltages above 1 kV

2159

Piling—Design and installation

2209

Timber—Poles for overhead lines

3600

Concrete structures

3607

Conductors—Bare overhead, aluminium and aluminium alloy—Steel reinforced

3608

Insulators—Porcelain and glass, pin and shackle type—Voltages not exceeding 1000 V a.c.

3609

Insulators—Porcelain stay type—Voltages greater than 1000 V a.c.

3822

Test methods for bare overhead conductors

3995

Design of steel lattice towers and masts

4058

Precast concrete pipes (pressure and non-pressure)

4100

Steel structures

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

AS 4398 4435 4435.1 4435.4

114

DRAFT ONLY

Insulators—Ceramic or glass—Station post for indoor and outdoor use—Voltages greater than 1000 V a.c. Insulators—Composite for overhead power lines—Voltages greater than 1000 V a.c. Part 1: Definitions, test methods and acceptance criteria for string insulator units Part 4: Definitions, test methods, acceptance criteria for post insulator units

4436

Guide for the selection of insulators in respect of polluted conditions

60305

Insulators for overhead lines with a nominal voltage above 1000 V—  Ceramic or glass insulator units for a.c. systems—Characteristics of insulator units of the cap and pin type

AS/NZS 1170 1170.2 1170.3 1170.5

Structural design actions Part 2: Wind actions Part 3: Snow and ice actions Part 5: Earthquake actions in Australia

1252

High strength steel bolts with associated nuts and washers for structural engineering

1328

Glued laminated structural timber

1768

Lightning protection

1891 1891.1 1891.2 1891.3 1891.4

Industrial fall arrest-systems and devices Part 1: Harnesses and ancillary equipment Part 2: Horizontal lifeline and rail systems Part 3: Fall-arrest devices Part 4: Selection, use and maintenance

2312

Guide to the protection of structural steel against atmospheric corrosion by the use of protective coatings

2344

Limits of electromagnetic interference from overhead a.c. powerlines and high voltage equipment installations in the frequency range 0.15 to 1000 MHz

2373

Electric cables— Twisted pair for control and protection circuits

2947

Insulators—Porcelain and glass for overhead power lines—Voltages greater than 1000 V a.c

3675

Conductors—Covered overhead—For working 6.35/11(12) kV up to and including 19/33(36) kV

3560

Electric cables—Cross-linked polyethylene insulated—Aerial  bundled—For working voltages up to and including 0.6/1(1.2) kV Part 1: Aluminium conductors Part 2: Copper conductors

3560.1 3560.2 3599 3599.1 3599.2 3675

voltages

Electric cables—Aerial bundled—Polymeric insulated—Voltages 6.35/11(12) kV and 12.7/22(24) kV Part 1: Metallic screened Part 2: Non-metallic screened Conductors—Covered overhead—For working 6.35/11(12) kV up to and including 19/33(36) kV 8326-PDR - 24/07/2008 14:25:50

voltages

DRAFT ONLY  

115

DRAFT ONLY

AS/NZS 3835

Earth potential rise—Protection of telecommunications network users, personnel and plant

4065

Concrete utility services poles

4435 4435.2

Insulators—Composite for overhead power lines—Voltages greater than 1000 V a.c. Part 2: Insulators—Composite for overhead power lines—Voltages greater than 1000 V a.c.—Standard strength classes and end fittings for string insulator units

4600

Cold-formed steel structures

4676

Structural design requirements for utility services poles

4677

Steel utility services poles

4680

Hot-dip galvanized (zinc) coatings on fabricated ferrous articles

4853

Electrical hazards on metallic pipelines

HB 101 (CJC5)

Coordination of power and telecommunications—Low frequency induction (LFI): Code of practice

 NZS 1170.5

Structural design actions—Earthquake actions—New Zealand

3101

Concrete structures

3101.1

Part 1: The design of concrete structures

3404

Steel structures standard

3404.1

Part 1: Steel structures standard

3603

Timber structures standard

6869

Limits and measurement methods of electromagnetic noise from high voltage a.c. power systems, 0.15

 NZECP 34

New Zealand Electrical Code of Practice for Electrical Safe Distances

41

New Zealand Electrical Code of Practice for Single Wire Earth Return Systems

46

New Zealand Electrical Code of Practice for High Voltage Live Line Work

EEA\NZ SM-EI

Industry Safety Rules Guide to Use of Helicopters in Power Company Work Use of Personal Fall Arrest Systems

ENA LLM 01

Guidelines for live line barehand work

LLM 02

Guidelines for live line stick work

LLM 03

Guidelines for live line glove and barrier work

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

ENA  NENS 04

116

National guidelines for safe approach distances to electrical and mechanical apparatus

 NENS 05

National fall protection guidelines for the electricity industry

ESAA D(b)5*

Current rating of bare overhead line conductors

EANSW *

High Voltage Earth Return for Rural Areas

IEC 60372

DRAFT ONLY

Locking devices for ball and socket couplings of string insulator units—Dimensions and tests

60433

Insulators for overhead lines with a nominal voltage above 1 000 V—Ceramic insulators for a.c. systems—Characteristics of insulator units of the long rod type

60471

Dimensions of clevis and tongue couplings of string insulator units

TR 60479 TR 60479-1

Guide to effects of current on human beings and livestock Part 1: General aspects

60652

Loading tests on overhead line towers

60720

Characteristics of line post insulators

60794 60794-4-1

Optical fibre cables Part 4-1: Aerial optical cables for high voltage power lines

TR 60815

Guide for the selection of insulators in respect of polluted conditions

TR 60826

Loading and strength of overhead transmission lines

60865-1

Short-circuit currents—Calculation of effects

61467

Insulators for overhead lines with nominal voltage over 1 000 V—  AC power arc tests on insulator sets

TR 61597

Overhead electrical conductors—Calculation methods for stranded  bare conductors

ISO 14713 12494 EN 50341 BS BS EN 50341-1

Protection against corrosion of iron and steel in structures - Zinc and aluminium coatings - Guidelines Atmospheric icing of structures Overhead Electrical Lines Exceeding AC 45 kV – Part 1: General Requirements— Common Specifications Overhead Electrical Lines Exceeding AC 45 kV – Part 1: General Requirements— Common Specifications

ASCE 10-97

Design of Latticed Steel Transmission Structures

48-05

Design of Steel Transmission Pole Structures

CIGRE TB196

Diaphragms for lattice steel supports

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

IEEE 691

117

DRAFT ONLY

Guide for Transmission Structure Foundation Design and Testing

ARPANSA

Draft Radiation Protection Standard for Exposure Limits to Electric and Magnetic Fields 0 Hz – 3 kHz

ICNIRP

Guidelines for Limiting Exposure to Time-Varying Magnetic, and Electromagnetic Fields (Up To 300 Ghz)

Electric,

* Available to members though Energy Networks Australia (ENA)

A2 RELATED DOCUMENTS

Attention is drawn to the following related documents: AS 1289 1289.6.3.1

Methods of testing soils for engineering purposes Method 6.3.1: Determination of the penetration resistance of a soil—Standard penetration test (SPT)

1657

Fixed platforms, walkways, construction and installation

1798

Lighting poles and bracket arms—Preferred dimensions

2560

Guide to sports lighting

2979

Traffic signal mast arms

AS/NZS 1158 1158.1.3

stairways

Minimum design loads on structures Dead and live loads and load combination Earthquake loads

1891 1891.4

Industrial fall arrest-systems and devices Part 3: Fall-arrest devices

4203 IEC 60038 60050 60050-441 60050-466 60050-471 60050-601 60050-604

ladders—Design,

Road lighting Part 1.3: Vehicular traffic (Category V) Lighting—Guide to design, installation, operation and maintenance

1170 1170.1 1170.4

 NZS 3115

and

Specification for concrete poles for electrical transmission and distribution Code of practice for general structural design and design loadings for  buildings—Vol 1 IEC standard voltages International Electrotechnical Vocabulary Chapter 441: Switchgear, controlgear and fuses Chapter 466: Overhead lines Chapter 471: Insulators Chapter 601: Generation, transmission and electricity—General Chapter 604: Generation, transmission and electricity—Operation

distribution

of

distribution

of

60287

Electric cables—Calculation of the current rating

60287-3-1

Part 3-1: Sections on operating conditions—Reference operating conditions and selection of cable type 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

IEC TR 60479 TR 60479-1

118

DRAFT ONLY

Guide to effects of current on human beings and livestock Part 1: General aspects

TR 60575

Thermal-mechanical performance test and mechanical performance test on string insulator units

60724

Short-circuit temperature limits of electric cables with rated voltages of 1 kV (Um = 1,2 kV) and 3 kV (Um = 3,6 kV)

60797

Residual strength of string insulator units of glass or ceramic material for overhead lines after mechanical damage of the dielectric

60909

Short-circuit current calculation in three-phase a.c. systems

61109

Composite insulators for a.c. overhead lines with a nominal voltage greater than 1 000 V—Definitions, test methods and acceptance criteria

TR 61211

Insulators of ceramic material or glass for overhead lines with a nominal voltage greater than 1 000 V—Puncture testing

TR 61774

Overhead lines—Meteorological data for assessing climatic loads

62219

Formed wire concentric lay overhead electrical stranded conductors1

EN EN ISO 1461

Hot dip galvanised coatings on fabricated ferrous products—  Specifications and test methods

EN ISO 9001

Quality systems. Model development, production

for

quality

assurance

in

design,

A3 REFERENCES

1

BURGESS, S., SALINGER, J., TURNER, R. and REID, S., 2007. Climate Hazards and extremes – Taranaki region. High winds and tornadoes. NIWA report WLG2007048, 84 pp.

2

CARMAN, W.D. and BAXTER, B. Transmission Structure Hazard Mitigation Strategies. 11th CEPSI Conference, Kuala Lumpur, October 1996.

3

CIGRE STUDY COMMITTEE 23 – 1996, Brochure 105, The Mechanical Effects Of Short-Circuit Currents in Open Air Substations (Rigid and Flexible Bus-Bars), Volume 1.

4

CIGRE STUDY COMMITTEE 23 (Substations) Working Group 23-03, The  Mechanical Effects Of Short-Circuit Currents in Open Air Substations (Rigid and  Flexible Bus-Bars) , Volume 2

5

CIGRE STUDY COMMITTEE 23—1996, Companion Book Of CIGRE Brochure 105 (Part II)

6

DURA ŇONA, V., STERLING, M. and BAKER, C., 2007.  An analysis of extreme non-synoptic winds. Journal of Wind Engineering and Industrial Aerodynamics, 95, 1000-1027

7

ESAA EG-1(1997)  ESAA Substation Earthing Guide.

8

GIBBS, H.  Inquiry into Communi ty Needs and High Voltage Transmission Line  Development . Published by New South Wales Government, 1991.

9

Guidelines for the Management of Electricity Easements. EC20, Electricity Council of NSW, February 1992. 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

119

DRAFT ONLY

10

HOWAT, C. and COOK, J.  An Assessment of the Hazards Associated with Siting Swimming Pools Near Substations and Transmission Lines. ESEA Conference, Sydney, August 1991.

11

KIESSLING, NEFZGER, NOLASCO and KAINTZY, K.  Overhead Power Lines (planning design construction). ISBN 3-540-00297-9, pp. 162-163.

12

MORGAN, V.T. Thermal Behaviour of Electrical Conductors, Steady, Dynamic and  Faul t-Current Rati ngs. Published in Brisbane by John Wiley and Sons Inc, 1991.

13

RAD, F.N., GARG, V.K. and COURTS, A.L.  Study of Distribution of Ground Fault Currents in Below Grade Swimming Pools Located Near Transmission Lines. IEEE Transactions on Power Delivery, 1980.

14

REESE, S., REVELL, M., TURNER, R., THURSTON, S., REID, S., UMA, S.R. and SCHROEDER, S., 2007. Taranaki Tornadoes of 4-5 July 2007: Post event damage  survey.  NIWA report WLG2007-71, 43 pp.Reid, S.J., 1987. Wind speeds for engineering design. New Zealand Engineering , March 1, 1987, pp 15-18.

15

REID, S. and TURNER, R., 2008. Gust speeds for downslope sites using 2D modelling. Journal of Wind Engineering and Industrial Aerodynamics. Submitted.

16

ROSS H.E. et al,  Recommended procedures for the safety perf ormance eval uation of highway safety features, NCHRP Report 350, National Cooperative Highway Research Program, National Academy Press, Washington D.C., 1993

17

SMOOT, A.W. and BENTEL, C.A. Electric Shock Hazard of Underwater Swimming  Pool Lighting Fixt ures . IEE Transactions of Power Apparatus and Systems, Vol. 83, September 1964, pp.945-964.

18

TAIT, A., and REID, S., 2007.  An analysis of extreme high winds in the Gisborne district . NIWA report WLG2007-25. 30pp

19

WOODHOUSE, D.J., NEWLAND, K.D, and CARMAN, W.D. Development of a Risk  Management Policy for Transmission Line Easements. Distribution 2000, 4th International Distribution Utility Conference, November 1997, Sydney.

20

HOLMES, J.D.,  Physical modelling of thunderstorms downdrafts by wind tunnel jet. 2nd AWES Workshop 20-21 February 1992. Monash University, Clayton, Victoria.

21

LETCHFORD, C.W. and ILLIDGE, Topographical effects in simulated thunderstorm downdrafts by wind tunnel jet . 7th AWES Workshop, 28-29 September 1998. Auckland, New Zealand.

22

PANEER R., SELVAM and HOLMES, J.D., Thunderstorm downdrafts from a point of view of building design. 1st AWES Workshop, 7-8 February 1991. Pokolbin, New South Wales.

23

DAVENPORT, A.G., SURRY, D., GEORGIOU, P.N and LYTHE,G., The response of transmission towers in hilly terrain to typhoon winds. The University of Western Ontario, Faculty of Engineering Sciences, London, Ontario.

24

GEORGIOU, P.N., SURRY, D. and DAVENPORT, A.G., Codification of wind loading in a region with typhoons and hills. Proc. of the Fourth Int. Conference on Tall Buildings, Hong Kong and Shanghai, April/May 1988. CHENG, Y.K. and LEE, P.K.K. Eds. Organizing Committee of the Conference, Hong Kong, 1988. Vol. 1, 252258.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

120

DRAFT ONLY

APPENDIX B

WIND LOADS (Normative) B1 AUSTRALIA

In Australia, transmission lines and their supporting towers and poles are vulnerable to extreme wind loads from both convective downdrafts (downbursts, microbursts) and synoptic winds (e.g. gales from East Coast lows in NSW, tropical cyclones in Queensland and WA). Analysis of all extreme winds in Australia has shown that coastal stations experience many more high gusts per annum than do inland stations, although the number of extreme convective downdraft gusts from small thunderstorms are similar. Generally it is clear that large gusts at inland stations within Australia are all generated by convective downdrafts. At coastal locations in the non-tropical regions, large gusts can be  produced by both large-scale synoptic events or by convective downdrafts. Figure 1 shows a zoning map to determine which storm type should be considered in design for wind. On the mainland, the regions on this map are delineated by a boundary 200 kilometres from the smoothed coastline.  Zone I  —shown in blue in Figure B1, designs are to provide only for winds from synoptic events (including tropical cyclones in Northern Australia), using multipliers from AS/NZS 1170.2, together with ‘c onventional’ span reducti on factors as provided in the following sections.  Zone II  —shown in beige, (i.e. inland Australia) desi gns are to provide only for convective downdrafts. Wind multipliers for terrain-height, and topography and span reduction factors for these events are as provided in the following sections.  Zone III  —shown in green in Figure B1, both events can occur, with approximately equal  probabili ty, and designs are to provide for both types of events.  NOT E: Fig ure 1 is not intended to show the zoning system for the magnitude of the win d gust speed – just the types of event producing the extreme gusts required to be considered for structural design. Reference should be made to AS/NZS 1170.2 for the relevant wind velocities relevant to the line for the selected security level and design life as defined in Section 6.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

121

Zone I - Synoptic winds only

DARWIN

DRAFT ONLY

Weipa

McDonnel Creek  Moreton Cooktown Cairns

Broome 200 km Croydon Onslow

Zone II - Convective downdrafts only

Carnarvon

Geraldton PERTH

200 km  Tow nsvi ll e Bowen Mackay Rockhampton Bundaberg Maryborough 25 ˚  BRISBANE Grafton Coffs Harbour

125˚  200 km

SYDNEY 

Zone III - Synoptic and convective Zone I - Synoptic winds only

HOBART 

FIGURE B1 WIND REGIONS FOR AUSTRALIAN DESIGN WIND GUST TYPES

B2 NEW ZEALAND

In New Zealand, transmission lines and their supporting towers and poles are vulnerable to extreme wind loads from both convective downdrafts (downbursts and micro-bursts) and synoptic winds (e.g., gales associated with mid-latitude cyclones throughout the country and high winds from ex-tropical cyclones over the North Island). In addition there are regions in the leeward zones close to high mountain ranges where katabatic or downslope high velocity winds occur in which these structures are also vulnerable. Generally it is clear that large gusts at inland stations outside of leeward zones are generated by convective downdrafts. Wind zones for the North and South Islands of New Zealand are shown in Figure B2

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

122

DRAFT ONLY

FIGURE B2 WIND REGIONS FOR NEW ZEALAND

B3 SYNOPTIC WIND REGIONS (AUSTRALIA ZONE I AND ZONE III AND NEW ZEALAND ZONES REGIONS W, A6 AND A7 )

All structures shall be designed for a 3 s gust regional wind speeds f or various return  periods as defined in AS/NZS 1170.2. The basic site design velocity shall be determi ned by selecting an a ppropriate return period for the line ( See Section 6) and applying formula variables from AS/NZS 1170.2.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

123

DRAFT ONLY

Cyclonic wind amplification factors  F c  and  F d  provided in AS/NZS 1170 shall be taken as 1.0 for all overhead lines, based on performance of overhead lines in cyclonic areas over time. The calculation of wind forces on structural elements is based on the wind pressure on the structural element and the net drag coefficient for the element. AS/NZS 1170.2 deals with the calculation of wind velocities (for synoptic conditions) and drag coefficients for the more common structural shapes. The equations presented here are intended to provide a context for the drag (or force) coefficients that are of particular relevance to overhead lines. Designers are referred to AS/NZS 1170.2 as appropriate. The selection of the regional wind speed should be based on the line’s location. Where an overhead line is of significant length, variations in wind loading may be required. The site design wind speed is the basic regional wind speed modified for the effects of the topography and terrain that the line traverses. V des, θ  shall be taken as V sit, β   for the purpose of determining wind actions on structures, conductors and elements of structures. where V des, θ (z)= V sit, β

=

building orthogonal design wind speeds as a function of height z wind speeds for a site, varying according to compass direction

AS/NZS 1170.2 provides regional wind speeds for each of the range of return periods. The design site wind speed shall be taken as— V z

=

V R M    d M z ,cat M s M t

where  M z,cat =  M d

=

gust winds speed multiplier for terrain category at height  z . Refer AS/NZS 1170.2 wind direction multiplier. Refer to AS/NZS 1170.2.

 NOT E: For all overhead lin es this sh all be taken as 1 .00.

 M s

=

shielding multiplier. Refer to AS/NZS 1170.2

 M t

=

topographic multiplier for gust wind speed. Refer to AS/NZS 1170.2

V R

=

basic regional wind velocity for the region corresponding to the selected return period. Refer AS/NZS 1170.2

Designers should be aware that changing land usage may alter the terrain category. for the conductors may be taken as the mean height of the conductors at EDT  z  above the terrain. for structures under 50m may be taken at the 2/3 structure height or at the  z  centre of each panel in lattice towers.  M d < 1.0 may be applied when determining design loads for sections of lines.  M s is normally taken as 1.0.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

124

DRAFT ONLY

B4 DOWNDRAFT WIND REGIONS REGIONS (AUSTRALIA ZONE II AND ZONEIII AND NEW ZEALAND ZONES REGION A 7)

Convective downdraft wind gust sometimes referred to as high intensity winds (HIW) are generated by severe thunderstorms and are the dominant design winds that occur across most regions of Australia and New Zealand. They take the form of downdrafts associated with cold air and hail columns, meso–cyclonic cells and tornadoes within storm front systems or mature subtropical thunderstorm cells. Evidence from the damage of many severe storms across Australia and New Zealand suggests that these events are responsible for many of the wind-related failures on overhead lines. They occur in both coastal and inland regions and are associated with, and embedded in many severe thunderstorms. They can also occur within tropical cyclone storm cells. B4.1 Downdraft winds

Downdraft winds, more commonly referred to as downbursts, macrobursts, or microbursts; are high velocity wind columns of cold air that can form within a thunderstorm cell, usually  but not always associate d with a hail column. The cold air column falls verticall y from great height and strikes the ground, and due to the translation of the storm cell the wind draft radiates from the impact site. The resulting gust widths can vary in width from typically a hundred metres to a kilometre. These gusts create damage swaths in vegetation at ground level and the wind can envelop one or more spans simultaneously and renders the application of the synoptic wind based span reduction factors inappropriate.. A span reduction factor shall be applied as provided in Figure B6 Studies have indicated that downdraft winds can have significant variability in direction due to their association with hail and cold air downdrafts and are also influenced by large scale topographical features. The maximum velocity also has been observed in recent failures to  be generally above a plane at approximat ely 15 m above ground as a result of the localized influence of vegetation and ground surface roughness. Downdraft gust wind speeds are provided in AS/NZS 1170.2 for each region and for the range of return periods. Wind pressures are to be calculated as for synoptic winds except for modification to M z  and  M t factors as provided below. Terrain -Height Multiplier M z,cat   has been found from laboratory and field tests to vary with height as shown in Figure B3 and according to the following rules: Height (m)

 M z,cat

0–50

1.0

50–100

1.0–0.5*(H–50)/50

Above 100

0.5

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

125

DRAFT ONLY

Downdraft Mz,cat

   ]   m    [    t    h   g    i   e    H

Mz,cat

FIGURE B3 TERRAIN-HEIGHT MULTIPLIER FOR CONVECTIVE DOWNDRAFTS

Topographic multiplier M t,downdraft   has also been found from research to be half of the values  provided in AS/NZS 1170.2 or synoptic winds.  M t,downdraft   values shall be calculated in accordance with the following:  M t,downdraft

=

1 + 0.5 ( M t,synoptic −1)

B4.2 Tornadoes (applies to all high security/high reliability overhead lines only such as regional transmission interconnectors) B4.2.1   General

Evidence exists of the occurrence of Tornadoes in several regions around Australia and  New Zealand of an intensity
The following provision should be made for tornado wind loads on long high security and high reliability lines, in particular, important long lines. Tornadoes are small rota tional (50–100 m diameter) cells usually embedded within and traversing at the same speed and direction as the thunderstorm. The thunderstorm translational speed could be in the order of 10–20 m/s and the tornado circumferential speed of 50 m/s or higher. Combining the two speeds gives a resultant gust speed of the order of 60+m/s

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

126

DRAFT ONLY

Tornadoes crossing lines between supports are unlikely to cause any structural damage but may cause aerial conductors to clash resulting in feeder trips. Tornadoes intercepting with supports have caused isolated known lattice structure failures in recent decades in Australia and with a higher frequency in overseas countries. Adopting the 60 m/s as the ultimate regional tornado wind speed (for all but the high importance lines), and taking all the wind (M) multipliers as 1.0 gives a design dynamic wind pressure of 2.2 kPa. This shall be applied as a uniform pressure (ie unmodified for height) to the support and insulators from any direction. In addition wide tower structures shall be also designed for a torsion wind (of the same  pressure) rotating abut the support centre. Each towe r body face be subj ected to in plane wind, and each crossarm face to projected perpendicular wind in a consistent rotational direction as indicated in Figure B4 .1 and Figure B4.2.  No wind is applied to the conductors in either case.

FIGURE B4.1 SQUARE BASED TOWERS

FIGURE B4.2 RECTANGULAR BASED OR WIDE TOWERS

B5 WIND PRESSURES

The dynamic pressure qz  shall be calculated as follows: qz

=

0.6V z2

× 10 −3 kPa

. . .B1

B5.1 Wind pressures on lattice steel towers

For each panel in the tower, the force on structural sections in the direction of the wind shall be calculated as follows:  F x

=

q z K xC d A*

. . .B2

where  K x

represents factors accounting for aspect ratio, wind direction and shielding of the member. Refer to AS/NZS 1170.2 for specific values.

C d

is the drag force coefficient of the member.

 A*

is the projected area of the structure section under consideration in a plane normal to the wind direction.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

127

DRAFT ONLY

For lattice towers that are essentially square in plan the force in the direction of the wind on the whole tower section under consideration shall be calculated as follows:  F s θ

=

q zC d A

where =

is the projected area of one face of the structure section under consideration in a vertical plane along the face.

=

drag force coefficient in accordance with AS/NZS 1170.2

 A C d

TABLE B2 LATTICE TOWER PANEL DRAG COEFFICIENTS FOR MULTIPLE FRAMES AND SINGLE FRAMES Solidity

Square tower

C d 0°

Single frames

C d 45°

C D 

Shielding

0.1

3.4

3.9

1.9

0.8

0.2

2.9

3.3

1.8

0.7

0.3

2.5

3.0

1.7

0.5

0.4

2.2

2.7

1.6

0.4

0.5

2.0

2.5

1.6

0.3

0.6

1.8

2.2

1.6

0.2

Solidity is the ratio of solid projected area to total enclosed area. For rectangular towers which are symmetrical about each axis—  F s θ

=

q z [ C d1  (  A1  +

η A 3) k θcos 2 θ +

C d2  (  A2 +

η A4)  k θsin 2θ]

. . .B3

where  A1 ,  A3 and  A2,  A4  are projected areas on longitudinal and transverse faces respectively C d

=

drag force coefficient for single frames (panels) (refer Table B2)

η

=

shielding factor (refer Table B2)

k θ

=

factor for angle of incidence

θ of wind to frames

(calculated by the equation)— k θ

=

1 + k 1 k 2 sin 2(2 θ),

. . .B4

where k 1

=

0.55

k 2

=

0.2 for

k 2

=

k 2

=

k 2

=

δ for 0.2 < δ ≤ 0.5 1 − δ for 0.5 < δ ≤  0.8 0.2 for 0.8 < δ ≤ 1.0

δ ≤  0.2

Where ancillaries such as antennae, mounting frames, cable runways, signage and banners are attached to a tower that have significant area, they should be included in the calculated force using the appropriate C d, area and shading factor from Australian Standards and component manufacturers information. The interference factor ( K in ) shall be taken as 1.0 in all cases for lattice towers. Refer to AS/NZS 1170.2.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

128

DRAFT ONLY

There is some variation in recommended C d factors for single and multiple frames between the va rious nat ional c odes. T he approach used i n BS 8100 Part 1 provides detailed  procedures for calculation of drag coefficients for rectangular (in plan) towers for different angle of incidence of wind. The BS 8100 Part 1 approach has been used here. Alternatively computational techniques may be used that provide for the automatic calculation of wind effects on individual structural elements of tower structures,  particularly for some towers of less common geometry where the wind on face method can  be difficult to implement. An example of such tower geometry is a flat configuration single circuit tower with 4 longitudinal faces in the upper body and a large cross beam with a small longitudinal face area. The alternative method is to load all members of the tower based on fluid dynamic  principles, an average drag factor and simplified member area calculations . This method would be difficult to implement using hand calculations but very simple to implement in a computer program. The results are generally conservative in comparison to the face method. The resulting force on each member is perpendicular to the member longitudinal axis and in the plane formed by the wind velocity vector and the member axis.

FIGURE B5 FORCES ON A MEMBER

The force is determined by the following equation:  F m = C f qz A mcos 2(α)

where  F m

=

resultant force on the member

qz

=

dynamic pressure at the member mid height

 A m

=

simplified member area – length x width

C f 

=

drag force factor angle members C f  = 1.6 round members C f = 1.0

α

=

angle between wind velocity vector and the normal to the member axes

From 3D geometry the resultant force direction vector can be determined using the vector  products: T 

=

W  ×  M  8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

129

 D

=

T  ×  M 

W

 –

wind velocity vector

 M 

–

member axis vector

T 

 –

vector perpendicular to the wind-member plane

 D

–

resultant force direction vector

DRAFT ONLY

Angle a  can be calculated form scalar product of the wind direction and resultant force direction vectors: cos( a)

=

WD

. . .B5

W D

The resultant force components in the global coordinate directions ( X, Y, Z ) can be finally calculated by multiplying the resultant force value by the normalized direction vector. B5.2 Wind pressure on poles

Due consideration shall be taken on the affect on the aerodynamic shape factor C fig   for  poles due to the attachment of all ancill aries Significant attachments to circulate cross-sections such as ladders, pipes etc will induce aerodynamic separation and in these case is C d = 1.2. The aerodynamic shape factor C fig shall be determined for specific elements, surfaces or  parts of surfaces in accordance with AS/NZS 1170.2 For timber poles a minimum C d  of 0.9 applies. For other poles of circular or polygonal cross section— (a)

the determination of the appropriate forces can be taken as the sum of the forces for the components of the pole and the ancillaries attached to the pole; or

(b)

a detailed approach can be adopted by considering the height of the structure as a series of sections. A minimum of 5 sections should be considered and the section should be of similar construction. Each section shall in turn be assessed to determine the proportion of projected area of the ancillaries to that of the pole to determine the appropriate C fig / C d  and the appropriate  Az. as follows: (i)

if the pole surface is smooth and the projected area of the ancillaries is less than 0.01 of the projected area of the pole section under consideration, then the total force on the section shall use the C fig /C d  of the smooth pole only and  A z  shall be the projected area of the pole only.

(ii)

if the pole surface is smooth and the projected area of the ancillaries is between 0.01 and 0.05 of the projected area of the pole section under consideration, then the total force on the section shall use the C fig / C d  of the non smooth pole only and  A z shall be the projected area of the pole only.

(iii)

if the pole surface is smooth and the projected area of the ancillaries is greater than 0.05 of the projected area of the pole section under consideration, then the total force on the section shall use the C fig /C d  of the non smooth pole and the appropriate C fig /C d  of the ancillary and Az shall be determined for both the  projected area of the pole and the ancillary.

(iv)

if the pole is not smooth then the same procedure as i), ii) and iii) shall be adopted with the C fig /C d of the pole being that for a non smooth section.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

130

DRAFT ONLY

B5.3 Wind forces on conductors

Wind force perpendicular to conductors shall be calculated as follows:  F c

=

q zCLdSRF cos 2α (N)

=

drag coefficient of conductor . This is assumed to be equal to 1 in the absence of more accurate information.

where C 

 NOT E: This value may vary between 1.2 and 0.8 dependent on conductor diameter outer surface roughness, and wind velocity. Smooth profile conductors are available that specifically provide even lower wind drag.

 L

=

conductor length under consideration (m)

d 

=

conductor diameter (m)

SRF  =

span reduction factor (see below)

α

angle between wind direction and the normal to the conductor (deg)

=

The span reduction factor takes account of the spatial characteristics of wind gusts and inertia of conductors. B5.3.1 Span reduction factor (SRF) for synoptic wind regions

For regions governed by synoptic winds Figure B6 applies. The curve in Figure B6 is based on the following relationship: SRF

= 0.59 +

⎛ − L ⎞ ⎜ ⎟ 0.41e⎝ 210 ⎠

Span Reduction Factor

   F    R    S

Span [m]

FIGURE B6 SRF FOR SYNOPTIC WIND REGIONS

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

131

DRAFT ONLY

B5.3.2 Span reduction factor (SRF) for cyclonic wind

For cyclonic wind Figure B7 applies. The curve of Figure B7 is based on the following relationship: SRF

= 0.59 +

⎛ − L ⎞ ⎜ ⎟ 0.5e⎝ 140 ⎠

Cyclonic Wind Span Reductio n Factor 

   F    R    S

Span [m]

FIGURE B7 SRF FOR CYCLONIC WIND REGION

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

132

DRAFT ONLY

B5.3.3 Span reduction factor (SRF) for downdraft wind regions

For regions governed by downdraft wind Figure B8 applies. The curve of Figure B8 is  based on the following expressions: For spans ≤200 m For spans >200 m

SRF = 1.0 SRT = 1.0

−

( L  − 200 1000

  0.3125

For tension calculations on tension sections greater than 1000 m, the synoptic wind should  be used instead of the downdraft wind.

Span Reduction Factor

   F    R    S

Span [m]

FIGURE B8 SRF FOR DOWNDRAFT WIND REGIONS

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

133

DRAFT ONLY

B5.4 Wind forces on insulators and fittings

Force on insulators and fitting assemblies shall be considered and is given by the following expression: =

qz.CdA

C 

=

1.2

 A

=

projected area of insulators and fittings in true length normal to wind (m²) – (See Figure B9)

 F i

where

These forces shall be considered to act on the attachment point on the support in the wind direction.

 Attac hm en t poi nt F i = q z . C d A

   h    t   g   n   e    l   e   u   r    T

 V iew al ong line Projected area is shaded  View tran sver se to lin e

FIGURE B9 PROJECTED AREA OF INSULATOR STRINGS

B6 TOPOGRAPHICAL EFFECTS

The following information is provided for guidance in the design layout of overhead lines. Reference should be made to CIGRE TB 256 for detailed design methods where required. AS/NZS 1170.2 provides general rules for speed-up of winds over hills and escarpments. There are however limitations for the application of these general rules for treating extreme terrain roughness, predominate hill forms and high mountainous escarpments, that can be encountered in the siting of an overhead line route. In particular closer attention needs to be given to the effects on wind speeds in more varying terrain where the roughness characteristics change significantly over short distances, down to the scale of an overhead line span; topographic generated features such as corner effects along the foot of mountains and hills; funnelling effects in valleys or in  between hills; vortex formati on behind steep terrain as well as other effect s that may cause significantly increased wind speeds in the local terrain. Such topographic features may have length scales ranging from a hundred metres up to several kilometres. Experiences from overhead line collapses and damage to buildings and other structures during the last fifty years, have revealed that many of these effects were neither known of at that time nor taken into account by designers. 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

134

DRAFT ONLY

Local wind speeds can be reduced or increased due to the topography. It is a matter of fact in hydrodynamics that when the wind is reduced in some places, it shall likewise be increased in other places in order to comply with the equation of continuity. Such increases are often found in places like— (a)

over hill crests;

(b)

near sharp edges (escarpments) exposed to high level winds over surrounding terrain;

(c)

on the side of hills and mountains ‘corner effect’;

(d)

in valleys or fjords where the airflow may be compressed locally ‘funnelling effect’;

(e)

rotor formation behind a mountain; and

(f)

 behind steep mountain sides (or edges) where particular turbulence may be formed ‘vortex streets’.

B6.2 Turbulence generation behind steep hills and ridges

In complex terrain it is often experienced that wind speeds on the leeward side of a steep mountain or hill may be significantly higher than they are on the windward side. This may occur both on— (a)

the leeward side of a rounded mountain ridge perpendicular to the wind; and

(b)

 behind singular hills with st eep slopes on the windward side.

Typical areas for such phenomena are within and on the downwind side of high mountain ranges. The same effects are also frequently found on the downwind side of major mountain or isolated hill ridges of even smaller scale. The occurrence of the second phenomenon b) is not as well known as the first, mainly  because of more limited extensions of each hill, and the possible lack of recent reported wind damage. Effects of this kind are generally known as ‘rotors’ and ‘vortex streets’. The distribution of wind velocity with height is known to be significantly different in narrow windstorms such as severe thunderstorms than in fully developed gales or cyclones. Physical and numerical modelling of thunderstorm downdrafts by Holmes, (See Paragraph A3, reference [20]), Letchford, (See Paragraph A3, reference [21]), Selvam and Holmes, (See Paragraph A3, reference [22]) have shown that there is a maximum wind speed developed between 0.3 and 0.6 delta above ground. Where delta is the height at which the velocity reaches half its maximum value. Above this height the velocity has been found to drop off markedly. These studies indicate that a structure approximating a 50–70 m tower will be fully loaded over its height if impacted by these high wind gusts. These studies have also examined the speed up effect that occurs over hills and ridges. This speed up is usually referred to as a topographical multiplier M t, which is the ratio of speed at a height over the feature to the speed at the same height in flat terrain. Holmes, (See Paragraph A3, reference [20]) investigated a single hill of slope 0.25 and found that the speedup on the crest was a maximum of 1.2 near ground and decreased linearly to an effective height of 100 m above the crest of the hill. Studies by Letchford, (See Paragraph A3, reference [21]) on embankments from 0.2 to 0.6 found similar results with a slight increase for the steeper ridges. This later work recommends, in the absence of further data, a value of M t = 1 + slope to be adopted and be applied at a height of 10 m above the ridge where the slope exceeds 0.10.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

135

DRAFT ONLY

B6.3 Escarpments

Observations of high wind damage during tropical cyclones in Northern Queensland indicate that speed up effects can also occur during high winds on the upper slopes of coastal mountain range escarpments, crest of escarpments. Analysis of damage patterns suggest a speed up of 1.2 ×  basic gust wind velocities can frequently occur. The upper level of amplification of this speedup is dependent on the escarpment slope profile, height and  basic wind velocit y. AS/NZS 1170. provides for values up to 1.5. Overhead lines traversing an escarpment need to be carefully evaluated and have structures  position to avoid as far as possible, these potential extreme gust zones immediately below the escarpment edge, and in the zone immediately behind the crest. If siting cannot be avoided then stronger structure types should be assessed. Structures located on the slopes of escarpments and subject to the speed up effects also need to accommodate the potential for resonance caused to the structure by localised wake turbulence from terrain variations. Tower failure investigations carried out by Prof A. Davenport, (See Paragraph A3, references [23] and [24]) in Hong Kong confirmed that earthwork benching to enable towers to be constructed, created vortex shedding during a Typhoon wind storm that resulted in severe resonance of tower members and resultant fatigue failure of towers. B6.4 Local effects B6.4.1 Channelling effects

Where wind storms have the potential to track within frontal weather system over relatively flat to undulating land, they normally travel in a predominate direction. However, thunderstorm winds generated from such systems occur as outflow winds or as isolated wind phenomena such as down bursts or severe downdrafts, are normally characterized by narrow damage paths with widths up to 2000 m at ground level. When these high i ntensity wind gusts with velocities ranging from 30–60 m/s approach local mountains, the wind flow patterns may be significantly modified and can be channelled and redirected. Placement of structures within predominate features such as gaps between mountain ridges, in narrow river valleys through mountainous zones, and on low ridges and plateaus within higher mountain zones can be severely effected. Velocity speedup, local turbulence and wind eddies can have complex effects on structure wind loadings. Evidence from transmission line tower failures within a narrow valley between 500 m high mountain ridges in Queensland, during a severe thunderstorm downburst has indicated speedup effects of 30% at 10m reference wind velocities and possible high turbulent effects 30m height above the valley floor as they impacted on a 54 m high structure. Wind gust directional changes of 45° were also observed. B6.4.2 Funneling effects

High intensity wind flows along valleys provide directional control of wind flow patterns. Where there is a narrowing of these valleys, such as towards and at the valley head, there is the potential for wind speed up effects to occur. Studies for wind turbine sites indicate velocity speeds can increase typically up to 20% above the crest. In a similar way to the channelling effects of valleys, converging mountain ranges and  passes have a simi lar effect on wind velocities. Structure sites located within narrow passes need to be carefully considered.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

136

DRAFT ONLY

B6.4.3 Katabatic wind effects

In many high mountainous regions, down drafts of cold air from high plateaus, ice and snow regions, and from high altitude air flows as a result of large scale temperature inversion or draw down effects from weather systems, can occur. These are sometimes more pronounced in some falling valleys from these mountainous regions and wind velocities up to 60 m/s have been recorded. These valley areas are in most cases denuded of vegetation and have normally never been used for residential purposes. Where vegetation has survived over time evidence usually exists of wind effects to plant growth. As a general rule this type of wind occurs for extended periods with the potential to significantly damage any structure placed within its path. B6.4.4 Extensive fetch distances

Overhead line structure placement often needs to occur on elevated positions where the line route passes over low ranges or around other significant topographical features. Such positions are more exposed to any approaching significant wind storm and in some cases the terrain at the elevated site may be Category 1 even though the immediate local terrain could appear to be Category 4. (reference AS/NZS 1170.2 ) Consideration should be given to providing increased structure design wind loadings, or strength for such situations. B6.4.5 Air turbulence near airports

Overhead lines located in close proximity to the flight paths of major airport runways may  be subject to the effects of wind turbulence effects from some types of aircraft during take off. Rotating vortexes have been found to spin off the wingtip zones of the aircraft and cause clashing of conductors as these turbulent effects impact lines. Under grounding of overhead lines should be adopted if these effects are experienced.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

137

DRAFT ONLY

APPENDIX C

SPECIAL FORCES (Normative) C1 GENERAL

This Appendix sets out requirements to be considered in overhead line design regarding special forces that may be encountered on some lines. C2 FORCES DUE TO SHORT-CIRCUIT CURRENTS

In flexible conductor systems, such as, landing spans to the substation gantries from towers/poles and spans within close proximity to the substation, the mechanical effects due to short-circuit effects produce conductor tensile forces resulting from the swing-out of elastically and thermally expanded conductors, which in turn can be the cause of secondary short-circuits. These conductor tensile forces when compared in magnitude with the maximum wind tensions can be significantly high and require the designers to take these into account when designing the supporting structures. The systems of equations required to represent the mechanical response of the supporting systems are non-linear. In the IEC 60865-1 a simplified method is stated for calculation of maximum values of the following:

Effect

At short-circuit inception * bundled conductors

At short-circuit inception *single conductor

Force 1 at time t 1

Force 2 at time t 2

Force 3 at time t 3

Horizontal displacement

Pinch force, F  pi (tensile force in the conductor) when the subconductors clash or reduce their distance without clashing

Short-circuit tensile force, F t due to swingout in the conductor  bundle during or at the end of the short-circuit current flow

Short-circuit drop force, F f  (tensile force in the conductor) when the span falls down from the highest  point of movement

Horizontal displacement, bh, during swing-out of the span

 —

Short-circuit tensile force, F t due to swingout in the conductor during or at the end of the shortcircuit current flow

Short-circuit drop force, F f  (tensile force in the conductor) when the span falls down from the highest  point of movement

Horizontal displacement, bh, during swing-out of the span

*The times t 1, t 2  and t 3  are derived from the total short-circuit duration. *The above forces,  F  pi ,  F t  and  F f   are related to the initial static tension existing within the span. Therefore the initial static tension or everyday tension is an important parameter in the calculation of the above forces.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

138

DRAFT ONLY

The simplified approach depends on general data such as span length, everyday tension, and distance between phases, structure stiffness, conductor data, short-circuit current and duration. In particular this may involve the following: (a)

A short-circuit level should be specified with reference to the levels specified for switchgear rating. For information, the short-circuit level (short-circuit 3-phase current, ISC_3) in a substation may exceed the following specified levels; (i)

40 kA for 420 kV highest system voltage;

(ii)

31.5 kA for 245 kV highest system voltage;

(iii) 20 kA for lower voltages. (b)

The short-circuit current used for checking is the maximum level allowed by the substation equipment (even if it is not attained in the present stage of development of the transmission system) in order to facilitate further evolution of the system.

(c)

The supports close to the substation should be checked taking into account the reduction of the short-circuit current due to line impedance.

(d)

The support check ceases where the short-circuit current decreases to less than the above specified levels.

(e)

This rule should be applied to check 5 to 10 spans from the substation. Usually, only 1 span is affected by the excessive swinging and 1 or 2 supports adjacent to the substation are subjected to the mechanical overloads from short-circuits.

(f)

Only the 2-phase short-circuit current, ІSC2, should be checked as the most restrictive. As an approximation—  ISC 2

=

3 2

× ISC 3

. . .C1

The reduction of short-circuit current with time should also be taken into account according to the electrical characteristics to the system. The fault time should be considered in accordance with the type of protection relays used and the possibility of covering breaker failure or not (breaker tripping time without failure estimated at 80 to 200 ms usually with solid state relaying). The load combinations required to assess and design structures able to withstand shortcircuit forces is of considerable interest, in addition the safety factors taken into account on the generated tensile forces due to short-circuit is important so as not to over-estimate this effect. Wind load and short-circuit load both vary in time, independently of each other. In addition, the direction of wind varies. There are no mathematical procedures available or standards for a true or reasonable combination of short-circuit and wind loads. Therefore it would be sufficient to consider a 25% utlimate wind effect in the load combination related to shortcircuit loadings. In practice short circuit loadings are treated as dynamic loadings due to their short time evolution. In the simplified approach this load is treated as an ‘exceptional load’ and a safety factor of 1.25 is recommended. In the case of short impulsive loads for which large stress rates occur, structural steels experience a delayed plastic flow phenomenon that results in a temporary increase in strength (yield point).

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

139

DRAFT ONLY

Based on the above, the following load combinations are to be considered for the landing gantries to the first span from poles/towers under short-circuit loadings— Short-circuit load

φ R n > 0.25 W n + 1.5 F t + 1.1 Gs + 1.25 Gc + 1.3 F sc *

. . .C2

 F t   tensions for conductors not in short-circuit on one of the 3-phases shall be based on temperature corresponding to everyday load condition with a nominal wind pressure of 0.25 times the ultimate design wind pressure.  F sc * short-circuit tensions are the maximum of the  F t ,  F f   and  F  pi   tensions from the calculation methods described above.

Design of foundations under short-circuit loadings is not practical due to the short duration of the forces and the response of the heavy and inert foundations. Therefore the reactions resulting from the short-circuit loadings can be considered for the steel anchor bolts and the steel structure itself, whereas the normal load conditions are suitable for the foundation design. A detailed and comprehensive method of analysis based on IEC 60865-1 is presented below for the estimation of the short-circuit loads,  F sc * described above. C3 CREEPING SNOW

Creeping snow is to be considered with regard to the potential for additional loadings on foundations and lower parts of supports (especially bracing members). Principles of calculation of loadings caused by creeping snow cannot be fully defined and local experience is important. Appropriate loading assumptions or protective measures should be adopted to reduce the risk of failures of supports. Protection measures should be taken where possible to deflect or restrain by means of an independent structure any potential creeping snow accumulations C4 EARTHQUAKES

Wind loadings are usually the more determining factor in the design of overhead line towers, however seismic loads may lead to additional loading forces that should be considered in known very active seismic zones. In these locations consideration needs to be given to the natural period of vibration of the structure, the site-structure resonance factor (depending on the soil conditions), and the height, weight and mass distribution of the support structure. Since the frequency of the support is higher than that of conductors, the dynamic load from conductors obviously is not significant. For the same reasons no important effects from the support on conductors should be expected. However, the ground acceleration due to earthquakes may influence the design of rigid and heavy concrete pole structures, particularly pole mounted transformer supports. Reference should be made to AS/NZS 1170.4 and NZS 1170.5 for appropriate general design provisions. In addition the following specific provisions for overhead lines should be considered. C4.1 General principles relating to overhead lines

The design of any overhead line near a known active fault or in an area susceptible to earthquake induced liquifaction, shall recognise the large movements which may result from settlement, rotation and translation of foundations. In this case, consideration should  be given to the social and economic consequences of failure in developing mitigation options. 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

140

DRAFT ONLY

In general pole and tower structures have proven not to be susceptible to damage from earthquake shaking motions. Structures of the following types however, shall be designed to resist earthquake loads: (a)

Pole structures supporting heavy equipment (i.e. transformers).

(b)

Pole structures in alpine areas subject to high ice loads (as defined in AS/NZS 1170.3) where at l east 50% of the contributing mass (i ncluding ice) is located in the top third of the structure height.

(c)

Pole structures supporting a short span attached to a rigid termination structure (e.g. substation termination).

Pole structures with a longer fundamental period ( T 1) and located in deep alluvial soils are often sensitive to the amplification effects of ground motion. This should be taken into account as appropriate. C4.2 Seismic mass

The seismic mass of the pole/tower structure shall include— (a)

the dead load arising from all permanent parts of the structure including hardware, equipment, the self weight of tower and any maintenance platforms, ladders and climbing facilities; and

(b)

the mass of conductors and stays.

If the pole structure is located in an alpine area, the additional weight of snow/ice on the conductors and towers shall be considered in determining the seismic weight. C4.3 Fundamental period of structure ( T 1)

The fundamental period can determined using the Rayleigh method in NZS 1170.5 or by computer analysis. Alternative calculation methods can be found in ANSI/TIA-222G. The typical fundamental frequency of power structures is typically— (a)

Single pole

0.5 to 1.5 Hz;

(b)

H-frames

1 to 3 Hz; and

(c)

Lattice structures

2 to 6 Hz.

C4.4 Ductility factor

The maximum ductility factor ( μ) used for design of any structure is limited to— Structure type

Free standing pole

Maximum ductility factor (μ)

Timber

1

Steel

2

Concrete

1.25

Free standing lattice tower

3

Guyed tower

3

C4.5 Modelling of cables and conductors

The conductors and cables may be modelled as linear spring (with due allowance for sag of the cable) by adjusting the modulus of elasticity as follows:  E eff 

=

 E c

(γ  L) 2 1+  E c 12σ 3

. . .C3

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

141

DRAFT ONLY

If this is to be modelled as a horizontal spring, then the horizontal component of cable tension should be taken as—  K eff , h

 Ac E ff 

= cos2 α 

. . .C4

 L

where is the cross sectional area of the conductor or cable (mm 2)

 Ac  E c

=

the modulus of elasticity of the conductor or cable

 E eff 

=

the effective modulus of elasticity (MPa)

σ

=

the tensile stress in the conductor or cable (MPa)

 L

=

the cable length (m)

γ

=

the cable unit weight (N/m)

α

=

the angle of the cable to the horizontal (degrees)

If the horizontal distance between the structure base and stay anchor point exceeds 300 m, out-of-phase excitation of the anchor point shall be included in the analysis. C4.6 Methods of analysis C4.6.1 Equivalent static force method

The equivalent static force method may be used provided all of the following conditions are met: (a)

The plan stiffness and mass distribution should be approximately symmetrical in both orthogonal directions, i.e. the eccentricity between the centre of mass and centre of stiffness is less than 30% of the smallest plan dimension of the structure.

(b)

The vertical regularity should be also constant with no abrupt changes of stiffness, i.e. the stiffness does vary by more than 50% between adjacent sections.

(c)

The mass regularity of a section (mass per unit length) should not vary by more than 200% from an adjacent section. Concentrated masses within the top third of the structure which contribute less than 50% to the total base overturning moment are acceptable.

(d)

The structure height is less than— (i)

Poles

15 m

(ii)

Lattice towers

30 m

(iii)

Guyed structures

no limit

 NOT ES 1

On a lattice tower, a section shall be considered the distance between vertical leg connections but not exceeding 15 m.

2

The mass of stays is excluded from determining mass irregularities.

3

Antenna mounts, platforms, torque arms and cross arms shall not be considered a stiffness irregularity.

C4.6.2 Modal response spectrum analysis

A modal analysis is required when the structure does not meet the requirements of Equivalent Static Force Method (i.e. significant mass or stiffness irregularities exist) and the height is less than (a)

Poles

60 m

(b)

Lattice towers

180 m 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

142

DRAFT ONLY

A modal analysis should be undertaken where the relative displacement between points on the structure is important. (The lateral force method underestimates the magnitude of differential displacement between points on a structure due to the contribution of higher modes). C4.6.3 Time history analysis

A time history analysis is required when the relative displacement between points on the structure is important or where the horizontal distance between the structure base and stay anchor point excee ds 300 m (out of plane movements are incl uded in the a nalysis) or exceeds the height requirements for a modal analysis. C4.7 Combination of effects

A combination of effects of orthogonal actions shall be applied to the structure to account for the simultaneous effects of shaking in the two perpendicular directions using either— (a)

combination of effects from two orthogonal directions for a static analysis— (i)

CASE 1: 100% from direction  X  plus 30% from direction Y 

(ii)

CASE 2: 100% from direction Y   plus 30% from direction  X;

(b)

the square root of sum of the squares (SRSS) or CQC methods for a modal analysis; or

(c)

3D time history analysis using the  Z   orthogonal earthquake component.

C4.8 Second order effect analysis ( P δ)

Second order effects ( P δ) need not be considered when δ M/M o  < 0.10 where δ M   is the overturning effect due to second order effects and  M o  is the first order overturning moment. Second order effects shall be considered for all guyed structures. C4.9 P -Δ Effects

Second order effects ( P Δ ) need not be considered when at least one of the following conditions is met: (a)

Fundamental period is less than 0.45 s.

(b)

Structure height less than 15 m and the fundamental period is less than 0.8 s.

(c)

The ductility factor is less than 1.5.

(d)

Lattice towers less than 140 m height where height ( h/W ) to face ratio is less than 10.

A rational analysis method which takes into account the post elastic deflections of the structure shall be used to determine the P Δ   effects. C4.10 Vertical seismic response

The structures shall be designed to remain elastic under both positive and negative vertical acceleration. This shall be considered to act non-concurrently with the horizontal seismic response.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

143

DRAFT ONLY

C4.11 Seismic displacements

Where the structural system can be simulated as a single degree of freedom structure, the seismic displacement at the centre of mass can be taken as follows, unless a more detailed study is undertaken:

Δ=

μ C (T ) gZRS pT12 

. . .C5

4π 2

where

Δ

=

the seismic displacement at centre of mass (m)

 g

=

9.81 ms 2

T 1

=

the fundamental period of the structure (s)

C (T ),  Z , R , S  p   are factors in NZS 1170.5 C4.12 Liquefaction

Liquefaction of loose saturated, cohesion-less soils (sands, silts and loose sandy gravels) during strong seismic tremors shall be taken into consideration in the route selection of lines. The consequences of liquefaction shall be considered, including— (a)

foundation failure in saturated sands and sandy clays;

(b)

loss of pole or pile lateral or vertical capacity;

(c)

subsidence; and

(d)

lateral spreading of slopes, embankments and ground towards river banks.

The risk of liquefaction shall be consistent with the other performance requirements for the  pole or line section. C4.13 Holding-down bolts

Where base plate mounting of structures are used, holding-down bolts shall provide a minimum net vertical uplift reaction under design earthquake conditions not less than 50% of the dead load reaction. C5 MINING SUBSIDENCE

Where overhead lines are located in areas subject to underground coal mining the impact of ground subsidence and horizontal displacement of soil strata shall be considered in design. This type of mining is generally carried out in softer sedimentary rock strata. In the case of other mineral mining they are normally in hard rock formations and the impact on overhead lines can be ignored. C5.1 General design provisions

Pole lines at lower voltage are not sensitive to mining subsidence unless electrical clearance are breached. Transmission line towers however, can be effected due primarily to the spread of the tower  base. In general ‘bore and pillar’ mining techniques provide columns of rock that safely support the mine overburden, and it has been common practice to locate tower structures over these columns where mine workings are within 100 m of the surface. Mine workings at greater depths normally have no impact at the ground surface.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

144

DRAFT ONLY

However in the case of older coal mines, these pillars weather over time and can collapse and cause general subsidence at the surface. This effect can normally be expected to occur over a period of time and to have limited or no damage to tower lines. ‘Long wall’ coal mining techniques, however progressively remove all material and allow the overburden to settle behind the advancing working face. This has the effect of translating rapid subsidence to the surface and to progressively ‘bend’ the surface strata as the earth mass settles. These bends cause stretching effects and horizontal displacement will occur. Horizontal displacements over a 10 m base spread, have been observed to be in the range of 100–300 mm. If the tower bases in these locations are tied together with reinforced concrete or steel tie  beams, damage to the above ground structure can be limited or avoided. Consideration needs to be given however to the horizontal forces applied to the structure foundation in these situations.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

145

DRAFT ONLY

APPENDIX D

GUIDELINES ON SERVICE LIFE OF OVERHEAD LI NES (Normative) D1 GENERAL

The service life of a structure is the period (generally in years) over which it will continue to serve its intended purpose safely, without undue maintenance or repair disproportionate to its cost of replacement and without exceeding any specified serviceability criteria. This recognizes that cumulative deterioration of the structure over time will occur, due to ‘wear and tear’ or environmental effects. Therefore, due maintenance and possible minor repairs will be required from time to time to maintain the structure in a safe and useable condition over its service life. The design life, or target nominal service life expectancy, of a structure is dependent on a number of variable factors. The information contained in this Appendix is given as a reasonable basis for the economic evaluation of alternative support systems; the selection of a particular structure type for given site conditions; the detail design of a particular structure; or the selection of suitable materials or protective treatment. It is generally considered that structures and fittings located within 1.0 km of the sea will be subjected to more severe exposure and would normally require either special protection or a shorter service life. D2 SUGGESTED NOMINAL SERVICE LIFE

Based on the above-ground exposure classes defined in Table D1 and Figures D2 and D3 the nominal service lives given in Table D2 are suggested. D3 ADDITIONAL CONSIDERATIONS D3.1 Soil type

Support structures and their foundations constructed or embedded in aggressive soils should have suitable protective barriers or preventative measures incorporated in their construction. Alternatively, a significantly reduced service life should be considered. The  presence of landscaped gardens and lawn and the ass ociate d effects of water and fertilizers should be considered. D3.2 High water tables

Poles embedded in sites prone to high water tables should be suitably treated to maintain consistent performance above and below ground. D3.3 Accumulation of condensation

When assessing the life of a hollow steel or concrete pole structure, consideration should be given to the potential effects of condensation entrapment due to pumping action due to temperature variations, if the internal void does not have adequate venting or drainage. D3.4 Regions of low humidity

In regions of low humidity, an extended service life is usually expected when compared to regions of more humid conditions.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

146

DRAFT ONLY

D3.5 Accidental damage

Accidental damage, such as vehicle impact or falling trees, can cause substantial overloads and even complete structure failure. Wind speeds in excess of the design wind speeds can similarly create substantial overloads. Many such accidents can occur and thus reduce the service life. D3.6 Fire

In regions susceptible to uncontrolled fires, consideration should be given to the use of fireresistant materials. The post-fire strength and durability of poles should be assessed by a competent person. D3.7 Concrete poles

Concrete poles, like other concrete structures, are typified by minimal maintenance, long service life and good aesthetics. Service life considerations include the following: (a)

 Environmental   High quality concrete exposed to normal ‘arid’ or ‘temperate’ conditions would be regarded as having an indeterminate service life—a life beyond 100 years. Studies have shown that the depth of carbonation in spun concrete has  been immeasurable (less than 1 mm) after a period of typically 30 years. This Standard recognizes this fact and specifies a minimum cover of 9 mm, provided that the concrete is proven to be high quality by achieving a water absorption value less than 5.5%.

The existence of chlorides in the environment is much more damaging. Poles being vertical structures have an inherent ability to shed surface contaminants, such as airborne sea spray, to a certain extent but the in-ground portion can be highly exposed. Except in marine splash conditions it is generally the below-ground portion of a pole that needs the most attention to cope with chlorides. (b)

Cracking  Excessive cracks will reduce the service life. The commonly accepted crack-width criteria for different exposures are as follows:

(i)

Width <0.3 mm

Exposure Classifications A1, A2, B1 (see Table D1).

(ii)

Width <0.2 mm

Exposure Classification B2.

(iii)

Width <0.1 mm

Exposure Classification C.

Generally, cracks are barely measurable in most concrete poles. The self-healing process (autogenous healing) normally seals cracks after some time. D3.8 Timber poles

The values of design life gi ven in Table D4 assume t hat the poles are subject to a systematic program of inspection, at least as rigorous as that recommended in Table D3, and that appropriate maintenance is promptly carried out when an inspection indicates a need for it. The primary hazard agencies that need to be considered with respect to timber poles are decay, termites and weathering. Allowance for this has been made in the design provisions of Appendix F by the use of pole degradation ( k d) factors. Where supplementary maintenance such as the provision of diffusion preservatives (boron rods) or specific protection systems for termites are provided, the service life of poles will  be shorter. The exposure classifications in Table D1 refer to generalized conditions, and it should be kept in mind that timber poles are susceptible to localized microclimatic effects. Aggressive termites can be found in most parts of Australia and the following termite hazard map Figure D1 provides a general guide to the extent of the potential problem. 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

147

DRAFT ONLY

While New Zealand has three known native termites species they do not pose a concern to timber poles. There are however potential imports of Australian termites that need to be monitored and eradicated if identified.

DARWIN

Cairns Broome

 Tow nsvi ll e

Port Hedland

Mount Isa

 A li ce Sp r in gs

Rockhampton

Charleville

BRISBANE Narrabim

Kalgoorlie

Geraldton

Dubbo Mildura  A lb ur y

PERTH  Al bany

 AD EL A ID E Mount Gambier MELBOURNE

Newcastle SYDNEY  CANBERRA  Bega

LEGEND: = = = = = =

Very high High Moderate Low Very low Negligible

HOBART 

FIGURE D1 TERMITE HAZARD MAP OF AUSTRALIA

D3.9 Steel poles and lattice steel towers D3.9.1   General

Steel materials are normally used with zinc coating applied by a hot-dip galvanizing process to extend the service life. The use of untreated mild steel in normal arid conditions may provide a service life in excess of 75 years. D3.9.2   Environmental

The protective life of metallic zinc coatings on steel is roughly proportional to the mass of zinc per unit of surface area, regardless of method of application. Hot-dip galvanizing  provides a minimum average coating mass of 350 g/m 2  on s teel less than 2 mm thick, 450 g/m2  on steel between 2 mm and 5 mm thickness and 600 g/m 2  on steel over 5 mm thick. The expected life for a given coating mass (years) in different atmospheric environments is shown in Table D2.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

148

DRAFT ONLY

TABLE D1 ABOVE-GROUND ENVIRONMENTAL EXPOSURE CLASSIFICATION (AUSTRALIA) Climatic zone (see Figure D2)

Geographic region(1)

Industrial proximity (2)

Exposure class (3)

 Non -indus trial

A1

Industrial — —  Non -indus trial

B1 B1 B2 A2

Industrial — —  Non -indus trial

B1 B1 B2 B1

 Nea r-c oas tal Coastal

Industrial — —

B2 B1 B2

Any

—

C

Inland Arid  Nea r-c oas tal Coastal Temperate

(4)

Inland  Nea r-c oas tal Coastal Inland

Tropical

(See Note 4)

 NOTE S: 1 The boundaries of the regions are related to the distance from the coastline to which prevailing onshore winds carry salt-laden air. The boundaries will be affected by both latitude and local topography and, therefore will vary from place to place. However, for exposure classification  pur poses the reg ion s a re define d i n Aust ral ia as fol lows: (a)  Inland  — greater than 50 km from coast. (b)  Near -coastal  —  bet ween 1 km and 50 km from c oas t. (c) Coast  — less than 1 km from coast. In general, for coastal locations, exposure classification B2 applies, except where it can be shown that there is an absence of airborne chlorides, e.g. due to the nature of the coastal topography, the lesser exposure classification B1 applies. 2

Industrial proximity is classed a s non-industrial if it is greater than 3.0 km from industrial  pla nts tha t dis cha rge air pol lutant s suc h as car bon dio xid e (CO2 ), sulphur dioxide (SO2 ) and sulphur trioxide (SO3 ), which form acids with airborne moisture. It is only appropriate for inland regions.

3

Classes A1 to C represent increasing degrees of severity of exposure.

4

The New Zealand climate is classified as ‘temperate’ throughout, and the regions to which the Exposure Class A2 applies is taken directly from Figure D3. The coastal region for application of Exposure Class B2 extends shorewards for 500 m from the high-tide mark. The near-coastal region to which Ex posure Class B1 applies extend s from there to the boundary of the A2 region. Active volcanic/geothermal areas may be regarded as Exposure Class C.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

149

FIGURE D2 CLIMATIC ZONES FOR AUSTRALIA

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY

DRAFT ONLY  

150

DRAFT ONLY

FIGURE D3 (in part) NEW ZEALAND REGIONS FOR EXPOSURE CLASSES A2 and B1

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

151

DRAFT ONLY

FIGURE D3 (in part) NEW ZEALAND REGIONS FOR EXPOSURE CLASSES A2 and B1

D3.10 Composite fibre poles (fibre reinforced resin composite material )

There is limited service history of composite fibre poles in Australia and the world. The longest experience is in North America where a service life of 40 years has been experienced. Composite fibre poles should have a UV protective coating or additives applied during manufacture to extend the service life of the pole. Moisture ingress into the fibre cores will cause fibre ‘blooming’ and lead to failure if the  pole is not maintained.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

152

DRAFT ONLY

TABLE D2 SUGGESTED RANGE OF NOMINAL SERVICE LIFE OF STEEL STRUCTURES AND CONCRETE POLES Suggested nominal service life (years) Galvanized steel(5)

Exposure class

Concrete

200 g/m 2(1)

400 g/m 2(1)

600 g/m 2(1)

C(2)

A1

60–100+

100+

100++

100+

A2

25–60

60–100

75–100+

80–100

B1

12–25

25–50

35–75

60–80

B2

8–25

15–50

35–75

50–60

C

( 3)

3–12

(6)

6–25

(6)

9–35

(6)

50

(4)

 NOT ES: 1

Preservative treatment is hot-dip galvanized, for the mass/square metre as noted, with no additional coatings such as chromate, paint or plastic. These figures are indicative only and make no allowance for any corrosion of the underlying steel.

2

Cover to reinforcement, C = 9 mm, or 19 mm.

3

It should be noted that above-ground conditions may differ from below-ground conditions. Aggressive below-ground environments may be regarded as a Class C exposure.

4

Past experience has shown that uncoated steel can have a reasonable service life in arid conditions.

TABLE D3 RECOMMENDED INSPECTION PERIODS FOR TIMBER POLES Species and class

Preservative treatment

Recommended inspection periods (years) First

Subsequent

Hardwood (Euc.Spp) Durability Class 1

 Nil

10

every 3 to 6

Hardwood (Euc.Spp) Durability Class 1

H5 to sapwood

20

every 3 to 6

Hardwood (Euc.Spp) Durability Class 2

 Nil

10

every 3 to 6

Hardwood (Euc.Spp) Durability Class 2

H5 to sapwood

20

every 3 to 6

Softwood (Australian)

H5

20

every 3 to 6

Softwood (New Zealand)

H5

20

every 3 to 6

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

153

DRAFT ONLY

 .    d   n   a    l   a   e    Z   w   e    N    f   o   s    t   r   a   p    l    l   a   o    t   s   e    i    l   p   p   a    2   e   n   o    Z   r   o    f   a    i   r   e    t    i   r    C   :    E    T    O    N

   S    E    L    O    P    R    E    B    M    I    T    R    O    F    S    E    N    O    Z    E    F    I    L    E    C    I    V    R    E    S    L    A    N    I    M    O    N    4    D    E    R    U    G    I    F

TABLE D4 SUGGESTED RANGE OF NOMINAL SERVICE LIFE OF TIMBER POLES Zone (see Figure D4)

Service life expectancy (years) H5 treated timber to AS 1604

Desapped untreated timber

Class 1

Class 2

Class 3

Class 4

Class 1

Class 2

1

45–55

35–45

25–35

40–50

25–35

15–25

2

50+

50+

30–40

50+

30–40

25–35

3

50+

50+

40–50

50+

50+

30–40

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

154

DRAFT ONLY

APPENDIX E

DESIGN FOR LIGHTNING PERFORMANCE (Normative) E1 DESIGN FOR LIGHTNING PERFORMANCE

Lightning induced outages are one of the major cause of outages on overhead lines in areas of moderate to high ceraunic activity. A moderate ceraunic level is between 30 and 50 thunderdays per year, and high level above 50 thunderdays per year. The acceptable outage rate due to lightning is therefore one of the most dominant design  parameters for an overhead line. In a low to moderate ceraunic activity area, an acceptable outage rate from lightning for overhead lines with overhead earthwires is typically 2 to 5 outages per 100 km per year. E1.1 Estimation of line outages due to lightning

The prediction of lightning outages is not an exact science and the methods adopted in one Authority may not be appropriate in others. It has been found that the parameters which can  be varied to achieve the largest influence on the lightning performance of overhead lines are— (a)

installation of earthwire;

(b)

having wood in the flashover circuit (crossarm or pole);

(c)

critical flashover voltage (CFO) of the insulators; and

(d)

 pole footing res istance.

Overhead earthwires are used to shield the line from lightning strikes and are usually installed on high reliability lines operating at sub-transmission and transmission voltage levels. They are also installed on overhead distribution lines for short distances (typically 800 m) out of a substation to protect the substation equipment from damaging overvoltages. One earthwire is usually sufficient to cater for shielding flashovers on structures below 20 m, but higher structures will need two earthwires to achieve effective shielding. With a single earthwire, the shielding angle is usually in the range of 30 to 40°. The arc quenching property of wood has been used by Authorities to reduce lightning induced outages on the network. When wood is added to the insulation path, the combined insulation strength of the insulator and wood is increased. The higher the impulse strength of the insulator/wood combination, the higher the resistance to flashover (see reference at the end of this Appendix) for the electrical properties of wood. The effective impulse strength of a series wood and insulator path can be calculated as follows:  I total =

[ I wood 2 +  I insulator 2]1/2

. . .E1

where  I wood

=

 I insulator  =

Impulse strength of wood Impulse strength of insulator

When an overhead earthwire is installed on powerlines, generally a down lead is run to earth to provide a low resistance path to ground. A low pole footing resistance not only reduces the probability of lightning induced backflashovers but also offers the following advantages: (i)

Reduces risk of injury to persons or animals due to rises in earth potential at the structure and the surrounding soil. 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

(ii)

155

DRAFT ONLY

Provides a low impedance path for earth faults to ensure there is sufficient fault current to operate protection relays.

E1.2 Measures to improve lightning performance

An improvement in lightning outage time on transmission lines can be achieved by installing auto-reclosing schemes. An improvement in lightning outage rates, particularly for distribution lines can be achieved by using wood in the crossarms or poles. The wood increases the impulse strength of the line to ground and can quench the lightning arcs thereby avoiding a power frequency fault. This performance can be described by the shielding failure flashover rate, R sf  , and by the  backflashover rate,  R b . It is fixed by operational considerations and depends on the insulation strength of the line and on the following parameters: (a)

The lightning ground flash density.

(b)

The height of the overhead line.

(c)

The conductor configuration.

(d)

The protection by shield wire (s).

(e)

The tower earthing.

(f)

The installation of surge arresters on the overhead line.

Reference: DARVENIZA, M.  Electr ical Propertie s of Wood and Line Des ign  published by University of Queensland, 1978.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

156

DRAFT ONLY

APPENDIX F

TIMBER POLES (Normative) F1 GENERAL

Design properties and design methods for timber utility poles and components shall be in accordance with AS 1720.1 or AS/NZS 1328. Where specifically defined for round timbers, they shall be in accordance with Paragraphs F1.2 to F1.4. F1.1 Characteristic strengths and elastic moduli

The characteristic strengths and elastic moduli for untrimmed poles that conform in quality to the grade requirements specified in AS 2209 shall be as specified in Tables F1 and F2, unless verified by ingrade testing. Strength groups and joint group classifications shall be assigned to species in accordance with AS 1720.2. TABLE F1 POLE TIMBERS GRADED TO AS 2209—RELATIONSHIP BETWEEN STRENGTH GROUPS AND CHARACTERISTIC PROPERTIES (MPa)

Strength group

Stress grade

Bending ( f  b ) (3)

Tension parallel to grain ( f  t ) (3) Hardwood

Softwood

Shear ( f  s ) (3)

Compression parallel to grain ( f  c) (3)

Short duration modulus-of elasticity ( E)

S1

F34

100

60

—

7.2

75

21500

S2

F27

80

50

—

6.1

60

18500

S3

F22

65

40

—

5.0

50

16000

S4

F17

50

30

26

4.3

40

14000

S5

F14

40

25

21

3.7

30

12000

S6

F11

35

20

17

3.1

25

10500

S7

F8

25

15

13

2.5

20

9100

 NOTE S: 8

The equivalence expressed in the table above is based upon the assumption that the poles are cut from mature trees.

9

The modulus of elasticity includes an allowance of about 5% for shear deformation.

10 See Paragraph F2.1.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

157

DRAFT ONLY

TABLE F2 CHARACTERISTIC STRENGTH PROPERTIES (MPa) FOR BEARING AND SHEAR AT JOINTS Bearing Strength group

Perpendicular to grain ( f  n ) (see Note)

Parallel to grain ( f  t) (see Note)

Shear at joint details ( f  s ) (see Note)

S1

60

—

7.2

S2

50

—

6.1

S3

40

—

5.0

S4

30

26

4.3

S5

25

21

3.7

S6

20

17

3.1

S7

15

13

2.5

 NOTE :Se e Par agraph F2. 1.

F1.2 Design factors—Material F1.2.1 Capacity factor

Values for the capacity factor ( φ), for calculating the design capacity of poles ( φ R), shall be determined using Table F3. TABLE F3 CAPACITY FACTORS FOR TIMBER POLES Basis for determining characteristic strength properties

Characteristic design property to which the value of ø shall apply for calculating the design capacity

Poles graded to AS 2209 Poles graded using proof grading in accordance with Section 7 of draft code Poles with bending properties established from in grade evaluation and subject to periodic testing/monitoring of  pro per tie s

All properties

0.90

( f ′  b ) (see Note)

0.95

All other properties

0.90

( f ′  b ) (see Note)

0.95

All other properties

0.90

 NOTE :Se e Par agraph F2. 1.

F1.2.2 Duration of load effects (strength)

The effect of duration of load on strength of timber poles and components is given by the modification factor k 1, as defined in Table F4. The effective duration of load refers to the cumulative duration for which the peak load occurs. Guidelines for determination of the effective duration of load are detailed in AS 1720.1. F1.2.3 Duration of load effects (stiffness)

For timber poles subject to sustained bending, creep effects should be considered. The effect of duration of load on stiffness of timber poles and components shall be determined in accordance with AS 1720.1 or NZS 3603. For other timber components, the short-term deflection shall be multiplied by the appropriate creep factor  j 2 o r  j3, as given in AS 1720.1 or NZS 3603

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

158

DRAFT ONLY

TABLE F4 DURATION OF LOAD FACTOR FOR STRENGTH Type of load

Effective duration of peak load

Modification factor ( k1) for strength of poles and timber components (see Note)

Modification factor ( k1 ) (see Note) for strength of timber connections using laterally loaded fasteners

Instantaneous (e.g. ultimate wind and earthquake)

3 seconds

1.00

1.14

Short term (e.g. construction maintenance)

3 hours

0.97

0.86

Medium term (e.g. snow/ice in subalpine areas)

3 days

0.94

0.77

Long term (e.g. snow/ice in alpine areas)

3 months

0.80

0.69

>1 year

0.57

0.57

Permanent  NOTE :Se e Par agraph F2. 1.

F1.2.4 Pole degradation factors

For all timber poles, the design shall allow for loss of strength and stiffness associated with degradation of the critical section of the pole at and below the ground line over its expected design life. The degradation factor ( k d) shall be determined from Table F5, unless more accurate durability information is available. The values of k d  given in Table F5 are based upon expected loss of effective section. In cases where the local environment in which the pole will be located is known to be of high hazard (e.g. due to excessive moisture or high probability of insect attack) more conservative values may be appropriate.  NOTE: Where a syst emat ic inspectio n and maintenance pro gram is in place and where any evidence of degradation is effectively preservative treated (e.g. using diffusion preservatives), then the values of kd given in Table F5 for untreated timbers will be conservative and higher values may be appropriate.

TABLE F5 POLE DEGRADATION FACTORS Type of pole

Design life (years)

Pole diameter d <250 mm

Pole diameter 250 d 400 mm

Pole diameter d >400 mm

 kd

 kd

 kd

Full length preservative-treated solftwood in accordance with As 2209

20

1.0

1.0

1.0

50

0.80

0.85

0.90

Full length preservative-treated hardwood in accordance with AS 2209

20

1.0

1.0

1.0

50

0.80

0.85

0.90

Durability Class 1 untreated hardwood in accordance with AS 2209

20

0.80

0.90

1.0

50

0.50

0.55

0.60

Durability Class 2 untreated hardwood in accordance with AS 2209

20

0.70

0.80

0.90

50

0.30

0.40

0.45

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

159

DRAFT ONLY

F1.2.5 Factor for immaturity

For poles having mid-length diameters less than 250 mm, due allowance shall be made for the properties of immature timber, using the modification factors k 20   and  j9  from Table F6, for strength and stiffness respectively. TABLE F6 IMMATURITY FACTORS  k 20  FOR DESIGN CAPACITY AND IMMATURITY FACTORS  j 9 FOR STIFFNESS Immaturity factor  k20 / j 9

Species

 d   = 100 m

 d   = 125 m

 d   = 150 m

 d   = 175 m

 d   = 200 m

 d   = 225 m

 d   = 250 m

Eucalypt and Corymbia

0.90

1.00

1.00

1.00

1.00

1.00

1.00

Softwoods

0.75

0.80

0.85

0.90

0.95

1.00

1.00

F1.2.6 Shaving factor

For timber members, the design characteristic strength properties shall be reduced if the  poles have been shaved, when modi fied from the natural pole form. The shaving factor for strength k 21   shall be determined as specified in Table F7. In addition to this modification for strength, the values specified for stiffness in Table F1 shall be reduced by 5% for shaved  poles. TABLE F7 SHAVING FACTOR  k 21 Characteristic property

Eucalypt and Corymbia species  k21

Softwood species  k 21

Bending

0.85

0.75

Compression parallel to grain

0.95

0.90

Compression perpendicular to grain

1.00

1.00

Tension

0.85

0.75

F1.2.7 Processing factor

Where poles are steamed as a part of the manufacturing and fabrication process, the characteristic strength properties shall be reduced using k 22 . For poles that are steamed, k 22   = 0.85, otherwise k 22  = 1.0 F2 DESIGN CAPACITY F2.1 Notation

The following notation is used in this Clause: k 1

=

the duration of load factor

k 12

=

the stability factor for compression, determined in accordance with Section 3 of AS 1720.1, except that the slenderness coefficient (S ) shall equal 1.15 L/ d  p where—  L

=

the distance between effective restraints in any plane and;

d  p

=

the nominal mid length diameter between the points of restraint

k 20

=

the immaturity factor

k 21

=

the shaving factor 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

160

k 22

=

the processing factor

k d

=

the degradation factor

 f ′ t

=

the characteristic strength in tension

 f ′ c

=

the characteristic strength in compression parallel to grain

 f ′ n

=

the characteristic strength of timber in bearing perpendicular to grain

 f ′  b

=

the characteristic strength in bending

 f ′ s

=

the characteristic strength in shear

 Ac

=

the cross-sectional area at the critical section

=  As

= =

 Z 

= =

π d 2

4 the shear plane area 3π d 3 16 the section modulus π d 3

d  p

=

32 the pole diameter at the critical section

 Z T

=

torsional section modulus

=

DRAFT ONLY

π d 3

16

F2.2 Bending strength

The design capacity of poles in bending ( φ  M ) for the strength limit state, shall satisfy the following: φ  M  ≤  M * φ  M  =

. . .F1

φk 1 k 20 k 21 k 22 k d [  f ′ b  Z ]

. . .F2

F2.3 Shear strength

The design capacity of poles in shear ( φ V ) for the strength limit state, shall satisfy the following: φ V  ≥ V * φ V  =

. . .F3

φk 1 k 20 k 22 k d [ f ′s  As]

. . .F4

F2.4 Compressive strength

The design capacity of poles in axial compression ( φ  N c) for the strength limit state, shall satisfy the following: φ  N c ≥ N* φ  N c =

. . .F5

φk 1 k 12 k 20 k 21 k 22 k d [  f ′ c  Ac]

8326-PDR - 24/07/2008 14:25:50

. . .F6

DRAFT ONLY  

161

DRAFT ONLY

F2.5 Combined bending and compression strength

Where a pole is subjected to combined bending and compression load effects, the diameter shall be such that the following is satisfied:

⎛ M * ⎞ ⎛  N c* ⎞ ⎜ φ M ⎟ + ⎜ φ N  ⎟ ≤ 1 ⎝ ⎠ ⎝ c⎠

. . .F7

F2.6 Torsional strength

The design capacity of poles under torsion about the pole axis ( φ T ) for the strength limit state shall satisfy the following equations: φ T 

≥

T *

. . .F8

φ T 

=

φ k 1 k 20 k 22 k d [ f ′ s  Z T ]

. . .F9

 NOT E: The torsional rig idity of timber poles is nor mally very hig h, with the result that in most situations the pole will rotate in the ground rather that induce resultant torsional forces in the wood. As such, torsional strength is only considered in exceptional circumstances where the pole is embedded rigidly into a foundation.

F2.7 Pole top deflection

Designers shall note that the modulus of elasticity (or stiffness) of poles in the ‘green’ state, or re-wetted by waterborne CCA preservative, can be significantly less than that of dry or seasoned poles. The values of modulus of elasticity (MOE) specified in Appendix F and in AS 1720.1 are average values for unseasoned timber. For situations where pole deflection is critical, designers shall use 5th percentile values of MOE. For poles, an approximation of the 5th percentile MOE is obtained by multiplying the average MOE by 0.5. Specific guidance on design for serviceability limit states is presented in AS 1720.1. It is recommended that poles subjected to sustained resultant loads be considered deflection sensitive. For example, a service, street light fitting or slight angle, may result in the structure developing a pronounced permanent bend as it undergoes in-situ drying.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

162

DRAFT ONLY

APPENDIX G

LATTICE STEEL TOWERS (SELF SUPPORTING AND GUYED MASTS) (Normative) G1 GENERAL

Lattice steel tower designs shall comply with the requirements of AS 3995 or ASCE 10-97 and the following special provisions: G2 CALCULATION OF INTERNAL FORCES AND MOMENTS G2.1 Method of analysis of lattice steel towers

In most cases, a single tower type can be used in various configurations with a number of different body extensions and leg combinations. Each of these configurations will result in a unique force distribution. To capture the most unfavourable forces in the tower members, it is recommended to model all the likely configurations and select the member sizes to satisfy each of these configurations. As many of the tower models will have a non-symmetrical leg combination it is important to consider loading from all possible directions. Primarily latticed towers are analyzed as ideal elastic three dimensional trusses pinned connected at joints. Such elastic analyzes produce only joint displacements tension, and compression in tower members and tension in guy stays. Moments from normal framing eccentricities are not calculated in the analysis. However,  bending moments in members becaus e of framing eccentricities, eccentric loads, distributed wind load on members can affect the member selection. First-order linear elastic truss analysis treats all members as linearly elastic (capable of carrying compression as well as tension), and assumes that the loaded configuration of the structure is identical to its unloaded configuration consequently ignoring the secondary effects of the deflected structure stipulating that the forces in the redundant members are equal to zero. This type of analysis is generally used for conventional, relatively rigid, self-supporting structures. In a second-order (geometrically nonlinear) elastic analysis, structure displacements under loads create member forces and these additional member forces are called the  P ∆  effects. A second-order elastic analysis may show that redundant members carry some load. Flexible self-supporting structures and guyed structures normally require a second-order analysis. When performing a computer analysis of an existing structure, careful attention shall be given to the method of analysis employed when the structure was originally designed by manual algebraic or graphical methods. A three-dimensional computer analysis may indicate forces in the members that are different from those used by manual methods. Bending moments caused by wind loads on individual member are generally negligible, but they may need to be considered in the design of slender bracings or horizontal edge members. It is normally unnecessary to consider deflections or vibration of lattice towers.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

163

DRAFT ONLY

G2.2 Guyed structures

Guys produce uplift loads on the guy foundation or anchor and compression loads on the structure and its foundation. The guys shall be adjustable in length to permit plumbing of the structure during construction and to account for elastic shortening of the mast, creep in the guy and any initial movement of the uplift anchor. Externally guyed supports (i.e. guyed masts) utilizing multiple stay arrangements are sensitive to inaccurate amount of pretension in the guys. The initial and final modulus of elasticity of the guys, creep of the guys together with the flexibility of the tower shall be used to compute the forces in tower members and foundation reactions. G3 EMBEDMENT OF STEEL MEMBERS INTO CONCRETE BY MEAN OF ANCHORING ELEMENTS

The total tensile or compression load of steel leg members anchored in concrete is transferred to the concrete by two methods— (a)

 ste el angl e stubs with anchoring elements such as angl e cleats or studs These shall  be checked for shear due to the compression str esses between the ele ment and the concrete. No bending moment in cleats or studs should be considered; and

(b)

base plate and holding-down bolts The holding-down bolts shall be checked for shear, axial load as well as possible bending moments due to lateral displacement of the bolts.

G4 CRANKED  K BRACING

For large tower widths, a bend may be introduced into the main diagonals. This has the effect of reducing the length and size of the redundant members but produces high stresses in the members meeting at the bend and necessitates transverse support at the joint. Diagonals and horizontals should be designed as for  K   bracing, effective lengths of diagonals being related to the lengths to the knee joint.

G5 PORTAL FRAMES

A horizontal member is sometimes introduced at the bend to turn a braced panel into a  portal frame. The main disadvantage of this is the lack of articulation present in the  K   brace. This system is sensitive to foundation settlement or movement and special consideration should be given to this possibility.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

164

DRAFT ONLY

G6 SECONDARY (REDUNDANT) MEMBERS

The following rules should be applied to the nominal bracing design: (a)

Face bracing— (i)

All members inclined ≤10° are considered horizontal— 2.5% Load =  = 1.77% of main member force 2

(ii)

Members inclined >10° and connected to the main leg— 2.5% Load =   = 1.25% of main member force 2

(iii) Members inclined >10° and not connected to the main leg— Force to balance vertical component of the connected inclined members (iv) (b)

Members inclined ≤30° to be checked for bending with 1.8 kN load in the middle of member. Bending check is independent from the axial load check.

Hip bracing— (i)

All members inclined ≤10° are considered horizontal— Load = 2.5% main member force

(ii)

Members inclined >10°— 2.5% Load =  = 1.77% of main member force 2

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

165

DRAFT ONLY

1.0% of the main leg load balanci ng 1.25% from the connected brace

Brace load 2.5% P/2 each

Inclined brace 2.5% P/ √ 2 H o r i z o n t al b r a c e 2.5% P

Restraint 2.5% P/ √2

LEGEND: P = Maximum main member compression force

B1 Inclined braces 2.5% P/2

a1

B2 a2

Force balancing vertical component of member connected to the main leg B1=B2* sin(a2) / sin(a1)

Horizontal braces 2.5% P/ √ 2 e a c h

In case of cranked K  bracing with an angle between the diagonal and main leg close to 15°, secondary effects should be taken into consideration (global instability, main leg shortening, bolt slip). G7 SECURITY OF FASTENERS G7.1 General application

All bolt nuts on lattice steel towers shall be locked in their tightened position against loosing by aerodynamic induced vibration by the use of heavy duty spring washers or locking pins. G7.2 Bolts in tension

Where bolts on major loaded connection points are in permanent tension or have nuts in a downward position they shall be fitted with lock nuts. G7.3 Deterrent to vandalism

All bolts within 3000 mm of the ground shall be secured to prevent or significantly deter their removal by vandalism. This can be achieved by welding the nuts to the thread projection or the use of driven lock  pins or similar device s that make it difficult to be removed. G8 ANTI CLIMBING DEVICES

Unauthorised climbing of structures supporting energized overhead lines is a significant  public safety issue, that requires a national uniform standard of approach. All structures that can be easily climbed shall have anti climbing devices or barriers  positioned within 4.0 m of the ground to prevent or significantly deter unauthorised climbing. 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

166

DRAFT ONLY

G9 PLAN BRACING

Horizontal plan bracing should be installed on all lattice steel towers at— (a)

the first horizontal structural member above ground;

(b)

changes of leg slope; at the lower face of all crossarms; and

(c)

vertical intervals not exceeding 15.0 m in the tower body.

Reference should be made t o CIGRE TB 196 for guidance on choice of an appropriate  bracing panel arrangement . G10 STRENGTH FACTORS ( )

Strength factors (φ ) which takes into account variability of material and workmanship for structural components used in lattice steel towers shall be taken as 0.9 unless otherwise  provided in the reference standard being used.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

167

DRAFT ONLY

APPENDIX H

ELECTRICAL DESIGN ASPECTS (Normative) H1 CORONA

Corona occurs when air is ionized. The most important corona effect for overhead lines is around the conductors. When the electric field on the surface of a conductor exceeds the corona inception voltage, the corona discharges in the form of arcs and streamers can generate radio interference, television interference and audible noise. Corona discharges usually occur during inclement weather (i.e. rain, fog ) when the surface voltage gradient on the conductor exceeds 16 kV/cm. During dry weather there is almost negligible corona generated. Other possible sources of corona are hardware surfaces and insulators. Polluted insulators may have significant surface leakage current activity which can also cause corona. Another related effect is spark discharges which may occur between discs of bridging strings that are lightly loaded, mechanically. Spark discharges can generate radio interference, television interference and audible noise. H1.1 Design

The radial electric field at the conductor surface is known as the surface voltage gradient. It is influenced by voltage, number of conductors per phase bundle, size of conductors, phase spacing, and to a lesser extent, line configuration, line phasing, line height, and line  proximity to other lines or wires. Conductor surface finish also has an effect. Care is required during stringing to ensure there is no damage to conductor surfaces. Any high points due to scratches on the conductor will have a high electric field and may act as a source for corona generation. In the first few months of energized operation, conductor surfaces are not yet weathered, and corona levels can be above expectations. Over time, the high points are burnt off and the corona activity reduces. At voltages above 110 kV, it is often the requirement to meet the RIV, TVI and audible noise levels which decide the conductor to install on the overhead line rather than thermal rating requirements. Avoiding corona is the main reason that conductors are bundled on lines at the higher voltage levels. Bundling has the effect of reducing the electric field on the surface of the conductors. The recommended design approach to control corona is to limit the surface voltage gradient to less than 16 kV/cm. The secondary effects of radio interference, television interference and audible noise can be estimated based on empirical formulae using conductor surface voltage gradient as an input. H1.2 Radio interference voltage H1.2.1 Design influences

The most important design influence on the corona-generated radio noise levels produced  by any high voltage line is the electric field very close to the conductors. This field is influenced by voltage, number of conductors per phase bundle, size of conductors, phase spacing, and to a lesser extent, line configuration, line phasing, line height, and line  proximity to other lines or wires. Radio noise levels are also influenced by the local earth conductivity and the relative smoothness of conductor and hardware surfaces.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

168

DRAFT ONLY

Generally, corona generated radio-noise levels become a significant design concern only for lines operating at voltages of 110 kV or above. For these high voltage s, noise-level  prediction methods assume that line hardware is designed or shielded so that only the corona on conductors will be responsible for observed radio noise levels, and that conductors are installed taking care not to damage their surface. In the first few months of energized operation, conductor surfaces are not yet weathered, and radio noise levels can be a few decibels above ultimate expectations. H1.3 Audible noise

The principal source of foul weather acoustic noise is water drops. Whether hanging from a wet line or on insulators, arriving at the line as rain drops, or streaming from the line, water can give rise to various types of discharge. Snow and ice rime on conductors may also give rise to noise. H1.3.1 Design influences

The most important design influence on the audible noise levels produced by a high-voltage line is the electric field very close to the conductors (surface electric gradient). This field is influenced by voltage, number of conductors per phase bundle, size of conductors, phase spacing, and to a lesser extent, line configuration, line phasing, line height, and line  proximity to other lines or wires. Audible noise levels are further influenced by the relative smoothness of conductor and hardware surfaces and contamination due to hydrophobic materials. In general, audible noise levels become a significant design concern only for lines operating at voltages of 110 kV or above. For these high voltages, noise-level prediction methods assume that line hardware is designed or shielded so that only the corona on conductors will  be responsible for observed audible noise levels in wet weather, and that conductors are installed taking care not to damage their surfaces. As with radio noise, audible noise levels may be a little above ultimate expectations during an initial weathering period. H1.4 Corona loss

In cases where the surface voltage gradient is very high there can be a power loss along the conductor due to corona emission. On overhead power lines, corona loss is expressed in watts per metre (W/m) or kilowatts per kilometre (kW/km). The power loss due to corona is typically less than a few kilowatts/kilometre in fair weather but, it can amount to tens of kilowatts/kilometre during heavy rain and up to one hundred kilowatts/kilometre during frost. The magnitude of fair-weather corona loss is insignificant in comparison with foul-weather loss (maximum corona loss). However, fair weather losses occur for a large percentage of time and affect the value of the total energy consumed by the line (yearly average corona loss). H2 ELECTROSTATIC INDUCTION

Electrostatic induction is caused by the electric field surrounding the powerline fields can induce charges on nearby metallic objects. Unless these charges are  properly by proper earthing, they can cause shock to the publ ic. These shocks from finger tip touch perceptible to hand grab annoyance. The thresholds sensations are given in Table H1.

8326-PDR - 24/07/2008 14:25:50

and these addressed can range for these

DRAFT ONLY  

169

DRAFT ONLY

TABLE H1 REACTION TO SPARK DISCHARGES Reaction/sensation

Threshold Energy (milliJoules

Charge ( Coulombs)

Fingertip touch perception

0.14

0.30

Hand grab perception

0.50

0.50

Fingertip touch annoyance

1.30

0.90

Hand grab annoyance

4.00

1.60

The charge induced to the metallic object is dependent on the surface area of the object and the overhead line’s electric field strength. The charge can safely be discharged to earth by installing earth leads to the metallic object. On extra high voltage lines (above 345 kV) the electric field strength on the power line can  be quite high and lead to high charges on large vehicles parked under the line. The high discharge currents can be a hazard to the public in proximity to the vehicle. H3 ELECTROMAGNETIC INDUCTION

Electromagnetic induction is caused by the load and/or fault currents flowing in the overhead line. These currents can generate high voltages in parallel metallic circuits. For telecommunication coordination, the limits are set out in ENA HB 102 For pipelines, the levels are outlined in AS/NZS 4853. These high induced voltages into nearby circuits or objects can be mitigated by the following methods: (a)

Earthing the circuit or object at regular intervals.

(b)

The installation of insulators to sectionalize the circuit.

(c)

Installing a shield wire on the overhead line.

(d)

Increase the separation between the circuit or object and the overhead line.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

170

DRAFT ONLY

APPENDIX I

CONCRETE POLES (Normative) I1 GENERAL

Design properties for concrete, reinforcement and tendons shall be as given in AS 3600 or  NZS 3101.1, or as may be otherwise specified. I2 STRENGTH I2.1 Characteristic or specified compressive strength

The characteristic or specified compressive strength at 28 days  (f  Nc  ), shall be not less than 40 MPa. I2.2 ICharacteristic flexural tensile strength or modulus of rupture

The characteristic flexural tensile strength or modulus of rupture after 28 days of standard curing may be taken as one of the following values as appropriate: (a)

For pole elements subject to sustained tensile stresses, 0.6√ f  Nc.

(b)

For pole elements subject to transient tensile stresses, 0.8 √ f  Nc.

I3 STRENGTH CAPACITY FACTOR

For poles designed by load testing in accordance with Section 8.5, the strength capacity factor (φ ) should not be taken as greater than 1.0. For poles designed by calculation, φ   shall be taken as not greater than the following values, as appropriate for the type of action effect being considered: (a)

Bending, 0.9.

(b)

Compression, shear, or torsion, or any of these in combination, 0.8.

(c)

Bearing, 0.7.

(d)

Combined bending and compression 0.9

I4 SERVICEABILITY I4.1 General

Concrete poles shall meet the serviceability criteria, appropriate to the use of the pole, set out in Paragraphs I4.2 to I4.3. I4.2 Deflection and rotation

For electromotive transport poles, communication equipment poles, and some floodlighting  poles, deflection and rotation parameter shall be determined by the operating system constraints. For most other uses, deflection and rotation shall not be considered a serviceability constraint unless specified by the purchaser. I4.3 Crack width

Crack widths at the serviceability limit state shall not exceed 0.25 mm unless otherwise  provided in design calculations. For sust ained dead loads or cable tension loads, the longterm effects of creep and shrinkage shall be considered.  NOT E: For fur ther i nformatio n on concrete crack width see Appendix D.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

171

DRAFT ONLY

I5 CONCRETE COVER I5.1 Exposure classifications

The exposure classification for poles shall be determined in accordance with AS 3600 or  NZS 3101.1 as appropriate. I5.2 Exposure classifications other than C, or U more severe than C

For all exposure classification other than C, or other than U more severe than C, the clear cover to reinforcement (including tie wires) and tendons shall be not less than the greatest of— (a)

the maximum nominal aggregate size;

(b)

three-quarters of the nominal diameter of the bar, wire or tendon to which the cover is measured; or

(c)

when tested in accordance with Appendix O, if— (i)

absorption ≤5.5%, cover = 9 mm;

(ii)

5.5% < absorption ≤6.5%, cover = 19 mm;

(iii) absorption >6.5%, cover as per AS 3600/NZS 3101.1; or (iv)

other methods of providing suitable durability.

I5.3 Exposure classification C, or U more severe than C

For exposure classification C, or U more severe than C, or for poles within 1 km from a coastline with prevailing onshore winds, one or more of the following additional protective actions should be adopted to achieve the required design life: (a)

Increase the thickness of concrete cover.

(b)

Increase the specified strength grade, or otherwise reduce the permeability of the concrete.

(c)

Apply a protective coating to exposed surfaces.

(d)

Apply a corrosion-resistant coating to the reinforcement or tendons.

(e)

Provide cathodic protection to the reinforcement or tendons.

(f)

Seal the base of spun concrete poles.

(g)

Any other appropriate action.

I6 REINFORCEMENT AND TENDONS I6.1 General

All reinforcement and tendons shall be effectively maintained in their correct position during manufacture of the pole. All supports used for this purpose shall be made from durable and stable materials that are not deleterious to the concrete or the reinforcement. I6.2 Poles designed by load testing

For poles designed by load testing in accordance with Section 8, the following exceptions apply to the requirements for reinforcement and tendons specified in AS 3600 or  NZS 3101.1: (a)

The minimum clear distances between parallel bars and tendons may be waived.

(b)

Lateral restraint of compression reinforcement by ties, or similar fitments, may be omitted.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

172

DRAFT ONLY

(c)

Enclosure of bundled bars, or bundled tendons, within ties or similar fitments may be omitted.

(d)

Shear reinforcement may be omitted if the tested prototypes contain no shear reinforcement and the tests demonstrate that the design strength can be achieved without failure.

I6.3 Poles designed by calculation

For poles designed by calculation, shear reinforcement may be omitted if the calculated shear strength provided by the concrete alone is not less than the minimum levels specified in AS 3600 or NZS 3101.1 for the omission of shear reinforcement in beams.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

173

DRAFT ONLY

APPENDIX J

COMPOSITE FIBRE POLES (Normative) J1 GENERAL

Poles made from composite materials shall be designed in accordance with the appropriate and relevant Australian or New Zealand Standard or by theories supported by rigorous  prototype testing. The materials used shall be suitable for the exposure and design service conditions without  jeopardising operational security of the line. Special attention shall be given to use of fire resistant materials in rural/semi rural applications. J2 STRENGTH

Composite fibre poles are thin walled structures and typically fail due to buckling. Pull through strength on the wall of the pole applied by bolts may be limited with standard washers and large curved plates may be required for surface bearing. Crushing torque is limited and is typically less than 150 Nm. J3 SERVICABILITY LIMITS

Composite fibre poles typically exhibit large deflection limits and these limits must be considered in the design. Manufacturer test data will provide deflection limits at appropriate loads for use in design of the pole.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

174

DRAFT ONLY

APPENDIX K

STEEL POLES (Normative) K1 GENERAL

Steel pole structure designs shall comply with the requirements of AS 4100, NZS 3404.1 or AS/NZS 4600 , or ASCE 48-05 as appropriate, and the following provisions. K2 STRENGTH FACTORS ( )

Strength factors (φ ) which takes into account variability of material and workmanship for steel pole components used shall be taken as 0.9 unless otherwise provided in the reference standard being used. Loading considered in design shall include combined bending and axial loading of the pole element. K3 MINIMUM THICKNESS

The thickness of steel plate used in any structural pole elements shall be not less than 1.6 mm. K4 REQUIREMENTS FOR PLATE THICKNESS LESS THAN 3MM

Where the thickness of steel plate used in a pole is less than 3 mm, requirements apply:

the following

(a)

Welding  Special attention shall be given to weld quality in thin-walled elements and in particular to the avoidance of weld undercut.

(b)

 Fatigue   Structural detailing shall avoid stress concentrations and connections subject to cyclic loading which rely on the localized bending resistance of thin-walled components.

(c)

 Handling Consideration should be given to the need for special handling of thinwalled elements to avoid localized distortion.

(d)

 Durability Due consideration should be given to the potential for accelerated corrosion at and below ground level where pole elements are direct buried into soil or where special backfill is used around the embedded pole element.

K5 LOW TEMPERATURE REQUIREMENTS

Steel grades for poles subject to low temperature conditions shall be chosen in accordance with the requirements for brittle fracture resistance given in AS 4100 or NZS 3404.1 as appropriate. K6 WELDING PROCEDURE FOR THICK BASE PLATES

Care should be applied in the use of thick base plates that have been cut from thick steel  blooms that may contain string inclusions that have the potential to open and delaminate after cutting, welding and during galvanizing due to release of locked in stresses.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

175

DRAFT ONLY

K7 HYDROGEN EMBRITTLEMENT ISSUES WITH HOT DIP GALVANIZING AFTER INCREMENTAL BENDING

Where incremental bending techniques or pressing is employed to form thick plates generally greater than 16 mm and the finished product is acid de-scaled and hot dip galvanized, care needs to be applied to avoid hydrogen embrittlement of cold worked materials. K8 INTERNAL TREATMENT OF STEEL POLES

All closed steel sections will have the potential to accumulate and trap condensation from the air due to temperature variations. This has the potential to accelerate corrosion of the internal surfaces if the internal space cannot vent to the atmosphere. Consideration shall be included in designs for the appropriate treatment of the internal surface to eliminate corrosion; to minimize corrosion effects; or to provide for limited corrosion of the internal surfaces over its intended design service life. K9 SLIP JOINTING

Where joints in segmented construction make use of overlapping close tolerance slip joints they shall be detailed such as to provide a minimum overlap of 1.3 times the largest inscribed circle of the components being joined. Designs shall nominate required dimensional tolerances of fitted sections together with recommended jacking forces for lap joints to ensure full load transfer can be achieved  between sections being joined. K10 ANCHOR BOLTS

Pole footing base plate holding-down bolts shall be proportioned to comply with Table K1.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

176

DRAFT ONLY

TABLE K1 DESIGN OF HOLDING-DOWN BOLTS Straight anchor

Anchor with bend

Anchor with plate

D = 4

v = min ( l,d1)

Lb

I1

Io

t > 0,3 r

D t

D

l2

 F a,Rd =

π × Φ ×  L b ×  f  bd

 F a,Rd =

π × Φ ×  L b ×  f  bd

with  L b  = ( l 1 + 3.2 D + 3.5 l 2)

with:

 f  bd

π × Φ ×  L b ×  f  bd with

 L b  = 2.45 φ

 f cd  ⎛ r 2

⎞ ⎛ r ⎞ 0.25 − ⎜ ⎟ ⎜ 1− ⎟ + l 0  fbd  ⎝ Φ 2 ⎠⎝ v ⎠

= bonding stress of steel into concrete

 F  bd

with:

 F a,Rd =

d1

=

0.36  f ck  γ c

 for plain bars and  f  bd

=

2.25  f ctk0.05 γ c

 for deformed bars

 f ck 

= 0.7  f ctm   and  f ctm = 0.3 f ck  2/3

 f ck 

= characteristic strength of concrete in compression

 f ctm

= average strength of concrete in tension

 f ctk  0.05

= characteristic strength of concrete in tension

γc

= partial safety factor on bonding 1.50

where

= for example with C20/25 concrete—  f ck 

= 20 N/mm 2;

 f ctm

= 2.2 N/mm 2;

 f ctk0.05

= 1.55 N/mm2; and

 f  bd

= 1.1 N/mm 2 for plain bars; or

 f  bd

= 2.3 N/mm 2 for deformed bars

The anchoring length shall be such that—

π× Φ

×  f  bd ≥  F t,Sd

 F a,Rd

=

 F t,Sd

= design tensile force per bolt for the ultimate limit state

× L b

where The size of the bolt shall be such that—  F t,SD ≤  F t,Rd = 0.9 ×  f ub

×  As × γMb

where  f ub

= ultimate tensile strength of holding-down bolt

 As

= tensile stress area of holding-down bolt

γMb

= partial safety factor on resistance of holding-down bolt = 1.25

 NOTE : Acco rding to Cla use 6.6 .5(6) of ENV 199 3-1-1, whe n thr ead s are cut by a non -speci ali st bol t manufacturer, the relevant value of T r ,Rd   s hall be reduced by multiplying it by a factor of 0.85. 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

177

DRAFT ONLY

APPENDIX L

STRUCTURE FOOTING DESIGN AND GUIDELINES FOR THE GEOTECHNICAL PARAMETERS OF SOILS AND ROCKS (Informative) L1 GENERAL PRINCIPLES

This Standard addresses fundamental performance criteria and the design methods associated with overhead line footings and their foundations, and are not to be considered as a rigid set of rules. The principles of this design standard are equally aimed at the design of new and existing foundations. If the foundations are upgraded to meet new loading requirements, care must be taken to assure the structural adequacy of the foundation. Many alternative approaches can be used for the design of footings and the interpretation of the foundation conditions, and the designer should exercise sound engineering judgment in determining which method is most appropriate for the situation. When designing overhead line foundations, the designer has the option to design each footing for site-specific loadings and subsurface conditions or to develop standard designs that can be used at predetermined similar sites. In addition, the relative distribution of the loads between the guys and the support (lattice tower or pole) depends on the guy pretension and the potential creep of the foundation. The flexibility of the guy, together with the flexibility of the structure is needed to compute the ultimate footing reactions and anchor loads. The initial and final modulus of elasticity of the guys, together with the creep of the guys, should be considered. Reference should be made to IEEE Standard 691. L2 GEOTECHNICAL PARAMETERS OF SOILS AND ROCKS

Geotechnical investigation should be carried out along the easement of transmission line to obtain geotechnical parameters required to design the transmission structure footings. As a minimum, the investigation should provide geotechnical parameters required to establish the ultimate load-bearing capacity of the subsurface foundation material and the overlying material properties. At the completion of a geotechnical site investigation a report should be  prepared. Generally, to determine the foundation ultimate load carrying capacity the shear strength of soil is required.  s

=

c +

σntan φ

. . .L1

where  s

=

shear strength

c

=

cohesion

σn

=

normal stress

φ

=

angle of internal friction

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

178

DRAFT ONLY

A cohesive soil can generally be expected to resist design loads for a short duration of time without experiencing significant movements; however when the design loads are applied over the service life of the structure, they may result in excessive displacements. The foundation design for long duration loads should be based on the effective stresses and drained properties of the soil. Soils that have cohesive properties in short term loading usually exhibit no cohesion under long term loads, though the angle of internal friction will increase to typically between 20° and 40°. Granular soils have similar properties under short and long term conditions and this standard recommends that for ‘granular’ soils the same properties are to be used under both long and short term loads. Dense saturated granular materials typically show a reduction in internal friction of 1° to 2° from the dense dry values L2.1 Typical soil properties

Geotechnical parameters for soil strata may be taken from Tables L1, L2, and L4. The values in Table L3 are based on research data and pull out tests on test piles, and their use should be assessed against any known properties from soil tests where these are available. The reduction in shear strength may occur when the soil is partially saturated (see below). In addition, soft clay (or even firm clay) may become very soft clay when it is partially saturated. TABLE L1 TYPICAL PROPERTIES OF COHESIVE SOILS Term

Weight

Shear strength, Cu (kPa)

Field guide to consistency

(kN/m 3 )

Unsaturated

Saturated

Very soft

16–19

0 to 10

≤6

Exudes between fingers when squeezed in hand

Soft

17–20

10 to 25

6 to 12

Can be moulded by light finger pressure

Firm

17.5–21

25 to 50

12 to 25

Can be moulded by strong finger  pre ssure

Stiff

18–22

50 to 100

25 to 50

Cannot be moulded by fingers. Can be indented by thumb

Very stiff

21–22

100 to 200

50 to 100

Can be indented by thumb nail

Hard

20–23

≥200

≥100

Can be indented with difficulty by thumb nail

 NOTE : S atu rat ed mea ns tha t all voi ds are fil led with wat er. The sat ura ted wei ght is not nec essari ly buoyant weight, though there is minimal increase in the degree of saturation required to produce a buoyant condition. Soils may be partially saturated. At optimum moisture content this produces the maximum dry density. Typically OMC range is 10% to 20%. Exceeding that figure will progressively reduce density.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

179

DRAFT ONLY

TABLE L2 TYPICAL PROPERTIES OF NON-COHESIVE SOILS Soil type

Unit weight

Angle of friction,

(kN/m3)

(degrees)

Loose gravel with sand content

16–19

28º–30º

Medium dense gravel with low sand content

18–20

30º–36º

Dense to very dense gravel with low sand content

19–21

36º–45º

Loose well graded sandy gravel

18–20

28º–30º

Medium dense clayey sandy gravel

19–21

30º–35º

Dense to very dense clayey sandy gravel

21–22

35º–40º

Loose, coarse to fine sand

17–22

28º–30º

Medium dense, coarse to fine sand

20–21

30º–35º

Dense to very dense, coarse to fine sand

21–22

35º–40º

Loose, fine and silty sand

15–17

200–220

Medium dense, fine and silty sand

17–19

25º–30º

Dense to very dense, fine and silty sand

19–21

35º–40º

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

180

DRAFT ONLY

TABLE L3 TYPICAL PROPERTIES OF ROCK Ultimate design values Type/classification Shear (kPa)

Bearing (kPa)

Dry density (kg/m 3 )

Hard

Igneous Basalt

1200

6000

27

1000

2500

24

750

1500

24

275

450

22

Granite Granodiorites Metamorphic Greywacke Hornfelds Quartzite Limestone Schists Sedimentary Hard sandstone Medium rock

Highly fractured hard rocks Medium sandstones Hard shale Conglomerates Weathered Granite Rhyolites Soft rock

Soft sandstone Mudstone Medium shale Phyllite

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

181

DRAFT ONLY

It should be acknowledge that the engineering properties of rock cannot be predicted with the accuracy typical in a soil investigation. The rock properties are related to rock defects i.e. weathering, joints, faults, shear and bedding zones etc. In addition, during an investigation (or construction works) when the core hole penetrates a fault zone additional  breaks in rock may occur. These breaks promoted/produced by these activities should be included in the estimated rock quality. L3 FOUNDATION DESIGN FOR POLES L3.1 Foundation types

Common types of pole footings are bored piers in soil, bored and socketed piers into rock, large diameter bored or driven caissons (normally with permanent liners), buried slab or raft footings, anchored footings (in soil or rock), and single pile or pile group foundations (in soils unable to support loads in surface formations) This section concentrates on the design requirements for lateral loads and moments only. When there are special requirement for compression loading the footings should be checked using established principles. L3.2 Bored Piers

The Brinch Hansen method presented here is considered to be appropriate to the dimensional range and characteristics of poles in transmission and distribution line structures. Other design methods may be used. This method is applicable to a wide variety of soil types and provides consistent results. Typically, the correlation between predicted and observed test results has been: (b)

undrained conditions:  H L = 1.01  H calc   with COV = 0.36

(c)

drained conditions:

 H L = 0.60  H calc with COV  = 0.37

where  H L

=

nominal failure load

 H calc

=

calculated value using recommended method

COV  =

coefficient of variation

It should be borne in mind that the accuracy of any solution will be limited by the accuracy of the input data. The appropriate component strength factor (Table 6.5) should be applied to HL. The Brinch Hansen method does not provide an indication of the pole rotation at the  H L load. This should be calculated separately using methods recommended in AS 2159 or another suitable source. (As a general indication, ground line rotational displacements of 1–  2° may be expected at  H L, though the centre of rotation is dependent on the foundation geometry and soil parameters.) If the load displacement plot is assumed to be hyperbolic and the initial slope and  H max . value are known, then values along the curve may be calculated. The initial slope is dependent on the modulus of elasticity for the soil and the foundation geometry.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

182

DRAFT ONLY

L3.3 Analytical procedure for determination of failure load/moment

The mathematical model of the pole/soil system is shown in Figure L1.

M

Ground surface

H Z Rigid body rotation

 Z r

F 2

 Z 2

Backfill

L

 Z 1

P 2

Centre of rotation F 2

Soil pressure distribution

D

FIGURE L1 MODEL OF THE POLE/SOIL SYSTEM

The system is subjected to a ground line lateral load,  H , and bending moment,  M . The ‘effective diameter’,  D, can be taken as the average pole diameter below ground for soil  backfill situations and the auger diamete rs for situations where concrete or soil/cement  backfill is used. The pole is assumed to rotate as a rigid body under the applied loads about a point of rotation at an unknown depth,  z r , below the surface. At the point of failure this rotation  produces a soil stress distribution as depicted in Figure B2 with the ultimate soil pressure,  p , varying with depth below the ground surface, z . The ultimate lateral soil resistance at any depth, z, below the surface can be expressed as—  P z

=

q z K q + cu K c

. . .L2

where qz

=

vertical overburden pressure at depth  z  = γ z 

γ

=

soil density (see Table L4)

cu

=

soil cohesion (see Table L1)

 K q,  K c =

factors that are a function of  z/D   and the soil angle of friction, φ   (see Table L2)

Values of K q are given in Table L5, and those of K c are plotted in Table L6.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

183

DRAFT ONLY

TABLE L4 TYPICAL SOIL DENSITIES Density (kN/m3 )

Soil type

Unsaturated

Saturated

16–18

9–11

Gravel

16–20

9.5–12.5

Coarse and medium sands

17–21

9.5–12.5

17.5–21.5

9.5–12.5

17.5–21

9.5–12.5

17.5–22.5

11–16

13–19

6.5–12.5

Cohesive soils  Non-co hes ive soils:

Fine and silty sands Rock/soil mix—Granite and shales Rock/soil mix—Basalts and dolerites Rock/soil mix—Limestones and sandstones

 NOTE : The sat ura ted den sities giv en abo ve result from the pre sence of ground wat er and soil por osity for the different soil types.

The limiting combination of  H and M   to cause failure may be obtained by considering the equilibrium of horizontal forces and moments, and solving the resulting simultaneous equations for the unknown depth of the centre of rotation, z r . In general form the equations are— (a)

 Horizontal equilibri um  H 

=

 F 1 −  F 2

. . .L3

where  F 2  F 2

(b)

= =

 z r 

∫

0  L

∫

zr 

 pz Ddz 

. . .L4  Ddz 

z

 Moment equili brium  M 

=

 F 2 z 2 −  F 1 z 1

. . .L5

where  z 1

=

distance to resultant load  F 1

 z 2

=

distance to resultant load  F 2

It is usually more convenient to solve the resulting equations by trial and error. That is, for a given horizontal load,  H , and a trial embedment depth, L , the unknown depth of rotation,  z r , and moment,  M , can be determined. The process is repeated by varying  L   until the required  M   is obtained. For non-cohesive soils, e.g. dry sand, the depth of rotation is typically 2/3 of the total depth. For cohesive soils, e.g. clayey sands, the depth of rotation is typically slightly more than half depth. As the eccentricity of load increases zr converges to either 2/3 or 1/2 of the total depth. Where a bed log is used the calculated soil forces F 1   and  F 2  may be based on the Brinch Hansen method. The forces should be based on soil pressure  p z  and the areas of the bed log and the pole foundation.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

184

DRAFT ONLY

TABLE L5 EARTH PRESSURE COEFFICIENT FOR OVERBURDEN PRESSURE,  K q Angle of friction  z/D

0°

5°

10°

15°

20°

25°

30°

35°

40°

45°

1.0

0

0.5 0

1.10

1.85

2.81

4.12

5.99

8.85

13.50

21.81

1.5

0

0.5 2

1.16

1.97

3.02

4.46

6.53

9.67

14.75

23.72

2.0

0

0.53

1.21

2.07

3.21

4.76

7.02

10.44

15.96

25.59

2.5

0

0.55

1.26

2.16

3.37

5.04

7.46

11.17

17.12

27.43

3.0

0

0.56

1.30

2.24

3.51

5.28

7.88

11.86

18.24

29.23

3.5

0

0.57

1.33

2.32

3.64

5.50

8.26

12.50

19.32

31.00

4.0

0

0.58

1.36

2.38

3.75

5.70

8.61

13.12

20.37

32.74

4.5

0

0.59

1.39

2.44

3.86

5.88

8.93

13.70

21.38

34.45

5.0

0

0.60

1.42

2.49

3.95

6.05

9.24

14.25

22.36

36.13

6.0

0

0.62

1.46

2.58

4.11

6.35

9.79

15.27

24.23

39.39

7.0

0

0.63

1.50

2.6 5

4.25

6.60

10.27

16.20

25.98

42.55

8.0

0

0.64

1.53

2.7 1

4.37

6.82

10.69

17.05

27.63

45.59

9.0

0

0.65

1.56

2.7 7

4.47

7.02

11.07

17.82

29.18

48.54

10.0

0

0.66

1.58

2.8 2

4.56

7.19

11.41

18.53

30.64

51.39

12.0

0

0.68

1.62

2.8 9

4.71

7.47

12.00

19.79

33.34

56.81

14.0

0

0.69

1.65

2.9 6

4.82

7.70

12.49

20.88

35.77

61.90

16.0

0

0.70

1.68

3.0 1

4.92

7.89

12.90

21.82

37.96

66.69

18.0

0

0.71

1.70

3.0 5

5.00

8.05

13.25

22.65

39.95

71.20

20.0

0

0.72

1.72

3.0 8

5.07

8.19

13.55

23.38

41.77

75.46

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

185

DRAFT ONLY

TABLE L6 EARTH PRESSURE COEFFICIENT FOR COHESION,  K C Angle of friction  z/D

~0°

5°

10°

15°

20°

25°

30°

35°

40°

45°

1.0

4.8

5.7

6.8

8.2

10.2

12.9

16.9

22.8

31.9

47.2

1.5

5.3

6.4

7.7

9.5

11.9

15.4

20.6

28.4

40.8

61.3

2.0

5.7

6.9

8.4

10.5

13.3

17.4

23.7

33.5

49.1

75.0

2.5

6.0

7.3

9.0

11.2

14.4

19.1

26.4

38.0

56.8

88.1

3.0

6.2

7.6

9.4

11.8

15.3

20.5

28.7

42.0

63.9

100.7

3.5

6.4

7.9

9.8

12.4

16.1

21.7

30.8

45.7

70.6

112.8

4.0

6.6

8.1

10.1

12.8

16.7

22.7

32.6

49.0

76.9

124.5

4.5

6.7

8.3

10.3

13.1

17.3

23.6

34.2

52.1

82.8

135.8

5.0

6.8

8.4

10.5

13.4

17.7

24.4

35.6

54.8

88.4

146.7

6.0

7.0

8.7

10.9

13.9

18.5

25.8

38.0

59.8

98.6

167.4

7.0

7.1

8.8

11.1

14.3

19.1

26.8

40.1

64.0

107.7

186.7

8.0

7.2

9.0

11.3

14.7

19.7

27.7

41.8

67.6

115.9

204.8

9.0

7.3

9.1

11.5

14.9

20.1

28.5

43.2

70.8

123.3

221.8

10.0

7.4

9.2

11.7

15.1

20.4

29.1

44.5

73.6

130.1

237.8

12.0

7.5

9.4

11.9

15.5

21.0

30.1

46.5

78.3

141.9

267.1

14.0

7.6

9.5

12.0

15.7

21.4

30.9

48.1

82.1

151.9

293.3

16.0

7.6

9.6

12.2

15.9

21.7

31.5

49.4

85.3

160.4

316.8

18.0

7.7

9.6

12.3

16.1

22.0

32.0

50.5

87.9

167.8

338.0

20.0

7.7

9.7

12.4

16.2

22.2

32.4

51.3

90.2

174.3

357.3

The over burden pressure and earth pressure coefficients,  K qz ,  K cz   at depth  z   as given in the table above can be calculated from the formulae below.  NOT E: For more inf ormation on these for mulas refer to the origin al Bri nch Hansen paper (see reference at the end of this Appendix).

 K 0

=

1 −sin ϕ

. . .L6

d c∞

=

1.58 + 4.09tan 4ϕ

. . .L7

 N c

=

 K

0 q

∞

1 ⎡ π tan ϕ  2 ⎛ 1 tan ⎜ π + ϕ ⎢e 2 ⎝4 ⎣

=

 K q

=

αq

=

 K qz

e

⎛ 1π +ϕ ⎞ ϕ ⎜2 ⎟ tan ⎝ ⎠

⎞ −1⎤ cot ϕ  ⎟ ⎥ ⎠ ⎦

. . .L8 ⎛1

⎞

−⎜ π −ϕ ⎟ tan ϕ   1 ⎞ 1 ⎞ ⎛1 ⎛1 cos ϕ tan ⎜ π + ϕ ⎟ − e ⎝ 2 ⎠ cos ϕ tan ⎜ π − ϕ ⎟   2 ⎠ 2 ⎠ ⎝4 ⎝4

∞

 N c d c K o tan ϕ   K q0 ∞

( K q

 K q0

= 1+ α q

. . .L10  K o sin ϕ 

− K  ) sin ⎛ 1 π + 1 ϕ ⎞ ⎜4 ⎟ 2 ⎠ ⎝ 0 q

+ K q∞α q

. . .L9

. . .L11

 z   D

. . .L12

 z   D 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

186

0 c

 K 

=

 K c∞

=

αc

=

 K cz

e

⎛ 1 π + ϕ ⎞ tan ϕ  ⎜2 ⎟ ⎝ ⎠

⎛1 cosϕ tan ⎜ π ⎝4

1 + ϕ − 1 ⎟⎞ cot ϕ 2 ⎠

DRAFT ONLY

 

 N c d c∞

. . .L14

 K c0

⎛1 2 sin ⎜ π ( K c − K  ) ⎝4 ∞

 K c0

0 c

+ K c∞α c

= 1+ α c

. . .L13

1 + ϕ ⎞⎟ 2 ⎠

. . .L15

 z   D

. . .L16

 z   D

where  z 

–

depth (metres)

 D

–

pile diameter (metres)

ϕ

–

soil friction angle (degrees)

L3.3.1.1 Shear design for bored piers

While several theories are available to assist in the analysis of forces developed in bored  piers, the following approach is recommended. Soil pressures are ass umed to be developed as indicated in Figure L2.

FIGURE L2 THEORETICAL SOIL PRESSURE DIAGRAM

The maximum shear value to be used in design calculations is as indicated in Figure L3.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

187

DRAFT ONLY

Shear design values

d 

d 

FIGURE L3 EQUIVALENT PILE SHEAR DIAGRAM

L3.3.1.2 Design of shear reinforcement

Basic requirements for calculation shall be based on provisions of AS 3600, and as set out  below:

 A bd

d o

d 

2a

C

FIGURE L4 CALCULATION OF SHEAR REINFORCEMENT

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

V *

188

=

≤φ V u

=

φ (V uc  +  V us )

DRAFT ONLY

. . .L17

Concrete and longitudinal reinforcement contribution— 1

V uc

=

 β 1 β 2 β 3 A bd

⎛  Ast f c′ ⎞ 3 ⎜  A ⎟ ⎝  bd ⎠

. . .L18

where  β 1as per AS 3600  β 2 as per AS 3600  β 3 

=

1.0

 Ast

=

half of the longitudinal reinforcement area

 A bd

=

concrete area equivalent to AS3600 ‘ bvd o’ to be calculated as follows: 2

d2

⎛ d  ⎞ (Π − α ) + ⎜ − c ⎟ tan(α ) 4 ⎝2 ⎠

 A bd

=

α

=

arccos

d o

=

d  − c

bv

=

 A bd /d o

. . .L189

⎛ d − 2c ⎞ ⎜ d  ⎟ ⎝ ⎠

Remaining symbols are as per AS 3600 Shear reinforcement contribution— V us

=

⎛ Π ⎞ ⎛ Asv fsv.f d o ⎞ cot θ  ⎜ 4 ⎟ ⎜  s ⎟ ⎝ ⎠ ⎝ ⎠

. . .L20

The minimum shear reinforcement shall be provided as per AS 3600 and the shear strength of a column with minimum reinforcement is given by the following: V u.min =

V uc  +

⎛ Π ⎞ 0.6 A  bd ⎜4⎟ ⎝ ⎠

. . .L21

L4 FOUNDATION DESIGN FOR LATTICE STEEL TOWERS L4.1 Foundation types

Lattice tower footings typically are designed for vertical forces (uplift or compression) combined with horizontal shear forces. The affect of footing movements due to differential settlement and variation in material types at the same site, should be included in the design. There are many footing types used for transmission lines. This Standard recommends design principles for the common types only i.e.— (a)

 bored straight-sided (and undercut (belled)) piers in clays and sands;

(b)

 bored piers socketed in soft to me dium strength rock;

(c)

guy anchors; and

(d)

excavated footings.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

189

DRAFT ONLY

Common types of tower footings are bored piers in soil, bored and socketed piers into rock, large diameter bored or driven caissons (normally with permanent liners), buried slab or raft footings, grillage footings (constructed on older lines or where access for plant is difficult), anchored footings (in soil or rock), and single pile or pile group foundations (in soils unable to support loads in surface formations) Refer to Figure L5 for typical details.

300 Normal variable up to 1500

300 Normal variable up to 1500

Ground level

300 Normal variable up to 1500

Ground level

 Va r i a bl e depth to rock 

Column reinforcing Rock level

Ground level

Column reinforcing to transfer load

Shear connectors

Column reinforcing

Short stub

Rock  Socket

Depth 2000-6000

Ø450-1000

Ø450-1000

Ø 4 5 0 -1000

Leg stub anchorage

Leg stub anchorage

Construction extension Ø200-2000

300 Normal variable up to 1500

300 Normal variable up to 1500

Ground level

Ground level Compacted backfill

Compacted backfill

2000-6000

Compacted backfill

Over the materials 2000 max. typ.

Rock level

Ø450-1000 Column reinforcing

1000 typ.

Leg stub anchorage

Leg stub anchorage Cement or chemical grouted tendons

2000-4000 Base slab 500 - 1500

FIGURE L5 TYPICAL TOWER FOOTING ARRANGEMENTS

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

190

DRAFT ONLY

L4.2 Footing design L4.2.1 Bored piers

Bored piers are formed by auguring a hole into soil (or soft rock), installing a full length stub angle or shorter stub angle and a reinforcing cage, and then filling with concrete. Transfer of force from the stub angle to the surrounding concrete is usually by cleats, though stud bolts are occasionally used. The base of the bored pier may be enlarged to form a ‘bell’ using an under-reaming tool. ‘Belling’ a pier in such soil conditions provides enhanced uplift capacity but only for shallow piers. Belled piers are not suitable for soils which may collapse due to water inflow, or other causes, during construction. Soil conditions with strong water inflows or weak soil strata may necessitate a permanent liner/steel casing for at least part of the depth of the pier being installed. Installation of  permanent liner wil l reduce the pier’s side resist ance which should be accounted for in the analysis. L4.2.2 Uplift analysis

The general ultimate pier uplift capacity is given as— QU

=

GP + G S + Q S + QB

. . .L22

where QU

=

uplift capacity of foundation

GP

=

pier weight (dead load)

GS

=

soil weight (dead load)

QS

=

side resistance of pier or along cylinder of soil

QB

=

contribution of bearing on top of bell (where applicable)

Tip suction should not be used in the design of footings. The failure mechanism depends significantly on the ratio of soil strength to soil stiffness. Since reliable data on soil stiffness is seldom available, it is recommended that three simplified failure models be used. The ultimate capacity should be taken for the model giving the lowest value of Q U. The interaction between soil and the footing is complex. The relative stiffness, strength and stress state of the soil, all of which vary with depth and are rarely known (outside the laboratory) with the precision associated with engineered material has lead to the development of simplified foundation failure models. It is recommended that three simplified failure models be examined in the design of piers. The ultimate capacity should  be taken for the mode l giving the lowest value of Q U. The pier capacity in uplift is invariably less than that in compression because movement of the pier will create tension in the soil mass and will tend to reduce of the lateral stress state in the soil. L4.2.2.1 Pier pull-out by shear failure model

A pull-out capacity is calculated by assuming failure of shaft friction along the depth of shaft plus the bearing on shoulder of the under-cut if present. The shaft adhesion is a fraction of the soil cohesion. For low cohesion values the adhesion is nearly equal to the cohesion. As the soil strength increases the fraction of cohesion that can be relied upon for adhesion reduces.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

191

DRAFT ONLY

8.74 mm

Qu

Ground Level

L0 DS GP QS

L1 QS

QB

L

QB

DU

FIGURE L6 SHEAR FAILURE MODEL

QU

=

G P + QS + QB

QU

=

uplift capacity of pier

GP

=

pier weight (dead load)

QS

=

side resistance of pier

QB

=

bearing on top of bell (where applicable)

QP

=

. . .L23

where

φ V CγC

. . .L24

where V C

=

volume of concrete

γC

=

concrete density

φ 

=

capacity reduction factor typically 0.9 for concrete foundation (weights and conductor vertical loads are known)

Qs

=

⎛  pDs L2 ⎞ φ  g f sπ D S( L 1− L 0) + γs K tan δ ⎜ ⎟ ⎝ 2 ⎠

where  f s

=

shaft adhesion factor (refer to Figure L7)

 L 1

=

length shaft

 D s

=

shaft diameter

 L 0

=

ignore first 0.5 m or 0.5*  DS  whichever is greater

γs

=

effective unit weight of soil

 K 

=

coefficient of horizontal soil stress

δ

=

friction angle between shaft material and surrounding soil

φ  g

=

geotechnical capacity reduction factor varies from 0.8 to 0.5

8326-PDR - 24/07/2008 14:25:50

. . .L25

DRAFT ONLY  

192

DRAFT ONLY

 ,   r   o    t   c   a    F   n   o    i    t   c   u    d   e    R

Undrained Shear Strength cu (kPa)

FIGURE L7 SHAFT ADHESION FACTOR

For undrained condition— QB

=  

− Ds2 ) + po ))

. . .L26

⎛ π ( Du2 − Ds2 ⎞ φg ⎜ ⎟ σ v  N c 4 ⎝ ⎠

. . .L27

φgπ ( Du2

(4(7cB

For drained condition— QB

=  

where C B

=

bell shear

 D U

=

undercut (bell) diameter

 N c , N q =

 bearing capacity factors

γ( L −  L1) .5 for uniform soil profile

σ v

=

effective vertical stress =

γ

=

soil weight

φ  g  

=

geotechnical capacity reduction factor varies from 0.8 to 0.5

 N q

=

e

 N c

=

( N q −  1)cot

 N γ

=

πtan φ

 tan 2 (45 +

φ/2)

φ 2( N q −  1)tan φ

L4.2.2.2 Pier pull-out by cylinder failure model

This model of failure is based on failure of cohesion on the surface of an equivalent cylinder which diameter equals to the effective diameter of the undercut  D E. The effective diameter of the undercut  DE  =  Ds + ( Du −  D s)/  ζ    should be based on ultimate soil properties and should be not less than shaft diameter 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

193

DRAFT ONLY

The method uses soil cohesion i.e. soil-to-soil friction that is equal to cu  in clays and φ s in sands. QU

=

G P + QC +Q B

. . .L28

where QU

=

uplift capacity of pier

GP

=

pier weight (dead load)

QC

=

side resistance of cylinder of effective pier diameter

Q C = φ  g   f cπ DE ( L −  L 0)

. . .L29

where  f c

=

soil cohesion i.e. soil-to-soil friction that is equal to cu  in clays and φ s i n sands

 D E

=

effective pier diameter =

ζ

=

bell diameter reduction coefficient varies from 1.5 to 3

 L 0

φ  g  

= =

 Ds + ( Du − Ds )

ζ 

 L minus (0.5 m or 0.5*  DS) whichever is greater

geotechnical capacity reduction factor varies from 0.8 to 0.5

QP = φ  g V C γC

. . .L30

where V C

=

volume of concrete

γC φ   

=

concrete density

=

capacity reduction factor typically 0.9 for concrete foundation as weight and conductor vertical loads are known)

Gs = φ  g V sγs

. . .L31

where =

soil weight (dead load)

V s

=

volume of soil

γCs φ   

=

effective unit weight of soil

=

capacity reduction factor typically 0.8

Gs

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

194

DRAFT ONLY

FIGURE L8 CYLINDRICAL FAILURE MODEL

L4.2.2.3 The earth cone pull-out model

The earth cone pull-out assumes that the uplift resistance is given only by the weight of soil and foundation within the cone. Theoretically, when the cone angle is zero, this method is a lower limit to the uplift capacity because it disregards the soil stresses and strength. Different soils characteristics require different cone angles, and there is no rational basis to establish these angles in a general manner. In addition, reference should be made to IEEE 691 for Kulhawy’s work regarding modification for cone breakout. This method generally does not govern for deeper footings and tend to underestimate the uplift capacity for shallow footings (depth ≤10 times shaft diameter) with soil of medium to dense consistency and stress states corresponding to normally consolidated or lightly overconsolidated. For deeper piers, the computed uplift resistance increases rapidly with depth while the results of model and field tests show only 1/4 to 1/7 the increase expected from computed values. This difference between observed and computed values suggests that the method does not accurately model the influence of embedment depth on uplift capacity. For that portion of the failure cone or pyramid below the groundwater table, the submerged weight of the footing and soil should be used to determine the uplift capacity.

FIGURE L9 CONE FAILURE MODEL

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

195

QU

=

G P + GS

DRAFT ONLY

. . .L31

where QU

=

uplift capacity of pier

GP

=

pier weight (dead load)

GS

=

weight of soil

QP

   V C γ C φ 

=

. . .L32

where V C

=

volume of concrete

γC

=

concrete density

    φ 

=

capacity reduction factor typically 0.8

GS

=  

   gV Sγ φ 

. . .L33

where V S

=

volume of soil

γ θS

=

soil density

   g φ 

=

=

varies between 10° to 30° geotechnical capacity reduction factor varies from 0.8 to 0.5

L4.2.3 Compression analysis

The failure model for compression loading involves a bearing failure in the soil below the toe of the pier and a shear failure between the pier shaft and soil or within the soil close to the soil/pier interface, allowing the pier to move downwards in relation to the surrounding soil. Piers loaded in compression do not reach a clearly defined ultimate capacity. Rather, load tests demonstrate that pile capacity continues to increase indefinitely as pier settlement increases. The side resistance of stiff piers (the usual case for transmission structure foundations) has been shown to be fully developed at displacements of less than 20 mm, whereas the development of bearing resistance under the toe of the pier is scale dependent. For this design standard, ultimate capacity for compression loading of piers is defined as the compression load reached at a settlement of 5% of the pier diameter (or bell diameter for the case of belled piers), by which stage the side resistance is usually fully mobilized together with a significant proportion of the end bearing resistance.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

196

FIGURE L10

QC

− GP +

=

DRAFT ONLY

COMPRESSION ANALYSIS MODEL

Q S + Q B

. . .L34

where QC

=

compression capacity of pier

GP

=

pier weight (dead load)

QS

=

side resistance of pier

QB

=

bearing under pier tip (bell where applicable)

GP

   g V C γC φ 

=

. . .L35

where V C

=

volume of concrete

γC

=

concrete density

   g φ 

=

geotechnical capacity reduction factor typically 1.2

Qs = φ  g   f cπ D s( L 1 −  L0)

. . .L36

where  f s

=

shaft adhesion

 L 1

=

length of shaft =  L for straight-sided pier

 D s

=

shaft diameter

 L 0

=

ignore first 0.5 m or 0.5*  DS  whichever is greater

φ  g

=

geotechnical capacity reduction factor varies from 0.8 to 0.5

φπ  Du 2

(4(9CB

+

. . .L37

p0 ))

where C B

=

bell shear 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

197

 D U

=

undercut (bell) diameter =  D S  for straight-sided pier

 p 0

=

overburden pressure = γ L  for uniform soil profile

γ

=

soil weight

φ   g

=

geotechnical capacity reduction factor varies from 0.8 to 0.5

DRAFT ONLY

L4.2.4 Bored piers socketed into rock

In fractured rock the failure mechanism is complex and is dependent on strength of the rock, bedding and fracture planes, and the depth to rock. Rock can be treated as hard clay or as rock with substantially more stiffness/rigidity. If rock is assumed to be sound i.e. no fractures bedding planes etc, then uplift capacity should be based only on rock – concrete shear strength. Soil friction – adhesion is largely irrelevant as the footing must move (i.e. fail in rock) before adhesion-friction is realised (conservative assumptions). If there is concern about fractures in rock, may assume a 45° fracture surface with weight only. If heavily jointed or shattered rock a failure cone of 30° should be assumed. The failure mode in rock is (nearly) the same as for pier in soil. Two uplift cases (pier and cone pull-outs) shall be considered for piers socketed into rock, the critical case shall be that giving the lowest capacity. L4.2.4.1 Mobilization of rock mass

FIGURE L11

ROCK MOBILIZATION MODEL

The general ultimate pier pull-out capacity is similar to the straight-sided bored pier and is given as— QU

=

0.8 GP + 0.8 GS + 0.8 GR  + φ   g Q S + φ   g QR 

where QU

=

uplift capacity of foundation

GP

=

concrete density (dead load)

GS

=

soil density (dead load)

G R 

=

rock density (dead load)

QS

=

side resistance of pier in soil 8326-PDR - 24/07/2008 14:25:50

. . .L38

DRAFT ONLY  

198

=

side resistance of pier in rock

=

cone angle in rock

=

35° for rock masses that are closely jointed and/or weathered

Q R 

θ R 

DRAFT ONLY

45° for other rock masses θ S

=

cone angle in soil varies between 10° to 30°

φ   g

=

geotechnical capacity reduction factor varies from 0.8 to 0.5

L4.2.4.2 Pier pull-out by shear failure model

Refer to Paragraph L4.2.4.1. L4.2.5 Guyed anchors L4.2.5.1 Cast in-situ anchor blocks

Anchors for guys can be installed by boring or excavating a vertical shaft into which feeds an inclined hole containing the below ground anchor tendon. The base section of the shaft is then partially filled with concrete to form an anchor block. The analysis of buried concrete guy anchors foundation subjected to uplift is complex and consequently the following simplified approach may be adopted to enable the guy foundation to be checked for uplift and sliding resistance.

θ A 

QU

Ground level QS

GS

S1

DG

QS

G A  PP

S2

S2

P A 

D A 

S3

B

* L

FIGURE L12 CAST IN-SITU ANCHOR BLOCK

The capacity reduction factor should be 0.5 and not less than the factor applicable to the stay tension. Anchor concrete blocks are frequently installed without any reliable knowledge of geotechnical soil properties. The appropriate soil properties should be adopted based on the weakest material in contact with the anchor block. In some cases this may be backfill material. Uplift resistance is— QV

=

0.8 GS + 0.8 GA  + φ gQS + φ gS 2

where QU

=

ultimate anchor tension force

 K 0

=

coefficient of earth pressure at rest

8326-PDR - 24/07/2008 14:25:50

. . .L39

DRAFT ONLY  

199

=

vertical component of Q U

=

QU *sin θ A

GA

=

concrete density (dead load)

GS

=

soil density (dead load)

φ 

=

angle of shearing resistance

 D G

=

soil depth above anchor

 B

=

anchor width

 L

=

anchor length

 D A

=

anchor depth

QS

=

side resistance along soil above anchor

=

γ K 0 D2G ( B +  L)tanφ 

=

shearing resistance on perimeter of anchor

=

2 γ K 0 DA ( D G + 0.5 DA )( B +  L )tan φ 

=

geotechnical capacity reduction factor varies from 0.8 to 0.5

QV

S 2

φ g

DRAFT ONLY

Sliding resistance is— QH

=

φ g (  P P +  P A + S 1  + 2 S 3)

QU

=

ultimate anchor tension force

=

horizontal component of QU

=

QU cos θ A

=

active back pressure on back of anchor

=

γ K P( DG+0.5 DA) B L

=

passive earth pressure on front of anchor

=

γ K A( D G+0.5 DA) BL

=

shearing resistance at top of anchor

=

γ DG BLtan φ 

=

shearing resistance on sides of anchor

=

2 γ KD A ( D G+0.5 DA ) BL tan φ 

=

geotechnical capacity reduction factor varies from 0.8 to 0.5

. . .L40

where

QH

 P A

 P P

S 1

S 3

φ g

L4.2.5.2 Bored pier anchors

Bored pier anchors or micropiles comprise a single small diameter inclined concrete filled  bored pier into which the anchor tendon has been inserted prior to pouring the concrete. The load applied to the anchorage is transferred to the base of the footing by a centrally located tension tendon. The anchorage is only designed to withstand the applied guy tensile load. The principles used in the design are similar to that for normal bored piers.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

200

DRAFT ONLY

L4.2.5.3 Rock anchors

Where firm drillable rock is encountered wit hin 1000 mm of the ground surface small diameter grouted rock anchors can provide an economical solution . The diameter of the drilled holes for the rock anchors is dependent on the grout used. If quick setting epoxy resin grout is used the hole diameter should be no larger than the anchor rod diameter + 20 mm. If cement grout is used, the hole diameter should be larger enough to enable the grout column to be injected and compacted. Adequate corrosion protection should be a pplied to the zone a bove the rock to 300 mm above ground. Concrete encasement can provide a suitable means of corrosion protection. Uplift capacity of the anchorage should be determined in accorda nce with AS 3600 and AS 4100 using rock’s ultimate bond stress and the capacity reduction factor determined by the geotechnical investigation. L4.2.5.4 Proprietary ground anchor systems

The analysis of proprietary ground anchors i.e. screw-in anchors and other forms of soil anchor systems should comply with the manufactures recommendations and have the capacity reduction factor of 0.5 applied. Anchors should be designed and installed to eliminate in-service creep, (other than a small amount of initial bedding in), so that guys loads are sustained without the need for subsequent re-tensioning of the guy wire. Where possible the installed anchors should be proof-tested to their designed load capacity. L4.2.6 Spread footings

Spread footings consist of concrete shaft and an enlarged base of either of mass concrete or a pad (slab) of reinforced concrete. Where the stub extends to base of the footing the shaft may not be reinforced, particularly in the case of the thick mass concrete types. Spread footings are formed by excavating square, rectangular or cylindrical holes in soil or rock using machines or hand-operated tools. The base of spread footings may be straight sided, which requires formwork, or cast against ground. When cast against ground an undercut or bell may be formed depending on soil conditions and the construction methods adopted. Excavated footings are backfilled with the excavated soil, excavated soils improved by cement or lime stabilisation, or imported backfill materials when the natural ground is cannot be compacted to achieve the required uniform strength and/or density. Grillage footings are also a type of spread footings which had common use in the past. Their use is now restricted to sites where access is difficult. Typically grillage footings consists of steel members forming the pyramid which are fixed to the tower stub. Backfill requirements are essentially the same as concrete footings. The design methodology is for these types of footings is similar to bored piers, with appropriate modification for their geometry and the failure occurring in disturbed backfill material, except for undercut footings where the failure may be in natural in situ materials. The three types of failure mechanism considered in the design of spread footings are— (a)

Shear failure —The backfill moves upward in relation to the natural soil, leaving a vertically sided ‘shear’ surface with plan dimensions equal to the base of the foundation. Where an undercut is formed the shear surface will be in natural material, which usually has superior strength properties to the backfill, provided that the excavation and backfilling has not significantly affected the in situ materials.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

201

DRAFT ONLY

The uplift capacity Qu i s— Q u =

φ  ( W +

W 

=

is foundation weight ( W f ) and soil weight ( W s) within foundation volume

Qsu

=

side resistance = 2( B +  L )

Qtu

=

tip resistance typically assumed to be zero

. . .L40

Q su  + Qtu )

where

σ  K  tan δ

If the  K tan δ  over the foundation depth is greater than 1 and  D/B   is less than 6 a cone/wedge breakout is possible. The Qsu   term is modified as follows: Q su  modified =

⎛ 2 +  β  ⎞ ⎜ 3 β  ⎟  Q su   original ⎝ ⎠

in which

β (b)

is  K  tan δ

 Bearing failure —The backfill experiences a bearing failure just above the top of the grillage or pad, and undercut, if formed. The material above the footing compresses and ‘flows’ around the bearing surface to the surround soil. The deformation required to develop the ultimate bearing capacity is usually well in excess of acceptable movement to ensure the tower’s structural integrity. It is a more likely mode of failure in deep footings (depth: width ratios in the order of 4 or more) where the limit on bearing capacity has reached or where the backfill compaction is inadequate.

Where an undercut is formed in natural ground, the incremental bearing capacity should be based on the plan area of the undercut. The bearing capacity of the undercut may be treated in a similar manner to the design of belled pier and should incorporate the capacity reduction factor determined by the geotechnical investigation. Grillage foundation foundations are more susceptible to bearing failure because the high bearing stresses generated by relatively small surface area of the steel in contact with the soil. (c)

Cone failure —The grillage or pad uplifts a wedge of soil in the form of a truncated, inverted pyramid; uplift loads are resisted by the weight of the soil and grillage or  pad, with soil shear along the failure surface taken as zero. Cone failures are possible  because the spread footings are usuall y shallow and the horizontal soil stresses (such as might be found in overconsolidated soils) are relatively high.

The design process should check all three proposed models. The strength of foundation is highly dependent on the method of backfilling which should be factored into any calculations. The critical case will be that with the lowest ultimate strength and acceptable deformations. L4.2.7 Rock or soil anchored footings

This type of footing is based on the applied load being transferred to the soil or foundation material by a number of soil or rock anchors extending below a load transfer cap. The normal design principle is for the transfer cap to transmit compression forces to the foundation material and for the anchors to provide uplift capacity. The progressive de-bonding of the anchor system employed with increasing load due to elastic extension of the tension tendon should be considered. Post-tensioned ground anchor systems can also be used to transfer tensile loads to the ground and provide anchor tendons (bars or pre-stressing strands), connections to the pier cap, corrosion protection, spacers, centralisers and grout. 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

202

DRAFT ONLY

Ground anchors are active anchors i.e. they are post-tensioned after installation, and locked off with an initial load so as to keep anchor extensions at the design load compatible with  pile cap dis placements. Footings are restrained against uplift by post-tensioned ground anchors, grouted into soil or rock, and connected to tower stubs by a pier cap. Anchor tendons should not be designed to resist lateral (shear) loads that are not parallel to the bar lengths. In these cases, pile caps or suitable bearing blocks should be used to  provide resistance to lateral loads. L4.2.8 Deep piled footings

Where weaker foundation strata are encountered deep piled systems can be used. These may take a variety of forms and could be based on cast in-situ systems, precast driven systems, and steel and precast concrete pile systems. Such systems should be designed to comply with the requirements of AS 2159. L4.2.9 Raft footings

Where construction is required in difficult soft soil areas or where limited construction access is available for heavy plant to install deep foundation systems, the use of shouldow depth raft slab footings above or partially below ground may provide a design solution. The concrete slab is normally designed to encompass the complete structure site and has strengthening ribs extending above to also provide containment of soil or rock ballast to resit vertical uplift loads. The stability of the footing and structure is provided by the composite action of the mass of the completed raft. L4.2.10 Load transfer from tower leg to footings

Connections between tower leg stubs and concrete footings may be means of a base plate and anchor bolt extending into the concrete of the footing , or by extending the stub into the shaft and providing suitable means to transfer the stub forces to the concrete. L4.2.10.1 Design of base plates

Base plate design should be generally based on ASCE 10-97 recommendations, except when modified by AS 4100 (e.g. shear stress on bolts) and AS 3600 requirements for bolt anchor length. Note friction of base plate is net friction dependent on degree of prestress in anchor bolts. Concrete column shafts should be proportioned to resist axial, moment and shears forces form tower and any localised effects from anchor bolts e.g. bursting. Bending of base plates should be checked using yield line methods of analysis. Provided that all possible yield lines patterns have been investigated, the lowest computed value for the ultimate moment (assuming plastic section properties) is the ultimate capacity. If bolt distribution or gusset plate geometry is non-symmetrical, a more conservative capacity reduction factor should be used. L4.2.10.2 Design of stubs

The transfer of force from the stub to the surrounding concrete is by a combination of steelconcrete bond and by shear connectors on the stub which transfer force, in a bearing mode to the concrete. In stubs which do not extend to the base of the footings, reinforcement in the shaft transfers the stub forces to the base of the footing. Bond between the stub and the surrounding concrete is adversely affected by the shape and finish on galvanised steel stubs. It is recommended that only ‘friction’ bond be considered in the transfer of force above the studs or cleats. When the stub is tension assumed friction  bond should limite d t o 0.35 MPa if the stress in the stub is less than 300 MPa, or ignored i n the design calculations if the stress is greater than 300MPa. Assumed friction bond in compression should not exceed 0.7 MPa. 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

203

DRAFT ONLY

Most of the stub axial force is resisted by shear connections. The normal method is to  provide bolted or wel ded cleats or studs attach ed to the lower end of the leg stub in sufficient number and spacing to transfer the force below the zone of bond development to the surrounding concrete, and shaft reinforcement if applicable. The design of the shear connectors is based on the bearing capacity of the concrete and load capacity of the connectors as determined by their stiff bearing area and bending capacity of the connector at its yields stress. It cannot be assumed that where multiple levels of connectors are required that the loads will be shared equally between connectors. Strain compatibility between the various elements (stub, connectors, concrete and reinforcement) imperfect concrete construction methods and the tolerances in bolted cleat connector may result in some connectors resisting a higher portion of the load. It is recommended that connectors that are placed in several levels along the stub be designed to resist axial loads not less than 25% greater than the stub design forces. Minimizing the distance between cleat levels will result in a more equal distribution of load  between cleats. However, the spacing should be sufficient to not restrict the flow of concrete around the stub and cleats and to ensure that a punching type shear failure in the concrete between the cleats will not occur. A vertical spacing between the horizontal legs of the cleats of twice the stub leg size will generally satisfy this requirement. Cropping of the ineffective part of the horizontal cleat leg will assist the flow of concrete when space may  be limite d, such as i n reinforced concrete shafts . Where the load transfer cleats are positioned at the base of the footing, the footing design should also be checked for punching shear under both maximum compression and uplift loads. When the stub end is within the shaft, longitudinal reinforcement is required to transmit the axial force to the concrete base. The forces transfer is usually assumed to be in a 45° cone  between the shear connectors and reinforcement. The length of the reinforcement above the cone intersection should be sufficient for the development of full bond strength in the reinforcement. L4.3 Foundation testing

Foundation testing may be used as a means of determining the load capacity of the footing or its components and its foundation materials to meet design requirements. The method of testing should be appropriate to the types of footing, ground conditions, loads and conditions the foundation will be subjected to while in service. Tests should be generally in accordance to AS 2159. L4.4 Cathodic protection

Consideration should be given in the design process to the inclusion of an appropriate cathodic protection system where aggressive soil conditions may exist that could adversely affect the design life of the footing. Such systems can be of the sacrificial anode or impressed current types. Reference

Bulletin No. 12 issued by the Geoteknisk Institut (The Danish Geotechnical Institute – Copenhagen 1961) Topics: BRINCH HANSEN, J., The ultimate resistance of rigid piles against transversal forces, CHRISTENSEN, N.H.,  Mode l tes ts with transvers ally loaded rigid piles in sand .

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

204

DRAFT ONLY

APPENDIX M

GUIDELINES ON APPLICATION OF STANDARDIZED WORK METHODS FOR CLIMBING AND WORKING AT HEIGHTS (Informative) M1 GENERAL OVERVIEW

There have been significant changes in legislation and work practices in the building and construction industries to make work sites safer and this has necessitated changes in work  practices . The following sets out a standardized approach for construction and maintenance work  practi ces on overhead lines, in an effort to further reduce unnecessary hazards for personnel moving between overhead line networks, and to provide uniform work practices around Australia and New Zealand. M2 REFERENCE STANDARDS FOR CLIMBING AND WORKING AT HEIGHTS

AS/NZS 1891

Industrial fall arrest systems and devices

1891.1

Part 1: Harnesses and anceillary equipment

1891.2

Part 2: Horizontal life line and rail systems

1891.3

Part 3: Fall arrest devices

1891.4

Part 4: Selection, use and maintenance

 NENS 05

Nat ional fall protection guidelines for the electrici ty industry

EEA/NZ

Use of Personal Fall Arrest Systems

M3 METHODS FOR ACCESSING WORK POSITIONS M3.1 Use of elevating work platforms (EWP)

All line construction and maintenance work on both pole and steel tower overhead line construction should be assessed on the basis of use of using EWPs as the first option to gain access and work at heights. If due to access constraints or the need to access poles and towers by climbing then attached climbing is permissible provided that appropriate fall arrest systems are used. This is coupled with an increasing need for all overhead line feeders to have greater operational availability and increased use of live line maintenance techniques, work methods should consider the use of EWP’s to the maximum extent. The use of man boxes attached to cranes may provide an alternative to use of EWPs . M3.2 Climbing techniques M3.2.1 Pole structures

Where access for the safe use of an EWP is not available, climbing access may be used only if safe climbing work methods on the structure are possible. Where structures are placed in difficult terrain and access for EWPs is not possible, the structure should be designed for climbing access, and for safe work from the structure. This will require the provision of fittings and devices to assist with the safe access and  positioning of workers on the str ucture. 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

205

DRAFT ONLY

M3.2.2 Lattice steel tower structures

All lattice steel structures should be fitted with facilities to allow climbing access to any work position to permit both de-energized and energized maintenance work. Some live line maintenance techniques on high voltage lines require the placement of workers on the structure as well as in the bucket of an EWP. This may require the transfer of personnel from an EWP to a structure superstructure in order to provide the safest means of access. M4 FALL PREVENTION SYSTEMS

Where any climbing or working at height is likely to be required the structure is to be designed to provide for linepersons to use a portable fall prevention system in accordance with AS/NZS 1891. For overhead line construction and maintenance activities this requires the provision of the following to minimize risk of potential injury with attachment at all times to provide either ‘restrained fall’ or ‘limited free fall’ restraint. M4.1 M4.1 ‘Restrianed fall’ fall arrest M4.1.1 Provision and use of a line workers body belt or work positioning harness

This is a fullbody harness that also has inbuilt shock absorption characteristics.

A combination of anchorage placement and fixed length restraint line or pole strap length which will permit only a restrained fall. This requires 6 kN ultimate strength anchorage for restraint devices. Any structural element should be capable of supporting this load as a single point load application, in a deformed state but without failure.

M4.2

‘Limited free fall’ fall arrest

M4.2.1 Provision and use of a Line workers body belt or work positioning harness.

This is a full body harness that also has inbuilt shock absorption characteristics.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

206

DRAFT ONLY

A combination of anchorage placement and fixed restraint line or length of pole strap which will permit only a limited free fall to <600 mm This requires the anchorage point to have a 12 kN ultimate strength anchorage.

M4.3 Use of static lines

Where multiple workers are required to ascend or descend a structure or to be able to move from position to position on a horizontal plane, the use of a static line may be used as a means of restraint. Where static lines are to be used a maximum of two people may be attached to the line at any one time and a top anchorage capacity of 21 kN is required. This can be achieved by attachment of a fibre sling around a climbing leg-bracing node  point or other structural member node points.

M4.4 Double lanyard restraint

In order to provide for M4.2 and M4.3 above a double lanyard or double pole strap restrain arrangement should be used to provide for the worker to be attached at all times while climbing or while in a work position or moving while in a work area. In all cases of restrained work the attachment/detachment of lanyard or pole strap is to be always above the waist position. Where the above is not possible due to the structural framing arrangement in relation to the required work position then an alternative restraint technique should be used and considered in the design with anchorage above the work position. This may require the provision of anchorage points to support devices such as inertia reels and static lines.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

207

DRAFT ONLY

M5 SPECIFIC STRUCTURE DESIGN PROVISIONS

Where pole steps or step bolts are required they should be in accordance with the provision of AS/NZS 1559.  NOT E: Where a tower or pole rescue is requir ed, each pole step may need to support the weight of two persons. For safety in climbing a step bolt size of 20 mm diameter and a clear shank length of 180 mm may be considered.

Attachment to any bracing node points on a lattice steel tower in general will provide an anchorage capacity of 15 kN. Once a work position is reached the worker is required to use a work positioning restraint  pole strap, in a ‘restrained fall’ position, and this requires the sel ection of anchorage points with at least 6 kN capacity. Any structural load carrying or redundant brace member fixed with a single 16 diameter bolt at each end can provide this load restraint capacity in a non deformed or deformed state. In general, attachment should be at bracing node points where ever possible in order to  provide containment of any potential lanyard movement , and afford more secure anchorage. The following anchorage capacities are required to be provided by the structure design: (a)

Intertia Reel attachment points for work on cross-arm tips—15 kN.

(b)

Attachment to bracing node points for work on E/W peak—15 kN.

(c)

Attachment to bracing node points—15 kN.

(d)

Typical static line attachment point above climbing step bolts—21 KN.

(e)

Typical horizontal restraint of any member in a tower—6 kN.

Refer to Figure M1 for typical arrangement of anchorage points on lattice steel structures.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

 Ty p ic a l s ta ti c line attachment point above climbing st ep b olts – 21 kN

208

DRAFT ONLY

Intertia Reel attachment points for w ork on cross arm tips – 15 kN  At ta c hm e nt to br a c ing node points for work  on E/W pea k – 15 kN  At ta c hm e nt to br a c ing node points – 15 kN  At ta c hme nt to 20 mm step bolts, or anchor loops, – 6 kN DO NOT ATTACH  TO 16 mm ST EP BOLTS Limit of lanyard attachment anchorage restraint – Inertia reel must be used beyond this point Limit of lanyard att achment anchorage restraint – attachment point must be above w aist position (except for Live Line access in crouched p osition to Cross- arm tip but w ith attachment alw ays above w aist)

FIGURE M1 TYPICAL STEEL TOWER CLIMBING ATTACHMENT POINTS AND  ANCHORAGE CAPACITIES

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

209

DRAFT ONLY

APPENDIX N

GUIDELINES ON UPGRADING OVERHEAD LINE STRUCTURES (Informative) N1 SCOPE

This Appendix provides guidelines on the requirements to be fulfilled for the modifications of existing structures and foundations to maintain structural integrity or upgrade structural capacity. Structures should include transmission or distribution towers/poles supporting high voltage electrical conductors or radio communication masts/poles and associated foundations. Criteria for condition assessment of existing structure, remedial work to repair corrosion and third party damage or disrupted members due to overload conditions are excluded from the scope of this Appendix. N2 GENERAL REQUIREMENTS

The following factors should be considered for the up-gradation of transmission structures: (a)

Structure upgrade designs should be prepared and authorised by a qualified structural design engineer with appropriate experience in transmission/distribution structures or radio communication structures.

(b)

The structure as a whole and its component parts should comply with stability, strength and serviceability limit states defined elsewhere in this Standard.

(c)

The designer should select an appropriate structure model for analysis that provides an accurate representation of the actual structure performance and justify assumptions regarding load transfer between existing components and modified components and to foundations.

(d)

The designer should consider changes in OHS legislative requirements, work  practi ces or other directives related to construction safety and personnel access that need to be accommodated in preparation of the scope of modifications.

N3 PURPOSE OF UPGRADE

Structural upgrade is defined as actions taken to improve structural and foundation  performance beyond the initial design specifications. This may be undertaken for a variety of purposes including the following: (a)

Improve structure reliability.

(b)

Change in structure load criteria or operational duty.

(c)

Change in maintenance procedures.

(d)

Modify structure geometry to accommodate increased electrical conductor operating temperature or improve electrical/radiation clearances.

(e)

Fixture of new components to comply with updated OHS criteria for personnel access.

(f)

Adding of new/larger telecommunication equipment.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

210

DRAFT ONLY

N4 STRUCTURAL ASSESMENT

The appropriate stress analysis of transmission tower requires calculation of the total forces in each member of the tower under action of combination of loads externally applied, plus the dead weight of the structure. These loads should have to be evaluated as per requirements specified in this Standard for the changed operational condition. When performing an analysis of an existing structure, careful attention should be given to the method of analysis employed when the structure originally designed. If the steel material property and member properties are not documented, material testing and careful engineering assessment is required. The designer should have to prepare documents for such material testing and engineering assessment which should form an integral part of the structural up-gradation proposal. Field inspection is a pre-requisite for the structural assessment of existing structures to ensure that the structures are in good condition and/or to adjust the capacity of individual structural member. It is possible that the original structure capacity was not utilized fully for various reasons such as unusual terrain conditions, site specific restrictions, availability of materials or conservative 2-D method of analysis. In such cases, structure upgrade can possibly be achieved with minimum effort. However, all original design assumptions should be reexamined again and the designer should determine and document if there is any major difference in the load distribution of the structure with new analysis. A correlation of past model assumptions with new model assumptions should have to be performed for the entire structure. N5 WORKING ON LOADED STRUCTURES

The designer should carryout a comprehensive structural analysis of the transmission structures considered for upgrading prior to any field work, personnel access, structure and/or foundation modification. Existing conductor tensions, component dead weight and resulting loads transferred onto structural supports should be carefully examined and taken into account when developing work procedures and selecting required equipment. N6 LOAD TEST ON STRUCTURES

Load testing can be used to verify that the performance of the structure or component is consistent with the theoretical design or the trialing of options without design. The number of tests and applied load to suit the required COV should be in accordance with Australian St andard AS/NZS 1170.0 or an equivalent recognised standard. This should reflect the accuracy of the calculations, the degree of difficulty in installation of the reinforcement and the security required. Some subjective judgement may be required on the  part of the designer to establish loading and performance criteria. Consideration should be given by the designer to any influence the test rig may have on the  performance of the structure or component. Testing of components should account for actual stiffness and possible variations of the surrounding structure. This should happen due to the modified stiffness matrix at a joint and/or pre-loading on existing member. Testing should preferably be continued maximum 150% of ultimate load or to destruction (whichever occurs first) to verify the presence of any brittle failure close to ultimate load. The tests should be carried out to a test plan which is prepared to demonstrate or test the  performance in sympathy with the design process. The records of the test should include as a minimum— (a)

test plan and purpose of each test; 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

211

DRAFT ONLY

(b)

load and deflection;

(c)

localized deformation;

(d)

any variations of the tested structure or component from the proposed final design and what influence this may have on the test outcome; and

(e)

conclusion.

N7 STRUCTURE UPGRADE N7.1 Lattice steel structure upgrade

The main purpose to upgrade the existing structure is to keep the resistance of the structure (including individual elements of a structure) within the limit of design resistance for the modified loading conditions and/or line design criteria. A list of preferred modification options is given in Paragraph N9. N7.1.1 Tension member upgrade

Strength of tension member can be achieved by replacing existing member with higher  profile or by adding new member to the existing member. The designer should have to propose the temporary load transfer arrangement as well as sequential working procedure for the replacement of any existing member with new one. Tensile strength can also be increased with the use of splice angles bolted with the existing leg member and supplementing angle section to cruciform/T-section by an additional angle. However, increase in wind area should have to be taken into consideration for reassessment of the structure with this arrangement. Strengthening within the nodes and across the joint is not necessary if the net cross section multiplied by the yield strength of the material is higher than the maximum force. If strengthening within the nodes and across the joint is required, the supplemented angle should have to pass through the joints by  providing adequate distance to clear the bolt threads of existing joint by providing splice angles with appropriate thickness. The splice angles should be arranged at least at one-third distance of the total buckling length. It is preferable to weld (or service level non slip bolted joint) the splice angle at the circumference with fillet seams to the supplemented sections in the workshop and after galvanizing the same adjust them to the existing members at site. However, Welding is not desirable in many cases due to the poor fatigue performance of welded connections. Refer to Paragraph N7.1.3 for connection details and Paragraph N7.1.4 for load transfer between old and new members. N7.1.2 Compression members upgrade

The strength of compression member can be increased by reducing its unsupported length or end restrained condition. Unsupported length can be reduced by inserting additional redundant members or changing the redundant pattern. Increasing the number of bolts at end of single bolted members should change the end restrained condition of compression member which in turn should increase the compression strength. Addition of new member should also increase compression strength of members. Refer to Paragraph N7.1.1 for the requirement of such modification. How ever, the sub-members should have to be bolted in such a way so that the composite member can be treated as a single member (i.e. fully composite section).

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

212

DRAFT ONLY

T-section should have the improved slenderness ratio and hence, changing compression member to that profile (especially to increase the diaphragm strength by providing T-shaped horizontal edge member) should increase the compression strength.

 Y 

0.5 L

L

 X   NOTE: Critical slenderness ratio should be the maximum of 0.51/r xx and L/r  yy.

FIGURE N1 CRITICAL SLENDERNESS RATIO OF T-SECTION

However, improvement in buckling performance is the best way to increase the compression strength of any member unless the modification in angle section yields an efficient load transfer. Please r efer to Paragraph N7.1.3 for connection detai ls and Paragraph N7.1.4 for load transfer between old and new members. N7.1.3 Connection upgrade and consideration in connection design

Connection can be upgraded by the use of high strength bolts confirming to specification AS/NZS 1252. Use of additional bolts at joint should also increase the connection capacity. Special attention should be given while designing connection between supplemented and existing angle sections. The connection between old member and supplemented member should have to be designed for a shear force equal to 2.5% of the composite member compression force. At least two bolts should be used at each connection. The bolt spacing should not be more than 6  xd  b , where d  b   is the diameter of hole. The connection between existing member and the supplementing member may be designed as non-slip joint. However, due care should be given to verify the bolt pretension and the faying surface condition at site to ensure the requirements considered during design are properly implemented. The slip factor should have to be assumed as per recommendation given in AS 4100. The surface should be roughened by means of hand wire brushing (after hot dip galvanization) and the treatment should be controlled to achieve visible roughening or scoring (but not removing the coating). Power wire brushing is not permitted because it may polish rather than roughen the surface, or remove the coating. N7.1.4 Force distribution in newly formed composite section

Addition of an angle section (as described in Paragraphs N7.1.1 and N7.1.2) moves the centroidal axis of the leg members outwards. However, since the existing member is preloaded with external forces, the supplemented member will not carry the load  proportionately with respect to the relative stiffnes s. This initial loading condition causes a higher proportionate axial load to the existing member and a lower one to the supplemented section. Due care should have to be taken during design to account such effect arising from the installation condition. It is essential to confirm minimum relative movement of submembers of the newly formed compound member to ensure balanced load distribution. In such case, slip in the serviceability limit state is required to be limited and connections should be designed for bolts serviceability limit state (see AS 4100).

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

213

DRAFT ONLY

N7.1.5 Guying of structures

Guys can be used in various arrangements to reinforce structures. The design of the guy system and supported structure should as a minimum account for— (a)

 possible variations in the effective stiffness of individual guys within the sys tem caused by variations in initial installed tension, foundation movement, variation in structure stiffness compared to actual stiffness. As a minimum it is recommended that combinations of guy stiffness varying to 150% and 50% of the proposed cable be considered. Load testing of the guy anchors is recommended to ensure against excessive slippage. Other considerations such as relaxation of individual guys should  be made;

(b)

the flexibility of the guy, together with the flexibility of the tower, is needed to compute the foundation reactions and anchor loads. Tower and anchors can be designed for the maximum amount of specified anchor slippage. The initial and final modulus of elasticity of the guys together with the creep should have to be considered; and

(c)

differential movement of the structure foundations relative to the guy anchor foundations. This can be assessed by comparing the depth of embedment of the foundation and likely soil heave or settlement. On narrow masts, small movements of the footing may relieve load.

Selection of the guy cable should satisfy strength requirements in accordance with AS 3995. Consideration should be given to the sizing of the cable for suitable stiffness. The guy cable should be as a minimum earthed for fault currents. The guy attachments should be designed for the full tensile capacity of the guy cable. The guy anchor foundations may be designed for less than the full capacity of the anchor. Consideration should be given to the termination fittings of the guy to allow coarse and fine length adjustment, tension measurement of the installed guys (by vibration frequency, mechanical tensiometer, measurement of sag), temporary removal of load to allow adjustment of the length and attachment points on the anchors for temporary replacement of the normal guys. Because of the large elongation of non steel ropes, only steel cables should be used for temporary or permanent guys. Buried components of the guying system should be designed to allow for the extreme level of corrosion for the type of installation. Guying systems may be considered either as a continuation of the conductors (i) OR as structural components (ii)— (i)

if the guying system is designed as continuation of the conductors using conductor hardware then allowance should be made for broken cables and attachments.

ii)

If the guying system is designed as a structural components the guy fittings should have suitable WLL markings and be selected in accordance with the WLL under EDT and WLL*3 under ultimate loads. The designer should check that the selected components have an ultimate capacity of at least 5*WLL.

(iii)

(as alternate of (ii)) If the guying system is designed as a structural components, usually the guy fittings will not be able to develop the full rated breaking strength (RBS) of the guy but should have to be designed for 70% of RBS under weather loads and 85% of RBS under failure containment conditions. The mechanical efficiency should be marked on guy fittings which may be defined as the percent of the guy RBS up to which the guy fitting is able to sustain.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

214

DRAFT ONLY

Pretension of guys should be at least 5% of CBL of the cable and preferably closer to 10% of CBL (with maximum ±10% tolerance).Depending on the procedure, the designer should specify either— (A)

pretension values; or

(B)

a tensioning sequence controlled by the pole top displacement.

The minimum pretension should be such that the leeward guys do not go slack under frequently occurring winds (e.g. yearly wind) or other everyday weather related load combination. At the lower range the sag of the cable may be excessive for visual and stiffness considerations. Guy fittings should have split pins or double nuts for locking against vibration. The guy attachment points on the structure should allow for possible variations in the installation of the guy position causing changes in the force components at the attachment. Pretensioning of the guy cable can be used to pre-load the foundations of the reinforced structure. Guy systems can be used to carry torsional load at a level in a tower but the effectiveness is dependent on the stiffness of the structure. N7.2 Structure upgrade N7.2.1 Wooden pole structure upgrade N7.2.1.1 Hardwood poles

Timber poles have been found to deteriorate over time in the ground line zone due to termites attack or soft rot mechanisms and at height due to the long term exposure to the natural elements. Where soft rot is detected in its early stages, poles can be assessed for loss of strength and limits set on the minimum permissible load factor to be provided before further reinforcement of the pole element is required. Pole nails provide a means of providing reinforcement of poles and extending their service life. Various strengths and types of pole nails or nail systems that are rigidly attached to the pole are available to either temporarily reinforce or to replace completely the base section of  poles. Where temporary reinforcing type systems are used careful consideration needs to be made of the level of serviceable strength that is provided over time under conditions where the wood pole butt suffers further deterioration. N7.2.1.2 Softwood poles

In general CCA treated softwood poles should not require upgrading during their design service life. N7.2.2 Steel pole structure upgrade N7.2.2.1 Direct embedded poles and socketed base type poles

Tubular form steel poles directly embedded into soil will normally have either a hot dip galvanized finish or a duplex tar epoxy coating applied over the galvanized. Galvanized steel in direct contact with soils will not have significant life unless in low rainfall or semi arid areas, and replacement of the base section is likely during the life of the structure. Duplex coated poles should not require upgrading during its design service life unless the coating system breaks down. 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

215

DRAFT ONLY

Poles socketed into concrete base sockets will perform generally in accordance with the above provisions. It should be assumed that any cast in situ socket will fill with water over time. Due to capillary action on the pole/seal interface. Accelerated loss of zinc coating will most likely occur to some extent, in the immediate above ground zone due to the daily drying/wetting cycle with dew particularly in grassed footpath areas. N7.2.2.2 Base plate mounted poles

The weakest element in this type of construction is the corrosion protection of the holding down bolts and any projections of bolt threads. Specific maintenance of the region is required in order to extend the service life of the structure. N7.2.2.3 Slip joints and internal surface protection

All cylindrical galvanized steel poles joined in the field with slip joints can be expected to have some but limited corrosion of the mating surfaces of the joint without any significant loss of strength, but needs to be checked over the life of the line. Temperature effects can have a major effect on the ingress of moisture into the inner void of steel poles due to the ‘breathing’/expansion of the pole drawing in moist air. Condensation will then occur during low temperature cycles that will cause corrosion of the inner zinc surfaces. To counteract this complete sealing of the inner void will limit available oxygen. Periodic internal boroscope inspection of the inner base section would be beneficial to extending the service life of poles. N7.2.3 Concrete pole structure upgrade

Most concrete poles are made from high strength concrete using a high compaction process. Some are also prestressed. Poles of this type have been in service for over 80 years without any degradation of the pole element. Limited scope exist to upgrade the design capacity of these structures unless by the use of composite elements attached to the outer or inner surfaces of the pole. N7.2.4 Composite pole structure upgrade

This type of pole has limited service experience at the time this Standard was prepared but is seen to be similar to concrete poles. N8 FOUNDATION UPGRADE

Increased reaction from super-structure for the purposes stated in Paragraph N3 should be transferred safely to the existing foundation system. The designer should have to design an appropriate anchoring system to satisfy this requirement. Additional uplift force can be counter measured by increasing the dead weight of the footing. However, due attention is required for the integrity between the new concrete section to the old concrete section. Lateral support can be achieved by methods as simple as modifying engineering properties of soil adjacent to the footing member (compaction, soil stabilising). Other methods may include enlarging the footing bearing area or installing tie beams between individual footings.  New foundation can be installed to transfer higher load from super structure and after completion of the new foundation construction, the structure can be re-positioned onto the new foundation. In such case, the old foundation may be abounded or may be used as a part of new foundation. 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

216

DRAFT ONLY

The designer should have to prepare the temporary load transfer arrangement as well as sequential working procedure required for safe strengthening of existing foundation system/construction of new foundation or safe re-positioning of structure onto the new foundation. Appropriate geotechnical investigation is required prior to any foundation modification or installation of new foundation for increased load transfer. The designer should have to carry out appropriate investigation to predict any potential stability hazard that may arise to existing foundation while constructing new foundation or modifying existing foundation causing soil disturbance. N9 MODIFICATION OF LATTICE STEEL STRUCTURE

Lattice steel structures can be strengthened by means of following measures: (a)

Adding new profile with existing structural element (e.g. adding back to back angle with existing angle at horizontal edge members/bracing members/compression chord of X-arm to enhance the buckling resistance).

(b)

Introducing additional redundant members/modifying redundant pattern to increase the compression strength of the structure component.

(c)

Modifying tower geometry to optimize the load distribution pattern within the structure (e.g. introducing additional diaphragm between panels).

(d)

Replacement of angle sections with larger section members.

(e)

Addition of guy (stay) wires.

(f)

Addition of bolts/splice plates to enhance end restrained condition of compression member or

(g)

Up-gradation of bolts to higher grade and/or diameter.

(h)

Modification in tower top geometry for thermal or voltage uprating of line.

(i)

Install tower on new base and/or use of tower extension above waist to increase height

N10 MODIFICATION OF POLE STRUCTURE

Pole structures can be strengthened by means of following measures: (a)

Adding stays.

(b)

Pole nails for wooden poles.

(c)

Doubling up concrete poles, some times even a small pole maybe added.

(d)

Inserting the steel section on the base of a wooden pole to increase height.

(e)

Use of fibre reinforced polymer to increase the flexural capacity of steel monopoles.

N11 SAFETY N11.1 Construction and maintenance work procedures

The designer should have to confirm the following aspects: (a)

Production of construction and maintenance procedures complying the design assumptions and requirements.

(b)

All potential constraints are documented.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

217

DRAFT ONLY

However, review of working procedures for independent engineering assessment to ensure the compliance with design assumptions and specified constraints should be required prior to commencing the field work. N11.2 Personnel access

Personnel access controls developed to comply with OHS legislative requirements and other directives have seen the specification of significantly increased maintenance and fall-arrest loads and fixing of more sophisticated climbing aids. The designer should consider whether such scope for the upgrade work on structures installed prior to these requirements should  be inclusive of these requirements.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

218

DRAFT ONLY

APPENDIX O

WATER ABSORPTION TEST (Normative) O1 SCOPE

This Appendix sets out the method for the determination of the water absorptive property of concrete poles, in a batch of poles.  NOT E: The test method is based on AS 4058.

O2 PRINCIPLE

The relative water absorption of the pole concrete is taken as a measure of the resistance of the concrete to atmospheric moisture penetration. The relative water absorption is measured as the difference in mass between an oven-dried specimen and the saturated surface-dry mass of the specimen after a fixed period of immersion in boiling water, expressed as a  percentage of the oven-dried mass . O3 APPARATUS

The apparatus consists of the following items: (a)

A ventilated drying oven of sufficient capacity to hold a test specimen and capable of maintaining a temperature of 105 ±3°C.

(b)

A desiccator of sufficient capacity to hold the test specimen from Item (a).

(c)

A water bath of sufficient plan area and depth for the test specimen to be completely immersed in water and in which the water can be maintained continuously at boiling  point for at least 5 h.

(d)

Cutting and grinding equipment for preparing the specimen.

(e)

Drying cloths and implements for handling the specimen from oven to desiccator to  bath.

(f)

A weighing mechanism capable of determining the mass of the test piece, during the various stages, to an accuracy of ±0.5 g.

O4 CONDITION OF SAMPLE POLES

The age of the sample pole(s), from the time of casting to the time of preparation of the test specimens, shall not be less than 14 days nor greater than 28 days. The poles shall not have  been subjected to any previous tes ting, which would affect the absorptive properties of the concrete. The area of the surface from which the test specimens are to be cut shall be free from cracks visible by normal or corrected vision. O5 PREPARATION OF TEST SPECIMEN

From each sample pole, extract a radial core that extends through the entire thickness of the wall, with end faces corresponding to the internal and external surfaces of the pole of area  between 1.0 × 104 mm 2 and 1.5 × 104 mm 2.  NOT E: A cylindrical specimen, made by cutting radially thr ough the wall wit h a coring bit of 115 mm diameter, or 125 mm nominal diameter, would satisfy these area requirements.

The cut surfaces of the specimen shall be ground smooth and the specimen kept in a damp condition until tested.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

219

DRAFT ONLY

O6 TEST PROCEDURES O6.1 General

The test shall be carried out when the age of the concrete in the specimen is not greater than 28 days.  NOT E: The abilit y of concrete to absorb water diminishes with increasing tim e after castin g and with increasing duration and quality of curing. Absorption tests made on 28-day-old concrete will, therefore, yield lower percentage values than tests on concrete less than 28 days old. Hence, if an early-age value is less than the permissible limiting value, no further test will be required. However, if this is not the case, a further test at 28 days would be required.

O6.2 Procedures O6.2.1 Determination of dry mass (m1 )

The procedure is as follows: (a)

Weigh the damp specimen to the nearest gram and record the mass as m0.

(b)

Dry the specimen at 105 ±3°C in the drying oven until consecutive weight measurements of the specimen, when made at intervals of not less than 4 h, show a change in mass of not greater than 0.1% of m 0. Record the lowest value, determined at room temperature as the dry mass (m1) to the nearest gram.

Each consecutive weighing required may be carried out either— (i)

by first allowing the specimen to cool from oven temperature to room temperature in the desiccator and then weighing; or

(ii)

by weighing the hot specimen within 1 min of its removal from the oven then, if no further drying is required, cooling it to room temperature in the desiccator and reweighing it as soon as possible, The latter reading is recorded as the dry mass ( m1 ).

O6.2.2 Immersion procedure

Immediately following the determination of the dry mass, suspend the specimen in the bath so that no part of the specimen is closer to a direct source of heat than 50 mm. Introduce  potable water into the bath at room temperature until all surfaces of the specimen are covered by at least 25 mm of water. Once the specimen has been covered to the required depth, heat the water rapidly to 100°C and maintain it at that temperature for 5 hours keeping the specimen covered with water throughout. At the end of this period, cool the specimen uniformly over 2 h to 20 ±5°C, by gradually replacing the hot water with colder water. O6.2.3 Determination of saturated surface-dry mass (m2 )

At the end of the immersion procedure, remove the specimen from the bath, allow it to drain for not more than 1 min, then remove any remaining water from the surface with the absorbent paper or cloth. Weigh the specimen in this saturated surface-dry condition and record the mass as ( m 2), to the nearest gram. If the specimen contains reinforcement, remove it from the concrete and clean off any adhering mortar. Weigh the reinforcement and record its mass as ( m3 ), to the nearest gram.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

220

DRAFT ONLY

O7 CALCULATIONS

The absorption of each test specimen shall be calculated from the following equation: k wj

=

(m2 − m1 ) ×100

. . .O1

( m1 − m3 )

where m1

=

the dry mass, in grams

m2

=

the saturated surface-dry mass, in grams

m3

=

the mass of reinforcement, in grams

O8 RECORDS AND REPORTS O8.1 Records

For each batch of poles for which water absorption tests are taken, the following records shall be kept: (a)

A means of identifying the individual test specimens and the batch from which they were taken.

(b)

The date on which the test specimens were taken from the batch, or the age of the concrete at that date.

(c)

For each specimen tested from the batch— (i)

the measured values of m1, m 2 and m 3;

(ii)

the calculated value of k wj ; and

(iii)

the date on which m1  was determined.

O8.2 Reports

For each batch of poles for which water absorption tests have been carried out, a report containing the following information shall be prepared: (a)

Identification of the test specimens and the batch from which they were taken.

(b)

The date on which the first test specimen was taken from the batch or the age of the concrete on that date.

(c)

The calculated values of k wj   for the batch.

(d)

A statement as to whether or not these values satisfy the criteria given in Paragraph I5.2.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

221

DRAFT ONLY

APPENDIX P

INSULATION GUIDELINES (Informative) P1 INSULATION COORDINATION BASICS

An overhead powerline should be designed to avoid a power frequency flashover because it can result in permanent damage to the insulator. Even if the insulation can withstand the initial flashover without damage, upon reclosure of the line there is everylikelihood of a subsequent flashover should the wetting conditions continue. Switching surges on overhead lines should also be considered and the appropriate amount of insulation installed to avoid these surges. Switching surges can reach up to 3 times the normal operating voltage and in the case when high speed autoreclosing is used, in the  presence of trapped charges, the surges can be up to 4 times normal operating voltage P2 DESIGN FOR POLLUTION

Pollution design recommendations are given in AS 4436. The basic concept is to increase the surface creepage distance so that it is long enough to prevent a pollution flashover across the surface. TABLE P1 GUIDE FOR SELECTING INSULATORS IN CONTAMINATED ENVIRONMENTS ESDD range (1)

Minimum nominal specific creepage distance(2)

g/m

mm/kV

Light

0 to1.2

16

Medium

1.2 to 2.0

20

Heavy

2.0 to 3.0

25

Very heavy

Above 3.0

31

Contamination severity

(1)

ESDD is the equivalent salt deposit density.

(2)

Ratio of leakage distance measured between phase and earth over the r.m.s phase to phase voltage of the highest voltage of the equipment.

(3)

Consideration should be given to increasing the creepage distances is areas where there are long periods without rainfall or very close to the marine coast

Example:

Select a suitable disc insulator string for a 33 kV line subject to light contamination. Use normal disc profiles where the creepage length is 300 mm. Voltage of line

=

33 kV

Minimum nominal specific creepage distance

=

16 mm/kV for light contamination

Required creepage distance for 33 kV

=

528 mm

 Number of discs = 528/300

=

1.76 → 2 discs

The pollution performance of insulators can also be improved with the use creepage extenders or hydrophobic coatings such as Room Temperature Silicon Rubber (RTV). These coatings have a finite life and will need to be replaced during the life of the insulator. 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

222

DRAFT ONLY

Pole top fires may occur when high leakage currents from polluted insulators track across interfaces between conductive to non-conductive material e.g.insulator to crossarm, and crossarm to pole. P3 DESIGN FOR SWITCHING SURGE PERFORMANCE CONSIDERATIONS

DESIGN

AND

LIGHTNING

A good coverage on the design for switching surge is given in AS 1824.2. When designing for switching surges, one of the parameters which is difficult to obtain is the switching surge impulse voltage. There are 2 main types of electrical tests conducted on insulators; one being the lightning impulse and the other the power frequency flashover (wet and dry). Switching tests have been conducted in laboratories and the flashover voltages have been inconsistent and found to be dependent on the shape of the surge, the type of electrodes and the presence of earth planes. In lieu of adequate test data on switching surges a good approximation for the switching surge flashover voltage is 0.8 times the lightning impulse flashover voltage. The insulator parameter that determines the insulator impulse performance (i.e. switching surge and lightning) is the arc distance across the insulator. Line insulation is usually selected independent of substation insulation. It is necessary to check substation insulation impulse performance and install surge arresters, especially when the line insulation is longer than the substation insulation. P4 SELECTION OF INSULATORS

The two main class of insulators are ceramic (glass and porcelain) and composite (EPDM, silicon rubber and cycloaliphatic). Ceramic insulators have traditionally been installed on overhead networks and have provided a reliable service in light to moderately contaminated environments. P4.1 Standard and fog profile disc insulators

A typical 254 mm ×  146 mm standard profile disc generally has a creepage length of approximately 300 mm. The profiles are variable bet ween manufacturers who have to  balance the requirements of having an aerodynamic shape to attract les s pollutants, deeper skirts to increase creepage length and greater distance between skirts to reduce arcing. A typical 254 mm ×  146 mm fog profile disc has a creepage length around 400 mm. This is a 40% improvement in leakage distance over the standard disc. The additional creepage length is gained by having deeper skirts and this comes at a higher cost. It is common  practi ce to instal l fog profile ins ulators in heavy to extreme contamination areas. This is acceptable for a marine or industrial environments which are exposed to regular rainfall, but in desert environments, contaminants can be trapped under the skirts and build up to such levels that they bridge the skirts. This then dramatically lowers the creepage length of the insulator. For areas of extremely low rainfall, it is common for the aerodynamically dinner  plate shaped insulators t o be used. P4.2 Ceramic pin, shackle and posts

Ceramic pin, shackle and post insulators have been manufactured since the early years of last century. These insulators come in various lengths and profiles to meet the electrical and mechanical loads. The pin insulator is prone to puncture especially from steep fronted lightning strikes because of the small amount of ceramic material between the top of the insulator and the metallic bolt inserted in the bottom of the ceramic. Pin insulators usually have less creepage length compared to the post types but can be designed with larger skirts to handle heavy contaminated conditions.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

223

DRAFT ONLY

Shackle insulators are installed in positions where there are higher conductor loads, such as angle or termination structures. These insulators have a disadvantage to the pin and post types in contaminated environments because the conductor attachment in the centre of the insulator reduces the creepage length of the insulator. Post insulators have an advantage over pin insulators in withstanding electrical puncture  because there is a larger amount of ceramic material between the top of the insulator and the metal base. Post insulators generally have the highest creepage lengths and can be manufactured with wider skirts to handle increasing amounts of pollution. The advantages of the post insulator come at a higher cost. P4.3 Composite long rod and line post insulators

Composite insulators are made with a fibre glass core and either EPDM or silicon rubber weathersheds. One major advantage of the composite insulators over the ceramic ones is that they do not have intermediate metal parts between the end fittings. Hence they have a superior creepage to dry arcing distance ratio. Composites are generally regarded as being superior to ceramic for low to moderately contaminated environments because of their ability to maintain hydrophobicity. One of the  polymers, EPDM, does lose hydrophobi city from the effects of UV radiation and arcing on the surface whilst the other, Silicon Rubber, has the ability to maintain hydrophobicity for a long period of time. This is due to the continuous migration of silicon oils from the bulk of the material to the surface. Ageing performance is commensurate with price. Silicon Rubber is slightly more expensive than EPDM. In heavy to extreme environments, both types of  polymers have shown significant evidence of ageing (erosion and cracks along the axis of the polymer). Polymeric insulators are increasingly being accepted and advantages over ceramic insulators include the following: (a)

Lightweight (long rods are 10% of the weight of an equivalent ceramic string) making it easier to install and maintain.

(b)

Less visual impact.

(c)

Vandal proof.

(d)

Lower cost.

(e)

Few couplings.

However, some disadvantages of polymeric insulators are as follows: (i)

Not yet proven to have a life span to match ceramics.

(ii)

Low torsional strength.

(iii)

Limited diagnostic testing available.

(iv)

Risk of damage from bird attack, especially when de-energized.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

224

DRAFT ONLY

APPENDIX Q

MID SPAN SEPARATION CALCULATIONS (Informative) Q1 GENERAL

In Section 3 an equation was developed to determine mid span phase to phase separation. The following example outlines the method of calculation. MID SPAN SEPARATION Example 1:

Single circuit 19/3.25 AAC at 33 kV 3-phase on pin insulators in a delta configuration with a span of 200 m. What is the mid span vertical separation required between phases if a crossarm with a separation of 2.1 m between outer phases is used? Sag at 50°C is 6.07 m and sited in Region A. Refer Figure 3.6. where

∴X

=

1.05

U 

=

33

k 

=

0.4

 D

=

6.07

l i

=

0

 X 2 +(1.2Y ) 2

≥

U 

150

+k

33

D + l i

1.052 +(1.2Y ) 2

≥

1.052 +(1.2Y ) 2

≥ 0.22 + 0.985

. . .Q3

1.052 +(1.2Y ) 2

≥1.205

. . .Q4

Y  ≥

150

+ 0.4 6.07 + 0

. . .Q1

0.591

. . .Q2

. . .Q5

1.2

Y  ≥  0.493

. . .Q6

Therefore required minimum vertical separation for centre phase is 0.493 m. Example 2:

Upper circuit 19/3.25 AAC at 33 kV 3-phase on pin insulators in a delta configuration with a span of 200 m located directly above the lower circuit. The lower circuit conductor is 19/.064 copper at 11 kV. The lower circuit has a 120°phase differential to the upper circuit. What is the mid span vertical separation required between circuits if a crossarm with a separation of 2.1 m between outer phases is used? Sag at 50°C is 6.07 m 19/3.25 AAC and 5.81 m for 19/.064 Copper sited in Region Type A. Refer to Figure Q1. 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

225

DRAFT ONLY

FIGURE Q1 CONDUCTOR SEPARATION AT MID SPAN (TWO CIRCUITS)

Because the circuits are located vertically above each other the horizontal component is taken as zero and— U 

  φ   from ‘U’ above + Vb2 − 2 VaVb Cos

=

Va2

=

33 11 ⎛ 33 ⎞ ⎛ 11 ⎞ ⎜ 3 ⎟ + ⎜ 3 ⎟ − 2 × 3 × 3 Cos120° ⎝ ⎠ ⎝ ⎠

2

=

2

22.9 kV

∴ X  =

0

U 

=

22.9 (the difference in the vector r.m.s. potential of the circuit voltages)

k 

=

0.4 (Region A)

 D

=

6.07 (greater of the two sags)

l i

=

0 (Pin insulators)

 X

2

+(1.2Y ) 2 ≥

0 +(1.2Y ) 2 (1.2Y ) 2

≥

U 

150

22.9 150

+k

D + l i

+ 0.4 6.07 + 0

≥ 0.153 + 0.985

Y  ≥

. . .Q9 . . .Q10

1.2Y  ≥1.138 1.2Y  ≥ 1.205 2

. . .Q8

. . .Q11

− 1.05 2

. . .Q12

1.138

. . .Q13

1.2

Y  ≥  0.948

. . .Q14

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

226

DRAFT ONLY

APPENDIX R

INSULATION SWING ANGLE CALCULATIONS (Informative) R1 CALCULATION OF SWING ANGLES

The swing angles of suspension insulator strings for both low and high wind conditions can  be approximated using the following formula.

Angle of insulator swing φ   = tan − 1

 F wi ⎛ ⎛ θ  ⎞ ⎞ ⎜ WP * d * Sw + 2 + 2H sin  ⎜ 2 ⎟ ⎟ ⎝ ⎠⎟ ⎜ W  ⎜ ⎟ W c + i ⎜ ⎟ 2 ⎝ ⎠

. . .R1

where WP 

=

reference wind pressure in Pascals

d 

=

conductor diameter in metres

S w

=

wind span affecting the insulator string in metres

 F wi

=

wind load on insulator in Newtons = 1.2 wind pressure

W c

=

effective conductor weight in Newtons (weight span length)

W i

=

weight of insulator string in Newtons

 H 

=

horizontal component of conductor tension in Newtons appropriate to the reference wind

θ 

=

line deviation angle

×  projected area of insulators ×  weight per unit

The swing angle of a phase conductor catenary in a single span for both low and high wind conditions can be approximated using the following formula. Angle of conductor swing (blowout) φ   = tan −1

⎛ WP * d * Sw ⎞ ⎜ ⎟ W s ⎝ ⎠

. . .R2

where WP 

=

reference wind pressure in Pascals

d 

=

conductor diameter in metres

S 

=

span length in metres

W s

=

effective conductor weight in Newtons (span length length)

×  weight per unit

 NOT E: It is import ant to note that the insulator swing for mula above may produce diff erent swing angles for suspension insulators at supports on either side of a line catenary where different wind to weight span ratios may exist.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

227

DRAFT ONLY

The horizontal displacement of any point on the conductor in the span can be calculated from the results produced by the two equations above by considering their combined effect and is given by the following: horizontal displacement  y1  = S g sin φ c  + i1  sin φ  i1  +

⎛  x1 ⎞ (i  sin φ  −i  sin φ  ) i2 1 i1 ⎜ x + x ⎟ 2 ⎝ 1 2⎠

. . .R3

where S g

=

sag for point on conductor under consideration in metres

φ c

=

angle of conductor swing (blowout) in degrees

φ i1

=

angle of first insulator swing in degrees

φ i2

=

angle of second insulator in degrees

i1

=

length of first insulator string in metres

=

length of second insulator string in metres

 x1

=

first span length fraction to point on conductor under consideration in metres

 x2

=

second span length fraction to point on conductor under consideration in metres

i2

 NOT E: At blowou t win d speeds the conductor temperature for sag determinatio n can be taken as ambient air temperature.

 l 2

12 Blowout rotation axis

 i 1

11

Sg

c

 x 1

 x 2

 T R ANSV ERSE V I E W

FIGURE R1

 y 1

LO NG I TU D INA L V IE W

HORIZONTAL DISPLACEMENT

The correction factor k   takes into account the distribution of the wind along the span, drag force coefficient and the averaging time for V r . For the heights of conductors that are normally encountered, k  may be considered to be independent of height and terrain effects.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

228

DRAFT ONLY

The conductor tension  H   should be based on— (a)

still air or low wind ...............................average temperature over the coldest month

(b)

high wind ..................................average temperature over the coldest month + 10°C

The estimation of swing angles may be made using a simplified deterministic approach or a detailed procedure using meteorological data. The latter method should be used when greater precision is required or where unusual and/or extreme local conditions prevail. Part A—Simplified procedure

For condition (a)—Still air or low wind Wind pressure ................................... ..60 to 100 Pa depending on local weather conditions (replace the term 0.6 V r 2  in Equation B1 by the selected wind pressure) Value for k ............................. ............................... ............................... ......................... 1.0 For condition (b)—High wind or maximum swing Wind pressure (0.6 V r 2) ........................................................................................... 500 Pa Value for k ............................. ............................... ............................... ......................... 1.0 Part B—Detailed procedure

The reference wind velocity V r   should be obtained from local weather records corresponding to a suitable return period and an averaging time, and corrected for terrain and height effects. The values for k   should ideally be selected on the basis of studies and local experience. However, for most applications a value selected from Figure R2 produces satisfactory results. The selection of the wind return period should be based on the degree of reliability required, and when directional effects are considered, the swing angle return  period is about twi ce that of the corresponding wind. Thus for the high wind case, a 50 year return period and an averaging time of 5 min (5 min gust) will provide a satisfactory operational performance for most applications with a  probabili ty of exceeding the calculated swing angle of about 1%. For the low wind condition, a wind return period of one year averaged over 5 min (5 min gust) is recommended for similar reasons. Table R1gives factors for converting wind velocities from one averaging time to another for each terrain category.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

229

DRAFT ONLY

       k

   R    O    T    C    A    F

WIND SPAN Sw (m)

FIGURE R2 CORRECTION FACTOR K

TABLE R1 FACTORS FOR CONVERTING A 3 S GUST WIND SPEED Gust period

Terrain Category 1

Terrain Category 2

Terrain Category 3

Terrain Category 4

3s

1.000

1.000

1.000

1.000

1 min

0.735

0.797

0.844

0.878

2 min

0.680

0.749

0.807

0.847

5 min

0.614

0.658

0.764

0.808

10 min

0.553

0.646

0.727

0.784

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

230

DRAFT ONLY

APPENDIX S

CONDUCTOR SAG AND TENSION CALCULATIONS (Informative)

FIGURE S1 INCLINED SPAN GEOMETRY

S1 TERMINOLOGY

Level span

The conductor supports are at the same level.

Inclined span

The conductor supports are at different levels.

Suspension span

Either or both conductor supports are free to swing longitudinally (along the line).

Deadend span

Both conductor supports are terminated.

Sag

The maximum vertical departure of the catenary from a chord  joining the support points (approximate ly mid span).

Section

That portion of an overhead line between strain structures consisting solely of intermediate suspension structures for which the ruling span concept is valid.

Ruling span

A hypothetical level deadend span used to model the tension  behaviour of a section.

Tension constraint

The maximum allowable conductor tension (independent of the ruling span) for a given loading condition.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

231

DRAFT ONLY

Controlling constraint 1

The tension constraint which produces the largest sags at the maximum operating temperature for a given ruling span.

Controlling constraint 2

The tension constraint which produces the longest unstressed constraint 2 conductor length for a given ruling span.

S2 VARIABLES −1

∝ Δ

=

coefficient of linear expansion

(°C

=

conductor slack

(m)

ε

=

total creep strain (mm/mm)—strand settling and metallurgical

θ

=

take-off angle (from horizontal) at the conductor support

π

=

3.14159

ρ σ

=

ice density

(kg/m 3)

=

stress

(MPa)

 A

=

total conductor cross-sectional area

(mm 2)

 Aa

=

cross-sectional area of the aluminium component of a conductor

(mm 2)

 As

=

cross-sectional area of the steel component of a conductor

(mm 2)

C

=

resultant catenary constant

(m)

C h

=

catenary constant using W h 

(m)

C v

=

catenary constant using W v 

(m)

d

=

conductor diameter

(m)

 D

=

conductor sag

(m)

 E

=

modulus of elasticity

(MPa)

h

=

height difference between conductor supports ( =  y 2 –  y1)

(m)

 H

=

horizontal component of tension

(N)

 I

=

chord length between conductor supports ( =

 L

=

span length ( =  x2 −  x1)

(m)

 L h

=

wind span for a structure

(m)

 L r 

=

ruling span of a section

(m)

 L v

=

weight span for a structure

(m)

m

=

conductor unit mass

(kg/m)

 P

=

transverse wind pressure

(Pa)

r

=

radial ice thickness

(m)

S

=

stressed conductor length

(m)

S 0

=

unstressed conductor length at 0°C

(m)

t

=

average conductor temperature

(°C)

T

=

tangential or axial tension

(N)

T a

=

average axial tension

(N)

V

=

vertical component of tension

(N)

W

=

resultant distributed conductor load

(N/m)

8326-PDR - 24/07/2008 14:25:50

 L2

+ h2 )

)

(m)

DRAFT ONLY  

232

DRAFT ONLY

W h

=

transverse component of distributed conductor load

(N/m)

W v

=

vertical component of distributed conductor load

(N/m)

S3 INTRODUCTION

A flexible, inelastic conductor with constant load (W) per unit of arc length suspended  between supports a ssumes the shape of a catenary— y

=

⎛ ⎝

⎛  x ⎞ − 1 ⎞   where the catenary constant C = ⎟ ⎟ ⎝ C ⎠ ⎠

C ⎜ cosh ⎜

 H  W 

. . .S1

An approximation of the catenary is the parabola which uses a constant load (W) per horizontal unit length. y

=

 x 2

. . .S2

2C 

For span lengths less than 0.7C, or sags less than 9% of the span length, the difference in sag between the catenary and the parabola is less than 1%. These mathematical models are adequate for describing inelastic conductors at any given tension. To determine the tension at different loading conditions the equations should be modified for temperature, elasticity, wind pressure, ice weight and age (creep). For all steel reinforced conductors, the use of a constant  E   value may result in calculated sags less than actual sags for temperatures greater than 90°C. This is subject to further research by CIGRE Study Committee 22/Working Group 12 and IEEE Subcommittee Towers, Poles and Conductors/WG ‘ Thermal Aspects of Overhead Conductors ’/Task Force ‘ Bare Conductor Sag at High Temperature ’. S4 RULING SPAN

The ruling span, also known as the equivalent span or the mean effective span (MES), is defined as that level dead-end span whose tension behaves identically to the tension in every span of a series of suspension spans under the same loading conditions. Note that the ruling span concept can only model a uniformly loaded section, e.g. where wind or ice on one span exists but not on the other spans in the section, other more precise modeling techniques are to be adopted. It is assumed that the insulator is free to swing along the line and long enough to equalize the tension in adjacent spans without transferring a longitudinal load onto the structure. In general, spans shorter than the ruling span tend to sag more than predicted whilst spans longer than the ruling span sag less than predicted at temperatures above the stringing temperature (assuming that the tensions were equal at stringing). The ruling span concept may not apply to fixed pin and post insulators because the structures may not be flexible enough to equalize tensions. However, if the stringing tension is low, or the spans are short, or the spans are approximately equal, then there is little difference in tension across the insulator under identical loading conditions in each span. Therefore the risk of conductor movement through the ties and associated fretting is minimized, except for non-uniform span loading. A value for the ruling span should be assumed before spotting structures because the actual ruling span can only be calculated after the structure locations are determined. In most cases the actual ruling span should be greater than or equal to the assumed ruling span to ensure the design clearances. However, the situation sometimes arises (for large ruling spans when the controlling constraint is associated with a heavy loading condition) where the tension decreases with increasing ruling spans at the maximum operating temperature.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

233

DRAFT ONLY

Under these circumstances the actual ruling span should be less than or equal to the assumed ruling span. The ruling span is calculated using— n

 L r 

∑=  L

3 i

i 1 n

=

  for level spans

. . .S3

  for inclined spans

. . .S4

∑=  L

i

i 1 n

 L r 

∑=  L

4 i

i 1 n

=

∑=  L

i

i 1

where  L2i

+ hi2   = the chord length between the supports of span

 I i

=

 L i

=

the horizontal span length of span

hi

=

the support height difference of span

n

=

the number of spans between strain structures

i

i i

For a single level, dead-end span the ruling span is

 Lr  =  L

However, for a single inclined dead-end span

 Lr  =

 L2  I 

. . .S5 . . .S6

 NOT E: Where rig id post or pin type insulators are used , the adoption of the ruling span concept may not accurately reflect the real sag and tensions under varying conductor temperature and wind loadings. Designers need to assess the magnitude of the errors produced by the ruling span concept and consider adoption of appropriate techniques to predict more accurate results if required.

S5 LOADING CONDITIONS

Longitudinal and yawed wind loading and point loads such as cable chairs, droppers, strain insulator strings and aircraft warning spheres require analytical tools not covered by this Standard. Once the conductor is strung, its tension can be influenced by the following factors considered by this Appendix: (a)

Conductor temperature ( t ).

(b)

Wind pressure transverse to the conductor ( P ).

(c)

Radial ice on the conductor ( r ).

(d)

Age of conductor as measured by the creep strain ( ε).

Wind and ice loading affect the horizontal and vertical component of distributed load W h

=

 P(d  + 2 r )

W v

=

9.81( m  +

. . .S7

πr (d  + r ))

where ρ ranges from about 300 kg/m3 for rime to 916 kg/m 3 for ice.

8326-PDR - 24/07/2008 14:25:50

. . .S8

DRAFT ONLY  

234

DRAFT ONLY

The resultant distributed load is the vector sum of W h  and W v W

Wh2

=

+ W v2

. . .S9

The catenary constants C , C h  and C v  are functions of W , W h  and W v  respectively.  C h  is used for conductor swing-out calculations, C v  is used to calculate sags and C   is used for calculating tension changes.  NOT E: The value of gravit ational acceler ation ‘ g ’ is normally taken as 9.8067 m/s 2.

S6 TENSION CONSTRAINTS

Tension constraints are used to limit the horizontal tensions for one or more of the following reasons: (a)

To restrict fatigue damage caused by aeolian vibration. This constraint is frequently referred to as the everyday tension ( EDT ) constraint. The tension limit is influenced  by the climate, terrain, extent of vibration protection, conductor material, conductor self damping characteristics and type of conductor support. Refer to Section 7.

(b)

To give a margin of structural safety under extreme weather conditions of wind and ice.

(c)

To limit the tension for short ruling spans under cold conditions. For short spans there are large variations of tension with temperature changes.

(d)

To give a margin of safety for personnel performing maintenance and stringing operations which could be done under light wind conditions.

The age of the conductor at which a particular tension constraint applies should be stipulated if the creep is significant. The tension reduces as the conductor creeps. An age of 10 years is usual ly applied since s trand settling and metallurgical creep a re virtually completed in that period. For a given ruling span only one tension constraint limits (or controls) the tensions for all other loading conditions. The controlling constraint is the most restrictive tension constraint, producing the largest sags and the least tensions for any given loading condition. A tension constraint can alternatively be expressed as a support tension, sag, conductor stress or catenary constant. Each of these alternatives can be converted to a horizontal tension as follows: (i)

Tangential tension ( T ) at a support 2

T  ⎞ (WLr  ) 2 ⎛  (based on the parabola and a level span)  H  = + ⎜ ⎟− 2 8 ⎝2⎠ T

(ii)

Sag ( D )  H 

(iii)

. . .S10

=

Wv L2r 

8 D

(based on the parabola)

. . .S11

Conductor stress ( σ)

For an ACSR conductor with a steel to aluminium modulus ratio of three and with the aluminium and steel in tension the aluminium stress can be converted to tension using—  H  ≈

σ( Aa + 3 As )

. . .S12

For a homogeneous conductor  H  = (iv)

σ A

Catenary constant ( C )  H 

=

. . .S13

WC 

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

235

DRAFT ONLY

For a given ruling span the tension constraint producing the shortest unstressed conductor length as given by Equation S14 is the controlling constraint. The conductor length at 0°C, under no tension and at an age when the creep strain is zero is— S 0

S 

= 1+

T a  EA

. . .S14

+ α t  + ε 

where the stressed conductor length is— S 

S 

= =

2 C sinh  Lr  +

 Lr 

. . .S15

2c

 L3r 

24C 2

. . .S16

 for the parabola

It is common practice to assume that T a ≈  H ; however, T a  is evaluated more accurately in Paragraph E9 for the catenary and the parabola. S7 TENSION CHANGES

The tension change (or change-of-state) equation equates the unstressed conductor length for two loading conditions. For one loading condition (i.e. the controlling tension constraint) Hi is defined. For the other loading condition the tension  H f   is desired. The tension change equation is— S 0

S i

= 1+

 H i  EA

S  f 

=

+ α t i + ε i

1+

H f   EA

+ α t  + ε  f 

. . .S17

The value of S 0  is known because by definition the controlling constraint is the tension constraint producing the smallest value of S 0. Note that S f   is a function of  H f   and can be evaluated using either the catenary Equation S15 or the parabolic Equation S16. Many references such as ‘ Overhead Electric Power Lines ’ by G.C. Cracey, 1963 (page 68) use the tension change equation based on the parabola because it reduces to a cubic equation which is readily solved. With computers the catenary tension change equation can  be solved using nume rical techniques s uch as the Newton-Raphson method. S8 SAGGING TENSIONS

For the purpose of determining sagging tensions, the variables with subscript ‘f’ shall refer to the controlling constraint whilst variables with subscript ‘i’ shall refer to loading conditions at the time of sagging. Therefore εf    is the creep strain that has occurred up until the age of the conductor when the controlling constraint applies (usually 10 years). The creep strain εi  occurs prior to sagging. The total creep strain is the sum of metallurgical creep and strand settling. Guidance on metallurgical cree p strain is gi ven in Appendix V. The strand settling strain can be approximated from the stress/strain curve by subtracting the elastic strain from the initial composite strain. Allowance should be made for the conductor to reach its maximum stress level during its lifetime. Therefore the strand settling associated with this level of stress would apply to final sags and tensions but rarely to initial (stringing) sags and tensions.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

236

DRAFT ONLY

It is common practice to convert the difference in creep strain ( εf  − εi ) to an equivalent thermal strain ( αt c) and overtension the conductor by using a temperature lower than that which actually applies at the time of sagging. Therefore if the controlling constraint applies at say 10 years, then the final sags and tensions are calculated using Equation S17 with εf  = εi = 0 and the i nitial s ags and tens ions are determined by a pplying a negative ε − ε i temperature correction of T c = f   to the final sags and tensions. α  S9 PHYSICAL PROPERTIES

Once a conductor tension has been determined for a section of transmission line using its ruling span in the tension change equation, the characteristics of each span in the section may be determined using the inelastic catenary or parabolic equations. Reference Figure S1 for the variables associated with the inclined span geometry. S10 CATENARY EQUATIONS

 x1

 x2

=

⎛ ⎞ ⎟ L h ⎛h⎞ L − ⎜ C   tanh −1 ⎜ ⎟ − = C sinh 1 ⎜ ⎟−  L 2 S  ⎝ ⎠ ⎜ 2C sinh ⎟ 2 2C  ⎠ ⎝

. . .S18

=

⎛ ⎞ ⎜ ⎟ L h ⎛h⎞ L C   tanh −1 ⎜ ⎟ + = C sinh −1 ⎜ ⎟+  L ⎝ S ⎠ 2 ⎜ 2C sinh ⎟ 2 2C  ⎠ ⎝

. . .S19

2

⎛ 2C sinh  L ⎞ + h 2 ⎜ ⎟ 2C ⎠ ⎝

. . .S20

  = weight span contribution to structure 1

. . .S21

S 

=

S 1 + S 2 =

S 1

=

−C s inh

 x1

S 2

=

−C s inh

 x 2

  = weight span contribution to structure 2

. . .S22

=

wind span contribution to structure 1 and structure 2

. . .S23

S 

2 V1

= − H sinh

 y1

=

C ⎜ cosh

T1

=

H cosh

⎛ ⎝

 x1 C 

C 

= Wv S1

V2

. . .S24

−1⎞⎟ C  ⎠

 x1 C 

= − sinh

 

 x1

 x1

= − H sinh

. . .S25

= H + Wy1

T 2 − T 1 = W h T 2 + T 1 =

tan θ 1

C 

C

=

 x2 C 

. . .S26

WS   L tanh 2C 

S 1

. . .S28

C 

= Wv S2

. . .S27

 

8326-PDR - 24/07/2008 14:25:50

. . .S29

DRAFT ONLY  

237

⎛ ⎝

 y2

=

C ⎜ cosh

T2

=

H cosh

Δ=

= H + Wy2

C 

. . .S31 . . .S32

= − sinh

 x2 C

S

≈

S 2

=

2C sinh

 L

. . .S33

C  h

C sinh −1

=

 x3

 D

 x2

. . .S30

S  − 1

tan θ 2

 D

−1⎞⎟ C  ⎠

 x 2

 L

⎛ ⎝

C ⎜ cosh

  approximately mid span

. . .S34

− 1⎞⎟ = 2C ⎠

. . .S35

L

IC ⎛ L

L ⎞ ⎜ cosh 2C − 1 ⎟ ⎝ ⎠

2C 

 L = C ⎛⎜ cosh − 1⎞⎟ (for a level span) 2C  ⎠ ⎝

T a

=

T a

=

DRAFT ONLY

⎛ S 2 +h 2 L L ⎞ sinh + ⎟ ⎜ 2S ⎝ S 2 − h 2 C C ⎠

. . .S36

CH

T

2

HL

+

2 S 

 

  (for a level span where T 1 = T 2 = T )

. . .S37

. . .S38

S11 PARABOLIC EQUATIONS

 x1

=

 x2

=

 L

2

=

Ch  L Ch  L

−

L

+

L

2 2

  = weight span contribution to structure 1

. . .S39

  = weight span contribution to structure 2

. . .S40

wind span contribution to structure 1 and structure 2

. . .S41

The equation for calculating the arc length of a parabola is more complex than that of the catenary, therefore a Maclaurin’s series approximation of the catenary equation is used here.

 L4

S 

=

1+

V 1

=

−W v x1 =

 y1

=

 D +

T 1

=

tan

θ1=

 H  C   x1 C

. . .S42

24C 2 I  Wv L

2

h2

16 D

−

 Hh  L

h

+ C 2

h

− 4D

. . .S43 . . .S44

2

 x12

=

−

. . .S45 . . .S46

L

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

238

Δ

=

S  − 1 =

V 2

=

−W v x2 =

 y2

=

T 2

=

tan  x3

 D

T a

C   x2 Ch

=

 L  L2

=

8C   H

=

S

+

2

8D2 3I 

 Hh  L

h

+

+ C 2

h

+ 4D

. . .S47 . . .S48 . . .S49

2

 x22

=

C

Wv L

16 D

 H 

=

24C 2 I

h2

 D +

θ2=

 L4

DRAFT ONLY

. . .S50 . . .S51

L

  (mid span)

. . .S52

  (independent of h )

. . .S53

⎛ I2 L3 ⎞ ⎜ L + 12C 2 ⎟ ⎝ ⎠

. . .S54

S12 MULTIPLE SPAN CALCULATIONS S12.1 Conductor loads

FIGURE S2 WIND AND WEIGHT SPANS (PARABOLA)

Static structure loads caused by the conductor are determined by the wind span and weight span for that structure. The wind span gives the transverse component of load due to wind and the weight span gives the vertical component of load. For suspension structure B with no deviation angle— Transverse load

=

 Lh

× W h

Vertical load

=

 Lv

× W v

Longitudinal load

=

0 (assuming insulator swing equalizes tension)

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

239

DRAFT ONLY

S12.2 Weight span to wind span ratio (Based on parabolic simplification)

For spotting suspension structures, a lower limit of weight span to wind span ratio is derived from the maximum allowable transverse insulator swing angle ( β  from vertical) that satisfies the electrical clearance requirements under the maximum wind condition. (Refer to Figure S2 for definitions of terms).  Lv  Lh

≥

W h W v tan β 

(neglecting insulator weight and wind)

. . .S55

The spotted weight span to wind span ratio is—  Lv  Lh

=1+

2bC v

. . .S56

L1 L2

where the wind span  Lh

=

 L1

+ L2 2

 Note that b  is negative when the support is below the chord joining adjacent supports (dashed line of Figure S2). S12.3 Variation of weight span with conductor tension (Based on parabolic simplification)

If the weight span ( Lv1 ) is known for a given tension ( H 1) then the weight span ( Lv2 ) at any other tension ( H 2) is—  Lv 2

= Lh +

C 2 C 1

( Lv1

− Lh )

. . .S57

where C1

=

 H1 Wv1

and C 2

=

H 2

. . .S58

W v2

Longitudinal profile drawings can be used to measure the weight spans for the plotted catenaries (e.g. the maximum operating temperature or sometimes the maximum working wind or ice load). The above formula can be used to calculate the conductor weight spans at other conditions of temperature, ice, wind or creep.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

240

DRAFT ONLY

APPENDIX T

CONDUCTOR TEMPERATURE MEASUREMENT AND SAG MEASUREMENT (Informative) T1 CONDUCTOR TEMPERATURE MEASUREMENT

Various measuring techniques have been used to establish the temperature for stringing new conductors. The actual temperature of the conductor should be measured during sagging of the conductor to avoid conductor over-tensioning or loss of ground clearance. The actual conductor temperature can be determined reasonably accurately by using a stainless steel dial type thermometer with the stem inserted into the core of the conductor of similar material. For smaller bare conductor the stainless steel dial type thermometer alone is usually sufficient. The thermometer should be hung in an exposed location parallel to the conductor and at a height similar to the conductor. A sufficient period should be allowed for the temperature to stabilize before it is read immediately prior to sagging of the conductor.  NOTE: Temperature correctio n may be requir ed to allow for conductor inelastic stretch.

T2 CONDUCTOR SAG MEASUREMENT

Conductor sag may be measured by direct methods, such as sight boards mounted on the structures or by theodolite measurement, or by measuring the conductor tension by dynamometer. T3 SIGHT BOARD METHOD

To produce a required sag a sight board is fitted at the required distance below the point of attachment at each end of the span and the conductor is tensioned until the tangent of the catenary is in line with the two boards. To measure an unknown sag the tangent of the catenary is sighted from a known distance ( A ) below the first point of attachment to a point  below the sec ond conductor attach ment (distance  B ).  D

=

⎛ ⎜⎜ ⎝

 A

+ 2

B

⎞ ⎟⎟ ⎠

2

. . .T1

where  D

=

conductor sag

 A

=

distance below the first conductor support

 B

=

distance below the second conductor support

(Refer to Figure T1).

FIGURE T1 QUANTITIES ASSOCIATED WITH SIGHT BOUND METHOD

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

241

DRAFT ONLY

T4 THEODOLITE METHOD

This method is more accurate and is recommended for long spans where the sag is greater than the height of either conductor attachment points above the ground. A theodolite is set up below the conductor attachment and the angle of tangency to the catenary is measured. The sag can be calculated by solving the following equation: tan

4  AD

θ=

+ H − 4D

. . .T2

 L

where

θ

=

angle of tangency to the catenary

 D

=

conductor sag

 A

=

vertical distance from the centre of the theodolite to the conductor support

 H 

=

difference in height of the conductor supports (positive when the support furthest from the theodolite is the higher)

 L

=

span length

(Refer to Figure T2).

FIGURE T2 QUANTITIES ASSOCIATED WITH THEODOLITE METHOD

This method should not be used where the point of tangency is greater than 80% of the span length because of the magnification of sighting errors.  P 

=

50

 A

. . .T3

 D

where P

=

point of tangency expressed as a percentage of the span length (%)

T5 WAVE SAG METHOD

One indirect method, known as wave sagging, relies on the relationship between conductor tension and the speed at which a mechanical pulse travels along the conductor. The conductor is struck at one end of a span with a suitable striker and at the same time a stopwatch is started. The pulse will be reflected at the other end of the span back to the striker. To reduce errors in measurement the time for three cycles is usually recorded.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

242

9.81 ⎛ t  ⎞

2

D

=

 D

=

conductor sag (m)

t 

=

time (seconds) for N return waves

 N 

=

number of return waves (usually three)

 g 

=

gravitational acceleration—normally taken as 9.8067 (m/s 2)

⎜

DRAFT ONLY

. . .T4

⎟

32 ⎝ N  ⎠

where

This relationship is based on the parabolic simplification of the catenary equation and should only be used for the relatively shorter distribution spans (e.g. up to 500 m) and for relatively level spans. T6 SWING SAG METHOD

Another indirect method, known as swing sagging, is based on a pendulum. The conductor is pulled to one side and released. The time for the conductor to swing from one side to the opposite and back is recorded. t  ⎛ ⎞ ⎜ 1.7961 N  ⎟ ⎝ ⎠

2

D

=

. . .T5

 D

=

conductor sag (m)

t 

=

time for conductor to swing  N   times from one side to the opposite side and back (seconds)

 N 

=

number of swings timed

where

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

243

DRAFT ONLY

APPENDIX U

RISK BASED APPROACH TO EARTHING (Normative) U1 RISK ANALYSIS

A probabilistic risk analysis is a calculation of the probability and consequences of various known and postulated accidents. Probabilistic risk analyzes are therefore an applied extension of statistics and are affected by the same limitations and assumptions from which the methods are derived. In this guide, the probabilistic risk analyzes are used to determine the probability of causing fatality to one or multiple individuals. The calculation of the probability of fatality is limited by the accuracy of the available data and the conditions under which the hazard may occur. The calculation of the probability of fatality may be simplified significantly if the following conditions are met: (a)

The occurrence of a hazard is random.

(b)

The occurrence of a hazard is independent of the presence of an individual.

(c)

The occurrence of a hazard will be independent of the occurrence of past hazards.

(d)

The hazard occurs at a constant rate per unit of time, one at a time*.

The development of a probabilistic risk approach on the basis of these assumptions restricts the application of the calculation to individuals who will not contribute to or cause the hazard to occur, and situations for which a fault which causes the hazard will not cause the generation of additional faults. If the probability of a fault occurring satisfies the above conditions the occurrence of faults may be classified as a ‘Poisson Process’ and the  probabili ty of an individual being in a hazard zone during a fault can be described by  P c:  P c

=

λH × λE × (  LE +  LH)

1 365 × 24 × 60 × 60

. . .U1

where

λH

=

hazard rate factor (average number of faults per year)

λE

=

exposure rate factor (average number of exposures per year)

 L H

=

average hazard duration (in seconds)

 L E

=

average exposure duration (in seconds)

* In certain situations, hazards separated by short intervals derived from a single cause may be approximated as a single fault. 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

244

DRAFT ONLY

 P c  is the probability that an individual is in a hazard zone during the fault. Hence, it can be thought of as the probability that the exposure of an individual and the presence of a fault coincide. To convert this probability to a probability of a fatality there are many variables to consider. Following a coincidence, a fatality depends on factors such as the footwear, clothing, age and health of the person in the hazard zone, as well as other environmental factors and the exact position of the individual. Hence, although  P c  is a useful measure of the probability of coincidence, it is a conservative estimate of the probability of death and it is extremely difficult to know whether it is a good approximation or highly conservative. This lack of precision is due to the multitude of unknown factors which control whether a coincidence becomes a fatality. In summary,  P c is an effective metric for the probability of fatality and can be used to rank hazard situations. However, it is difficult to directly estimate the probability of a fatality. The coincidence probability is therefore be considered equivalent to the probability of fatality.

In some cases it may be more useful to set the coincidence probability,  P c, to the high and low limits,  P high (=10 −4),  P low   (=10 −6) and back calculate the limits for the total time spent inside the hazard zone each year.

μ low-int

= =

μ int-high

31,536,000 × 1 × 10 −6 λH

31,536, 000 × 1 × 10 −4 λH

×

 LE

+ LH

 LE

×

=

31.5

=

3153.6

 LE  LE

+ LH

λ H

λ H

×

LE LE

×

+

. . .U2

LH LE

LE

+

LH

. . .U3

The method of defining the exposure limits according to the fault rate, and comparing the calculated risk according to limits of 10 −4 and 10 −6  are mathematically equivalent. These limits provide a simple method which may be used by on-site personnel to estimate whether the exposure is likely to exceed the tolerable limits set. The cumulative exposure of an individual may be expressed as: μ 

λE LE

=

. . .U4

where

λE

=

exposure rate factor (average number of exposures per year)

 L E

=

average exposure duration (in seconds)

 μ

=

cumulative exposure per year (in seconds)

In complex cases for which the rate at which hazards occur has large seasonal variations, the risk should be determined by using the coincidence probability. U2 FAULTS ON TOWERS AND CABLES

To assist with calculations, where more accurate data is not available, some typical data on overhead line fault rates and protection fault clearing times can be found in Table U1 and Table U2, respectively. For considering faults on overhea d lines, if the l ine length of interest is known, then the average number of faults per unit time on overhead lines in Table U1 can be used to estimate the rate at which hazardous voltages will occur on a tower λH .

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

245

DRAFT ONLY

The fault rates for underground cables are much lower than for overhead lines. Typical underground cable fault rates are 2 to 3 per 100 km for 11 to 33 kV and less than 1 for higher voltages. The average fault duration,  L H, can be estimated from values given in Table U2. Note that for close in faults , earth fault cur rent is high and the protection operates quickly. However, for faults further out along the feeder, line impedance causes lower fault current which takes longer to be seen by the protection. Consequently, different fault locations need to be considered to determine the worst case EPR and clearing time combination. TABLE U1 TYPICAL OVERHEAD LINE FAULT RATES System voltage (phase to phase)

Overhead line fault rate (faults/100 km year)

LV

20–150

11 kV–33kV

5–10 shielded, 10–40 unshielded

66 kV

2–5

100 kV–132 kV

1–4

220 kV–275 kV

<1.0

330 kV

<0.5

400 kV

<0.5

500 kV

<0.5

 NOTE S: 11 The rate at which faults occur on a tower is different to the rate at which hazards occur. The hazard zones around towers connected by OHEWs are reduced by the flow of current transferred through adjacent towers, however this transferred current can also create hazards at those towers. The rate at which hazards occur can therefore be significantly larger than the tower fault rate. 12 The higher outage rates occur in northern Australia where there is more frequent high wind and lightning storms. 13 The lower outage rates occur in southern Australia and New Zealand where there is less frequent high wind and lower lightning activity.

TABLE U2 TYPICAL PRIMARY PROTECTION CLEARING TIMES System voltage (phase to phase)

Primary protection clearing time

LV

2s

11 kV–33 kV

1s

66 kV

0.5 s

100 kV–250 kV

220 ms

251 kV–275 kV

120 ms

330 kV

120 ms

400 kV

120 ms

500 kV

100 ms

 NOTE :Th e pri mar y protec tio n cle ari ng tim es for >100kV are based on Nation al Electricity Code fault clearing time requirements for remote end.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

246

DRAFT ONLY

U3 SIMPLIFIED CALCULATION OF PERMISSIBLE EXPOSURE LIMITS

The above calculation may be simplified if certain additional conditions are met— (a)

the length of time for which a person is within a hazard region is significantly greater (more than 100 times greater) than the average length of a fault;

(b)

the rate at which faults occur over time is constant (i.e. faults are equally likely to occur at any time of the day or season); and

(c)

there is only one source of hazards within the hazard region.

The above conditions are usually too strict for most situations as slight variations in fault rate and exposure length can occur. Further analysis is required for such situations however the analysis does not usually alter the calculated probability significantly. If conditions (a), (b), and (c) are met, the limits for cumulative exposure per year can be calculated as— μ high

=

3153.6 λH

, μ low

=

31.5

. . .U5

λ H

The coincidence probability may be calculated using the simplified equation—  Pc

= λH × λ E ×

LE

1

. . .U6

365 × 24 × 60 × 60

Example 1 Problem

A jogger goes for a run every day of the week. At the end of each run, the jogger leans against a 11 kV concrete pole to do stretching exercises for two minutes. Hazards occur at the pole once every 150 years and create a hazard on and around the pole. The length of an exposure is significantly longer than the fault clearing time. Solution 1

The average length of time that the jogger is exposed in the hazard region  L E is 120 s, and the average number of exposures per year, λE , is 365. Faults occur once every 150 years on average. The fault rate factor is therefore— λ H

=

1 hazard 150 years

= 6.67 × 10−3 hazards per year  

. . .U7

The equivalent probability is therefore—  Pc

≈ λH × λ E × LE

1

6.67 ×10 −3 × 365 120

365 × 24 × 60 × 60

365 × 24 ×60 ×60

= 9.3×10−6

. . .U8

This risk level is above the tolerable level of 10 −6  and falls in the Intermediate risk category defined in section Consequently, risk treatment measures should be investigated to reduce the risk to as low as reasonably practical. Solution 2

The hazard rate λH   is equal to— λ H

=

1 hazard 150 years

= 6.67 × 10−3 hazards per year  

8326-PDR - 24/07/2008 14:25:50

. . .U9

DRAFT ONLY  

247

DRAFT ONLY

The limits for the cumulative exposure per year are— μ high

=

3153.6 λ H

μ low = 0.01

3153.6

=

6.67 ×10 −3

= 472,803s per year = 9092 s per week 

× μ lhigh = 4728 s per year = 91 s per week

. . .U10 . . .U11

The jogger’s exposure is above the lower limit of 91 s per week and falls in the ‘Intermediate’ ris k category defined in Section 10. As expecte d, the methods us ed in Solution 1 and Solution 2 produce the same result. U4 ADVANCED CALCULATION OF THE PROBABILITY OF FATALITY

If a situation does not meet one or all of conditions (a)–(c), a more rigorous analysis may be required to calculate the probability of fatality. The appropriate method of calculating the coincidence probability will be outlined for situations which do not meet the specified conditions in the following paragraphs. U5 CALCULATION OF THE PROBABILITY OF FATALITY FOR COMPARABLE EXPOSURE AND FAULT LENGTHS

The simplified calculation approximates the coincidence probability as the probability that a fault will occur while an individual is within the hazard region. For situations in which the length of exposure is comparable to the length of the fault however, a significant  proportion of the coincidence probability is derived from the arrival of an individual into a faulted hazard area. This is taken into account by the original calculation for the coincidence probability which takes into the case that a hazard is occurring when an individual enters a hazard region and the case that a hazard will occur while an individual is in the hazard region. Example 2: Problem:

A jogger goes for a run every day of the week. At the halfway point of each run the jogger touches a metal gate next to a 275 kV tower for 1 s. Faults occur at the pole once every 120 years and create a touch voltage hazard on the gate for 1 s. Solution 1: The risk associated with this scenario may be calculated directly using equation B1 as shown. The average length of an exposure  L E is approximately 1 s, the average length of a fault  LF  is 1 s, and the number of exposures per year that occur λE  is 365. The rate at which hazards occur is— λ H

=

1 hazard 120 years

= 8.33 × 10 −3 hazards per year  

. . .U12

The coincidence probability per year is therefore—  Pc

= λH λ E ( LH  +

LE )

1 365 × 24 × 60 × 60

= (8.33× 10 −3 ) (365) (1 + 1)

1 365 × 24 × 60 × 60

= 8.33× 10−3 × 365 × 6.34 × 10 −8 = 1.93 × 10 −7

8326-PDR - 24/07/2008 14:25:50

. . .U13

DRAFT ONLY  

248

DRAFT ONLY

The difference between the risk for cases in which the fault length is similar to the exposure length is therefore significant and in this case doubles the calculated risk. This risk level is  below the tolerable level of 10 −6  defined in Paragraph U6. Consequently, no risk treatment action is necessary. Solution 2:

The fault rate factor is therefore— λ H

=

1 hazard 120 years

= 8.33 × 10 −3 hazards per year  

. . .U14

The limits for the cumulative exposure per year are— μ high

=

3153.6 ⎛ λ H

3153.6 ⎛ 1s ⎞  L E  ⎞ ⎜ ⎟ = 8.33 10 −3 ⎜ 1s 1s ⎟ = 189,291s per year  × ⎝ + ⎠ ⎝ L H + LE  ⎠

. . .U15

= 3640s per week  μ low = 0.01

× μ lhigh = 1893 s per year = 36 s per week

. . .U16

The exposure of an individual in the hazard zone can be calculated by using—

μ

=

λE  LE = (120) (365) = 43,800 s per year = 840 s per week

. . .U17

U6 TOLERABLE RISK LIMITS

Any injuries or fatalities to workers or members of the public are unacceptable, however the inherent danger of electricity and disproportionate cost of protecting every individual from every conceivable hazard require that some level of risk be tolerated. Tolerable limits vary according to the classification of the risk. Individual Limits

The unacceptable and acceptable individual fatality probability limits in the context of this document are shown in Table U3. TABLE U3 RISK MANAGEMENT MATRIX—FREQUENCY OF OCCURRENCE VERSUS SEVERITY OF CONSEQUENCE Probability of single fatality (per year)

Risk classification for public death

Resulting implication for risk treatment

≥10 − 4

High

Intolerable Must prevent occurrence regardless of costs.

10 −4 –10 −6

Intermediate

As low as reasonably practical for intermediate risk Must minimize occurrence unless risk reduction is impractical and costs are grossly disproportionate to safety gained.

≤10 − 4

Low

As low as reasonably practical for low risk Minimize occurrence if reasonably practical and cost of reduction is reasonable given  pro jec t c ost s.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

249

DRAFT ONLY

U7 RISK TREATMENT MEASURES U7.1 General

When designing earthing systems, the following risk treatment methods should be considered to manage the risk associated with step, touch and transferred voltage hazards: (a)

Reduction of the impedance of the earthing system.

(b)

Reduction of earth fault current using neutral earthing impedances or resonant earthing.

(c)

Reduction of the fault clearing times.

(d)

Surface insulating layer.

(e)

Installation of gradient control conductors.

(f)

Separation of HV and LV earth electrodes.

(g)

Isolation.

Often a combination of risk treatments will be required to control EPR hazards. The above methods are detailed below. U7.2 Reducing earth grid impedance

Reduction in the impedance of an earthing system can be effective in reducing the EPR hazards. However, since the fault current usually increases as the earth grid impedance decreases, the effectiveness of the reduction depends on the impedance of the earth grid relative to the total earth fault circuit impedance. For the reduction to be effective, the reduced impedance needs to be low compared to the other impedances in the faulted circuit. Typically, the earth grid impedance must approach the power system source impedance  before the EPR starts decreasing significantly . If the earthing system earth impedance is reduced by enlarging the earthing system, then even though the EPR on the earthing system will reduce, the resultant EPR contours may be  pushed out further. In some circumsta nces, the increase in the siz e of the EPR contours may  be significant for a small reduction in the EPR of the sys tem. As a result, the size of any transferred EPR hazard zones will increase. Whether this is a desirable end result will depend on the specifics of a particular situation. If the earthing system earth impedance is reduced by bonding remote earths to it, then the resultant reduced EPR is also spread to the remote earths. This also introduces new transferred EPRs onto the earthing system when there are earth faults at any of these remote earths. Examples of this include bonding pylons to substations via overhead earth wires, and bonding the earthing system to extensive LV network systems. This risk treatment measure can be very effective in significant urban areas where an extensive earthing system can be obtained by bonding together protective earth and neutral (PEN) conductors from adjacent LV networks. The following methods may be considered when attempting to reduce the impedance of earth electrodes. U7.3 Overhead shield wires

Shield wires are typically used on transmission lines at or above 66 kV usually at least over a short section of line out from the substation. Shield wires are also sometimes used on distribution lines (11 kV and above) for the first kilometre out from the substation but this is not common.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

250

DRAFT ONLY

While the primary purpose of the shield wires is to provide lightning shielding for the substation, bonding of the shield wires to the substation earth grid can significantly reduce earth fault currents through the earth grid for faults at the station or at conductive poles or towers bonded to the shield wires. Inductive coupling between the shield wire(s) and the faulted phase conductor can significantly reduce the earth return current during fault conditions at conductive poles or towers bonded to the shield wire(s). This, in turn, reduces the EPR levels at both the substation and at the conductive pole or tower. However the incidence of (transferred) EPR events at the conductive poles or towers will become more frequent since each station EPR will be transferred to the nearby towers/poles. For a bus earth fault at a substation, the shield wires can divert significant current away from the substation earth grid. The net effect of the shield wires is to reduce the impedance of the overall earthing system (earth grid and tower/pole footing electrodes in parallel) thereby reducing the EPR. Consideration shall be given to the shield wire size (fault rating), particularly for the first few spans from the substation. U7.4 Cable screen

Bonded cable screens provide galvanic and inductive return paths for fault current for both cable faults and destination substation faults. Bonding of cable screens to the earthing systems at both ends is advantageous in most situations. However, the transfer of EPR hazards through the cable screens to remote sites should be considered as part of the design. The bonding of single core cables at both ends may affect the rating of the cables, depending on the cable configuration (due to induced currents in the screens and sheaths). Care should be taken to ensure the rating of the cable is adequate for the application. The rating of the cable screen should be adequate for the expected fault current and for the current induced in the screen during normal operation. U7.5 Earth electrode enhancement

If the soil resistivity is high and the available area for the grounding system is restricted, methods of enhancing the earth electrode may be required. Such methods include the encasement of the electrode in conducting compounds, chemical treatment of the soil surrounding the electrode and the use of buried metal strips, wires or cables. These methods may be considered in certain circumstances as a possible solution to the  problem of high electrode resistance to earth. They may also be applied in areas where considerable variation of electrode resistance is experienced due to seasonal climatic changes. Chemical treatment of the soil surrounding an electrode should only be considered in exceptional circumstances where no other practical solution exists, as the treatment requires regular maintenance. Since there is a tendency for the applied salts to be washed away by rain, it is necessary to reapply the treatment at regular intervals. U7.6 Reduction of earth fault current

Earth fault currents flowing through earthing systems may be reduced by the installations of neutral earthing impedances such as neutral earthing resistors (NER). Alternatively, resonant earthing such as Petersen Coils, Arc Suppression Coils, Earth Fault Neutraliser Earthing, may be very effective.  NERs are typically employed in distribution networks to limit the current that would flow through the neutral star point of a transformer or generator in the event of an earth fault.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

251

DRAFT ONLY

 NERs may be an effective way of reducing the EPR at faulte d sites and thereby controlling step, touch and transferred voltages especially in urban areas where distribution system earth electrodes are bonded to a significant MEN system. However, the reduction in EPR may not always be significant if the impedance of the earthing system is relatively high. The use of NERs for the control of EPR hazards should be investigated on a case by case  basis.  NERs can be very effective in reducing induction into parallel services such as telecommunication circuits or pipelines. Resonant earthing (Petersen coils) are very effective is controlling step, touch and transferred voltages. A Petersen coil is an inductance that is connected between the neutral point of the system and earth. The inductance of the coil is adjusted so that on the occurrence of a single phase to earth fault, the capacitive current in the unfaulted phases is compensated by the inductive current passed by the Petersen coil. Upon the occurrence of an earth fault, the system capacitance discharges into the fault and the faulted phase voltage collapses to a very low value leaving a very small residual current flowing in the fault. This current is so small that any arc between the faulted phase and earth will not be maintained and the fault will extinguish. Transient faults do not result in supply interruptions and in some jurisdictions permanent earth faults can be left on the system without the supply being interrupted while the fault is located and repaired. Modern systems provide automatic tuning of the inductance to accommodate changes in network topology. To increase safety and to eliminate restriking faults on underground cables, some systems also provide electronic compensation to reduce the remaining residual current and voltage on the faulted phase to zero. Resonant earthing c an reduce MEN EPR to a safe level even in systems wi th high MEN resistance. U7.7 Reduction of fault clearing times

EPR hazards can be mitigated by the reduction of the fault clearing time. This may be easy to implement in certain situations and may be very effective. Reduction of the fault clearing time may require significant protection review and upgrade, and may prove impracticable. The need for adequate protection grading may also limit the effectiveness of this measure. U7.8 Surface insulating layer

To limit the current flowing through a person contacting a temporary livened earthed structure, a thin layer of high resistivity material, such as crushed rock and asphalt, is often used on top of the ground surface. This thin layer of surface material helps in limiting the  body current by adding resist ance to touch and step voltage circuits. Crushed rock is used mainly, but not exclusively, in zone substations and transmission substations for the following reasons: (a)

To increase tolerable levels of touch and step voltages during a power system earth fault.

(b)

To provide a weed-free, self draining surface.

Asphalt may also be used in zone substations and transmission substations but is likely to  be more expensive than crushed rock. Asphalt has the advantage of providing easy vehi cle access. Vehicle access over crushed rock may sometime be problematic especially if the  basecourse i s not prepared correctly. 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

252

DRAFT ONLY

Asphalt and crushed rock can also be used to control touch and step voltages around towers and poles. Limited data is available on the flashover withstand of asphalt which may be as low as 4 kV for a 50 mm thick sample. Therefore, where asphalt is used for mitigation, touch voltage should typically not exceed 4 kV and step voltage should not exceed 8 kV. For applications where these limits are exceeded, the withstand voltage should be determined based on the type of asphalt that is being considered. For design purposes the following criteria applies: i)

A resistivity of 3,000 Ω-m and a minimum thickness of 100 mm should be used for crushed rock.

ii)

resistivity of 10,000 Ω-m and a mi nimum thickness of 50 mm should be us ed for asphalt.

The insulating property of crushed rock can be easily compromised by pollution (e.g. with soil). Therefore, regular inspection and maintenance of a crushed rock layer is required to ensure that the layer stays clean and maintains its minimum required thickness. The insulating property of asphalt can be compromised by cracks and excessive water  penetration. The integrity of the asphalt layer used for surface treatment shall be maintained. Close attention is required to the preparation of the ground prior to the application of crushed rock or asphalt. Suitable basecourse shall be prepared before laying the crushed rock or asphalt. Chip seal should not be used since the resistivity of the chip seal surface is not typically very high and its breakdown voltage is usually low. Concrete should not be used to control touch and step potentials due to its low resistivity unless the reinforcing in the concrete is used to provide an equipotential zone. U7.9 Gradient control conductors

Touch voltages on a structure can be mitigated to some extent by using gradient control conductors buried at various distances from the structure. Typically gradient control conductors are buried at a distance of one metre from the structure. Additional gradient control conductors are also buried further out from structures as required. In zone and transmission substations, gradient control conductors are typically used for the control of touch voltages outside the station security fence. These conductors are very effective when used in conjunction with a metre wide strip of crushed rock or asphalt installed around the outside of the fence. When designing zone and transmission substations, provision should be made to allow such a strip to be installed, if required. Gradient control conductors can also be used to control touch voltages on distribution substations and equipment. Step voltages cannot be controlled with the use of gradient control conductors. U7.10 Separation of HV and LV earth electrodes

When an earth fault takes place at the HV side of a distribution centre, the EPR on the HV earth electrode is transferred to the LV system via the PEN conductor. By separating the HV and LV electrodes, the transfer of EPR from the HV system to the LV system can be controlled. The minimum separation distance required between the HV and LV earthing systems is dependent on— (a)

the size of the HV earthing system; 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

253

(b)

the maximum EPR on the HV earthing system; and

(c)

the distances to the earths bonded to the LV system.

DRAFT ONLY

A minimum separation dis tance of 4 m is suggested between the HV and LV earthing systems. In some instances the required separation may be much larger (i.e. low/high resistivity layering with a LV network of limited extent). The integrity of the separated HV and LV earthing systems may be difficult to maintain into the future since other earthed structures may be installed at later stages within the physical separation distance. Separated HV and LV earthing systems may not be effective in controlling hazardous step and touch voltages in the event of a HV line to LV line contact at the distribution transformer, or on a conjoint HV/LV line section. The following options may be considered for protecting against HV to LV contacts: (i)

Ensuring the configuration of LV lines at the distribution transformer poles is such that a HV line to LV line contact is unlikely.

(ii)

Replace the LV lines over conjoint HV/LV spans with— (A)

LV buried cable;

(B)

LV lines on a separate poles; or

(C)

LV aerial bundled conductor cable that is insulated to withstand the full HV conductor voltage.

The transformer shall be rated to withstand the maximum EPR on the HV earthing system, without breaking down to the LV side of the transformer (e.g. via HV/LV winding  breakdown, or transformer tank to LV winding breakdown). When the LV earthing system is segregated from the HV earthing system at a distribution substation, the total earth impedance of the LV earthing system plus associated MEN earths, shall be sufficiently low to ensure the HV feeder protection will operate in the event of a HV winding to LV winding fault. A safety factor should be considered when calculating this maximum earth impedance value. U7.11 Isolation

Access to structures where hazardous touch voltages may be present can be restricted by the installation of safety barriers or fences. These barriers or fences would typically be nonconductive such as wood, plastic or rubber. For example, a tower could be surrounded by a wooden fence to restrict access to the tower base, or a sheet of rubber could be wrapped around the base of a steel or concrete pole. The installation of isolation barriers usually requires ongoing maintenance but can be very effective in reducing the risk. Third party fences should be isolated from the substation security fence using nonconductive section of fences. Non-conductive sections may also be required at additional locations along third party fences. Mitigation of step and touch voltages of metallic pipelines e.g. water pipes connected to a HV or LV network earthing system can be effectively achieved by the installation of plastic  pipes. Example 3:

To illustrate the principles of risk based earthing design following the simplified method  presented in this guide, a simple case study is detailed below. The cas e study follows the steps detailed in Section 10

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

254

DRAFT ONLY

The case study involves an existing 33 kV concrete pole located close to a bus stop. This  pole was identified as potentially carrying an EPR risk for people using the bus stop. The  bus stop is typically used by people travelling to work and it can therefore be ass umed that footwear is worn around the pole. Step 1—Basic data:

(a)

The prospective earth fault current at the source substation is 7 kA.

(b)

The resistance to earth of the 3 kV pole was measured as 20 Ω .

(c)

The resistivity of the top soil layer was measured as 50 Ω-m.

(d)

The earth fault clearing time is 0.5 s.

(e)

The earth fault frequency for the line is 5 per year.

(f)

The line consists of 200 poles.

Step 2 —Functional requirement

The pole already meets the functional requirements. Step 3—Connection to other earthing systems

In this case, bonding the 33 kV pole to nearby earthing systems is not practical. Step 4—Pole EPR

Using parameters associated with the earth fault current path for an earth fault at the pole, the EPR on the pole was calculated as 6 kV. Step 5—Prospective tolerable step and touch voltage limits

The touch voltage limit was determined from Figure 10.2 for a fault clearing time of 0.5 s and for a soil resistivity of 50 Ω -m (footwear included). The step voltage limit was determined from Figure 10.1 for a fault clearing time of 0.5 s and for a soil resistivity of 50 Ω -m (footwear excluded). VT (limit) = 600 VS (limit) = 5000 Step 6—Is EPR

VT (limit) and VS (limit)?

The EPR on the pole is greater than the touch and step voltage limits. Step 7—Calculate actual step and touch voltages

The actual touch voltage on the pole was calculated as approximately 3000 V The actual maximum step voltage was calculated as approximately 2000 V Step 8—Are actual touch and step voltages

VT (limit) and VS (limit)?

Actual touch voltage exceeds the touch voltage limit but the actual step voltage is less than the step voltage limit. Therefore, only touch voltage hazards exist. Step 9—Risk analysis

The only hazardous components at the pole are the touch voltages onto the concrete pole. The risk can be assessed by calculating the coincidence probability. Applying equation U6

 Pc

= λH × λ E ×

LE

1 365 × 24 × 60 × 60

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

255

DRAFT ONLY

The frequency of earth faults for the line with 200 poles is 5 faults per year. Therefore— λ H

=

5 200

= 0.025

If for the purpose of this case study, we assume that the pole is being touched once a day for 5 min (i.e. someone leans against the pole) for five days of the week (i.e. for 260 days  per yea r), λE = 260.  L E  Pc

=

5 min

= λH × λ E × LE

× 60 s = 300 s 1 365 × 24 × 60 × 60

=

(0.025)(260)(300) (365 × 24 × 60 ×60)

= 6 ×10−5

Since only one person is typically affected,  N 2  = 1 and the equivalent probability is—  P e

=

 N 2 P c =  P c = 6

× 10 −5

The risk is therefore ‘Intermediate’ and should be minimised unless the risk reduction is impractical and the costs are grossly disproportionate to safety gained. A cost benefit analysis should be carried out to determine whether the costs of risk treatment options are disproportionate to safety gained. Calculate the present value (PV) of the liability— Value of a statistical life (VOSL) = $10,000,000 Liability per year = 10,000,000 × 6

× 10 −5 = $600

PV = $13,000 (assuming an asset lifespan of 50 years and a discount rate of 4%) Step 10—Risk treatment options

A number of risk treatment options can be considered. Examples of risk treatment options are— (a)

Installing an underslung earth wire on the line.

(b)

Installing a gradient control conductor and an asphalt layer around the pole.

(c)

Installing an insulating barrier around the pole to prevent people from touching the  pole.

(d)

Moving the pole.

(e)

Moving the bus stop.

A few of the above risk treatment options are detailed below to illustrate the principles. (i)

 Installing an underslung earth wire on the line

A study has shown that an underslung earth wire would reduce the EPR on the pole to 600 V. The resulting touch voltage on the pole would then reduce to 300 V which is  below the tolerable touch voltage limit. The cost of this risk treatment option has  been determined to be approximately $200k. Comparing the cost of ris k treatment to the prevent value of the liability indicates that the cost of this risk treatment option is grossly disproportionate to the safety gained. (ii)

 Installing a gradient control conductor and an asphalt layer around the pole

With a gradient control conductor installed at a distance of one metre around the pole, the touch voltage reduc es to 900 V. This touch volta ge exceeds the touch voltage limit. However, if asphalt is also installed around the pole, the touch voltage limit increases to 2000 V with the result that the touch voltage is lower than the limit. The cost of this risk treatment option is $10k and is below the present value of the liability. There may be some additional ongoing costs associated with maintenance of the asphalt. 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

256

DRAFT ONLY

(iii)  Installing an insulating barrier around the pole to prevent people from touching the  pole An insulating barrier could be installed around the pole to prevent people from being able to touch the pole. Such an insulating barrier could take the form of a wooden enclosure or a fibreglass jacket. The cost of this risk treatment option is $5k and is significantly below the present value of the liability. There may be some additional ongoing costs associated with maintenance of the insulating barrier. (iv)  Additi onal risk treatment options may be considered as r equired  Clearly, economically viable risk treatment options exist for this case and one of the option should be implemented. The cheapest risk treatment option may not be the best option. Other considerations may dictate which risk treatment option is selected. For example, an underslung earth wire may be the best option if a number of other EPR issues exist along the line. For other cases, the costs and practicality of the selected mitigation option may be such that there is some residual risk in the intermediate category after mitigation is applied. The remaining steps detailed in section Section 10 should then be considered as required. The exposure corresponding to the transition from low to intermediate and from intermediate to high may also be calculated as a sensitivity/sanity check. The calculations  below show that the exposure would have to be in excess of 41 minutes per week for the risk to be come high. In this case, it is unlikely that someone would be exposed for so long every week. μ high

=

3153.6 λ h

= 126,144 s per year = 2426 s per week

For the risk to fall within the low risk category, the exposure for a person would need to be less than 24 s per week as shown below. In this case, it appears that the exposure is likely to exceed 24 s per week. μ low

=

31.5 λ h

= 1260 s per year = 24 s per week

The above sensitivity check confirms that an intermediate risk level should be adopted for this case.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

257

DRAFT ONLY

APPENDIX V

CONDUCTOR PERMANENT ELONGATION (Informative) V1 GENERAL

Conductor permanent elongation expressed as a function of time, temperature, conductor stress and conductor constants is given as—

ε

c1

=

kt 

σc2 ec3( θ− 20)

. . .V1

where

ε

=

unit strain in mm/km

t 

=

time in years

σ θ

=

conductor average stress in MPa

=

conductor average temperature in °C

k , c1, c2 and c3 are constants

In many cases, the conductor exposure period at elevated temperatures is very small relative to an everyday exposure temperature assessed to be 20°C hence the above equation may be reduced to—

t 

=

c1

kt 

σc2

. . .V2

Conductor constants ar e determined by conductor creep tests as des cribed in AS 3822. Typical creep test results are illustrated in Figure V1 and yield the creep constants k , c1, c2 and c3.

   )    N    I

 T 85 C  = 20% CBL

   O    I    T    A    G    N    O    L    E    (    G    O    L

 T 20 C  = 40% CBL  T 20 C  = 30% CBL  T 20 C  = 20% CBL Initial creep

LOG (TIME)

FIGURE V1 TYPICAL CONDUCTOR CREEP TEST RESULTS

The cumulative conductor permanent elongation is dependent on the aggregation of  permanent elongation intervals characterized by differing conductor stress es and temperatures. Graphically, a conductor may be subjected to a number of differing stress levels and temperatures each with a given time interval as illustrated in Figure V2. In this example, the initial exposure is at 20% CBL and 20°C with a duration, t 1 to t 2  which will result in creep accumulation of ε2 − ε1 as the conductor behaviour moves from a to b.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

258

   )    N    O    I    T    A    G    N    O    L    E    (    G    O    L

DRAFT ONLY

 T 85 C  = 20% CBL

3 2 1

d c

 T 20 C  = 20% CBL

a t3

e

b

t1 t4

t2

t5 LOG (TIME)

FIGURE V2 TYPICAL CONDUCTOR PERMANENT ELONGATION ACCUMULATION

At c, the conductor experiences an elevated temperature at say 16% CBL and 85° with duration, t 3 to t 4  which will result in creep accumulation of ε3 − ε2   as the conductor  behaviour moves from c to d. At d, the conductor may return to the original condition and hence the original creep curve and transition to point e. Thus, conductor permanent elongation may be determined for the predicted operating duty of the transmission line. Whilst this has been illustrated as a graphical representation of the creep accumulation, the application of the elongation equation knowing the conductor stress history, exposure duration and conductor temperature allows a mathematical determination of the creep accumulation. Also illustrated in this example is that— (a)

the creep at a low temperature is much less than that at an elevated temperature; and

(b)

the creep from one creep curve may be translated to another creep curve (ie from  point b to point c and also from point d to point e).

Conductor creep is cumulative for a given set of operating conditions of time, temperature and stress. c1

⎡ σ (i−1) ⎤ c 2 ( −1) ⎢ σ  ⎥ ⎣ 1 ⎦ t i

T eq(i) =

. . .V3

where

σ(i)

T eq(i)

=

the equivalent time in years for unit strain at stress level

σ(i-1)

=

the stress level in MPa associated with time interval t (  i − 1)

σ(i)

=

the stress level in MPa associated with time interval t eq(i)

t (i-1)

=

time interval in years associated with stress level

σ(i −1)

One of the most important aspects of understanding conductor permanent elongation is determining design allowances for the long term conductor behaviour. The design allowance for conductor elongation is necessary to account for the changes in conductor sag and hence ground clearance over time. To compensate for conductor inelastic stretch it is necessary to carry out one or a combination of the following: (i)

add a margin on the statutory ground clearance requirements;

(ii)

subtract an allowance on the maximum design temperature;

(iii)

prestress conductors prior to final sagging; and or

(iv)

over-tension conductors.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

259

DRAFT ONLY

Reference: CIGRE WG 22.05 ‘ Permanent Elongation of Conductors Predictor Equations and Evaluation Methods ,’ CIGRE Electra No 75 1981.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

260

DRAFT ONLY

APPENDIX W

CONDUCTOR MODULUS OF ELASTICITY (Normative) W1 GENERAL

Homogeneous conductor modulus of elasticity is given as  E al

=

68 GPa (aluminium)

. . .W1

 E st

=

193 GPa (SC/GZ)

. . .W2

Figure W1 illustrates a s tress strain curve for a homogenous conductor. Essent ially the figure shows the loading and unloading as a function of stress and strain where strain is expressed as a percentage of elongation. As the applied load exceeds the elastic limit of the conductor some permanent elongation will result as shown in Figure W1.

Homogenous conductor

   S    S    E    R    T    S

Leading

Unloading

Permanent elongation

STRAIN (% ELONGATION)

FIGURE W1 STRESS STRAIN CURVE FOR A HOMOGENOUS CONDUCTOR

Figure W2 illustrates a stress strai n curve for a non homogenous conductor such as an ACSR construction.

Composite conductor

   S    S    E    R    T    S

Outer wires (al)

core ( gz  )

 Tr ans i tio n po int

STRAIN (% ELONGATION)

FIGURE W2 STRESS STRAIN CURVE FOR NON HOMOGENOUS CONDUCTOR

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

261

DRAFT ONLY

The initial characteristics of the conductor stress strain may be described by a polynomial equation as follows:

με

=

 A0 +  A1S  +  A2S 2 +  A3S 3 +  A nS n

. . .W3

where

με

=

conductor strain

 An

=

coefficients derived from conductor test

S 

=

conductor stress

‘ A0’ is general very small and can be ignored. Usually a 3rd order polynomial describes the data adequately, however in some cases higher orders may be more appropriate. Similar  polynomials are derived for the initial curves of the steel core and the alu mini um outer layer. Linear regression may be applied to the unloading curves and is used to determine the line of best fit. The slope of the line is termed the final modulus of elasticity. For a non homogenous conductor, consisting of dissimilar materials, the composite modulus above the transition point may be theoretically determined knowing the weighted ratios of the aluminium and steel components to the composite conductor and the material modulus of aluminium and steel and is given as—

+ A2 E 2  A1 + A2

 A1E1

 E comp =

. . .W4

where  A

=

cross sectional area

 E 

=

conductor modulus of elasticity

1

=

subscript denoting material 1

2

=

subscript denoting material 2

Below the transition point the modulus will be that of the core material and in the case of an ACSR/GZ, the modulus will be that of the GZ wires. Equation W4 does not account for the wire geometry of a helical stranded conductor and this equation will always over estimate the modulus by about 1%. A 1% error in modulus will generally result in conductor sag error of about 2%. In more recent times Nigol and Barrett (see reference at end of this Appendix) discovered that the stress and strains in helically stranded aluminium wires of a conductor were not the same as those of the individual straight wires. By examining the wire geometry of a helically stranded wire, Nigol and Barrett derived an equation for the conductor strain related to the wire strain, and to the change of layer radius R. From this work, a more accurate modulus may be determined and for a non homogenous conductor with multiple layers the composite modulus is given by—  Ec

 N  ⎡ ⎡n ⎤⎤ = ⎢ Ecore Acore + ∑ ⎢∑ ni,j Ai,j E i ,j ⎥ ⎥  Ac ⎢⎣  j =1 ⎣ i =1 ⎦ ⎥⎦

1

i

where  A

=

cross sectional area

 E 

=

conductor final modulus of elasticity

 N i

=

number of wires in the conductor

 N ij

=

number of wires in i  layer of material  j

=

subscript denoting composite

c

8326-PDR - 24/07/2008 14:25:50

. . .W5

DRAFT ONLY  

262

1

=

subscript denoting material 1

2

=

subscript denoting material 2

DRAFT ONLY

The modulus for AAC, AAAC and ACSR/GZ conductors are published in relevant Australian Standards. The final stress strain curve of a non homogeneous construction includes a transition tension/stress load point defined as the point on the final modulus composite conductor curve where the slope of the curve changes from the composite modulus to that of core modulus. This is an unloading point where the aluminium because of permanent elongation does not support any stress and the total conductor stress is supported by the core. The conductor modulus below the transition point is that of the steel core material. Of particular interest is the change in transition tension/stress with a change in temperature. A phenomenon reported by Nigol Barrett known as the birdcaging temperature, when above this temperature the conductor expands at the rate of the steel core. With increasing tensions the birdcaging temperature will increase because additional thermal expansion is required in the aluminium before the load is transferred wholly to the steel core. Conductor tension changes shall be determined in accordance with Table W1. TABLE W1 CONDUCTOR TENSION DETERMINATION MODELS Model

Modulus of Elasticity

 Non lin ear stre ss strain

Conduc tor stress strain des cri bed by a p oly nom ial equ ati on and determine conductor permanent elongation for tension excursions

Linear stress strain

Use final modulus for either homogeneous of non homogeneous conductors

Reference

 NIGOL, O. and BARRETT, J.S .,  Development of an Accurate Model of ACSR Conductors  for Calculating Sags at High Temperatures —Part III . Report prepared for the Canadian Electrical Association, March 1980.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

263

DRAFT ONLY

APPENDIX X

CONDUCTOR COEFFICENT OF THERMAL EXPANSION (Informative) X1 GENERAL

Homogeneous conductor coefficient of thermal expansion (CTE) is given as—

× 10 −6 (aluminum)

αal

=

23

αst

=

11.5 × 10

−6

  (sc/gz)

 Non homogenous conductor, consis ting of dissimilar materials, the composite CTE above the transition point is given as— α comp

+ A2 E 2α 2  A1 E1 + A2 E 2

 A1 E1α1

=

. . .X1

where  A

=

cross sectional area

α

=

coefficient of thermal expansion

 E 

=

conductor modulus of elasticity

1

=

subscript denoting material 1

2

=

subscript denoting material 2

Below the transition point the CTE will be that of the core material and in the case of an ACSR/GZ, the CTE will be that of the GZ wires. Equation X1 does not account for the wire geometry of a helical stranded conductor and this equation will always over estimate the CTE by up to 5%. A 5% error in CTE will generally result in conductor sag error of about 2%. A more accurate CTE may be determined by examining the wire geometry and an increase in temperature which will cause an increase in wire length resulting in an increase in lay length. Hence for a non homogenous conductor with multiple layers the composite CTE is given by— αc

=

 N  ⎡ ⎡n ⎤⎤  E A α + ⎢ core core core ∑ ⎢∑ ni,j Ai ,jα i,j ⎥ ⎥  Ec Ac ⎣⎢  j =1 ⎣ i =1 ⎦ ⎦⎥

1

i

. . .X2

where  A

=

cross sectional area

α

=

coefficient of thermal expansion

 E 

=

conductor final modulus of elasticity

 N i

=

number of wires in the conductor

 N ij

=

number of wires in i layer of material j

c

=

subscript denoting composite

1

=

subscript denoting material 1

2

=

subscript denoting material 2

CTE for AAC, AAAC and ACSR/GZ conductors are published in the relevant Australian Standards.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

264

DRAFT ONLY

APPENDIX Y

CONDUCTOR DEGRADATION and SELECTION FOR DIFFERING ENVIRONMENTS (Informative) Y1 GENERAL

To one degree or another, most materials experience some form of interaction with a range of diverse environments. Often these interactions result in degradation of material ductility, strength and in the case of conductors, effective cross sectional area and hence conductivity. Conductor corrosion susceptibility depends on the material, the construction and the protective mechanisms employed in the design. The severity of the corrosive environment and the presence of chlorides, sulphur dioxide and other pollutants will accelerate corrosion. Atmospheric corrosion takes place in aqueous environments and the exposure duration of wetness is a principal factor. Y1.1 Pit corrosion

Pitting is the loss of parent material at a localised site on a surface exposed to the environment. Pitting may be caused by corona corrosion in UHV lines or more commonly  by localised electrolytic reaction in which water and oxygen must be present. Pit growth rate is generally very small. Surface pitting is generally associated with an exposure to industrial and coastal environments. With time, pit corrosion will continue to be initiated and existing shallow  pits may widen. Catastrophic localised corrosion is not likely to occur and the overall effect would be the gradual loss of cross sectional area. Y1.2 Crevice corrosion

When an electrolyte such as water is present in the interstitial spaces between wires, localised etching or crevice corrosion may occur. This may be associated with conductor suspension fittings coupled with environments of particularly high rainfall, frequented by fogs and or perhaps in close proximity to chloride and or sulphate atmospheric depositions. Corrosion may take place and voluminous grey to white slightly moist deposits between the  penultimate and ultimate aluminium layers wil l be found. Chemical invest igations generally reveal levels of aluminium oxide, sulphates and chlorides of about 60%, 5% and 1% respectively. Y1.3 Homogenous Al and Al alloy conductors

The corrosion mechanism is generally limited to pit corrosion and is influence by atmospheric chloride and sulphate levels. The performance is generally excellent due to firstly, the formation of a resistive coating of aluminium oxide and secondly that the PH levels of aluminium ranges from 4 to 8.5 which results in passive behaviour. Nevertheless all aluminium conductors show some pit corrosion and the level of pit corrosion is dependent on the level of impurities held in the substrate. One example is aluminium alloy 6201A which employs compound Mg 2Si, is anodic in aluminium and reactive to acidic solutions and tends to dissolve away leaving an inactive pit.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

265

DRAFT ONLY

Y1.4 Homogenous copper conductor corrosion

The corrosion mechanism is generally limited to pit corrosion and is influenced by the  presence of ammonia in the atmosphere. The performance is generally excellent due to the formation of a protective coating of copper oxide however severe corrosion will result when copper conductors are used in the vicinity of abattoirs and or fertiliser factories. When in contact with aluminium, special jointing techniques are critical to avoid severe and rapid galvanic corrosion of the aluminium from copper oxides in the presence of an electrolyte such as water. Y1.5 Homogenous galvanized steel wire conductors

The corrosion mechanism is limited to initially the gradual loss of zinc followed by localized galvanic action of the steel substrate. The rate of corrosion is approximately linear and is generally determined by the classification of the environment. Hence, the most critical element in determining the life of the zinc coating is coating thickness and this  provides a reli able correlation in de termini ng the expected life of zinc coated wires. Application of the known corrosion rates to zinc coated steel wires, the associated age and the location of the line enables the deterioration of the wires to be determined. The corrosion rates for zinc and steel are given in Table Y1 TABLE Y1 CORROSION RATES FOR ZINC AND STEEL Corrosion rate m/yr 1

Corrosivity classification

Zinc/steel corriosion ratio (approx)

zinc

steel

Mild

<1

<10

1:10

Moderate

<2

10 – 20

1:20

Tropical

<2

20 – 50

1:50

Industrial

2–4

20 – 50

1:15

Marine (>1 km)

2–4

20 – 80

1:20

Severe marine (<1 km)

4 >10

80 -200

1:20

Y1.6 Non homogenous Al conductors steel reinforced

Initially a galvanic cell is set up with the zinc coating of the steel wires as the anode and the aluminium wires as the cathode with the zinc corroding in the presence of sulphur oxides. After some time the zinc will expose the steel substrate. At this stage the aluminium will then act as an anode and the steel as a cathode resulting in the aluminium being sacrificial to the steel. At this stage, the aluminium corrosion rate accelerates rapidly. The most effective method of reducing corrosion is to prevent moisture, sulphur oxides and other corrosive substances from coming into contact with the zinc aluminium interface. This may be achieved by applying a protective material such as grease, bitumen, paint or a  plastic film over the zinc wires. Y1.7 Protective greases

Protective greases provide a layer or barrier to corrosion products and conductors may be  partly grease d which provides better performance than ungreased conductors. Fully greased conductors provide superior performance in the most aggressive environments. The performance of the grease is influenced by consideration of the drop point which should be much greater than the maximum operating temperature of line.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

266

DRAFT ONLY

If the drop point of the grease is less than the maximum operating temperature of line, then grease will liquefy, run to centre of span, form droplets and for lines greater than 33 kV cause radio interference. A cautionary note, that bituminous compounds used in 50’s and 60’s in ACSR/GZ have a drop point of about 700°C and there are many examples where lines may now be operating at or near maximum operating temperatures and the compound may have liquefied, run to the centre of the span and fallen as droplets. Y1.8 Application recommendations

Carter (see reference 2 at the end of the Appendix) reviewed the types of conductor constructions in common use and surveyed service experience and resistance to corrosion under varying conditions. Also published were results of corrosion tests in severe saline environments, commenced in 1964 in collaboration with Illawarra County Council (predecessor of Integral Energy). The results were consistent with those reported by other international and national authors at the time and indicate the following general conclusions— (a)

for aluminium, slight external pitting generally less than 250 μm will occur after about 3 years;

(b)

there is no difference in the extent of external pitting between 1350 aluminium and 6201 aluminium alloy;

(c)

there is good internal and external corrosion resistance provided by homogenous conductor constructions;

(d)

for ACSR/GZ protection of the aluminium wires will occur up to the point that degradation of the zinc coating has occurred;

(e)

severe attack on bare galvanized wires up to 3 years and complete removal of the zinc coating will occur in 3 years with salt deposition > 160 g.m −2 ; and

(f)

a delay in the onset of internal corrosion results will occur from the use of protective grease.

When selecting a conductor for a hostile environment the following factors should be considered: (i)

Full or partial greasing of the conductor significantly improves corrosion resistance.

(ii)

Ensure that all fittings are compatible so that electrolytic corrosion does not occur.

(iii)

Insulated/covered conductor systems may provide protection against corrosion  provided the conductors are completel y sealed by the insulation/covering and do not  provide traps for corrosive solutions nor allow ingress of moisture.

(iv)

The aluminium coating on SC/AC is very soft and should be treated carefully if it is to provide adequate corrosion protection. The corrosion resistance of SC/AC is very dependent on the thickness of the coating.

Carter’s work was used in the 90’s coupled with other service experience (see reference 3 at the end of the Appendix) to develop conductor application recommendations adopted by ESAA (now ENA) (see reference 4 at the end of the Appendix) shown in Table Y2.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

267

DRAFT ONLY

TABLE Y2 CONDUCTOR SELECTION FOR DIFFERING ENVIRONMENTS Salt spray pollution Conductor type

Industrial pollution

Open ocean

Bay, inlets and salt lakes

Acidic

Alkaline

AAC

Good

Good

Good

Poor

AAAC/6201

Good

Good

Average

Poor

AAAC/1120

Good

Good

Good

Poor

ACSR/GZ

Poor

Poor

Average

Poor

ACSR/AZ

Average

Good

Average

Poor

ACSR/AC

Good

Good

Average

Poor

SC/GZ

Poor

Poor

Poor

Average

SC/ZC

Good

Good

Good

Poor

OPGW

Good

Good

Average

Poor

HDCu

Good

Good

Average

Good

References

1.

ROBINSON, J.,  Development of A Dur ability Branding System for Steel Cons tructi on  Products , Corrosion Management, Vol 10, No. 2, pp 3 – 10, November 2001

2.

CARTER, R.D., Corrosion Resistance of Aluminium Conductors in Overhead Service . MM Metals Report released to the Aluminium Development Council.

3.

BRENNAN, G.F.,  Methodology for Ass essment of Serviceability of Aged Transmission Line Conductors   Postgraduate Thesis, Wollongong University, 1989.

4.

Guidelines for design and maintenance of overhead distribution and transmission lines , Electricity Supply Association of Australia Publication C(b)1, 1991.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

268

DRAFT ONLY

APPENDIX Z

CONDUCTOR STRESS AND FATIGUE (Informative) Z1 GENERAL

Fatigue failures of overhead line conductors occur almost exclusively at points where the conductor is secured to fittings. The cause of such failures is dynamic stresses induced by vibration combined with high static stresses. It is necessary therefore to limit both the static and dynamic stresses if the conductor is to have acceptable fatigue endurance. Z2 STATIC STRESSES Z2.1 Static tensile stress

The line conductor tension produces static tensile stresses in the individual conductor wires. For homogeneous conductors, the outer layer stress can be calculated by dividing the tangential tension in the conductor by the cross-sectional area. For non homogeneous conductors, the static tensile stress in the aluminium wires can be estimated by—

=

σ A1

T   AA1

. . .Z1

+ nASt

where

σAl

=

stress in aluminium wires area of aluminium

 AAl  ASt

=

area of steel

T 

=

conductor tension

n

=

 E fe / E al

 E al

=

68 GPa (aluminium)

 E st

=

193 GPa (sc/gz)

The ratio of the density of steel to aluminium is similar to the ratio of their moduli of elasticity and Equation Z1 may be rewritten as— σ A1

∝

T 

. . .Z2

m

In the case of ACSR conductors, the stress in the aluminium wires decreases with time as the metallurgical creep in the aluminium is much greater than in the steel and results in a load transfer from the aluminium to the steel. This effect becomes more predominant as the  percentage of steel in the conductor decreases. Z2.2 Static bending stress

Static bending stress results from the bending of the conductor at the support point and is a function of the span length, tension, self weight and flexural stiffness of the conductor and the radius of curvature of the support clamp. Z2.3 Static compressive stress

Static compressive stresses arise as a result of tensile and bending forces in the individual wires of the conductor and the conductor’s self weight on the support and from external clamping pressures. 8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

269

DRAFT ONLY

While the stresses are primarily bearing or radial stresses with very small associated longitudinal stress, they are a source of aggravated fretting which can significantly reduce the fatigue endurance of the conductor. Z3 DYNAMIC STRESSES

Dynamic stresses are alternating bending stresses caused by wind-induced vibration in the conductor and the stresses can vary widely in magnitude, frequency and duration. The fatigue fracture of an individual wire within a conductor is the result of a large number of stress cycles which cumulatively exhaust the fatigue strength or endurance limit of the material. The wind induced vibration or commonly known as aeolian vibration occurs when laminar wind flows across a conductor causing vortices to be shed alternatively from top and bottom of the conductor. This continuous shedding of vortices causes an alternating force to be applied to the conductor, thus causing vibration predominantly in the vertical plane. The severity of the vibration problem is determined by the nature of the wind flow, its direction with respect to the line, the line tension and the frequency of occurrence of the laminar winds. It is therefore necessary when considering dynamic stresses to take into account the topographical and climatic conditions of the line route. Laminar flow winds are generally most prevalent in early morning in winter. The vibration induced by wind veloci ties betwe en 0.5 m/s and 7 m/s is characterized by short wave lengths, relatively high frequencies and low amplitudes. Wind velocities less than 0.5 m/s do not have sufficient energy to induce vibrat ion and velocities gre ater than 7 m/s are turbulent in nature and do not produce the vortex shedding necessary to induce vibration. The temperature under which the horizontal tensions are applied should therefore be based on this condition. The average temperature over the coldest month is generally used for this  purpose. Practically all fatigue failures of conductors originate at wire crossover points or at support contact points where fretting occurs. Fretting is the form of damage that arises when two surfaces in contact are exposed to slight periodic relative motion. The fretting produces abraded particles and in the case of aluminium, the product consists of black aluminium oxide. Fretting initiates fatigue cracks and the overall fatigue strength of the conductor is significantly reduced. Conductor fatigue endurance is related to bending and compressive static stresses and is relatively insensitive to static tensile stresses. However as static stress levels increase, the conductor self-damping characteristics are reduced. This reduction in conductor selfdamping, coupled with the dynamic stress induced by laminar winds, which are terrain dependent, and length of time exposure to transverse laminar winds are considered to be the most significant factor in conductor fatigue endurance. Z4 LIMITING OUTER LAYER STRESSES Z4.1 Limiting static stresses

The outer layer stresses (OLS) used for the derivation of Table Z1 are generally based on work carried out by CIGRE and the Swedish State Power Board, and represent the allowable static tensile stress in the outer layer of a conductor under certain specified conditions. A conductor which is most likely to experience damage due to vibration will be supported in a short bolted clamp or on a pin insulator with no armour rods or dampers in a terrain conducive to laminar wind flow. This combination of factors defines the base case outer layer stress.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

270

DRAFT ONLY

A conductor which is least likely to experience damage due to vibration will be fully supported, fully damped and erected in a terrain not conducive to laminar wind flow. This combination of factors defines the recommended maximum outer layer stress levels. In Table Z1 the base case outer layer stresses have been converted to a base case horizontal tension expressed as a percentage of the calculated breaking load (CBL). The values listed in Table RTE are expressed as horizontal te nsion, rather than t angential tension. This approximation is satisfactory, except for very long spans or for spans in very steep terrain. Some adjustments have been made in the light of operational experience, in particular with regard to small diameter ACSR conductor with high steel content where experience has shown that, with effective damping, these conductors can be strung to higher allowable tensions. The static bending and static compressive stresses resulting from the support arrangement used for the base case can be reduced by using long radius shaped clamps, armour rods,  preformed ties or helical support/s uspension units. As a consequence of appropriatel y designed supports, a higher static tensile stress may be tolerated. Shaped long radius clamps and armour rods, or pin insulators with armour rods, allow an increase in the static tensile stress of 5% to 7%, while helical support/suspension units, or  preformed ties wit h elastomer inserts, used in conjunction with armour rods on pin insulators allow an increase of 10% to 15% on the base case. These allowable increases have been converted to a percentage of CBL and included i n Table Z1 under ‘clamp category’. The performance of AAAC irrespective of alloy is considered to related to fretting fatigue and Table Z1 reflects this consideration. Z4.2 Limiting dynamic stresses

Control of dynamic stresses is the most significant factor in the fatigue endurance of overhead conductors. Dynamic stresses can be limited by— (a)

terrain not conducive to laminar wind flow. Factors such as mountainous terrain, tree cover and urban development will minimize conductor vibration;

(b)

the use of effective vibration dampers;

(c)

the use of spacer dampers with bundled conductor; and

(d)

the presence of some or all of the above factors will allow the static tensile stress (design horizontal tension) to be increased in accordance with Table Z1.

Combinations of open or rolling terrain without dampers are in general not recommended  because the level of dynamic stress es that result can cause the fatigue life of the conductor to be reached at a very early stage. In this case the fatigue life may be relatively insensitive to everyday tension. This is particularly important for steel and small diameter high steel content ACSR conductors which have little inherent self damping. Z5 VIBRATION DAMPERS

Use of effective dampers is critical if use is to be made of this factor in the selection of the higher horizontal tensi ons from Table Z1. Selection of dampers should be based on the recommendations of the manufacturer and compliance with the relevant Australian or New Zealand or equivalent International Standards. Vibration damping requirements may be calculated, for example for Stockbridge type dampers using energy balance considerations which may allow higher tensions to be used. The following considerations are relevant:

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

(a)

271

DRAFT ONLY

Damper type Spiral dampers are generally considered to be more effective for conductor diameters up to 12 mm, and Stockbridge type dampers for conductor diameters above 15 mm. In the range 12 to 15 mm either type may provide an effective solution, alternatively an optimum solution may involve a combination of the two types

(b)

Damper construction Robustness of design to achieve a useful life compatible with that of other line components; avoidance of conductor damage at the point of attachment consideration of working live line working; and corona discharge and radio frequency interference limited to acceptable levels

(c)

(d)

Damping characteristics (Stockbridge dampers only)— (i)

Frequency response and energy dissipation—Should be capable of limiting  bending stress and strain anywhere along the conductor to permissible levels for all frequencies of vibration encountered in aeolian vibration; as the frequency is dependent on conductor diameter, dampers with different responses will be required for different conductors. It is important that the dampers have adequate energy dissipation over a wide frequency range and cover the highest level of expected frequency; and dampers which meet the performance criteria of AS 1154.1 will generally provide acceptable energy dissipation and frequency range;

(ii)

Impedance—The reactive and resistive mechanical impedance of the damper should match the conductor as closely as possible;

(iii)

Endurance—The fatigue life of the damper itself should be sufficient to endure the rigorous service life of the conductor. The performance of the damper should not deteriorate due to fatigue and ageing. With hardware using elastomer inserts, degradation due to exposure to ozone and ultra violet light should be taken into consideration; and

(iv)

Damper stress—The dampers should not create significant stresses on the conductor due to clamping or damping forces exerted by the bending stresses at the damper clamp.

 Number of dampers per span— For fully damped conductors the number of dampers in a span should be sufficient to dissipate wind induced energy in the conductor. It should also be noted that dampers to be used in Category 1 Terrain should provide substantially more energy dissipation than those used for higher terrain categories to fully damp the conductor. Consideration should be given to damper life when selecting the number of dampers in a span. There could be situations when effective energy dissipation can be achieved with fewer dampers, but this may be at the expense of the damper life.

(e)

Damper location— The ideal location is the anti-node of the vibrating loop, however, as vibration frequency and loop length is a function of wind velocity, the Manufacturer’s recommendation for a location to suit the full range of frequent wind velocities should be obtained.

8326-PDR - 24/07/2008 14:25:50

D R A F  T  O  N L Y

TABLE Z1 CONDUCTOR EVERYDAY LOAD HORIZONTAL TENSION (H) Recommended incremental increase in horizontal tension (% CBL)

Conductor or overhead earthwire type

Static stress considerations

Base case horizontal tension (% CBL)

Dynamic stress considerations Damping/terrain category No dampers

Clamp category* Terrain category† A

 8   3  2   6  P  D R 2  4   /    0  7   /   2   0   0   8  1  4  :  2   5  :   5   0 

COPPER SC/GZ, SC/AC AAC AAAC/1120 AAAC/6201 ACSR 3/4, 4/3 ACSR 6/1, 6/7 ACSR 30/7 ACSR 54/7, 54/19 AACSR/1120 6/1, 6/7 AACSR/1120 18/1 AACSR/1120 30/7 AACSR/1120 54/7, 54/19 AACSR/6201 6/1, 6/7 AACSR/6201 18/1 AACSR/6201 30/7 Optical conductor * Clamp category:

† Terrain Category:

25 10 18 15 13 10 17 16 18 14 16 13 14 13 14 12 14 Type A Type B Type C Type 1 Type 2 Type 3

B C 1 2 3 0 1.5 2.5 0 2 4 0 2.5 5.0 0 5 10 0 1.5 2.5 0 2 4 0 1.5 2.5 0 2 4 0 1.5 2.5 0 2 4 0 2.0 4.0 0 4 8 0 1.5 2.5 0 2 4 0 1.5 2.5 0 2 4 0 1.5 2.5 0 2 4 0 1.5 2.5 0 2 4 0 1.5 2.5 0 2 4 0 1.5 2.5 0 2 4 0 1.5 2.5 0 2 4 0 1.5 2.5 0 2 4 0 1.5 2.5 0 2 4 0 1.5 2.5 0 2 4 NA NA 2.0 NA NA NA Short trunnion clamp, post or pin insulator with ties (without armour rods) Post or pin insulator (clamped or tied) with armour rods or shaped trunnion clamps with armour rods Helically formed armour grip with elastomer insert or helically formed ties with armour rods Flat, no obstacles (See Note 12) Rolling terrain with scattered trees (See Note 12) Mountain, forest or urban

Fully damped all terrain categories

Recommended maximum horizontal tension (% CBL0

6.5 16. 0 6.5 6.5 5.5 13.0 7.5 6.5 6.5 6.5 7.5 6.5 6.5 6.5 6.5 6.5 4.0

34 31 27 24 21 27 27 25 27 23 26 22 23 22 23 21 20

2   7  2 

D R A F  T  O  N L Y

DRAFT ONLY  

273

DRAFT ONLY

 Notes on Tab le Z1: 1

Generally, the temperature under which the horizontal tensions from Table Z1 are applied is based on the average temperature over the coldest month, which in the absence of detailed data may be calculated as the average of daily mean maximum temperature and daily mean minimum temperature.

2

Limits for covered conductors are subject to further research.

3

Limits for LVABC are given in Clause 4.4.1.5.

4

Limits for HVABC should be based on the limits for the support conductor (subject to further research).

5

The tension values given in Table Z1 are a guide only and need not apply to situations where proven line  per forman ce indica tes tha t a hig her or lower ten sion would be app ropria te. Thi s cou ld app ly for exa mpl e to a new line built adjacent to an existing line where the conductor and support (the same as the type to be used) have shown adequate performance.

6

When using the tension limits in Table Z1, additional considerations may need to be given to— (a) The conductor diameter, as this is the governing factor with respect to vibration frequency. Smaller diameter conductors will vibrate at higher frequencies and reach their fatigue life in a shorter time, however, smaller conductors are easier to damp effectively. For all conductors particular care should  be tak en to ensure tha t t he dam per eff ici enc y r ang e i s effe cti ve ove r t he range of fre que nci es likely to occur. (b) The span length, because of the requirement to increase vibration protection with increased span length. (c) The conductor design, including self damping characteristics, compactness, bundled cables, number of aluminium layers, steel/aluminium ratio, etc. (d) The extent to which supports, insulators and fittings can withstand vibration transmitted to them by the conductor.

7

Consideration should be given to the exposure created by structure height, particularly with regard to steel overhead earthwire on steel tower transmission lines where tensions significantly lower than those listed in Table Z1 are normally used.

8

Any terminations, suspensions or joints should be designed so as not to cause damage to conductors or to  be dam age d by con duc tors when the con duc tor is sub jec t to vib rat ion . Vibrat ion dam per s are design ed to reduce the amplitude of vibration whereas armour rods and other protective fittings are primarily designed to protect against the damage to conductors resulting from mechanical vibration.

9

An accurate measurement of conductor temperature during stringing is essential to ensure the initial conductor tensions are achieved.

10 An accurate prediction of conductor creep is necessary to ensure that design final conductor tensions are achieved. 11 Tensions for optical conductors are based on a conductor composed of aluminium clad or galvanized steel  plu s alu min ium or alu min ium all oy wire s. The opt ica l fibres are car rie d in a met all ic tub e loc ate d in the centre or an inner layer of the conductor. Optical conductor should always be installed with helical type armour grips and be fully damped. The manufacturer of the optical conductor should be consulted regarding the recommended maximum tension. 12 Where conductors are strung in Terrain Categories 1 and 2, it is recommended that vibration dampers be applied. If dampers are not applied, care should be taken to ensure that supporting structures and insulators are not subject to vibration damage, especially when use is made of the tension increase for Type C suspension clamps. 13 Use of spacers on bundled conductors may contribute some damping but it is good practice to also fit vibration dampers to bundled conductors.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

274

DRAFT ONLY

APPENDIX AA

CONDUCTOR TENSION CHANGE OF STATE EQUATION (Informative) AA1 GENERAL

The method employed to determine conductor tension due to a change of state of temperature, wind loading and or ice loading depends on whether the design operating tension is within the linear stress strain regime or whether design tensions excursions are in the non linear stress strain regime. For non linear stress strain design, two methods are commonly used and are the ‘graphical’ and ‘strain summation.’ Both methods have been analysed, compared and described in some detail (see reference 1 at the end of this Appendix) To employ the non linear stress strain detailed knowledge of the particular conductor stress strai n characteristic as detailed in Appendix W is required. The linear stress strain model may be used using the modulus of elasticity determined in accordance with Appendix W. Having decided on either the use of a non-linear or linear method, the designer can then use either the equivalent span theory (see reference 2 at the end of this Appendix) or the complex finite element analysis (see reference 3 at the end of this Appendix) to determine conductor tensions. The equivalent span theory is explained below and may be used for the majority of overhead line designs. AA2 EQUIVALENT SPAN

An equivalent span assumes a continuous conductor, supported at intermediate structures and the tension within the section between conductor termination points is assumed to be equal irrespective of the number of intermediate structures, span lengths and terrain profile. The equivalent span or ruling span is a determination from the lengths of all the spans  between tension structures of a s pan length that will dictate the conductor tension within the section. The ruling span is given by—

∑ L ∑ L

3

 L ruling  =

. . .AA1

For example, three spans 240 m, 280 m and 220 m between two tension structures would have a ruling span determined as follows:  L ruling  =

2403 + 2803 + 2203 240

+ 280 + 220

= 251 m

. . .AA2

The total section length is 740 m and the conductor tension determined for the change of state equation would based on a span of 251 m. Under some circumstances such as long insulator lengths, significant changes of elevation  between adjacent structures or where adjacent spans are of significant differing lengths the equivalent span theory has limited application and finite element analysis using commercial software should be used to determine conductor tension.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

275

DRAFT ONLY

AA3 TENSION CHANGE OF STATE EQUATION

The tension change of state equation determinates the conductor tension for any condition of temperature, wind loading and or ice loading. The key to understanding the tension change of state equation relationships is that— (a)

there is some initial conductor condition which is usually a predetermined design condition;

(b)

there is a final conductor condition and this is normally the condition that is being determined; and

(c)

the fundamental relationship is based on conductor length between two points where the conductor length is constrained from any axial movement or in other words mechanically terminated.

Take the simple example of a single span, length L with the conductor terminated at A and B as illustrated in Figure AA1.

B (x 1 ,y 1 )

 A  ( –x 1 ,y 1 ) Sy

L

FIGURE AA1 SIMPLE OVERHEAD LINE SPAN SHOWING SPAN LENGTH AND CONDUCTOR LENGTH

In this example the general time independent conductor tension change of state equation for the conductor length cord, l is— l initial + Δ l = l

. . .AA3

final

where

Δl

=

change in conductor length due to changes in temperature, ice and or wind load and or tension.

By substitution into Equati on AA3, the Taylor serie s expansion of the initi al parabolic conductor length, the change in length due to change in temperature, the change in length due to change in tension and the Taylor series expansion of the final parabolic conductor length results in Equation AA4 (see reference 4 at the end of this Appendix).  L

+

ω12 L3

α L(θ 2 2

24Th1

− θ 1 ) +

 L AEf

(T2

− T1 ) = L +

ω 22 L3

24Th22

where  L

=

span length

ω

=

conductor mass

T h

=

conductor horizontal tension

θ 

=

conductor temperature

α

=

coefficient of thermal expansion

 A

=

conductor cross sectional area

 E f 

=

conductor final modulus of elasticity

8326-PDR - 24/07/2008 14:25:50

 

. . .AA4

DRAFT ONLY  

276

1

=

subscript denoting initial condition

2

=

subscript denoting final condition

DRAFT ONLY

The tension change of state equation may be manipulated and result in a cubic Equation AA5 which may be solved using a range of mathematical techniques. T23

+

AT2

=B

. . .AA5

where 2

 A

=

 B

=

C 1

=

C 2

=

⎛ ω  LC  ⎞ C2 (t2 − t1 ) + ⎜ 1 1 ⎟ − T1 ⎝ T 1 ⎠

 

( ω 2 LC 1 )2

 EA

24

α EA

Equation AA3 omits consideration of conductor permanent elongation and hence is termed the time independent tension change of state equation. The time dependent equation for tension change of state equation for conductor length, l is— l initial + Δ l +

ε = l final

ε

conductor permanent informative ADF.

. . .AA6

where =

elongation

determined

in

accordance

with

The time dependent equation may be solved to determine conductor sag change with time for a particular condition such as the maximum operating condition. This then permits determination of the required allowances for conductor permanent elongation as described in Appendix V. References

1.

CIGRE SCB2.12.3, Sag Tension Calculation Methods for Overhead Lines . CIGRE Technical Brochure No.324, 2007.

2.

BOYSE, C.O. AND SIMPSON, N.G., The Problem of Conductor Sagging on Overhead Transmission Lines. Journal of the Inst. of Elec. Eng. Vol 91, Pt II, Dec 1944, pp 219 – 231.

3.

BARRIEN, J,  Precise Sags and Tensions in Multiple Span Transmiss ion Lines . Electrical Engineering Transactions IEAust, Vol II, No.1, 1975, pp 6-11.

4

Overhead Conductor Design , BICC Wire Mill Division Prescot, Lancashire, England, 1967, pp 21-28.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

277

DRAFT ONLY

APPENDIX BB

CONDUCTOR SHORT TIME AND SHORT-CIRCUIT RATING (Informative) BB1 FAULT RATINGS BB1.1 General

The main factors to consider when determining the fault rating of a line are— (a)

the annealing of the conductor resulting from overheating due to the magnitude and duration of the fault current;

(b)

the sagging of the conductor into another conductor below it; and

(c)

movement of conductors due to electromagnetic forces leading to conductor clashing, arcing, conductor damage, secondary faults, etc.

BB1.2 Annealing

The short circuit or transient thermal state condition for a homogenous conductor, assuming— (a)

uniform current distribution within the conductor and the wires;

(b)

the resistance temperature characteristic of the conductor is linear;

(c)

the specific heat of the conductor is constant and the heating is adiabatic; that is due to the transient nature of the current flow the heat gains and losses at the surface of the conductor are ignored; and

(d)

the fault duration is small such that no heat will be dissipated from the conductor

then the following equation is a reasonable approximation of the conductor temperature rise— T 2

20 −

=

1  Ar

⎡ Ar RJ 2r  ⎤ ⎥  DC  ⎥⎦

⎡ 1 ⎤ ⎢ + ⎢T1 − 20 + ⎥ e⎢⎣ Ar  ⎦ ⎣

. . .BB1

where T 2

=

final temperature in °C

T 1

=

initial temperature in °C

 Ar

=

temperature coefficient of resistance in °C  –1

 R

=

resistivity in ohm mm at 20°C

 D

=

density in g/mm 3

 J 

=

current density in A/mm 2

t

=

duration in seconds (includes reclosure times)

C 

=

specific heat = C20 ⎨1 + Ac ⎢⎜

C 20

=

specific heat at 20°C in Jg

 Ac

=

temperature coefficient of specific heat

⎧ ⎩

⎡⎛ T1 + T 2 ⎞ ⎤ − 20 ⎥ ⎟ ⎣⎝ 2 ⎠ ⎦

−1

 °C

−1

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

278

DRAFT ONLY

Rearranging Equation BB1—

 J 2t

⎡ ⎣

⎛ T1 + T 2 − 20 ⎞ ⎤ ⎡ T  20 1 ⎤ ⎟ ⎥ ⎢ 2 − +  A ⎥ ⎝ 2 ⎠ ⎦ 1n ⎢ r  ⎥ 1  Ar  R ⎢ T  − 20 + ⎥ ⎢⎣ 1  Ar  ⎥⎦

 DC20 ⎢1 + Ac ⎜

=

. . .BB2

TABLE BB1 CONDUCTOR CONSTANTS Constants

Units

AAC

AAAC/ 1120

AAAC/ 6201A

HD copper

SC/GZ

SC/AC

Ar (at 20°C) *

°C− 1  

0.0 0403

0.00390

0.00360

0.00381

0.00440

0.00360

R (at 20°C) *

Ωmm

D*

g/mm 3  

C 20 **

Jg − 1 °C −1

Ac **

°C− 1  

28.3 ×  10 − 6 29.3 ×  10 −6 32.8 ×  10 − 6

17.77 ×  10 −6  

190

× 10 −6

× 10 − 3 2.70 × 10 −3 2.70 × 10 − 3

8.89 ×  10 −3  

7.8

× 10 − 3  6.59 × 10 −3

2.70

0.9 4.5

0.9

× 10 − 4 

4.5

0.9

× 10 −4  4.5 × 10 −4 

0.4 2.9

× 10 −4 

85

0.5 1.0

× 10 − 4 

× 10 −6

0.5 1.0

× 10

*

Value taken from the appropriate Australian Standard, i.e. AS 1531, AS 1746, AS 1222.1, AS 1222.2.

**

Values are median values of data sourced from several references including—

−4

 —

V T Mor gan , ‘ Rating of Bare Over head Conducto rs for Intermi ttent and Cycl ic Curr ents ’, Proc IEE, 1361-1376, 116(8), 1969.

 —

V T Mor gan , ‘ Rating of Condu ctor s for Short-Du rati on Curr ents ’ , Proc IEE, 555-570, 118(3/4), 1971.

 —

Draft IEEE Sta nda rd, ‘ Calculating the Current-Temperature relationship of Bare Overhead Conductors’, 1993.

From Equation BB2 the fault rating can be determined based on maximum allowable temperature. Constants for specific conductor types are contained in the relevant Australian Standards and as shown in Table BB1. Aluminium loses approximately 10% of its tensile strength at a temperature of 210°C with a significant proportion of the annealing taking place during the cooling period following a fault. This annealing is cumulative over the life of the conductor. It anneals rapidly at temperatures exceeding 340°C and commences melting at approximately 645°C. The mechanical properties of the steel core of ACSR are affected very little at these temperatures. Zinc melts at approximately 420°C. Copper loses 10% of its tensile strength at a temperature of 220°C. To provide for a loss of conductor tensile strength of less than 5% due to fault conditions over its life, the temperatures indicated in Table BB2 should not be exceeded. The rate of cooling is dependent on the thermal mass of the conductor, therefore lower maximum temperatures are applicable to conductors of large cross-section.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

279

DRAFT ONLY

TABLE BB2 GUIDELINES FOR 5% LOSS OF TENSILE STRENGTH FOR TOTAL FAULT CLEARING TIME (INCLUDING RECLOSES) Conductor type

HDCu AAC, AAAC/1120, ACSR/GZ,

Approximate size (mm²)

Maximum temperature

60

200°C

100

160°C

300 to 500

150°C

100

220°C

ACSR/AZ, ACSR/AC AAAC/6201A SC/GZ, SC/AC

400°C

OPGW

***

***Dependent on construction. Reference: ROEHMANN, L.F. and HAZAN, E., Short time annealing characteristics of electrical conductors, AIEE Trans 82/3 p1061, Dec 1963.

BB1.3 Sag under fault

Overhead lines have been known to sag into subsidiary lines or undercrossings under fault. If this is to be avoided it may be advisable for the line to be designed to have a positive clearance to the lower conductor. It is recommended that the appropriate non-flashover distance from AS 2067 for the system voltage be used for this clearance. BB1.4 Movement of conductors under fault

The movement of conductors due to the electromagnetic forces generated by large short time current is a complex matter for which a simple satisfactory solution is not available. The Transmission Line Reference Book  —115-138 kV Compact Line Design   (EPRI EL-100V3, Research Project 260, 1978) Section A3, Simulation and Tests of Motion Due to Fault Currents  —gives equations which may be used to determine conductor swi ng and the mechanical forces due to fault currents. By taking these criteria and the degree of reliability required into account, a suitable compromise on structure design, conductor configuration and economics can be achieved.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

280

DRAFT ONLY

APPENDIX CC

CONDUCTOR ANNEALING (Informative) CC1 GENERAL

Aluminium alloys are designated by the numbering system in Table CC1. The first digit specifies the principle alloying elements, and the remaining digits refer to the specific composition of the alloy. The alloys are subdivided into two subgroups—heat treatable and non heat treatable alloys. Heat treatable alloys are age hardened (precipitation hardened), whereas non heat treatable alloys are hardened by solid solution strengthening (not used for conductors because of the reduction in electrical conductivity), strain hardening, or dispersion strengthening. TABLE CC1 DESIGNATION SYSTEM FOR WROUGHT ALUMINIUM ALLOYS 1xxx

Commercially pure Al (>99%)

Non heat treatable

2xxx

Al-Cu

Heat treatable

3xxx

Al-Mn

Non heat treatable

4xxx

Al-Si and Al-Mg-Si

Heat treatable if Mg is present

5xxx

Al-Mg

Non heat treatable

6xxx

Al-Mg-Si

Heat treatable

7xxx

Al-Mg-Zn

Heat treatable

The degree of strengthening is given by the temper designation in Table CC2 TABLE CC2 TEMPER DESIGNATIONS FOR ALUMINIUM ALLOYS F

As fabricated (hot rolled, forged, cast, etc)

O

Annealed (most ductile condition)

H1x

Cold worked only (x refers to the amount of cold working or strengthening)

H2x

cold worked and partly annealed

H3x

cold worked and stabilised at a low temperature to prevent age hardening

W

Solution treated

Tx

Age hardened (x refers to the amount of strain hardening)

Resistance to room temperature creep and annealing varies with composition or fabrication variations. EC alloy 1350 has about 0.20% (by weight) Fe and 0.08% Si. Addition of iron decreases resistances to creep and annealing. Addition of Mg to a high iron alloy increased the resistances to creep and annealing. Production of rod by the continuous cast process also causes higher resistances to creep and annealing than the conventional hot-rolled  process.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

281

DRAFT ONLY

CC2 WIRE FABRICATION

Aluminium strands are drawn from 9.5 mm rod which can be produced by either the continuous cast (known as Properzi) process or by the hot-rolled process. Continuous cast rod is the result of the tandem manufacturing steps of casting, rolling and solution heat treating, if applicable. This allows the continuous production of coils limited in size only by the capability of the materials handling equipment. By contrast, hot-rolled rod is produced from cast billets that are rolled and solution heat-treated, if applicable. Large coils of hotrolled rod are made by welding together smaller coils. Conductors derive their strength from the metallurgical properties of the alloy and from strain hardening (cold working) during the wire drawing process. In the case of heat treatable aluminium alloys such as 6201, the strengthening of the wire that occurs during the aging treatment is added to that achieved during the drawing process. For example, the  process of tempering produces approximately 41% of the overall strength for HDC; 56% of the overall strength for 1350-H19 and 60% of the overall strength for 6201-T81. Smaller diameter wire experiences more strain hardening and achieves about 3% higher tensile strength. The greater the gain in tensile strength from cold working, the greater the loss of strength from annealing for a given temperature and time duration. CC3 ANNEALING FROM ELEVATED TEMPERATURE OPERATION

Morgan (see reference 6 to this Appendix) proposed the formulae below for determining the loss of tensile strength of strands due to annealing. Morgan related the loss of strength of the wires to the percentage reduction in cross sectional area during wire drawing, since this determines the degree of strain hardening. ⎛ ⎛ ⎜ − e⎝ ⎜ = Wa 1 − e ⎜ ⎝

 A′ +

W

 B ′

C′ R ⎞ 1n ( t ) + + D ′1n ⎛⎜ ⎞⎟ ⎟ T* T * ⎝ 80 ⎠ ⎠

⎞ ⎟ ⎟ ⎠

⎛ ⎛ D ⎞2 ⎞  R = 100 ⎜ 1 − ⎜ w ⎟ ⎟ ⎜ ⎝  Do ⎠ ⎟ ⎝ ⎠

. . .CC1

. . .CC2

where W 

=

loss of tensile strength in the partially annealed state (% of ultimate tensile strength in the tempered state)

W a

=

loss of tensile strength in the fully annealed state (% of ultimate tensile strength in the tempered state)

 A′ ,  B′ , C ′  and  D′

=

experimentally derived constants for the alloy

T *

=

wire absolute temperature ( K )

t

=

time duration at temperature T* (hours)

 R

= reduction in cross-sectional area during wire drawing (%)

 D o  D w

=

diameter of prior to drawing (mm) – usually 9.5 mm for aluminium

= diameter of the drawn wire i.e. strand diameter (mm) – usually 2.5 to 4.75 mm for aluminium

Table CC3 is an excerpt from Table 2 of [reference 6 to this Appendix] using average values of –C’/A’.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

282

DRAFT ONLY

TABLE CC3 ANNEALING EQUATION CONSTANTS Alloy

W a (%)

A

B (K)

C (K)

D

1350-H19

56

7.8

150

−4700

7.5

6201A-T81

60

16.2

270

−9000

4

HDC (110A-H)

41

14

175

−6700

3

In general, Aluminium loses approximately 10% of its tensile strength at a temperature of 210°C with a significant proportion of the annealing taking place during the cooling period following a fault. This annealing is cumulative over the life of the conductor. It anneals rapidly at temperatures exceeding 340°C and commences melting at approximately 645°C. For ACSR, the mechanical properties of the steel core are affected very little at these temperatures. Zinc melts at approximately 420°C. Copper loses 10% of its tensile strength at a temperature of 220°C. CC4 ANNEALING FROM FAULT CURRENTS

Excessive heating of conductors and in particular overhead earthwire during a short circuit can cause a reduction in tensile strength and permanent elongation. The permanent reduction in electrical clearance can reduce the reliability of the line. Failure of the conductor and or earthwire either during the fault or subsequently during adverse weather can cause an outage as well as damage to the support structures. In the case of steel stands, any loss of protective zinc coating can lead to corrosion In particular, the earthwire size is determined by the assuming a maximum acceptable temperature that causes minimum permanent damage. The effect of cumulative heating of the earthwire when the line is reclosed under short circuit conditions should be considered. Permanent damage includes— (a)

loss of protective coating i.e. zinc, grease;

(b)

reduction in tensile strength (annealing);

(c)

 permanent elongation; and

(d)

 permane nt attenuati on losses for OPG W.

For AAC and AAAC earthwires the reduction in tensile strength will be accompanied by accelerated creep. For ACSR earthwires there will be a transfer of load from the aluminium to the steel, resulting in larger sags than perhaps anticipated. Consideration should be given the instantaneous sag of the earthwire at elevated temperatures to ensure that the sag does not result in a consequential fault during an auto reclose operation. CC5 MAXIMUM OPERATING TEMPERATURES

Typical conductor types, csa and maximum allowable temperature [See reference 8 to this Appendix] are given in Table CC4 for loss of strength of 10%. Notwithstanding this it is stressed that this is a guide only and annealing cumulative damage should be determined by summing the loss of tensile strength as a percentage of original strength for the range operating temperatures and operating durations.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

283

DRAFT ONLY

TABLE CC4 TYPICAL CONDUCTOR MAXIMUM OPERATING TEMPERATURES Conductor type

HDCu AAC, AAAC/1120, ACSR/GZ, ACSR/AZ, ACSR/AC AAAC/6201A

csa (mm²)

Maximum temperature

60

200°C

100

160°C

300 to 500

150°C

100

220°C

SC/GZ, SC/AC

400°C

OPGW

Dependent on construction

References 1.

KIESSLING, F. et al, Overhead Power Lines – Planning and Design   , Springer, pp 250– 251

2.

IEEE Std 1283-2004,  IEEE Guide for Determ ining the Effects of High-Temperature Operation on Conductors, Connectors, and Accessories

3.

BARBER, K.W.; CALLAGHAN, K.J.,  Improv ed overhead line conductors using aluminium alloy 1120 , IEEE Transactions on Power Delivery, Volume 10, Issue 1, Date: Jan 1995, pp 403 - 409

4.

WESTERLUND, R.W.,  Effects of compositi on and fabrication practice on res ist ance to annealing and creep of aluminium conductor alloys , Metallurgical and Materials Transactions B, Volume 5, Number 3/March, 1974, pp 667-672, Springer Boston

5.

CIGRE WG22.12,  Loss in Str ength of Overhead Electr ical Conductors Caus ed by  Elevated Temperature Operation , ELECTRA No. 162, October 1995, pp 115–118

6.

Vincent Morgan,  Effect of Elevated Tem perature Operation on the Tensile Strength of Overhead Conductors , IEEE Transactions on Power Delivery, Vol. 11, No. 1, January 1996, pp 345-352

7.

FRANC JAKL and ANDREJ JAKL,  Effect of Elevated Temperatures on Mechanical  Properties of Overhead Conductors under Steady State and Short-Circuit Conditions , IEEE Transactions on Power Delivery, Vol. 15, No. 1, January 2000, pp 242 – 246

8.

ROEHMANN, L.F. and HAZAN, E., Short time annealing characteristics of electrical conductors , AIEE Trans 82/3 p1061, Dec 1963.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

284

DRAFT ONLY

APPENDIX DD

MECHANICAL DESIGN OF INSULATOR - LIMIT STATES (Normative) DD1 INSULATOR LIMIT STATES

There are 3 states for the mechanical design of insulators, these being— (a)

everyday load;

(b)

serviceable wind load; and

(c)

failure containment load.

DD2 MECHANICAL DESIGN— SIMPLIFIED APPROACH

Table DD1 shows the load and wind conditions for a range of insulator types. These define the minimum requirements for an overhead line of relative reliability of 1 or less. TABLE DD1 INSULATOR LOADING CONDITIONS State

Tension insulator condition

Suspension and vee string insulator condition

Post and pin insulator condition

Everyday tension (EDT), 0 Pa wind

Vertical weight span, 0 Pa wind

Vertical weight span, 0 Pa wind

Serviceable

Serviceable wind or 500 Pa wind

Resultant load at serviceable wind or 500 Pa transverse load

Resultant load with serviceable wind or 500 Pa transverse + longitudinal unbalance load

Failure containment

Conductor calculated  bre aki ng loa d (CBL ( CBL))

Resultant load for ultimate conductor wind transverse load

Resultant load with ultimate transverse wind + longitudinal unbalance load

Everyday

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

285

DRAFT ONLY

APPENDIX EE

EASEMENT WIDTH (Informative) EE1 EASEMENT WIDTHS

Table EE1 provides typical easement widths for a range of voltages. For distribution voltages, approval for an overhead line on private property is generally negotiated with the property owner and may not require a formal easement agreement. It is generally not required to obtain easements for overhead powerlines located on road reserves because of building set back conditions contained in local authority planning schemes. However if an easement is required Table EE1 gives the nominal widths. TABLE EE1 TYPICAL EASEMENT WIDTHS FOR A RANGE OF VOLTAGES (FOR TYPICAL SPANS) Nominal voltage

Easement building restriction widths generally used (measured from the centre line of the overhead line) *

Typical width of easement

Up to 33 kV

5 to 10 m

10 to 20 m

66 kV

10 to 15 m

20 to 30m

110/132 kV

15 to 20 m

30 to 40 m

220 kV

15 to 25 m

30 to 50 m

275 kV conventional

25 to 30 m

50 to 60 m

275 kV guyed

30 m

70 m

330 kV

30 m

60 m

400 kV

30 m

65 m

500 KV

35 m

70 m

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

286

DRAFT ONLY

APPENDIX FF

SNOW AND ICE LOADS (Normative) FF1 GENERAL

The accumulation of snow and ice on conductors and supports varies greatly with altitude, latitude and local conditions such as terrain. In general, lines located in areas higher than 800 m above sea level in Australia and in some areas of New Zealand may be subject to occasional snow/ice loadings. However, there is insufficient consistently re-occurring data for most regions on which to base return periods for snow and ice loads. Hence details  provid ro vided ed are consid con sidere ered d to t o prov p rovide ide a reas r eas onable ona ble guide gui de to design des igners ers.. Only combined wind and ice loads on conductors are considered in this standard. Wind loads on ice covered supports and insulators may be treated similarly when appropriate drag factors are used. The effect of wind on an ice covered conductor is determined by three variables: (a)

the wind speed during the period of time that the conductor is ice covered; and

(b)

the mass of the ice layer;

 NOTE: OT E: The shap e of o f the t he ice layer, lay er, i.e. i.e . the t he dia meter met er and the rel evant eva nt dra g f actor. act or.

Reference should also be made to the provisions contained in AS/NZS 1170.3 and CIGRE Technical Brochure 291, Guidelines for meteorological icing models, statistical methods and topographical effects , April 2006. In particular the following specific provisions should be made: FF1.1 Australia

In areas with ice and snow loadings, the minimum design loads should be based on a radial ice thickness of 12 mm with a density of 900 kg/m3 (SG = 0.9) and coincident with a wind  press re ssure ure of 100 Pa at a conduc con ductor tor temper tem peratu ature re of –5°C. –5° C. These The se loads loa ds may be taken tak en as corresponding to a return period of 50 years though the appropriateness is uncertain. Provision should also be made for the unbalanced longitudinal loads produced by ice forming on certain spans but not others, due to local topographic effects. In this regard, line sections with large adjacent span ratios should also be investigated. In regions within Tasmania icing can occur at low altitudes but with reduced thickness of accretion. In this area the requirements provided in Table GG1 shall be included in design loadings.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

287

DRAFT ONLY

TABLE GG1 TASMANIA REGION ICE LOADING CONDITIONS Elevation (m)

Wire type

Earthwire

0–499

Conductor

0–599

Ice condition—  900 kg/m3

Ambient temperature (°C)

Wind pressure (Pa) Spans >150 m

Spans <150 m

 Non -ic e

Coe xistin xis tin g temperature

Inclement (design) weather conditions prevail

Ice–6 mm

−10°C

190

380

Eathwire

500–799

Conductor

600–799

Both

800–999

Ice–9 mm

−10°C

190

380

Both

>1000

Ice–12 mm

−10°C

190

380

 NOTE S: 1

Icing should be assumed to occur in all areas of Tasmania and is dependent on altitude and locations where ice loading has been known to occur.

2

Snow offset cross arms should be used on all vertical configuration circuits to minimise clashing of conductors. Earthwires are not to be positioned above phase conductors in horizontal/flat construction configuration

3

Ice build up is assumed to only occur on conductors. Lattice structures with congested bracing arrangements that may trap snow accumulations shall have increased windage areas provided in designs.

4

Where in-cloud icing may occur on elevated location expert guidance should be sought from local meteorology sources.

5

Where the line is subject to moist air rising from the coast (West Coast and around the South East Coasts of Tasmania), the susceptibility to ice accretion is higher. In those areas, the elevation shall be 100 metres lower at which ice conditions apply.

These effects may then be used to evaluate wire tensions and the calculation of wire loads on structures. FF1.2 New Zealand

Ice (or wet snow) is to be considered on wires only. For ice cases which include wind, the reduced return period wind should be applied to un-iced pole or tower, taking into account the structure’s overall drag coefficient. On towers heavily congested by members, all gaps of less than 75 mm should be considered as being filled with ice. For exposed sites on ridges, non uniform ice build may result and the ice build up shall be taken as the full ice accretion thickness on one side of the structure and 40% of ice build up on the other side. All large deviation (greater than 30°) and section poles shall be designed for the full ice accretion thickness on one side of the structure and no ice build up on the other side. The drag coefficient to be used for wind co-incident with ice conditions shall be taken as 1.1 times the relevant drag coefficient ( C d) for wind conditions only, but in no case be less than 1.2. FF1.2.1 Temperature effects

Unless specific data is available, the following design temperatures shall be used. (a)

Snow—0ºC

(b)

Ice— (i) (ii)

−3ºC Inland areas >5 km from coast: temperature = −0.0085 ×  altitude −5ºC Coastal areas:

temperature = – 0.0085 ×  altitude

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

288

DRAFT ONLY

The temperature shall be based on the highest altitude of the line. If there is significant variation in altitude along the line, then the line shall be broken into several temperature zones. FF1.2.2 Conductor tensions (F T  T )  

The conductor tensions shall be based on a span equal to the ruling span. Consideration shall be made for the overall effect of differences in tension of adjacent spans on the structure. Where significant span differences arise, the structure shall be checked for full loading on one side of the structure and 40% of loading on the other side. Allowance shall be made for some flexibility of post and pin insulators when calculating tensions. FF1.2.3 Snow and ice zones

The snow and ice zones are based on AS/NZS 1170.3 Figure 7.1 (snow zones). These are  based as ed on the 198 1988 8 Coun C ouncil cil Bounda Bou ndarie ries. s. Specific historical knowledge and records of other lines in the same locality may be utilized in generating ice and snow loading requirements.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

289

DRAFT ONLY

FIGURE GG.1 NEW ZEALAND SNOW AND ICE ZONES

FF1.2.4 Radial snow and ice build up on conductors

Table GG2 below specifies radial snow/ice thicknesses corresponding to a 50 year event. Relatively low density Wet S now occurs at low elevations below 600 m. At higher elevations, ice is expected to form. Two snow/Ice cases shall be checked

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

290

DRAFT ONLY

TABLE GG2 ICE AND SNOW PARAMETERS FOR NEW ZEALAND Radia snow or ice thickness (Rice) on conductors Zone

 N0 Upper North Island

 N1 Lower North Island

 N2, N3, N5 South Island

 N4 Canterbury

Altitude

Wet snow thickness at 400 kg/m 3

Ice thickness at 7000 kg/m 3

Co-incident wind return period for ice (years)

450–600

25

—

1

600–900

30

5

1

900–1200

35

8

1

>1200 150–450

40 25

10 —

5 1

450–600 600–900

30 35

10 15

1 1

900–1200

40

20

5

>1200 0—150

45 30

25 10

5 1

150–300

35

15

1

300–450

40

20

1

450–600

45

25

1

600–750

—

30

5

750–900

—

35

5

900–1200

—

40

5

>1200

—

45

5

0—150 150–300

45 (30 50 (35)

15 (10) 20 (15)

1 1

300–450 450–600

55 (40) 60 (45)

25 (20) 30

1 1

600–750

65 (50)

35

5

750–900 900–1200

— —

40 45

5 5

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

291

DRAFT ONLY

 NOTE S: 1

The figures in brackets are the existing standard thicknesses. Ice density has been assumed as 900 kg/m³. [Based on current knowledge, this appears too high]. The snow values are based on AS/NZS 4676 and equivalent Transpower radial thicknesses (these were converted to uniform density values).

2

For wind associated with ice, it is recommended that at low altitudes that a 1 year return period be used; for higher altitudes a higher value has been adopted on the basis that wind is more likely to occur and that ice formation may remain for many days.

3

AS/NZS 4676 requires 30 mm radial snow (0.4 SG) be considered at all below 600m altitudes for Canterbury (N4).

4

AS/NZS 1170.3 suggests that 30 mm radial ice (0.9 SG) at 0ºC combined with a 10 year return period wind be used for building structures in sub alpine regions. This may be appropriate for rigid structures only; it is very conservative for overhead lines (which are very flexible).

5

ISO 12494 suggests that combined actions be considered involving maximum wind (50 year RP) and reduced icing (factor = 0.7) also maximum icing (50 year RP) and reduced wind cases (50 year RP); wet snow is usually taken in still air conditions. This is similar to IEC 60826 requirements.

6

For wind associated with ice, the overall effect is similar to current overhead line standards. Although the ice density has been reduced from 915 to 700 kg/m³ and the wind speed reduced, the iced diameter has been increased slightly to compensate. Most lines companies don’t want to see a reduction in transverse loading on the poles, hence results should be comparable.

7

The proposed wet snow values are based on limited data on 2006 June storm in Orion’s area (this was up to a 50 year event in some locations). Reported snow build up was 20 mm to 50 mm radial thickness at an equivalent of 400 kg/m³ snow density. This indicates that current standards are probably too low at  par tic ula rly at lower alt itu des.

FF1.2.5 Co-incident wind and ice conditions

 No wind shall be applied to wet snow. Wind loads shall be calculated as per AS/NZS 1170.2. Only winds from the SW, S or SE directions shall be considered coincident with ice. FF1.2.6 Ice densities

For all radial ice thicknesses, a base density of 700 kg/m³ shall be used. This is consistent with a medium rime ice which is believed to be the predominant icing mechanism in New Zealand. For conductors less than 11mm, the radial ice thickness shall be increased by 10%. FF1.2.7 Snow densities

For all radial snow thicknesses, a density of 400 kg/m³ shall be used. FF1.2.8 Differential ice loading

In addition to the uniform extreme ice/snow loading case, every structure within ice/snow zones shall also be checked for torsional and longitudinal loading resulting from Differential Icing as described in the Table GG.3. No coincident wind sha ll apply with differential icing.

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

292

DRAFT ONLY

FIGURE GG2 DIFFERENTIAL ICE LOADING

TABLE GG3 DIFFERENTIAL ICE AND SNOW LOADING CONDITIONS Differential ice and snow loading conditions Longitudinal condition Support type

Single circuit Double circuit

Torsional condition

Left span

Right span

Left span

Right span

xyabc

XYABC

XYABC

XYABC

abc

ABC

ABC

ABC

xabcdef

XABCDEF

XABCDEF

XABCDEF

abcdef

ABCDEF

ABCDEF

ABCDEF

A,B,C,D,E,F represent phase conductors and x,y are earthwires. A,B,C,D,E,F,X,Y represent spans loaded with 70% of maximum ice/snow weight. The letters a,b,c,d,e,f,x,y represent spans loaded with 30% maximum ice/snow weight.

FF1.2.9 Snow loading on pole structures

Poles in areas subject to snow shall have a minimum down-line strength of at least— (a)

50% of their transverse strength. This allows some equalisation of out-of-balance loads before significant damage occurs; and

(b)

50% of the initial stringing tension of the conductors being supported on the pole under everyday conditions (still air). This ensures that multiple circuit poles have sufficient robustness.

Consideration should be given to the effects of redistribution of forces between stays and rigid poles under snow loads.  NOT E: In soft soils, up to 200 mm of movement may occur before the soil passive anchor capacity is reached].

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY  

293

*** END OF DRAFT ***

8326-PDR - 24/07/2008 14:25:50

DRAFT ONLY

PREPARATION OF JOINT AUSTRALIAN/NEW ZEALAND STANDARDS

Joint Australian/New Zealand Standards are prepared by a consensus process involving representatives nominated by organizations in both countries drawn from all major interests associated with the subject. Australian/New Zealand Standards may be derived from existing industry Standards, from established international Standards and practices or may  be developed within a Standards Aus tralia , Standards New Zealand or joint technical committee. During the development process, Australian/New Zealand Standards are made available in draft form at all sales offices and through affiliated overseas bodies in order that all interests concerned with the application of a proposed Standard are given the opportunity to submit views on the requirements to be included. The following interests are represented on the committee responsible for this draft Australian/ New Zealand Standard: CIGRE Electrical Engineers Association of NZ Inc Electrical Regulatory Authorities Council Electricity Engineers Association (New Zealand) Energy networks Association Engineers Australia  National Electrical and Communi cations A ssociation Transpower New Zealand Limited Vector Ltd